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).

Maturation history modeling of Sufyan Depression, northwest Muglad Basin, Sudan

NASA Astrophysics Data System (ADS)

Wang, Ying; Liu, Luofu; An, Fuli; Wang, Hongmei; Pang, Xiongqi

2016-08-01

The Sufyan Depression is located in the northwest of Muglad Basin and is considered as a favorable exploration area by both previous studies and present oil shows. In this study, 16 wells are used or referred, the burial history model was built with new seismic, logging and well data, and the thermal maturity (Ro, %) of proved AG source rocks was predicted based on heat flow calculation and EASY %Ro modeling. The results show that the present heat flow range is 36 mW/m2∼50 mW/m2 (average 39 mW/m2) in 13 wells and 15 mW/m2∼55 mW/m2 in the whole depression. Accordingly, the geothermal gradient is 20 °C/km∼26 °C/km and 12 °C/km∼30 °C/km, respectively. The paleo-heat flow has three peaks, namely AG-3 period, lower Bentiu period and Early Paleogene, with the value decreases from the first to the last, which is corresponding to the tectonic evolution history. Corresponding to the heat flow distribution feature, the AG source rocks become mature earlier and have higher present marurity in the south area. For AG-2_down and AG-3_up source rocks that are proved to be good-excellent, most of them are mature with Ro as 0.5%-1.1%. But they can only generate plentiful oil and gas to charge reservoirs in the middle and south areas where their Ro is within 0.7%-1.1%, which is consistent with the present oil shows. Besides, the oil shows from AG-2_down reservoir in the middle area of the Sufyan Depression are believed to be contributed by the underlying AG-3_up source rock or the source rocks in the south 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.

Shale characterization in mass transport complex as a potential source rock: An example from onshore West Java Basin, Indonesia

NASA Astrophysics Data System (ADS)

Nugraha, A. M. S.; Widiarti, R.; Kusumah, E. P.

2017-12-01

This study describes a deep-water slump facies shale of the Early Miocene Jatiluhur/Cibulakan Formation to understand its potential as a source rock in an active tectonic region, the onshore West Java. The formation is equivalent with the Gumai Formation, which has been well-known as another prolific source rock besides the Oligocene Talang Akar Formation in North West Java Basin, Indonesia. The equivalent shale formation is expected to have same potential source rock towards the onshore of Central Java. The shale samples were taken onshore, 150 km away from the basin. The shale must be rich of organic matter, have good quality of kerogen, and thermally matured to be categorized as a potential source rock. Investigations from petrography, X-Ray diffractions (XRD), and backscattered electron show heterogeneous mineralogy in the shales. The mineralogy consists of clay minerals, minor quartz, muscovite, calcite, chlorite, clinopyroxene, and other weathered minerals. This composition makes the shale more brittle. Scanning Electron Microscope (SEM) analysis indicate secondary porosities and microstructures. Total Organic Carbon (TOC) shows 0.8-1.1 wt%, compared to the basinal shale 1.5-8 wt%. The shale properties from this outcropped formation indicate a good potential source rock that can be found in the subsurface area with better quality and maturity.

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.

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

Hydrocarbon Source Rocks in the Deep River and Dan River Triassic Basins, North Carolina

USGS Publications Warehouse

Reid, Jeffrey C.; Milici, Robert C.

2008-01-01

This report presents an interpretation of the hydrocarbon source rock potential of the Triassic sedimentary rocks of the Deep River and Dan River basins, North Carolina, based on previously unpublished organic geochemistry data. The organic geochemical data, 87 samples from 28 drill holes, are from the Sanford sub-basin (Cumnock Formation) of the Deep River basin, and from the Dan River basin (Cow Branch Formation). The available organic geochemical data are biased, however, because many of the samples collected for analyses by industry were from drill holes that contained intrusive diabase dikes, sills, and sheets of early Mesozoic age. These intrusive rocks heated and metamorphosed the surrounding sediments and organic matter in the black shale and coal bed source rocks and, thus, masked the source rock potential that they would have had in an unaltered state. In places, heat from the intrusives generated over-mature vitrinite reflectance (%Ro) profiles and metamorphosed the coals to semi-anthracite, anthracite, and coke. The maximum burial depth of these coal beds is unknown, and depth of burial may also have contributed to elevated thermal maturation profiles. The organic geochemistry data show that potential source rocks exist in the Sanford sub-basin and Dan River basin and that the sediments are gas prone rather than oil prone, although both types of hydrocarbons were generated. Total organic carbon (TOC) data for 56 of the samples are greater than the conservative 1.4% TOC threshold necessary for hydrocarbon expulsion. Both the Cow Branch Formation (Dan River basin) and the Cumnock Formation (Deep River basin, Sanford sub-basin) contain potential source rocks for oil, but they are more likely to have yielded natural gas. The organic material in these formations was derived primarily from terrestrial Type III woody (coaly) material and secondarily from lacustrine Type I (algal) material. Both the thermal alteration index (TAI) and vitrinite reflectance data (%Ro) indicate levels of thermal maturity suitable for generation of hydrocarbons. The genetic potential of the source rocks in these Triassic basins is moderate to high and many source rock sections have at least some potential for hydrocarbon generation. Some data for the Cumnock Formation indicate a considerably higher source rock potential than the basin average, with S1 + S2 data in the mid-20 mg HC/g sample range, and some hydrocarbons have been generated. This implies that the genetic potential for all of these strata may have been higher prior to the igneous activity. However, the intergranular porosity and permeability of the Triassic strata are low, which makes fractured reservoirs more attractive as drilling targets. In some places, gravity and magnetic surveys that are used to locate buried intrusive rock may identify local thermal sources that have facilitated gas generation. Alternatively, awareness of the distribution of large intrusive igneous bodies at depth may direct exploration into other areas, where thermal maturation is less than the limits of hydrocarbon destruction. Areas prospective for natural gas also contain large surficial clay resources and any gas discovered could be used as fuel for local industries that produce clay products (principally brick), as well as fuel for other local industries.

Aquifers survey in the context of source rocks exploitation: from baseline acquisition to long term monitoring

NASA Astrophysics Data System (ADS)

Garcia, Bruno; Rouchon, Virgile; Deflandre, Jean-Pierre

2017-04-01

Producing hydrocarbons from source rocks (like shales: a mix of clays, silts, carbonate and sandstone minerals containing matured organic matter, i.e. kerogen oil and gas, but also non-hydrocarbon various species of chemical elements including sometimes radioactive elements) requires to create permeability within the rock matrix by at least hydraulically fracturing the source rock. It corresponds to the production of hydrocarbon fuels that have not been naturally expelled from the pressurized matured source rock and that remain trapped in the porosity or/and kerogen porosity of the impermeable matrix. Azimuth and extent of developed fractures can be respectively determined and mapped by monitoring the associated induced microseismicity. This allows to have an idea of where and how far injected fluids penetrated the rock formation. In a geological context, aquifers are always present in the vicinity -or on fluid migration paths- of such shale formations: deep aquifers (near the shale formation) up to sub-surface and potable (surface) aquifers. Our purpose will be to track any unsuitable invasion or migration of chemicals specifies coming from matured shales of production fluids including both drilling and fracturing ones into aquifers. Our objective is to early detect and alarm of any anomaly to avoid any important environmental issue. The approach consists in deploying a specific sampling tool within a well to recover formation fluids and to run a panoply of appropriate laboratory tests to state on fluid characteristics. Of course for deep aquifers, such a characterization process may consider aquifer properties prior producing shale oil and gas, as they may contain naturally some chemical species present in the source rocks. One can also consider that a baseline acquisition could be justified in case of possible previous invasion of non-natural fluids in the formation under survey (due to any anthropogenic action at surface or in the underground). The paper aims at presenting the protocol and routine test we propose to make our early detection approach efficient for production of shale hydrocarbon fluids, in considering the source-rock reservoir itself, the aquifers, and also the chemical species present in the fluids that are used for hydraulic fracturing operations.

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.

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.

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.

Modal petrology of six soils from Apollo 16 double drive tube core 64002

NASA Technical Reports Server (NTRS)

Houck, K. J.

1982-01-01

Petrographic data form six size fractions for six samples of Apollo 16 drive tube section 64002 show source rocks similar to those of core 60009. Analysis of modal data from the 64002 core show that the upper three and lowest core soils are mature and have similar maturation histories, while the two middle soils are submature and have histories that are similar to each other but unlike those from the aforementioned soils. In all of these soils, mixing has dominated over reworking, and appears to involve two mature soils distinguished by differing source rocks and an immature, plagioclase-rich soil which is correlated with larger clasts of chalky, friable breccia. These breccias and the plagioclase-rich soil are tentatively associated with the Descartes Formation.

Publications - GMC 72 | Alaska Division of Geological & Geophysical Surveys

Science.gov Websites

DGGS GMC 72 Publication Details Title: Organic carbon, rock-eval pyrolysis, kerogen type, maturation , and vitrinite reflectance geochemical data, and a source rock evaluation for the Exxon OCS-Y-0280-1 publication sales page for more information. Bibliographic Reference Texaco, Inc., 1987, Organic carbon, rock

Formation resistivity as an indicator of oil generation in black shales

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

Hester, T.C.; Schmoker, J.W.

1987-08-01

Black, organic-rich shales of Late Devonian-Early Mississippi age are present in many basins of the North American craton and, where mature, have significant economic importance as hydrocarbon source rocks. Examples drawn from the upper and lower shale members of the Bakken Formation, Williston basin, North Dakota, and the Woodford Shale, Anadarko basin, Oklahoma, demonstrate the utility of formation resistivity as a direct in-situ indicator of oil generation in black shales. With the onset of oil generation, nonconductive hydrocarbons begin to replace conductive pore water, and the resistivity of a given black-shale interval increases from low levels associated with thermal immaturitymore » to values approaching infinity. Crossplots of a thermal-maturity index (R/sub 0/ or TTI) versus formation resistivity define two populations representing immature shales and shales that have generated oil. A resistivity of 35 ohm-m marks the boundary between immature and mature source rocks for each of the three shales studied. Thermal maturity-resistivity crossplots make possible a straightforward determination of thermal maturity at the onset of oil generation, and are sufficiently precise to detect subtle differences in source-rock properties. For example, the threshold of oil generation in the upper Bakken shale occurs at R/sub 0/ = 0.43-0.45% (TTI = 10-12). The threshold increases to R/sub 0/ = 0.48-0.51% (TTI = 20-26) in the lower Bakken shale, and to R/sub 0/ = 0.56-0.57% (TTI = 33-48) in the most resistive Woodford interval.« less

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.

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.

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

Schiefelbein, C.; Ho, T.

Changes in the physical properties (measured in terms of vitrinite reflectance, elemental analysis, and C-13 nuclear magnetic resonance) of an immature coal (0.46% R{sub o}) from Craig County, Colorado, that was thermally altered using hydrous pyrolysis were used to establish a correspondence between hydrous pyrolysis time/temperature reaction conditions and relative maturity (expressed in terms of vitrinite reflectance). This correspondence was used to determine the oil generation maturity limits for an immature hydrogen-rich (Type I fluorescing amorphous oil-prone kerogen) source rock from an offshore Congo well that was thermally altered using the same reaction conditions as applied to the immature coal.more » The resulting changes in the physical properties of the altered source rock, measured in terms of decreasing reactive carbon content (from Rock-Eval pyrolysis), were used to construct a hydrocarbon yield curve from which the relative maturity associated with the onset, main phase, and peak of oil generation was determined. Results, substantiated by anhydrous pyrolysis techniques, indicate that the source rock from Congo has a late onset of appreciable ({gt}10% transformation) oil generation (0.9% R{sub o} {plus minus} 0.1%), generates maximum quantities of oil from about 1.1 to 1.3% R{sub o}, and reaches the end (or peak) of the primary oil generating window at approximately 1.4% R{sub o} ({plus minus}0.1%) when secondary cracking reactions become important. However, the bottom of the oil window can be extended to about 1.6% R{sub o} because the heavy molecular weight degradation by-products (asphaltenes) that are not efficiently expelled from source rocks continue to degrade into progressively lower molecular weight hydrocarbons.« 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.

Oil geochemistry of the northern Llanos Basin, Colombia. A model for migration

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

Ramon, J.C.; Dzou, L.

1996-12-31

The chemical composition of 23 crude oils and one oil seep from Llanos Basin, Colombia were studied in detail by geochemical methods in order to understand their genetic relationship. A filling history model is proposed to explain the observed composition variations in Llanos Basin oils. Geochemical fingerprinting indicates that there are six families of crude oils. The biomarker compositions have been used to identify characteristics of the source rocks. The Llanos oils contain marine algal- derived {open_quotes}C30 steranes{close_quotes} (i.e., 24-n-propylcholestanes), which are diagnostic for oils generated from marine Cretaceous source rocks. A significant HC-contribution from a Tertiary source is alsomore » indicated by the presence of high concentration of the {open_quotes}flowering plant{close_quotes}-markers oleanane, bicadinanes and oleanoids. Low DBT/Phen, %sulfur values and high diasteranes concentration indicate that the source rock is clay-rich. Biomarker maturity parameters indicate a wide range of source-rock thermal maturities from early to late oil window. Heavy biodegradation has been particularly common among the first oils to fill reservoirs in central Llanos oil fields. The older altered heavy oils were mixed with a second pulse of oil explaining the wide range of oil gravities measured in the central Llanos Basin.« less

Classes of organic molecules targeted by a methanogenic microbial consortium grown on sedimentary rocks of various maturities

PubMed Central

Meslé, Margaux; Dromart, Gilles; Haeseler, Frank; Oger, Philippe M.

2015-01-01

Organic-rich shales are populated by methanogenic consortia that are able to degrade the fossilized organic matter into methane gas. To identify the organic fraction effectively degraded, we have sequentially depleted two types of organic-rich sedimentary rocks, shale, and coal, at two different maturities, by successive solvent extractions to remove the most soluble fractions (maltenes and asphaltenes) and isolate kerogen. We show the ability of the consortia to produce methane from all rock samples, including those containing the most refractory organic matter, i.e., the kerogen. Shales yielded higher methane production than lignite and coal. Mature rocks yielded more methane than immature rocks. Surprisingly, the efficiency of the consortia was not influenced by the removal of the easily biodegradable fractions contained in the maltenes and asphaltenes. This suggests that one of the limitations of organic matter degradation in situ may be the accessibility to the carbon and energy source. Indeed, bitumen has a colloidal structure that may prevent the microbial consortia from reaching the asphaltenes in the bulk rock. Solvent extractions might favor the access to asphaltenes and kerogen by modifying the spatial organization of the molecules in the rock matrix. PMID:26136731

The origin of oil in the Cretaceous succession from the South Pars Oil Layer of the Persian Gulf

NASA Astrophysics Data System (ADS)

Rahmani, Omeid; Aali, Jafar; Junin, Radzuan; Mohseni, Hassan; Padmanabhan, Eswaran; Azdarpour, Amin; Zarza, Sahar; Moayyed, Mohsen; Ghazanfari, Parviz

2013-07-01

The origin of the oil in Barremian-Hauterivian and Albian age source rock samples from two oil wells (SPO-2 and SPO-3) in the South Pars oil field has been investigated by analyzing the quantity of total organic carbon (TOC) and thermal maturity of organic matter (OM). The source rocks were found in the interval 1,000-1,044 m for the Kazhdumi Formation (Albian) and 1,157-1,230 m for the Gadvan Formation (Barremian-Hauterivian). Elemental analysis was carried out on 36 samples from the source rock candidates (Gadvan and Kazhdumi formations) of the Cretaceous succession of the South Pars Oil Layer (SPOL). This analysis indicated that the OM of the Barremian-Hauterivian and Albian samples in the SPOL was composed of kerogen Types II and II-III, respectively. The average TOC of analyzed samples is less than 1 wt%, suggesting that the Cretaceous source rocks are poor hydrocarbon (HC) producers. Thermal maturity and Ro values revealed that more than 90 % of oil samples are immature. The source of the analyzed samples taken from Gadvan and Kazhdumi formations most likely contained a content high in mixed plant and marine algal OM deposited under oxic to suboxic bottom water conditions. The Pristane/nC17 versus Phytane/nC18 diagram showed Type II-III kerogen of mixture environments for source rock samples from the SPOL. Burial history modeling indicates that at the end of the Cretaceous time, pre-Permian sediments remained immature in the Qatar Arch. Therefore, lateral migration of HC from the nearby Cretaceous source rock kitchens toward the north and south of the Qatar Arch is the most probable origin for the significant oils in the SPOL.

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

The thermal maturation degree of organic matter from source rocks revealed by wells logs including examples from Murzuk Basin, Libya

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

Negoita, V.; Gheorghe, A.

1995-08-01

The customary technique used to know the organic matter quantity per rock volume it as well as the organic matter maturation stage is based on geochemical analyses accomplished on a preselected number of samples and cuttings drawn from boreholes during the drilling period. But the same objectives can be approached without any extra cost using the continuous measurements of well logs recorded in each well from the ground surface to the total depth. During the diagenetic stage, the identification of potential source rocks out of which no hydrocarbon have been generated may be carried out using a well logging suitemore » including Gamma Ray Spectrometry, the Compensated Neutron/Litho Density combination and a Dual Induction/Sonic Log. During the catagenetic stage the onset of oil generation brings some important changes in the organic matter structure as well as in the fluid distribution throughout the pore space of source rocks. The replacement of electric conductive water by electric non-conductive hydrocarbons, together with water and oil being expelled from source rocks represent a process of different intensities dependent of time/temperature geohistory and kerogen type. The different generation and expulsion scenarios of hydrocarbons taking place during the catagenetic and metagenetic stages of source rocks are very well revealed by Induction and Laterolog investigations. Several crossplots relating vitrinite reflectance, total organic carbon and log-derived physical parameters are illustrated and discussed. The field applications are coming from Murzuk Basin, where Rompetrol of Libya is operating.« less

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.

Petroleum generation and migration in the Mesopotamian Basin and Zagros fold belt of Iraq: Results from a basin-modeling study

USGS Publications Warehouse

Pitman, Janet K.; Steinshouer, D.; Lewan, M.D.

2004-01-01

A regional 3-D total petroleum-system model was developed to evaluate petroleum generation and migration histories in the Mesopotamian Basin and Zagros fold belt in Iraq. The modeling was undertaken in conjunction with Middle East petroleum assessment studies conducted by the USGS. Regional structure maps, isopach and facies maps, and thermal maturity data were used as input to the model. The oil-generation potential of Jurassic source-rocks, the principal known source of the petroleum in Jurassic, Cretaceous, and Tertiary reservoirs in these regions, was modeled using hydrous pyrolysis (Type II-S) kerogen kinetics. Results showed that oil generation in source rocks commenced in the Late Cretaceous in intrashelf basins, peak expulsion took place in the late Miocene and Pliocene when these depocenters had expanded along the Zagros foredeep trend, and generation ended in the Holocene when deposition in the foredeep ceased. The model indicates that, at present, the majority of Jurassic source rocks in Iraq have reached or exceeded peak oil generation and most rocks have completed oil generation and expulsion. Flow-path simulations demonstrate that virtually all oil and gas fields in the Mesopotamian Basin and Zagros fold belt overlie mature Jurassic source rocks (vertical migration dominated) and are situated on, or close to, modeled migration pathways. Fields closest to modeled pathways associated with source rocks in local intrashelf basins were charged earliest from Late Cretaceous through the middle Miocene, and other fields filled later when compression-related traps were being formed. Model results confirm petroleum migration along major, northwest-trending folds and faults, and oil migration loss at the surface.

Maps showing thermal maturity of Upper Cretaceous marine shales in the Wind River Basin, Wyoming

USGS Publications Warehouse

Finn, Thomas M.; Pawlewicz, Mark J.

2013-01-01

The Wind River Basin is a large Laramide (Late Cretaceous through Eocene) structural and sedimentary basin that encompasses about 7,400 square miles in central Wyoming. The basin is bounded by the Washakie Range, Owl Creek, and southern Bighorn Mountains on the north, the Casper arch on the east and northeast, the Granite Mountains on the south, and the Wind River Range on the west. Important conventional and unconventional oil and gas resources have been discovered and produced from reservoirs ranging in age from Mississippian through Tertiary. It has been suggested that various Upper Cretaceous marine shales are the principal hydrocarbon source rocks for many of these accumulations. Numerous source rock studies of various Upper Cretaceous marine shales throughout the Rocky Mountain region have led to the conclusion that these rocks have generated, or are capable of generating, oil and (or) gas. With recent advances and success in horizontal drilling and multistage fracture stimulation there has been an increase in exploration and completion of wells in these marine shales in other Rocky Mountain Laramide basins that were traditionally thought of only as hydrocarbon source rocks. Important parameters that control hydrocarbon production from shales include: reservoir thickness, amount and type of organic matter, and thermal maturity. The purpose of this report is to present maps and a structural cross section showing levels of thermal maturity, based on vitrinite reflectance (Ro), for Upper Cretaceous marine shales in the Wind River Basin.

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

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

The origin, type and hydrocarbon generation potential of organic matter in a marine-continental transitional facies shale succession (Qaidam Basin, China).

PubMed

Wang, Guo-Cang; Sun, Min-Zhuo; Gao, Shu-Fang; Tang, Li

2018-04-26

This organic-rich shale was analyzed to determine the type, origin, maturity and depositional environment of the organic matter and to evaluate the hydrocarbon generation potential of the shale. This study is based on geochemical (total carbon content, Rock-Eval pyrolysis and the molecular composition of hydrocarbons) and whole-rock petrographic (maceral composition) analyses. The petrographic analyses show that the shale penetrated by the Chaiye 2 well contains large amounts of vitrinite and sapropelinite and that the organic matter within these rocks is type III and highly mature. The geochemical analyses show that these rocks are characterized by high total organic carbon contents and that the organic matter is derived from a mix of terrestrial and marine sources and highly mature. These geochemical characteristics are consistent with the results of the petrographic analyses. The large amounts of organic matter in the Carboniferous shale succession penetrated by the Chaiye 2 well may be due to good preservation under hypersaline lacustrine and anoxic marine conditions. Consequently, the studied shale possesses very good hydrocarbon generation potential because of the presence of large amounts of highly mature type III organic matter.

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 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.

D/H isotope ratios of kerogen, bitumen, oil, and water in hydrous pyrolysis of source rocks containing kerogen types I, II, IIS, and III

USGS Publications Warehouse

Schimmelmann, A.; Lewan, M.D.; Wintsch, R.P.

1999-01-01

Immature source rock chips containing different types of kerogen (I, II, IIS, III) were artificially matured in isotopically distinct waters by hydrous pyrolysis and by pyrolysis in supercritical water. Converging isotopic trends of inorganic (water) and organic (kerogen, bitumen, oil) hydrogen with increasing time and temperature document that water-derived hydrogen is added to or exchanged with organic hydrogen, or both, during chemical reactions that take place during thermal maturation. Isotopic mass-balance calculations show that, depending on temperature (310-381??C), time (12-144 h), and source rock type, between ca. 45 and 79% of carbon-bound hydrogen in kerogen is derived from water. Estimates for bitumen and oil range slightly lower, with oil-hydrogen being least affected by water-derived hydrogen. Comparative hydrous pyrolyses of immature source rocks at 330??C for 72 h show that hydrogen in kerogen, bitumen, and expelled oil/wax ranks from most to least isotopically influenced by water-derived hydrogen in the order IIS > II ~ III > I. Pyrolysis of source rock containing type II kerogen in supercritical water at 381 ??C for 12 h yields isotopic results that are similar to those from hydrous pyrolysis at 350??C for 72 h, or 330??C for 144 h. Bulk hydrogen in kerogen contains several percent of isotopically labile hydrogen that exchanges fast and reversibly with hydrogen in water vapor at 115??C. The isotopic equilibration of labile hydrogen in kerogen with isotopic standard water vapors significantly reduces the analytical uncertainty of D/H ratios when compared with simple D/H determination of bulk hydrogen in kerogen. If extrapolation of our results from hydrous pyrolysis is permitted to natural thermal maturation at lower temperatures, we suggest that organic D/H ratios of fossil fuels in contact with formation waters are typically altered during chemical reactions, but that D/H ratios of generated hydrocarbons are subsequently little or not affected by exchange with water hydrogen at typical reservoir conditions over geologic time. It will be difficult to utilize D/H ratios of thermally mature bulk or fractions of organic matter to quantitatively reconstruct isotopic aspects of paleoclimate and paleoenvironment. Hope resides in compound-specific D/H ratios of thermally stable, extractable biomarkers ('molecular fossils') that are less susceptible to hydrogen exchange with water-derived hydrogen.

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

Hydrocarbon Reservoir Identification in Volcanic Zone by using Magnetotelluric and Geochemistry Information

NASA Astrophysics Data System (ADS)

Firda, S. I.; Permadi, A. N.; Supriyanto; Suwardi, B. N.

2018-03-01

The resistivity of Magnetotelluric (MT) data show the resistivity mapping in the volcanic reservoir zone and the geochemistry information for confirm the reservoir and source rock formation. In this research, we used 132 data points divided with two line at exploration area. We used several steps to make the resistivity mapping. There are time series correction, crosspower correction, then inversion of Magnetotelluric (MT) data. Line-2 and line-3 show anomaly geological condition with Gabon fault. The geology structure from the resistivity mapping show the fault and the geological formation with the geological rock data mapping distribution. The geochemistry information show the maturity of source rock formation. According to core sample analysis information, we get the visual porosity for reservoir rock formation in several geological structure. Based on that, we make the geological modelling where the potential reservoir and the source rock around our interest area.

World class Devonian potential seen in eastern Madre de Dios basin

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

Peters, K.E.; Wagner, J.B.; Carpenter, D.G.

The Madre de Dios basin in northern Bolivia contains thick, laterally extensive, organic-rich Upper Devonian source rocks that reached the oil-generative stage of thermal maturity after trap and seal formation. Despite these facts, less than one dozen exploration wells have been drilled in the Madre de Dios basin, and no significant reserves have been discovered. Mobil geoscientists conducted a regional geological, geophysical, and geochemical study of the Madre de Dios basin. The work reported here was designed to assess the distribution, richness, depositional environment, and thermal maturity of Devonian source rocks. It is supported by data from over 3,000 mmore » of continuous slimhole core in two of the five Mobil wells in the basin. Source potential also exists in Cretaceous, Mississippian, and Permian intervals. The results of this study have important implications for future exploration in Bolivia and Peru.« less

Origin of a Tertiary oil from El Mahafir wildcat & geochemical correlation to some Muglad source rocks, Muglad basin, Sudan

NASA Astrophysics Data System (ADS)

Fadul Abul Gebbayin, Omer. I. M.; Zhong, Ningning; Ali Ibrahim, Gulfan; Ali Alzain, Mohamed

2018-01-01

Source rock screening analysis was performed on four stratigraphic units from the Muglad basin namely; Abu Gabra, Zarqa, Ghazal, and Baraka formations using pyrolysis and Vitrinite Reflectance (Ro). Results, integrated with the chromatographic and isotopic data from these rocks extracts and a Tertiary oil from El Mahafir-1 wild cat, were used to determine the origin of the oil. A good organic source within the Middle Abu Gabra Formation is observed in wells El Toor-6 and Neem Deep-1 (TOC, 1.0-2.0% & S2 5.0-10.0 mg C/g rock), with mixed kerogens I, II, & III, and thermally mature (% Ro = 0.74-0.94). The Campanian-Early Maastrichtian sequence, i.e. Zarqa and Ghazal formations are generally poor (TOC, <0.5% & S2 <2.5 mg C/g rock), dominated by type III kerogens, and immature at the studied locations. The Baraka shale nevertheless, is good at El Mahafir-1 well (avg. TOC 1.8% & S2 5.0-10.0 mg C/g rock) and fair at Timsah-1 well (Avg. TOC 0.69% & S2 2.5-5.0 mg C/g rock) with a Kerogen that is predominantly Sapropellic at the former, and an exclusively Humic at the later. The formation is mature at Timsah (% Ro = 0.77-1.16) and early mature at El Mahafir-1 (% Ro = 0.64-0.81). Consistent with the pyrolysis, chromatographic data of the rock extracts confirms the mixed source nature of the Abu Gabra Formation which consists of both algal [prominent LMW n-alkanes & elevated C27 steranes (36-47%)], as well as terrigenous material [higher diasterane/regular sterane ratios (0.50-0.56), abundant rearranged hopanes, & relatively high CPIs (1.22-1.9)], accumulated in an oxic to sub-oxic environment (Pr/Ph, 1.3-3.0). Abu Gabra further shows low C29/C30 hopanes (0.45-0.54), low C28 steranes (21-26%) with high Gammacerane index (20.3). In contrast, the environment during the Late Cretaceous was strongly reducing (Pr/Ph, 0.37-1.0), associated with a wide organic diversity, both in space and time and is characterized by dominant algal input at some areas and or stratigraphic intervals [Elevated tricyclics, higher C29/C30 hopanes (0.5-1.14), and relatively low Gammacerane indices (4.6-14.4)], while mixed with abundant terrigenous material at others. A direct correlation between El Mahafir oil and the Abu Gabra extracts is thus inferred based on: its mixed organic source nature, oxic to sub-oxic depositional environment (Pr/Ph 1.22), relatively low C29/C30 hopanes (0.54), low C28 steranes (29%), and a high gammacerane index (20.5). This is largely supported by the maturity modeling results which suggest generation is only from the Abu Gabra at this location.

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.

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.

Vitrinite equivalent reflectance of Silurian black shales from the Holy Cross Mountains, Poland

NASA Astrophysics Data System (ADS)

Smolarek, Justyna; Marynowski, Leszek; Spunda, Karol; Trela, Wiesław

2014-12-01

A number of independent methods have been used to measure the thermal maturity of Silurian rocks from the Holy Cross Mountains in Poland. Black shales are characterized by diverse TOC values varying from 0.24-7.85%. Having calculated vitrinite equivalent reflectance using three different formulas, we propose that the most applicable values for the Silurian rocks are those based on Schmidt et al. (2015) equation. Based on this formula, the values range from % 0.71 VReqvVLR (the vitrinite equivalent reflectance of the vitrinite-like macerals) to % 1.96 VReqvVLR. Alternative, complementary methods including Rock Eval pyrolysis and parameters based on organic compounds (CPI, Pr/n-C17, Ph/n-C18, MPI1, and MDR) from extracts did not prove adequate as universal thermal maturity indicators. We have confirmed previous suggestions that Llandovery shales are the most likely Silurian source rocks for the generation of hydrocarbons in the HCM.

Origin and migration of hydrocarbon gases and carbon dioxide, Bekes Basin, southeastern Hungary

USGS Publications Warehouse

Clayton, J.L.; Spencer, C.W.; Koncz, I.; Szalay, A.

1990-01-01

The Bekes Basin is a sub-basin within the Pannonian Basin, containing about 7000 m of post-Cretaceous sedimentary rocks. Natural gases are produced from reservoirs (Precambrian to Tertiary in age) located on structural highs around the margins of the basin. Gas composition and stable carbon isotopic data indicate that most of the flammable gases were derived from humic kerogen contained in source rocks located in the deep basin. The depth of gas generation and vertical migration distances were estimated using quantitative source rock maturity-carbon isotope relationships for methane compared to known Neogene source rock maturity-depth relationships in the basin. These calculations indicate that as much as 3500 m of vertical migration has occured in some cases. Isotopically heavy (> - 7 > 0) CO2 is the predominant species present in some shallow reservoirs located on basin-margin structural highs and has probably been derived via long-distance vertical and lateral migration from thermal decompositon of carbonate minerals in Mesozoic and older rocks in the deepest parts of the basin. A few shallow reservoirs (< 2000m) contain isotopically light (-50 to -60%0) methane with only minor amounts of C2+ homologs (< 3% v/v). This methane is probably mostly microbial in origin. Above-normal pressures, occuring at depths greater than 1800 m, are believed to be the principal driving force for lateral and vertical gas migration. These pressures are caused in part by active hydrocarbon generation, undercompaction, and thermal decomposition of carbonates. 

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.

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 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

The upper limit of maturity of natural gas generation and its implication for the Yacheng formation in the Qiongdongnan Basin, China

NASA Astrophysics Data System (ADS)

Su, Long; Zheng, Jianjing; Chen, Guojun; Zhang, Gongcheng; Guo, Jianming; Xu, Yongchang

2012-08-01

Vitrinite reflectance (VR, Ro%) measurements from residual kerogen of pyrolysis experiments were performed on immature Maoming Oil Shale substituted the samples for the gas-prone source rocks of Yacheng formation of the Qiongdongnan Basin in the South China Sea. The work was focused on determination an upper limit of maturity for gas generation (ULMGG) or "the deadline of natural gas generation". Ro values at given temperatures increase with increasing temperature and prolonged heating time, but ΔRo-value, given a definition of the difference of all values for VR related to higher temperature and adjacent lower temperature in open-system non-isothermal experiment at the heating rate of 20 °C/min, is better than VR. And representative examples are presented in this paper. It indicates that the range of natural gas generation for Ro in the main gas generation period is from 0.96% to 2.74%, in which ΔRo is in concordance with the stage for the onset and end of the main gas generation period corresponding to 0.02% up to 0.30% and from 0.30% up to 0.80%, respectively. After the main gas generation period of 0.96-2.74%, the evolution of VR approach to the ULMGG of the whole rock for type II kerogen. It is equal to 4.38% of VR, where the gas generation rates change little with the increase of maturation, ΔRo is the maximum of 0.83% corresponding to VR of 4.38%Ro, and the source rock does not nearly occur in the end process of hydrocarbon gas generation while Ro is over 4.38%. It shows that it is the same the ULMGG from the whole rock for type II kerogen as the method with both comparison and kinetics. By comparing to both the conclusions of pyrolysis experiments and the data of VR from the source rock of Yacheng formation on a series of selected eight wells in the shallow-water continental shelf area, it indicate that the most hydrocarbon source rock is still far from reaching ULMGG from the whole rock for type II kerogen. The source rock of Yacheng formation in the local areas of the deepwater continental slope basin have still preferable natural gas generative potential, especially in the local along the central depression belt (namely the Ledong, Lingshui, Songnan and Baodao sags from southwest to northeast) from the depocenter to both the margin and its adjacent areas. It help to evaluate the resource potential for oil and gas of the hydrocarbon source rock in the deepwater continental slope of the Qiongdongnan Basin or other basins with lower exploration in the northern of the South China Sea and to reduce the risk in exploration.

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).

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

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

USGS Publications Warehouse

Jiang, D.-X.; Wang, Y.-D.; Robbins, E.I.; Wei, J.; Tian, N.

2008-01-01

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

Mineralogical, chemical and K-Ar isotopic changes in Kreyenhagen Shale whole rocks and <2 μm clay fractions during natural burial and hydrous-pyrolysis experimental maturation

NASA Astrophysics Data System (ADS)

Clauer, N.; Lewan, M. D.; Dolan, M. P.; Chaudhuri, S.; Curtis, J. B.

2014-04-01

Progressive maturation of the Eocene Kreyenhagen Shale from the San Joaquin Basin of California was studied by combining mineralogical and chemical analyses with K-Ar dating of whole rocks and <2 μm clay fractions from naturally buried samples and laboratory induced maturation by hydrous pyrolysis of an immature outcrop sample. The K-Ar age decreases from 89.9 ± 3.9 and 72.4 ± 4.2 Ma for the outcrop whole rock and its <2 μm fraction, respectively, to 29.7 ± 1.5 and 21.0 ± 0.7 Ma for the equivalent materials buried to 5167 m. The natural maturation does not produce K-Ar ages in the historical sense, but rather K/Ar ratios of relative K and radiogenic 40Ar amounts resulting from a combined crystallization of authigenic and alteration of initial detrital K-bearing minerals of the rocks. The Al/K ratio of the naturally matured rocks is essentially constant for the entire depth sequence, indicating that there is no detectable variation in the crystallo-chemical organization of the K-bearing alumino-silicates with depth. No supply of K from outside of the rock volumes occurred, which indicates a closed-system behavior for it. Conversely, the content of the total organic carbon (TOC) content decreases significantly with burial, based on the progressive increasing Al/TOC ratio of the whole rocks. The initial varied mineralogy and chemistry of the rocks and their <2 μm fractions resulting from differences in detrital sources and depositional settings give scattered results that homogenize progressively during burial due to increased authigenesis, and concomitant increased alteration of the detrital material. Hydrous pyrolysis was intended to alleviate the problem of mineral and chemical variations in initially deposited rocks of naturally matured sequences. However, experiments on aliquots from thermally immature Kreyenhagen Shale outcrop sample did not mimic the results from naturally buried samples. Experiments conducted for 72 h at temperatures from 270 to 365 °C did not induce significant changes at temperatures above 310 °C in the mineralogical composition and K-Ar ages of the rock and <2 μm fraction. The K-Ar ages of the <2 μm fraction range from 72.4 ± 4.2 Ma in the outcrop sample to 62.4 ± 3.4 Ma in the sample heated the most at 365 °C for 216 h. This slight decrease in age outlines some loss of radiogenic 40Ar, together with losses of organic matter as oil, gas, and aqueous organic species. Large amounts of smectite layers in the illite-smectite mixed layers of the pyrolyzed outcrop <2 μm fraction remain during thermal experiments, especially above 310 °C. With no illitization detected above 310 °C, smectite appears to have inhibited rather than promoted generation of expelled oil from decomposition of bitumen. This hindrance is interpreted to result from bitumen impregnating the smectite interlayer sites and rock matrix. Bitumen remains in the <2 μm fraction despite leaching with H2O2. Its presence in the smectite interlayers is apparent by the inability of the clay fraction to fully expand or collapse once bitumen generation from the thermal decomposition of the kerogen is completed, and by almost invariable K-Ar ages confirming for the lack of any K supply and/or radiogenic 40Ar removal. This suggests that once bitumen impregnates the porosity of a progressively maturing source rock, the pore system is no longer wetted by water and smectite to illite conversion ceases. Experimental attempts to evaluate the smectite conversion to illite should preferentially use low-TOC rocks to avoid inhibition of the reaction by bitumen impregnation.

Effects of smectite on the oil-expulsion efficiency of the Kreyenhagen Shale, San Joaquin Basin, California, based on hydrous-pyrolysis experiments

USGS Publications Warehouse

Lewan, Michael D.; Dolan, Michael P.; Curtis, John B.

2014-01-01

The amount of oil that maturing source rocks expel is expressed as their expulsion efficiency, which is usually stated in milligrams of expelled oil per gram of original total organic carbon (TOCO). Oil-expulsion efficiency can be determined by heating thermally immature source rocks in the presence of liquid water (i.e., hydrous pyrolysis) at temperatures between 350°C and 365°C for 72 hr. This pyrolysis method generates oil that is compositionally similar to natural crude oil and expels it by processes operative in the subsurface. Consequently, hydrous pyrolysis provides a means to determine oil-expulsion efficiencies and the rock properties that influence them. Smectite in source rocks has previously been considered to promote oil generation and expulsion and is the focus of this hydrous-pyrolysis study involving a representative sample of smectite-rich source rock from the Eocene Kreyenhagen Shale in the San Joaquin Basin of California. Smectite is the major clay mineral (31 wt. %) in this thermally immature sample, which contains 9.4 wt. % total organic carbon (TOC) comprised of type II kerogen. Compared to other immature source rocks that lack smectite as their major clay mineral, the expulsion efficiency of the Kreyenhagen Shale was significantly lower. The expulsion efficiency of the Kreyenhagen whole rock was reduced 88% compared to that of its isolated kerogen. This significant reduction is attributed to bitumen impregnating the smectite interlayers in addition to the rock matrix. Within the interlayers, much of the bitumen is converted to pyrobitumen through crosslinking instead of oil through thermal cracking. As a result, smectite does not promote oil generation but inhibits it. Bitumen impregnation of the rock matrix and smectite interlayers results in the rock pore system changing from water wet to bitumen wet. This change prevents potassium ion (K+) transfer and dissolution and precipitation reactions needed for the conversion of smectite to illite. As a result, illitization only reaches 35% to 40% at 310°C for 72 hr and remains unchanged to 365°C for 72 hr. Bitumen generation before or during early illitization in these experiments emphasizes the importance of knowing when and to what degree illitization occurs in natural maturation of a smectite-rich source rock to determine its expulsion efficiency. Complete illitization prior to bitumen generation is common for Paleozoic source rocks (e.g., Woodford Shale and Retort Phosphatic Shale Member of the Phosphoria Formation), and expulsion efficiencies can be determined on immature samples by hydrous pyrolysis. Conversely, smectite is more common in Cenozoic source rocks like the Kreyenhagen Shale, and expulsion efficiencies determined by hydrous pyrolysis need to be made on samples that reflect the level of illitization at or near bitumen generation in the subsurface.

Terrigenous sediment supply along the Chilean continental margin: modern regional patterns of texture and composition

NASA Astrophysics Data System (ADS)

Lamy, F.; Hebbeln, D.; Wefer, G.

The regional patterns of texture and composition of modern continental slope and pelagic sediments off Chile between 25°S and 43°S reflect the latitudinal segmentation of geological, morphological, and climatic features of the continental hinterland. Grain-size characteristics are controlled by the grain-size of source rocks, the weathering regime, and mode of sediment input (eolian off northern Chile vs fluvial further south). Bulk-mineral assemblages reveal a low grade of maturity. Regional variations are governed by the source-rock composition of the different geological terranes and the relative source-rock contribution of the Coastal Range and Andes, as controlled by the continental hydrology. The relative abundance of clay minerals is also predominantly influenced by the source-rock composition and partly by continental smectite neoformation. Latitudinal variations of illite crystallinities along the Chilean continental slope (and west of the Peru-Chile trench) clearly reflect modifications of the weathering regime which correspond to the strong climatic zonation of Chile.

Transformation of juvenile Izu-Bonin-Mariana oceanic arc into mature continental crust: An example from the Neogene Izu collision zone granitoid plutons, Central Japan

NASA Astrophysics Data System (ADS)

Saito, Satoshi; Tani, Kenichiro

2017-04-01

Granitic rocks (sensulato) are major constituents of upper continental crust. Recent reviews reveal that the average composition of Phanerozoic upper continental crust is granodioritic. Although oceanic arcs are regarded as a site producing continental crust material in an oceanic setting, intermediate to felsic igneous rocks occurring in modern oceanic arcs are dominantly tonalitic to trondhjemitic in composition and have lower incompatible element contents than the average upper continental crust. Therefore, juvenile oceanic arcs require additional processes in order to get transformed into mature continental crust enriched in incompatible elements. Neogene granitoid plutons are widely exposed in the Izu Collision Zone in central Japan, where the northern end of the Izu-Bonin-Mariana (IBM) arc (juvenile oceanic arc) has been colliding with the Honshu arc (mature island arc) since Middle Miocene. The plutons in this area are composed of various types of granitoids ranging from tonalite to trondhjemite, granodiorite, monzogranite and granite. Three main granitoid plutons are distributed in this area: Tanzawa plutonic complex, Kofu granitic complex, and Kaikomagatake granitoid pluton. Tanzawa plutonic complex is dominantly composed of tonalite and trondhjemite and characterized by low concentration of incompatible elements and shows geochemical similarity with modern juvenile oceanic arcs. In contrast, Kofu granitic complex and Kaikomagatake granitoid pluton consists mainly of granodiorite, monzogranite and granite and their incompatible element abundances are comparable to the average upper continental crust. Previous petrogenetic studies on these plutons suggested that (1) the Tanzawa plutonic complex formed by lower crustal anatexis of juvenile basaltic rocks occurring in the IBM arc, (2) the Kofu granitic complex formed by anatexis of 'hybrid lower crust' comprising of both basaltic rocks of the IBM arc and metasedimentary rocks of the Honshu arc, and (3) the Kaikomagatake granitoid pluton formed by anatexis of 'hybrid lower crust' consisting of K-rich rear-arc crust of the IBM arc and metasedimentary rocks of the Honshu arc. These studies collectively suggest that the chemical diversity within the Izu Collision Zone granitoid plutons reflects the chemical variation of basaltic sources (i.e., across-arc chemical variation in the IBM arc) as well as variable contribution of the metasedimentary component in the source region. The petrogenetic models of the Izu Collision Zone granitoid plutons suggest that collision with another mature arc/continent, hybrid lower crust formation and subsequent hybrid source anatexis are required for juvenile oceanic arcs to produce granitoid magmas with enriched compositions. The Izu Collision Zone granitoid plutons provide an exceptional example of the collision-induced transformation from a juvenile oceanic arc to the mature continental crust.

Hydrocarbon source-rock evaluation - Solor Church Formation (middle Proterozoic, Keweenawan Supergroup), southeastern Minnesota

USGS Publications Warehouse

Hatch, J.R.; Morey, G.B.

1984-01-01

In the type section (Lonsdale 65-1 core, Rice County, Minnesota) the Solor Church Formation (Middle Proterozoic, Keweenawan Supergroup) consists primarily of reddish-brown mudstone and siltstone and pale reddish-brown sandstone. The sandstone and siltstone are texturally and mineralogically immature. Hydrocarbon source-rock evaluation of bluish-gray, greenish-gray and medium-dark-gray to grayish-black beds, which primarily occur in the lower 104 m (340 ft) of this core, shows: (1) the rocks have low organic carbon contents (<0.5 percent for 22 of 25 samples); (2) the organic matter is thermally very mature (Tmax = 494°C, sample 19) and is probably near the transition between the wet gas phase of catagenesis and metagenesis (dry gas zone); and (3) the rocks have minimal potential for producing additional hydrocarbons (genetic potential <0.30 mgHC/gm rock). Although no direct evidence exists from which to determine maximum depths of burial, the observed thermal maturity of the organic matter requires significantly greater depths of burial and(or) higher geothermal gradients. It is likely, at least on the St. Croix horst, that thermal alteration of the organic matter in the Solor Church took place relatively early, and that any hydrocarbons generated during this early thermal alteration were probably lost prior to deposition of the overlying Fond du Lac Formation (Middle Proterozoic, Keweenawan Supergroup).

Hydrocarbon source rock evaluation: Solor Church Formation. (Middle Proterozoic, Keweenawan Supergroup) southeastern Minnesota

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

Hatch, J.R.; Morey, G.B.

In the type section (Lonsdale 65-1 core, Rice County, Minnesota) the Solar Church Formation (Middle Proterozoic, Keweenawan Supergroup) consists primarily of reddish-brown mudstone and siltstone and pale reddish-brown sandstone. The sandstone and siltstone are texturally and mineralogically immature. Hydrocarbon source-rock evaluation of bluish-gray, greenish-gray and medium-dark-gray to grayish-black beds, which primarily occur in the lower 104 m (340 ft) of this core, shows: (1) the rocks have low organic carbon contents (<0.5% for 22 of 25 samples); (2) the organic matter is thermally very mature (T/sub max/ = 494/sup 0/C, sample 19) and is probably near the transition between themore » wet gas phase of catagenesis and metagenesis (dry gas zone); and (3) the rocks have minimal potential for producing additional hydrocarbons (genetic potential <0.30 mgHC/gm rock). Although no direct evidence exists from which to determine maximum depths of burial, the observed thermal maturity of the organic matter requires significantly greater depths of burial and(or) higher geothermal gradients. It is likely, at least on the St. Croix horst, that thermal alteration of the organic matter in the Solor Church took place relatively early, and that any hydrocarbons generated during this early thermal alteration were probably lost prior to deposition of the overlying Fond du Lac Formation (Middle Proterozoic, Keweenawan Supergroup). 5 figs., 2 tabs.« less

Peculiarities of convection and oil maturation in 3D porous medium structure.

NASA Astrophysics Data System (ADS)

Yurie Khachay, Professor; Mindubaev, Mansur

2017-04-01

An important estimation of oil source thickness productivity is to study the thermal influences of magmatic intrusions on the maturation of the organic matter. The heterogeneity of permeability distribution of the reservoir rock and respectively the convection structure provide temperature heterogeneity and different degree of maturity for the oil source material. A numerical algorithm for solving the problem of developed convection in two-dimensional and three-dimensional models of the porous medium, which consists of a system of Darcy equations, heat conduction with convection term and the continuity equation, is developed. Because of the effective values of the coefficients of thermal conductivity, heat capacity, viscosity and permeability of the medium depend from the temperature; the system of equations is nonlinear. For solution we used the dimensionless system of coordinates. For numerical solution we used the longitudinal cross-implicit scheme. The coordinates step for the 3D model had been used constant and equal to H/20, where H=1- dimensionless thickness of porous medium layer. As it is shown from the variants of numerical solution, by the stationary regime of developed convection because of the temperature heterogeneous distribution in the sedimentary reservoir the formation of oil source matter different degree of maturity is possible. That result is very significant for estimation of reservoirs oil-bearing The work was fulfilled by supporting of the Fund of UB RAS, project 1518532. Reference 1. Yurie Khachay and Mansur Mindubaev, 2016, Effect of convective transport in porous media on the conductions of organic matter maturation and generation of hydrocarbons in trap rocks complexes, Energy Procedia. 74 pp.79-83.

Petroleum geochemistry of oil and gas from Barbados: Implications for distribution of Cretaceous source rocks and regional petroleum prospectivity

USGS Publications Warehouse

Hill, R.J.; Schenk, C.J.

2005-01-01

Petroleum produced from the Barbados accretionary prism (at Woodbourne Field on Barbados) is interpreted as generated from Cretaceous marine shale deposited under normal salinity and dysoxic conditions rather than from a Tertiary source rock as previously proposed. Barbados oils correlate with some oils from eastern Venezuela and Trinidad that are positively correlated to extracts from Upper Cretaceous La Luna-like source rocks. Three distinct groups of Barbados oils are recognized based on thermal maturity, suggesting petroleum generation occurred at multiple levels within the Barbados accretionary prism. Biodegradation is the most significant process affecting Barbados oils resulting in increased sulfur content and decreased API gravity. Barbados gases are interpreted as thermogenic, having been co-generated with oil, and show mixing with biogenic gas is limited. Gas biodegradation occurred in two samples collected from shallow reservoirs at the Woodbourne Field. The presence of Cretaceous source rocks within the Barbados accretionary prism suggests that greater petroleum potential exists regionally, and perhaps further southeast along the passive margin of South America. Likewise, confirmation of a Cretaceous source rock indicates petroleum potential exists within the Barbados accretionary prism in reservoirs that are deeper than those from Woodbourne Field.

Thermal maturation history of the Wilcox group (Paleocene-Eocene), Texas: Results of regional-scale multi-1D modeling

USGS Publications Warehouse

Rowan, E.L.; Warwick, Peter D.; Pitman, Janet K.; Kennan, Lorcan; Pindell, James; Rosen, Norman C.

2007-01-01

The thermal maturation history of the Paleocene-Eocene Wilcox Group has been reconstructed based on burial history models of 53 wells in the Texas coastal plain. This modeling study has been conducted in conjunction with a geologically based assessment of the oil and gas resources in Cenozoic strata of the Gulf of Mexico coastal plain and state waters. In the onshore Texas coastal plain, coals and organic-rich shales, predominantly of terrestrial origin, within the Wilcox Group are the primary source of oil (Wenger et al., 1994) as well as a source of gas. The Wilcox, however, is modeled as a single unit, without subdivision into source rock and non-source rock intervals.Generation of oil from Type III kerogen within the Wilcox Group is modeled using hydrous pyrolysis reaction kinetic parameters (Lewan, M.D., written communication, 2006). Gas generation from Type III kerogen is represented using calculated Ro values. The models are calibrated with bottom hole temperature (BHT), and vitrinite reflectance (Ro %) data for the Wilcox Group. Ro data from near-coastal sites have been selected to minimize the possible effects of uplift and erosion and then composited to give a regional Rodepth trend.Model calculations for the study area, the onshore Texas coastal plain, indicate that downdip portions of the basal Wilcox had reached sufficient thermal maturity to generate hydrocarbons by early Eocene (~50 Ma). This relatively early maturation is explained by rapid sediment accumulation in the early Tertiary combined with the reaction kinetic parameters used in the models. Thermal maturation increases through time with increasing burial depth and temperature, gradually moving the maturation front updip. At present day, hydrocarbon generation is complete in the downdip Wilcox within the study area but is currently ongoing in the updip portions of the formation.

Shahejie-Shahejie/Guantao/Wumishan and Carboniferous/Permian Coal-Paleozoic Total Petroleum Systems in the Bohaiwan Basin, China (based on geologic studies for the 2000 World Energy Assessment Project of the U.S. Geological Survey)

USGS Publications Warehouse

Ryder, Robert T.; Qiang, Jin; McCabe, Peter J.; Nuccio, Vito F.; Persits, Felix

2012-01-01

This report discusses the geologic framework and petroleum geology used to assess undiscovered petroleum resources in the Bohaiwan basin province for the 2000 World Energy Assessment Project of the U.S. Geological Survey. The Bohaiwan basin in northeastern China is the largest petroleum-producing region in China. Two total petroleum systems have been identified in the basin. The first, the Shahejie&ndashShahejie/Guantao/Wumishan Total Petroleum System, involves oil and gas generated from mature pods of lacustrine source rock that are associated with six major rift-controlled subbasins. Two assessment units are defined in this total petroleum system: (1) a Tertiary lacustrine assessment unit consisting of sandstone reservoirs interbedded with lacustrine shale source rocks, and (2) a pre-Tertiary buried hills assessment unit consisting of carbonate reservoirs that are overlain unconformably by Tertiary lacustrine shale source rocks. The second total petroleum system identified in the Bohaiwan basin is the Carboniferous/Permian Coal–Paleozoic Total Petroleum System, a hypothetical total petroleum system involving natural gas generated from multiple pods of thermally mature coal beds. Low-permeability Permian sandstones and possibly Carboniferous coal beds are the reservoir rocks. Most of the natural gas is inferred to be trapped in continuous accumulations near the center of the subbasins. This total petroleum system is largely unexplored and has good potential for undiscovered gas accumulations. One assessment unit, coal-sourced gas, is defined in this total petroleum system.

Estimating organic maturity from well logs, Upper Cretaceous Austin Chalk, Texas Gulf coast

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

Hines, G.A.; Berg, R.R.

1990-09-01

The Austin Chalk is both a source rock for oil and a fractured reservoir, and the evaluation of its organic maturity from well logs could be an aid to exploration and production. Geochemical measurements have shown three zones of organic maturity for source materials: (1) an immature zone to depths of 6,000 ft, (2) a peak-generation and accumulation zone from 6,000 to 6,500 ft, and (3) a mature, expulsion and migration zone below 6,500 ft. The response of common well logs identifies these zones. True resistivity (R{sub t}) is low in the immature zone, increases to a maximum in themore » peak-generation zone, and decreases to intermediate values in the expulsion zone. Density and neutron porosities are different in the immature zone but are nearly equal in the peak generation and expulsion zones. Correlations with conventional core analyses indicate that R{sub t} values between 9 and 40 ohm-m in the expulsion zone reflect a moveable oil saturation of 10 to 20% in the rock matrix. The moveable saturation provides oil from the matrix to fractures and is essential for sustained oil production. Therefore, the evaluation of moveable oil from well logs could be important in exploration.« less

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.

Acoustic and Petrophysical Evolution of Organic-Rich Chalk Following Maturation Induced by Unconfined Pyrolysis

NASA Astrophysics Data System (ADS)

Shitrit, Omri; Hatzor, Yossef H.; Feinstein, Shimon; Vinegar, Harold J.

2017-12-01

Thermal maturation is known to influence the rock physics of organic-rich rocks. While most studies were performed on low-porosity organic-rich shales, here we examine the effect of thermal maturation on a high-porosity organic-rich chalk. We compare the physical properties of native state immature rock with the properties at two pyrolysis-simulated maturity levels: early-mature and over-mature. We further evaluate the applicability of results from unconfined pyrolysis experiments to naturally matured rock properties. Special attention is dedicated to the elastic properties of the organic phase and the influence of bitumen and kerogen contents. Rock physics is studied based on confined petrophysical measurements of porosity, density and permeability, and measurements of bedding-normal acoustic velocities at estimated field stresses. Geochemical parameters like total organic carbon (TOC), bitumen content and thermal maturation indicators are used to monitor variations in density and volume fraction of each phase. We find that porosity increases significantly upon pyrolysis and that P wave velocity decreases in accordance. Solids density versus TOC relationships indicate that the kerogen increases its density from 1.43 to 1.49 g/cc at the immature and early-mature stages to 2.98 g/cc at the over-mature stage. This density value is unusually high, although increase in S wave velocity and backscatter SEM images of the over-mature samples verify that the over-mature kerogen is significantly denser and stiffer. Using the petrophysical and acoustic properties, the elastic moduli of the rock are estimated by two Hashin-Shtrikman (HS)-based models: "HS + BAM" and "HS kerogen." The "HS + BAM" model is calibrated to the post-pyrolysis measurements to describe the mechanical effect of the unconfined pyrolysis on the rock. The absence of compaction in the pyrolysis process causes the post-pyrolysis samples to be extremely porous. The "HS kerogen" model, which simulates a kerogen-supported matrix, depicts a compacted version of the matrix and is believed to be more representative of a naturally matured rock. Rock physics analysis using the "HS kerogen" model indicates strong mechanical dominance of porosity and organic content, and only small maturity-associated effects.

Geochemical study of crude oils from the Xifeng oilfield of the Ordos basin, China

NASA Astrophysics Data System (ADS)

Duan, Y.; Wang, C. Y.; Zheng, C. Y.; Wu, B. X.; Zheng, G. D.

2008-01-01

The Xifeng oilfield is the largest newly-discovered oilfield in the Ordos basin. In order to determine the possible source, crude oils collected systematically from the oilfield and an adjacent oilfield have been examined isotopically and molecularly. The predominance of long-chain n-alkanes, high abundance of C 29 sterane, lower ratios of C 25/C 26 tricyclic terpane and C 25 tricyclic terpane/C 24 tetracyclic terpane and high C 24 tetracyclic terpane/(C 24 tetracyclic terpane + C 26 tricyclic terpanes ratio in the studied oils suggest generation from a source with mixed terrigenous and algal-bacterial organic matter. The presence of diterpenoid hydrocarbon with abietane skeletons is characteristic of the main contribution of higher land plants to the oils. The biomarker distributions in the oils show that they were formed under a weakly reducing freshwater environment. Molecular maturity parameters indicate that the crude oils are mature. The oil-source rock correlation and oil migration investigation suggest that the oils in the Xifeng oilfield originated from the source rocks of the Yanchang formation deposited in a shallow to deep freshwater lacustrine environment, especially Chang-7 source rocks. The data from the distribution of pyrrolic nitrogen compounds indicate that the charging direction of the Chang-8 crude oils is mainly from the Zhuang 12 well northeast of the oilfield toward the southwest. This direction of oil migration is consistent with that indicated by regional geological data.

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 Undiscovered Oil and Gas Resources of the Uinta-Piceance Province of Colorado and Utah, 2002

USGS Publications Warehouse

,

2002-01-01

The U.S. Geological Survey (USGS) recently completed an assessment of the undiscovered oil and gas potential of the UintaPiceance Province of northwestern Colorado and northeastern Utah (fig. 1). The assessment of the Uinta-Piceance Province is geology based and uses the Total Petroleum System concept. The geologic elements of Total Petroleum Systems include hydrocarbon source rocks (source rock maturation, hydrocarbon generation and migration), reservoir rocks (sequence stratigraphy, petrophysical properties), and hydrocarbon traps (trap formation and timing). Using this geologic framework, the USGS defined five Total Petroleum Systems and 20 Assessment Units within these Total Petroleum Systems, and quantitatively estimated the undiscovered oil and gas resources within each Assessment Unit (table 1).

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).

Evaluation of hydrocarbon potential

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

Cashman, P.H.; Trexler, J.H. Jr.

1992-09-30

Task 8 is responsible for assessing the hydrocarbon potential of the Yucca Mountain vincinity. Our main focus is source rock stratigraphy in the NTS area in southern Nevada. (In addition, Trexler continues to work on a parallel study of source rock stratigraphy in the oil-producing region of east central Nevada, but this work is not funded by Task 8.) As a supplement to the stratigraphic studies, we are studying the geometry and kinematics of deformation at NTS, particularly as these pertain to reconstructing Paleozoic stratigraphy and to predicting the nature of the Late Paleozoic rocks under Yucca Mountain. Our stratigraphicmore » studies continue to support the interpretation that rocks mapped as the {open_quotes}Eleana Formation{close_quotes} are in fact parts of two different Mississippian units. We have made significant progress in determining the basin histories of both units. These place important constraints on regional paleogeographic and tectonic reconstructions. In addition to continued work on the Eleana, we plan to look at the overlying Tippipah Limestone. Preliminary TOC and maturation data indicate that this may be another potential source rock.« 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.

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.

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 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.

Eastern Madre de Dios Devonian generated large volumes of oil

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

Peters, K.E.; Wagner, J.B.; Carpenter, D.G.

This is the second part of an article giving details of a Mobil Corp. regional geological, geophysical, and geochemical study of the Madre de Dios basin. The assessment covered the distribution, richness, depositional environment, and thermal maturity of Devonian source rocks.

Thermal maturity patterns of Cretaceous and Tertiary rocks, San Juan Basin, Colorado and New Mexico

USGS Publications Warehouse

Law, B.E.

1992-01-01

Horizontal and vertical thermal maturity patterns and time-temperature modeling indicate that the high levels of thermal maturity in the northern part of the basin are due to either: 1) convective heat transfer associated with a deeply buried heat source located directly below the northern part of the basin or 2) the circulation of relatively hot fluids into the basin from a heat source north of the basin located near the San Juan Mountains. Time-temperature and kinetic modeling of nonlinear Rm profiles indicates that present-day heat flow is insufficient to account for the measured levels of thermal maturity. Furthermore, in order to match nonlinear Rm profiles, it is necessary to assign artifically high thermal-conductivity values to some of the stratigraphic units. These unrealistically high thermal conductivities are interpreted as evidence of convective heat transfer. -from Author

Stabilization of kerogen thermal maturation: Evidence from geothermometry and burial history reconstruction, Niobrara Limestone, Berthoud oil field, western Denver Basin, Colorado

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

Barker, C.E.; Crysdale, B.L.

1990-05-01

The burial history of this fractured Niobrara Limestone reservoir and source rock offers a setting for studying the stabilization of thermal maturity because soon after peak temperature of approximately 100{degree}C was reached, exhumation lowered temperature to about 60-70{degree}C. Vitrinite reflectance (Rm = 0.6-0.7%) and published clay mineralogy data from the Niobrara Limestone indicate that peak paleotemperature was approximately 100{degree}C. Fluid inclusion data also indicate oil migration occurred at 100{degree}C. Burial history reconstruction indicates 100{degree}C was reached in the Niobrara Limestone only during minimum burial, which occurred at 70 Ma and 8000 ft depth. However, erosion beginning at 70 Ma andmore » continuing until 50 Ma removed over 3,000 ft of rock. This depth of erosion agrees with an Rm of 0.4% measured in surface samples of the Pierre Shale. The exhumation of the reservoir decreased temperature by about 30{degree}C to near the corrected bottom-hole temperature of 50-70{degree}C. Lopatin time-temperature index (TTI) analysis suggests the Niobrara Limestone as a source rock matured to the oil generation stage (TTI = 10) about 25 Ma, significantly later than maximum burial, and after exhumation caused cooling. The Lopatin TTI method in this case seems to overestimate the influence of heating time. If time is an important factor, thermal maturity should continue to increase after peak burial and temperature so that vitrinite reflectance will not be comparable to peak paleotemperatures estimated from geothermometers set at near-peak temperature and those estimated from burial history reconstruction. The agreement between geothermometry and the burial history reconstruction in Berthoud State 4 suggests that the influence of heating time must be small. The elapsed time available at near peak temperatures was sufficient to allow stabilization of thermal maturation in this case.« less

Lower Cody Shale (Niobrara equivalent) in the Bighorn Basin, Wyoming and Montana: thickness, distribution, and source rock potential

USGS Publications Warehouse

Finn, Thomas M.

2014-01-01

The lower shaly member of the Cody Shale in the Bighorn Basin, Wyoming and Montana is Coniacian to Santonian in age and is equivalent to the upper part of the Carlile Shale and basal part of the Niobrara Formation in the Powder River Basin to the east. The lower Cody ranges in thickness from 700 to 1,200 feet and underlies much of the central part of the basin. It is composed of gray to black shale, calcareous shale, bentonite, and minor amounts of siltstone and sandstone. Sixty-six samples, collected from well cuttings, from the lower Cody Shale were analyzed using Rock-Eval and total organic carbon analysis to determine the source rock potential. Total organic carbon content averages 2.28 weight percent for the Carlile equivalent interval and reaches a maximum of nearly 5 weight percent. The Niobrara equivalent interval averages about 1.5 weight percent and reaches a maximum of over 3 weight percent, indicating that both intervals are good to excellent source rocks. S2 values from pyrolysis analysis also indicate that both intervals have a good to excellent source rock potential. Plots of hydrogen index versus oxygen index, hydrogen index versus Tmax, and S2/S3 ratios indicate that organic matter contains both Type II and Type III kerogen capable of generating oil and gas. Maps showing the distribution of kerogen types and organic richness for the lower shaly member of the Cody Shale show that it is more organic-rich and more oil-prone in the eastern and southeastern parts of the basin. Thermal maturity based on vitrinite reflectance (Ro) ranges from 0.60–0.80 percent Ro around the margins of the basin, increasing to greater than 2.0 percent Ro in the deepest part of the basin, indicates that the lower Cody is mature to overmature with respect to hydrocarbon generation.

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.

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.

Basin-centered gas evaluated in Dnieper-Donets basin, Donbas foldbelt, Ukraine

USGS Publications Warehouse

Law, B.E.; Ulmishek, G.F.; Clayton, J.L.; Kabyshev, B.P.; Pashova, N.T.; Krivosheya, V.A.

1998-01-01

An evaluation of thermal maturity, pore pressures, source rocks, reservoir quality, present-day temperatures, and fluid recovery data indicates the presence of a large basin-centered gas accumulation in the Dnieper-Donets basin (DDB) and Donbas foldbelt (DF) of eastern Ukraine (Fig. 1).

Changes in porosity and organic matter phase distribution monitored by NMR relaxometry following hydrous pyrolysis under uniaxial confinement

USGS Publications Warehouse

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

2013-01-01

Artificial maturation methods are used to induce changes in source rock thermal maturity without the uncertainties that arise when comparing natural samples from a particular basin that often represent different levels of maturation and different lithofacies. A novel uniaxial confinement clamp was used on Woodford Shale cores in hydrous pyrolysis experiments to limit sample expansion by simulating the effect of overburden present during thermal maturation in natural systems. These samples were then subjected to X-ray computed tomography (X-CT) imaging and low-field nuclear magnetic resonance (LF-NMR) relaxometry measurements. LF-NMR relaxometry is a noninvasive technique commonly used to measure porosity and pore-size distributions in fluid-filled porous media, but may also measure hydrogen present in hydrogen-bearing organic solids. Standard T1 and T2 relaxation distributions were determined and two dimensional T1-T2 correlation measurements were performed on the Woodford Shale cores. The T1-T2 correlations facilitate resolution of organic phases in the system. The changes observed in NMR-relaxation times correspond to bitumen and lighter hydrocarbon production that occur as source rock organic matter matures. The LF-NMR porosities of the core samples at maximum oil generation are significantly higher than porosities measured by other methods. This discrepancy likely arises from the measurement of highly viscous organic constituents in addition to fluid-filled porosity. An unconfined sample showed shorter relaxation times and lower porosity. This difference is attributed to the lack of fractures observed in the unconfined sample by X-CT.

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

Assessment of hydrocarbon source rock potential of Polish bituminous coals and carbonaceous shales

USGS Publications Warehouse

Kotarba, M.J.; Clayton, J.L.; Rice, D.D.; Wagner, M.

2002-01-01

We analyzed 40 coal samples and 45 carbonaceous shale samples of varying thermal maturity (vitrinite reflectance 0.59% to 4.28%) from the Upper Carboniferous coal-bearing strata of the Upper Silesian, Lower Silesian, and Lublin basins, Poland, to evaluate their potential for generation and expulsion of gaseous and liquid hydrocarbons. We evaluated source rock potential based on Rock-Eval pyrolysis yield, elemental composition (atomic H/C and O/C), and solvent extraction yields of bitumen. An attempt was made to relate maceral composition to these source rock parameters and to composition of the organic matter and likely biological precursors. A few carbonaceous shale samples contain sufficient generation potential (pyrolysis assay and elemental composition) to be considered potential source rocks, although the extractable hydrocarbon and bitumen yields are lower than those reported in previous studies for effective Type III source rocks. Most samples analysed contain insufficient capacity for generation of hydrocarbons to reach thresholds required for expulsion (primary migration) to occur. In view of these findings, it is improbable that any of the coals or carbonaceous shales at the sites sampled in our study would be capable of expelling commercial amounts of oil. Inasmuch as a few samples contained sufficient generation capacity to be considered potential source rocks, it is possible that some locations or stratigraphic zones within the coals and shales could have favourable potential, but could not be clearly delimited with the number of samples analysed in our study. Because of their high heteroatomic content and high amount of asphaltenes, the bitumens contained in the coals are less capable of generating hydrocarbons even under optimal thermal conditions than their counterpart bitumens in the shales which have a lower heteroatomic content. Published by Elsevier Science B.V.

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

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.

Experimental controls on D/H and 13C/12C ratios of kerogen, bitumen and oil during hydrous pyrolysis

USGS Publications Warehouse

Schimmelmann, A.; Boudou, J.-P.; Lewan, M.D.; Wintsch, R.P.

2001-01-01

Large isotopic transfers between water-derived hydrogen and organic hydrogen occurred during hydrous pyrolysis experiments of immature source rocks, in spite of only small changes in organic 13C/12C. Experiments at 330 ??C over 72 h using chips or powder containing kerogen types I and III identify the rock/water ratio as a main factor affecting ????D for water and organic hydrogen. Our data suggest that larger rock permeability and smaller rock grain size increase the H-isotopic transfer between water-derived hydrogen and thermally maturing organic matter. Increasing hydrostatic pressure may have a similar effect, but the evidence remains inconclusive. ?? 2001 Elsevier Science Ltd. All rights reserved.

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

Marine petroleum source rocks and reservoir rocks of the Miocene Monterey Formation, California, U.S.A

USGS Publications Warehouse

Isaacs, C.M.

1988-01-01

The Miocene Monterey Formation of California, a biogenous deposit derived mainly from diatom debris, is important both as a petroleum source and petroleum reservoir. As a source, the formation is thought to have generated much of the petroleum in California coastal basins, which are among the most prolific oil provinces in the United States. Oil generated from the Monterey tends to be sulfur-rich and heavy (<20° API), and has chemical characteristics that more closely resemble immature source extracts than "normal" oil. Thermal-maturity indicators in Monterey kerogens appear to behave anomalously, and several lines of evidence indicate that the oil is generated at lower than expected levels of organic metamorphism. As a reservoir, the Monterey is important due both to conventional production from permeable sandstone beds and to fracture production from fine-grained rocks with low matrix permeability. Fractured reservoirs are difficult to identify, and conventional well-log analysis has not proven to be very useful in exploring for and evaluating these reservoirs. Lithologically similar rocks are broadly distributed throughout the Circum-Pacific region, but their petroleum potential is unlikely to be realized without recognition of the distinctive source and reservoir characteristics of diatomaceous strata and their diagenetic equivalents.

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.

An integrated study of geochemistry and mineralogy of the Upper Tukau Formation, Borneo Island (East Malaysia): Sediment provenance, depositional setting and tectonic implications

NASA Astrophysics Data System (ADS)

Nagarajan, Ramasamy; Roy, Priyadarsi D.; Kessler, Franz L.; Jong, John; Dayong, Vivian; Jonathan, M. P.

2017-08-01

An integrated study using bulk chemical composition, mineralogy and mineral chemistry of sedimentary rocks from the Tukau Formation of Borneo Island (Sarawak, Malaysia) is presented in order to understand the depositional and tectonic settings during the Neogene. Sedimentary rocks are chemically classified as shale, wacke, arkose, litharenite and quartz arenite and consist of quartz, illite, feldspar, rutile and anatase, zircon, tourmaline, chromite and monazite. All of them are highly matured and were derived from a moderate to intensively weathered source. Bulk and mineral chemistries suggest that these rocks were recycled from sedimentary to metasedimentary source regions with some input from granitoids and mafic-ultramafic rocks. The chondrite normalized REE signature indicates the presence of felsic rocks in the source region. Zircon geochronology shows that the samples were of Cretaceous and Triassic age. Comparable ages of zircon from the Tukau Formation sedimentary rocks, granitoids of the Schwaner Mountains (southern Borneo) and Tin Belt of the Malaysia Peninsular suggest that the principal provenance for the Rajang Group were further uplifted and eroded during the Neogene. Additionally, presence of chromian spinels and their chemistry indicate a minor influence of mafic and ultramafic rocks present in the Rajang Group. From a tectonic standpoint, the Tukau Formation sedimentary rocks were deposited in a passive margin with passive collisional and rift settings. Our key geochemical observation on tectonic setting is comparable to the regional geological setting of northwestern Borneo as described in the literature.

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.

Hydrocarbon source potential and maturation in eocene New Zealand vitrinite-rich coals: Insights from traditional coal analyses, and Rock-Eval and biomarker studies

USGS Publications Warehouse

Newman, J.; Price, L.C.; Johnston, J.H.

1997-01-01

The results of traditional methods of coal characterisation (proximate, specific energy, and ultimate analyses) for 28 Eocene coal samples from the West Coast of New Zealand correspond well with biomarker ratios and Rock-Eval analyses. Isorank variations in vitrinite fluorescence and reflectance recorded for these samples are closely related to their volatile-matter content, and therefore indicate that the original vitrinite chemistry is a key controlling factor. By contrast, the mineral-matter content and the proportion of coal macerals present appear to have had only a minor influence on the coal samples' properties. Our analyses indicate that a number of triterpane biomarker ratios show peak maturities by high volatile bituminous A rank; apparent maturities are then reversed and decline at the higher medium volatile bituminous rank. The Rock-Eval S1 +S2 yield also maximizes by high volatile bituminous A rank, and then declines; however, this decline is retarded in samples with the most hydrogen-rich (perhydrous) vitrinites. These Rock-Eval and biomarker trends, as well as trends in traditional coal analyses, are used to define the rank at which expulsion of gas and oil occurs from the majority of the coals. This expulsion commences at high volatile A bituminous rank, and persists up to the threshold of medium volatile bituminous rank (c. 1.1% Ro ran. or 1.2% Ro max in this sample set), where marked hydrocarbon expulsion from perhydrous vitrinites begins to take place.

Geochemistry, palynology, and regional geology of worldclass Upper Devonian source rocks in the Madre de Dios basin, Bolivia

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

Peters, K.E.; Conrad, K.T.; Carpenter, D.G.

Recent exploration drilling indicates the existence of world-class source rock in the Madre de Dios basin, Bolivia. In the Pando-1 X and -2X wells, over 200 m of poorly bioturbated, organic-rich (TOC = 3-16 wt.%) prodelta to shelf mudstones in the Frasnian-Famennian Tomachi Formation contain oil-prone organic matter (hydrogen index = 400-600 mg HC/g TOC). Our calculated source prolificity indices for this interval in these wells (SPI = 15-18 tons of hydrocarbons per square meter of source rock) exceed that for the Upper Jurassic in Central Saudi Arabia. The Tomachi interval is lithologically equivalent to the Colpacucho Formation in themore » northern Altiplano, the Iquiri Formation in the Cordillera Oriental, and is coeval with other excellent source rocks in North America, Africa, and Eurasia. All of these rocks were deposited under conditions favorable for accumulation of organic matter, including a global highstand and high productivity. However, the Madre de Dios basin was situated at high latitude during the Late Devonian and some of the deposits are interpreted to be of glacial origin, indicating conditions not generally associated with organic-rich deposition. A biomarker and palynological study of Upper Devonian rocks in the Pando-1X well suggests deposition under conditions similar to certain modern fjords. High productivity resulted in preservation of abundant organic matter in the bottom sediments despite a cold, toxic water column. Low-sulfur crude oil produced from the Pando-1X well is geochemically similar to, but more mature than, extracts from associated organic-rich Tomachi samples, and was generated from deeper equivalents of these rocks.« less

Low-maturity Kulthieth Formation coal: A possible source of polycyclic aromatic hydrocarbons in benthic sediment of the northern Gulf of Alaska

USGS Publications Warehouse

Van Kooten, G. K.; Short, J.W.; Kolak, J.J.

2002-01-01

The successful application of forensic geology to contamination studies involving natural systems requires identification of appropriate endmembers and an understanding of the geologic setting and processes affecting the systems. Studies attempting to delineate the background, or natural, source for hydrocarbon contamination in Gulf of Alaska (GOA) benthic sediments have invoked a number of potential sources, including seep oils, source rocks, and coal. Oil seeps have subsequently been questioned as significant sources of hydrocarbons present in benthic sediments of the GOA in part because the pattern of relative polycyclic aromatic hydrocarbon (PAH) abundance characteristic of benthic GOA sediments is inconsistent with patterns typical of weathered seep oils. Likewise, native coal has been dismissed in part because ratios of labile hydrocarbons to total organic carbon (e.g. PAH:TOC) for Bering River coal field (BRCF) sources are too low - i.e. the coals are over mature - to be consistent with GOA sediments. We present evidence here that native coal may have been prematurely dismissed, because BRCF coals do not adequately represent the geochemical signatures of coals elsewhere in the Kulthieth Formation. Contrary to previous thought, Kulthieth Formation coals east of the BRCF have much higher PAH: TOC ratios, and the patterns of labile hydrocarbons in these low thermal maturity coals suggest a possible genetic relationship between Kulthieth Formation coals and nearby oil seeps on the Sullivan anticline. Analyses of low-maturity Kulthieth Formation coal indicate the low maturity coal is a significant source of PAH. Source apportionment models that neglect this source will underestimate the contribution of native coals to the regional background hydrocarbon signature. ?? Published by Elsevier Science Ltd. on behalf of AEHS.

Modelling the role of magmatic intrusions in the post-breakup thermal evolution of Volcanic Passive Margins

NASA Astrophysics Data System (ADS)

Peace, Alexander; McCaffrey, Ken; Imber, Jonny; van Hunen, Jeroen; Hobbs, Richard; Gerdes, Keith

2013-04-01

Passive margins are produced by continental breakup and subsequent seafloor spreading, leaving a transition from continental to oceanic crust. Magmatism is associated with many passive margins and produces diagnostic criteria that include 1) abundant breakup related magmatism resulting in a thick igneous crust, 2) a high velocity zone in the lower crust and 3) seaward dipping reflectors (SDRs) in seismic studies. These Volcanic Passive Margins (VPMs) represent around 75% of the Atlantic passive margins, but beyond this high level description, these magma-rich settings remain poorly understood and present numerous challenges to petroleum exploration. In VPMs the extent to which the volume, timing, location and emplacement history of magma has played a role in controlling heat flow and thermal evolution during margin development remains poorly constrained. Reasons for this include; 1) paucity of direct heat flow and thermal gradient measurements at adequate depth ranges across the margins, 2) poor onshore exposure 3) highly eroded flood basalts and 4) poor seismic imaging beneath thick offshore basalt sequences. As a result, accurately modelling the thermal history of the basins located on VPMs is challenging, despite the obvious importance for determining the maturation history of potential source rocks in these settings. Magmatism appears to have affected the thermal history of the Vøring Basin on the Norwegian VPM, in contrast the effects on the Faeroe-Shetland Basin was minimal. The more localised effects in the Faeroe-Shetland Basin compared to Vøring Basin may be explained by the fact that the main reservoir sandstones appear to be synchronous with thermal uplift along the basin margin and pulsed volcanism, indicating that the bulk of the magmatism occurred at the basin extremities in the Faeroe-Shetland Basin, where its effect on source maturation was lessened. Our hypothesis is that source maturation occurs as a result of regional temperature and pressure increases, and the effects of even a large singular magmatic event are small beyond the immediate vicinity, therefore quantifying cumulative regional heat flow is of utmost importance. The apparently complex relationships between source rock maturation and magmatism are not limited to the north-east Atlantic margins. Other VPMs of interest include the regions between West Greenland and Eastern Canada (Labrador Sea, Davis Strait and Baffin Bay), East Greenland, NW Australia, Western India and segments of the Western African and Eastern South American margins. This project utilises 1D numerical modelling of magmatic intrusions into a sedimentary column to gain an understanding into the thermal influence of post-breakup magmatic activity on source rock maturation in representative VPMs. Considerations include the timing, periodicity of intrusions, thickness, spacing and background heat in the basin.

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.

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).

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.

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.

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.

New insights on timing of oil and gas generation in the central Gulf Coast interior zone based on hydrous-pyrolysis kinetic parameters

USGS Publications Warehouse

Lewan, Michael D.; Dutton, Shirley P.; Ruppel, Stephen C.; Hentz, Tucker F.

2002-01-01

Timing of oil and gas generation from Turonian and Smackover source rocks in the central Gulf CoastInterior Zone was determined in one-dimensional burial-history curves (BHCs) using hydrous-pyrolysis kinetic parameters. The results predict that basal Smackover source-rock intervals with Type-IIS kerogen completed oil generation between 121 and 99 Ma, and Turonian source-rocks with Type-II kerogen remain immature over most of the same area. The only exception to the latter occurs in the northwestern part of the Mississippi salt basin, where initial stages of oil generation have started as a result of higher thermal gradients. This maturity difference between Turonian and Smackover source rocks is predicted with present-day thermal gradients. Predicted oil generation prior to the Sabine and Monroe uplifts suggests that a significant amount of the oil emplaced in Cretaceous reservoirs of these uplifts would have been lost during periods of erosion. Hydrous-pyrolysis kineticparameters predict that cracking of Smackover oil to gas started 52 Ma, which postdates major uplift and erosional events of the Sabine and Monroe uplifts. This generated gas would accumulate and persist in these uplift areas as currently observed. The predicted timing of oil and gas generation with hydrous-pyrolysis kinetic parameters is in accordance with the observed scarcity of oil from Turonian source rocks, predominance of gas accumulations on the Sabine and Monroe uplifts, and predominance of oil accumulations along the northern rim of the Interior Zone.

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.

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.

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.

The nature of porosity in organic-rich mudstones of the Upper Jurassic Kimmeridge Clay Formation, North Sea, offshore United Kingdom

USGS Publications Warehouse

Fishman, Neil S.; Hackley, Paul C.; Lowers, Heather; Hill, Ronald J.; Egenhoff, Sven O.; Eberl, Dennis D.; Blum, Alex E.

2012-01-01

Analyses of organic-rich mudstones from wells that penetrated the Upper Jurassic Kimmeridge Clay Formation, offshore United Kingdom, were performed to evaluate the nature of both organic and inorganic rock constituents and their relation to porosity in this world-class source rock. The formation is at varying levels of thermal maturity, ranging from immature in the shallowest core samples to mature in the deepest core samples. The intent of this study was to evaluate porosity as a function of both organic macerals and thermal maturity. At least four distinct types of organic macerals were observed in petrographic and SEM analyses and they all were present across the study area. The macerals include, in decreasing abundance: 1) bituminite admixed with clays; 2) elongate lamellar masses (alginite or bituminite) with small quartz, feldspar, and clay entrained within it; 3) terrestrial (vitrinite, fusinite, semifusinite) grains; and 4) Tasmanites microfossils. Although pores in all maceral types were observed on ion-milled surfaces of all samples, the pores (largely nanopores with some micropores) vary as a function of maceral type. Importantly, pores in the macerals do not vary systematically as a function of thermal maturity, insofar as organic pores are of similar size and shape in both the immature and mature Kimmeridge rocks. If any organic pores developed during the generation of hydrocarbons, they were apparently not preserved, possibly because of the highly ductile nature of much of the rock constituents of Kimmeridge mudstones (clays and organic material). Inorganic pores (largely micropores with some nanopores) have been observed in all Kimmeridge mudstones. These pores, particularly interparticle (i.e., between clay platelets), and intraparticle (i.e., in framboidal pyrite, in partially dissolved detrital K-feldspar, and in both detrital and authigenic dolomite) are noteworthy because they compose much of the observable porosity in the shales in both immature and mature samples. The absence of a systematic increase in organic porosity as a function of either maceral type or thermal maturity indicates that such porosity was probably unrelated to hydrocarbon generation. Instead, much of the porosity within mudstones of the Kimmeridge appears to be largely intraparticle and interparticle (adjacent to inorganic constituents), so the petroleum storage potential in these organic-rich mudstones largely resides in inorganic pores.

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.

Low temperature hydrothermal maturation of organic matter in sediments from the Atlantis II Deep, Red Sea

NASA Technical Reports Server (NTRS)

Simoneit, Bernd R. T.; Grimalt, Joan O.; Hayes, J. M.; Hartman, Hyman

1987-01-01

Hydrocarbons and bulk organic matter of two sediment cores within the Atlantis II Deep are analyzed, and microbial inputs and minor terrestrial sources are found to represent the major sedimentary organic material. Results show that extensive acid-catalyzed reactions are occurring in the sediments, and the Atlantis II Deep is found to exhibit a lower degree of thermal maturation than other hydrothermal or intrusive systems. The lack of carbon number preference noted among the n-alkanes suggests that the organic matter of these sediments has undergone some degree of catagenesis, though yields of hydrocarbons are much lower than those found in other hydrothermal areas, probably due to the effect of lower temperature and poor source-rock characteristics.

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.

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.

Geochemical characterization of the siliciclastic rocks of Chitravati Group, Cuddapah Supergroup: Implications for provenance and depositional environment

NASA Astrophysics Data System (ADS)

Somasekhar, V.; Ramanaiah, S.; Sarma, D. Srinivasa

2018-06-01

Petrological and geochemical studies have been carried out on Pulivendla and Gandikota Quartzite from Chitravati Group of Cuddapah Supergroup to decipher the provenance and depositional environment. Both the units are texturally mature with sub-rounded to well-rounded and moderately to well-sorted grains. Majority of the framework grains are quartz, in the form of monocrystalline quartz, followed by feldspars (K-feldspar and plagioclase), mica, rock fragments, heavy minerals, with minor proportion of the matrix and cement. Based on major element geochemical classification diagram, Pulivendla Quartzite is considered as quartz-arenite and arkose to sub-arkose, whereas Gandikota Quartzite falls in the field of lith-arenite and arkose to sub-arkose. Weathering indices like CIA, PIA, CIW, ICV, Th/U ratio and A-CN-K ternary diagram suggest moderate to intense chemical weathering of the source rocks of these quartzites. Whole rock geochemistry of quartzites indicate that they are primarily from the first-cycle sediments, along with some minor recycled components. Also their sources were mostly intermediate-felsic igneous rocks of Archean age. The tectonic discrimination plots, Th-Sc-Zr/10 of both these formations reflect active to passive continental margin setting. Chondrite-normalized rare earth element (REE) patterns, and various trace element ratios like Cr/Th, Th/Co, La/Sc and Th/Cr indicate dominantly felsic source with minor contribution from mafic source. Th/Sc ratios of Pulivendla and Gandikota Quartzite are in close proximity with average values of 2.83, 3.45 respectively, which is higher than AUCC (Th/Sc=0.97), demonstrating that the contributions from more alkali source rocks than those that contributed to AUCC.

Determining quantity and quality of retained oil in mature marly chalk and marlstone of the Cretaceous Niobrara Formation by low-temperature hydrous pyrolysis

USGS Publications Warehouse

Lewan, Michael; Sonnenfeld, Mark D.

2017-01-01

Low-temperature hydrous pyrolysis (LTHP) at 300°C (572°F) for 24 h released retained oils from 12- to 20-meshsize samples of mature Niobrara marly chalk and marlstone cores. The released oil accumulated on the water surface of the reactor, and is compositionally similar to oil produced from the same well. The quantities of oil released from the marly chalk and marlstone by LTHP are respectively 3.4 and 1.6 times greater than those determined by tight rock analyses (TRA) on aliquots of the same samples. Gas chromatograms indicated this difference is a result of TRA oils losing more volatiles and volatilizing less heavy hydrocarbons during collection than LTHP oils. Characterization of the rocks before and after LTPH by programmable open-system pyrolysis (HAWK) indicate that under LTHP conditions no significant oil is generated and only preexisting retained oil is released. Although LTHP appears to provide better predictions of quantity and quality of retained oil in a mature source rock, it is not expected to replace the more time and sample-size efficacy of TRA. However, LTHP can be applied to composited samples from key intervals or lithologies originally recognized by TRA. Additional studies on duration, temperature, and sample size used in LTHP may further optimize its utility.

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.

Biological marker distribution in coexisting kerogen, bitumen and asphaltenes in Monterey Formation diatomite, California

NASA Technical Reports Server (NTRS)

Tannenbaum, E.; Ruth, E.; Huizinga, B. J.; Kaplan, I. R.

1986-01-01

Organic-rich (18.2%) Monterey Formation diatomite from California was studied. The organic matter consist of 94% bitumen and 6% kerogen. Biological markers from the bitumen and from pyrolysates of the coexisting asphaltenes and kerogen were analyzed in order to elucidate the relationship between the various fractions of the organic matter. While 17 alpha(H), 18 alpha(H), 21 alpha(H)-28,30-bisnorhopane was present in the bitumen and in the pryolysate of the asphaltenes, it was not detected in the pyrolysates of the kerogen. A C40-isoprenoid with "head to head" linkage, however, was present in pyrolysates of both kerogen and asphaltenes, but not in the bitumen from the diatomite. The maturation level of the bitumen, based on the extent of isomerization of steranes and hopanes, was that of a mature oil, whereas the pyrolysate from the kerogen showed a considerably lower maturation level. These relationships indicate that the bitumen may not be indigenous to the diatomite and that it is a mature oil that migrated into the rock. We consider the possibility, however, that some of the 28,30-bisnorhopane-rich Monterey Formation oils have not been generated through thermal degradation of kerogen, but have been expelled from the source rock at an early stage of diagenesis.

Mineralogical, chemical and K-Ar isotopic changes in Kreyenhagen Shale whole rocks and <2 µm clay fractions during natural burial and hydrous-pyrolysis experimental maturation

USGS Publications Warehouse

Clauer, Norbert; Lewan, Michael D.; Dolan, Michael P.; Chaudhuri, Sambhudas; Curtis, John B.

2014-01-01

Large amounts of smectite layers in the illite–smectite mixed layers of the pyrolyzed outcrop <2 μm fraction remain during thermal experiments, especially above 310 °C. With no illitization detected above 310 °C, smectite appears to have inhibited rather than promoted generation of expelled oil from decomposition of bitumen. This hindrance is interpreted to result from bitumen impregnating the smectite interlayer sites and rock matrix. Bitumen remains in the <2 μm fraction despite leaching with H2O2. Its presence in the smectite interlayers is apparent by the inability of the clay fraction to fully expand or collapse once bitumen generation from the thermal decomposition of the kerogen is completed, and by almost invariable K–Ar ages confirming for the lack of any K supply and/or radiogenic 40Ar removal. This suggests that once bitumen impregnates the porosity of a progressively maturing source rock, the pore system is no longer wetted by water and smectite to illite conversion ceases. Experimental attempts to evaluate the smectite conversion to illite should preferentially use low-TOC rocks to avoid inhibition of the reaction by bitumen impregnation.

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.

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

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).

Oil-source correlations between the Mississippian Heath Shales and the reservoired oils in the Pennsylvanian Tyler Sands, Montana

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

Cole, G.A.; Drozd, R.J.; Daniel, J.A.

The Mississippi Heath Formation exposed in Fergus County, central Montana, is comprised predominantly of nearshore, marine, black, calcareous shales and carbonates with minor anhydrite and coal beds. The black shales and limestones have been considered as sources for shale oil via Fischer Assay and pyrolysis analysis. These shales are potential source units for the oils reservoired in the overlying Pennsylvanian Tyler Formation sands located 50 mi (80 km) to the east of the Fergus County Heath sediment studied. Heath Formation rocks from core holes were selectively sampled in 2-ft increments and analyzed for their source rock characteristics. Analyses include percentmore » total organic carbon (%TOC), Rock-Eval pyrolysis, pyrolysis-gas chromatography, and characterization of the total soluble extracts using carbon isotopes and gas chromatography-mass Spectrometry. Results indicated that the Heath was an excellent potential source unit that contained oil-prone, organic-rich (maximum of 17.6% TOC), calcareous, black shale intervals. The Heath and Tyler formations also contained intervals dominated by gas-prone, organic-rich shales of terrestrial origin. Three oils from the Tyler Formation sands in Musselshell and Rosebud counties were characterized by similar methods as the extracts. The oils were normally mature, moderate API gravity, moderate sulfur, low asphaltene crudes. Oil to source correlations between the Heath shale extracts and the oils indicated the Heath was an excellent candidate source rock for the Tyler reservoired oils. Conclusions were based on excellent matches between the carbon isotopes of the oils and the kerogen-kerogen pyrolyzates, and from the biomarkers.« less

Géodynamique et évolution thermique de la matière organique: exemple du bassin de Qasbat-Tadla, Maroc centralBasin geodynamics and thermal evolution of organic material: example from the Qasbat-Tadla Basin, central Morocco

NASA Astrophysics Data System (ADS)

Er-Raïoui, H.; Bouabdelli, M.; Bélayouni, H.; Chellai, H.

2001-05-01

Seismic data analysis of the Qasbat-Tadla Basin allows the deciphering of the main tectonic and sedimentary events that characterised the Hercynian orogen and its role in the basin's structural development. The global tectono-sedimentary framework involves structural evolution of an orogenic foreland basin and was the source of rising geotherms in an epizonal metamorphic environment. The complementary effects of these parameters has led to different source rock maturity levels, ranging from oil producing to graphite domains. Different maturity levels result from three distinct structural domains within the basin, each of which exhibit characteristic geodynamic features (tectonic contraints, rate of subsidence, etc.).

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.

Mössbauer spectroscopic study of the test well (DND) located in Jaisalmer Basin of Rajasthan, India

NASA Astrophysics Data System (ADS)

Ganwani, Girish; Meena, Samay Singh; Ram, Sahi; Bhatia, Beena; Tripathi, R. P.

2018-05-01

The Jaisalmer basin represents mainly the westerly dipping flank of Indus shelf. The palynological and geochemical studies have predicted good quality of hydrocarbons in this basin. The cretaceous and Jurassic sediments are believed to contain source rock in this basin. In present preliminary study, Mössbauer spectroscopic investigation has been done on sedimentary samples collected from different depths of upper cretaceous sedimentary sequence of well DND-1 drilled in Jaisalmer basin. The iron is found mainly in carbonate and clay. The relatively small presence of Fe2+ in comparison to Fe3+ in clay is an indication of poor reducing environment in sediments, which can be attributed to poor maturity of source rocks in upper cretaceous sediments of this basin.

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

Gentzis, T.; Goodarzi, F.; Mukhopadhyay, P.K.

The hydrocarbon potential of the Mesozoic succession in the vicinity of King Christian Island in central Sverdrup Basin was evaluated on the basis of maturation parameters and knowledge of the regional geology. The triassic Schei Point Group, which is the main source rock interval in Sverdrup Basin, is in the mature stage of hydrocarbon generation (Ro > 0.60%). The type of organic matter is mainly planktonic marine algae and bituminite, deposited in an offshore shelf setting. Rock-eval T{sub max} values are in the range 428--444 C, in general agreement with reflectance. Organic richness is indicated by the high hydrogen indexmore » (HI) values in the shales (in excess of 300 mg HC/gTOC). Less rich source rocks are found in the Jurassic-age Jameson Bay and Ringnes formations, in accordance with previous studies in the nearby Lougheed and Melville islands. Numerous oil and gas fields have been discovered in King Christian Island to date. Geology shows that the presence or absence of liquid and gaseous hydrocarbons in the reservoirs is related to the development of a system of faults and fractures in the successions stratigraphically above the source rocks. These zones have acted as conduits for oil and gas migration and, ultimately, loss. The presence of bitumen staining and numerous populations of solid bitumen, interpreted as allochthonously derived, support the theory of hydrocarbon migration in the King Christian Island succession. Migration has taken place over a vertical distance of 800 m to 1500 m. Problems were encountered in measuring vitrinite reflectance, related mainly to the presence of cavings, bitumen staining, vitrinite typing, oxidation of organic matter, and effect of igneous intrusions. The thermal effect from igneous sills and dykes resulted in thermal cracking of liquid hydrocarbons to gaseous in certain areas. A zone of paleo-overpressure was identified near the contact between a thick sandstone unit and overlying shales exhibiting a kinky vitrinite reflectance profile.« less

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).

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.

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.

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%.

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.

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.

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).

A New Biomarker Proxy for Palaeo-pCO2 Reconstruction in Ancient Sediments

NASA Astrophysics Data System (ADS)

Pancost, R. D.; Magness, S.; Maxwell, J. R.

2001-12-01

The carbon isotopic composition of marine organic matter has commonly been used in chemostratigraphy or as a proxy for ancient pCO2 levels. Both of these goals require that the source of organic matter be well defined, and in the case of palaeo-pCO2 investigations, the organic matter must be derived ultimately from aquatic photoautotrophs. However, additional sources, including terrestrial biomass, heterotrophs, or bacteria, can also contribute to total organic carbon (TOC). In the past decade, numerous workers have attempted to refine organic carbon isotope records using the isotopic composition of individual compounds (biomarkers) rather than the TOC. The appeal of this approach is that by examining specific biomarkers, a signal diagnostic for photoautotrophic organisms can be obtained. For compound-specific isotope analyses to be most effective, the compounds analysed must have a relatively specific source. Among the most commonly used biomarkers in palaeo-pCO2 investigations are alkenones, long-chain ketones derived exclusively from certain species of haptophyte algae. However, alkenones are absent in rocks older than the Jurassic and either absent or present in low abundances in rocks older than the Miocene. Thus, in older rocks, other biomarkers, including steranes (derived from eukaryotic sterols), phytane (presumably derived from chlorophyll), and n-alkanes (derived from algal macromolecules), are used. Unfortunately, these compounds can have alternative sources and become less reliable as isotopic proxies for photoautotrophs with increasing thermal maturity and complexity of the hydrocarbon distribution. Here we propose the use of a maleimides (1H-pyrrole-2,5-diones) as a new biomarker class for evaluating past changes in photoautotroph carbon isotopic compositions. Maleimides have three key advantages over other biomarkers in ancient rocks. First, they are degradation products of chlorophyll and have no known alternative origins in marine sediments. Second, because of their unique structure, they can be readily isolated from other organic components facilitating the determination of accurate carbon isotope ratios. Finally, the pyrrole structure is relatively stable insuring that maleimides survive even in thermally mature rocks. We have applied the analysis of maleimides to investigations of sediments from the Kupferschiefer (Permian), Vena del Gesso (Messinian) and Livello Bonarelli (Cenomanian-Turonian boundary) formations. In all three cases, the carbon isotopic compositions of selected maleimides exhibit shifts predicted by either carbonate or other biomarker carbon isotope profiles.

Resource assessment in Western Australia using a geographic information system

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

Jackson, A.

1991-03-01

Three study areas in Western Australia covering from 77,000 to 425,000 mi{sup 2} were examined for oil and gas potential using a geographic information system (GIS). A data base of source rock thickness, source richness, maturity, and expulsion efficiency was created for each interval. The GIS (Arc/Info) was used to create, manage, and analyze data for each interval in each study area. Source rock thickness and source richness data were added to the data base from digitized data. Maturity information was generated with Arc/Info by combining geochemical and depth to structure data. Expulsion efficiency data was created by a systemmore » level Arc/Info program. After the data base for each interval was built, the GIS was used to analyze the geologic data. The analysis consisted of converting each data layer into a lattice (grid) and using the lattice operation in Arc/Infor (addition, multiplication, division, and subtraction) to combine the data layers. Additional techniques for combining and selecting data were developed using Arc/Info system level programs. The procedure for performing the analyses was written as macros in Arc/Info's macro programming language (AML). The results of the analysis were estimates of oil and gas volumes for each interval. The resultant volumes were produced in tabular form for reports and cartographic form for presentation. The geographic information system provided several clear advantages over traditional methods of resource assessment including simplified management, updating, and editing of geologic data.« less

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

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.

Application of fuzzy set and Dempster-Shafer theory to organic geochemistry interpretation

NASA Technical Reports Server (NTRS)

Kim, C. S.; Isaksen, G. H.

1993-01-01

An application of fuzzy sets and Dempster Shafter Theory (DST) in modeling the interpretational process of organic geochemistry data for predicting the level of maturities of oil and source rock samples is presented. This was accomplished by (1) representing linguistic imprecision and imprecision associated with experience by a fuzzy set theory, (2) capturing the probabilistic nature of imperfect evidences by a DST, and (3) combining multiple evidences by utilizing John Yen's generalized Dempster-Shafter Theory (GDST), which allows DST to deal with fuzzy information. The current prototype provides collective beliefs on the predicted levels of maturity by combining multiple evidences through GDST's rule of combination.

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.

Caspase-activated ROCK-1 allows erythroblast terminal maturation independently of cytokine-induced Rho signaling

PubMed Central

Gabet, A-S; Coulon, S; Fricot, A; Vandekerckhove, J; Chang, Y; Ribeil, J-A; Lordier, L; Zermati, Y; Asnafi, V; Belaid, Z; Debili, N; Vainchenker, W; Varet, B; Hermine, O; Courtois, G

2011-01-01

Stem cell factor (SCF) and erythropoietin are strictly required for preventing apoptosis and stimulating proliferation, allowing the differentiation of erythroid precursors from colony-forming unit-E to the polychromatophilic stage. In contrast, terminal maturation to generate reticulocytes occurs independently of cytokine signaling by a mechanism not fully understood. Terminal differentiation is characterized by a sequence of morphological changes including a progressive decrease in cell size, chromatin condensation in the nucleus and disappearance of organelles, which requires transient caspase activation. These events are followed by nucleus extrusion as a consequence of plasma membrane and cytoskeleton reorganization. Here, we show that in early step, SCF stimulates the Rho/ROCK pathway until the basophilic stage. Thereafter, ROCK-1 is activated independently of Rho signaling by caspase-3-mediated cleavage, allowing terminal maturation at least in part through phosphorylation of the light chain of myosin II. Therefore, in this differentiation system, final maturation occurs independently of SCF signaling through caspase-induced ROCK-1 kinase activation. PMID:21072057

Maps showing thermal maturity of Upper Cretaceous marine shales in the Bighorn Basin, Wyoming and Montana

USGS Publications Warehouse

Finn, Thomas M.; Pawlewicz, Mark J.

2014-01-01

The Bighorn Basin is one of many structural and sedimentary basins that formed in the Rocky Mountain foreland during the Laramide orogeny, a period of crustal instability and compressional tectonics that began in latest Cretaceous time and ended in the Eocene. The basin is nearly 180 mi long, 100 mi wide, and encompasses about 10,400 mi2 in north-central Wyoming and south-central Montana. The basin is bounded on the northeast by the Pryor Mountains, on the east by the Bighorn Mountains, and on the south by the Owl Creek Mountains). The north boundary includes a zone of faulting and folding referred to as the Nye-Bowler lineament. The northwest and west margins are formed by the Beartooth Mountains and Absaroka Range, respectively. Important conventional oil and gas resources have been discovered and produced from reservoirs ranging in age from Cambrian through Tertiary. In addition, a potential unconventional basin-centered gas accumulation may be present in Cretaceous reservoirs in the deeper parts of the basin. It has been suggested by numerous authors that various Cretaceous marine shales are the principal source rock for these accumulations. Numerous studies of various Upper Cretaceous marine shales in the Rocky Mountain region have led to the general conclusion that these rocks have generated or are capable of generating oil and (or) gas. In recent years, advances in horizontal drilling and multistage fracture stimulation have resulted in increased exploration and completion of wells in Cretaceous marine shales in other Rocky Mountain Laramide basins that were previously thought of only as hydrocarbon source rocks. Important parameters controlling hydrocarbon production from these shale reservoirs include: reservoir thickness, amount and type of organic matter, and thermal maturity. The purpose of this report is to present maps and a cross section showing levels of thermal maturity, based on vitrinite reflectance (Ro), for selected Upper Cretaceous marine shales in the Bighorn Basin.

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.

Geochemical characterization of Neogene sediments from onshore West Baram Delta Province, Sarawak: paleoenvironment, source input and thermal maturity

NASA Astrophysics Data System (ADS)

Togunwa, Olayinka S.; Abdullah, Wan H.

2017-08-01

The Neogene strata of the onshore West Baram Province of NW Borneo contain organic rich rock formations particularly within the Sarawak basin. This basin is a proven prolific oil and gas province, thus has been a subject of great interest to characterise the nature of the organic source input and depositional environment conditions as well as thermal maturation. This study is performed on outcrop samples of Lambir, Miri and Tukau formations, which are of stratigraphic equivalence to the petroleum bearing cycles of the offshore West Baram delta province in Sarawak. The investigated mudstone samples are organic rich with a total organic carbon (TOC) content of more than 1.0 wt.%. The integration of elemental and molecular analyses indicates that there is no significant variation in the source input between these formations. The investigated biomarkers parameters achieved from acyclic isoprenoids, terpanes and steranes biomarkers of a saturated hydrocarbon biomarkers revealed that these sediments contain high contribution of land plants with minor marine organic matter input that was deposited and preserved under relatively oxic to suboxic conditions. This is further supported by low total sulphur (TS), high TOC/TN ratios, source and redox sensitive trace elements (V, Ni, Cr, Co and Mo) concentrations and their ratios, which suggest terrigenous source input deposited under oxic to suboxic conditions. Based on the analysed biomarker thermal maturity indicators, it may be deduced that the studied sediments are yet to enter the maturity stage for hydrocarbon generation, which is also supported by measured vitrinite reflectance values of 0.39-0.48% Ro.

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.

Thermal maturity map of the lower part of the Upper Cretaceous Mesaverde Group, Uintah Basin, Utah

USGS Publications Warehouse

Nuccio, Vito F.; Johnson, Ronald C.

1986-01-01

The ability of rock to generate oil and gas is directly related to the type and quantity of kerogen and to its thermal maturity; therefore, thermal maturity is a commonly used tool for oil and gas exploration.  The purpose of this study ws to provide a thermal-maturity map for the lower part of the Upper Cretaceous Mesaverde Group in the eastern part of the Uinta Basin.  Prior to this study, thermal-maturity data were not available for the Uinta Basin.  This study uses coal rank to show the thermal maturity of the associated rocks.  The map was prepared in cooperation with the U.S. Department of Energy under its western gas sands project.

Intrusive rocks of the Wadi Hamad Area, North Eastern Desert, Egypt: Change of magma composition with maturity of Neoproterozoic continental island arc and the role of collisional plutonism in the differentiation of arc crust

NASA Astrophysics Data System (ADS)

Basta, Fawzy F.; Maurice, Ayman E.; Bakhit, Bottros R.; Azer, Mokhles K.; El-Sobky, Atef F.

2017-09-01

The igneous rocks of the Wadi Hamad area are exposed in the northernmost segment of the Arabian-Nubian Shield (ANS). These rocks represent part of crustal section of Neoproterozoic continental island arc which is intruded by late to post-collisional alkali feldspar granites. The subduction-related intrusives comprise earlier gabbro-diorites and later granodiorites-granites. Subduction setting of these intrusives is indicated by medium- to high-K calc-alkaline affinity, Ta-Nb troughs on the spider diagrams and pyroxene and biotite compositions similar to those crystallized from arc magmas. The collisional alkali feldspar granites have high-K highly fractionated calc-alkaline nature and their spider diagrams almost devoid of Ta-Nb troughs. The earlier subduction gabbro-diorites have lower alkalis, LREE, Nb, Zr and Hf values compared with the later subduction granodiorites-granites, which display more LILE-enriched spider diagrams with shallower Ta-Nb troughs, reflecting variation of magma composition with arc evolution. The later subduction granitoids were generated by lower degree of partial melting of mantle wedge and contain higher arc crustal component compared with the earlier subduction gabbro-diorites. The highly silicic alkali feldspar granites represent extensively evolved melts derived from partial melting of intermediate arc crustal sources during the collisional stage. Re-melting of arc crustal sources during the collisional stage results in geochemical differentiation of the continental arc crust and the silicic collisional plutonism drives the composition of its upper part towards that of mature continental crust.

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

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).

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.

Silurian shale origin for light oil, condensate, and gas in Algeria and the Middle East

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

Zumberge, J.E.; Macko, S.

1996-01-01

Two of the largest gas fields in the world, Hasi R'Mel, Algeria and North Dome, Qatar, also contain substantial condensate and light oil reserves. Gas to source rock geochemical correlation is difficult due to the paucity of molecular parameters in the former although stable isotope composition is invaluable. However, by correlating source rocks with light oils and condensates associated with gas production using traditional geochemical parameters such as biomarkers and isotopes, a better understanding of the origin of the gas is achieved. Much of the crude oil in the Ghadames/Illizi Basins of Algeria has long been thought to have beenmore » generated from Silurian shales. New light oil discoveries in Saudi Arabia have also been shown to originate in basal euxinic Silurian shales. Key sterane and terpane biomarkers as well as the stable carbon isotopic compositions of the C15+ saturate and aromatic hydrocarbon fractions allow for the typing of Silurian-sourced, thermally mature light oils in Algeria and the Middle East. Even though biomarkers are often absent due to advanced thermal maturity, condensates can be correlated to the light oils using (1) carbon isotopes of the residual heavy hydrocarbon fractions, (2) light hydrocarbon distributions (e.g., C7 composition), and (3) compound specific carbon isotopic composition of the light hydrocarbons. The carbon isotopes of the C2-C4 gas components ran then be compared to the associated condensate and light oil isotopic composition.« less

Silurian shale origin for light oil, condensate, and gas in Algeria and the Middle East

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

Zumberge, J.E.; Macko, S.

Two of the largest gas fields in the world, Hasi R`Mel, Algeria and North Dome, Qatar, also contain substantial condensate and light oil reserves. Gas to source rock geochemical correlation is difficult due to the paucity of molecular parameters in the former although stable isotope composition is invaluable. However, by correlating source rocks with light oils and condensates associated with gas production using traditional geochemical parameters such as biomarkers and isotopes, a better understanding of the origin of the gas is achieved. Much of the crude oil in the Ghadames/Illizi Basins of Algeria has long been thought to have beenmore » generated from Silurian shales. New light oil discoveries in Saudi Arabia have also been shown to originate in basal euxinic Silurian shales. Key sterane and terpane biomarkers as well as the stable carbon isotopic compositions of the C15+ saturate and aromatic hydrocarbon fractions allow for the typing of Silurian-sourced, thermally mature light oils in Algeria and the Middle East. Even though biomarkers are often absent due to advanced thermal maturity, condensates can be correlated to the light oils using (1) carbon isotopes of the residual heavy hydrocarbon fractions, (2) light hydrocarbon distributions (e.g., C7 composition), and (3) compound specific carbon isotopic composition of the light hydrocarbons. The carbon isotopes of the C2-C4 gas components ran then be compared to the associated condensate and light oil isotopic composition.« less

Hydrocarbon potential of Early Cretaceous lacustrine sediments from Bima Formation, Yola Sub-basin, Northern Benue Trough, NE Nigeria: Insight from organic geochemistry and petrology

NASA Astrophysics Data System (ADS)

Sarki Yandoka, Babangida M.; Abdullah, Wan Hasiah; Abubakar, M. B.; Adegoke, Adebanji Kayode; Maigari, A. S.; Haruna, A. I.; Yaro, Usman Y.

2017-05-01

The Early Cretaceous lacustrine sediments from Bima Formation in the Yola Sub-basin, Northern Benue Trough, northeastern Nigeria were studied based on organic geochemistry and petrology. This is in other to provide information on hydrocarbon generation potential; organic matter type (quality), richness (quantity), origin/source inputs, redox conditions (preservation) and thermal maturation in relation to thermal effect of Tertiary volcanics. The total organic carbon (TOC) contents ranges from 0.38 to 0.86 wt % with extractable organic matter (EOM) below 1000 ppm and pyrolysis S2 yield values from 0.16 to 0.68 mg/g, suggesting poor to fair source rock richness. Based on kerogen pyrolysis and microscopy coupled with biomarker parameters, the organic matters contain Type I (lacustrine algae), Type III (terrestrially derived land-plants) and Type IV kerogens deposited in a mixed lacustrine-terrestrial environment under suboxic to relatively anoxic conditions. This suggest potential occurrence of Early Cretaceous lacustrine sediments (perhaps Lower Cretaceous petroleum system) in Yola Sub-basin of the Northern Benue Trough as present in the neighbouring basins of Chad, Niger and Sudan Republics that have both oil and gas generation potential within the same rift trend (WCARS). Vitrinite reflectance (%Ro) and Tmax values of the lacustrine shales ranges from 1.12 to 2.32 VRo% and 448-501 °C, respectively, indicating peak-late to post-maturity stage. This is supported by the presence of dark brown palynomorphs, amorphous organic matter and phytoclasts as well as inertinite macerals. Consequently, the organic matters in the lacustrine shales of Bima Formation in the Yola Sub-basin appeared as a source of oil (most likely even waxy) and gas prone at a relatively deeper part of the basin. However, the high thermal maturity enhanced the organic matters and most of the hydrocarbons that formed in the course of thermal maturation were likely expelled to the reservoir rock units and further cracked into secondary or major gas probably due to thermal effects of Tertiary volcanic intrusion known to be present in the 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).

Hydrocarbon potential of Morocco

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

Achnin, H.; Nairn, A.E.M.

1988-08-01

Morocco lies at the junction of the African and Eurasian plates and carries a record of their movements since the end of the Precambrian. Four structural regions with basins and troughs can be identified: Saharan (Tarfaya-Ayoun and Tindouf basins); Anti-Atlas (Souss and Ouarzazate troughs and Boudnib basin); the Essaouria, Doukkala, Tadla, Missour, High Plateau, and Guercif basins; and Meseta and Rif (Rharb and Pre-Rif basins). The targets in the Tindouf basin are Paleozoic, Cambrian, Ordovician (clastics), Devonian (limestones), and Carboniferous reservoirs sourced primarily by Silurian shales. In the remaining basins, excluding the Rharb, the reservoirs are Triassic detritals, limestones atmore » the base of the Lias and Dogger, Malm detritals, and sandy horizons in the Cretaceous. In addition to the Silurian, potential source rocks include the Carboniferous and Permo-Carboniferous shales and clays; Jurassic shales, marls, and carbonates; and Cretaceous clays. In the Rharb basin, the objectives are sand lenses within the Miocene marls. The maturation level of the organic matter generally corresponds to oil and gas. The traps are stratigraphic (lenses and reefs) and structural (horsts and folds). The seals in the pre-Jurassic rocks are shales and evaporites; in the younger rocks, shales and marl. Hydrocarbon accumulations have been found in Paleozoic, Triassic, Liassic, Malm, and Miocene rocks.« less

Sedimentary provenance of Maastrichtian oil shales, Central Eastern Desert, Egypt

NASA Astrophysics Data System (ADS)

Fathy, Douaa; Wagreich, Michael; Mohamed, Ramadan S.; Zaki, Rafat

2017-04-01

Maastrichtian oil shales are distributed within the Central Eastern Desert in Egypt. In this study elemental geochemical data have been applied to investigate the probable provenance of the sedimentary detrital material of the Maastrichtian oil shale beds within the Duwi and the Dakhla formations. The Maastrichtian oil shales are characterized by the enrichment in Ca, P, Mo, Ni, Zn, U, Cr and Sr versus post-Archean Australian shales (PAAS). The chondrite-normalized patterns of the Maastrichtian oil shale samples are showing LREE enrichment, HREE depletion, slightly negative Eu anomaly, no obvious Ce anomaly and typical shale-like PAAS-normalized patterns. The total REE well correlated with Si, Al, Fe, K and Ti, suggesting that the REE of the Maastrichtian oil shales are derived from terrigenous source. Chemical weathering indices such as Chemical Index of Alteration (CIA), Chemical Proxy of Alteration (CPA) and Plagioclase Index of Alteration (PIA) indicate moderate to strong chemical weathering. We suggest that the Maastrichtian oil shale is mainly derived from first cycle rocks especially intermediate rocks without any significant inputs from recycled or mature sources. The proposed data illustrated the impact of the parent material composition on evolution of oil shale chemistry. Furthermore, the paleo-tectonic setting of the detrital source rocks for the Maastrichtian oil shale is probably related to Proterozoic continental island arcs

Evolution of sulfur speciation in bitumen through hydrous pyrolysis induced thermal maturation of Jordanian Ghareb Formation oil shale

USGS Publications Warehouse

Birdwell, Justin E.; Lewan, Michael; Bake, Kyle D.; Bolin, Trudy B.; Craddock, Paul R.; Forsythe, Julia C.; Pomerantz, Andrew E.

2018-01-01

Previous studies on the distribution of bulk sulfur species in bitumen before and after artificial thermal maturation using various pyrolysis methods have indicated that the quantities of reactive (sulfide, sulfoxide) and thermally stable (thiophene) sulfur moieties change following consistent trends under increasing thermal stress. These trends show that sulfur distributions change during maturation in ways that are similar to those of carbon, most clearly illustrated by the increase in aromatic sulfur (thiophenic) as a function of thermal maturity. In this study, we have examined the sulfur moiety distributions of retained bitumen from a set of pre- and post-pyrolysis rock samples in an organic sulfur-rich, calcareous oil shale from the Upper Cretaceous Ghareb Formation. Samples collected from outcrop in Jordan were subjected to hydrous pyrolysis (HP). Sulfur speciation in extracted bitumens was examined using K-edge X-ray absorption near-edge structure (XANES) spectroscopy. The most substantial changes in sulfur distribution occurred at temperatures up to the point of maximum bitumen generation (∼300 °C) as determined from comparison of the total organic carbon content for samples before and after extraction. Organic sulfide in bitumen decreased with increasing temperature at relatively low thermal stress (200–300 °C) and was not detected in extracts from rocks subjected to HP at temperatures above around 300 °C. Sulfoxide content increased between 200 and 280 °C, but decreased at higher temperatures. The concentration of thiophenic sulfur increased up to 300 °C, and remained essentially stable under increasing thermal stress (mg-S/g-bitumen basis). The ratio of stable-to-reactive+stable sulfur moieties ([thiophene/(sulfide+sulfoxide+thiophene)], T/SST) followed a sigmoidal trend with HP temperature, increasing slightly up to 240 °C, followed by a substantial increase between 240 and 320 °C, and approaching a constant value (∼0.95) at temperatures above 320 °C. This sulfur moiety ratio appears to provide complementary thermal maturity information to geochemical parameters derived from other analyses of extracted source rocks.

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.

Thermal-maturity limit for primary thermogenic-gas generation from humic coals as determined by hydrous pyrolysis

USGS Publications Warehouse

Lewan, Michael; Kotarba, M.J.

2014-01-01

Hydrous-pyrolysis experiments at 360°C (680°F) for 72 h were conducted on 53 humic coals representing ranks from lignite through anthracite to determine the upper maturity limit for hydrocarbon-gas generation from their kerogen and associated bitumen (i.e., primary gas generation). These experimental conditions are below those needed for oil cracking to ensure that generated gas was not derived from the decomposition of expelled oil generated from some of the coals (i.e., secondary gas generation). Experimental results showed that generation of hydrocarbon gas ends before a vitrinite reflectance of 2.0%. This reflectance is equivalent to Rock-Eval maximum-yield temperature and hydrogen indices (HIs) of 555°C (1031°F) and 35 mg/g total organic carbon (TOC), respectively. At these maturity levels, essentially no soluble bitumen is present in the coals before or after hydrous pyrolysis. The equivalent kerogen atomic H/C ratio is 0.50 at the primary gas-generation limit and indicates that no alkyl moieties are remaining to source hydrocarbon gases. The convergence of atomic H/C ratios of type-II and -I kerogen to this same value at a reflectance of indicates that the primary gas-generation limits for humic coal and type-III kerogen also apply to oil-prone kerogen. Although gas generation from source rocks does not exceed vitrinite reflectance values greater than , trapped hydrocarbon gases can remain stable at higher reflectance values. Distinguishing trapped gas from generated gas in hydrous-pyrolysis experiments is readily determined by of the hydrocarbon gases when a -depleted water is used in the experiments. Water serves as a source of hydrogen in hydrous pyrolysis and, as a result, the use of -depleted water is reflected in the generated gases but not pre-existing trapped gases.

A conceptual review of regional-scale controls on the composition of clastic sediment and the co-evolution of continental blocks and their sedimentary cover.

PubMed

Cox, R; Lowe, D R

1995-01-02

Both sediment recycling and first-cycle input influence the composition of clastic material in sedimentary systems. This paper examines conceptually the roles played by these processes in governing the composition of clastic sediment on a regional scale by outlining the expected effects on sediment composition of protracted sediment recycling and of continuous first-cycle input on a maturing continental block. Generally speaking, long-term recycling tends to enrich sediments in the most chemically and mechanically stable components: quartz in the sand and silt size fractions, and illite among the clay minerals. Sandstones trend towards pure quartz arenites, and mudrocks become more potassic and aluminous. The average grain size of clastic sediment decreases by a combination of progressive attrition of sand grains and ongoing breakdown of primary silicate minerals to finer-grained clay minerals and oxides. Sandstones derived by continuous first-cycle input from an evolving continental crustal source also become increasingly rich in quartz, but in addition become more feldspathic as the proportion of granitic material in the upper continental crust increases during crustal stabilization. Associated mudrocks also become richer in potassium and aluminum, but will have higher K2O/Al2O3 ratios than recycled muds. The average grain size of the sediment may increase with time as the proportion of sand-prone granitic source rocks increases at the expense of more mud-prone volcanic sources. In general, except in instances where chemical weathering is extreme, first-cycle sediments lack the compositional maturity of recycled detritus, and are characterized by the presence of a variety of primary silicate minerals. Sedimentary systems are not usually completely dominated by either recycling or first-cycle detritus. Generally, however, sedimentary systems associated with the earliest phases of formation and accretion of continental crust are characterized by first-cycle input from igneous and metamorphic rocks, whereas those associated with more mature cratons tend to be dominated by recycled sedimentary material.

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.

Composition and stable-isotope geochemistry of natural gases from Kansas, Midcontinent, U.S.A.

USGS Publications Warehouse

Jenden, P.D.; Newell, K.D.; Kaplan, I.R.; Watney, W.L.

1988-01-01

More than 28??1012 ft.3 (79??1010 m3) of natural gas and 5.3??109 bbl (8.4??108 m3) of oil have been produced in Kansas, U.S.A., from Paleozoic carbonate and sandstone reservoirs on structural uplifts and shallow embayments along the northern margin of the Anadarko basin. A heavily-explored, geologically well-characterized state, Kansas is an excellent place to study hydrocarbon migration and to test geochemical models for the origin of natural gases. Immature to marginally-mature rocks of eastern Kansas (Cherokee and Forest City basins) produce mixed microbial and thermogenic gases. Gases in this region have wetness = 0.03-51%, methane ??13C = -65 to -43??? and methane ??D = -260 to -150???. Gases from central and western Kansas (Nemaha uplift to Hugoton embayment) are entirely thermogenic and have wetness =4-51%, methane ??13C = -48 to -39??? and methane ??D = -195 to -140???. Ethane and propane ??13C-values throughout Kansas vary from -38 to -28??? and from -35 to -24???, respectively. Mature thermogenic gas (generated from source rocks in southwestern Kansas and the Anadarko basin with 1.0% ??? Ro ??? 1.4%) is recognized throughout the state. Lateral migration into shallow reservoirs on the Central Kansas and northern Nemaha uplifts and in the Cherokee basin probably occurred along basal Pennsylvanian conglomerates and weathered Lower Paleozoic carbonates at the regional sub-Pennsylvanian unconformity. Early thermogenic gas (generated by local source rocks with Ro ??? 0.7%) is recognized in isolated fields in the Salina and Forest City basins, in Ordovician reservoirs beneath the sub-Pennsylvanian unconformity in the Cherokee basin, and in reservoirs generally above the unconformity in the Cherokee and Sedgwick basins, the eastern Central Kansas uplift and the Hugoton embayment. ?? 1988.

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.

Induction of Oligodendrocyte Differentiation and In Vitro Myelination by Inhibition of Rho-Associated Kinase

PubMed Central

Taylor, Christopher; Pereira, Albertina; Seng, Michelle; Tham, Chui-Se; Izrael, Michal; Webb, Michael

2014-01-01

In inflammatory demyelinating diseases such as multiple sclerosis (MS), myelin degradation results in loss of axonal function and eventual axonal degeneration. Differentiation of resident oligodendrocyte precursor cells (OPCs) leading to remyelination of denuded axons occurs regularly in early stages of MS but halts as the pathology transitions into progressive MS. Pharmacological potentiation of endogenous OPC maturation and remyelination is now recognized as a promising therapeutic approach for MS. In this study, we analyzed the effects of modulating the Rho-A/Rho-associated kinase (ROCK) signaling pathway, by the use of selective inhibitors of ROCK, on the transformation of OPCs into mature, myelinating oligodendrocytes. Here we demonstrate, with the use of cellular cultures from rodent and human origin, that ROCK inhibition in OPCs results in a significant generation of branches and cell processes in early differentiation stages, followed by accelerated production of myelin protein as an indication of advanced maturation. Furthermore, inhibition of ROCK enhanced myelin formation in cocultures of human OPCs and neurons and remyelination in rat cerebellar tissue explants previously demyelinated with lysolecithin. Our findings indicate that by direct inhibition of this signaling molecule, the OPC differentiation program is activated resulting in morphological and functional cell maturation, myelin formation, and regeneration. Altogether, we show evidence of modulation of the Rho-A/ROCK signaling pathway as a viable target for the induction of remyelination in demyelinating pathologies. PMID:25289646

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.

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.

Effect of thermal maturation on the K-Ar, Rb-Sr and REE systematics of an organic-rich New Albany Shale as determined by hydrous pyrolysis

USGS Publications Warehouse

Clauer, Norbert; Chaudhuri, Sambhudas; Lewan, M.D.; Toulkeridis, T.

2006-01-01

Hydrous-pyrolysis experiments were conducted on an organic-rich Devonian-Mississippian shale, which was also leached by dilute HCl before and after pyrolysis, to identify and quantify the induced chemical and isotopic changes in the rock. The experiments significantly affect the organic-mineral organization, which plays an important role in natural interactions during diagenetic hydrocarbon maturation in source rocks. They produce 10.5% of volatiles and the amount of HCl leachables almost doubles from about 6% to 11%. The Rb-Sr and K-Ar data are significantly modified, but not just by removal of radiogenic 40Ar and 87Sr, as described in many studies of natural samples at similar thermal and hydrous conditions. The determining reactions relate to alteration of the organic matter marked by a significant change in the heavy REEs in the HCl leachate after pyrolysis, underlining the potential effects of acidic fluids in natural environments. Pyrolysis induces also release from organics of some Sr with a very low 87Sr/86Sr ratio, as well as part of U. Both seem to have been volatilised during the experiment, whereas other metals such as Pb, Th and part of U appear to have been transferred from soluble phases into stable (silicate?) components. Increase of the K2O and radiogenic 40Ar contents of the silicate minerals after pyrolysis is explained by removal of other elements that could only be volatilised, as the system remains strictly closed during the experiment. The observed increase in radiogenic 40Ar implies that it was not preferentially released as a volatile gas phase when escaping the altered mineral phases. It had to be re-incorporated into newly-formed soluble phases, which is opposite to the general knowledge about the behavior of Ar in supergene natural environments. Because of the strictly closed-system conditions, hydrous-pyrolysis experiments allow to better identify and even quantify the geochemical aspects of organic-inorganic interactions, such as elemental exchanges, transfers and volatilisation, in potential source-rock shales during natural diagenetic hydrocarbon maturation.

The provenance of Archean clastic metasediments in the Narryer Gneiss Complex, western Australia: Trace element geochemistry, Nd isotopes, and U-Pb ages for detrital zircons

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

Maas, R.; McCulloch, M.T.

1991-07-01

Clastic metasedimentary rocks of mid-Archean age from the Mt. Narryer and Jack Hills metasedimentary belts have REE patterns resembling those of mid- to late-Archean pelitic-quartzitic cratonic sequences elsewhere, and post-Archean continental rocks in general. Detrital zircons in the metasediments range in age from ca. 3,000 to 3,700 Ma. This indicates a provenance from mature cratonic sources controlled by K-rich granitic rocks. Additional minor sediment sources were identified as older, mainly chemical sedimentary sequences, ultramafic rocks, and felsic rocks characterized by low HREE contents, perhaps of tonalitic affinity. Differences between sedimentary REE patterns and those in the surrounding 3.73-3.0 Ga orthogneissmore » terrain, and between detrital zircon ages and the age distribution in the gneisses, suggest that the present association of the metasedimentary belts with the orthogneiss terrain is of tectonic origin. The occurrence of detrital zircons with U-Pb ages > 4 Ga in certain quartzites and conglomerates of the Jack Hills and Mt. Narryer metasedimentary sequences indicates a further, most likely granitic, source. {epsilon}{sub Nd}(T{sub Dep}) values in Jack Hills metasediments vary widely (+5 to {minus}12) but have a smaller range in the Mt. Narryer belt ({minus}5 to {minus}9). The lowest {epsilon}{sub Nd} values of both sequences are interpreted to reflect the presence of detritus derived from 4.1-4.2 Ga old LREE-enriched continental crust in proportions considerably larger ({ge} 10%) than estimated previously from the abundance of pre-4 Ga detrital zircons ({approx}3%). This would imply the former existence of significant volumes of pre-4 Ga continental crust in the provenance of the Mt. Narryer and Jack Hills metasediments.« less

Geochemical evaluation of part of the Cambay basin, India

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

Banerjee, A.; Rao, K.L.N.

1993-01-01

In Broach-Jambusar and Ahmedabad-Mehsana blocks of Cambay basin, India, the hydrocarbon generated (HCG) and hydrocarbon expelled (HCE) per unit area of four Paleogene formations were computed at 38 locations to select the best targets and thus reduce exploration risk. Fractional generation curves, which show relation between vitrinite reflectance and fraction of original generative potential converted to hydrocarbons, were constructed for study areas and used to calculate HCG through remaining generation potential (S[sub 2] of Rock-Eval) and the thickness of the sedimentary section. HCE was estimated by subtracting volatile hydrocarbon content (S[sub 1] of Rock-Eval), representing the unexpelled in-situ-generated bitumen, frommore » the computed value of HCG. HCG and HCE, which combine source rock richness, thickness, and maturity, are useful for comparative evaluation of charging capacity of source rocks. Positive and negative HCEs characterize drainage and accumulation locales, respectively. In the study areas, the major generative depressions are at Sobhasan/Linch/Wadu and Ahmedabad in the Ahmedabad-Mehsana block and the Tankari and Broach depressions in the Broach-Jambusar block. In these areas, Paleogene source rocks have generated between 3 million and 12 million MT hydrocarbon/km[sup 2]. The major known oil and gas accumulations, which are in middle to lower Eocene sandstones in vicinity of the generative depressions, overlie 2 million to 7 million MT hydrocarbon/km[sup 2] and HCG contours in both blocks and correlate well with negative HCE in the reservoir. Isopach maps of several major middle to lower Eocene reservoir sandstones in conjunction with HCG maps for Paleogene section help to delineate favorable exploration locales. 23 refs., 31 figs.« less

Organic and clay mineral diagenesis in Neogene sediments of western Taiwan

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

Hsueh, C.M.

1985-01-01

Three deep wells (two in the northern region and one in the southern region) with completion depths of over 5000m have been selected and the rock samples thoroughly examined. The TOC data of most samples studied are less than 1%, which is the TOC of an average shale. The low TOC is unfavorable for the Neogene sediments in western Taiwan as good source rocks. The data of C,H elemental analysis and Rock-Eval pyrolysis imply that the quality of kerogen in the northern region inclines to type II wet-gas prone, and in the southern region inclines to type III dry-gas prone.more » The maturity parameters of bitumen ratio, vitrinite reflectance, Tmax of Rock-Eval pyrolysis, and TTI of Lopatin's method show that the threshold of the oil-generative zone (about 0.6% Ro) in the northern region is in middle Miocene (about 3000m) and in the southern region is in lower Pliocene (about 4500m). The result of clay mineral analysis reveals that the transformation of smectitic clays to ordered mixed-layered smectite-illite can be identified and correlated with 0.6% Ro vitrinite reflectance. The illite crystallinity values are in the range of incipient to weak metamorphism and decrease with burial depth implying that the source area of low-grade metamorphic rocks has been uplifted rapidly so that the erosion from the exposed source area where the metamorphic grade became higher and higher was sufficiently fast to prevent weathering of illite. The Neogene sediments studied would not be expected to generate substantial amounts of oil. However, it can be expected that the pre-Miocene sediments in the northern region and the pre-Pliocene sediments in the southern region should have generated substantial amounts of gas at deeper depths.« less

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

Thermal history of sedimentary basins, maturation indices, and kinetics of oil and gas generation

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

Tissot, B.P.; Pelet, R.; Ungerer, P.

1987-12-01

Temperature is the most sensitive parameter in hydrocarbon generation. Thus, reconstruction of temperature history is essential when evaluating petroleum prospects. No measurable parameter can be directly converted to paleotemperature. Maturation indices such as vitrinite reflectance, T/sub max/ from Rock-Eval pyrolysis, spore coloration, Thermal Alteration Index (TAI), or concentration of biological markers offer an indirect approach. All these indices are a function of the thermal history through rather complex kinetics, frequently influenced by the type of organic matter. Their significance and validity are reviewed. Besides the problems of identification (e.g. vitrinite) and interlaboratory calibration, it is important to simultaneously interpret kerogenmore » type and maturation and to avoid difficult conversions from one index to another. Geodynamic models, where structural and thermal histories are connected, are another approach to temperature reconstruction which could be calibrated against the present distribution of temperature and the present value of maturation indices. Kinetics of kerogen decomposition controls the amount and composition of hydrocarbons generated. An empirical time-temperature index (TTI), originally introduced by Lopatin, does not allow such a quantitative evaluation. Due to several limitations (no provision for different types of kerogen and different rates of reactions, poor calibration on vitrinite reflectance), it is of limited interest unless one has no access to a desk-top computer. Kinetic models, based on a specific calibration made on actual source rock samples, can simulate the evolution of all types of organic matter and can provide a quantitative evaluation of oil and gas generated. 29 figures.« less

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.

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.

Material-balance assessment of the New Albany-Chesterian petroleum system of the Illinois basin

USGS Publications Warehouse

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

2002-01-01

The New Albany-Chesterian petroleum system of the Illinois basin is a well-constrained system from which petroleum charges and losses were quantified through a material-balance assessment. This petroleum system has nearly 90,000 wells penetrating the Chesterian section, a single New Albany Shale source rock accounting for more than 99% of the produced oil, well-established stratigraphic and structural frameworks, and accessible source rock samples at various maturity levels. A hydrogen index (HI) map based on Rock-Eval analyses of source rock samples of New Albany Shale defines the pod of active source rock and extent of oil generation. Based on a buoyancy-drive model, the system was divided into seven secondary-migration catchments. Each catchment contains a part of the active pod of source rock from which it derives a petroleum charge, and this charge is confined to carrier beds and reservoirs within these catchments as accountable petroleum, petroleum losses, or undiscovered petroleum. A well-constrained catchment with no apparent erosional or leakage losses is used to determine an actual petroleum charge from accountable petroleum and residual migration losses. This actual petroleum charge is used to calibrate the other catchments in which erosional petroleum losses have occurred. Petroleum charges determined by laboratory pyrolysis are exaggerated relative to the actual petroleum charge. Rock-Eval charges are exaggerated by a factor of 4-14, and hydrouspyrolysis charges are exaggerated by a factor of 1.7. The actual petroleum charge provides a more meaningful material balance and more realistic estimates of petroleum losses and remaining undiscovered petroleum. The total petroleum charge determined for the New Albany-Chesterian system is 78 billion bbl, of which 11.4 billion bbl occur as a accountable in place petroleum, 9 billion bbl occur as residual migration losses, and 57.6 billion bbl occur as erosional losses. Of the erosional losses, 40 billion bbl were lost from two catchments that have highly faulted and extensively eroded sections. Anomalies in the relationship between erosional losses and degree of erosion suggest there is potential for undiscovered petroleum in one of the catchments. These results demonstrate that a material-balance assessment of migration catchments provides a useful means to evaluate and rank areas within a petroleum system. The article provides methodologies for obtaining more realistic petroleum charges and losses that can be applied to less data-rich petroleum systems.

The provenance of Archean clastic metasediments in the Narryer Gneiss Complex, Western Australia: Trace element geochemistry, Nd isotopes, and U-Pb ages for detrital zircons

NASA Astrophysics Data System (ADS)

Maas, Roland; McCulloch, Malcolm T.

1991-07-01

Clastic metasedimentary rocks of mid-Archean age from the Mt. Narryer and Jack Hills metasedimentary belts have REE patterns resembling those of mid- to late-Archean pelitic-quartzitic cratonic sequences elsewhere, and post-Archean continental rocks in general. Detrital zircons in the metasediments range in age from ca. 3000 to 3700 Ma. This indicates a provenance from mature cratonic sources controlled by K-rich granitic rocks. Additional minor sediment sources were identified as older, mainly chemical sedimentary sequences, ultramafic rocks, and felsic rocks characterized by low HREE contents, perhaps of tonalitic affinity. The association of the near-shore/fluviatile clastic association studied here with extensive turbiditic and chemical sedimentary sequences indicates these sources formed part of a (rifted ?) cratonic margin ca. 3 Ga ago. Differences between sedimentary REE patterns and those in the surrounding 3.73-3.0 Ga orthogneiss terrain, and between detrital zircon ages and the age distribution in the gneisses, suggest that the present association of the metasedimentary belts with the orthogneiss terrain is of tectonic origin. The occurrence of detrital zircons with U-Pb ages > 4 Ga in certain quartzites and conglomerates of the Jack Hills and Mt. Narryer metasedimentary sequences indicates a further, most likely granitic, source. ɛNd( TDep) values in Jack Hills metasediments vary widely (+5 to -12) but have a smaller range in the Mt. Narryer belt (-5 to -9). The lowest ɛNd values of both sequences are interpreted to reflect the presence of detritus derived from 4.1-4.2 Ga old LREE-enriched continental crust in proportions considerably larger (≥ 10%) than estimated previously from the abundance of pre-4 Ga detrital zircons (≈3%). This would imply the former existence of significant volumes of pre-4 Ga continental crust in the provenance of the Mt. Narryer and Jack Hills metasediments.

WEST AND EAST PALISADES ROADLESS AREAS, IDAHO AND WYOMING.

USGS Publications Warehouse

Oriel, Steven S.; Benham, John R.

1984-01-01

Studies of the West and East Palisades Roadless Areas, which lie within the Idaho-Wyoming thrust belt, document structures, reservoir formations, source beds, and thermal maturities comparable to those in producing oil and gas field farther south in the belt. Therefore, the areas are highly favorable for the occurrence of oil and gas. Phosphate beds of appropriate grade within the roadless areas are thinner and less accessible than those being mined from higher thrust sheets to the southwest; however, they contain 98 million tons of inferred phosphate rock resources in areas of substantiated phosphate resource potential. Sparsely distributed thin coal seams occur in the roadless areas. Although moderately pure limestone is present, it is available from other sources closer to markets. Geochemical anomalies from stream-sediment and rock samples for silver, copper, molydenum, and lead occur in the roadless areas but they offer little promise for the occurrence of metallic mineral resources. A possible geothermal resource is unproven, despite thermal phenomena at nearby sites.

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?

FTIR absorption indices for thermal maturity in comparison with vitrinite reflectance R0 in type-II kerogens from Devonian black shales

USGS Publications Warehouse

Lis, G.P.; Mastalerz, Maria; Schimmelmann, A.; Lewan, M.D.; Stankiewicz, B.A.

2005-01-01

FTIR absorbance signals in kerogens and macerals were evaluated as indices for thermal maturity. Two sets of naturally matured type-II kerogens from the New Albany Shale (Illinois Basin) and the Exshaw Formation (Western Canada Sedimentary Basin) and kerogens from hydrous pyrolysis artificial maturation of the New Albany Shale were characterized by FTIR. Good correlation was observed between the aromatic/aliphatic absorption ratio and vitrinite reflectance R 0. FTIR parameters are especially valuable for determining the degree of maturity of marine source rocks lacking vitrinite. With increasing maturity, FTIR spectra express four trends: (i) an increase in the absorption of aromatic bands, (ii) a decrease in the absorption of aliphatic bands, (iii) a loss of oxygenated groups (carbonyl and carboxyl), and (iv) an initial decrease in the CH2/CH3 ratio that is not apparent at higher maturity in naturally matured samples, but is observed throughout increasing R0 in artificially matured samples. The difference in the CH2/CH 3 ratio in samples from natural and artificial maturation at higher maturity indicates that short-term artificial maturation at high temperatures is not fully equivalent to slow geologic maturation at lower temperatures. With increasing R0, the (carboxyl + carbonyl)/aromatic carbon ratio generally decreases, except that kerogens from the Exshaw Formation and from hydrous pyrolysis experiments express an intermittent slight increase at medium maturity. FTIR-derived aromaticities correlate well with R0, although some uncertainty is due to the dependence of FTIR parameters on the maceral composition of kerogen whereas R0 is solely dependent on vitrinite. ?? 2005 Elsevier Ltd. All rights reserved.

Source potential of the Zairian onshore pre-salt subbasins of the West African Aptian salt basin

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

Swirydczuk, K.; Tshiband, D.; Nyimi, M.

1996-08-01

Three pre-salt subbasins are located onshore in Zaire in the Congo-Cabinda Basin. Production exists to the west, and extensive outcrops of Mavuma tar sands are located immediately to the east of these subbasins. Five pre-salt wells confirmed that thick Barremian lacustrine claystones of the Bucomazi Formation form the main source horizon in all the subbasins. Upper Bucomazi claystones average 4% and reach 12% TOC. Lower Bucomazi claystones average 2% (high of 6%). A mixed Type I/Type II algal oil-prone kerogen predominates. Up to 1% TOC is present in claystones in the underlying Lucula section. Dry pyrolysis shows significant differences inmore » kerogen kinetics from subbasin to subbasin. R{sub o} and T{sub max} were used to model heat flow through time. Ages were from biostratigraphic analyses and radiometric dating of thin volcanics within the Lucula and Bucomazi formations. Apatite fission track analyses provided control on uplift history. Pseudowells were used in maturation modelling to predict source rock maturity in the subbasins. The upper Bucomazi is immature except in the deeper parts of two of the subbasins. The Lower - Bucomazi and Upper Lucula are mature in all subbasins and in the deepest subbasins are overmature. Oil generation occurred shortly after deposition of the Loeme Salt. Analyses of Lindu oil support this early migration. Estimates of oil that may have been generated in the eastern-most subbasin suggest that extensive Mavuma tar sands, which have been typed to lacustrine source, could have been sourced from this subbasin.« less

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

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

Kinetic effect of heating rate on the thermal maturity of carbonaceous material as an indicator of frictional heat during earthquakes

NASA Astrophysics Data System (ADS)

Kaneki, Shunya; Hirono, Tetsuro

2018-06-01

Because the maximum temperature reached in the slip zone is significant information for understanding slip behaviors during an earthquake, the maturity of carbonaceous material (CM) is widely used as a proxy for detecting frictional heat recorded by fault rocks. The degree of maturation of CM is controlled not only by maximum temperature but also by the heating rate. Nevertheless, maximum slip zone temperature has been estimated previously by comparing the maturity of CM in natural fault rocks with that of synthetic products heated at rates of about 1 °C s-1, even though this rate is much lower than the actual heating rate during an earthquake. In this study, we investigated the kinetic effect of the heating rate on the CM maturation process by performing organochemical analyses of CM heated at slow (1 °C s-1) and fast (100 °C s-1) rates. The results clearly showed that a higher heating rate can inhibit the maturation reactions of CM; for example, extinction of aliphatic hydrocarbon chains occurred at 600 °C at a heating rate of 1 °C s-1 and at 900 °C at a heating rate of 100 °C s-1. However, shear-enhanced mechanochemical effects can also promote CM maturation reactions and may offset the effect of a high heating rate. We should thus consider simultaneously the effects of both heating rate and mechanochemistry on CM maturation to establish CM as a more rigorous proxy for frictional heat recorded by fault rocks and for estimating slip behaviors during earthquake.

Isotopic Equilibrium in Mature Oceanic Lithosphere: Insights From Sm-Nd Isotopes on the Corsica (France) Ophiolites

NASA Astrophysics Data System (ADS)

Rampone, E.; Hofmann, A. W.; Raczek, I.; Romairone, A.

2003-12-01

In mature oceanic lithosphere, formed at mid-ocean ridges, residual mantle peridotites and associated magmatic crust are, in principle, linked by a cogenetic relationship, because the times of asthenospheric mantle melting and magmatic crust production are assumed to be roughly coheval. This implies that oceanic peridotites and associated magmatic rocks should have similar isotopic compositions. Few isotope studies have been devoted to test this assumption. At mid-ocean ridges, similar Nd isotopic compositions in basalts and abyssal peridotites have been found by Snow et al. (1994), thus indicating that oceanic peridotites are indeed residues of MORB melting. By contrast, Salters and Dick (2002) have documented Nd isotope differences between abyssal peridotites and associated basalts, with peridotites showing higher 143Nd/144Nd values, and they concluded that an enriched pyroxenitic source component is required to explain the low end of the 143Nd/144Nd variation of the basalts. Here we present Sm/Nd isotope data on ophiolitic mantle peridotites and intruded gabbroic rocks from Mt.Maggiore (Corsica, France), interpreted as lithosphere remnants of the Jurassic Ligurian Tethys ocean. The peridotites are residual after low-degree (<10%) fractional melting. In places, spinel peridotites grade to plagioclase-rich impregnated peridotites. Clinopyroxene separates from both spinel- and plagioclase- peridotites display high 147Sm/144Nd (0.49-0.59) and 143Nd/144Nd (0.513367-0.513551) ratios, consistent with their depleted signature. The associated gabbros have Nd isotopic compositions typical of MORB (143Nd/144Nd = 0.51312-0.51314). Sm/Nd data on plag, whole rock and cpx from an olivine gabbro define an internal isochron with an age of 162 +/- 10 Ma, and an initial epsilon Nd value (9.0) indicating a MORB-type source. In the Sm-Nd isochron diagram, the peridotite data also conform to the above linear array, their initial (160 Ma) epsilon Nd values varying in the range 7.6-8.9. Sm/Nd isotopic compositions of the peridotites are therefore consistent with a Jurassic age of melting and melt impregnation, and point to isotopic compositional similarities between depleted peridotites and associated magmatic rocks. In a regional geodynamic context, Sm/Nd isotope data for the Mt.Maggiore gabbro-peridotite association represent the first record of the attainment of a mature oceanic stage of the Ligurian Tethys ocean. Also, the data presented provide striking evidence of the existence of isotopic equilibrium between melts and their mantle residue. References Snow et al. (1994), Nature 371, 57-60. Salters and Dick (2002), Nature 418,68-72.

Variability over time in the sources of South Portuguese Zone turbidites: evidence of denudation of different crustal blocks during the assembly of Pangaea

NASA Astrophysics Data System (ADS)

Pereira, M. F.; Ribeiro, C.; Vilallonga, F.; Chichorro, M.; Drost, K.; Silva, J. B.; Albardeiro, L.; Hofmann, M.; Linnemann, U.

2014-07-01

This study combines geochemical and geochronological data in order to decipher the provenance of Carboniferous turbidites from the South Portuguese Zone (SW Iberia). Major and trace elements of 25 samples of graywackes and mudstones from the Mértola (Visean), Mira (Serpukhovian), and Brejeira (Moscovian) Formations were analyzed, and 363 U-Pb ages were obtained on detrital zircons from five samples of graywackes from the Mira and Brejeira Formations using LA-ICPMS. The results indicate that turbiditic sedimentation during the Carboniferous was marked by variability in the sources, involving the denudation of different crustal blocks and a break in synorogenic volcanism. The Visean is characterized by the accumulation of immature turbidites (Mértola Formation and the base of the Mira Formation) inherited from a terrane with intermediate to mafic source rocks. These source rocks were probably formed in relation to Devonian magmatic arcs poorly influenced by sedimentary recycling, as indicated by the almost total absence of pre-Devonian zircons typical of the Gondwana and/or Laurussia basements. The presence of Carboniferous grains in Visean turbidites indicates that volcanism was active at this time. Later, Serpukhovian to Moscovian turbiditic sedimentation (Mira and Brejeira Formations) included sedimentary detritus derived from felsic mature source rocks situated far from active magmatism. The abundance of Precambrian and Paleozoic zircons reveals strong recycling of the Gondwana and/or Laurussia basements. A peri-Gondwanan provenance is indicated by zircon populations with Neoproterozoic (Cadomian-Avalonian and Pan-African zircon-forming events), Paleoproterozoic, and Archean ages. The presence of late Ordovician and Silurian detrital zircons in Brejeira turbidites, which have no correspondence in the Gondwana basement of SW Iberia, indicates Laurussia as their most probable source.

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.

Map showing thermal-alteration indicies in roadless areas and the Santa Lucia Wilderness in the Los Padres National Forest, Southwestern California

USGS Publications Warehouse

Frederiksen, N.O.

1985-01-01

South of the Santa Ynez fault, the TAI's of exposed rocks near the fault are mainly between 2+ and 3– (2+/3–) to 3 and are generally in the early stage of thermal maturity with respect to the possible generation of oil. North of the Santa Ynez fault, the exposed rocks have TAI's mostly of 2 to 2+ and are mainly immature or transitional from immature to mature. However, Jurassic(?) and Lower Cretaceous samples from the central San Rafael Mountains have distinctly higher TAI's, similar to those of rocks south of the Santa Ynez fault.

Phaeodarian radiolarians as potential indicators of thermal maturation

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

Casey, R.E.

1986-04-01

Phaeodarian radiolarian skeletons contain large amounts of organic matter, and discolored phaeodarian skeletons are observed in the fossil record, which suggests that the skeletons may be useful as thermal maturation indicators. Such a maturation index would be useful in Monterey-type rocks that are difficult to interpret with conventional thermal maturation indexes. Phaeodarians extracted from plankton samples, Holocene Santa Barbara and Orca basin sediments, and Neogene Monterey rocks with siliceous facies were subjected to different temperatures of varying duration in pyrolysis experiments. To calibrate the observed phaeodarian color changes with a known standard, Holocene pine pollen were subjected to the samemore » treatment. These phaeodarian go through the same color change spectrum as do the pollen, but they appear to lag slightly behind the pollen color changes.« less

Geochemistry of Archean metasedimentary rocks of the Aravalli craton, NW India: Implications for provenance, paleoweathering and supercontinent reconstruction

NASA Astrophysics Data System (ADS)

Ahmad, Iftikhar; Mondal, M. E. A.; Satyanarayanan, M.

2016-08-01

Basement complex of the Aravalli craton (NW India) known as the Banded Gneissic Complex (BGC) is classified into two domains viz. Archean BGC-I and Proterozoic BGC-II. We present first comprehensive geochemical study of the Archean metasedimentary rocks occurring within the BGC-I. These rocks occur associated with intrusive amphibolites in a linear belt within the basement gneisses. The association is only concentrated on the western margin of the BGC-I. The samples are highly mature (MSm) to very immature (MSi), along with highly variable geochemistry. Their major (SiO2/Al2O3, Na2O/K2O and Al2O3/TiO2) and trace (Th/Sc, Cr/Th, Th/Co, La/Sc, Zr/Sc) element ratios, and rare earth element (REE) patterns are consistent with derivation of detritus from the basement gneisses and its mafic enclaves, with major contribution from the former. Variable mixing between the two end members and closed system recycling (cannibalism) resulted in the compositional heterogeneity. Chemical index of alteration (CIA) of the samples indicate low to moderate weathering of the source terrain in a sub-tropical environment. In A-CN-K ternary diagram, some samples deceptively appear to have undergone post-depositional K-metasomatism. Nevertheless, their petrography and geochemistry (low K2O and Rb) preclude the post-depositional alteration. We propose non-preferential leaching of elements during cannibalism as the cause of the deceptive K-metasomatism as well as enigmatic low CIA values of some highly mature samples. The Archean metasedimentary rocks were deposited on stable basement gneisses, making the BGC-I a plausible participant in the Archean Ur supercontinent.

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.

Provenance and depositional history of continental slope sediments in the Southwestern Gulf of Mexico unraveled by geochemical analysis

NASA Astrophysics Data System (ADS)

Armstrong-Altrin, John S.; Machain-Castillo, María Luisa; Rosales-Hoz, Leticia; Carranza-Edwards, Arturo; Sanchez-Cabeza, Joan-Albert; Ruíz-Fernández, Ana Carolina

2015-03-01

The aim of this work is to constrain the provenance and depositional history of continental slope sediments in the Southwestern Gulf of Mexico (~1089-1785 m water depth). To achieve this, 10 piston sediment cores (~5-5.5 m long) were studied for mineralogy, major, trace and rare earth element geochemistry. Samples were analyzed at three core sections, i.e. upper (0-1 cm), middle (30-31 cm) and lower (~300-391 cm). The textural study reveals that the core sediments are characterized by silt and clay fractions. Radiocarbon dating of sediments for the cores at different levels indicated a maximum of ~28,000 year BP. Sediments were classified as shale. The chemical index of alteration (CIA) values for the upper, middle, and lower sections revealed moderate weathering in the source region. The index of chemical maturity (ICV) and SiO2/Al2O3 ratio indicated low compositional maturity for the core sediments. A statistically significant correlation observed between total rare earth elements (∑REE) versus Al2O3 and Zr indicated that REE are mainly housed in detrital minerals. The North American Shale Composite (NASC) normalized REE patterns, trace element concentrations such as Cr, Ni and V, and the comparison of REE concentrations in sediments and source rocks indicated that the study area received sediments from rocks intermediate between felsic and mafic composition. The enrichment factor (EF) results indicated that the Cd and Zn contents of the upper section sediments were influenced by an anthropogenic source. The trace element ratios and authigenic U content of the core sediments indicated the existence of an oxic depositional environment.

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.

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.

Oil/source rock correlations in the Polish Flysch Carpathians and Mesozoic basement and organic facies of the Oligocene Menilite Shales: Insights from hydrous pyrolysis experiments

USGS Publications Warehouse

Curtis, John B.; Kotarba, M.J.; Lewan, M.D.; Wieclaw, D.

2004-01-01

The Oligocene Menilite Shales in the study area in the Polish Flysch Carpathians are organic-rich and contain varying mixtures of Type-II, Type-IIS and Type-III kerogen. The kerogens are thermally immature to marginally mature based on atomic H/C ratios and Rock-Eval data. This study defined three organic facies, i.e., sedimentary strata with differing hydrocarbon-generation potentials due to varying types and concentrations of organic matter. These facies correspond to the Silesian Unit and the eastern and western portions of the Skole Unit. Analysis of oils generated by hydrous pyrolysis of outcrop samples of Menilite Shales demonstrates that natural crude oils reservoired in the flysch sediments appear to have been generated from the Menilite Shales. Natural oils reservoired in the Mesozoic basement of the Carpathian Foredeep appear to be predominantly derived and migrated from Menilite Shales, with a minor contribution from at least one other source rock most probably within Middle Jurassic strata. Definition of organic facies may have been influenced by the heterogeneous distribution of suitable Menilite Shales outcrops and producing wells, and subsequent sample selection during the analytical phases of the study. ?? 2004 Elsevier Ltd. All rights reserved.

Experimental investigation of the role of rock fabric in gas generation and expulsion during thermal maturation: Anhydrous closed-system pyrolysis of a bitumen-rich Eagle Ford Shale

USGS Publications Warehouse

Shao, Deyong; Ellis, Geoffrey S.; Li, Yanfang; Zhang, Tongwei

2018-01-01

Gold-tube pyrolysis experiments were conducted on miniature core plugs and powdered rock from a bitumen-rich sample of Eagle Ford Shale to investigate the role of rock fabric in gas generation and expulsion during thermal maturation. The samples were isothermally heated at 130, 300, 310, 333, 367, 400, and 425 °C for 72 h under a confining pressure of 68.0 MPa, corresponding to six levels of induced thermal maturity: pre-oil generation (130 °C/72 h), incipient oil/bitumen generation (300 and 310 °C/72 h), early oil generation (333 °C/72 h), peak oil generation (367 °C/72 h), early oil cracking (400 °C/72 h), and late oil cracking (425 °C/72 h). Experimental results show that gas retention coupled with compositional fractionation occurs in the core plug experiments and varies as a function of thermal maturity. During the incipient oil/bitumen generation stage, yields of methane through pentane (C1–C5) from core plugs are significantly lower than those from rock powder, and gases from core plugs are enriched in methane. However, the differences in C1–C5 gas yield and composition decrease throughout the oil generation stage, and by the oil cracking stage no obvious compositional difference in C1–C5 gases exists. The decrease in the effect of rock fabric on gas yield and composition with increasing maturity is the result of an increase in gas expulsion efficiency. Pyrolysis of rock powder yields 4–16 times more CO2 compared to miniature core plugs, with δ13CCO2 values ranging from −2.9‰ to −0.6‰, likely due to carbonate decomposition accelerated by reactions with organic acids. Furthermore, lower yields of gaseous alkenes and H2 from core plug experiments sugge

Geochemistry and organic facies of La Luna-Tres Esquinas cycle: Maturity, biomarkers and kerogen issues

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

Olivares, C.; Lorente, M.A.; Cassani, F.

1996-08-01

Four surface sections from the Venzuelan Andes were chosen for this study. The results show interesting trends for exploration of the Andean Belt. In the Eastern Andes (Trujillo), sections San Lazaro and Chejende yield thick, post-mature, highly tectonically disturbed La Luna Formation. San Lazaro section has a fault contact showing La Luna post-mature, inertinitic shales in contact with gray shales, ftanites and carbonates bearing marginally mature, highly fluorescent organic gels. Biomarkers show a high level of hopanes, predominance of C27/C29, and S/R ratio=64% characteristic of marine, moderate mature organic matter. Chejende section has almost the same pattern of marine organicmore » matter (COT=9%) but post-mature. In the Central Andes (Merida), El Valle and San Javier sections yield extremely rich source rocks with very different organic matter. El Valle section (Tres Esquinas Member) has very rich structured algal matter (COT=8%), marginally mature, which is correlated with a short term carbon isotope ({delta}{sup 13}C) fluctuation found in the Campanian-Santonian (anoxic?) cycle. The abundance of C27/C29, and high levels of hopanes are related to marine anoxic conditions. The San Javier section shows evidence of a very rich type I/II kerogen, bearing algal-bacterial amorphous masses, marginally mature and rich (COT=3%); this pattern matches with the abundance of C27/C29 as well as with the ratio S/R=64%, which means moderate maturity. From these results, two provinces can be separated today: a highly tectonized, post-mature, Eastern Andes Province and a very rich, marginally mature, Central Andes Province.« 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.

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

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.

Assessment of the potential of the rock gunnel (Pholis gunnellus) along the Atlantic coast of Canada as a species for monitoring the reproductive impacts of contaminant exposures.

PubMed

Vallis, L; MacLatchy, D L; Munkittrick, K R

2007-05-01

Evaluating the impacts of point source discharges on fish species in estuarine environments can be challenging because of a paucity of resident species. We evaluated the biology of rock gunnel (Pholis gunnellus) at three relatively uncontaminated sites in the Bay of Fundy, along the Atlantic coast of Canada. Rock gunnel are seasonally resident (April to November) in tide pools, but little was known about their life history in Atlantic Canada or their potential for use for monitoring environmental quality. Fish were collected between April and November, and ranged from 2.46 g-15.2g in weight and 97 mm-170 mm in length, with a maximum age of 7 years. Both males and females were similar in size, and both reached sexual maturity at a size of 5.5 g. Organ weights and condition indices of fish were stable from spring when they returned from offshore (April to May) until late summer (August to September), but fall fish (October to November) had slightly larger gonads, livers and condition indices. Rock gunnel may be a useful indicator to provide insight into local impacts of point sources over a short time period. However, they do not provide adequate information on reproductive development and performance since they are not exposed to onshore contaminants during the periods of gonadal development that have most commonly found to be sensitive to anthropogenic stressors.

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.

Vitrinite Reflectance Data for the Wind River Basin, Central Wyoming

USGS Publications Warehouse

Finn, Thomas M.; Roberts, Laura N.R.; Pawlewicz, Mark J.

2006-01-01

Introduction: The Wind River Basin is a large Laramide (Late Cretaceous through Eocene) structural and sedimentary basin that encompasses about 7,400 mi2 in central Wyoming. The basin boundaries are defined by fault-bounded Laramide uplifts that surround it, including the Owl Creek and Bighorn Mountains to the north, Wind River Range to the west, Granite Mountains to the south, and Casper Arch to the east. The purpose of this report is to present new vitrinite reflectance data to be used in support of the U.S Geological Survey assessment of undiscovered oil and gas resources of the Wind River Basin. One hundred and nineteen samples were collected from Jurassic through Tertiary rocks, mostly coal-bearing strata, in an effort to better understand and characterize the thermal maturation and burial history of potential source rocks.

Catagenesis of organic matter of oil source rocks in Upper Paleozoic coal formation of the Bohai Gulf basin (eastern China)

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

Li, R.X.; Li, Y.Z.; Gao, Y.W.

2007-05-15

The Bohai Gulf basin is the largest petroliferous basin in China. Its Carboniferous-Permian deposits are thick (on the average, ca. 600 m) and occur as deeply as 5000 m. Coal and carbonaceous shale of the Carboniferous Taiyuan Formation formed in inshore plain swamps. Their main hydrocarbon-generating macerals are fluorescent vitrinite, exinite, alginite, etc. Coal and carbonaceous shale of the Permian Shanxi Formation were deposited in delta-alluvial plain. Their main hydrocarbon-generating macerals are vitrinite, exinite, etc. The carbonaceous rocks of these formations are characterized by a high thermal maturity, with the vitrinite reflectance R{sub 0} > 2.0%. The Bohai Gulf basinmore » has been poorly explored so far, but it is highly promising for natural gas.« less

Deformation and the timing of gas generation and migration in the eastern Brooks Range foothills, Arctic National Wildlife Refuge, Alaska

USGS Publications Warehouse

Parris, T.M.; Burruss, R.C.; O'Sullivan, P. B.

2003-01-01

Along the southeast border of the 1002 Assessment Area in the Arctic National Wildlife Refuge, Alaska, an explicit link between gas generation and deformation in the Brooks Range fold and thrust belt is provided through petrographic, fluid inclusion, and stable isotope analyses of fracture cements integrated with zircon fission-track data. Predominantly quartz-cemented fractures, collected from thrusted Triassic and Jurassic rocks, contain crack-seal textures, healed microcracks, and curved crystals and fluid inclusion populations, which suggest that cement growth occurred before, during, and after deformation. Fluid inclusion homogenization temperatures (175-250??C) and temperature trends in fracture samples suggest that cements grew at 7-10 km depth during the transition from burial to uplift and during early uplift. CH4-rich (dry gas) inclusions in the Shublik Formation and Kingak Shale are consistent with inclusion entrapment at high thermal maturity for these source rocks. Pressure modeling of these CH4-rich inclusions suggests that pore fluids were overpressured during fracture cementation. Zircon fission-track data in the area record postdeposition denudation associated with early Brooks Range deformation at 64 ?? 3 Ma. With a closure temperature of 225-240??C, the zircon fission-track data overlap homogenization temperatures of coeval aqueous inclusions and inclusions containing dry gas in Kingak and Shublik fracture cements. This critical time-temperature relationship suggests that fracture cementation occurred during early Brooks Range deformation. Dry gas inclusions suggest that Shublik and Kingak source rocks had exceeded peak oil and gas generation temperatures at the time structural traps formed during early Brooks Range deformation. The timing of hydrocarbon generation with respect to deformation therefore represents an important exploration risk for gas exploration in this part of the Brooks Range fold and thrust belt. The persistence of gas high at thermal maturity levels suggests, however, that significant volumes of gas may have been generated.

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.

Thermal maturity patterns in New York State using CAI and %Ro

USGS Publications Warehouse

Weary, D.J.; Ryder, R.T.; Nyahay, R.E.

2001-01-01

New conodont alteration index (CAI) and vitrinite reflectance (%Ro) data collected from drill holes in the Appalachian basin of New York State allow refinement of thermal maturity maps for Ordovician and Devonian rocks. CAI isotherms on the new maps show a pattern that approximates that published by Harris et al. (1978) in eastern and western New York, but it differs in central New York, where the isotherms are shifted markedly westward by more than 100 km and are more tightly grouped. This close grouping of isograds reflects a steeper thermal gradient than previously noted by Harris et al. (1978) and agrees closely with the abrupt west-to-east increase in thermal maturity across New York noted by Johnsson (1986). These data show, in concordance with previous studies, that thermal maturity levels in these rocks are higher than can be explained by simple burial heating beneath the present thickness of overburden. The Ordovician and Devonian rocks of the Appalachian Basin in New York must have been buried by very thick post-Devonian sediments (4-6 km suggested by Sarwar and Friedman 1995) or were exposed to a higher-than-normal geothermal flux caused by crustal extension, or a combination of the two.

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.

Catalytic generation of methane at 60-100 °C and 0.1-300 MPa from source rocks containing kerogen Types I, II, and III

NASA Astrophysics Data System (ADS)

Wei, Lin; Schimmelmann, Arndt; Mastalerz, Maria; Lahann, Richard W.; Sauer, Peter E.; Drobniak, Agnieszka; Strąpoć, Dariusz; Mango, Frank D.

2018-06-01

Low temperature (60 and 100 °C) and long-term (6 months to 5 years) heating of pre-evacuated and sterilized shales and coals containing kerogen Types I (Mahogany Shale), II (Mowry Shale and New Albany Shale), and III (Springfield Coal and Wilcox Lignite) with low initial maturities (vitrinite reflectance Ro 0.39-0.62%) demonstrates that catalytically generated hydrocarbons may explain the occurrence of some non-biogenic natural gas accumulations where insufficient thermal maturity contradicts the conventional thermal cracking paradigm. Extrapolation of the observed rate of catalytic methanogenesis in the laboratory suggests that significant amounts of sedimentary organic carbon can be converted to relatively dry natural gas over tens of thousands of years in sedimentary basins at temperatures as low as 60 °C. Our laboratory experiments utilized source rock (shale and coal) chips sealed in gold and Pyrex® glass tubes in the presence of hydrogen-isotopically contrasting waters. Parallel heating experiments applied hydrostatic pressures from 0.1 to 300 MPa. Control experiments constrained the influence of pre-existing and residual methane in closed pores of rock chips that was unrelated to newly generated methane. This study's experimental methane yields at 60 and 100 °C are 5-11 orders of magnitude higher than the theoretically predicted yields from kinetic models of thermogenic methane generation, which strongly suggests a contribution of catalytic methanogenesis. Higher temperature, longer heating time, and lower hydrostatic pressure enhanced catalytic methanogenesis. No clear relationships were observed between kerogen type or total organic carbon content and methane yields via catalysis. Catalytic methanogenesis was strongest in Mowry Shale where methane yields at 60 °C amounted to ∼2.5 μmol per gram of organic carbon after one year of hydrous heating at ambient pressure. In stark contrast to the earlier findings of hydrogen isotopic exchange between water and thermogenic methane in hydrous pyrolysis experiments above 300 °C, the hydrogen isotopic composition of added water exerted limited influence on the δ2H value of methane generated catalytically at low temperatures. We hypothesize that the catalytic sites responsible for methanogenesis are located in hydrophobic microenvironments with limited access to water. The δ13CCH4 values of methane generated catalytically at 60-100 °C range from ∼-57.6 to -41.4‰ and are thus similar to typical thermogenic methane (δ13CCH4 >-50‰) and microbially generated methane (<-55‰). Future studies need to evaluate the possibility that clumped isotope characteristics of catalytically generated methane can diagnose the low-temperature regime of catalytic methanogenesis. Furthermore, testing of freshly cored anoxic rocks is needed to determine whether the use of archived, oxygen-exposed rocks in geochemical maturation/catalysis studies introduces artifacts in experimental hydrocarbon yields.

Thermal maturity and petroleum kitchen areas of Liassic Black Shales (Lower Jurassic) in the central Upper Rhine Graben, Germany

NASA Astrophysics Data System (ADS)

Böcker, Johannes; Littke, Ralf

2016-03-01

In the central Upper Rhine Graben (URG), several major oil fields have been sourced by Liassic Black Shales. In particular, the Posidonia Shale (Lias ɛ, Lower Toarcian) acts as excellent and most prominent source rock in the central URG. This study is the first comprehensive synthesis of Liassic maturity data in the URG area and SW Germany. The thermal maturity of the Liassic Black Shales has been analysed by vitrinite reflectance (VRr) measurements, which have been verified with T max and spore coloration index (SCI) data. In outcrops and shallow wells (<600 m), the Liassic Black Shales reached maturities equivalent to the very early or early oil window (ca. 0.50-0.60 % VRr). This maturity is found in Liassic outcrops and shallow wells in the entire URG area and surrounding Swabian Jura Mountains. Maximum temperatures of the Posidonia Shale before graben formation are in the order of 80-90 °C. These values were likely reached during Late Cretaceous times due to significant Upper Jurassic and minor Cretaceous deposition and influenced by higher heat flows of the beginning rift event at about 70 Ma. In this regard, the consistent regional maturity data (VRr, T max, SCI) of 0.5-0.6 % VRr for the Posidonia Shale close to surface suggest a major burial-controlled maturation before graben formation. These consistent maturity data for Liassic outcrops and shallow wells imply no significant oil generation and expulsion from the Posidonia Shale before formation of the URG. A detailed VRr map has been created using VRr values of 31 wells and outcrops with a structure map of the Posidonia Shale as reference map for a depth-dependent gridding operation. Highest maturity levels occur in the area of the Rastatt Trough (ca. 1.5 % VRr) and along the graben axis with partly very high VRr gradients (e.g. well Scheibenhardt 2). In these deep graben areas, the maximum temperatures which were reached during upper Oligocene to Miocene times greatly exceed those during the Cretaceous.

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.

Rho kinase inhibition drives megakaryocyte polyploidization and proplatelet formation through MYC and NFE2 downregulation.

PubMed

Avanzi, Mauro P; Goldberg, Francine; Davila, Jennifer; Langhi, Dante; Chiattone, Carlos; Mitchell, William Beau

2014-03-01

The processes of megakaryocyte polyploidization and demarcation membrane system (DMS) formation are crucial for platelet production, but the mechanisms controlling these processes are not fully determined. Inhibition of Rho kinase (ROCK) signalling leads to increased polyploidization in umbilical cord blood-derived megakaryocytes. To extend these findings we determined the effect of ROCK inhibition on development of the DMS and on proplatelet formation. The underlying mechanisms were explored by analysing the effect of ROCK inhibition on the expression of MYC and NFE2, which encode two transcription factors critical for megakaryocyte development. ROCK inhibition promoted DMS formation, and increased proplatelet formation and platelet release. Rho kinase inhibition also downregulated MYC and NFE2 expression in mature megakaryocytes, and this down-regulation correlated with increased proplatelet formation. Our findings suggest a model whereby ROCK inhibition drives polyploidization, DMS growth and proplatelet formation late in megakaryocyte maturation through downregulation of MYC and NFE2 expression. © 2014 John Wiley & Sons Ltd.

The Rho-GTPase effector ROCK regulates meiotic maturation of the bovine oocyte via myosin light chain phosphorylation and cofilin phosphorylation.

PubMed

Lee, So-Rim; Xu, Yong-Nan; Jo, Yu-Jin; Namgoong, Suk; Kim, Nam-Hyung

2015-11-01

Oocyte meiosis involves a unique asymmetric division involving spindle movement from the central cytoplasm to the cortex, followed by polar body extrusion. ROCK is a Rho-GTPase effector involved in various cellular functions in somatic cells as well as oocyte meiosis. ROCK was previously shown to promote actin organization by phosphorylating several downstream targets, including LIM domain kinase (LIMK), phosphorylated cofilin (p-cofilin), and myosin light chain (MLC). In this study, we investigated the roles of ROCK and MLC during bovine oocyte meiosis. We found that ROCK was localized around the nucleus at the oocyte's germinal-vesicle (GV) stage, but spreads to the rest of the cytoplasm in later developmental stages. On the other hand, phosphorylated MLC (p-MLC) localized at the cortex, and its abundance decreased by the metaphase-II stage. Disrupting ROCK activity, via RNAi or the chemical inhibitor Y-27632, blocked both cell cycle progression and polar body extrusion. ROCK inhibition also resulted in decreased cortical actin, p-cofilin, and p-MLC levels. Similar to the phenotype associated with inhibition of ROCK activity, inhibition of MLC kinase by the chemical inhibitor ML-7 caused defects in polar body extrusion. Collectively, our results suggest that the ROCK/MLC/actomyosin as well as ROCK/LIMK/cofilin pathways regulate meiotic spindle migration and cytokinesis during bovine oocyte maturation. © 2015 Wiley Periodicals, Inc.

Re-Os geochronology and Os isotope fingerprinting of petroleum sourced from a Type I lacustrine kerogen: Insights from the natural Green River petroleum system in the Uinta Basin and hydrous pyrolysis experiments

NASA Astrophysics Data System (ADS)

Cumming, Vivien M.; Selby, David; Lillis, Paul G.; Lewan, Michael D.

2014-08-01

Rhenium-osmium (Re-Os) geochronology of marine petroleum systems has allowed the determination of the depositional age of source rocks as well as the timing of petroleum generation. In addition, Os isotopes have been applied as a fingerprinting tool to correlate oil to its source unit. To date, only classic marine petroleum systems have been studied. Here we present Re-Os geochronology and Os isotope fingerprinting of different petroleum phases (oils, tar sands and gilsonite) derived from the lacustrine Green River petroleum system in the Uinta Basin, USA. In addition we use an experimental approach, hydrous pyrolysis experiments, to compare to the Re-Os data of naturally generated petroleum in order to further understand the mechanisms of Re and Os transfer to petroleum. The Re-Os geochronology of petroleum from the lacustrine Green River petroleum system (19 ± 14 Ma - all petroleum phases) broadly agrees with previous petroleum generation basin models (∼25 Ma) suggesting that Re-Os geochronology of variable petroleum phases derived from lacustrine Type I kerogen has similar systematics to Type II kerogen (e.g., Selby and Creaser, 2005a,b; Finlay et al., 2010). However, the large uncertainties (over 100% in some cases) produced for the petroleum Re-Os geochronology are a result of multiple generation events occurring through a ∼3000-m thick source unit that creates a mixture of initial Os isotope compositions in the produced petroleum phases. The 187Os/188Os values for the petroleum and source rocks at the time of oil generation vary from 1.4 to 1.9, with the mode at ∼1.6. Oil-to-source correlation using Os isotopes is consistent with previous correlation studies in the Green River petroleum system, and illustrates the potential utility of Os isotopes to characterize the spatial variations within a petroleum system. Hydrous pyrolysis experiments on the Green River Formation source rocks show that Re and Os transfer are mimicking the natural system. This transfer from source to bitumen to oil does not affect source rock Re-Os systematics or Os isotopic compositions. This confirms that Os isotope compositions are transferred intact from source to petroleum during petroleum generation and can be used as a powerful correlation tool. These experiments further confirm that Re-Os systematics in source rocks are not adversely affected by petroleum maturation. Overall this study illustrates that the Re-Os petroleum geochronometer and Os isotope fingerprinting tools can be used on a wide range of petroleum types sourced from variable kerogen types.

Re-Os geochronology and Os isotope fingerprinting of petroleum sourced from a Type I lacustrine kerogen: insights from the natural Green River petroleum system in the Uinta Basin and hydrous pyrolysis experiments

USGS Publications Warehouse

Cumming, Vivien M.; Selby, David; Lillis, Paul G.; Lewan, Michael D.

2014-01-01

Rhenium–osmium (Re–Os) geochronology of marine petroleum systems has allowed the determination of the depositional age of source rocks as well as the timing of petroleum generation. In addition, Os isotopes have been applied as a fingerprinting tool to correlate oil to its source unit. To date, only classic marine petroleum systems have been studied. Here we present Re–Os geochronology and Os isotope fingerprinting of different petroleum phases (oils, tar sands and gilsonite) derived from the lacustrine Green River petroleum system in the Uinta Basin, USA. In addition we use an experimental approach, hydrous pyrolysis experiments, to compare to the Re–Os data of naturally generated petroleum in order to further understand the mechanisms of Re and Os transfer to petroleum. The Re–Os geochronology of petroleum from the lacustrine Green River petroleum system (19 ± 14 Ma – all petroleum phases) broadly agrees with previous petroleum generation basin models (∼25 Ma) suggesting that Re–Os geochronology of variable petroleum phases derived from lacustrine Type I kerogen has similar systematics to Type II kerogen (e.g., Selby and Creaser, 2005a, Selby and Creaser, 2005b and Finlay et al., 2010). However, the large uncertainties (over 100% in some cases) produced for the petroleum Re–Os geochronology are a result of multiple generation events occurring through a ∼3000-m thick source unit that creates a mixture of initial Os isotope compositions in the produced petroleum phases. The 187Os/188Os values for the petroleum and source rocks at the time of oil generation vary from 1.4 to 1.9, with the mode at ∼1.6. Oil-to-source correlation using Os isotopes is consistent with previous correlation studies in the Green River petroleum system, and illustrates the potential utility of Os isotopes to characterize the spatial variations within a petroleum system. Hydrous pyrolysis experiments on the Green River Formation source rocks show that Re and Os transfer are mimicking the natural system. This transfer from source to bitumen to oil does not affect source rock Re–Os systematics or Os isotopic compositions. This confirms that Os isotope compositions are transferred intact from source to petroleum during petroleum generation and can be used as a powerful correlation tool. These experiments further confirm that Re–Os systematics in source rocks are not adversely affected by petroleum maturation. Overall this study illustrates that the Re–Os petroleum geochronometer and Os isotope fingerprinting tools can be used on a wide range of petroleum types sourced from variable kerogen types.

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

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

Bray, R.; Lawrence, S.; Swart, R.

Namibia`s territorial waters occupy a large portion of West Africa`s continental shelf. The area to the 1,000 m isobath is comparable in size to the combined offshore areas of Gabon, Congo, Zaire, and Angola. Around half as much again lies in 1,000--2,500 m of water. The whole unlicensed part of this area will be open for bidding when the Third Licensing Round starts Oct. 1, 1998. Offshore Namibia is underexplored by drilling with only seven exploration wells drilled. Shell`s Kudu field represents a considerable gas resource with reserves of around 3 tcf and is presently the only commercial discovery.Namibia`s offshoremore » area holds enormous exploration potential. Good quality sandstone reservoirs are likely to be distributed widely, and a number of prospective structural and stratigraphic traps have been identified. The recognition of Cretaceous marine oil-prone source rocks combined with the results of new thermal history reconstruction and maturity modeling studies are particularly significant in assessment of the oil potential. The paper discusses resource development and structures, oil source potential, maturity, and hydrocarbon generation.« less

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

Thermal modeling in Ceuta, Maracaibo Basin, Venezuela

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

Marcano, F.; Padron, S.

1993-02-01

Hydrocarbon generation from Upper Cretaceous source rocks (Fm.La Luna) in Ceuta, center-eastern Maracaibo lake area in Venezuela, is modeled here, using a kinetic method and the conventional Time-Temperature Index (TTI) procedure. Geological evolution, burial and erosional history is based on available interpretation of 3D seismic and well data. Fragmentary present-day subsurface temperature data comes from corrected measurements in a few wells. Paleogradient/heat paleoflux was estimated during the thermal modeling on wells, by calculating vitrinite reflectances (Ro) or Tmax values and then comparing them with measured ones. However, thermal-indicator data does not always appear to be consistent and some data hadmore » to be rejected. Paleogradient evolution in the Cretaceous is controlled by the development of a isolated thermal compartment related to overpressures in a thick shaly sequence in the Upper Cretaceous. A geological section was studied in detail to illustrate possible migration paths to known fields and undrilled traps. Results show a good fit between the thermal evolution of the source rock and the maturity of the crude produced in the area.« less

Thermal evolution of sedimentary basins in Alaska

USGS Publications Warehouse

Johnsson, Mark J.; Howell, D.G.

1996-01-01

The complex tectonic collage of Alaska is reflected in the conjunction of rocks of widely varying thermal maturity. Indicators of the level of thermal maturity of rocks exposed at the surface, such as vitrinite reflectance and conodont color alteration index, can help constrain the tectonic evolution of such complex regions and, when combined with petrographic, modern heat flow, thermogeochronologic, and isotopic data, allow for the detailed evaluation of a region?s burial and uplift history. We have collected and assembled nearly 10,000 vitrinite-reflectance and conodont-color-alteration index values from the literature, previous U.S. Geological Survey investigations, and our own studies in Alaska. This database allows for the first synthesis of thermal maturity on a broadly regional scale. Post-accretionary sedimentary basins in Alaska show wide variability in terms of thermal maturity. The Tertiary interior basins, as well as some of the forearc and backarc basins associated with the Aleutian Arc, are presently at their greatest depth of burial, with immature rocks exposed at the surface. Other basins, such as some backarc basins on the Alaska Peninsula, show higher thermal maturities, indicating modest uplift, perhaps in conjunction with higher geothermal gradients related to the arc itself. Cretaceous ?flysch? basins, such as the Yukon-Koyukuk basin, are at much higher thermal maturity, reflecting great amounts of uplift perhaps associated with compressional regimes generated through terrane accretion. Many sedimentary basins in Alaska, such as the Yukon-Koyukuk and Colville basins, show higher thermal maturity at basin margins, perhaps reflecting greater uplift of the margins in response to isostatic unloading, owing to erosion of the hinterland adjacent to the basin or to compressional stresses adjacent to basin margins.

Permian arc evolution associated with Panthalassa subduction along the eastern margin of the South China block, based on sandstone provenance and U-Pb detrital zircon ages of the Kurosegawa belt, Southwest Japan

NASA Astrophysics Data System (ADS)

Hara, Hidetoshi; Hirano, Miho; Kurihara, Toshiyuki; Takahashi, Toshiro; Ueda, Hayato

2018-01-01

We have studied the petrography, geochemistry, and detrital zircon U-Pb ages of sandstones from shallow-marine forearc sediments, accretionary complexes (ACs), and metamorphosed accretionary complexes (Meta-ACs) within the Kurosegawa belt of Southwest Japan. Those rocks formed in a forearc region of a Permian island arc associated with subduction of the Panthalassa oceanic crust along the eastern margin of the South China block (Yangtze block). The provenance of the shallow-marine sediments was dominated by basaltic to andesitic volcanic rocks and minor granitic rocks during the late Middle to Late Permian. The ACs were derived from felsic to andesitic volcanic rocks during the Late Permian. The provenance of Meta-ACs was dominated by andesitic volcanic rocks in the Middle Permian. The provenance, source rock compositions, and zircon age distribution for the forearc sediments, ACs and Meta-ACs have allowed us to reconstruct the geological history of the Permian arc system of the Kurosegawa belt. During the Middle Permian, the ACs were accreted along the eastern margin of the South China block. The Middle Permian arc was an immature oceanic island arc consisting of andesitic volcanic rocks. During the Late Permian, the ACs formed in a mature arc, producing voluminous felsic to andesitic volcanic rocks. A forearc basin developed during the late Middle to Late Permian. Subsequently, the Middle Permian ACs and part of the Late Permian AC underwent low-grade metamorphism in the Late to Early Jurassic, presenting the Meta-ACs.

Heat flow and hydrocarbon generation in the Transylvanian basin, Romania

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

Cranganu, C.; Deming, D.

1996-10-01

The Transylvanian basin in central Romania is a Neogene depression superimposed on the Cretaceous nappe system of the Carpathian Mountains. The basin contains the main gas reserves of Romania, and is one of the most important gas-producing areas of continental Europe; since 1902, gas has been produced from more than 60 fields. Surface heat flow in the Transylvanian basin as estimated in other studies ranges from 26 to 58 mW/m{sup 2}, with a mean value of 38 mW/m{sup 2}, relatively low compared to surrounding areas. The effect of sedimentation on heat flow and temperature in the Transylvanian basin was estimatedmore » with a numerical model that solved the heat equation in one dimension. Because both sediment thickness and heat flow vary widely throughout the Transylvanian basin, a wide range of model variables were used to bracket the range of possibilities. Three different burial histories were considered (thin, average, and thick), along with three different values of background heat flow (low, average, and high). Altogether, nine different model permutations were studied. Modeling results show that average heat flow in the Transylvanian basin was depressed approximately 16% during rapid Miocene sedimentation, whereas present-day heat flow remains depressed, on average, about 17% below equilibrium values. We estimated source rock maturation and the timing of hydrocarbon generation by applying Lopatin`s method. Potential source rocks in the Transylvanian basin are Oligocene-Miocene, Cretaceous, and Jurassic black shales. Results show that potential source rocks entered the oil window no earlier than approximately 13 Ma, at depths of between 4200 and 8800 m. Most simulations encompassing a realistic range of sediment thicknesses and background heat flows show that potential source rocks presently are in the oil window; however, no oil has ever been discovered or produced in the Transylvanian basin.« 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.

Fluvial/lacustrine diagenesis: Significance for hydrocarbon production and entrapment in the carboniferous Albert Fm, Moncton basin, NB

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

Noble, J.P.A.; Chowdhury, A.H.; Yu, H.

1996-12-31

The Carboniferous Horton Group Albert Formation sediments include lacustrine source-rock oil shales and fluvial porous reservoir sandstones. The petrography, stable isotopes, fluid inclusions, cathodoluminescence and mirror/trace element chemistry of these sandstones are used to establish the diagenetic history and controlling factors. Early diagenetic calcite, quartz and albite cements with minor chlorite and kaolinite are variably present and related to depositional mineralogy and lake levels winch controlled the porewater chemistry. Antitaxial veins occurring preferentially in shales are shown, from heavy {delta}C{sup 13} values and fluid inclusions, to be related to methanogenesis in overpressured zones at shallow depths. Later burial calcite andmore » extensive albitisation are related to mineral reactions during the phase of rapid subsidence at temperatures of 80{degrees} to 150{degrees} in the deepest segment of the basin, together with significant dissolution of carbonates and feldspars related mainly to organic acids generated by organic maturation processes. Mass balance calculations indicate that not enough organic matter was present to account for all the estimated secondary porosity and some evidence suggests that reactions between kaolinite and calcite/ankerite to produce chlorite, and mixed layer illite-smectite ordering reactions, produced significant secondary porosity. Burial history reconstructions and thermal modelling of the Albert Fm. sediments using Arrhenius type maturity models and reflectance and rock-eval data suggest locally variable maturation and reservoir production related to the locally different fault tectonic histories characteristic of strike-slip lacustrine segmented basins. The Horton depositional cycle was followed by major dextral transpression with local faulting and inversion and vein cementation.« less

Fluvial/lacustrine diagenesis: Significance for hydrocarbon production and entrapment in the carboniferous Albert Fm, Moncton basin, NB

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

Noble, J.P.A.; Chowdhury, A.H.; Yu, H.

1996-01-01

The Carboniferous Horton Group Albert Formation sediments include lacustrine source-rock oil shales and fluvial porous reservoir sandstones. The petrography, stable isotopes, fluid inclusions, cathodoluminescence and mirror/trace element chemistry of these sandstones are used to establish the diagenetic history and controlling factors. Early diagenetic calcite, quartz and albite cements with minor chlorite and kaolinite are variably present and related to depositional mineralogy and lake levels winch controlled the porewater chemistry. Antitaxial veins occurring preferentially in shales are shown, from heavy [delta]C[sup 13] values and fluid inclusions, to be related to methanogenesis in overpressured zones at shallow depths. Later burial calcite andmore » extensive albitisation are related to mineral reactions during the phase of rapid subsidence at temperatures of 80[degrees] to 150[degrees] in the deepest segment of the basin, together with significant dissolution of carbonates and feldspars related mainly to organic acids generated by organic maturation processes. Mass balance calculations indicate that not enough organic matter was present to account for all the estimated secondary porosity and some evidence suggests that reactions between kaolinite and calcite/ankerite to produce chlorite, and mixed layer illite-smectite ordering reactions, produced significant secondary porosity. Burial history reconstructions and thermal modelling of the Albert Fm. sediments using Arrhenius type maturity models and reflectance and rock-eval data suggest locally variable maturation and reservoir production related to the locally different fault tectonic histories characteristic of strike-slip lacustrine segmented basins. The Horton depositional cycle was followed by major dextral transpression with local faulting and inversion and vein cementation.« less

Stable sulfur isotope partitioning during simulated petroleum formation as determined by hydrous pyrolysis of Ghareb Limestone, Israel

USGS Publications Warehouse

Amrani, A.; Lewan, M.D.; Aizenshtat, Zeev

2005-01-01

Hydrous pyrolysis experiments at 200 to 365??C were carried out on a thermally immature organic-rich limestone containing Type-IIS kerogen from the Ghareb Limestone in North Negev, Israel. This work focuses on the thermal behavior of both organic and inorganic sulfur species and the partitioning of their stable sulfur isotopes among organic and inorganic phases generated during hydrous pyrolyses. Most of the sulfur in the rock (85%) is organic sulfur. The most dominant sulfur transformation is cleavage of organic-bound sulfur to form H2 S(gas). Up to 70% of this organic sulfur is released as H2S(gas) that is isotopically lighter than the sulfur in the kerogen. Organic sulfur is enriched by up to 2??? in 34S during thermal maturation compared with the initial ??34S values. The ??34S values of the three main organic fractions (kerogen, bitumen and expelled oil) are within 1??? of one another. No thermochemical sulfate reduction or sulfate formation was observed during the experiments. The early released sulfur reacted with available iron to form secondary pyrite and is the most 34S depleted phase, which is 21??? lighter than the bulk organic sulfur. The large isotopic fractionation for the early formed H2S is a result of the system not being in equilibrium. As partial pressure of H2S(gas) increases, retro reactions with the organic sulfur in the closed system may cause isotope exchange and isotopic homogenization. Part of the ??34S-enriched secondary pyrite decomposes above 300??C resulting in a corresponding decrease in the ??34S of the remaining pyrite. These results are relevant to interpreting thermal maturation processes and their effect on kerogen-oil-H2S-pyrite correlations. In particular, the use of pyrite-kerogen ??34S relations in reconstructing diagenetic conditions of thermally mature rocks is questionable because formation of secondary pyrite during thermal maturation can mask the isotopic signature and quantity of the original diagenetic pyrite. The main transformations of kerogen to bitumen and bitumen to oil can be recorded by using both sulfur content and ??34S of each phase including the H2S(gas). H2S generated in association with oil should be isotopically lighter or similar to oil. It is concluded that small isotopic differentiation obtained between organic and inorganic sulfur species suggests closed-system conditions. Conversely, open-system conditions may cause significant isotopic discrimination between the oil and its source kerogen. The magnitude of this discrimination is suggested to be highly dependent on the availability of iron in a source rock resulting in secondary formation of pyrite. Copyright ?? 2005 Elsevier Ltd.

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

Louda, J.W.; Baker, E.W.

The premier molecular index for assessing the thermal maturity(history) of a bitumen is the DPEP-to-ETIO ratio. A restatement of that data set has appeared and is the %-DPEP. This is also preferred by the present authors. These indices (D/E, %D) chronicle the relative presence, absence, and changes in that relationship for porphyrins with ({open_quotes}DPEP{close_quotes}, {open_quotes}CAP{close_quotes}) or without ({open_quotes}ETIO{close_quotes}) exocyclic cycloalkyl ring moieties. An alternative index, the Alkylation Index (Al) has received scant attention since its inception nearly 2 decades ago. This index increasingly weights the higher (>C32), more alkylated, species and ratios those to the pigments at C32 and lower.more » The present report is an integration of several of our past and more recent studies on sediments, shales and petroleum crudes. The application of cross-plotting %-DPEP versus Alkylation Index (%D x Al), in order to {open_quote}fine-tune{close_quote} thermal maturity assessments, for source rocks and oils is covered. Potential problems due to (1) the {open_quote}contamination{close_quote} of mature bitumen with immature biomarkers or (2) biodegradation are also discussed.« less

The Apollo 14 regolith - Petrology of cores 14210/14211 and 14220 and soils 14141, 14148, and 14149

NASA Technical Reports Server (NTRS)

Simon, S. B.; Papike, J. J.; Laul, J. C.

1982-01-01

New modal data are presented for continuous polished thin sections from double drive tube 14210/14211, and single drive tube 14220, and for polished grain mounts of four soils from the double drive tube, one from the single drive tube, and the soils 14148 (trench top), 14149 (trench bottom), and 14141 (Cone Crater). Modal data show that the Cone Crater soil is immature, whereas the 'smooth plains' soils are mature and rich in agglutinates and breccias. Neither core exhibits any major variations with depth. Microprobe analyses of mineral and glass fragments are consistent with derivation of the soils predominantly from the local rocks, with about 5-11% exotic mare component indicated by the modal data. About 4% of the glasses are SiO2- and K2O-rich granitic glasses which are comminuted mesostasis from the local melt rocks. The soils are depleted in feldspar relative to the source rocks. The preferred explanation for this depletion is that feldspar is concentrated in the less than 10 microns fines and is consumed in the formation of agglutinates, regolith breccias, and feldspathic glass.

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.

Realistic molecular model of kerogen's nanostructure

NASA Astrophysics Data System (ADS)

Bousige, Colin; Ghimbeu, Camélia Matei; Vix-Guterl, Cathie; Pomerantz, Andrew E.; Suleimenova, Assiya; Vaughan, Gavin; Garbarino, Gaston; Feygenson, Mikhail; Wildgruber, Christoph; Ulm, Franz-Josef; Pellenq, Roland J.-M.; Coasne, Benoit

2016-05-01

Despite kerogen's importance as the organic backbone for hydrocarbon production from source rocks such as gas shale, the interplay between kerogen's chemistry, morphology and mechanics remains unexplored. As the environmental impact of shale gas rises, identifying functional relations between its geochemical, transport, elastic and fracture properties from realistic molecular models of kerogens becomes all the more important. Here, by using a hybrid experimental-simulation method, we propose a panel of realistic molecular models of mature and immature kerogens that provide a detailed picture of kerogen's nanostructure without considering the presence of clays and other minerals in shales. We probe the models' strengths and limitations, and show that they predict essential features amenable to experimental validation, including pore distribution, vibrational density of states and stiffness. We also show that kerogen's maturation, which manifests itself as an increase in the sp2/sp3 hybridization ratio, entails a crossover from plastic-to-brittle rupture mechanisms.

Realistic molecular model of kerogen's nanostructure.

PubMed

Bousige, Colin; Ghimbeu, Camélia Matei; Vix-Guterl, Cathie; Pomerantz, Andrew E; Suleimenova, Assiya; Vaughan, Gavin; Garbarino, Gaston; Feygenson, Mikhail; Wildgruber, Christoph; Ulm, Franz-Josef; Pellenq, Roland J-M; Coasne, Benoit

2016-05-01

Despite kerogen's importance as the organic backbone for hydrocarbon production from source rocks such as gas shale, the interplay between kerogen's chemistry, morphology and mechanics remains unexplored. As the environmental impact of shale gas rises, identifying functional relations between its geochemical, transport, elastic and fracture properties from realistic molecular models of kerogens becomes all the more important. Here, by using a hybrid experimental-simulation method, we propose a panel of realistic molecular models of mature and immature kerogens that provide a detailed picture of kerogen's nanostructure without considering the presence of clays and other minerals in shales. We probe the models' strengths and limitations, and show that they predict essential features amenable to experimental validation, including pore distribution, vibrational density of states and stiffness. We also show that kerogen's maturation, which manifests itself as an increase in the sp(2)/sp(3) hybridization ratio, entails a crossover from plastic-to-brittle rupture mechanisms.

Origins of hydrocarbon gas seeping out from offshore mud volcanoes in the Nile delta

NASA Astrophysics Data System (ADS)

Prinzhofer, Alain; Deville, Eric

2013-04-01

This paper discusses the origin of gas seepages (free gas or dissolved gas in ground water or brine) sampled with the Nautile submarine during the Nautinil cruise at the seafloor of the deep water area of the Nile turbiditic system on different mud volcanoes and brine pools. Generally, the gas is wet and includes C1, C2, C3, iC4, nC4, CO2. These gas samples show no evidence of biodegradation which is not the case of the gas present in the deep hydrocarbon accumulations at depth. It indicates that the gas expelled by the mud volcanoes is not issued from direct leakages from deep gas fields. The collected gas samples mainly have a thermogenic origin and show different maturities. Some samples show very high maturities indicating that these seepages are sourced from great depths, below the Messinian salt. Moreover, the different chemical compositions of the gas samples reflect not only differences in maturity but also the fact that the gas finds its origin in different deep source rocks. Carbon dioxide has an organic signature and cannot result from carbonate decomposition or mantle fluids. The crustal-derived radiogenic isotopes show that the analyzed gas samples have suffered a fractionation processes after the production of the radiogenic isotopes, due either to oil occurrence at depth interacting with the flux of gas, and/or fractionation during the fluid migration.

Organic geochemical study of domanik deposits, Tatarstan Republic.

NASA Astrophysics Data System (ADS)

Nosova, F. F.; Pronin, N. V.

2010-05-01

High-bituminous argillo-siliceous carbonate deposits of domanik formation (DF) occurring within pale depressions and down warps in the east of the Russian platform are treated by many investigators as a main source of oil and gas in the Volga-Ural province. In this study a special attention was turned to organic-rich rocks DF witch outcrop in the central part (Uratminskaya area 792, 806 boreholes) and in the west part (Sviyagskaya, 423) of the Tatarstan Republic. The aim of the present paper is to characterize the organic matter: origin, depositional environments, thermal maturity and biodegradation-weathering effects. Nowadays the most informative geochemical parameters are some biomarkers which qualitatively and are quantitatively defined from distributions of n-alkanes and branched alkanes. Biomarkers - it's original fingerprints of biomass of organic matter, that reflect molecular hydrocarbonic structure. The bulk, molecular composition of oil is initially a function of the type and maturity of the source rock from which it has been expelled, while the source rock type reflects both the nature of precursor organisms and the conditions of its deposition. Methodology used in this study included sampling, bitumen extraction, liquid-column chromatography and gas chromatography/mass spectrometry analyses. The bitumen was fractionated by column chromatography on silica gel. Non-aromatic or alifatics, aromatics and polar compounds were obtained. Alifatic were analysed by gas chromatography/mass spectrometry Percin Elmer. The hydrocarbons present in the sediments of DF and have a carbon numbers ranging from 12 through 38. The samples contain variably inputs from both terrigenous and non-terrigenous (probably marine algal) organic matter as evident in bimodal GC fingerprints of some samples. Pristane and phytane, also, occur in very high concentration in sample extracts. The relatively low Pr/Ph ratios, CPI and OEP<1 imply that the domanik organic matter was deposited in reducing environments. Mass chromatograms show the distribution of regular steranes, iso-steranes, lower molecular weight C21 and C22 steranes (pregnanes) (m/z 217) and triterpanes (m/z 191). The biomarkers distribution of the domanic samples generally suggests a major marine phytoplankton contribution relative to terrigenous land plant source input. The marine affinity is evident from the relatively abundant C27 steranes, which are biomarkers for marine algal contribution to organic matter and low C29 sterane contens. In this present study, samples are dominated by 5α, 14α, 17α (H)-20R and 5β, 14α, 17α (H)-20R steranes (biological configuration). The ratios of 20S/(20S+20R) for αααC29 steranes and ββ/(αα + ββ) for 5α-C29 steranes in the samples, are 0.21 to 0.55 and to 0.12 to 0.50, respectively. The thermal maturity level, assessed by values of several biomarker parameters has been estimated to be within end of diagenesis/eginning of catagenesis and correspond to theoretical vitrinite values (R0) in the range 0.57-0.65%.

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

Radial patterns of bitumen dykes around Quaternary volcanoes, provinces of northern Neuquén and southernmost Mendoza, Argentina

NASA Astrophysics Data System (ADS)

Cobbold, Peter R.; Ruffet, Gilles; Leith, Leslie; Loseth, Helge; Rodrigues, Nuno; Leanza, Hector A.; Zanella, Alain

2014-12-01

Where the Neuquén Basin of Argentina abuts the Andes, hundreds of veins of solid hydrocarbon (bitumen) are visible at the surface. Many of these veins became mines, especially in the last century. By consensus, the bitumen has resulted from maturation of organic-rich shales, especially the Vaca Muerta Fm of Late Jurassic age, but also the Agrio Fm of Early Cretaceous age. To account for their maturation, recent authors have invoked regional subsidence, whereas early geologists invoked magmatic activity. During 12 field seasons (since 1998), we have tracked down the bitumen localities, mapped the veins and host rocks, sampled them, studied their compositions, and dated some of them. In the provinces of northern Neuquén and southernmost Mendoza, the bitumen veins are mostly sub-vertical dykes. They tend to be straight and continuous, crosscutting regional structures and strata of all ages, from Jurassic to Palaeocene. Most of the localities lie within 70 km of Tromen volcano, although four are along the Rio Colorado fault zone and another two are at the base of Auca Mahuida volcano. On both volcanic edifices, lavas are of late Pliocene to Pleistocene age. Although regionally many of the bitumen dykes tend to track the current direction of maximum horizontal tectonic stress (ENE), others do not. However, most of the dykes radiate outward from the volcanoes, especially Tromen. Thicknesses of dykes tend to be greatest close to Tromen and where the host rocks are the most resistant to fracturing. Many of the dykes occur in the exhumed hanging walls of deep thrusts, especially at the foot of Tromen. Here the bitumen is in places of high grade (impsonite), whereas further out it tends to be of medium grade (grahamite). A few bitumen dykes contain fragments of Vaca Muerta shale, so that we infer forceful expulsion of source rock. At Curacó Mine, some shale fragments contain bedding-parallel veins of fibrous calcite (beef) and these contain some bitumen, which is geochemically of low grade. In contrast, a large crosscutting bitumen dyke is of higher grade and formed later. At other localities, near basement faults, bitumen dykes have cap-rocks of hydrothermal calcrete. Other dykes or their wall rocks contain hydrothermal minerals. Finally, some dykes splay upward towards the current land surface. We conclude that (1) the bitumen dykes formed during volcanic activity in Pliocene-Pleistocene times, and that (2) heat advection by hydrothermal fluids helped to generate oil, which migrated upwards or downwards from the source rock and filled intrusive veins, before solidifying to bitumen, by loss of volatile elements. This unconventional hydrocarbon system may have significant implications for regional exploration in the foothills of the Andes.

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

Detrital zircon ages in Korean mid-Paleozoic meta-sandstones (Imjingang Belt and Taean Formation): Constraints on tectonic and depositional setting, source regions and possible affinity with Chinese terranes

NASA Astrophysics Data System (ADS)

Han, Seokyoung; de Jong, Koen; Yi, Keewook

2017-08-01

Sensitive High-Resolution Ion Microprobe (SHRIMP) U-Th-Pb isotopic data of detrital zircons from mature, quartz-rich meta-sandstones are used to constrain possible tectonic affinities and source regions of the rhythmically layered and graded-bedded series in the Yeoncheon Complex (Imjingang Belt) and the correlative Taean Formation. These metamorphic marine turbidite sequences presently occur along the Paleoproterozoic (1.93-1.83 Ga) Gyeonggi Massif, central Korea's main high-grade metamorphic gneiss terrane. Yet, detrital zircons yielded highly similar multimodal age spectra with peaks that do not match the age repartition in these basement rocks, as late (1.9-1.8 Ga) and earliest (∼ 2.5 Ga) Paleoproterozoic detrital modes are subordinate but, in contrast, Paleozoic (440-425 Ma) and Neoproterozoic (980-920 Ma) spikes are prominent, yet the basement essentially lacks lithologies with such ages. The youngest concordant zircon ages in each sample are: 378, 394 and 423 Ma. The maturity of the meta-sandstones and the general roundness of zircons of magmatic signature, irrespective of their age, suggest that sediments underwent considerable transport from source to sink, and possibly important weathering and recycling, which may have filtered out irradiation-weakened metamorphic zircon grains. In combination with these isotopic data, presence of a low-angle ductile fault contact between the Yeoncheon Complex and the Taean Formation and the underlying mylonitized Precambrian basement implies that they are in tectonic contact and do not have a stratigraphic relationship, as often assumed. Consequently, in all likelihood, both meta-sedimentary formations: (1) are at least of early Late Devonian age, (2) received much of their detritus from distant (reworked) Silurian-Devonian and Early Neoproterozoic magmatic sources, not present in the Gyeonggi Massif, (3) and not from Paleoproterozoic crystalline rocks of this massif, or other Korean Precambrian basement terranes, and (4) should be viewed as independent tectonic units that had sources not exposed in Korea. A thorough literature review reveals that the Yeoncheon Complex and the Taean Formation were potentially sourced from the Liuling, Nanwan and Foziling groups in the Qinling-Dabie Belt, which all show very similar detrital zircon age spectra. These immature middle-late Devonian sandstones were deposited in a pro-foreland basin formed as a result of the aborted subduction of the South Qinling Terrane below the North Qinling Terrane, which was uplifted and eroded during post-collision isostatic rebound. The submarine fans where the mature distal turbiditic Yeoncheon and Taean sandstones were deposited may have constituted the eastern terminal part of a routing system originating in the uplifted and eroded middle Paleozoic Qinling Belt and adjacent part of the foreland basin.

Provenance, diagenesis, tectonic setting and reservoir quality of the sandstones of the Kareem Formation, Gulf of Suez, Egypt

NASA Astrophysics Data System (ADS)

Zaid, Samir M.

2013-09-01

The Middle Miocene Kareem sandstones are important oil reservoirs in the southwestern part of the Gulf of Suez basin, Egypt. However, their diagenesis and provenance and their impact on reservoir quality, are virtually unknown. Samples from the Zeit Bay Oil Field, and the East Zeit Oil Field represent the Lower Kareem (Rahmi Member) and the Upper Kareem (Shagar Member), were studied using a combination of petrographic, mineralogical and geochemical techniques. The Lower Rahmi sandstones have an average framework composition of Q95F3.4R1.6, and 90% of the quartz grains are monocrystalline. By contrast, the Upper Shagar sandstones are only slightly less quartzose with an average framework composition of Q76F21R3 and 82% of the quartz grains are monocrystalline. The Kareem sandstones are mostly quartzarenite with subordinate subarkose and arkose. Petrographical and geochemical data of sandstones indicate that they were derived from granitic and metamorphic terrains as the main source rock with a subordinate quartzose recycled sedimentary rocks and deposited in a passive continental margin of a syn rift basin. The sandstones of the Kareem Formation show upward decrease in maturity. Petrographic study revealed that dolomite is the dominant cement and generally occurs as fine to medium rhombs pore occluding phase and locally as a grain replacive phase. Authigenic quartz occurs as small euhedral crystals, locally as large pyramidal crystals in the primary pores. Authigenic anhydrites typically occur as poikilotopic rhombs or elongate laths infilling pores but also as vein filling cement. The kaolinite is a by-product of feldspar leaching in the presence of acidic fluid produced during the maturation of organic matter in the adjacent Miocene rocks. Diagenetic features include compaction; dolomite, silica and anhydrite cementation with minor iron-oxide, illite, kaolinite and pyrite cements; dissolution of feldspars, rock fragments. Silica dissolution, grain replacement and carbonate dissolution greatly enhance the petrophysical properties of many sandstone samples.

Geological studies of the COST No. B-3 Well, United States Mid-Atlantic continental slope area

USGS Publications Warehouse

Scholle, Peter A.

1980-01-01

The COST No. B-3 well is the first deep stratigraphic test to be drilled on the Continental Slope off the Eastern United States. The well was drilled in 2,686 ft (819 m) of water in the Baltimore Canyon trough area to a total depth of 15,820 ft (4,844 m) below the drill platform. It penetrated a section composed of mudstones, calcareous mudstones, and limestones of generally deep water origin to a depth of about 8.200 ft (2,500 m) below the drill floor. Light-colored, medium- to coarse-grained sandstones with intercalated gray and brown shales, micritic limestones, and minor coal and dolomite predominate from about 8,200 to 12,300 ft (2,500 to 3,750 m). From about 12,300 ft (3,750 m) to the bottom, the section consists of limestones (including oolitic and intraclastic grainstones) with interbedded fine-to medium-grained sandstones, dark-colored fissile shales, and numerous coal seams. Biostratigraphic examination has shown that the section down to approximately 6,000 ft (1,830 m) is Tertiary. The boundary between the Lower and Upper Cretaceous sections is placed between 8,600 and 9,200 ft (2,620 and 2,800 m) by various workers. Placement of the Jurassic-Cretaceous boundary shows an even greater range based on different organisms; it is placed variously between 12,250 and 13,450 ft (3,730 and 5,000 m). The oldest unit penetrated in the well is considered to be Upper Jurassic (Kimmeridgian) by some workers and Middle Jurassic (Callovian) by others. The Lower Cretaceous and Jurassic parts of the section represent nonmarine to shallow-marine shelf sedimentation. Upper Cretaceous and Tertiary units reflect generally deeper water conditions at the B-3 well site and show a general transition from deposition at shelf to slope water depths. Examination of cores, well cuttings, and electric logs indicates that potential hydrocarbon-reservoir units are present throughout the Jurassic and Cretaceous section. Porous and moderately permeable limestones and sandstones have been found in the Jurassic section, and significant thicknesses of sandstone with porosities as high as 30 percent and permeabilities in excess of 100 md have been encountered in the Cretaceous interval from about 7,000 to 12,000 ft (2,130 to 3,650 m). Studies of organic geochemistry, vitrinite reflectance, and color alteration of visible organic matter indicate that the Tertiary section, especially in its upper part, contains organic-carbon-rich sediments that are good potential oil source rocks. However, this part of the section is thermally immature and is unlikely to have acted as a source rock anywhere in the area of the B-3 well. The Cretaceous section is generally lean in organic carbon, the organic matter which is present is generally gas-prone, and the interval is thermally immature (although the lowest part of this section is approaching thermal maturity). The deepest part of the well, the Jurassic section, shows the onset of thermal maturity. The lower half of the Jurassic rocks has high organic-carbon contents with generally gas-prone organic matter. This interval is therefore considered to be an excellent possible gas source; it has a very high methane content. The combination of gas-prone source rocks, thermal maturity, significant gas shows in the well at 15,750 ft (4,801 m) and porous reservoir rocks in the deepest parts of the well indicate a considerable potential for gas production from the Jurassic section in the area of the COST No. B-3 well. Wells drilled farther downslope from the B03 site may encounter more fully marine or deeper marine sections that may have a greater potential for oil (rather than gas) generation.

Empirical relation between carbonate porosity and thermal maturity: an approach to regional porosity prediction

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

Schmoker, J.W.

1984-11-01

Data indicate that porosity loss in subsurface carbonate rocks can be empirically represented by the power function, theta = a (TTI) /SUP b/ , where theta is regional porosity, TTI is Lopatin's time-temperature index of thermal maturity, the exponent, b, equals approximately -0.372, and the multiplier, a, is constant for a given data population but varies by an order of magnitude overall. Implications include the following. 1. The decrease of carbonate porosity by burial diagenesis is a maturation process depending exponentially on temperature and linearly on time. 2. The exponent, b, is essentially independent of the rock matrix, and maymore » reflect rate-limiting processes of diffusive transport. 3. The multiplying coefficient, a, incorporates the net effect on porosity of all depositional and diagenetic parameters. Within constraints, carbonate-porosity prediction appears possible on a regional measurement scale as a function of thermal maturity. Estimation of carbonate porosity at the time of hydrocarbon generation, migration, or trapping also appears possible.« less

Comparative Petrographic Maturity of River and Beach Sand, and Origin of Quartz Arenites.

ERIC Educational Resources Information Center

Ferree, Rob A.; And Others

1988-01-01

Describes a deterministic computer model that incorporates: (1) initial framework composition; (2) abrasion factors for quartz, feldspar, and rock fragments; and (3) a fragmentation ratio for rock fragments to simulate the recycling of coastal sands by rivers and beaches. (TW)

Subsalt source rock maturity in the Sudanese Red Sea

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

Geiger, C.; Pigott, J.; Forgotson, J.M. Jr.

1995-08-01

Thermal modeling can demonstrate that stratal salt deposits may provide a significant heat conduit and conceptually provide a basis for hypothermal fairways of hydrocarbon aspiration in regions of dominant thermal overmaturity. However, accurate evaluation of thermal maturity suppression by modeling must be geologically constrained. With respect to the Tertiary Tokar Delta of offshore Sudan, ID tectonic subsidence analysis of boreholes in the region reveals at least two major pu1ses of crustal extension and associated heating (24-20 m.a. and 5.4-2.7 m.a.). Integrating the borehole geochemical information with a Tokar Delta seismic stratigraphic interpretation allows the construction of constrained 2D thermal basinmore » models through time using Procom BMT. The best match between the observed and modelled vitrinite reflectance values is achieved by using a two phase tectonic stretching model with pulses at 22{+-}2 m.a. and 4{+-}1.5 m.a. and incremental subcrustal stretching factors which vary between 2.65-2.75. Utilizing these parameters suggests the top of the oil window to occur within the Zeit Formation and bottom of the oil window to exist at the base of the Dungunab Salt. As only subsalt source rocks are observed, this model would tend to negate the possibility of the occurrence of liquid hydrocarbons. For the Tokar Delta the presently observed general high heat flow is so high that it leads in all cases to overcooked organics for a subsalt source. However, that hydrocarbons in the post-salt Zeit Formation of the Tokar Delta have been discovered suggests significant secondary hydrocarbon migration to have occurred within the late Miocene (15.4 - 5.4 m.a.). Potential migration pathways would be a1ong basement-induced fault conduits. If true, similar secondary migration play concepts may be applicable elsewhere in the Red Sea.« less

Comparison of natural gases accumulated in Oligocene strata with hydrous pyrolysis gases from Menilite Shales of the Polish Outer Carpathians

USGS Publications Warehouse

Kotarba, M.J.; Curtis, John B.; Lewan, M.D.

2009-01-01

This study examined the molecular and isotopic compositions of gases generated from different kerogen types (i.e., Types I/II, II, IIS and III) in Menilite Shales by sequential hydrous pyrolysis experiments. The experiments were designed to simulate gas generation from source rocks at pre-oil-cracking thermal maturities. Initially, rock samples were heated in the presence of liquid water at 330 ??C for 72 h to simulate early gas generation dominated by the overall reaction of kerogen decomposition to bitumen. Generated gas and oil were quantitatively collected at the completion of the experiments and the reactor with its rock and water was resealed and heated at 355 ??C for 72 h. This condition simulates late petroleum generation in which the dominant overall reaction is bitumen decomposition to oil. This final heating equates to a cumulative thermal maturity of 1.6% Rr, which represents pre-oil-cracking conditions. In addition to the generated gases from these two experiments being characterized individually, they are also summed to characterize a cumulative gas product. These results are compared with natural gases produced from sandstone reservoirs within or directly overlying the Menilite Shales. The experimentally generated gases show no molecular compositions that are distinct for the different kerogen types, but on a total organic carbon (TOC) basis, oil prone kerogens (i.e., Types I/II, II and IIS) generate more hydrocarbon gas than gas prone Type III kerogen. Although the proportionality of methane to ethane in the experimental gases is lower than that observed in the natural gases, the proportionality of ethane to propane and i-butane to n-butane are similar to those observed for the natural gases. ??13C values of the experimentally generated methane, ethane and propane show distinctions among the kerogen types. This distinction is related to the ??13C of the original kerogen, with 13C enriched kerogen generating more 13C enriched hydrocarbon gases than kerogen less enriched in 13C. The typically assumed linear trend for ??13C of methane, ethane and propane versus their reciprocal carbon number for a single sourced natural gas is not observed in the experimental gases. Instead, the so-called "dogleg" trend, exemplified by relatively 13C depleted methane and enriched propane as compared to ethane, is observed for all the kerogen types and at both experimental conditions. Three of the natural gases from the same thrust unit had similar "dogleg" trends indicative of Menilite source rocks with Type III kerogen. These natural gases also contained varying amounts of a microbial gas component that was approximated using the ????13C for methane and propane determined from the experiments. These approximations gave microbial methane components that ranged from 13-84%. The high input of microbial gas was reflected in the higher gas:oil ratios for Outer Carpathian production (115-1568 Nm3/t) compared with those determined from the experiments (65-302 Nm3/t). Two natural gas samples in the far western part of the study area had more linear trends that suggest a different organic facies of the Menilite Shales or a completely different source. This situation emphasizes the importance of conducting hydrous pyrolysis on samples representing the complete stratigraphic and lateral extent of potential source rocks in determining specific genetic gas correlations. ?? 2009 Elsevier Ltd.

Low temperature hydrothermal maturation of organic matter in sediments from the Atlantis II Deep, Red Sea.

PubMed

Simoneit, B R; Grimalt, J O; Hayes, J M; Hartman, H

1987-01-01

Hydrocarbons and bulk organic matter of two sediment cores (No. 84 and 126, CHAIN 61 cruise) located within the Atlantis II Deep have been analyzed. Although the brines overlying the coring areas were reported to be sterile, microbial inputs and minor terrestrial sources the major sedimentary organic material. This input is derived from the upper water column above the brines. Both steroid and triterpenoid hydrocarbons show that extensive acid-catalyzed reactions are occurring in the sediments. In comparison with other hydrothermal (Guaymas Basin) or intrusive systems (Cape Verde Rise), the Atlantis II Deep exhibits a lower degree of thermal maturation. This is easily deduced from the elemental composition of the kerogens and the absence of polynuclear aromatic hydrocarbons of a pyrolytic origin in the bitumen. The lack of carbon number preference among the n-alkanes suggests, especially in the case of the long chain homologs, that the organic matter of Atlantis II Deep sediments has undergone some degree of catagenesis. However, the yields of hydrocarbons are much lower than those observed in other hydrothermal areas. The effect of lower temperature and poor source-rock characteristics appear to be responsible for the differences.

Organic geochemistry of impactites from the Haughton impact structure, Devon Island, Nunavut, Canada

NASA Astrophysics Data System (ADS)

Parnell, John; Bowden, Stephen A.; Osinski, Gordon R.; Lee, Pascal; Green, Paul; Taylor, Colin; Baron, Martin

2007-04-01

Organic matter in impactites from the 24 km wide and 39 Ma old Haughton impact structure, Canadian High Arctic, is a mixture of fossil and modern biological components. The fossil component represents a conventional oil that was generated from Lower Palaeozoic marine source material before impact and permeates bedrock dolomites. Biomarker maturity parameters record the thermal effect of the mid-Tertiary impact. Maturity-influenced sterane, rearranged hopanoid, and triaromatic steroid ratios all increase towards the centre of the impact structure, where thermal alteration was greatest. The heating was probably dominated by an impact-related hydrothermal system, as such systems last long enough for kinetically-based thermal alteration to occur. Kinetically-related biomarker data suggest that the hydrothermal heating lasted for c. 5000 years. Biomarkers are also preserved in dolomite clasts within impact melt breccia, and indicate strong thermal alteration. Modern biological contamination of the rocks is responsible for the superposition of two geochemical signatures (which could be cyanobacteria, non-marine algae, or higher plant matter) onto the fossil component, but they can be recognized and distinguished. The data show that the impact structure system holds a record of both the pre-impact organic signature and the thermal signature of the impact, and thereby indicates that organic geochemistry is a valuable tool in documenting the response of rocks to impacts.

Raman spectroscopy as a tool to understand Kerogen production potential

NASA Astrophysics Data System (ADS)

Khatibi, S.; Ostadhassan, M.; Mohammed, R. A.; Alexeyev, A.

2017-12-01

A lot attention has given to unconventional reservoirs specifically oil shale in North America during the last decades. Understanding Kerogen properties in terms of maturity and production potential are crucial for unconventional reservoir. Since, the amount of hydrocarbon generation is a function of kerogen type and content in the formation, and the magnitude and duration in which heat and pressure were applied. This study presents a non-destructive and fast method to determine Kerogen properties in terms of Rock-Eval parameters by means of Raman Spectroscopy. Samples were gathered from upper and lower Bakken formation, with different maturities at different depth. Raman spectroscopy as a powerful nondestructive analytical tool for molecular reconstruction was employed to find Raman spectra of different samples. In the next step, Rock-Eval was performed for each sample and different measurements were made. Then in an original approach, correlation between Rock-Eval parameters with Raman Spectroscopy results was established to fully understand how kerogen productivity potentials can be reflected on the Raman response. Results showed, maturity related parameters (RO, Tmax), S1 (already generated oil in the rock), S2 (potential hydrocarbon) and OSI (oil saturation index as indication of potential oil flow zones) can be correlated to band separation, D band intensity, G band intensity and G/D intensity, respectively. Proposed method provide a fast nondestructive method to evaluate Kerogen quality even at field without any special sample preparation.

Distribution and evolution of Zn, Cd, and Pb in Apollo 16 regolith samples and the average U-Pb ages of the parent rocks

NASA Technical Reports Server (NTRS)

Cirlin, E. H.; Housley, R. M.

1982-01-01

The concentration of surface (low temperature site) and interior (high temperature site) Cd, Zn, and Pb in 13 Apollo 16 highland fines samples, pristine rock 65325, and mare fines sample 75081 were analyzed directly from the thermal release profiles obtained by flameless atomic absorption technique (FLAA). Cd and Zn in pristine ferroan anothosite 65325, anorthositic grains of the most mature fines 65701, and basaltic rock fragments of mare fines 75081 were almost all surface Cd and Zn indicating that most volatiles were deposited on the surfaces of vugs, vesicles and microcracks during the initial cooling process. A considerable amount of interior Cd and Zn was observed in agglutinates. This result suggests that high temperature site interior volatiles originate from entrapment during the lunar maturation processes. Interior Cd found in the most mature fines sample 65701 was only about 15% of the total Cd in the sample. Interior Pb present in Apollo 16 fines samples went up to 60%. From our Cd studies we can assume that this interior Pb in highland fines samples is largely due to the radiogenic decay which occurred after the redistribution of the volatiles took place. We obtained an average age of 4.0 b.y. for the parent rocks of Apollo 16 highland regolith from our interior Pb analyses.

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

Tectonothermal modeling of hydrocarbon maturation, Central Maracaibo Basin, Venezuela

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

Manske, M.C.

1996-08-01

The petroliferous Maracaibo Basin of northwestern Venezuela and extreme eastern Colombia has evolved through a complex geologic history. Deciphering the tectonic and thermal evolution is essential in the prediction of hydrocarbon maturation (timing) within the basin. Individual wells in two areas of the central basin, Blocks III and V, have been modeled to predict timing of hydrocarbon generation within the source Upper Cretaceous La Luna Formation, as well as within interbedded shales of the Lower-Middle Eocene Misoa Formation reservoir sandstones. Tectonic evolution, including burial and uplift (erosional) history, has been constrained with available well data. The initial extensional thermal regimemore » of the basin has been approximated with a Mackenzie-type thermal model, and the following compressional stage of basin development by applying a foreland basin model. Corrected Bottom Hole Temperature (BHT) measurements; from wells in the central basin, along with thermal conductivity measurements of rock samples from the entire sedimentary sequence, resulted in the estimation of present day heat flow. An understanding of the basin`s heat flow, then, allowed extrapolation of geothermal gradients through time. The relation of geothermal gradients and overpressure within the Upper Cretaceous hydrocarbon-generating La Luna Formation and thick Colon Formation shales was also taken into account. Maturation modeling by both the conventional Time-Temperature Index (TTI) and kinetic Transformation Ratio (TR) methods predicts the timing of hydrocarbon maturation in the potential source units of these two wells. These modeling results are constrained by vitrinite reflectance and illite/smectite clay dehydration data, and show general agreement. These results also have importance regarding the timing of structural formation and hydrocarbon migration into Misoa reservoirs.« less

Incremental growth of an upper crustal, A-type pluton, Argentina: Evidence of a re-used magma pathway

NASA Astrophysics Data System (ADS)

Alasino, Pablo H.; Larrovere, Mariano A.; Rocher, Sebastián; Dahlquist, Juan A.; Basei, Miguel A. S.; Memeti, Valbone; Paterson, Scott; Galindo, Carmen; Macchioli Grande, Marcos; da Costa Campos Neto, Mario

2017-07-01

Carboniferous igneous activity in the Sierra de Velasco (NW Argentina) led to the emplacement of several magmas bodies at shallow levels (< 2 kbar). One of these, the San Blas intrusive complex formed over millions of years (≤ 2-3 m.y.) through three periods of magma additions that are characterized by variations in magma sources and emplacement style. The main units, mostly felsic granitoids, have U-Pb zircon crystallization ages within the error range. From older to younger (based on cross-cutting relationships) intrusive units are: (1) the Asha unit (340 ± 7 Ma): a tabular to funnel-shaped intrusion emplaced during a regional strain field dominated by WSW-ENE shortening with contacts discordant to regional host-rock structures; (2) the San Blas unit (344 ± 2 Ma): an approximate cylindrical-shaped intrusion formed by multiple batches of magmas, with a roughly concentric fabric pattern and displacement of the host rock by ductile flow of about 35% of shortening; and (3) the Hualco unit (346 ± 6 Ma): a small body with a possible mushroom geometry and contacts concordant to regional host-rock structures. The magma pulses making up these units define two groups of A-type granitoids. The first group includes the peraluminous granitic rocks of the Asha unit generated mostly by crustal sources (εNdt = - 5.8 and εHft in zircon = - 2.9 to - 4.5). The second group comprises the metaluminous to peraluminous granitic rocks of the youngest units (San Blas and Hualco), which were formed by a heterogeneous mixture between mantle and crustal sources (εNdt = + 0.6 to - 4.8 and εHft in zircon = + 3 to - 6). Our results provide a comprehensive view of the evolution of an intrusive complex formed from multiple non-consanguineous magma intrusions that utilized the same magmatic plumbing system during downward transfer of host materials. As the plutonic system matures, the ascent of magmas is governed by the visco-elastic flow of host rock that for younger batches include older hot magma mush. The latter results in ductile downward flow of older, during rise of younger magma. Such complexes may reflect the plutonic portion of volcanic centers where chemically distinct magmas are erupted.

Potential cretaceous play in the Rharb basin of northern Morocco

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

Jobidon, G.P.

1993-09-01

The autochthonous Cretaceous in the Rharb basin of northern Morocco is located underneath a cover of neogene sediments and of the Prerif nappe olistostrome, which was emplaced during the Tortonian 7 m.y. The presence of infranappe Cretaceous sediments is documented in a few onshore wells in the Rharb basin and in the adjacent Prerif Rides area, as well as in the Rif Mountains. Their presence in the deeper portion of the Rharb basin is difficult to detail because of poor seismic resolution data beneath dispersive prerif nappe. A recent study of offshore seismic data acquired by PCIAC in 1987 indicatesmore » that the infranappe interval can be more than 1500 m thick in some of the offshore Kenitra area. These sediments have seismic signatures that would correspond to Middle Cretaceous transgressions, culminating with a Turonian highstand. Their deposition systems were located on the northern and western flanks of the Meseta and were followed by a hiatus lasting until the Miocene. Regional studies of gravity and magnetic data provide and additional understanding of the Rif province, its evolution, and the possible presence of autochthonous Cretaceous sediments below the prerif nappe cover. The infranappe of Rharb basin has a good potential to develop into a major hydrocarbon play with the presence of middle Cretaceous reservoir rocks, Turonian-Cenomanian black shale source rocks, as well as the timely combination of trap formation, source rock maturation, and hydrocarbon migration.« less

Characterization of coal-derived hydrocarbons and source-rock potential of coal beds, San Juan Basin, New Mexico and Colorado, U.S.A.

USGS Publications Warehouse

Rice, D.D.; Clayton, J.L.; Pawlewicz, M.J.

1989-01-01

Coal beds are considered to be a major source of nonassociated gas in the Rocky Mountain basins of the United States. In the San Juan basin of northwestern New Mexico and southwestern Colorado, significant quantities of natural gas are being produced from coal beds of the Upper Cretaceous Fruitland Formation and from adjacent sandstone reservoirs. Analysis of gas samples from the various gas-producing intervals provided a means of determining their origin and of evaluating coal beds as source rocks. The rank of coal beds in the Fruitland Formation in the central part of the San Juan basin, where major gas production occurs, increases to the northeast and ranges from high-volatile B bituminous coal to medium-volatile bituminous coal (Rm values range from 0.70 to 1.45%). On the basis of chemical, isotopic and coal-rank data, the gases are interpreted to be thermogenic. Gases from the coal beds show little isotopic variation (??13C1 values range -43.6 to -40.5 ppt), are chemically dry (C1/C1-5 values are > 0.99), and contain significant amounts of CO2 (as much as 6%). These gases are interpreted to have resulted from devolatilization of the humic-type bituminous coal that is composed mainly of vitrinite. The primary products of this process are CH4, CO2 and H2O. The coal-generated, methane-rich gas is usually contained in the coal beds of the Fruitland Formation, and has not been expelled and has not migrated into the adjacent sandstone reservoirs. In addition, the coal-bed reservoirs produce a distinctive bicarbonate-type connate water and have higher reservoir pressures than adjacent sandstones. The combination of these factors indicates that coal beds are a closed reservoir system created by the gases, waters, and associated pressures in the micropore coal structure. In contrast, gases produced from overlying sandstones in the Fruitland Formation and underlying Pictured Cliffs Sandstone have a wider range of isotopic values (??13C1 values range from -43.5 to -38.5 ppt), are chemically wetter (C1/C1-5 values range from 0.85 to 0.95), and contain less CO2 (< 2%). These gases are interpreted to have been derived from type III kerogen dispersed in marine shales of the underlying Lewis Shale and nonmarine shales of the Fruitland Formation. In the underlying Upper Cretaceous Dakota Sandstone and Tocito Sandstone Lentil of the Mancos Shale, another gas type is produced. This gas is associated with oil at intermediate stages of thermal maturity and is isotopically lighter and chemically wetter at the intermediate stage of thermal maturity as compared with gases derived from dispersed type III kerogen and coal; this gas type is interpreted to have been generated from type II kerogen. Organic matter contained in coal beds and carbonaceous shales of the Fruitland Formation has hydrogen indexes from Rock-Eval pyrolysis between 100 and 350, and atomic H:C ratios between 0.8 and 1.2. Oxygen indexes and atomic O:C values are less than 24 and 0.3, respectively. Extractable hydrocarbon yields are as high as 7,000 ppm. These values indicate that the coal beds and carbonaceous shales have good potential for the generation of liquid hydrocarbons. Voids in the coal filled with a fluorescent material that is probably bitumen is evidence that liquid hydrocarbon generation has taken place. Preliminary oil-source rock correlations based on gas chromatography and stable carbon isotope ratios of C15+ hydrocarbons indicate that the coals and (or) carbonaceous shales in the Fruitland Formation may be the source of minor amounts of condensate produced from the coal beds at relatively low levelsof thermal maturity (Rm=0.7). ?? 1989.

Tectono-thermal History of the Southern Nenana Basin, Interior Alaska: Implications for Conventional and Unconventional Hydrocarbon Exploration

NASA Astrophysics Data System (ADS)

Dixit, N. C.; Hanks, C. L.

2014-12-01

The Tertiary Nenana basin of Interior Alaska is currently the focus of both new oil exploration and coalbed methane exploitation and is being evaluated as a potential CO2sequestration site. The basin first formed as a Late Paleocene extensional rift with the deposition of oil and gas-prone, coal-bearing non-marine sediments with excellent source potential. Basin inversion during the Early Eocene-Early Oligocene times resulted in folding and erosion of higher stratigraphic levels, forming excellent structural and stratigraphic traps. Initiation of active faulting on its eastern margin in the middle Oligocene caused slow tectonic subsidence that resulted in the deposition of reservoir and seal rocks of the Usibelli Group. Onset of rapid tectonic subsidence in Pliocene that continues to the present-day has provided significant pressure and temperature gradient for the source rocks. Apatite fission-track and vitrinite reflectance data reveals two major paleo-thermal episodes: Late Paleocene to Early Eocene (60 Ma to 54.8 Ma) and Late Miocene to present-day (7 Ma to present). These episodes of maximum paleotemperatures have implications for the evolution of source rock maturity within the basin. In this study, we are also investigating the potential for coalbed methane production from the Late Paleocene coals via injection of CO2. Our preliminary analyses demonstrate that 150 MMSCF of methane could be produced while 33000 tonnes of CO2 per injection well (base case of ~9 years) can be sequestered in the vicinity of existing infrastructure. However, these volumes of sequestered CO2and coal bed methane recovery are estimates and are sensitive to the reservoir's geomechanical and flow properties. Keywords: extensional rift, seismic, subsidence, thermal history, fission track, vitrinite reflectance, coal bed methane, Nenana basin, CO2 sequestration

The Hydrocarbon Fingerprints of Organic-rich Shales

NASA Astrophysics Data System (ADS)

Davies, S. J.; Sommariva, R.; Blake, R.; Ortega, M.; Cuss, R. J.; Harrington, J.; Emmings, J.; Lovell, M.; Monks, P.

2016-12-01

Geological characterization of key source rocks and potential unconventional reservoirs from the UK Mississippian has shed new light on the heterogeneous character of shales (mudstones) and also on the mechanisms for preserving organic matter of different types and abundances. Sedimentological studies of these mudstones suggest that systematic variations in total organic carbon (TOC) content are related to the dominant sediment delivery process (hemipelagic suspension settling vs. sediment gravity flows). Questions remain, however, as to how the physical character and chemical composition (e.g. lithology, mineralogy, organic matter type, maturity and abundance) of a mudstone relates to the volume and type of hydrocarbon gas that could be released. Using novel proof-of-principle laboratory experiments, we demonstrate that it is possible to quantify, in real-time (second by second), methane and a wide range of non-methane hydrocarbons (NMHC) gases as they are released from a crushed mudstone sample. Real time measurements are undertaken using proton-transfer-reaction time-of-flight mass spectrometry (PTR- TOF- MS). The PTR technique is not sensitive to some classes of NHMC and the whole range of hydrocarbons is analyzed using thermal desorption gas chromatography mass spectrometry (TD- GC- MS). Our data indicate that NMHC gases (mostly alkanes and aromatics) are released with temperature and humidity-dependent release rates, which depend on the physio-chemical characteristics of the different hydrocarbons classes and on the mode of storage within the shale. Knowledge of the abundance of methane and the speciated NMHC, and how that relates to geological characteristics of a mudstone is important to understand both the source rock potential and the potential pollutants. Ultimately, we aim to link these results to the geomechanical properties of shales. We discuss the implications of our findings for the environment and for the industrial and commercial exploitation of source rocks and unconventional reservoirs.

The Mapping X-ray Fluorescence Spectrometer (MapX)

NASA Astrophysics Data System (ADS)

Sarrazin, P.; Blake, D. F.; Marchis, F.; Bristow, T.; Thompson, K.

2017-12-01

Many planetary surface processes leave traces of their actions as features in the size range 10s to 100s of microns. The Mapping X-ray Fluorescence Spectrometer (MapX) will provide elemental imaging at 100 micron spatial resolution, yielding elemental chemistry at a scale where many relict physical, chemical, or biological features can be imaged and interpreted in ancient rocks on planetary bodies and planetesimals. MapX is an arm-based instrument positioned on a rock or regolith with touch sensors. During an analysis, an X-ray source (tube or radioisotope) bombards the sample with X-rays or alpha-particles / gamma-rays, resulting in sample X-ray Fluorescence (XRF). X-rays emitted in the direction of an X-ray sensitive CCD imager pass through a 1:1 focusing lens (X-ray micro-pore Optic (MPO)) that projects a spatially resolved image of the X-rays onto the CCD. The CCD is operated in single photon counting mode so that the energies and positions of individual X-ray photons are recorded. In a single analysis, several thousand frames are both stored and processed in real-time. Higher level data products include single-element maps with a lateral spatial resolution of 100 microns and quantitative XRF spectra from ground- or instrument- selected Regions of Interest (ROI). XRF spectra from ROI are compared with known rock and mineral compositions to extrapolate the data to rock types and putative mineralogies. When applied to airless bodies and implemented with an appropriate radioisotope source for alpha-particle excitation, MapX will be able to analyze biogenic elements C, N, O, P, S, in addition to the cations of the rock-forming elements >Na, accessible with either X-ray or gamma-ray excitation. The MapX concept has been demonstrated with a series of lab-based prototypes and is currently under refinement and TRL maturation.

Provenance of Austroalpine basement metasediments: tightening up Early Palaeozoic connections between peri-Gondwanan domains of central Europe and Northern Africa

NASA Astrophysics Data System (ADS)

Siegesmund, S.; Oriolo, S.; Heinrichs, T.; Basei, M. A. S.; Nolte, N.; Hüttenrauch, F.; Schulz, B.

2018-03-01

New U-Pb and Lu-Hf detrital zircon data together with whole-rock geochemical and Sm-Nd data were obtained for paragneisses of the Austroalpine basement south of the Tauern Window. Geochemically immature metasediments of the Northern-Defereggen-Petzeck (Ötztal-Bundschuh nappe system) and Defereggen (Drauzug-Gurktal nappe system) groups contain zircon age populations which indicate derivation mainly from Pan-African orogens. Younger, generally mature metasediments of the Gailtal Metamorphic Basement (Drauzug-Gurktal nappe system), Thurntaler Phyllite Group (Drauzug-Gurktal nappe system) and Val Visdende Formation (South Alpine Basement) were possibly derived from more distant sources. Their significantly larger abundances of pre-Pan-African zircons record a more advanced stage of downwearing of the Pan-African belts and erosion of older basement when the Austroalpine terrane was part of the Early Palaeozoic Northern Gondwana passive margin. Most zircon age spectra are dominated by Ediacaran sources, with lesser Cryogenian, Tonian and Stenian contributions and subordinate Paleoproterozoic and Neoarchean ages. These age patterns are similar to those recorded by Cambro-Ordovician sedimentary sequences in northeastern Africa between Libya and Jordan, and in some pre-Variscan basement inliers of Europe (e.g. Dinarides-Hellenides, Alboran microplate). Therefore, the most likely sources seem to be in the northeastern Saharan Metacraton and the Northern Arabian-Nubian Shield (Sinai), further supported by whole-rock Sm-Nd and zircon Lu-Hf data.

Depositional environments and tectonic significance of the Wajid Sandstone of southern Saudi Arabia

NASA Astrophysics Data System (ADS)

Dabbagh, Mohamed E.; Rogers, John J. W.

The Wajid Sandstone, of probable Early Paleozoic age, rests disconformably on crystalline rocks of the southern part of the Arabian shield. Scattered outcrops extend over an area about 450 km north-south and 300 km east-west. The southern part of the formation, near the Yemen border, consists of fluvial sandstones and very minor siltstones and silty shales. The fluvial origin is demonstrated by the presence of fining-upward cycles, channels, trough cross bedding, and absence of all organic traces. The northern part of the outcrop area consists of internally homogeneous, tabular cross-bedded, horizontally bedded sandstones apparently formed in a shallow marine environment. These marine rocks contain trace fossils broadly similar to Skolithos. Abundant cross bedding in both facies of the Wajid indicates a northward transport direction, toward what is now the center of the Arabian shield. The southern part of the Arabian shield, which was cratonized about 500 to 600 Ma ago (Pan-African age), was apparently still a depositional area receiving sediments from a southern source in Early Paleozoic time. Other, older, shields also show a tendency to be areas of deposition shortly after their apparent age of stabilization, becoming sources of clastic sediments only after several hundreds of millions of years. The conversion from basin to uplifted source may indicate a prolonged process of shield maturation after initial stabilization.

Publications - GMC 161 | Alaska Division of Geological & Geophysical

Science.gov Websites

, vitrinite reflectance data (410'-7930' only), and organic matter maturation values of cuttings (220'-11230 data (410'-7930' only), and organic matter maturation values of cuttings (220'-11230') from the Alaska Information gmc161.pdf (1.2 M) Keywords Pyrolysis; Rock-Eval Pyrolysis; Total Organic Carbon; Vitrinite

Biomarkers Indigenous to Late Archean Rocks

NASA Astrophysics Data System (ADS)

Eigenbrode, J. L.; Freeman, K. H.; Summons, R. E.; Love, G. D.; Snape, C. E.

2003-12-01

Two new lines of evidence support the authenticity of molecular fossils in late Archean rocks of the Hamersley Province, Western Australia. Specifically, they support 1) a syngenetic relationship between the kerogen and extractable biomarkers, and 2) a indigenous relationship between extractable compounds and the host rocks. Carbon skeletons released from kerogen via high-pressure hydropyrolysis match those found in associated extracted bitumen. Biomarker ratios indicate less mature steranes and terpanes (i.e. hopanes and tricyclic terpanes) are embedded in the kerogen matrix as compared to the highly mature steranes and terpanes in the extracts, which is similar to findings in other hydropyrolysis experiments. Lithology-associated variations in biomarker distributions are noteworthy and suggest environmental settings are associated with differing biotic ecosystems. The evidence reported here confirms the 2.7 Ga antiquity of diverse biosynthetic pathways. Molecular data, together with isotopic data, indicate aerobic and anaerobic respiration pathways were fundamental to the complex microbial biogeochemistry of the late Archean. The biomarkers in these rocks support an early radiation of the three domains of life and radiation within the bacteria, such that clades of cyanobacteria, green sulfur bacteria, and proteobacteria had been established.

The influence of pressure on petroleum generation and maturation as suggested by aqueous pyrolysis

USGS Publications Warehouse

Price, L.C.; Wenger, L.M.

1992-01-01

Because fluid pressures are transient in sedimentary basins over geologic time, the effect of increasing fluid pressure on organic-matter metamorphism is difficult to determine, and conflicting opinions exist concerning its influence. Properly-performed aqueous-pyrolysis experiments can closely simulate hydrocarbon generation and maturation in nature, and thus offer an excellent way to study the influence of pressure. Such experiments, carried out on the Retort Phosphatic Shale Member of the Lower Permian Phosphoria Formation (type II-S organic matter) at different constant temperatures, demonstrated that increasing pressure significantly retards all aspects of organic matter metamorphism, including hydrocarbon generation, maturation and thermal destruction. This conclusion results from detailed quantitative and qualitative analyses of all products from hydrocarbon generation, from the C1 to C4 hydrocarbon gases to the asphaltenes, and also from analyses of the reacted rocks. We have documented that our aqueous-pyrolysis experiments closely simulated natural hydrocarbon generation and maturation. Thus the data taken as a function of pressure have relevance to the influence of normal and abnormal fluid pressures as related to: 1) depths and temperatures of mainstage hydrocarbon generation; 2) the thermal destruction of deposits of gas or light oil, or their preservation to unexpectedly high maturation ranks; and 3) the persistence of measurable to moderate concentrations of C15+ hydrocarbons in fine-grained rocks even to ultra-high maturation ranks. ?? 1992.

Mechanical study of the Chartreuse Fold-and-Thrust Belt: relationships between fluids overpressure and decollement within the Toarcian source-rock

NASA Astrophysics Data System (ADS)

Berthelon, Josselin; Sassi, William; Burov, Evgueni

2016-04-01

Many source-rocks are shale and constitute potential detachment levels in Fold-and-Thrust Belts (FTB): the toarcian Schistes-Cartons in the French Chartreuse FTB for example. Their mechanical properties can change during their burial and thermal maturation, as for example when large amount of hydrocarbon fluids are generated. A structural reconstruction of the Chartreuse FTB geo-history places the Toarcian Formation as the major decollement horizon. In this work, a mechanical analysis integrating the fluids overpressuring development is proposed to discuss on the validity of the structural interpretation. At first, an analogue of the Chartreuse Toarcian Fm, the albanian Posidonia Schist, is documented as it can provide insights on its initial properties and composition of its kerogen content. Laboratory characterisation documents the vertical evolution of the mineralogical, geochemical and mechanical parameters of this potential decollement layer. These physical parameters (i.e. Total Organic Carbon (TOC), porosity/permeability relationship, friction coefficient) are used to address overpressure buildup in the frontal part of the Chartreuse FTB with TEMISFlow Arctem Basin modelling approach (Faille et al, 2014) and the structural emplacement of the Chartreuse thrust units using the FLAMAR thermo-mechanical model (Burov et al, 2014). The hydro-mechanical modeling results highlight the calendar, distribution and magnitude of the overpressure that developed within the source-rock in the footwall of a simple fault-bend fold structure localized in the frontal part of the Chartreuse FTB. Several key geological conditions are required to create an overpressure able to fracture the shale-rocks and induce a significant change in the rheological behaviour: high TOC, low permeability, favourable structural evolution. These models highlight the importance of modeling the impact of a diffuse natural hydraulic fracturing to explain fluids propagation toward the foreland within the decollement layer. In turn, with the FLAMAR geo-mechanical models it is shown that for key mechanical parameters within the Chartreuse mechanical stratigraphy (such as friction coefficient, cohesion and viscosity properties), the mechanical boundary conditions to activate, localize and propagate shear thrust in the toarcian source-rock can be found to discuss on the hydro-mechanics of the structural evolution: the very weak mechanical properties that must be attributed to the source-rock to promote the formation of a decollement tend to justify the hypothesis of high fluids pressures in it. In FLAMAR, the evolution of the toarcian source-rock mechanical properties, calibrated on the temperature of kerogen-to-gas transformation, can be introduced to allow its activation as a decollement at a burial threshold. However, without hydro-mechanical coupling, it is not possible to predict where the overpressured regions that localised these changes are positioned. As such, this work also highlights the need for a fully-coupled hydro-mechanical model to further investigate the relationship between fluids and deformations in FTB and accretionary prisms. Burov, E., Francois, T., Yamato, P., & Wolf, S. (2014). Mechanisms of continental subduction and exhumation of HP and UHP rocks. Gondwana Research, 25(2), 464-493. Faille, I., Thibaut, M., Cacas, M.-C., Havé, P., Willien, F., Wolf, S., Agelas, L., Pegaz-Fiornet, S., 2014. Modeling Fluid Flow in Faulted Basins. Oil Gas Sci. Technol. - Rev. d'IFP Energies Nouv. 69, 529-553.

Geochemical Aspects of Formation of Large Oil Deposits in the Volga-Ural Sedimentary Basin

NASA Astrophysics Data System (ADS)

Plotnikova, I.; Nosova, F.; Pronin, N.; Nosova, J.; Budkevich, T.

2012-04-01

The study of the rocks domanikoid type in the territory of the Ural-Volga region has an almost century-long history, beginning with the first studies of A.D. Archangelsky in the late 20's of last century. But nevertheless the question of the source of oil that formed the industrial deposits of Volga-Ural oil and gas province (OGP), where Romashkinskoye oil field occupies a special place, remains unresolved and topical. According to the sedimentary-migration theory of origin of oil and gas, it is supposed that the primary source of hydrocarbons in this area are the deposits of domanikoid type that contain a large ammount of sapropel organic matter (OM). Semiluki (domanik) horizon of srednefranski substage of the Upper Devonian is considered to be a typical domanikoid stratum. Investigation of the OM of the rocks and oils of the sedimentary cover on the basis of chromato-mass spectrometry method allows us to study the correlations between rock and oil and to assess the location (or absence) of the sources of hydrocarbons in the Paleozoic sedimentary cover. The results of geochemical study of dispersed organic matter (DOM) of rocks from Semiluksky horizon of the Upper Devonian and of the oil from Pashiysky horizon of the Middle Devonian form the basis of this paper. The objectives of this study were the following: to determine the original organic matter of the rocks, which would indicate the conditions of sedimentation of the supposed rock-oil sources; the study of chemofossils (biomarkers) in oil from Pashiyskiy horizon; and the identification of genetic association of DOM rocks from Semiluksky horizon with this oil on the basis of the oil-DOM correlation. The study of biomarkers was carried out with the help of chromato-mass spectrometry in the Laboratory of Geochemistry of Fossil Fuels (Kazan Federal University). In this study we used several informative parameters characterizing the depositional environment, the type of source OM and its maturity: STER / PENT, hC35/hC34, GAM / HOP, S27/S28/S29 (steranes), DIA / REG, Ts / Tm, MOR / HOP, NOR / HOP, TET / TRI, C29SSR, C29BBAA, C31HSR, S30STER, TRI / PENT, TRI / HOP. Comparison in the rock-oil system was performed primarily according to the parameters indicating the depositional environment of the source rock that contains syngenetic DOM - according to the coefficients that determine lithological conditions for the formation of the supposed oil-source bed strata (DIA / REG, Ts / Tm, NOR / HOP, TRI / HOP and STER / PENT). Biomarker ratios indicate a different type of sedimentation basins. Sediments, which accumulated DOM from Semilukskiy horizon, can be characterized by low clay content, or its absence, that is consistent with the carbonate type of cut of the horizon. The bacterial material that was accumulated under reducing conditions of sedimentation appeared to be the source of syngenetic OM. Chemofossils found in oils from Pashiyskiy horizon are typical of sedimentary strata that contain clay - for clastic rocks, which in the study area are mainly represented by deposits and Eyfel Givetian layers of the Middle Devonian and lowfransk substage of the Upper Devonian. The study of correlations obtained for the different coefficients of OM and oils showed that only the relationships between Ts/Tm and DIA/REG and between NOR/HOP and TRI/HOP are characteristic of close, almost similar values of correlation both for the dispersed organic matter and for oil. In all other cases, the character of the correlation of OM is significantly different from that of oil. The differences in values and ranges of biomarker ratios as well as the character of their correlation indicates the absence of genetic connection between the oil from Pashiyskiy horizon for the dispersed organic matter from Semilukskiy horizon. This conclusion is based on the study of five biomarker parameters (DIA/REG, Ts/Tm, NOR/HOP, TRI/HOP and STER/PENT). The research results described in the article clearly indicate the need for further studies of geochemical features of the organic matter of the Paleozoic mantle rocks and the underlying sedimentary and crystalline complexes of Precambrian.

Unconventional shallow biogenic gas systems

USGS Publications Warehouse

Shurr, G.W.; Ridgley, J.L.

2002-01-01

Unconventional shallow biogenic gas falls into two distinct systems that have different attributes. Early-generation systems have blanketlike geometries, and gas generation begins soon after deposition of reservoir and source rocks. Late-generation systems have ringlike geometries, and long time intervals separate deposition of reservoir and source rocks from gas generation. For both types of systems, the gas is dominantly methane and is associated with source rocks that are not thermally mature. Early-generation biogenic gas systems are typified by production from low-permeability Cretaceous rocks in the northern Great Plains of Alberta, Saskatchewan, and Montana. The main area of production is on the southeastern margin of the Alberta basin and the northwestern margin of the Williston basin. The huge volume of Cretaceous rocks has a generalized regional pattern of thick, non-marine, coarse clastics to the west and thinner, finer grained marine lithologies to the east. Reservoir rocks in the lower part tend to be finer grained and have lower porosity and permeability than those in the upper part. Similarly, source beds in the units have higher values of total organic carbon. Patterns of erosion, deposition, deformation, and production in both the upper and lower units are related to the geometry of lineament-bounded basement blocks. Geochemical studies show that gas and coproduced water are in equilibrium and that the fluids are relatively old, namely, as much as 66 Ma. Other examples of early-generation systems include Cretaceous clastic reservoirs on the southwestern margin of Williston basin and chalks on the eastern margin of the Denver basin. Late-generation biogenic gas systems have as an archetype the Devonian Antrim Shale on the northern margin of the Michigan basin. Reservoir rocks are fractured, organic-rich black shales that also serve as source rocks. Although fractures are important for production, the relationships to specific geologic structures are not clear. Large quantities of water are coproduced with the gas, and geochemical data indicate that the water is fairly fresh and relatively young. Current thinking holds that biogenic gas was generated, and perhaps continues to be, when glacial meltwater descended into the plumbing system provided by fractures. Other examples of late-generation systems include the Devonian New Albany Shale on the eastern margin of the Illinois basin and the Tertiary coalbed methane production on the northwestern margin of the Powder River basin. Both types of biogenic gas systems have a similar resource development history. Initially, little technology is used, and gas is consumed locally; eventually, sweet spots are exploited, widespread unconventional reservoirs are developed, and transport of gas is interstate or international. However, drilling and completion techniques are very different between the two types of systems. Early-generation systems have water-sensitive reservoir rocks, and consequently water is avoided or minimized in drilling and completion. In contrast, water is an important constituent of late-generation systems; gas production is closely tied to dewatering the system during production. Existing production and resource estimates generally range from 10 to 100 tcf for both types of biogenic gas systems. Although both system types are examples of relatively continuous accumulations, the geologic frameworks constrain most-economic production to large geologic structures on the margins of basins. Shallow biogenic gas systems hold important resources to meet the increased domestic and international demands for natural gas.

Geology and hydrocarbon potential of the Oued Mya Basin, Algeria

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

Benamrane, O.; Messaoudi, M.; Messelles, H.

1992-01-01

The hydrocarbon System Ourd Mya is located in the Sahara Basin. It is one of the producing basin in Algeria. The stratigraphic section consists of Paleozoic and Mesosoic, it is about 5000m thick. In the eastern part, the basin is limited by the Hassi-Messaoud high zone which is a giant oil field producing from the Cambrian sands. The western part is limited by Hassi R'mel which is one of the biggest gas field in the world, it is producing from the triassic sands. The Mesozoic section is laying on the lower Devonian and in the eastern part, on the Cambrian.more » The main source rock is the Silurian shale with an average thickness of 50m and a total organic matter of 6% (14% in some cases). Results of maturation modeling indicate that the lower Silurian source is in the oil window. The Ordovician shales are also a source rock, but in a second order. Clastic reservoirs are in the Triassic sequence which is mainly fluvial deposits with complex alluvial channels, it is the main target in the basin. Clastic reservoirs within the lower Devonian section have a good hydrocarbon potential in the east of the basin through a southwest-northeast orientation. The late Triassic-Early Jurassic evaporites overlie the Triassic clastic interval and extend over the entire Oued Mya Basin. This is considered as a super-seal evaporate package, which consists predominantly of anhydrite and halite. For Paleozoic targets, a large number of potential seals exist within the stratigraphic column. The authors infer that a large amount of the oil volume generated by the Silurian source rock from the beginning of Cretaceous until now, still not discovered could be trapped within structure closures and mixed or stratigraphic traps related to the fluvial Triassic sandstones, marine Devonian sands and Cambro-Ordovician reservoirs.« less

Compound-specific carbon isotope analysis of instantaneous gas generated from shaly coal during hydrous pyrolysis

NASA Astrophysics Data System (ADS)

Tsai, Wen-Yu; Sun, Chih-Hsien; Huang, Wuu-Liang

2010-05-01

Isotopes of natural gases have provided important information for indicating their maturation, origins and influencing factors during the generation processes. In order to distinguish compositions of gas generated at different intervals of maturities, the present study investigates the variation of compound-specific carbon isotope (CSI) ratios of hydrocarbon gases from a shaly coal by instantaneous hydrous pyrolysis, during which the earlier generated gas was evacuated before the start of next maturation stage. The experiments were conducted at ten different maturity stages (0.65 to 2.02 % Ro) from a terrestrial shaly coal with 0.48 % Ro. The gas products were analyzed by GC-IR-MS. The results show that, in general, the δ13C values of methane (C1), ethane (C2), propane (C3) slightly increase, then decrease and finally increase with increasing maturities. This reverse phenomenon indicates the heterogeneous and complex compositions of the kerogen. The isotope compositions of gases exhibit three distinct clusters in natural gas plot of δ13C values versus 1/n (where n is carbon number of the gaseous molecule), corresponding to three different groups of maturity stages. By linking the same maturity stage of δ13C values, all lines show nearly parallel in each group with consistently reverse trend of δ13C3 < δ13C2 > δ13C1. These three distinct clusters were also observed in the cross plotting of iC4/nC4 versus iC5/nC5 isomer ratios. This may imply that the kerogen is composed of three discrete structural domains which were progressively cracked at three major groups of maturity stages. The reverse trend was inconsistent with data for gas collected cumulatively in most prior pyrolysis experiments and the linear relationship predicted from kinetic isotope effect (KIE) model. Although the non-linear relationship or reverse trend, δ13C3 < δ13C2, was also reported for some natural gases, it was interpreted as a result of mixing from different source rocks or other processes. Our results, however, suggest that this non-linear relationship or reverse phenomenon can also be attributed to the mixing of gases generated from different maturity stages solely from a single source formation. Therefore, our results provide a new interpretation for the variation of isotope data of the cumulative and instantaneous gases in hydrous pyrolysis experiments and isotope variation in natural gas.

Geologic assessment of undiscovered oil and gas resources in the Albian Clastic and Updip Albian Clastic Assessment Units, U.S. Gulf Coast Region

USGS Publications Warehouse

Merrill, Matthew D.

2016-03-11

U.S. Geological Survey National Oil and Gas Assessments (NOGA) of Albian aged clastic reservoirs in the U.S. Gulf Coast region indicate a relatively low prospectivity for undiscovered hydrocarbon resources due to high levels of past production and exploration. Evaluation of two assessment units (AUs), (1) the Albian Clastic AU 50490125, and (2) the Updip Albian Clastic AU 50490126, were based on a geologic model incorporating consideration of source rock, thermal maturity, migration, events timing, depositional environments, reservoir rock characteristics, and production analyses built on well and field-level production histories. The Albian Clastic AU is a mature conventional hydrocarbon prospect with undiscovered accumulations probably restricted to small faulted and salt-associated structural traps that could be revealed using high resolution subsurface imaging and from targeting structures at increased drilling depths that were unproductive at shallower intervals. Mean undiscovered accumulation volumes from the probabilistic assessment are 37 million barrels of oil (MMBO), 152 billion cubic feet of gas (BCFG), and 4 million barrels of natural gas liquids (MMBNGL). Limited exploration of the Updip Albian Clastic AU reflects a paucity of hydrocarbon discoveries updip of the periphery fault zones in the northern Gulf Coastal region. Restricted migration across fault zones is a major factor behind the small discovered fields and estimation of undiscovered resources in the AU. Mean undiscovered accumulation volumes from the probabilistic assessment are 1 MMBO and 5 BCFG for the Updip Albian Clastic AU.

Mapping thermal maturity in the Chainman shale, near Eureka, Nevada, with Landsat Thematic Mapper images

USGS Publications Warehouse

Rowan, L.C.; Pawlewicz, M.J.; Jones, O.D.

1992-01-01

The purpose of this study was to determine if there is a correlation between measurements of organic matter (OM) maturity and laboratory measurements of visible and near-infrared spectral reflectance, and if Landsat Thematic Mapper (TM) images could be used to map maturity. The maturity of Mississippian Chainman Shale samples collected in east-central Nevada and west-central Utah was determined by using vitrinite reflectance and Rock-Eval pyrolysis. TM 4/TM 5 values correspond well to vitrinite reflectance and hydrogen index variations, and therefore this ratio was used to evaluate a TM image of the Eureka, Nevada, area for mapping thermal maturity differences in the Chainman Shale. -from Authors

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.

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.

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

Not Available

An Apple IIe microcomputer is being used to collect data and to control a pyrolysis system. Pyrolysis data for bitumen and kerogen are widely used to estimate source rock maturity. For a detailed analysis of kinetic parameters, however, data must be obtained more precisely than for routine pyrolysis. The authors discuss the program which controls the temperature ramp of the furnace that heats the sample, and collects data from a thermocouple in the furnace and from the flame ionization detector measuring evolved hydrocarbons. These data are stored on disk for later use by programs that display the results of themore » experiment or calculate kinetic parameters. The program is written in Applesoft BASIC with subroutines in Apple assembler for speed and efficiency.« less

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.

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.

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

Detecting the thermal aureole of a magmatic intrusion in immature to mature sediments: a case study in the East Greenland Basin (73°N)

NASA Astrophysics Data System (ADS)

Aubourg, Charles; Techer, Isabelle; Geoffroy, Laurent; Clauer, Norbert; Baudin, François

2014-01-01

The Cretaceous and Triassic argillaceous rocks from the passive margin of Greenland have been investigated in order to detect the thermal aureole of magmatic intrusions, ranging from metric dyke to kilometric syenite pluton. Rock-Eval data (Tmax generally <468 °C), vitrinite reflectance data (R0 < 0.9 per cent) and illite cristallinity data (ICI > 0.3), all indicate a maximum of 5 km burial for the argillaceous rocks whatever the distance to an intrusion. The K-Ar dating of the clays <2 μm fraction suggests that illites are mostly detrital, except near magmatic intrusions where younger ages are recorded. To get more information about the extent of the thermal aureole, rock magnetism data were determined. At distance away from the thermal aureole of the syenite intrusion, Triassic argillaceous rocks reveal a standard magnetic assemblage compatible with their burial (R0 ˜ 0.4 per cent). It is constituted essentially by neoformed stoichiometric magnetite (Fe3O4). In contrast, within the thermal aureole of the magmatic intrusions, the Cretaceous argillaceous rocks contain micron-sized pyrrhotite (Fe7S8), firmly identified through the recognition of Besnus transition at 35 K. The thermal demagnetization of natural remanence carried by this pyrrhotite shows a diagnostic `square shouldered' pattern, indicating a narrow grain size distribution of pyrrhotite. The extension of this diagnostic pyrrhotite maps a ˜10-km-thick aureole around the syenitic pluton. Away from this aureole, the magnetic assemblage is diagnostic of those found in argillaceous rocks where organic matter is mature.

The New Albany shale in Illinois: Emerging play or prolific source

USGS Publications Warehouse

Crockett, Joan; Morse, David E.

2010-01-01

The New Albany shale (Upper Devonian) in the Illinois basin is the primary hydrocarbon source rock for the basins nearly 4 billion bbl of oil production to date. The gas play is well-established in Indiana and Western Kentucky. One in-situ oil producing well was reported in a multiply competed well in the New Albany at Johnsonville field in Wayne County, Illinois. The Illinois gas and oil wells at Russellville, in Lawrence County are closely associated with the 0.6% reflectance contour, which suggests a higher level of thermal maturity in this area. Today, only one field, Russellville in eastern Lawrence County has established commercial production in the Ness Albany in Illinois. Two wildcat wells with gas shows were drilled in recent years in southern Saline County, where the New Albany is relatively deeply buried and close to faults associated with the Fluorspar District.

Compaction of basin sediments as a function of time-temperature history

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

Schmoker, J.W.; Gautier, D.L.

1989-03-01

Processes that affect burial diagenesis are dependent on time-temperature history (thermal maturity). Therefore, the porosity loss of sedimentary rocks during burial may often be better treated as a function of time-temperature history than of depth. Loss of porosity in the subsurface for sandstones, carbonates, and shales can be represented by a power function /phi/ = A(M)/sup B/, where /phi/ is porosity, A and B are constants for a given sedimentary rock population of homogeneous properties, and M is a measure of thermal maturity such as vitrinite reflectance (R/sub 0/) or Lopatin's time-temperature index (TTI). Regression lines of carbonate porosity andmore » of sandstone porosity upon thermal maturity form an envelope whose axis is approximated by /phi/ = 7.5(R/sub 0/)/sup /minus/1.18/ or, equivalently, by /phi/ = 30(TTI)/sup /minus/0.33/. These equations are preliminary generic relations of use for the regional modeling of both carbonate and sandstone compaction in sedimentary basins. The dependence of porosity upon time-temperature history incorporates the hypothesis that porosity-reducing processes operate continuously in sedimentary basins and, consequently, that compaction of basin sediments continues as long as porosity exists. Calculations indicate that subsidence due to loss of porosity through time (with depth held constant) can produce a second-stage passively formed basin in which many hundreds of meters of sediments can accumulate and which conforms with the structure of the original underlying basin. Such sediment accumulation results from the thermal maturation of thick sequences of sedimentary rocks rather than from global sea level change or tectonic subsidence.« less

Oil gravity distribution in the diatomite at South Belridge Field, Kern County, CA: Implications for oil sourcing and migration

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

Hill, D.W.; Sande, J.J.; Doe, P.H.

1995-04-01

Understanding oil gravity distribution in the Belridge Diatomite has led to economic infill development and specific enhanced recovery methods for targeted oil properties. To date more than 100 wells have provided samples used to determining vertical and areal distribution of oil gravity in the field. Detailed geochemical analyses were also conducted on many of the oil samples to establish different oil types, relative maturities, and to identify transformed oils. The geochemical analysis also helped identify source rock expulsion temperatures and depositional environments. The data suggests that the Belridge diatomite has been charged by a single hydrocarbon source rock type andmore » was generated over a relatively wide range of temperatures. Map and statistical data support two distinct oil segregation processes occurring post expulsion. Normal gravity segregation within depositional cycles of diatomite have caused lightest oils to migrate to the crests of individual cycle structures. Some data suggests a loss of the light end oils in the uppermost cycles to the Tulare Formation above, or through early biodegradation. Structural rotation post early oil expulsion has also left older, heavier oils concentrated on the east flank of the structure. With the addition of other samples from the south central San Joaquin area, we have been able to tie the Belridge diatomite hydrocarbon charge into a regional framework. We have also enhanced our ability to predict oil gravity and well primary recovery by unraveling some key components of the diatomite oil source and migration history.« less

Sedimentary records on the subduction-accretion history of the Russian Altai, northwestern Central Asian Orogenic Belt

NASA Astrophysics Data System (ADS)

Chen, Ming; Sun, Min

2017-04-01

The Russian Altai, comprising the northern segment of the Altai-Mongolian terrane (AM) in the south, the Gorny Altai terrane (GA) in the north and the intervening Charysh-Terekta-Ulagan-Sayan suture zone, is a key area of the northwestern Central Asian Orogenic Belt (CAOB). A combined geochemical and detrital zircon study was conducted on the (meta-)sedimentary sequences from the Russian Altai to reveal the tectono-magmatic history of these two terranes and their amalgamation history, which in turn place constraints on the accretionary orogenesis and crustal growth in the CAOB. The Cambrian-Ordovician meta-sedimentary rocks from the northern AM are dominated by immature sediments possibly sourced from intermediate-felsic igneous rocks. Geochemical data show that the sediments were likely deposited in a continental arc-related setting. Zircons separated from these rocks are mainly 566-475 Ma and 1015-600 Ma old, comparable to the magmatic records of the Tuva-Mongolian terrane and surrounding island arcs in the western Mongolia. The similar source nature, provenance and depositional setting of these rocks to the counterparts from the Chinese Altai (i.e., the southern AM) imply that the whole AM possibly represents a coherent accretionary prism of the western Mongolia in the early Paleozoic rather than a Precambrian continental block with passive marginal deposition as previously thought. In contrast, the Cambrian to Silurian (meta-)sedimentary rocks from the GA are characterized by a unitary zircon population with ages of 640-470 Ma, which were potentially sourced from the Kuznetsk-Altai intra-oceanic island arc in the east of this terrane. The low abundance of 640-540 Ma zircons (5%) may attest that this arc was under a primitive stage in the late Neoproterozoic, when mafic igneous rocks dominated. However, the voluminous 530-470 Ma zircons (95%) suggest that this arc possibly evolved toward a mature one in the Cambrian to early Ordovician with increasing amount of intermediate-felsic igneous rocks, highlighting both crustal growth and recycling. Importantly, a significant amount of additional 2431-772 Ma zircons occur in the early Devonian sedimentary sequence of the GA. These detrital zircons possibly have the same source as their counterpart from the AM. This implies that the two terranes with countrary evolutionary history, i.e. the GA and AM, amalgamated before the early Devonian. To summary, the AM and GA represented two separated subduction-accretion systems in the early Paleozoic and subsequently amalgamated prior to the early Devonian, documenting complicated accretionary orogenesis and significant lateral crustal growth in the CAOB. Acknowledgement This study is financially supported by the Major Research Project of the Ministry of Science and Technology of China (2014CB44801 and 2014CB448000), Hong Kong Research Grant Council (HKU705313P and HKU17303415), National Science Foundation of China (41273048) and the Fundamental Research Funds for the Central Universities, China University of Geosciences (Wuhan) (162301132731).

Hydrocarbon gases associated with permafrost in the Mackenzie Delta, Northwest Territories, Canada

USGS Publications Warehouse

Collett, T.S.; Dallimore, S.R.

1999-01-01

Molecular and isotopic analyses of core gas samples from 3 permafrost research core holes (92GSCTAGLU, 92GSCKUMAK, 92GSCUNIPKAT; sample core depths ranging from 0.36 to 413.82 m) in the Mackenzie Delta of the Northwest Territories of Canada reveal the presence of hydrocarbon gases from both microbial and thermogenic sources. Analyses of most headspace and blended gas samples from the ice-bonded permafrost portion of the core holes yielded C1/(C2 + C3) hydrocarbon gas ratios and CH4-C isotopic compositions (??13C CH4) indicative of microbially sourced CH4 gas. However, near the base of ice-bonded permafrost and into the underlying non-frozen stratigraphic section, an increase in ethane (C2) concentrations, decreases in C1/(C2 + C3) hydrocarbon gas ratios, and CH4-C isotopic (??13C CH4) data indicate the presence of hydrocarbon gases derived from a thermogenic source. The thermogenic gas below permafrost in the Mackenzie Delta likely migrated from deeper hydrocarbon accumulations and/or directly from thermally mature hydrocarbon source rocks.

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.

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

The metamorphic basement of the southern Sierra de Aconquija, Eastern Sierras Pampeanas: Provenance and tectonic setting of a Neoproterozoic back-arc basin

NASA Astrophysics Data System (ADS)

Cisterna, Clara Eugenia; Altenberger, Uwe; Mon, Ricardo; Günter, Christina; Gutiérrez, Antonio

2018-03-01

The Eastern Sierras Pampeanas are mainly composed of Neoproterozoic-early Palaeozoic metamorphic complexes whose protoliths were sedimentary sequences deposited along the western margin of Gondwana. South of the Sierra de Aconquija, Eastern Sierras Pampeanas, a voluminous metamorphic complex crops out. It is mainly composed of schists, gneisses, marbles, calk-silicate schists, thin layers of amphibolites intercalated with the marbles and granitic veins. The new data correlate the Sierra de Aconquija with others metamorphic units that crop out to the south, at the middle portion of the Sierra de Ancasti. Bulk rock composition reflects originally shales, iron rich shales, wackes, minor litharenites and impure limestones as its protoliths. Moreover, comparisons with the northern Sierra de Aconquija and from La Majada (Sierra de Ancasti) show similar composition. Amphibolites have a basaltic precursor, like those from the La Majada (Sierra de Ancasti) ones. The analyzed metamorphic sequence reflects low to moderate weathering conditions in the sediments source environment and their chemical composition would be mainly controlled by the tectonic setting of the sedimentary basin rather than by the secondary sorting and reworking of older deposits. The sediments composition reveal relatively low maturity, nevertheless the Fe - shale and the litharenite show a tendency of minor maturity among them. The source is related to an acid one for the litharenite protolith and a more basic to intermediate for the other rocks, suggesting a main derivation from intermediate to felsic orogen. The source of the Fe-shales may be related to and admixture of the sediments with basic components. Overall the composition point to an upper continental crust as the dominant sediment source for most of the metasedimentary rocks. The protolith of the amphibolites have basic precursors, related to an evolving back-arc basin. The chemical data in combination with the specific sediment association (wackes, shales, Fe-shales and minor litharenites) are characteristic for turbidity currents deposits along tectonically active region. They are also commonly associated with calcareous clays (marbles), commonly observed in the evolution of basins with slope and shelf derived carbonate turbidites. The amphibolites members are probably derived from lava-flows synchronous with the sedimentation during the basin evolution. The basin was controlled by a continental island arc possible evolving to a back-arc setting, as indicated for the mixed nature of the inferred source. The metasedimentary sequence from the Cuesta de La Chilca have petrographic, structural and strong chemical similarities, building a north-south striking belt from the north of the Sierra de Aconquija and to the south along the Sierra de Ancasti (La Majada area). The observed similarities allow to present this portion of the Eastern Sierras Pampeanas as a crustal block that records the sedimentary sequences developed along the geodynamic context of the southwestern margin of Gondwana during the Neoproterozoic and Early Palaeozoic.

New Prespective Paleogeography of East Java Basin; Implicationrespond to Oil and Gas Eksploration at Kujung Formation Carbonate Reservoar

NASA Astrophysics Data System (ADS)

Aprilana, C.; Premonowati; S, Hanif I.; Choirotunnisa; Shirly, A.; Utama, M. K.; Sinulingga, Y. R.; Syafitra, F.

2018-03-01

Paleogeography is one of critical points that always less considered by explorationist in the world. Almost all of the consideration is focused on trapping mechanism. Paleogeography is guidance in understanding both of physical and chemical of rock characteristic which will correlate with its depositional environment. Integration of various geological and geophysical data such as; tectonic, structural geology, stratigraphy, lithology, and biostratigraphy will lead us to a better understanding of rock characteristics. Six paleogeographic interpretations was made consist of; Early Tertiary (P5-56-55 ma), Middle Eocene (P14-41 ma), Late Oiligocene (P22-25.5 ma), Early Miocene (N7-16.5 ma), Middle Miocene (N9-14.5 ma), and Pleistocene (NN19-1.5 ma). That six paleogeographic interpretations are assumed represent the paleogeographic evolution of East Java Basin time after time. In Middle Eocene time, it would be more than hundred possibilities regarding the location where the formation deposited. This would be controlled by the existence of some local structural paleohighs and horsts which oriented NW-SE followed by their own sedimentary transportation path. With assumption that hydrocarbon generation was occurred in 15 Ma and the depth of maturation window lies on about 2,500 m depth. Therefore, the possibility of source rock maturation is high, due to almost of the clastics sediment of Ngimbang deposited into the series of grabens. The Kujung reef types simplified defines and categorize into; 1) Patch Reef 2) Berrier Reef 3) Pinnacle Reef Over Isolated Reef. Kujung Carbonates were deposited in Early Miocene when regional transgression occurred. The depositional environments were dominated by shallow marine littoral-sublittoral. Generally, the reservoir quality of this Kujung Carbonate shows fair to good quality, in range7-32% porosity, and 1-1400 mD permeability (internal SKK Migas data).

Effect of concentration of dispersed organic matter on optical maturity parameters: Interlaboratory results of the organic matter concentration working group of the ICCP.

USGS Publications Warehouse

Mendonca, Filho J.G.; Araujo, C.V.; Borrego, A.G.; Cook, A.; Flores, D.; Hackley, P.; Hower, J.C.; Kern, M.L.; Kommeren, K.; Kus, J.; Mastalerz, Maria; Mendonca, J.O.; Menezes, T.R.; Newman, J.; Ranasinghe, P.; Souza, I.V.A.F.; Suarez-Ruiz, I.; Ujiie, Y.

2010-01-01

The main objective of this work was to study the effect of the kerogen isolation procedures on maturity parameters of organic matter using optical microscopes. This work represents the results of the Organic Matter Concentration Working Group (OMCWG) of the International Committee for Coal and Organic Petrology (ICCP) during the years 2008 and 2009. Four samples have been analysed covering a range of maturity (low and moderate) and terrestrial and marine geological settings. The analyses comprise random vitrinite reflectance measured on both kerogen concentrate and whole rock mounts and fluorescence spectra taken on alginite. Eighteen participants from twelve laboratories from all over the world performed the analyses. Samples of continental settings contained enough vitrinite for participants to record around 50 measurements whereas fewer readings were taken on samples from marine setting. The scatter of results was also larger in the samples of marine origin. Similar vitrinite reflectance values were in general recorded in the whole rock and in the kerogen concentrate. The small deviations of the trend cannot be attributed to the acid treatment involved in kerogen isolation but to reasons related to components identification or to the difficulty to achieve a good polish of samples with high mineral matter content. In samples difficult to polish, vitrinite reflectance was measured on whole rock tended to be lower. The presence or absence of rock fabric affected the selection of the vitrinite population for measurement and this also had an influence in the average value reported and in the scatter of the results. Slightly lower standard deviations were reported for the analyses run on kerogen concentrates. Considering the spectral fluorescence results, it was observed that the ??max presents a shift to higher wavelengths in the kerogen concentrate sample in comparison to the whole-rock sample, thus revealing an influence of preparation methods (acid treatment) on fluorescence properties. ?? 2010 Elsevier B.V.

Chitin: 'Forgotten' Source of Nitrogen: From Modern Chitin to Thermally Mature Kerogen: Lessons from Nitrogen Isotope Ratios

USGS Publications Warehouse

Schimmelmann, A.; Wintsch, R.P.; Lewan, M.D.; DeNiro, M.J.

1998-01-01

Chitinous biomass represents a major pool of organic nitrogen in living biota and is likely to have contributed some of the fossil organic nitrogen in kerogen. We review the nitrogen isotope biogeochemistry of chitin and present preliminary results suggesting interaction between kerogen and ammonium during thermal maturation. Modern arthropod chitin may shift its nitrogen isotope ratio by a few per mil depending on the chemical method of chitin preparation, mostly because N-containing non-amino-sugar components in chemically complex chitin cannot be removed quantitatively. Acid hydrolysis of chemically complex chitin and subsequent ion-chromatographic purification of the "deacetylated chitin-monomer" D-glucosamine (in hydrochloride form) provides a chemically well-defined, pure amino-sugar substrate for reproducible, high-precision determination of ??15N values in chitin. ??15N values of chitin exhibited a variability of about one per mil within an individual's exoskeleton. The nitrogen isotope ratio differed between old and new exoskeletons by up to 4 per mil. A strong dietary influence on the ??15N value of chitin is indicated by the observation of increasing ??15N values of chitin from marine crustaceans with increasing trophic level. Partial biodegradation of exoskeletons does not significantly influence ??15N values of remaining, chemically preserved amino sugar in chitin. Diagenesis and increasing thermal maturity of sedimentary organic matter, including chitin-derived nitrogen-rich moieties, result in humic compounds much different from chitin and may significantly change bulk ??15N values. Hydrous pyrolysis of immature source rocks at 330??C in contact with 15N-enriched NH4Cl, under conditions of artificial oil generation, demonstrates the abiogenic incorporation of inorganic nitrogen into carbon-bound nitrogen in kerogen. Not all organic nitrogen in natural, thermally mature kerogen is therefore necessarily derived from original organic matter, but may partly result from reaction with ammonium-containing pore waters.

Biomarkers in Tertiary mélange, western Olympic Peninsula, Washington, U.S.A.

USGS Publications Warehouse

Kvenvolden, Keith A.; Hostettler, Frances D.; Rapp, John B.; Snavely, Parke D.

1991-01-01

Middle Eocene to middle Miocene mélange and broken formations are exposed in the coastal outcrops along the west side of the Olympic Peninsula, Washington. A petroleum geochemical assessment of these geologic units has included the investigation of biomarker compounds. A comparison was made of biomarkers in an oil sample from a middle Miocene reservoir penetrated in the Medina No. 1 well with biomarkers in extracts from two samples of middle Eocene Ozette mélange (one sample having a strong petroliferous odor, and the other sample lacking this characteristic odor). Distribution patterns of n-alkanes, tricyclic terpanes, pentacyclic triterpanes, steranes, and diasteranes are remarkably similar in the oil and rock extracts. Biomarker maturity parameters indicate higher maturity in the oil relative to the extracts. The presence of 17α(H)-23,28-bisnorlupane, 18α(H)- and 18β(H)-oleanane, and de-A-lupane and an odd-carbon-number dominance of the n-alkanes in the oil and extracts seems to tie the hydrocarbons to a common source that has a significant terrigenous component.

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.

Geomorphic degradations on the surface of venus: an analysis of venera 9 and venera 10 data.

PubMed

Florensky, C P; Ronca, L B; Basilevsky, A T

1977-05-20

On the basis of the physical and chemical measurements made on the surface of Venus and transmitted back to Earth by the Soviet automatic landers Venera 9 and Venera 10, a geomorphically inactive environment should be expected. An analysis of the television photographs reveals, however, that at least two processes of degradation occur. One operates on a scale of decimeters to meters and is responsible for the fracturing of a layered source rock and the subsequent downslope movement of the fragments. Mass-wasting, perhaps activated by venusian quakes or by unknown geological processes, is likely to be the agent. Another geomorphic degradation process occurs on the scale of a centimeter or less and is responsible for the rounding of edges and the pitting of rock surfaces. The agents of this process are not known, but atmospheric action, perhaps in connection with volcanic episodes, may be the cause. From a geomorphic point of view, the landscape of the Venera 9 landing site can be considered young and that of the Venera 10 landing site, mature.

Differentiation of pre-existing trapped methane from thermogenic methane in an igneous-intruded coal by hydrous pyrolysis

USGS Publications Warehouse

Dias, Robert F.; Lewan, Michael D.; Birdwell, Justin E.; Kotarba, Maciej J.

2014-01-01

So as to better understand how the gas generation potential of coal changes with increasing rank, same-seam samples of bituminous coal from the Illinois Basin that were naturally matured to varying degrees by the intrusion of an igneous dike were subjected to hydrous pyrolysis (HP) conditions of 360 °C for 72 h. The accumulated methane in the reactor headspace was analyzed for δ13C and δ2H, and mol percent composition. Maximum methane production (9.7 mg/g TOC) occurred in the most immature samples (0.5 %Ro), waning to minimal methane values at 2.44 %Ro (0.67 mg/g TOC), and rebounding to 3.6 mg/g TOC methane in the most mature sample (6.76 %Ro). Methane from coal with the highest initial thermal maturity (6.76 %Ro) shows no isotopic dependence on the reactor water and has a microbial δ13C value of −61‰. However, methane from coal of minimal initial thermal maturity (0.5 %Ro) shows hydrogen isotopic dependence on the reaction water and has a δ13C value of −37‰. The gas released from coals under hydrous pyrolysis conditions represents a quantifiable mixture of ancient (270 Ma) methane (likely microbial) that was generated in situ and trapped within the rock during the rapid heating by the dike, and modern (laboratory) thermogenic methane that was generated from the indigenous organic matter due to thermal maturation induced by hydrous pyrolysis conditions. These findings provide an analytical framework for better assessment of natural gas sources and for differentiating generated gas from pre-existing trapped gas in coals of various ranks.

Petrogenesis of meta-volcanic rocks from the Maimón Formation (Dominican Republic): Geochemical record of the nascent Greater Antilles paleo-arc

NASA Astrophysics Data System (ADS)

Torró, Lisard; Proenza, Joaquín A.; Marchesi, Claudio; Garcia-Casco, Antonio; Lewis, John F.

2017-05-01

Metamorphosed basalts, basaltic andesites, andesites and plagiorhyolites of the Early Cretaceous, probably pre-Albian, Maimón Formation, located in the Cordillera Central of the Dominican Republic, are some of the earliest products of the Greater Antilles arc magmatism. In this article, new whole-rock element and Nd-Pb radiogenic isotope data are used to give new insights into the petrogenesis of the Maimón meta-volcanic rocks and constrain the early evolution of the Greater Antilles paleo-arc system. Three different groups of mafic volcanic rocks are recognized on the basis of their immobile element contents. Group 1 comprises basalts with compositions similar to low-Ti island arc tholeiites (IAT), which are depleted in light rare earth elements (LREE) and resemble the forearc basalts (FAB) and transitional FAB-boninitic basalts of the Izu-Bonin-Mariana forearc. Group 2 rocks have boninite-like compositions relatively rich in Cr and poor in TiO2. Group 3 comprises low-Ti island arc tholeiitic basalts with near-flat chondrite-normalized REE patterns. Plagiorhyolites and rare andesites present near-flat to subtly LREE-depleted chondrite normalized patterns typical of tholeiitic affinity. Nd and Pb isotopic ratios of plagiorhyolites, which are similar to those of Groups 1 and 3 basalts, support that these felsic lavas formed by anatexis of the arc lower crust. Geochemical modelling points that the parental basic magmas of the Maimón meta-volcanic rocks formed by hydrous melting of a heterogeneous spinel-facies mantle source, similar to depleted MORB mantle (DMM) or depleted DMM (D-DMM), fluxed by fluids from subducted oceanic crust and Atlantic Cretaceous pelagic sediments. Variations of subduction-sensitive element concentrations and ratios from Group 1 to the younger rocks of Groups 2 and 3 generally match the geochemical progression from FAB-like to boninite and IAT lavas described in subduction-initiation ophiolites. Group 1 basalts likely formed at magmatic stages transitional between FAB and first-island arc magmatism, whereas Group 2 boninitic lavas resulted from focused flux melting and higher degrees of melt extraction in a more mature stage of subduction. Group 3 basalts probably represent magmatism taking place immediately before the establishment of a steady-state subduction regime. The relatively high extents of flux melting and slab input recorded in the Maimón lavas support a scenario of hot subduction beneath the nascent Greater Antilles paleo-arc. Paleotectonic reconstructions and the markedly depleted, though heterogeneous character of the mantle source, indicate the rise of shallow asthenosphere which had sourced mid-ocean ridge basalts (MORB) and/or back-arc basin basalts (BABB) in the proto-Caribbean domain prior to the inception of SW-dipping subduction. Relative to the neighbouring Aptian-Albian Los Ranchos Formation, we suggest that Maimón volcanic rocks extruded more proximal to the vertical projection of the subducting proto-Caribbean spreading ridge.

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.

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

MX Siting Investigation. Geotechnical Evaluation. Detailed Aggregate Resources Study. Pahroc Study Area, Nevada.

DTIC Science & Technology

1981-06-05

source is a fairly limited outcrop of calcareous sandstone classified as dolomite rock (Do). Class RBIb Sources: Pour basin-fill sources within the study...Paleozoic rocks consist of limestone, dolomite , and quartzite with interbedded sandstone and shale. These units are generally exposed along the northern...categories simplify discussion and presentation without altering the conclusions of the study. 2.2.1 Rock Units Dolomite rocks (Do) and carbonate rocks

Devonian volcanic rocks of the southern Chinese Altai, NW China: Petrogenesis and implication for a propagating slab-window magmatism induced by ridge subduction during accretionary orogenesis

NASA Astrophysics Data System (ADS)

Ma, Xiaomei; Cai, Keda; Zhao, Taiping; Bao, Zihe; Wang, Xiangsong; Chen, Ming; Buslov, M. M.

2018-07-01

Ridge-trench interaction is a common tectonic process of the present-day Pacific Rim accretionary orogenic belts, and this process may facilitate "slab-window" magmatism that can produce significant thermal anomalies and geochemically unusual magmatic events. However, ridge-trench interaction has rarely been well-documented in the ancient geologic record, leading to grossly underestimation of this process in tectonic syntheses of plate margins. The Chinese Altai was inferred to have undergone ridge subduction in the Devonian and a slab-window model is proposed to interpret its high-temperature metamorphism and geochemically unique magmatic rocks, which can serve as an excellent and unique place to refine the tectonic evolution associated with ridge subduction in an ancient accretionary orogeny. For this purpose, we carried out geochemical and geochronological studies on Devonian basaltic rocks in this region. Secondary ion mass spectrometry (SIMS) zircon U-Pb dating results yield an age of 376.2 ± 2.4 Ma, suggesting an eruption at the time of Late Devonian. Geochemically, the samples in this study have variable SiO2 (43.3-58.3 wt%), low K2O (0.02-0.07 wt%) and total alkaline contents (2.16-5.41 wt%), as well as Fe2O3T/MgO ratios, showing typical tholeiitic affinity. On the other hand, the basaltic rocks display MORB-like REE patterns ((La/Yb)N = 0.90-2.57) and (Ga/Yb)N = 0.97-1.28), and have moderate positive εNd(t) values (+4.4 to +5.4), which collectively suggest a derivation from a mixing source comprising MORB-like mantle of a mature back-arc basin and subordinate arc mantle wedge. These basaltic rocks are characterized by Low La/Yb (1.26-3.69), Dy/Yb (1.51-1.77) and Sm/Yb (0.83-1.32) ratios, consistent with magmas derived from low degree (∼10%) partial melting of the spinel lherzolite source at a quite shallow mantle depth. Considering the distinctive petrogenesis of the basaltic rocks in this region, the Late Devonian basalts in the southern Chinese Altai is suggested to have witnessed the propagating process of slab-window magmatism that was induced by ridge subduction in a nascent rifting stage of a back-arc basin.

Effect of organic matter properties, clay mineral type and thermal maturity on gas adsorption in organic-rich shale systems

USGS Publications Warehouse

Zhang, Tongwei; Ellis, Geoffrey S.; Ruppel, Stephen C.; Milliken, Kitty; Lewan, Mike; Sun, Xun; Baez, Luis; Beeney, Ken; Sonnenberg, Steve

2013-01-01

A series of CH4 adsorption experiments on natural organic-rich shales, isolated kerogen, clay-rich rocks, and artificially matured Woodford Shale samples were conducted under dry conditions. Our results indicate that physisorption is a dominant process for CH4 sorption, both on organic-rich shales and clay minerals. The Brunauer–Emmett–Teller (BET) surface area of the investigated samples is linearly correlated with the CH4 sorption capacity in both organic-rich shales and clay-rich rocks. The presence of organic matter is a primary control on gas adsorption in shale-gas systems, and the gas-sorption capacity is determined by total organic carbon (TOC) content, organic-matter type, and thermal maturity. A large number of nanopores, in the 2–50 nm size range, were created during organic-matter thermal decomposition, and they significantly contributed to the surface area. Consequently, methane-sorption capacity increases with increasing thermal maturity due to the presence of nanopores produced during organic-matter decomposition. Furthermore, CH4 sorption on clay minerals is mainly controlled by the type of clay mineral present. In terms of relative CH4 sorption capacity: montmorillonite ≫ illite – smectite mixed layer > kaolinite > chlorite > illite. The effect of rock properties (organic matter content, type, maturity, and clay minerals) on CH4 adsorption can be quantified with the heat of adsorption and the standard entropy, which are determined from adsorption isotherms at different temperatures. For clay-mineral rich rocks, the heat of adsorption (q) ranges from 9.4 to 16.6 kJ/mol. These values are considerably smaller than those for CH4 adsorption on kerogen (21.9–28 kJ/mol) and organic-rich shales (15.1–18.4 kJ/mol). The standard entropy (Δs°) ranges from -64.8 to -79.5 J/mol/K for clay minerals, -68.1 to -111.3 J/mol/K for kerogen, and -76.0 to -84.6 J/mol/K for organic-rich shales. The affinity of CH4 molecules for sorption on organic matter is stronger than for most common clay minerals. Thus, it is expected that CH4 molecules may preferentially occupy surface sites on organic matter. However, active sites on clay mineral surfaces are easily blocked by water. As a consequence, organic-rich shales possess a larger CH4-sorption capacity than clay-rich rocks lacking organic matter. The thermodynamic parameters obtained in this study can be incorporated into model predictions of the maximum Langmuir pressure and CH4- sorption capacity of shales under reservoir temperature and pressure conditions.

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).

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.

The sedimentary organic matter from a Lake Ichkeul core (far northern Tunisia): Rock-Eval and biomarker approach

NASA Astrophysics Data System (ADS)

Affouri, Hassène; Sahraoui, Olfa

2017-05-01

The vertical distributions of bulk and molecular biomarker composition in samples from a ca. 156 cm sediment core from Lake Ichkeul were determined. Bulk analysis (Rock-Eval pyrolysis, carbonate, lipid extraction) and molecular analysis of saturated fractions were used to characterize the nature, preservation conditions and input of sedimentary organic matter (OM) to this sub-wet lake environment. The sediments are represented mainly by gray-black silty-clay facies where the carbonate (CaCO3) content varies in a range of 10-30% dry sediment. Rock-Eval pyrolysis revealed a homogeneous total organic carbon (TOC) content of ca. 1% sediment, but with down core fluctuation, indicating different anoxic conditions at different depths and material source variation. The values show three periods of relative enrichment, exceeding ca. 1%, at 146-134 cm, 82 cm and 14-0 cm depth. The low Hydrogen Index (HI) values [<119 mg hydrocarbon (HC)/g TOC)] were characteristic of continental Type III OM. The Tmax values in the range 415-420 °C were characteristic of immature OM at an early diagenetic stage. The distributions of n-alkanes (C17 to C34), isoprenoid (iso) alkanes (pristane and phytane), terpanes and steranes showed that the OM is a mixture of marine algal and bacterial source and emergent and floating higher plant origin. In addition, the distributions, as well as several biomarker ratios (n-alkanes, iso-alkanes/n-alkanes), showed that the OM is a mixture of immature and mature. Significant downcore fluctuation was observed in the molecular composition. This indicates intense microbial activity below ca. 50 cm core depth under an anoxic and brackish environment.

Determining the source and genetic fingerprint of natural gases using noble gas geochemistry: a northern Appalachian Basin case study

USGS Publications Warehouse

Hunt, Andrew G.; Darrah, Thomas H.; Poreda, Robert J.

2012-01-01

Silurian and Devonian natural gas reservoirs present within New York state represent an example of unconventional gas accumulations within the northern Appalachian Basin. These unconventional energy resources, previously thought to be noneconomically viable, have come into play following advances in drilling (i.e., horizontal drilling) and extraction (i.e., hydraulic fracturing) capabilities. Therefore, efforts to understand these and other domestic and global natural gas reserves have recently increased. The suspicion of fugitive mass migration issues within current Appalachian production fields has catalyzed the need to develop a greater understanding of the genetic grouping (source) and migrational history of natural gases in this area. We introduce new noble gas data in the context of published hydrocarbon carbon (C1,C2+) (13C) data to explore the genesis of thermogenic gases in the Appalachian Basin. This study includes natural gases from two distinct genetic groups: group 1, Upper Devonian (Marcellus shale and Canadaway Group) gases generated in situ, characterized by early mature (13C[C1  C2][13C113C2]: –9), isotopically light methane, with low (4He) (average, 1  103 cc/cc) elevated 4He/40Ar and 21Ne/40Ar (where the asterisk denotes excess radiogenic or nucleogenic production beyond the atmospheric ratio), and a variable, atmospherically (air-saturated–water) derived noble gas component; and group 2, a migratory natural gas that emanated from Lower Ordovician source rocks (i.e., most likely, Middle Ordovician Trenton or Black River group) that is currently hosted primarily in Lower Silurian sands (i.e., Medina or Clinton group) characterized by isotopically heavy, mature methane (13C[C1 – C2] [13C113C2]: 3), with high (4He) (average, 1.85  103 cc/cc) 4He/40Ar and 21Ne/40Ar near crustal production levels and elevated crustal noble gas content (enriched 4He,21Ne, 40Ar). Because the release of each crustal noble gas (i.e., He, Ne, Ar) from mineral grains in the shale matrix is regulated by temperature, natural gases obtain and retain a record of the thermal conditions of the source rock. Therefore, noble gases constitute a valuable technique for distinguishing the genetic source and post-genetic processes of natural gases.

Alaskan North Slope petroleum systems

USGS Publications Warehouse

Magoon, L.B.; Lillis, P.G.; Bird, K.J.; Lampe, C.; Peters, K.E.

2003-01-01

Six North Slope petroleum systems are identified, described, and mapped using oil-to-oil and oil-to-source rock correlations, pods of active source rock, and overburden rock packages. To map these systems, we assumed that: a) petroleum source rocks contain 3.2 wt. % organic carbon (TOC); b) immature oil-prone source rocks have hydrogen indices (HI) >300 (mg HC/gm TOC); c) the top and bottom of the petroleum (oil plus gas) window occur at vitrinite reflectance values of 0.6 and 1.0% Ro, respectively; and d) most hydrocarbons are expelled within the petroleum window. The six petroleum systems we have identified and mapped are: a) a southern system involving the Kuna-Lisburne source rock unit that was active during the Late Jurassic and Early Cretaceous; b) two western systems involving source rock in the Kingak-Blankenship, and GRZ-lower Torok source rock units that were active during the Albian; and c) three eastern systems involving the Shublik-Otuk, Hue Shale and Canning source rock units that were active during the Cenozoic. The GRZ-lower Torok in the west is correlative with the Hue Shale to the east. Four overburden rock packages controlled the time of expulsion and gross geometry of migration paths: a) a southern package of Early Cretaceous and older rocks structurally-thickened by early Brooks Range thrusting; b) a western package of Early Cretaceous rocks that filled the western part of the foreland basin; c) an eastern package of Late Cretaceous and Paleogene rocks that filled the eastern part of the foreland basin; and d) an offshore deltaic package of Neogene rocks deposited by the Colville, Canning, and Mackenzie rivers. This petroleum system poster is part of a series of Northern Alaska posters on modeling. The poster in this session by Saltus and Bird present gridded maps for the greater Northern Alaskan onshore and offshore that are used in the 3D modeling poster by Lampe and others. Posters on source rock units are by Keller and Bird as well as Peters and others. Sandstone and shale compaction properties used in sedimentary basin modeling are covered in a poster by Rowan and others. The results of this modeling exercise will be used in our next Northern Alaska oil and gas resource assessment.

Bedrock geology and mineral resources of the Knoxville 1°x2° quadrangle, Tennessee, North Carolina, and South Carolina

USGS Publications Warehouse

Robinson, Gilpin R.; Lesure, Frank G.; Marlowe, J.I.; Foley, Nora K.; Clark, S.H.

1992-01-01

Vermiculite produced from a large deposit near Tigerville, S.C., in the Inner Piedmont. Deposit worked out and mine backfilled. Smaller deposits associated with ultramafic rocks in the east flank of the Blue Ridge are now uneconomic and have not been worked in the past 20 years. C. Metals: Copper in three deposits, the Fontana and Hazel Creek mines in the Great Smoky Mountains National Park in the Central Blue Ridge, and the Cullowhee mine in the east flank of the Blue Ridge. D. Organic fuels:  The rocks of the quadrangle contain no coal and probably lie outside the maximum range in thermal maturity permitting the survival of oil. The rocks in the Valley and Ridge and for a short distance eastward below the west flank of the Blue Ridge probably lie within a zone of thermal maturity permitting the survival of natural gas. Consequently the western part of the quadrangle is an area of high risk for hydrocarbon exploration. No exploration drilling has been done in this belt. 

Miniregoliths. I - Dusty lunar rocks and lunar soil layers

NASA Technical Reports Server (NTRS)

Comstock, G. M.

1978-01-01

A detailed Monte-Carlo model for rock surface evolution shows that erosion processes alone cannot account for the shapes of the solar flare particle track profiles generally observed at depths of about 100 microns and less in rocks. The observed profiles are easily explained by a steady accumulation of fine dust at a rate of 0.3 to 3 mm per m.y., depending on the micrometeoroid impact rate which controls the dust cover and results in maximum dust thicknesses on the order of 100 microns to 1 mm. The commonly used lunar soil track parameters are derived in terms of parameters characterizing the exposure of soil grains in the few-millimeter-thick surface mixing and maturation zone which is one form of miniregolith. Correlation plots permit determining the degree of mixing in soil samples and the amount of processing (maturation) in surface miniregoliths. It is shown that the sampling process often artificially mixes together finer distinct layers, and that ancient miniregolith layers on the order of a millimeter thick are probably common in the lunar soil.

Petrogenesis of metamorphosed Paleoproterozoic, arc-related tonalites, granodiorites and coeval basic to intermediate rocks from southernmost Brazil, based on elemental and isotope geochemistry

NASA Astrophysics Data System (ADS)

Gregory, Tiago Rafael; Bitencourt, Maria de Fátima; Nardi, Lauro Valentim Stoll; Florisbal, Luana Moreira

2017-04-01

In southern Brazil, three associations of metamorphosed tonalites and granodiorites that are compositionally similar to tonalite-trondhjemite-granodiorite (TTG) or adakitic associations have been identified in the Arroio dos Ratos Complex (ARC) Paleoproterozoic magmatism. The metatonalites of Association 1 (A1; 2148 ± 33 Ma) have a well-developed fabric, compatible with strong solid-state deformation. The metatonalites and metagranodiorites of Association 2 (A2; 2150 ± 28 Ma) are intrusive in A1 and have a similar composition, but are less deformed, and their primary structures are partly preserved. Both associations display contemporaneity relations with basic to intermediate magmas. Association 3 (A3; 2077 ± 13 Ma) is represented by tonalitic to granodioritic gneisses, without any associated basic to intermediate magmatism, and its main characteristic is the banding that resulted from strong solid-state deformation. Partial melting features are locally present in A3. The geochemical compositions of the three associations are similar and indicate sources related to a continental magmatic arc environment. The 87Sr/86Sr(i) ratios (between 0.701 and 0.703), positive ƐNd(t) values (+ 1.45 to + 5.19), and TDM ages close to the crystallization ages indicate juvenile sources for the A1 and A2 associations. The A3 rocks have a 87Sr/86Sr(i) ratio of 0.715, an ƐNd(t) value of + 0.47 and a TDM age that is close to the crystallization age, indicating a source composition different from those of the other associations. The Pb isotope ratios of A1 and A2 are similar and compatible with the evolution of mantle and orogen (208Pb/204Pb = 37.3-37.6; 207Pb/204Pb = 15.62-15.65; 206Pb/204Pb = 18.0-18.2). The Pb isotope ratios of A3 differ from A1 and A2, indicating a more Th-poor source (208Pb/204Pb = 37.1; 207Pb/204Pb = 15.64; 206Pb/204Pb = 18.5). The geochemistry of associations A1 and A2 suggests a juvenile source with contamination by crustal material. However, the Sr-Nd-Pb isotope signature of this contaminant is similar to that of the source material that originated these associations. This may be the crust generated in the magmatic arc, which is compatible with the geochronological results. The dataset points to the occurrence of self-cannibalism processes in the generation of the ARC rocks. The similar chemical composition and ƐNd(t) values of A3 relative to A1 and A2 indicate that the A3 source is similar to the one that generated the tonalitic and granodioritic rocks of A1 and A2. However, the slightly lower 208Pb/204Pb, and higher 206Pb/204Pb and 87Sr/86Sr(i) ratios indicate that the A3 association has also the addition of a distinct crustal source. The A3 association high values of the parameter 87Sr/86Sr(i) and its Pb isotope signature indicate a source with high Rb and U, and low Th contents. Such features, and moreover the depletion of HREE combined with TDM values near the igneous age, suggest that the source for A3 may be juvenile arc sediments. The greater degree of crustal contribution, the lack of associated basic to intermediate rocks, and the younger age possibly mark the more mature or late stages of the arc. The major and trace elements, as well as the isotope data obtained in this study suggest that melting of a metasomatized mantle wedge can be the process that generated the ARC basic to intermediate rocks (A1 and A2). The generation of tonalitic and granodioritic rocks with adakitic characteristics (i.e., the depletion of heavy rare earth elements in tonalitic and granodioritic rocks of A1, A2 and A3) may have arisen from the melting of a garnet-rich source or from fractional crystallization of ARC basic to intermediate magmas, which in time increased crustal assimilation under high-pressure conditions. The crustal garnet-rich source could be the basic rocks newly placed at the base of the crust, derived from partial melting of metasomatized mantle. The remobilization of this material by partial melting may have generated tonalitic and granodioritic liquids depleted in heavy REE due to the presence of garnet in the residue. The three associations display microstructures that indicate two episodes of recrystallization, one of a higher temperature and one of a lower temperature. The age of the high-temperature structure remains under discussion and may be attributed to a Paleoproterozoic metamorphic event. The low-temperature event is compatible with the temperature conditions observed in adjacent areas, in the host rocks of the Neoproterozoic post-collisional granitoids that have been emplaced along the Southern Brazilian Shear Belt (SBSB). Zircon crystals with Paleoproterozoic igneous cores exhibit a metamorphic overgrowth at 635 ± 6 Ma, compatible with the crystallization ages of the SBSB granitoids.

The organic geochemical characterization: An indication of type of kerogen and maturity of early - Mid Jurassic shale in the Blue Nile formation

NASA Astrophysics Data System (ADS)

Shoieba, Monera Adam; Sum, Chow Weng; Abidin, Nor Syazwani Zainal; Bhattachary, Swapan Kumar

2018-06-01

The heterogeneity and complexity of shale gas has become clear as the development of unconventional resources have improved. The Blue Nile Basin, is one of the many Mesozoic rift basins in Sudan associated with the Central African Rift System (CARS). It is located in the eastern part of the Republic of Sudan and has been the major focus for shale gas exploration due to the hydrocarbon found in the basin. But so far no success of discovery has been achieved because the shale gas potentiality of the study area is still unknown. The objective of this study is to assess the type of kerogen and maturity of the shale samples from the Blue Nile Formation within the Blue Nile Basin. This was done by employing organic geochemical methods such as pyrolysis gas chromatography (Py-GC) and petrographic analysis such as vitrinite reflectance (Ro%). Ten representative shale samples from TW-1 well in the Blue Nile Formation have been used to assess the quality of the source rock. Pyrolysis GC analysis indicate that all the selected shale samples contain Type II kerogen that produces oil and gas. The Blue Nile Formation possesses vitrinite reflectance (Ro%) of 0.60-0.65%, indicating that the shale samples are mature in the oil window.

Preliminary thermal-maturity map of the Cameo and Fairfield or equivalent coal zone in the Piceance Creek Basin, Colorado

USGS Publications Warehouse

Nuccio, Vito F.; Johnson, Ronald C.

1983-01-01

This map was prepared in cooperation with the U.S. Department of Energy's Western Gas Sands Project and was constructed to show the thermal maturity of the Upper Cretaceous Mesaverde Formation (or Group) in the Piceance Creek Basin. The ability of a source rock to generate oil and gas is directly related to its kerogen content and thermal maturity; hence, thermal maturity is commonly used as an exploration tool. This publication consists of two parts: a coal rank map for the basinwide Cameo and Fairfield or equivalent coal zone and three cross sections showing the variation in a coal rank for the entire Mesaverde. Structure contours on the map show the top of the Rollins Sandstone Member of the Mesaverde Formation and its equivalent the Trout Creek Sandstone Member of the Iles Formation of the Mesaverde Group, which immediately underlie the Cameo and Fairfield zone. The structure contours show the fairly strong correlation between structure and coal rank in the basin, suggesting that maximum overburden was the key factor in determining the coal ranks. Even in the southern part of the basin where extensive plutonism occurred during the Oligocene, coal ranks still generally follow structure; indicating that the plutons had little affect on the coals. On the cross sections both the top of the Rollins and Trout Creek, and the top of the Mesaverde Formation/Group are shown. A complete analysis of the entire Mesaverde in the basin would require more information than is presently available.

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

Generation, migration, and entrapment of Precambrian oils in the Eastern Flank Heavy Oil province, south Oman

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

Konert, G.; Van Den Brink, H.A.; Visser, W.

1991-08-01

The prolific Eastern Flank Heavy Oil province east of the South Oman Salt basin is unique because of the widespread occurrence of Precambrian source rocks from which the hydrocarbons originated. Fission-track analysis and burial studies suggest that most of these source rocks became mature and generated hydrocarbons in the Ordovician; subsequently, the source beds were uplifted and did not re-enter the oil window. Its uniqueness is also based on the all-important role played by Precambrian salt. The traps in Palaeozoic clastics were initially structured by halokinesis, and subsequently by salt dissolution. The latter process gradually removed the salt from themore » area is largely responsible for the present-day structure with palaeo-withdrawal basins inverted in present-day turtles. Present-day traps are mainly post-Late Jurassic in age, significantly post-dating the time of oil generation. Detailed field studies indicate that charge phases appear to correlate with periods of increased salt dissolution in the Late Jurassic-Early Cretaceous, Late Cretaceous, and Tertiary. Oil was probably stored in intermediate traps below and within the salt. It was gradually released upon progressive tilting of the basin flank; it migrated updip toward the basinward retreating salt edge, and subsequently (back) spilled into the stratigraphically younger traps. Also, removal of the top seal of intra-salt and sub-salt traps by salt dissolution allowed upward remigration. It follows that charge concepts in the Eastern Flank Heavy Oil province depend on defining salt-edge-related hydrocarbon release areas, rather than on kitchen modeling.« less

ROCK1 and 2 differentially regulate actomyosin organization to drive cell and synaptic polarity

PubMed Central

Badoual, Mathilde; Asmussen, Hannelore; Patel, Heather; Whitmore, Leanna; Horwitz, Alan Rick

2015-01-01

RhoGTPases organize the actin cytoskeleton to generate diverse polarities, from front–back polarity in migrating cells to dendritic spine morphology in neurons. For example, RhoA through its effector kinase, RhoA kinase (ROCK), activates myosin II to form actomyosin filament bundles and large adhesions that locally inhibit and thereby polarize Rac1-driven actin polymerization to the protrusions of migratory fibroblasts and the head of dendritic spines. We have found that the two ROCK isoforms, ROCK1 and ROCK2, differentially regulate distinct molecular pathways downstream of RhoA, and their coordinated activities drive polarity in both cell migration and synapse formation. In particular, ROCK1 forms the stable actomyosin filament bundles that initiate front–back and dendritic spine polarity. In contrast, ROCK2 regulates contractile force and Rac1 activity at the leading edge of migratory cells and the spine head of neurons; it also specifically regulates cofilin-mediated actin remodeling that underlies the maturation of adhesions and the postsynaptic density of dendritic spines. PMID:26169356

Microbiology and geochemistry of hydrocarbon-rich sediments erupted from the deep geothermal Lusi site, Indonesia

NASA Astrophysics Data System (ADS)

Krüger, Martin; Straten, Nontje; Mazzini, Adriano; Scheeder, Georg; Blumenberg, Martin

2016-04-01

The Lusi eruption represents one of the largest ongoing sedimentary hosted geothermal systems, which started in 2006 following an earthquake on Java Island. Since then it has been producing hot and hydrocarbon rich mud from a central crater with peaks reaching 180.000 m3 per day. Numerous investigations focused on the study of offshore microbial colonies that commonly thrive at offshore methane and oil seeps and mud volcanoes, however very little has been done for onshore seeping structures. Lusi represents a unique opportunity to complete a comprehensive study of onshore microbial communities fed by the seepage of CH4 as well as of heavier liquid hydrocarbons originating from one or more km below the surface. While the source of the methane at Lusi is clear (Mazzini et al., 2012), the origin of the seeping oil, either form the deep mature Eocene Ngimbang (type II kerogen) or from the less mature Pleistocene Upper Kalibeng Fm. (type III kerogen), is still discussed. In the framework of the Lusi Lab project (ERC grant n° 308126) we analysed an oil film and found that carbon preference indices among n-alkanes, sterane and hopane isomers (C29-steranes: 20S/(20S+20R) and α,β-C32 Hopanes (S/(S+R), respectively) are indicative of a low thermal maturity of the oil source rock (~0.5 to 0.6 % vitrinite reflectance equivalents = early oil window maturity). Furthermore, sterane distributions, the pristane to phytane ratio and a relatively high oleanane index, which is an indication of an angiosperm input, demonstrate a strong terrestrial component in the organic matter. Together, hydrocarbons suggest that the source of the oil film is predominantly terrestrial organic matter. Both, source and maturity estimates from biomarkers, are in favor of a type III organic matter source and are therefore suggestive of a mostly Pleistocene Upper Kalibeng Fm. origin. We also conducted a sampling campaign at the Lusi site collecting samples of fresh mud close to the erupting crater, using a remotely controlled drone as well as older, weathered samples for comparison. In all samples large numbers of active microorganisms were present. Rates for aerobic methane oxidation were high, as was the potential of the microbial communities to degrade hydrocarbons (oils, alkanes, BTEX tested). The data suggests a transition of microbial populations from an anaerobic, hydrocarbon-driven metabolism in fresher samples from center or from small seeps to more generalistic, aerobic microbial communities in older, more consolidated sediments. Ongoing microbial activity in crater sediment samples under high temperatures (80-95C) indicate a deep origin of the involved microorganisms (deep biosphere). First results of molecular analyses of the microbial community compositions confirm the above findings. This study represents an initial step to better understand onshore seepage systems and provides an ideal analogue for comparison with the better investigated offshore structures.

Lithologic Controls on Critical Zone Processes in a Variably Metamorphosed Shale-Hosted Watershed

NASA Astrophysics Data System (ADS)

Eldam Pommer, R.; Navarre-Sitchler, A.

2017-12-01

Local and regional shifts in thermal maturity within sedimentary shale systems impart significant variation in chemical and physical rock properties, such as pore-network morphology, mineralogy, organic carbon content, and solute release potential. Even slight variations in these properties on a watershed scale can strongly impact surface and shallow subsurface processes that drive soil formation, landscape evolution, and bioavailability of nutrients. Our ability to map and quantify the effects of this heterogeneity on critical zone processes is hindered by the complex coupling of the multi-scale nature of rock properties, geochemical signatures, and hydrological processes. This study addresses each of these complexities by synthesizing chemical and physical characteristics of variably metamorphosed shales in order to link rock heterogeneity with modern earth surface and shallow subsurface processes. More than 80 samples of variably metamorphosed Mancos Shale were collected in the East River Valley, Colorado, a headwater catchment of the Upper Colorado River Basin. Chemical and physical analyses of the samples show that metamorphism decreases overall rock porosity, pore anisotropy, and surface area, and introduces unique chemical signatures. All of these changes result in lower overall solute release from the Mancos Shale in laboratory dissolution experiments and a change in rock-derived solute chemistry with decreasing organic carbon and cation exchange capacity (Ca, Na, Mg, and K). The increase in rock competency and decrease in reactivity of the more thermally mature shales appear to subsequently control river morphology, with lower channel sinuosity associated with areas of the catchment underlain by metamorphosed Mancos Shale. This work illustrates the formative role of the geologic template on critical zone processes and landscape development within and across watersheds.

Source rock potential in Pakistan

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

Raza, H.A.

1991-03-01

Pakistan contains two sedimentary basins: Indus in the east and Balochistan in the west. The Indus basin has received sediments from precambrian until Recent, albeit with breaks. It has been producing hydrocarbons since 1914 from three main producing regions, namely, the Potwar, Sulaisman, and Kirthar. In the Potwar, oil has been discovered in Cambrian, Permian, Jurassic, and Tertiary rocks. Potential source rocks are identified in Infra-Cambrian, Permian, Paleocene, and Eocene successions, but Paleocene/Eocene Patala Formation seems to be the main source of most of the oil. In the Sulaiman, gas has been found in Cretaceous and Tertiary; condensate in Cretaceousmore » rocks. Potential source rocks are indicated in Cretaceous, Paleocene, and Eocene successions. The Sembar Formation of Early Cretaceous age appears to be the source of gas. In the Kirthar, oil and gas have been discovered in Cretaceous and gas has been discovered in paleocene and Eocene rocks. Potential source rocks are identified in Kirthar and Ghazij formations of Eocene age in the western part. However, in the easter oil- and gas-producing Badin platform area, Union Texas has recognized the Sembar Formation of Early Cretaceous age as the only source of Cretaceous oil and gas. The Balochistan basin is part of an Early Tertiary arc-trench system. The basin is inadequately explored, and there is no oil or gas discovery so far. However, potential source rocks have been identified in Eocene, Oligocene, Miocene, and Pliocene successions based on geochemical analysis of surface samples. Mud volcanoes are present.« less

Geochemical characteristics and reservoir continuity of Silurian Acacus in Ghadames Basin, Southern Tunisia

NASA Astrophysics Data System (ADS)

Mahmoudi, S.; Mohamed, A. Belhaj; Saidi, M.; Rezgui, F.

2017-11-01

The present work is dealing with the study of lateral and vertical continuity of the multi-layers Acacus reservoir (Ghadames Basin-Southern Tunisia) using the distribution of hydrocarbon fraction. For this purpose, oil-oil and source rock-oil correlations as well as the composition of the light fractions and a number of saturate and aromatic biomarkers parameters, including C35/C34 hopanes and DBT/P, have been investigated. Based on the ratios of light fraction and their fingerprints, the Acacus reservoir from Well1 and Well2 have found to be laterally non-connected although the hydrocarbons they contain have the same source rock. Moreover, the two oil samples from two different Acacus reservoir layers crossed by Well3-A3 and A9, display a similar hydrocarbons distribution, suggesting vertical reservoir continuity. On the other hand, the biomarker distributions of the oils samples and source rocks assess a Silurian ;Hot shale; that is the source rock feeding the Acacus reservoir. The biomarker distribution is characterized by high tricyclic terpanes contents compared to hopanes for the Silurian source rock and the two crude oils. This result is also confirmed by the dendrogram that precludes the Devonian source rocks as a source rock in the study area.

Analysis of steranes and triterpanes in geolipid extracts by automatic classification of mass spectra

NASA Technical Reports Server (NTRS)

Wardroper, A. M. K.; Brooks, P. W.; Humberston, M. J.; Maxwell, J. R.

1977-01-01

A computer method is described for the automatic classification of triterpanes and steranes into gross structural type from their mass spectral characteristics. The method has been applied to the spectra obtained by gas-chromatographic/mass-spectroscopic analysis of two mixtures of standards and of hydrocarbon fractions isolated from Green River and Messel oil shales. Almost all of the steranes and triterpanes identified previously in both shales were classified, in addition to a number of new components. The results indicate that classification of such alkanes is possible with a laboratory computer system. The method has application to diagenesis and maturation studies as well as to oil/oil and oil/source rock correlations in which rapid screening of large numbers of samples is required.

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.

Terrestrial tight oil reservoir characteristics and Graded Resource Assessment in China

NASA Astrophysics Data System (ADS)

Wang, Shejiao; Wu, Xiaozhi; Guo, Giulin

2016-04-01

The success of shale/tight plays and the advanced exploitation technology applied in North America have triggered interest in exploring and exploiting tight oil in China. Due to the increased support of exploration and exploitation，great progress has been made in Erdos basin, Songliao basin, Junggar basin, Santanghu basin, Bohai Bay basin, Qaidam Basin, and Sichuan basin currently. China's first tight oil field has been found in Erdos basin in 2015, called xinanbian oil field, with over one hundred million tons oil reserves and one million tons of production scale. Several hundred million tons of tight oil reserve has been found in other basins, showing a great potential in China. Tight oil in China mainly developed in terrestrial sedimentary environment. According to the relations of source rock and reservoir, the source-reservoir combination of tight oil can be divided into three types, which are bottom generating and top storing tight oil,self- generating and self-storing tight oil，top generating and bottom storing tight oil. The self- generating and self-storing tight oil is the main type discovered at present. This type of tight oil has following characteristics:(1) The formation and distribution of tight oil are controlled by high quality source rocks. Terrestrial tight oil source rocks in China are mainly formed in the deep to half deep lacustrine facies. The lithology includes dark mudstone, shale, argillaceous limestone and dolomite. These source rocks with thickness between 20m-150m, kerogen type mostly I-II, and peak oil generation thermal maturity(Ro 0.6-1.4%), have great hydrocarbon generating potential. Most discovered tight oil is distributed in the area of TOC greater than 2 %.( 2) the reservoir with strong heterogeneity is very tight. In these low porosity and permeability reservoir,the resources distribution is controlled by the physical property. Tight sandstone, carbonate and hybrid sedimentary rocks are three main tight reservoir types in China. The porosity is 2-14%(average 5-10%)and the permeability is less than 1mD. The laboratory test and exploration practice confirmed that the oil content was positively related to physical property. The higher the porosity, the better the oil content will have. (3) Source rock and reservoir are superimposed. From the contact relationship of source rock and reservoir, the reservoir developed in the source rock has the advantage of capturing oil and gas, so the oil saturation can be as high as 70-80%. (4) The increased pressure caused by hydrocarbon generation and the connected fracture are the key factors for tight oil accumulation. The Fuyu tight oil formed underling source rock in Songliao Basin is a good example. The fracture system is the key factor for tight oil accumulation. Considering the strong heterogeneity of terrestrial tight oil reservoir in china, we create hierarchical resource abundance analogy, EUR analogy, cell element volumetric methods to evaluate tight oil resource potential. In order to find exploration "sweet spots", establishing tight oil resource classification evaluation standards are key steps to objectively evaluate tight oil resource distribution. The resource classification evaluation standards are established by the relationship analysis between reservoir properties and oil properties, and the correlation analysis between production, resource abundance, and reservoir thickness. The first-grade tight oil resource, which is recently available and can easily be developed, has following main parameters: the porosity is greater than 8%, thickness is over 10m, resource abundance is above 150,000 tons / km2, and pressure coefficient is greater than 1.3; The second-grade tight oil resource is currently unavailable, but with advanced technology can expected to be developed. The main parameters are as following: the porosity is 5% -8%, thickness is less than 5-10m, resource abundance is 50000-150000 tons / km2, the pressure coefficient is 1.0 to 1.3; The third-grade resource has poor quality, need long-term to be effective explored, has following main parameters: porosity is less than 5%, the thickness is less than 5m, resource abundance is less than 50,000 tons / km2, the pressure coefficient is less than 1.0. Using created resource evaluation methods, the tight oil resources has been calculated in china. The first-grade recoverable resource of tight oil is about 610 million tons. The second-grade recoverable resource is 450 million tons. And the third-grade recoverable resource is 400 million tons. The first-grade and second-grade recoverable resources are mainly distributed in the Ordos basin, Bohai Bay basin, Songliao basin, Junggar basin, and Qaidam Basin. The third-grade resources are mainly distributed in Sichuan and Santanghu basin.

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.

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.

Amorphous silica maturation in chemically weathered clastic sediments

NASA Astrophysics Data System (ADS)

Liesegang, Moritz; Milke, Ralf; Berthold, Christoph

2018-03-01

A detailed understanding of silica postdepositional transformation mechanisms is fundamental for its use as a palaeobiologic and palaeoenvironmental archive. Amorphous silica (opal-A) is an important biomineral, an alteration product of silicate rocks on the surface of Earth and Mars, and a precursor material for stable silica phases. During diagenesis, amorphous silica gradually and gradationally transforms to opal-CT, opal-C, and eventually quartz. Here we demonstrate the early-stage maturation of several million year old opal-A from deeply weathered Early Cretaceous and Ordovician sedimentary rocks of the Great Artesian Basin (central Australia). X-ray diffraction, scanning electron microscopy, and electron probe microanalyses show that the mineralogical maturation of the nanosphere material is decoupled from its chemical properties and begins significantly earlier than micromorphology suggests. Non-destructive and locally highly resolved X-ray microdiffraction (μ-XRD2) reveals an almost linear positive correlation between the main peak position (3.97 to 4.06 Å) and a new asymmetry parameter, AP. Heating experiments and calculated diffractograms indicate that nucleation and growth of tridymite-rich nanodomains induce systematic peak shifts and symmetry variations in diffraction patterns of morphologically juvenile opal-A. Our results show that the asymmetry parameter traces the early-stage maturation of amorphous silica, and that the mineralogical opal-A/CT stage extends to smaller d-spacings and larger FWHM values than previously suggested.

Metabasalts as sources of metals in orogenic gold deposits

NASA Astrophysics Data System (ADS)

Pitcairn, Iain K.; Craw, Dave; Teagle, Damon A. H.

2015-03-01

Although metabasaltic rocks have been suggested to be important source rocks for orogenic gold deposits, the mobility of Au and related elements (As, Sb, Se, and Hg) from these rocks during alteration and metamorphism is poorly constrained. We investigate the effects of increasing metamorphic grade on the concentrations of Au and related elements in a suite of metabasaltic rocks from the Otago and Alpine Schists, New Zealand. The metabasaltic rocks in the Otago and Alpine Schists are of MORB and WPB affinity and are interpreted to be fragments accreted from subducting oceanic crust. Gold concentrations are systematically lower in the higher metamorphic grade rocks. Average Au concentrations vary little between sub-greenschist (0.9 ± 0.5 ppb) and upper greenschist facies (1.0 ± 0.5 ppb), but decrease significantly in amphibolite facies samples (0.21 ± 0.07 ppb). The amount of Au depleted from metabasaltic rocks during metamorphism is on a similar scale to that removed from metasedimentary rocks in Otago. Arsenic concentrations increase with metamorphic grade with the metabasaltic rocks acting as a sink rather than a source of this element. The concentrations of Sb and Hg decrease between sub-greenschist and amphibolite facies but concentration in amphibolite facies rocks are similar to those in unaltered MORB protoliths and therefore unaltered oceanic crust cannot be a net source of Sb and Hg in a metamorphic environment. The concentrations of Au, As, Sb, and Hg in oceanic basalts that have become integrated into the metamorphic environment may be heavily influenced by the degree of seafloor alteration that occurred prior to metamorphism. We suggest that metasedimentary rocks are much more suitable source rocks for fluids and metals in orogenic gold deposits than metabasaltic rocks as they show mobility during metamorphism of all elements commonly enriched in this style of deposit.

Magnetic Susceptibility Measurements for in Situ Characterization of Lunar Soil

NASA Technical Reports Server (NTRS)

Oder, R. R.

1992-01-01

Magnetic separation is a viable method for concentration of components of lunar soils and rocks for use as feedstocks for manufacture of metals, oxygen, and for recovery of volatiles such as He-3. Work with lunar materials indicates that immature soils are the best candidates for magnetic beneficiation. The magnetic susceptibility at which selected soil components such as anorthite, ilmenite, or metallic iron are separated is not affected by soil maturity, but the recovery of the concentrated components is. Increasing soil maturity lowers recovery. Mature soils contain significant amounts of glass-encased metallic iron. Magnetic susceptibility, which is sensitive to metallic iron content, can be used to measure soil maturity. The relationship between the ratio of magnetic susceptibility and iron oxide and the conventional maturity parameter, I(sub s)/FeO, ferromagnetic resonant intensity divided by iron oxide content is given. The magnetic susceptibilities were determined using apparatus designed for magnetic separation of the lunar soils.

Marine and nonmarine gas-bearing rocks in Upper Cretaceous Blackhawk and Neslen Formations, eastern Uinta Basin, Utah: sedimentology, diagenesis, and source rock potential

USGS Publications Warehouse

Pitman, Janet K.; Franczyk, K.J.; Anders, D.E.

1987-01-01

Thermogenic gas was generated from interbedded humic-rich source rocks. The geometry and distribution of hydrocarbon source and reservoir rocks are controlled by depositional environment. The rate of hydrocarbon generation decreased from the late Miocene to the present, owing to widespread cooling that occurred in response to regional uplift and erosion associated with the development of the Colorado Plateau. -from Authors

Bedrock geology and mineral resources of the Knoxville 1° x 2° quadrangle, Tennessee, North Carolina, and South Carolina

USGS Publications Warehouse

Robinson, Gilpin R.; Lesure, Frank G.; Marlowe, J. I.; Foley, Nora K.; Clark, S.H.

2004-01-01

Vermiculite produced from a large deposit near Tigerville, S.C-, in the Inner Piedmont. Deposit worked out and mine backfilled. Smaller deposits associated with ultramafic rocks in the east flank of the Blue Ridge are now uneconomic and have not been worked in the past 20 years. C. Metals: Copper in three deposits, the Fontana and Hazel Creek mines in the Great Smoky Mountains Abstract Figure 1. Location of the Knoxville 1ºx2º quadrangle, with state and county boundaries National Park in the Central Blue Ridge, and the Cullowhee mine in the east flank of the Blue Ridge. D. Organic fuels: The rocks of the quadrangle contain no coal and probably lie outside the maximum range in thermal maturity permitting the survival of oil. The rocks in the Valley and Ridge and for a short distance eastward below the west flank of the Blue Ridge probably lie within a zone of thermal maturity permitting the survival of natural gas. Consequently the western part of the quadrangle is an area of high risk for hydrocarbon exploration. No exploration drilling has been done in this belt.

Overview of the potential and identified petroleum source rocks of the Appalachian basin, eastern United States: Chapter G.13 in Coal and petroleum resources in the Appalachian basin: distribution, geologic framework, and geochemical character

USGS Publications Warehouse

Coleman, James L.; Ryder, Robert T.; Milici, Robert C.; Brown, Stephen; Ruppert, Leslie F.; Ryder, Robert T.

2014-01-01

The Appalachian basin is the oldest and longest producing commercially viable petroleum-producing basin in the United States. Source rocks for reservoirs within the basin are located throughout the entire stratigraphic succession and extend geographically over much of the foreland basin and fold-and-thrust belt that make up the Appalachian basin. Major source rock intervals occur in Ordovician, Devonian, and Pennsylvanian strata with minor source rock intervals present in Cambrian, Silurian, and Mississippian strata.

Geochemical imprint of depositional conditions on organic matter in laminated-Bioturbated interbeds from fine-grained marine sequences

USGS Publications Warehouse

Pratt, L.M.; Claypool, G.E.; King, J.D.

1986-01-01

Laminated organic-rich shales are interbedded at a scale of centimeters to a few meters with bioturbated organic-poor mudstones or limestones in some fine-grained marine sequences. We have analyzed the organic matter in pairs of laminated/bioturbated interbeds from Cretaceous and Devonian rocks deposited in epicontinental and oceanic settings for the purpose of studying the influence of depositional and early diagenetic environment on the organic geochemical properties of marine shales. Results of these analyses indicate that for rocks that are still in a diagenetic stage of thermal alteration, the relative abundance of biomarker compounds and specific biomarker indices can be useful indicators of depositional and early diagenetic conditions. Pristane/phytane ratios are generally highest for laminated rocks from epicontinental basins and appear to reflect the input of isoprenoid precursors more than oxygenated versus anoxic depositional conditions. The thermally immature laminated rocks are characterized by relatively high contents of 17??(H), 21??(H)-hopanes, hopenes, sterenes and diasterenes, and by strong predominance of the 22R over 22S homohopane isomers. Thermally immature bioturbated samples are characterized by absence of the ??,??-hopanes, by low contents of both saturated and unsaturated polycyclic hydrocarbons, and by slight or no predominance of the 22R over 22S homohopane isomers. There are less obvious compositional differences between the saturated hydrocarbons in the laminated and bioturbated units from the thermally mature sequences. For both the thermally mature and immature laminated samples, the degree of isomerization at the 22C position for hopanes and at the 20C position for steranes is generally consistent with the degree of thermal maturity interpreted from other properties of the organic matter. The bioturbated samples, however, exhibit inconsistent and anomalously high degrees of isomerization for the homohopanes, resulting either from reworking and oxidation of the primary organic matter or from the presence of older recycled organic matter. ?? 1986.

Geochemical characterization of the Jurassic Amran deposits from Sharab area (SW Yemen): Origin of organic matter, paleoenvironmental and paleoclimate conditions during deposition

NASA Astrophysics Data System (ADS)

Hakimi, Mohammed Hail; Abdullah, Wan Hasiah; Makeen, Yousif M.; Saeed, Shadi A.; Al-Hakame, Hitham; Al-Moliki, Tareq; Al-Sharabi, Kholah Qaid; Hatem, Baleid Ali

2017-05-01

Calcareous shales and black limestones of the Jurassic Amran Group, located in the Sharab area (SW Yemen), were analysed based on organic and inorganic geochemical methods. The results of this study were used to reconstruct the paleoenvironmental and paleoclimatic conditions during Jurassic time and their relevance to organic matter enrichment during deposition of the Amran calcareous shale and black limestone deposits. The analysed Amran samples have present-day TOC and Stotal content values in the range of 0.25-0.91 wt % and 0.59-4.96 wt %, respectively. The relationship between Stotal and TOC contents indicates that the Jurassic Amran deposits were deposited in a marine environment as supported by biomarker environmental indicators. Biomarker distributions also reflect that the analysed Amran deposits received high contributions of marine organic matter (e.g., algal and microbial) with minor amount of land plant source inputs. Low oxygen (reducing) conditions during deposition of the Jurassic Amran deposits are indicated from low Pr/Ph values and relatively high elemental ratios of V/Ni and V/(V + Ni). Enrichment in the pyrite grains and very high DOPT and high Fe/Al ratios further suggest reducing bottom waters. This paleo-redox (i.e., reducing) conditions contributed to preservation of organic matter during deposition of the Jurassic Amran deposits. Semi-arid to warm climatic conditions are also evidenced during deposition of the Amran sediments and consequently increased biological productivity within the photic zone of the water column during deposition. Therefore, the increased bio-productivity in combination with good preservation of organic matter identified as the major mechanisms that gave rise to organic matter enrichment. This contradicts with the low organic matter content of the present-day TOC values of less than 1%. The biomarker maturity data indicate that the analysed Amran samples are of high thermal maturity; therefore, the low present-day TOC is attributed to the thermal effect on the original organic matter. This high thermal maturity level is due to the presence of volcanic rocks, which have invaded the Jurassic rocks during Late Oligocene to Early Miocene.

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

Geologic framework for the assessment of undiscovered oil and gas resources in sandstone reservoirs of the Upper Jurassic-Lower Cretaceous Cotton Valley Group, U.S. Gulf of Mexico region

USGS Publications Warehouse

Eoff, Jennifer D.; Dubiel, Russell F.; Pearson, Ofori N.; Whidden, Katherine J.

2015-01-01

The Cotton Valley Group extends in the subsurface from southern Texas to the Florida Panhandle in an arcuate belt that crosses northern Louisiana, the southern part of Arkansas, and southern Mississippi and Alabama. Three of the AUs are quantitatively assessed for undiscovered volumes of hydrocarbons in conventional accumulations. The Cotton Valley Updip Oil AU includes areas between the maximum updip limit of the Cotton Valley Group and a curved belt of regional faults (included in the Peripheral Fault System AU). Hydrocarbon charge to this AU remains uncertain. The Peripheral Fault System Oil and Gas AU includes the Mexia, Talco, State Line, South Arkansas, Pickens, Gilbertown, and other fault segments, which trapped early oil that migrated from source rocks within the Smackover Formation. Hydrocarbons in the Downdip Oil and Gas AU are primarily associated with low-amplitude salt-related features in the East Texas, North Louisiana, and Mississippi salt basins. The Tight Sandstone Gas AU contains gas-charged sandstones previously referred to collectively as “massive.” Their reservoir properties are consistent with the USGS’s definition of continuous reservoirs, and their resources, therefore, are assessed using a separate methodology. Optimal coincidence of low-permeability sandstone, gas-mature source rocks, and complex structures of the regional Sabine feature encouraged development of a general “sweet spot” area in eastern Texas.

Integration of channel and floodplain suites. I. Developmental sequence and lateral relations of alluvial paleosols.

USGS Publications Warehouse

Bown, T.M.; Kraus, M.J.

1987-01-01

The lower Eocene Willwood Formation of the Bighorn Basin, northwest Wyoming, consists of about 770 m of alluvial rocks that exhibit extensive mechanical and geochemical modifications resulting from Eocene pedogenesis. Five arbitrary stages are proposed to distinguish these soils of different maturities in the Willwood Formation. An inverse relationship exists between soil maturity and short-term sediment accumulation rate. Illustrates several important principles of soil-sediment interrelationships in aggrading alluvial systems that have broad application to other deposits.-from Authors

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

Thermal maturity of northern Appalachian Basin Devonian shales: Insights from sterane and terpane biomarkers

USGS Publications Warehouse

Hackley, Paul C.; Ryder, Robert T.; Trippi, Michael H.; Alimi, Hossein

2013-01-01

To better estimate thermal maturity of Devonian shales in the northern Appalachian Basin, eleven samples of Marcellus and Huron Shale were characterized via multiple analytical techniques. Vitrinite reflectance, Rock–Eval pyrolysis, gas chromatography (GC) of whole rock extracts, and GC–mass spectrometry (GCMS) of extract saturate fractions were evaluated on three transects that lie across previously documented regional thermal maturity isolines. Results from vitrinite reflectance suggest that most samples are immature with respect to hydrocarbon generation. However, bulk geochemical data and sterane and terpane biomarker ratios from GCMS suggest that almost all samples are in the oil window. This observation is consistent with the presence of thermogenic gas in the study area and higher vitrinite reflectance values recorded from overlying Pennsylvanian coals. These results suggest that vitrinite reflectance is a poor predictor of thermal maturity in early mature areas of Devonian shale, perhaps because reported measurements often include determinations of solid bitumen reflectance. Vitrinite reflectance interpretations in areas of early mature Devonian shale should be supplanted by evaluation of thermal maturity information from biomarker ratios and bulk geochemical data.

Sr-Nd-Hf Isotopic Analysis of <10 mg Dust Samples: Implications for Ice Core Dust Source Fingerprinting

NASA Astrophysics Data System (ADS)

Újvári, Gábor; Wegner, Wencke; Klötzli, Urs; Horschinegg, Monika; Hippler, Dorothee

2018-01-01

Combined Sr-Nd-Hf isotopic data of two reference materials (AGV-1/BCR2) and 50, 10, and 5 mg aliquots of carbonate-free fine grain (<10 μm) separates of three loess samples (Central Europe/NUS, China/BEI, USA/JUD) are presented. Good agreement between measured and reference Sr-Nd-Hf isotopic compositions (ICs) demonstrate that robust isotopic ratios can be obtained from 5 to 10 mg size rock samples using the ion exchange/mass spectrometry techniques applied. While 87Sr/86Sr ratios of dust aluminosilicate fractions are affected by even small changes in pretreatments, Nd isotopic ratios are found to be insensitive to acid leaching, grain-size or weathering effects. However, the Nd isotopic tracer is sometimes inconclusive in dust source fingerprinting (BEI and NUS both close to ɛNd(0) -10). Hafnium isotopic values (<10 μm fractions) are homogenous for NUS, while highly variable for BEI. This heterogeneity and vertical arrays of Hf isotopic data suggest zircon depletion effects toward the clay fractions (<2 μm). Monte Carlo simulations demonstrate that the Hf IC of the dust <10 μm fraction is influenced by both the abundance of zircons present and maturity of crustal rocks supplying this heavy mineral, while the <2 μm fraction is almost unaffected. Thus, ɛHf(0) variations in the clay fraction are largely controlled by the Hf IC of clays/heavy minerals having high Lu/Hf and radiogenic 176Hf/177Hf IC. Future work should be focused on Hf IC of both the <10 and <2 μm fractions of dust from potential source areas to gain more insight into the origin of last glacial dust in Greenland ice cores.

Seismic Velocity and Elastic Properties of Plate Boundary Faults

NASA Astrophysics Data System (ADS)

Jeppson, Tamara N.

The elastic properties of fault zone rock at depth play a key role in rupture nucleation, propagation, and the magnitude of fault slip. Materials that lie within major plate boundary fault zones often have very different material properties than standard crustal rock values. In order to understand the mechanics of faulting at plate boundaries, we need to both measure these properties and understand how they govern the behavior of different types of faults. Mature fault zones tend to be identified in large-scale geophysical field studies as zones with low seismic velocity and/or electrical resistivity. These anomalous properties are related to two important mechanisms: (1) mechanical or diagenetic alteration of the rock materials and/or (2) pore fluid pressure and stress effects. However, in remotely-sensed and large-length-scale data it is difficult to determine which of these mechanisms are affecting the measured properties. The objective of this dissertation research is to characterize the seismic velocity and elastic properties of fault zone rocks at a range of scales, with a focus on understanding why the fault zone properties are different from those of the surrounding rock and the potential effects on earthquake rupture and fault slip. To do this I performed ultrasonic velocity experiments under elevated pressure conditions on drill core and outcrops samples from three plate boundary fault zones: the San Andreas Fault, California, USA; the Alpine Fault, South Island, New Zealand; and the Japan Trench megathrust, Japan. Additionally, I compared laboratory measurements to sonic log and large-scale seismic data to examine the scale-dependence of the measured properties. The results of this study provide the most comprehensive characterization of the seismic velocities and elastic properties of fault zone rocks currently available. My work shows that fault zone rocks at mature plate boundary faults tend to be significantly more compliant than surrounding crustal rocks and quantifies that relationship. The results of this study are particularly relevant to the interpretation of field-scale seismic datasets at major fault zones. Additionally, the results of this study provide constraints on elastic properties used in dynamic rupture models.

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.

Zircon U-Pb ages and Hf isotopic compositions indicate multiple sources for Grenvillian detrital zircon deposited in western Laurentia

NASA Astrophysics Data System (ADS)

Howard, Amanda L.; Farmer, G. Lang; Amato, Jeffrey M.; Fedo, Christopher M.

2015-12-01

Combined U-Pb ages and Hf isotopic data from 1.0 Ga to 1.3 Ga (Grenvillian) detrital zircon in Neoproterozoic and Cambrian siliciclastic sedimentary rocks in southwest North America, and from igneous zircon in potential Mesoproterozoic source rocks, are used to better assess the provenance of detrital zircon potentially transported across Laurentia in major river systems originating in the Grenville orogenic highlands. High-precision hafnium isotopic analyses of individual ∼1.1 Ga detrital zircon from Neoproterozoic siliciclastic sedimentary rocks in Sonora, northern Mexico, reveal that these zircons have low εHf (0) (-22 to -26) and were most likely derived from ∼1.1 Ga granitic rocks embedded in local Mojave Province Paleoproterozoic crust. In contrast, Grenvillian detrital zircons in Cambrian sedimentary rocks in Sonora, the Great Basin, and the Mojave Desert, have generally higher εHf (0) (-15 to -21) as demonstrated both by high precision solution-based, and by lower precision laser ablation, ICPMS data and were likely derived from more distal sources further to the east/southeast in Laurentia. Comparison to new and existing zircon U-Pb geochronology and Hf isotopic data from Grenvillian crystalline rocks from the Appalachian Mountains, central and west Texas, and from Paleoproterozoic terranes throughout southwest North America reveals that zircon in Cambrian sandstones need not entirely represent detritus transported across the continent from Grenville province rocks in the vicinity of the present-day southern Appalachian Mountains. Instead, these zircons could have been derived from more proximal, high εHf (0), ∼1.1 Ga, crystalline rocks such as those exposed today in the Llano Uplift in central Texas and in the Franklin Mountains of west Texas. Regardless of the exact source(s) of the Grenvillian detrital zircon, new and existing whole-rock Nd isotopic data from Neoproterozoic to Cambrian siliciclastic sedimentary rocks in the Mojave Desert demonstrate that the occurrences of higher εHf (0), Grenvillian detrital zircons are decoupled from the sources of the bulk of the sedimentary detritus in which the zircons are entrained. The Cambrian Wood Canyon Formation and the underlying ;off craton; Neoproterozoic Johnnie Formation and Stirling Quartzite all contain higher εHf (0), Grenvillian detrital zircon, in some cases as the dominant detrital zircon population. However, only portions of the Wood Canyon Formation have whole rock Nd isotopic compositions consistent with a bulk sediment source in ∼1.1 Ga sources rocks. Whole rock Nd isotopic compositions of the remaining portions of this unit, and all of the Johnnie Formation and Stirling Quartzite, require bulk sediment sources principally in Paleoproterozoic continental crust. We consider the observed decoupling in the sources of Grenvillian detrital zircon and bulk sediment in the Wood Canyon Formation and underlying siliciclastic sediments as a demonstration that detrital zircon U-Pb and Hf isotopic data alone can provide an incomplete picture of the source of sediments that comprise a given siliciclastic stratigraphic unit.

Geochemistry of approximately 1.9 Ga sedimentary rocks from northeastern Labrador, Canada

NASA Technical Reports Server (NTRS)

Hayashi, K. I.; Fujisawa, H.; Holland, H. D.; Ohmoto, H.

1997-01-01

Fifty-eight rock chips from fifteen samples of sedimentary rocks from the Ramah Group (approximately 1.9 Ga) in northeastern Labrador, Canada, were analyzed for major and minor elements, including C and S, to elucidate weathering processes on the Earth's surface about 1.9 Ga ago. The samples come from the Rowsell Harbour, Reddick Bight, and Nullataktok Formations. Two rock series, graywackes-gray shales of the Rowsell Harbour, Reddick Bight and Nullataktok Formations, and black shales of the Nullataktok Formation, are distinguishable on the basis of lithology, mineralogy, and major and trace element chemistry. The black shales show lower concentrations than the graywackes-gray shales in TiO2 (0.3-0.7 wt% vs. 0.7-1.8 wt%), Al2O3 (9.5-20.1 wt% vs. 13.0-25.0 wt%), and sigma Fe (<1 wt% vs. 3.8-13.9 wt% as FeO). Contents of Zr, Th, U, Nb, Ce, Y, Rb, Y, Co, and Ni are also lower in the black shales. The source rocks for the Ramah Group sediments were probably Archean gneisses with compositions similar to those in Labrador and western Greenland. The major element chemistry of source rocks for the Ramah Group sedimentary rocks was estimated from the Al2O3/TiO2 ratios of the sedimentary rocks and the relationship between the major element contents (e.g., SiO2 wt%) and Al2O3/TiO2 ratios of the Archean gneisses. This approach is justified, because the Al/Ti ratios of shales generally retain their source rock values; however, the Zr/Al, Zr/Ti, and Cr/Ni ratios fractionate during the transport of sediments. The measured SiO2 contents of shales in the Ramah Group are generally higher than the estimated SiO2 contents of source rocks by approximately 5 wt%. This correction may also have to be applied when estimating average crustal compositions from shales. Two provenances were recognized for the Ramah Group sediments. Provenance I was comprised mostly of rocks of bimodal compositions, one with SiO2 contents approximately 45 wt% and the other approximately 65 wt%, and was the source for most sedimentary rocks of the Ramah Group, except for black shales of the Nullataktok Formation. The black shales were apparently derived from Provenance II that was comprised mostly of felsic rocks with SiO2 contents approximately 65 wt%. Comparing the compositions of the Ramah Group sedimentary rocks and their source rocks, we have recognized that several major elements, especially Ca and Mg, were lost almost entirely from the source rocks during weathering and sedimentation. Sodium and potassium were also leached almost entirely during the weathering of the source rocks. However, significant amounts of Na were added to the black shales and K to all the rock types during diagenesis and/or regional metamorphism. The intensity of weathering of source rocks for the Ramah Group sediments was much higher than that of typical Phanerozoic sediments, possibly because of a higher PCO2 in the Proterozoic atmosphere. Compared to the source rock values, the Fe3+/Ti ratios of many of the graywackes and gray shales of the Ramah Group are higher, the Fe2+/Ti ratios are lower, and the sigma Fe/Ti ratios are the same. Such characteristics of the Fe geochemistry indicate that these sedimentary rocks are comprised of soils formed by weathering of source rocks under an oxygen-rich atmosphere. The atmosphere about 1.9 Ga was, therefore, oxygen rich. Typical black shales of Phanerozoic age exhibit positive correlations between the organic C contents and the concentrations of S, U, and Mo, because these elements are enriched in oxygenated seawater and are removed from seawater by organic matter in sediments. However, such correlations are not found in the Ramah Group sediments. Black shales of the Ramah Group contain 1.7-2.8 wt% organic C, but are extremely depleted in sigma Fe (<1 wt% as FeO), S (<0.3 wt%), U (approximately l ppm), Mo (<5 ppm), Ni (<2 ppm), and Co (approximately 0 ppm). This lack of correlation, however, does not imply that the approximately 1.9 Ga atmosphere-ocean system was anoxic. Depletion of these elements from the Ramah Group sediments may have occurred during diagenesis.

Fluid evolution during burial and Variscan deformation in the Lower Devonian rocks of the High-Ardenne slate belt (Belgium): sources and causes of high-salinity and C-O-H-N fluids

NASA Astrophysics Data System (ADS)

Kenis, I.; Muchez, Ph.; Verhaert, G.; Boyce, A.; Sintubin, M.

2005-08-01

Fluid inclusions in quartz veins of the High-Ardenne slate belt have preserved remnants of prograde and retrograde metamorphic fluids. These fluids were examined by petrography, microthermometry and Raman analysis to define the chemical and spatial evolution of the fluids that circulated through the metamorphic area of the High-Ardenne slate belt. The earliest fluid type was a mixed aqueous/gaseous fluid (H2O-NaCl-CO2-(CH4-N2)) occurring in growth zones and as isolated fluid inclusions in both the epizonal and anchizonal part of the metamorphic area. In the central part of the metamorphic area (epizone), in addition to this mixed aqueous/gaseous fluid, primary and isolated fluid inclusions are also filled with a purely gaseous fluid (CO2-N2-CH4). During the Variscan orogeny, the chemical composition of gaseous fluids circulating through the Lower Devonian rocks in the epizonal part of the slate belt, evolved from an earlier CO2-CH4-N2 composition to a later composition enriched in N2. Finally, a late, Variscan aqueous fluid system with a H2O-NaCl composition migrated through the Lower Devonian rocks. This latest type of fluid can be observed in and outside the epizonal metamorphic part of the High-Ardenne slate belt. The chemical composition of the fluids throughout the metamorphic area, shows a direct correlation with the metamorphic grade of the host rock. In general, the proportion of non-polar species (i.e. CO2, CH4, N2) with respect to water and the proportion of non-polar species other than CO2 increase with increasing metamorphic grade within the slate belt. In addition to this spatial evolution of the fluids, the temporal evolution of the gaseous fluids is indicative for a gradual maturation due to metamorphism in the central part of the basin. In addition to the maturity of the metamorphic fluids, the salinity of the aqueous fluids also shows a link with the metamorphic grade of the host-rock. For the earliest and latest fluid inclusions in the anchizonal part of the High-Ardenne slate belt the salinity varies respectively between 0 and 3.5 eq.wt% NaCl and between 0 and 2.7 eq.wt% NaCl, while in the epizonal part the salinity varies between 0.6 and 17 eq.wt% NaCl and between 3 and 10.6 eq.wt% for the earliest and latest aqueous fluid inclusions, respectively. Although high salinity fluids are often attributed to the original sedimentary setting, the increasing salinity of the fluids that circulated through the Lower Devonian rocks in the High-Ardenne slate belt can be directly attributed to regional metamorphism. More specifically the salinity of the primary fluid inclusions is related to hydrolysis reactions of Cl-bearing minerals during prograde metamorphism, while the salinity of the secondary fluid inclusions is rather related to hydration reactions during retrograde metamorphism. The temporal and spatial distribution of the fluids in the High-Ardenne slate belt are indicative for a closed fluid flow system present in the Lower Devonian rocks during burial and Variscan deformation, where fluids were in thermal and chemical equilibrium with the host rock. Such a closed fluid flow system is confirmed by stable isotope study of the veins and their adjacent host rock for which uniform δ180 values of both the veins and their host rock demonstrate a rock-buffered fluid flow system.

Zircon U-Pb ages and petrogenesis of a tonalite-trondhjemite-granodiorite (TTG) complex in the northern Sanandaj-Sirjan zone, northwest Iran: Evidence for Late Jurassic arc-continent collision

NASA Astrophysics Data System (ADS)

Azizi, Hossein; Zanjefili-Beiranvand, Mina; Asahara, Yoshihiro

2015-02-01

The Ghalaylan Igneous Complex is located in the northern part of the Sanandaj-Sirjan zone (SSZ) in northwest Iran. At the surface, the complex is ellipsoidal or ring-shaped. The igneous rocks, which are medium- to fine-grained, were intruded into a Jurassic metamorphic complex and are cut by younger dikes. Zircon U-Pb ages indicate that the crystallization of the main body occurred from 157.9 ± 1.6 to 155.6 ± 5.6 Ma. The igneous complex includes granodiorite, tonalite, and quartz monzonite, as well as subvolcanic to volcanic rocks such as dacite and rhyolite. The rocks have high concentrations of Al2O3 (15-19 wt.%), SiO2 (65-70 wt.%), and Sr (700-1100 ppm), high (La/Yb)N ratios (15-40), and very low concentrations of MgO (< 0.83 wt.%), Ni (< 7 ppm), and Cr (usually < 50 ppm). There is a lack of negative Eu anomalies. These geochemical features show that the rocks are similar to high-silica adakites and Archaean tonalite-trondhjemite-granodiorite (TTG) rocks. The initial ratios of 87Sr/86Sr and 143Nd/144Nd vary from 0.70430 to 0.70476 and from 0.51240 to 0.51261, respectively, values that are similar to those of primitive mantle and the bulk Earth. The chemical compositions of the igneous rocks of the complex, and their isotope ratios, differ from those of neighboring granitic bodies in the northern SSZ. Based on our results, we suggest a new geodynamic model for the development of this complex, as follows. During the generation of the Songhor-Ghorveh island arc in the Neotethys Ocean, an extensional basin, such as a back-arc, developed between the island arc and the Sanandaj-Sirjan zone (SSZ). As a consequence, basaltic magma was injected from the asthenosphere without the development of a mature oceanic crust. During arc-continent collision in the Late Jurassic, hot basaltic rocks were present beneath the SSZ at depths of 30-50 km, and the partial melting of these rocks led to the development of TTG-type magmas, forming the source of the Ghalaylan Igneous Complex.

Preliminary results of thermal conductivity and elastic wave velocity measurements of various rock samples collected from outcrops in hanging wall of the Alpine Fault

NASA Astrophysics Data System (ADS)

Lin, W.; Tadai, O.; Shigematsu, N.; Nishikawa, O.; Mori, H.; Townend, J.; Capova, L.; Saito, S.; Kinoshita, M.

2015-12-01

The Alpine Fault is a mature active fault zone likely to rupture in the near future and DFDP aims to measure physical and chemical conditions within the fault. DFDP-2B borehole was drilled into hanging wall of the Alpine Fault. Downhole temperature measurements carried out in DFDP-2B borehole showed that the geothermal gradient in the hanging wall of the fault is very high, likely reaching to 130-150 °C/km (Sutherland et al., 2015 AGU Fall Meeting). To explain this abnormal feature, the determination of thermal properties of all the rock types in the hanging wall of the Alpine Fault is essential. To measure thermal properties and elastic wave velocities, we collected six typical rock block samples from outcrops in Stony creek and Gaunt creek. These include ultramylonite, mylonite, muscovite schist, garnet amphibolite, protomylonite and schist, which are representative of the hanging wall of the Alpine Fault. Their wet bulk densities are 2.7 - 2.8 g/cm3, and porosities are 1.4 - 3.0%. We prepared a pair of 4 cm cube specimens of each rock type with one flat plane parallel to the foliation. First, we measured thermal conductivity by the transient plane heat source (hot disc) method in a bulk mode, i.e. to deal with the rock as an isotropic material. However, several samples have clearly visible foliation and are likely to be anisotropic. Thus, the data measured in bulk mode provided an average value of the rocks in the range of approximately 2.4 - 3.2 W/mK. The next step will be to measure thermal conductivity in an anisotropic mode. We also measured P wave velocity (Vp) using the same samples, but in two directions, i.e. parallel and perpendicular to the foliation, respectively. Our preliminary results suggested that Vp is anisotropic in all the six rocks. Generally, Vp parallel to foliation is higher than that in the perpendicular direction. Vp in the parallel direction ranged in 5.5 - 6.0 km/s, whereas in the perpendicular direction it was 4.4 - 5.5 km/s. We thank the PIs and onsite staffs of the DFDP-2 project for their helps to collecting rock samples, and the financial support by JSPS (Japan-New Zealand Joint Research Program).

Effects of structural heterogeneity on frictional heating from biomarker thermal maturity analysis of the Muddy Mountain thrust, Nevada, USA

NASA Astrophysics Data System (ADS)

Coffey, G. L.; Savage, H. M.; Polissar, P. J.; Rowe, C. D.

2017-12-01

Faults are generally heterogeneous along-strike, with changes in thickness and structural complexity that should influence coseismic slip. However, observational limitations (e.g. limited outcrop or borehole samples) can obscure this complexity. Here we investigate the heterogeneity of frictional heating determined from biomarker thermal maturity and microstructural observations along a well-exposed fault to understand whether coseismic stress and frictional heating are related to structural complexity. We focus on the Muddy Mountain thrust, Nevada, a Sevier-age structure that has continuous exposure of its fault core and considerable structural variability for up to 50 m, to explore the distribution of earthquake slip and temperature rise along strike. We present new biomarker thermal maturity results that capture the heating history of fault rocks. Biomarkers are organic molecules produced by living organisms and preserved in the rock record. During heating, their structure is altered systematically with increasing time and temperature. Preliminary results show significant variability in thermal maturity along-strike at the Muddy Mountain thrust, suggesting differences in coseismic temperature rise on the meter- scale. Temperatures upwards of 500°C were generated in the principal slip zone at some locations, while in others, no significant temperature rise occurred. These results demonstrate that stress or slip heterogeneity occurred along the Muddy Mountain thrust at the meter-scale and considerable along-strike complexity existed, highlighting the importance of careful interpretation of whole-fault behavior from observations at a single point on a fault.

Microporoelastic Modeling of Organic-Rich Shales

NASA Astrophysics Data System (ADS)

Khosh Sokhan Monfared, S.; Abedi, S.; Ulm, F. J.

2014-12-01

Organic-rich shale is an extremely complex, naturally occurring geo-composite. The heterogeneous nature of organic-rich shale and its anisotropic behavior pose grand challenges for characterization, modeling and engineering design The intricacy of organic-rich shale, in the context of its mechanical and poromechanical properties, originates in the presence of organic/inorganic constituents and their interfaces as well as the occurrence of porosity and elastic anisotropy, at multiple length scales. To capture the contributing mechanisms, of 1st order, responsible for organic-rich shale complex behavior, we introduce an original approach for micromechanical modeling of organic-rich shales which accounts for the effect of maturity of organics on the overall elasticity through morphology considerations. This morphology contribution is captured by means of an effective media theory that bridges the gap between immature and mature systems through the choice of system's microtexture; namely a matrix-inclusion morphology (Mori-Tanaka) for immature systems and a polycrystal/granular morphology for mature systems. Also, we show that interfaces play a role on the effective elasticity of mature, organic-rich shales. The models are calibrated by means of ultrasonic pulse velocity measurements of elastic properties and validated by means of nanoindentation results. Sensitivity analyses using Spearman's Partial Rank Correlation Coefficient shows the importance of porosity and Total Organic Carbon (TOC) as key input parameters for accurate model predictions. These modeling developments pave the way to reach a "unique" set of clay properties and highlight the importance of depositional environment, burial and diagenetic processes on overall mechanical and poromechanical behavior of organic-rich shale. These developments also emphasize the importance of understanding and modeling clay elasticity and organic maturity on the overall rock behavior which is of critical importance for a practical rock physics model that accounts for time dependent phenomena which can be employed for seismic inversion.

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

Duration of mineralization and fluid-flow history of the Upper Mississippi Valley zinc-lead district

USGS Publications Warehouse

Rowan, E.L.; Goldhaber, M.B.

1995-01-01

Studies of fluid inclusions in sphalerite and biomarkers from the Upper Mississippi Valley zinc district show homogenization temperatures to be primarily between 90 and 150??C, yet show relatively low levels of thermal maturity. Numerical calculations are used to simulate fluid and heat flow through fracture-controlled ore zones and heat transfer to the adjacent rocks. Combining a best-fit path through fluid-inclusion data with measured thermal alteration of biomarkers, the time interval during which mineralizing fluids circulated through the Upper Mississippi Valley district was calculated to be on the order of 200 ka. Cambrian and Ordovician aquifers underlying the district, principally the St. Peter and Mt. Simon Sandstones, were the source of the mineralizing fluid. The duration of mineralization thus reflects the fluid-flow history of these regional aquifers. -from Authors

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.

Molecular marker and stable carbon isotope analyses of carbonaceous Ambassador uranium ores of Mulga Rock in Western Australia

NASA Astrophysics Data System (ADS)

Jaraula, C.; Schwark, L.; Moreau, X.; Grice, K.; Bagas, L.

2013-12-01

Mulga Rock is a multi-element deposit containing uranium hosted by Eocene peats and lignites deposited in inset valleys incised into Permian rocks of the Gunbarrel Basin and Precambrian rocks of the Yilgarn Craton and Albany-Fraser Orogen. Uranium readily adsorbs onto minerals or phytoclasts to form organo-uranyl complexes. This is important in pre-concentrating uranium in this relatively young ore deposit with rare uraninite [UO2] and coffinite [U(SiO4)1-x(OH)4x], more commonly amorphous and sub-micron uranium-bearing particulates. Organic geochemical and compound-specific stable carbon isotope analyses were conducted to identify possible associations of molecular markers with uranium accumulation and to recognize effect(s) of ionizing radiation on molecular markers. Samples were collected from the Ambassador deposit containing low (<200 ppm) to high (>2000 ppm) uranium concentrations. The bulk rock C/N ratios of 82 to 153, Rock-Eval pyrolysis yields of 316 to 577 mg hydrocarbon/g TOC (Hydrogen Index, HI) and 70 to 102 mg CO2/g TOC (Oxygen Index, OI) are consistent with a terrigenous and predominantly vascular plant OM source deposited in a complex shallow water system, ranging from lacustrine to deltaic, swampy wetland and even shallow lake settings as proposed by previous workers. Organic solvent extracts were separated into saturated hydrocarbon, aromatic hydrocarbon, ketone, and a combined free fatty acid and alcohol fraction. The molecular profiles appear to vary with uranium concentration. In samples with relatively low uranium concentrations, long-chain n-alkanes, alcohols and fatty acids derived from epicuticular plant waxes dominate. The n-alkane distributions (C27 to C31) reveal an odd/even preference (Carbon Preference Index, CPI=1.5) indicative of extant lipids. Average δ13C of -27 to -29 ‰ for long-chain n-alkanes is consistent with a predominant C3 plant source. Samples with relatively higher uranium concentrations contain mostly intermediate-length n-alkanes, ketones, alcohols, and fatty acids (C20 to C24) with no preferential distribution (CPI~1). Intermediate length n-alkanes have modest carbon isotope enrichment compared to long-chain n-alkanes. These shorter-chain hydrocarbons are interpreted to represent alteration products. The diversity and relative abundance of ketones in highly mineralised Mulga Rock peats and lignites are not consistent with aerobic and diagenetic degradation of terrigenous OM in oxic environments. Moreover, molecular changes cannot be associated with thermal breakdown due to the low maturity of the deposits. It is possible that the association of high uranium concentrations and potential radiolysis resulted in the oxidation of alcohol functional groups into aldehydes and ketones and breakdown of highly aliphatic macromolecules (i.e. spores, pollen, cuticles, and algal cysts). These phytoclasts are usually considered to be recalcitrant as they evolved to withstand chemical and physical degradation. Previous petrographic analyses show that spores, pollen and wood fragments are preferentially enriched in uranium. Their molecular compositions are feasible sources of short- to intermediate-length n-alkanes that dominate the mineralised peats and lignites.

Characterisation of DOC and its relation to the deep terrestrial biosphere

NASA Astrophysics Data System (ADS)

Vieth, Andrea; Vetter, Alexandra; Sachse, Anke; Horsfield, Brian

2010-05-01

The deep subsurface is populated by a large number of microorganisms playing a pivotal role in the carbon cycling. The question arises as to the origin of the potential carbon sources that support deep microbial communities and their possible interactions within the deep subsurface. As the carbon sources need to be dissolved in formation fluids to become available to microorganisms, the dissolved organic carbon (DOC) needs further characterisation as regards concentration, structural as well as molecular composition and origin. The Malm carbonates in the Molasse basin of southern Germany are of large economic potential as they are targets for both hydrocarbon and geothermal exploration (ANDREWS et al., 1987). Five locations that differ in their depth of the Malm aquifer between 220 m and 3445 m below surface have been selected for fluid sampling. The concentration and the isotopic composition of the DOC have been determined. To get a better insight into the structural composition of the DOC, we also applied size exclusion chromatography and quantified the amount of low molecular weight organic acids (LMWOA) by ion chromatography. With increasing depth of the aquifer the formation fluids show increasing salinity as chloride concentrations increase from 2 to 300 mg/l and also the composition of the DOC changes. Water samples from greater depth (>3000 m) showed that the DOC mainly consists of LMWOA (max. 83 %) and low percentages of neutral compounds (alcohols, aldehyde, ketones, amino acids) as well as "building blocks". Building blocks have been described to be the oxidation intermediates from humic substances to LMWOA. With decreasing depth of the aquifer, the DOC of the fluid becomes increasingly dominated by neutral compounds and the percentage of building blocks increases to around 27%. The fluid sample from 220 m depth still contains a small amount of humic substances. The DOC of formation fluids in some terrestrial sediments may originate from organic-rich layers like coals and source rocks which may provide carbon sources for the deep biosphere by leaching water soluble organic compounds. We investigated the potential of a series of Eocene-Pleistocene coals, mudstones and sandstones from New Zealand with different maturities (Ro between 0.29 and 0.39) and total organic carbon content (TOC) regarding their potential to release such compounds. The water extraction of these New Zealand coals using Soxhlet apparatus resulted in yields of LMWOA that may feed the local deep terrestrial biosphere over geological periods of time (VIETH et al., 2008). However, the DOC of the water extracts mainly consisted of humic substances. To investigate the effect of thermal maturity of the organic matter as well as the effect of the organic matter type on the extraction yields, we examined additional coal samples (Ro between 0.29 and 0.80) and source rock samples from low to medium maturity (Ro between 0.3 to 1.1). Within our presentation we would like to show the compositional diversity and variability of dissolved organic compounds in natural formation fluids as well as in water extracts from a series of very different lithologies and discuss their effects on the carbon cycling in the deep terrestrial subsurface. References: Andrews, J. N., Youngman, M. J., Goldbrunner, J. E., and Darling, W. G., 1987. The geochemistry of formation waters in the Molasse Basin of Upper Austria. Environmental Geology 10, 43-57. Vieth, A., Mangelsdorf, K., Sykes, R., and Horsfield, B., 2008. Water extraction of coals - potential to estimate low molecular weight organic acids as carbon feedstock for the deep terrestrial biosphere? Organic Geochemistry 39, 985-991.

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.

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.

Natural Offshore Oil Seepage and Related Tarball Accumulation on the California Coastline - Santa Barbara Channel and the Southern Santa Maria Basin: Source Identification and Inventory

USGS Publications Warehouse

Lorenson, T.D.; Hostettler, Frances D.; Rosenbauer, Robert J.; Peters, Kenneth E.; Dougherty, Jennifer A.; Kvenvolden, Keith A.; Gutmacher, Christina E.; Wong, Florence L.; Normark, William R.

2009-01-01

Oil spillage from natural sources is very common in the waters of southern California. Active oil extraction and shipping is occurring concurrently within the region and it is of great interest to resource managers to be able to distinguish between natural seepage and anthropogenic oil spillage. The major goal of this study was to establish the geologic setting, sources, and ultimate dispersal of natural oil seeps in the offshore southern Santa Maria Basin and Santa Barbara Basins. Our surveys focused on likely areas of hydrocarbon seepage that are known to occur between Point Arguello and Ventura, California. Our approach was to 1) document the locations and geochemically fingerprint natural seep oils or tar; 2) geochemically fingerprint coastal tar residues and potential tar sources in this region, both onshore and offshore; 3) establish chemical correlations between offshore active seeps and coastal residues thus linking seep sources to oil residues; 4) measure the rate of natural seepage of individual seeps and attempt to assess regional natural oil and gas seepage rates; and 5) interpret the petroleum system history for the natural seeps. To document the location of sub-sea oil seeps, we first looked into previous studies within and near our survey area. We measured the concentration of methane gas in the water column in areas of reported seepage and found numerous gas plumes and measured high concentrations of methane in the water column. The result of this work showed that the seeps were widely distributed between Point Conception east to the vicinity of Coal Oil Point, and that they by in large occur within the 3-mile limit of California State waters. Subsequent cruises used sidescan and high resolution seismic to map the seafloor, from just south of Point Arguello, east to near Gaviota, California. The results of the methane survey guided the exploration of the area west of Point Conception east to Gaviota using a combination of seismic instruments. The seafloor was mapped by sidescan sonar, and numerous lines of high -resolution seismic surveys were conducted over areas of interest. 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. These samples were used to construct a chemometric fingerprint (multivariate statistics) decision tree to classify 288 additional samples, including tarballs of unknown origin collected from Monterey and San Mateo County beaches after a storm in early 2007. A subset of 9 of 23 active offshore platform oils and one inactive platform oil representing a few oil reservoirs from the western Santa Barbara Channel were used in this analysis, and thus this model is not comprehensive and the findings are not conclusive. The platform oils included in this study are from west to east: Irene, Hildago, Harvest, Hermosa, Heritage, Harmony, Hondo, Holly, Platform A, and Hilda (now removed). 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. 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 intermediate traits, 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 Formation source rock favored generation from all thre

Detailed Aggregate Resources Study, Dry Lake Valley, Nevada.

DTIC Science & Technology

1981-05-29

LOCAL SAND SOURCES IGENERALLY CYLINDERS. DRYING SHRINKAGE I COLLECTED WITHIN A FEW MILES OF CORRESPONDING LEDGE-ROCK SOURCES) SUPPLIED FINE MENS...COMPRESSIVE AND TENSILE STh LEDGE-ROCK SOURCES SUPPLIED COARSE AGGREGATES; LOCAL SAND SOURCES IGENERALLY CYLINDERS. DRYING SHRINKAGE COLLECTED WITHIN A FEW

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 Chinese Cretaceous Continental Scientific Drilling Project in the Songliao Basin, NE China: Organic-rich source rock evaluation with geophysical logs from Borehole SK-2

NASA Astrophysics Data System (ADS)

Zhang, X.; Zou, C.

2017-12-01

The Cretaceous strata have been recognized as an important target of oil or gas exploration in the Songliao Basin, northeast China. The second borehole (SK-2) of the Chinese Cretaceous Continental Scientific Drilling Project in the Songliao Basin (CCSD-SK) is the first one to drill through the Cretaceous continental strata in the frame of ICDP. It was designed not only to solve multiple scientific problems (including the Cretaceous paleoenvironment and paleoclimate, as well as deep resources exploration of the Songliao Basin), but also to expect to achieve new breakthroughs in oil and gas exploration. Based on the project, various geophysical log data (including gamma, sonic, resistivity, density etc.) and core samples have been collected from Borehole SK-2. We do research on organic-rich source rocks estimation using various geophysical log data. Firstly, we comprehensively analyzed organic-rich source rocks' geophysical log response characteristics. Then, source rock's identification methods were constructed to identify organic-rich source rocks with geophysical logs. The main identification methods include cross-plot, multiple overlap and Decision Tree method. Finally, the technique and the CARBOLOG method were applied to evaluate total organic carbon (TOC) content from geophysical logs which provide continuous vertical profile estimations (Passey, 1990; Carpentier et al., 1991). The results show that source rocks are widely distributed in Borehole SK-2, over a large depth strata (985 5700m), including Nenjiang, Qingshankou, Denglouku, Yingcheng, Shahezi Formations. The organic-rich source rocks with higher TOC content occur in the Qingshankou (1647 1650m), Denglouku (2534 2887m) and Shahezi (3367 5697m) Formations. The highest TOC content in these formations can reach 10.31%, 6.58%, 12.79% respectively. The bed thickness of organic-rich source rocks in the these formations are totally up to 7.88m, 74.34m, 276.60m respectively. These organic-rich rocks in the Qingshankou, Denglouku and Shahezi Formations can be considered as excellent source rocks in the Songliao Basin, which are beneficial for oil or gas accumulation. This work was supported by the CCSD-SK of China Geological Survey (No. 12120113017600) and the National Natural Science Foundation Project (grant No.41274185).

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.

The evolution of Gondwana: U-Pb, Sm-Nd, Pb-Pb and geochemical data from Neoproterozoic to Early Palaeozoic successions of the Kango Inlier (Saldania Belt, South Africa)

NASA Astrophysics Data System (ADS)

Naidoo, Thanusha; Zimmermann, Udo; Chemale, Farid

2013-08-01

The provenance of Neoproterozoic to Early Palaeozoic rocks at the southern margin of the Kalahari craton reveals a depositional setting and evolution with a significant position in the formation of Gondwana. The sedimentary record shows a progression from immature, moderately altered rocks in the Ediacaran Cango Caves Group; to mature, strongly altered rocks in the Early Palaeozoic Kansa Group and overlying formations; culminating below very immature quartzarenites of Ordovician age. Petrographic and geochemical observations suggest the evolution of a small restricted basin with little recycling space towards a larger continental margin where substantial turbidite deposition is observed. For the southern Kalahari craton, a tectonic evolution comparable to supracrustal rocks in southern South America, Patagonia and Antarctica is supported by similarities in U-Pb ages of detrital zircons (Mesoproterozoic, Ediacaran and Ordovician grain populations); Sm-Nd isotopes (TDM: 1.2-1.8 Ga); and Pb-Pb isotopes. The maximum depositional age of the Huis Rivier Formation (upper Cango Caves Group) is determined at 644 Ma, but a younger age is still possible due to the limited zircon yield. The Cango Caves Group developed in a retro-arc foreland basin syntectonically to the Terra Australis Orogeny, which fringed Gondwana. The Kansa Group and overlying Schoemanspoort Formation are related to an active continental margin developed after the Terra Australis Orogen, with Patagonia being the ‘missing link’ between the Central South American arc and Antarctica during the Ordovician. This explains the occurrence of Ordovician detritus in these rocks, as a source rock of this age has not been discovered in South Africa. The absence of arc characteristics defines a position distal to the active continental margin, in a retro-arc foreland basin. The similarity of isotope proxies to major tectonic provinces in Antarctica and Patagonia, with those on the margins of the Kalahari craton, also points to a common geological evolution during the Mesoproterozoic and highlights the global relevance of this study.

Detrital rutile geochemistry and thermometry from the Dabie orogen: Implications for source-sediment links in a UHPM terrane

NASA Astrophysics Data System (ADS)

Liu, Lei; Xiao, Yilin; Wörner, G.; Kronz, A.; Simon, K.; Hou, Zhenhui

2014-08-01

This study explores the potential of detrital rutile geochemistry and thermometry as a provenance tracer in rocks from the Central Dabie ultrahigh-pressure metamorphic (UHPM) zone in east-central China that formed during Triassic continental collision. Trace element data of 176 detrital rutile grains selected from local river sediments and 91 rutile grains from distinct bedrocks in the Shuanghe and Bixiling areas, obtained by both electron microprobe (EMP) and in situ LA-ICP-MS analyses, suggest that geochemical compositions and thermometry of detrital rutiles are comparable to those from their potential source rocks. After certification of the Cr-Nb discrimination method for the Central Dabie UHPM zone, we show that 29% of the detrital rutiles in the Shuanghe area were derived from metamafic sources whereas in the Bixiling area that it is up to 76%. Furthermore, the proportion of distinct types of detrital rutiles combined with modal abundances of rutile in metapelites and metamafic bedrocks can be used to estimate the proportion of different source lithologies. Based on this method the proportion of mafic source rocks was estimated to ∼10% at Shuanghe and >60% at Bixiling, respectively, which is consistent with the proportions of eclogite (the major rutile-bearing metamafic rock) distribution in the field. Therefore, the investigation of detrital rutiles is a potential way to evaluate the proportion of metamafic rocks and even to prospect for metamafic bodies in UHPM terranes. Zr-in-rutile temperatures were calculated at different pressures and compared with temperatures derived from rock-in rutiles and garnet-clinopyroxene Fe-Mg thermometers. Temperatures calculated for detrital rutiles range from 606 °C to 707 °C and 566 °C to 752 °C in Shuanghe and Bixiling, respectively, at P = 3 GPa with an average temperatures of ca. 630 °C for both areas. These temperature averages and ranges are similar to those calculated for rutiles from surrounding source rocks. Combined with comparable Zr distribution characteristics between detrital and source rock rutiles, demonstrating a close source-sediment link for rutiles from clastic and rock in UHPM terranes. Thus rutiles can be accurate tracers of source rock lithologies in sedimentary provenance studies even at a small regional scale. In Bixiling, Nb/Ta ratios of metamafic and metapelitic detrital rutiles fall between 11.0 to 27.3 and 7.7 to 20.5, respectively. In contrast, in Shuanghe, these ratios are highly variable, ranging from 10.9 to 71.0 and 7.6 to 87.1, respectively. When ignoring four outlier compositions with extremely high Nb/Ta in Shuanghe, a distinct clustering of Nb/Ta ratios in rutiles is shown: metapelitic detrital rutiles have Nb/Ta of 7-40 vs. metamafic detrital rutiles with Nb/Ta = 11-25. The Nb/Ta characteristics in detrital rutiles from both areas may reflect the degree of fluid-rock interaction during metamorphism and/or different source lithologies. Therefore, the trace element compositions in detrital rutiles can accurately trace the lithology, proportion and fluid-rock interaction of different source rocks.

Preliminary evaluation of the shale gas prospectivity of the Lower Cretaceous Pearsall Formation in the onshore Gulf Coast region, United States

USGS Publications Warehouse

Enomoto, Catherine B.; Scott, Kristina; Valentine, Brett J.; Hackley, Paul C.; Dennen, Kristin; Lohr, Celeste D.

2012-01-01

Recent work by the U.S. Geological Survey indicated that the Lower Cretaceous Pearsall Formation contains an estimated mean undiscovered, technically recoverable unconventional gas resource of 8.8 trillion cubic ft in the Maverick Basin, South Texas. Cumulative gas production from horizontal wells in the core area of the emerging play has exceeded 5 billion cubic ft since 2008. However, very little information is available to characterize the Pearsall Formation as an unconventional gas resource beyond the Maverick Basin in the greater Gulf Coast region. Therefore, this reconnaissance study examines spatial distribution, thickness, organic richness and thermal maturity of the Pearsall Formation in the onshore U.S. Gulf states using wireline logs and drill cuttings sample analysis. Spontaneous potential and resistivity curves of approximately forty wireline logs from wells in five Gulf Coast states were correlated to ascertain the thickness of the Pearsall Formation and delineate its three members: Pine Island Shale, James Limestone or Cow Creek Limestone, and Bexar Shale, in ascending stratigraphic order. In Florida and Alabama the Pearsall Formation is up to about 300 ft thick; in Mississippi, Louisiana, Arkansas, and East Texas, thickness is up to as much as 800 ft. Drill cuttings sampled from 11 wells at depths ranging from 4600 to 19,600 feet subsurface indicate increasingly oxygenated depositional environments (predominance of red shale) towards the eastern part of the basin. Cuttings vary widely in lithology but indicate interbedded clastics and limestones throughout the Pearsall Formation, consistent with previous regional studies. Organic petrographic and geochemical analyses of 17 cutting samples in the Pearsall Formation indicate a wide range in thermal maturity, from immature (0.43% Ro [vitrinite reflectance]) in paleo-high structural locations to the peak oil window (0.99% Ro) in the eastern portion of the Gulf Coast Basin. This is in contrast to dry gas thermal maturity throughout the Pearsall Formation in the South Texas Maverick Basin. Organic carbon content is low overall, even in immature samples, with a range of 0.17 to 1.08 wt.% by Leco in 22 Pearsall Formation samples. The pyrolysis output range was 0.23 to 2.33 mg hydrocarbon/g rock. The thermal maturity and Rock-Eval pyrolysis data and organic petrologic observations from this study will be used to better focus specific areas of investigation where the Pearsall Formation may be prospective as an unconventional hydrocarbon source and reservoir.

Geology and hydrocarbon potential of the Oued Mya basin, Algeria

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

Benamrane, O.; Messaoudi, M.; Messelles, H.

1993-09-01

The Oued Mya hydrocarbon system is located in the Sahara basin. It is one of the best producing basins in Algeria, along with the Ghadames and Illizi basins. The stratigraphic section consists of Paleozoic and Mesozoic, and is about 5000 m thick. This intracratonic basin is limited to the north by the Toughourt saddle, and to the west and east it is flanked by regional arches, Allal-Tilghemt and Amguid-Hassi Messaoud, which culminate in the super giant Hassi Messaoud and Hassi R'mel hydrocarbon accumulations, respectively, producing oil from the Cambrian sands and gas from the Trissic sands. The primary source rockmore » in this basin is lower Silurian shale, with an average thickness of 50 m and a total organic carbon of 6% (14% in some cases). Results of maturation modeling indicate that the lower Silurian source is in the oil window. The Ordovician shales are also source rocks, but in a second order. Clastic reservoirs are in the Trissic sequence, which is mainly fluvial deposits with complex alluvial channels, and the main target in the basin. Clastic reservoirs in the lower Devonian section have a good hydrocarbon potential east of the basin through a southwest-northwest orientation. The Late Trissic-Early Jurassic evaporites that overlie the Triassic clastic interval and extend over the entire Oued Mya basin, are considered to be a super-seal evaporite package, which consists predominantly of anhydrite and halite. For paleozoic targets, a large number of potential seals exist within the stratigraphic column. This super seal does not present oil dismigration possibilities. We can infer that a large amount of the oil generated by the Silurian source rock from the beginning of Cretaceous until now still is not discovered and significantly greater volumes could be trapped within structure closures and mixed or stratigraphic traps related to the fluvial Triassic sandstones, marine Devonian sands, and Cambrian-Ordovician reservoirs.« less

Thermal stability of ladderane lipids as determined by hydrous pyrolysis

USGS Publications Warehouse

Jaeschke, A.; Lewan, M.D.; Hopmans, E.C.; Schouten, S.; Sinninghe, Damste J.S.

2008-01-01

Anaerobic ammonium oxidation (anammox) has been recognized as a major process resulting in loss of fixed inorganic nitrogen in the marine environment. Ladderane lipids, membrane lipids unique to anammox bacteria, have been used as markers for the detection of anammox in marine settings. However, the fate of ladderane lipids after sediment burial and maturation is unknown. In this study, anammox bacterial cell material was artificially matured by hydrous pyrolysis at constant temperatures ranging from 120 to 365 ??C for 72 h to study the stability of ladderane lipids during progressive dia- and catagenesis. HPLC-MS/MS analysis revealed that structural alterations of ladderane lipids already occurred at 120 ??C. At temperatures >140 ??C, ladderane lipids were absent and only more thermally stable products could be detected, i.e., ladderane derivatives in which some of the cyclobutane rings were opened. These diagenetic products of ladderane lipids were still detectable up to temperatures of 260 ??C using GC-MS. Thus, ladderane lipids are unlikely to occur in ancient sediments and sedimentary rocks, but specific diagenetic products of ladderane lipids will likely be present in sediments and sedimentary rocks of relatively low maturity (i.e., C31 hopane 22S/(22S + 22R) ratio 0.5). ?? 2008 Elsevier Ltd.

Early Precambrian mantle derived rocks in the southern Prince Charles Mountains, East Antarctica: age and isotopic constraints

USGS Publications Warehouse

Mikhalsky, E.V.; Henjes-Kunst, F.; Roland, N.W.

2007-01-01

Mafic and ultramafic rocks occurring as lenses, boudins, and tectonic slabs within metamorphic units in the southern Mawson Escarpment display mantle characteristics of either a highly enriched, or highly depleted nature. Fractionation of these mantle rocks from their sources may be as old as Eoarchaean (ca 3850 Ma) while their tectonic emplacement probably occurred prior to 2550 Ma (U-Pb SHRIMP data). These results provide for the first time evidence for Archaean suturing within East Antarctica. Similar upper mantle sources are likely present in the northern Mawson Escarpment. A younger age limit of these rocks is 2200 Ma, as indicated by presumably metamorphic zircon ages while their magmatic age may be constrained by single zircon dates at 2450-2250 Ma. The area of the northern Mawson Escarpment is most likely of ensimatic origin and includes mafic rocks which were derived from distinct mantle source(s) during Palaeoproterozoic time.

Maize aflatoxin accumulation segregates with early maturing selections from an S2 breeding cross population.

PubMed

Henry, W Brien

2013-01-15

Maize breeders continue to seek new sources of aflatoxin resistance, but most lines identified as resistance sources are late maturing. The vast difference in flowering time makes it hard to cross these lines with proprietary commercial lines that mature much earlier and often subjects the reproductive phase of these resistant lines to the hottest and driest portion of the summer, making silking, pollination and grain fill challenging. Two hundred crosses from the GEM Project were screened for aflatoxin accumulation at Mississippi State in 2008, and a subset of these lines were screened again in 2009. The breeding cross UR13085:S99g99u was identified as a potential source of aflatoxin resistance, and maturity-based selections were made from an S2 breeding population from this same germplasm source: UR13085:S99g99u-B-B. The earliest maturing selections performed poorly for aflatoxin accumulation, but later maturing selections were identified with favorable levels of aflatoxin accumulation. These selections, while designated as "late" within this study, matured earlier than most aflatoxin resistant lines presently available to breeders. Two selections from this study, designated S5_L7 and S5_L8, are potential sources of aflatoxin resistance and will be advanced for line development and additional aflatoxin screening over more site years and environments.

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.

Geology of the Plumtree area, Spruce Pine district, North Carolina

USGS Publications Warehouse

Brobst, Donald Albert

1953-01-01

This report describes the results of study and geologic mapping (1:12,000) in the 70-square-mile Plumtree area in the northeastern part of the Spruce Pine pegmatite district, on the Blue Ridge upland in western North Carolina. The district has been the chief domestic source of feldspar and sheet mica. The mining belt just west of the Blue Ridge Front trends northeast and is 25 miles long and 10 miles wide. The center of the Plumtree area lies 10 miles northeast of Spruce Pine pegmatite district, on the Blue Ridge upland in western North Carolina. The district has been the chief domestic source of feldspar and sheet mica. The mining belt just west of the Blue Ridge Front trends northeast and is 25 miles long and 10 miles wide. The center of the Plumtree area lies 10 miles northeast of Spruce Pine and includes parts of Mitchell and Avery Counties shown on the portions of the 7.5-minute Spruce Pine, Linville Falls, Newland, North Carolina, and Carvers Gap, North Carolina and Tennessee quadrangle. The topography varies from rugged mountains to rounded or flat topped hills near the entrenched, meandering master streams. Old erosion surfaces are approximately 600,1,100, 1,500, and 2,500 feet above the present master stream level. The area is in late youth or early maturity after rejuvenation.. The regionally metamorphosed rocks of the amophibolite facies form three mappable units: mica gneiss, mica schist, and hornblende rock. These rocks, perhaps of Precambrian age, are intimately interlayered with thicknesses of the individual layers ranging from less than one inch to several tons of feet. Field relationships and chemical data suggest that the mica (Carolina-type) rocks were derived from sandstones, graywackes, and shales and that the hornblende-rich (Roan-type) layers were derived from impure carbonate rocks. The igneous rocks include alaskite and associated pegmatite of early Paleozoic age (?), dunite and associated soapstone of a prepegmatite age, and a few diabasic dikes of post-pegmatite age (Triassic?). The alaskite and pegmatite have similar bulk compositions, notably low in iron (0.3 percent). The major constituents in order of decreasing abundance are plagioclase, perthitic microcline, quartz, and muncovite. All of these minerals, as well as clay deposits derived from the weathering of alaskite under old terraces, have economic value. The zoned pegmatites contain fewer zones which are less complex mineralogically than those in the pegmatites of many other areas. These essentially unmetamorphosed bodies were intruded approximately at the peak of the regional metamorphism. Their emplacement was controlled by local structure and rock type. The source of this igneous material may have been the mobilized portions of the Cranberry gneiss which underlies the area. The dunite bodies were intruded early in the metamorphic cycle. The bodies are commonly zoned: from the wall rock inwards (1) talc-antrophyllite-serpentine fringe, (3) serpentinized dunite, (3) granular olivine core. Dunite, chromite, vermiculite, and anthophyllite are the major economic commodities. Extensive hydrothermal alteration of dunite bodies produced soapstone. The area is the northeast end of a southwest plunging synclinorium about 20 miles wide with the steeper limb on the northwest side. There are three structural zones: zone I on the northwest is characterized by the northeast-trending isoclinal folds with steep southeast dips; zone II on the southwest includes an area of rocks with low and variable dip; zone III is the complex central core. In the extreme northeast zones I and II have an indistinct boundary where they coalesce along the rim of the synclinorium. Six stratigraphic units are exposed totaling approximately 10,500 feet of metamorphic rocks. Small scale structural features include a foliation, and a lineation in the planes of the foliation. Minor folding reflects the trends of the major structures. There are randomly orient

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

Burwood, R.; Fortems, G.; Mycke, B.

Deposited under lacustrine conditions during the rift-phase opening of the southern Atlantic, the lower Congo Bucomazi Formation is a highly productive source rock sequence. Reaching considerable thickness (1.8 km), a heterogeneous organofacies reflects both rapid accumulation and changing conditions during Early Cretaceous Barremian sedimentation. As a component of organofacies, low resolution studies showed kerogen kinetic parameters (Ea/A) varied widely according to the gross paleoenvironmental conditions prevailing during deposition. As a a general trend, refractory (type I, higher Ea) kerogens of the [open quotes]basin fill[close quotes] Organic Rich Zone (ORZ) give way to more labile (type II, lower Ea) assemblages inmore » the up-section [open quotes]sheet drape[close quotes] sediments. At higher resolution, a considerable fine structure in Ea fluctuation, presumably reflecting micropaleoenvironment control, becomes evident. Using Ea values assembled for the Bucomazi type section, subsidence modeling for a Ponta Vermelha depocenter section showed a wide disparity in behavior. Being more representative of the sheet-drape episode, type II assemblages matured earlier, at lesser overburdens, and provided the initial hydrocarbon charge. For the ORZ assemblages, the dominant type I component was of retarded maturation, only becoming productive at commensurately greater overburdens. Cumulatively, these events merge to provide an extended period of hydrocarbon generation with implications for production of aggregate oils of varied emplacement histories. Significantly, the net effect of the observed Ea contrast results in the less prolific (but more labile) uppermost Bucomazi assuming a more important charging role than the ORZ of superior source richness. The latter can only realize its full potential under the greatest overburdens attainable in the most subsident depocenters.« less

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.

Coal-rock interface detector

NASA Technical Reports Server (NTRS)

Rose, S. D.; Crouch, C. E.; Jones, E. W. (Inventor)

1979-01-01

A coal-rock interface detector is presented which employs a radioactive source and radiation sensor. The source and sensor are separately and independently suspended and positioned against a mine surface of hydraulic pistons, which are biased from an air cushioned source of pressurized hydraulic fluid.

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

Fluids in crustal deformation: Fluid flow, fluid-rock interactions, rheology, melting and resources

NASA Astrophysics Data System (ADS)

Lacombe, Olivier; Rolland, Yann

2016-11-01

Fluids exert a first-order control on the structural, petrological and rheological evolution of the continental crust. Fluids interact with rocks from the earliest stages of sedimentation and diagenesis in basins until these rocks are deformed and/or buried and metamorphosed in orogens, then possibly exhumed. Fluid-rock interactions lead to the evolution of rock physical properties and rock strength. Fractures and faults are preferred pathways for fluids, and in turn physical and chemical interactions between fluid flow and tectonic structures, such as fault zones, strongly influence the mechanical behaviour of the crust at different space and time scales. Fluid (over)pressure is associated with a variety of geological phenomena, such as seismic cycle in various P-T conditions, hydrofracturing (including formation of sub-horizontal, bedding-parallel veins), fault (re)activation or gravitational sliding of rocks, among others. Fluid (over)pressure is a governing factor for the evolution of permeability and porosity of rocks and controls the generation, maturation and migration of economic fluids like hydrocarbons or ore forming hydrothermal fluids, and is therefore a key parameter in reservoir studies and basin modeling. Fluids may also help the crust partially melt, and in turn the resulting melt may dramatically change the rheology of the crust.

Southern Mozambique basin: most promising hydrocarbon province offshore eat Africa

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

De Buyl, M.; Flores, G.

1984-09-01

Recent offshore acquisition of 12,800 km (8,000 mi) of seismic reflection data, with gravity and magnetic profiles encompassing the southern half of the Mozambique basin, reveals new facets of the subsurface geology. Integrated interpretation of these new geophysical data with old well information results in the development of depositional and tectonic models that positively establish the hydrocarbon potential of the basin. The recent comprehensive interpretation affords the following conclusions. (1) Significant oil shows accompany wet gas discoveries suggest that the South Mozambique basin is a mature province, as the hydrocarbon associations imply thermogenic processes. (2) Super-Karoo marine Jurassic sequences havemore » been encountered in Nhamura-1 well onshore from the application of seismic stratigraphy and well correlation. (3) Steeply dipping reflectors truncated by the pre-Cretaceous unconformity testify to significant tectonic activity preceding the breakup of Gondwanaland. Hence, preconceived ideas about the depth of the economic basement and the absence of mature source rocks of pre-Cretaceous age should be revised. (4) Wildcats in the vicinity of ample structural closures have not been, in retrospect, optimally positioned nor drilled to sufficient depth to test the viability of prospects mapped along a major offshore extension of the East African rift system delineated by this new survey.« less

Paleogeographic evolution of foldbelts adjacent to petroleum basins of Venezuela and Trinidad

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

Goodman, E.D.; Koch, P.S.; Summa, L.L.

1996-08-01

The foldbelts of Venezuela and Trinidad have shaped the history of adjacent sedimentary basins. A set of paleogeographic maps on reconstructed bases depict the role of foldbelts in the development of the sedimentary basins of Venezuela. Some of the foldbelts are inverted, pre-Tertiary graben/passive margin systems. Other foldbelts are allochthonous nappes or parautochthons that override the Mesozoic passive margin hinge without inversion. The emergence of these foldbelts changed the course of existing river systems and provided a new source for sediments and maturation in adjacent deeps. The Merida Andes area was remobilized beginning in the Early Miocene as a zonemore » of lateral shear, along which the Bonaire Block has moved over 200 km to the northeast, dismembering the Maracaibo and Barinas basins. Late Miocene to Recent transpression and fault reactivation have driven rapid Andean uplift with thrust-related subsidence and maturation (e.g., SE Maracaibo foredeep). To the east, uplift and erosion of the Serrania del Interior (1) curtailed mid-Tertiary fluvial systems flowing northward from the igneous and sedimentary rocks of the Guyana Shield, deflecting them eastward, and (2) removed the thick early Miocene foredeep fill into a younger foredeep. Thus, the fold-thrust belts and sedimentary basins in this region are linked in their evolutionary histories.« less

Geosynthesis of organic compounds: I. Alkylphenols

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

Ioppolo-Armanios, M.; Alexander, R.; Kagi, R.I.

1995-07-01

Methylation, isopropylation, and sec-butylation are proposed as geosynthetic processes to account for the alkylphenol compositions of crude oils with phenol distributions dominated by ortho and para substituted compounds. Phenol distributions in eleven crude oils and four kerogen pyrolysates were analysed using GC-MS (gas chromatography-mass spectrometry). Ten of the crude oils show high relative abundances of ortho and para substituted phenol isomers and some were also enriched in C{sub 3}-C{sub 5} alkylphenols compared to the kerogen pyrolysates. Because the distributions of products obtained from the laboratory alkylation of cresols closely resemble those of phenols in these crude oils, we propose thatmore » similar alkylation processes occur in source rocks. Alkylation ratios reflecting the degree of methylation, isopropylation, and sec-butylation, which were based on the relative abundance of the dominant alkylation products compared to their likely precursor ortho-cresol, indicate that high levels of methylation occurred in crude oils over a wide range of maturities, whereas high levels of isopropylation and sec-butylation were observed only in mature samples. Dissolution of the phenols in crude oils by water contact was discounted as an explanation for the observed phenol distributions based on the relative distribution coefficients of phenols between a hydrocarbon phase and water.« less

Double-Edge Sword of Sustained ROCK Activation in Prion Diseases through Neuritogenesis Defects and Prion Accumulation

PubMed Central

Alleaume-Butaux, Aurélie; Nicot, Simon; Pietri, Mathéa; Baudry, Anne; Dakowski, Caroline; Tixador, Philippe; Ardila-Osorio, Hector; Haeberlé, Anne-Marie; Bailly, Yannick; Peyrin, Jean-Michel; Launay, Jean-Marie; Kellermann, Odile; Schneider, Benoit

2015-01-01

In prion diseases, synapse dysfunction, axon retraction and loss of neuronal polarity precede neuronal death. The mechanisms driving such polarization defects, however, remain unclear. Here, we examined the contribution of RhoA-associated coiled-coil containing kinases (ROCK), key players in neuritogenesis, to prion diseases. We found that overactivation of ROCK signaling occurred in neuronal stem cells infected by pathogenic prions (PrPSc) and impaired the sprouting of neurites. In reconstructed networks of mature neurons, PrPSc-induced ROCK overactivation provoked synapse disconnection and dendrite/axon degeneration. This overactivation of ROCK also disturbed overall neurotransmitter-associated functions. Importantly, we demonstrated that beyond its impact on neuronal polarity ROCK overactivity favored the production of PrPSc through a ROCK-dependent control of 3-phosphoinositide-dependent kinase 1 (PDK1) activity. In non-infectious conditions, ROCK and PDK1 associated within a complex and ROCK phosphorylated PDK1, conferring basal activity to PDK1. In prion-infected neurons, exacerbated ROCK activity increased the pool of PDK1 molecules physically interacting with and phosphorylated by ROCK. ROCK-induced PDK1 overstimulation then canceled the neuroprotective α-cleavage of normal cellular prion protein PrPC by TACE α-secretase, which physiologically precludes PrPSc production. In prion-infected cells, inhibition of ROCK rescued neurite sprouting, preserved neuronal architecture, restored neuronal functions and reduced the amount of PrPSc. In mice challenged with prions, inhibition of ROCK also lowered brain PrPSc accumulation, reduced motor impairment and extended survival. We conclude that ROCK overactivation exerts a double detrimental effect in prion diseases by altering neuronal polarity and triggering PrPSc accumulation. Eventually ROCK emerges as therapeutic target to combat prion diseases. PMID:26241960

Studying physical properties of deformed intact and fractured rocks by micro-scale hydro-mechanical-seismicity model

NASA Astrophysics Data System (ADS)

Raziperchikolaee, Samin

The pore pressure variation in an underground formation during hydraulic stimulation of low permeability formations or CO2 sequestration into saline aquifers can induce microseismicity due to fracture generation or pre-existing fracture activation. While the analysis of microseismic data mainly focuses on mapping the location of fractures, the seismic waves generated by the microseismic events also contain information for understanding of fracture mechanisms based on microseismic source analysis. We developed a micro-scale geomechanics, fluid-flow and seismic model that can predict transport and seismic source behavior during rock failure. This model features the incorporation of microseismic source analysis in fractured and intact rock transport properties during possible rock damage and failure. The modeling method considers comprehensive grains and cements interaction through a bonded-particle-model. As a result of grain deformation and microcrack development in the rock sample, forces and displacements in the grains involved in the bond breakage are measured to determine seismic moment tensor. In addition, geometric description of the complex pore structure is regenerated to predict fluid flow behavior of fractured samples. Numerical experiments are conducted for different intact and fractured digital rock samples, representing various mechanical behaviors of rocks and fracture surface properties, to consider their roles on seismic and transport properties of rocks during deformation. Studying rock deformation in detail provides an opportunity to understand the relationship between source mechanism of microseismic events and transport properties of damaged rocks to have a better characterizing of fluid flow behavior in subsurface formations.

Shale characterization on Barito field, Southeast Kalimantan for shale hydrocarbon exploration

NASA Astrophysics Data System (ADS)

Sumotarto, T. A.; Haris, A.; Riyanto, A.; Usman, A.

2017-07-01

Exploration and exploitation in Indonesia now are still focused on conventional hydrocarbon energy than unconventional hydrocarbon energy such as shale gas. Tanjung Formation is a source rock of Barito Basin located in South Kalimantan that potentially as shale hydrocarbon. In this research, integrated methods using geochemical analysis, mineralogy, petrophysical analysis and seismic interpretation has been applied to explore the shale hydrocarbon potential in Barito Field for Tanjung formation. The first step is conducting geochemical and mineralogy analysis to the shale rock sample. Our analysis shows that the organic richness is ranging from 1.26-5.98 wt.% (good to excellent) with the depth of early mature window of 2170 m. The brittleness index is in an average of 0.44-0.56 (less Brittle) and Kerogen type is classified into II/III type that potentially produces oil and gas. The second step is continued by performing petrophysical analysis, which includes Total Organic Carbon (TOC) calculation and brittleness index continuously. The result has been validated with a laboratory measurement that obtained a good correlation. In addition, seismic interpretation based on inverted acoustic impedance is applied to map the distributions of shale hydrocarbon potential. Our interpretation shows that shale hydrocarbon potential is localized in the eastern and southeastern part of the study area.

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

Use of commercial and social sources of alcohol by underage drinkers: the role of pubertal timing.

PubMed

Storvoll, Elisabet E; Pape, Hilde; Rossow, Ingeborg

2008-01-01

We have explored whether alcohol use and procurement of alcohol from commercial and social sources vary with pubertal timing. A sub-sample of 9291 Norwegian minors (13-17 year-olds) was extracted from a nationwide school survey (response rate: 92%). Adolescents who had matured early (early developers, EDs) reported higher consumption and more alcohol-related harm than those who had matured late (late developers, LDs) or at the "normal" time (on time developers, ODs). Purchases from on-premise and off-premise outlets were much more important sources of alcohol for EDs than for ODs and LDs - both in relative and absolute terms. Moreover, EDs were somewhat more likely to obtain alcohol from social sources. Taken together, the findings indicate that adolescents who mature early have access to a larger variety of sources of alcohol than adolescents who mature later - which in turn may explain their increased level of drinking.

Kaersutite-bearing xenoliths and megacrysts in volcanic rocks from the Funk Seamount in the souhtwest Indian Ocean

NASA Technical Reports Server (NTRS)

Reid, Arch M.; Le Roex, Anton P.

1988-01-01

The petrography, mineral chemistry, and whole-rock compositions of volcanic rocks dredged from the Funk Seamount, located 60 km NW of Marion Island in the southwestern Indian Ocean, are presented together with the mineral chemistry of their inclusions. On the basis of these characteristics, the possible relationships between the Funk Seamount's volcanic rocks and the megacrysts and xenoliths in these rocks are discussed. It is argued that the Funk Seamount lavas derive from a similar mantle source region as that of the Marion Island and Prince Edward Island hotspot lavas. The geochemical signature of these lavas implies derivation from a source that is enriched (e.g., in Ti, K, P, and Nb) over the depleted mantle source regions for the adjacent mid-ocean ridge basalts.

Reappraisal of hydrocarbon biomarkers in Archean rocks

PubMed Central

French, Katherine L.; Hallmann, Christian; Hope, Janet M.; Schoon, Petra L.; Zumberge, J. Alex; Hoshino, Yosuke; Peters, Carl A.; George, Simon C.; Love, Gordon D.; Brocks, Jochen J.; Buick, Roger; Summons, Roger E.

2015-01-01

Hopanes and steranes found in Archean rocks have been presented as key evidence supporting the early rise of oxygenic photosynthesis and eukaryotes, but the syngeneity of these hydrocarbon biomarkers is controversial. To resolve this debate, we performed a multilaboratory study of new cores from the Pilbara Craton, Australia, that were drilled and sampled using unprecedented hydrocarbon-clean protocols. Hopanes and steranes in rock extracts and hydropyrolysates from these new cores were typically at or below our femtogram detection limit, but when they were detectable, they had total hopane (<37.9 pg per gram of rock) and total sterane (<32.9 pg per gram of rock) concentrations comparable to those measured in blanks and negative control samples. In contrast, hopanes and steranes measured in the exteriors of conventionally drilled and curated rocks of stratigraphic equivalence reach concentrations of 389.5 pg per gram of rock and 1,039 pg per gram of rock, respectively. Polycyclic aromatic hydrocarbons and diamondoids, which exceed blank concentrations, exhibit individual concentrations up to 80 ng per gram of rock in rock extracts and up to 1,000 ng per gram of rock in hydropyrolysates from the ultraclean cores. These results demonstrate that previously studied Archean samples host mixtures of biomarker contaminants and indigenous overmature hydrocarbons. Therefore, existing lipid biomarker evidence cannot be invoked to support the emergence of oxygenic photosynthesis and eukaryotes by ∼2.7 billion years ago. Although suitable Proterozoic rocks exist, no currently known Archean strata lie within the appropriate thermal maturity window for syngenetic hydrocarbon biomarker preservation, so future exploration for Archean biomarkers should screen for rocks with milder thermal histories. PMID:25918387

Organic petrology and geochemistry of Eocene Suzak bituminous marl, north-central Afghanistan: Depositional environment and source rock potential

USGS Publications Warehouse

Hackley, Paul C.; Sanfilipo, John

2016-01-01

Organic geochemistry and petrology of Eocene Suzak bituminous marl outcrop samples from Madr village in north-central Afghanistan were characterized via an integrated analytical approach to evaluate depositional environment and source rock potential. Multiple proxies suggest the organic-rich (TOC ∼6 wt.%) bituminous marls are ‘immature’ for oil generation (e.g., vitrinite Ro < 0.4%, Tmax < 425 °C, PI ≤ 0.05, C29 ααα S/S + R ≤ 0.12, C29 ββS/ββS+ααR ≤ 0.10, others), yet oil seeps are present at outcrop and live oil and abundant solid bitumen were observed via optical microscopy. Whole rock sulfur content is ∼2.3 wt.% whereas sulfur content is ∼5.0–5.6 wt.% in whole rock extracts with high polar components, consistent with extraction from S-rich Type IIs organic matter which could generate hydrocarbons at low thermal maturity. Low Fe-sulfide mineral abundance and comparison of Pr/Ph ratios between saturate and whole extracts suggest limited Fe concentration resulted in sulfurization of organic matter during early diagenesis. From these observations, we infer that a Type IIs kerogen in ‘immature’ bituminous marl at Madr could be generating high sulfur viscous oil which is seeping from outcrop. However, oil-seep samples were not collected for correlation studies. Aluminum-normalized trace element concentrations indicate enrichment of redox sensitive trace elements Mo, U and V and suggest anoxic-euxinic conditions during sediment deposition. The bulk of organic matter observed via optical microscopy is strongly fluorescent amorphous bituminite grading to lamalginite, possibly representing microbial mat facies. Short chain n-alkanes peak at C14–C16 (n-C17/n-C29 > 1) indicating organic input from marine algae and/or bacterial biomass, and sterane/hopane ratios are low (0.12–0.14). Monoaromatic steroids are dominated by C28clearly indicating a marine setting. High gammacerane index values (∼0.9) are consistent with anoxia stratification and may indicate intermittent saline-hypersaline conditions. Stable C isotope ratios also suggest a marine depositional scenario for the Suzak samples, consistent with the presence of marine foraminifera including abundant planktic globigerinida(?) and rare benthic discocyclina(?) and nummulites(?). Biomarker 2α-methylhopane for photosynthetic cyanobacteria implies shallow photic zone deposition of Madr marls and 3β-methylhopane indicates presence of methanotrophic archaea in the microbial consortium. The data presented herein are consistent with deposition of Suzak bituminous marls in shallow stratified waters of a restricted marine basin associated with the southeastern incipient or proto-Paratethys. Geochemical proxies from Suzak rock extracts (S content, high polar content, C isotopes, normal (αααR) C27–29 steranes, and C29/C30 and C26/C25 hopane ratios) are similar to extant data from Paleogene oils produced to the north in the Afghan-Tajik Basin. This observation may indicate laterally equivalent strata are effective source rocks as suggested by previous workers; however, further work is needed to strengthen oil-source correlations.

New Insights Into the Genesis and Compositional Evolution of I-type Granitic magmas in the Lachlan Fold Belt (SE Australia) by in situ Hf Isotopic Analysis of Zircon

NASA Astrophysics Data System (ADS)

Kemp, T. I.; Hawkesworth, C. J.; Hergt, J. M.; Woodhead, J.

2004-05-01

Isotope studies have proved of enormous benefit in fingerprinting the source rocks of silicic magmas and tracing open system petrogenetic processes, such as crustal assimilation or magma mixing. Quantification of these processes, especially the role of mantle-derived magmas, is essential to formulating realistic models for the thermal regime and compositional evolution of the continental crust. However, this remains problematic, since whole-rock isotopic data registers the final state of the magmatic system but gives no information on the pathways by which this state was attained. For example, the eNd - initial 87Sr/86Sr isotopic array defined by the classic I- and S-type granites of the Lachlan Fold Belt has been variously interpreted to reflect (1) mixing between two end-member magmas, one depleted mantle-like, the other evolved and continental crust-like, (2) mixing between a juvenile magma and a magma sourced from mafic lower crust, accompanied by sediment assimilation, (3) derivation of the granites from mixed source rocks and (4) derivation from a sequence of protoliths of various ages and sedimentary maturity. The implications of these possibilities for crustal architecture, and whether granitic magmatism was associated with the recycling or growth of new continental crust are drastically different. One way to now resolve such ambiguities is by unravelling the isotopic information encoded in the fine-scale growth zoning of minerals such as zircon, which potentially tracks the processes operative during crystallisation. To this end we report the first laser-ablation ICP-MS study into the Hf isotope stratigraphy of zircons hosted by LFB I-type granites and their mafic enclaves. This is integrated with a prior U-Pb isotope study and trace element concentrations measured on the same zircons. Two suites were investigated, the Cobargo and Why Worry Suites of the Bega Batholith. Although the bulk rock isotopic variation within these suites is restricted, this study reveals remarkable fluctuations in Hf isotopic ratios recorded within and between melt-precipitated zircons of granitic and enclave samples. This can only be reconciled by open-system behaviour, though contrasting patterns of Hf isotope variation within zoned zircons demonstrate that this differed significantly between the two suites. The Cobargo Suite was generated by mixing between two contrasting magmas, followed by crustal assimilation. Zircons from the Why Worry Suite have more evolved Hf isotope ratios, consistent with recycling of older crust during granitic generation, though increase in eHf towards zircon rims manifests interaction with primitive magmas. Globules of these are represented by mafic enclaves, the mantle heritage of which is preserved by high eHf values of zircon cores, even though whole-rock isotope contrasts with the host have been erased by equilibration. Analysis of inherited zircons contained by the Why Worry Suite establishes that the 450-600 Ma age population have evolved eHf values, and thus meta-igneous rocks of this age are appropriate protoliths for these granites. The primitive eHf values of the Cobargo Suite preclude derivation from similar sources, instead suggesting formation from mantle-derived materials. Incorporating the existing geochemical and isotope datasets, the Hf-in-zircon data will be coupled with recent thermal simulations to erect a general model for granite formation and the evolution of the continental crust during Lachlan orogenesis.

Investigation of water-soluble organic matter extracted from shales during leaching experiments

NASA Astrophysics Data System (ADS)

Zhu, Yaling; Vieth-Hillebrand, Andrea; Wilke, Franziska D. H.; Horsfield, Brian

2017-04-01

The huge volumes and unknown composition of flowback and produced waters cause major public concerns about the environmental and social compatibility of hydraulic fracturing and the exploitation of gas from unconventional reservoirs. Flowback and produced waters contain not only residues of fracking additives but also chemical species that are dissolved from the shales themselves during fluid-rock interaction. Knowledge of the composition, size and structure of dissolved organic carbon (DOC) as well as the main controls on the release of DOC are a prerequisite for a better understanding of these interactions and its effects on composition of flowback and produced water. Black shales from four different geological settings and covering a maturity range Ro = 0.3-2.6% were extracted with deionized water. The DOC yields were found to decrease rapidly with increasing diagenesis and remain low throughout catagenesis. Four DOC fractions have been qualitatively and quantitatively characterized using size-exclusion chromatography. The concentrations of individual low molecular weight organic acids (LMWOA) decrease with increasing maturity of the samples except for acetate extracted from the overmature Posidonia shale, which was influenced by hydrothermal brines. The oxygen content of the shale organic matter also shows a significant influence on the release of organic acids, which is indicated by the positive trend between oxygen index (OI) and the concentrations of formate and acetate. Based on our experiments, both the properties of the organic matter source and the thermal maturation progress of the shale organic matter significantly influence the amount and quality of extracted organic compounds during the leaching experiments.

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.

Qualitative and quantitative analysis of Dibenzofuran, Alkyldibenzofurans, and Benzo[b]naphthofurans in crude oils and source rock extracts

USGS Publications Warehouse

Meijun Li,; Ellis, Geoffrey S.

2015-01-01

Dibenzofuran (DBF), its alkylated homologues, and benzo[b]naphthofurans (BNFs) are common oxygen-heterocyclic aromatic compounds in crude oils and source rock extracts. A series of positional isomers of alkyldibenzofuran and benzo[b]naphthofuran were identified in mass chromatograms by comparison with internal standards and standard retention indices. The response factors of dibenzofuran in relation to internal standards were obtained by gas chromatography-mass spectrometry analyses of a set of mixed solutions with different concentration ratios. Perdeuterated dibenzofuran and dibenzothiophene are optimal internal standards for quantitative analyses of furan compounds in crude oils and source rock extracts. The average concentration of the total DBFs in oils derived from siliciclastic lacustrine rock extracts from the Beibuwan Basin, South China Sea, was 518 μg/g, which is about 5 times that observed in the oils from carbonate source rocks in the Tarim Basin, Northwest China. The BNFs occur ubiquitously in source rock extracts and related oils of various origins. The results of this work suggest that the relative abundance of benzo[b]naphthofuran isomers, that is, the benzo[b]naphtho[2,1-d]furan/{benzo[b]naphtho[2,1-d]furan + benzo[b]naphtho[1,2-d]furan} ratio, may be a potential molecular geochemical parameter to indicate oil migration pathways and distances.

Rho-GTPase effector ROCK phosphorylates cofilin in actin-meditated cytokinesis during mouse oocyte meiosis.

PubMed

Duan, Xing; Liu, Jun; Dai, Xiao-Xin; Liu, Hong-Lin; Cui, Xiang-Shun; Kim, Nam-Hyung; Wang, Zhen-Bo; Wang, Qiang; Sun, Shao-Chen

2014-02-01

During oocyte meiosis, a spindle forms in the central cytoplasm and migrates to the cortex. Subsequently, the oocyte extrudes a small body and forms a highly polarized egg; this process is regulated primarily by actin. ROCK is a Rho-GTPase effector that is involved in various cellular functions, such as stress fiber formation, cell migration, tumor cell invasion, and cell motility. In this study, we investigated possible roles for ROCK in mouse oocyte meiosis. ROCK was localized around spindles after germinal vesicle breakdown and was colocalized with cytoplasmic actin and mitochondria. Disrupting ROCK activity by RNAi or an inhibitor resulted in cell cycle progression and polar body extrusion failure. Time-lapse microscopy showed that this may have been due to spindle migration and cytokinesis defects, as chromosomes segregated but failed to extrude a polar body and then realigned. Actin expression at oocyte membranes and in cytoplasm was significantly decreased after these treatments. Actin caps were also disrupted, which was confirmed by a failure to form cortical granule-free domains. The mitochondrial distribution was also disrupted, which indicated that mitochondria were involved in the ROCK-mediated actin assembly. In addition, the phosphorylation levels of Cofilin, a downstream molecule of ROCK, decreased after disrupting ROCK activity. Thus, our results indicated that a ROCK-Cofilin-actin pathway regulated meiotic spindle migration and cytokinesis during mouse oocyte maturation.

FNF Construction Inc. Window Rock Airport Project: Coverage Under General Air Quality Permit for New or Modified Minor Source Cement Batch Plants in Indian Country

EPA Pesticide Factsheets

Approved Request for Coverage under General Air Quality Permit for New or Modified Minor Source Cement Batch Plants in Indian Country for FNF Construction Inc. Window Rock Airport Soil Cement Mixing Plant Project, Beacon Road, Window Rock, Arizona 86515.

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.

40 CFR 436.180 - Applicability; description of the phosphate rock subcategory.

Code of Federal Regulations, 2013 CFR

2013-07-01

... phosphate rock subcategory. 436.180 Section 436.180 Protection of Environment ENVIRONMENTAL PROTECTION... SOURCE CATEGORY Phosphate Rock Subcategory § 436.180 Applicability; description of the phosphate rock... bearing rock, ore or earth for the phosphate content. [43 FR 9809, Mar. 10, 1978] ...

40 CFR 436.180 - Applicability; description of the phosphate rock subcategory.

Code of Federal Regulations, 2012 CFR

2012-07-01

... phosphate rock subcategory. 436.180 Section 436.180 Protection of Environment ENVIRONMENTAL PROTECTION... SOURCE CATEGORY Phosphate Rock Subcategory § 436.180 Applicability; description of the phosphate rock... bearing rock, ore or earth for the phosphate content. [43 FR 9809, Mar. 10, 1978] ...

40 CFR 436.180 - Applicability; description of the phosphate rock subcategory.

Code of Federal Regulations, 2014 CFR

2014-07-01

... phosphate rock subcategory. 436.180 Section 436.180 Protection of Environment ENVIRONMENTAL PROTECTION... SOURCE CATEGORY Phosphate Rock Subcategory § 436.180 Applicability; description of the phosphate rock... bearing rock, ore or earth for the phosphate content. [43 FR 9809, Mar. 10, 1978] ...

Structural plays in Ellesmerian sequence and correlative strata of the National Petroleum Reserve, Alaska

USGS Publications Warehouse

Moore, Thomas E.; Potter, Christopher J.

2003-01-01

Reservoirs in deformed rocks of the Ellesmerian sequence in southern NPRA are assigned to two hydrocarbon plays, the Thrust-Belt play and the Ellesmerian Structural play. The two plays differ in that the Thrust-Belt play consists of reservoirs located in allochthonous strata in the frontal part of the Brooks Range fold-and-thrust belt, whereas those of the Ellesmerian Structural play are located in autochthonous or parautochthonous strata at deeper structural levels north of the Thrust-Belt play. Together, these structural plays are expected to contain about 3.5 TCF of gas but less than 6 million barrels of oil. These two plays are analyzed using a two-stage deformational model. The first stage of deformation occurred during the Neocomian, when distal strata of the Ellesmerian sequence were imbricated and assembled into deformational wedges emplaced northward onto regionally south-dipping authochon at 140-120 Ma. In the mid-Cretaceous following cessation of the deformation, the Colville basin, the foreland basin to the orogen, was filled with a thick clastic succession. During the second stage of deformation at about 60 Ma (early Tertiary), the combined older orogenic belt-foreland basin system was involved in another episode of north-vergent contractional deformation that deformed pre-existing stratigraphic and structurally trapped reservoir units, formed new structural traps, and caused significant amounts of uplift, although the amount of shortening was relatively small in comparison to the first episode of deformation. Hydrocarbon generation from source strata (Shublik Formation, Kingak Shale, and Otuk Formation) and migration into stratigraphic traps occurred primarily by sedimentary burial principally between 100-90 Ma, between the times of the two episodes of deformation. Subsequent burial caused deep stratigraphic traps to become overmature, cracking oil to gas, and some new generation to begin progressively higher in the section. Structural disruption of the traps in the Early Tertiary is hypothesized to have released sequestered hydrocarbons and caused remigration into newly formed structural traps formed at higher structural levels. Because of the generally high maturation of the Colville basin at the time of the deformation and remigration, most of the hydrocarbons available to fill traps were gas. In the the Thrust-Belt play, the primary reservoir lithology is expected to be dolomitic carbonate rocks of the Lisburne Group, which contain up to 15% porosity. Antiformal stacks of imbricated Lisburne Group strata form the primary trapping configuration, with chert and shale of the overlying Etivluk Group forming seals on closures. Traps are expected to have been charged primarily with remigrated gas, but oil generated from local sources in the Otuk Formation may have filled some traps at high structural levels. The timing for migration of gas into traps is excellent, but only moderate for oil because peak oil generation for the play as a whole occurred 30 to 40 m.y. before trap formation. Reservoir and seal quality in the play are questionable, reducing the likelyhood of hydrocarbon accumulations being present in the play. Our analysis suggests that the play will hold 5.7 million barrels of technically recoverable oil and 1.5 TCF gas (mean values). In the Ellesmerian Stuctural play, the primary reservoir lithologies will be dolomitic carbonate rocks of the Lisburne Group and, less likely, clastic units in the Ellesmerian sequence. Traps in the play are anticlinal closures caused by small amounts of strain in the footwall below the basal detachment for most early Tertiary thrusting. Because these traps lie beneath the main source rock units (Shublik, Kingak, lower Brookian sequence), reservoirs that are juxtaposed by faulting against source-rock units are expected to have the most favorable migration pathways. The charge will be primarily remigrated gas; no oil is expected because of the great depths (15,000 to 26,000 ft) and consequent high thermal maturity of this play. Although the the probability of charge and timeliness of trap formation and gas remigration are excellent, seal and reservoir qualities are anticipated to be poor. Our analysis suggests that about 2.0 TCF of techncially recoverable gas can be expected in the play.

pre-Mesozoic evolution of the basement of the Catalan Coastal Ranges: implications from geochemical and Sm-Nd isotope data of the Palaeozoic succession of the Collserola Range

NASA Astrophysics Data System (ADS)

Vilà, Miquel; Pin, Christian

2016-04-01

In the whole of the Western Europe and neighbouring areas numerous studies have addressed the provenance of pre-Mesozoic sedimentary rocks and the Palaeozoic geodynamic evolution using the Sm-Nd systematics. However, at present, there are still large areas of the Variscan mountain chain without systematic determinations of their whole - rock Sm-Nd isotope signatures. This is the case of the Palaeozoic blocks of the Catalan Coastal Ranges (NE Iberia). In the context of the Variscan belt many authors interpret the Palaeozoic basement of the Catalan Coastal Ranges as part of the southern foreland basin of the mountain belt. The pre-Mesozoic rocks in the Catalan Coastal Ranges exhibit important stratigraphical affinities with those outcropping in the Eastern Pyrenees, Montagne Noire, Sardinia and Iberian Range. Paleogeographic reconstructions predict that the Catalan Coastal Ranges were located in a transitional area between the northern branch of the Ibero-Armorican arc and the core of the arc. The Collserola Range, located in the metropolitan area of Barcelona, includes a representative Palaeozoic stratigraphic section, from Cambro-Ordovician to Carboniferous, of the central part of the Catalan Coastal Ranges. In this presentation we present an up-to-date review of the stratigraphy and structure of the Palaeozoic of the Collserola Range, and provide geochemical and Sm-Nd isotope data to constrain the Pre-Mesozoic crustal evolution of this sector of the Variscan belt. Geochemical compositions indicate that the Palaeozoic siliciclastic rocks of the Collserola Range were fed by a relative mature heterogeneous source of sediment, comprising from quartz-rich sediments to intermediate igneous rocks. The siliciclastic rocks of the Collserola Range show great geochemical affinity with the turbidites of passive margins. The Sm-Nd signature of the siliciclastic rocks is compatible with those of the Palaeozoic and Late Proterozoic fine grained siliciclastic rocks of the neighbouring terrains of SW Europe. There is a small decrease of the ɛNdT with decreasing age of sedimentation, from the Cambro-Ordovician to the Carboniferous, suggesting an increase of the amount of more 'juvenile' material. The presence of small volumes of alkaline basaltic rocks provides evidence for the input of juvenile material in the Early Palaeozoic basin and suggests that an extensional tectonic regime prevailed during the Cambro-Ordovician sedimentation. From a geodynamic point of view, overall, the analysis of the data evokes that the Palaeozoic rocks of the Catalan Coastal Ranges were part of the Northern Gondwana passive margin before the closure of the Rheic Ocean and the subsequent Variscan orogeny.

Space Weathering of Rocks

NASA Technical Reports Server (NTRS)

Noble, Sarah

2011-01-01

Space weathering discussions have generally centered around soils but exposed rocks will also incur the effects of weathering. On the Moon, rocks make up only a very small percentage of the exposed surface and areas where rocks are exposed, like central peaks, are often among the least space weathered regions we find in remote sensing data. However, our studies of weathered Ap 17 rocks 76015 and 76237 show that significant amounts of weathering products can build up on rock surfaces. Because rocks have much longer surface lifetimes than an individual soil grain, and thus record a longer history of exposure, we can study these products to gain a deeper perspective on the weathering process and better assess the relative impo!1ance of various weathering components on the Moon. In contrast to the lunar case, on small asteroids, like Itokowa, rocks make up a large fraction of the exposed surface. Results from the Hayabusa spacecraft at Itokowa suggest that while the low gravity does not allow for the development of a mature regolith, weathering patinas can and do develop on rock surfaces, in fact, the rocky surfaces were seen to be darker and appear spectrally more weathered than regions with finer materials. To explore how weathering of asteroidal rocks may differ from lunar, a set of ordinary chondrite meteorites (H, L, and LL) which have been subjected to artificial space weathering by nanopulse laser were examined by TEM. NpFe(sup 0) bearing glasses were ubiquitous in both the naturally-weathered lunar and the artificially-weathered meteorite samples.

Unexpected trend in the compositional maturity of second-cycle sand

USGS Publications Warehouse

Solano-Acosta, W.; Dutta, P.K.

2005-01-01

It is generally accepted that recycling of sandstone generates relatively more mature sand than its parent sandstone. Such maturity is accomplished mainly through chemical weathering as the chemically unstable minerals are eliminated. Because chemical weathering is ubiquitous on the Earth's surface, maturity due to recycling is expected in most geological settings. However, contrary to one's expectation, second-cycle Holocene sand, exclusively derived from sandy facies of the first-cycle Pennsylvanian-Permian Cutler Formation, is actually less mature than its first-cycle parent near Gateway, Colorado. Both the Cutler sandstone and Holocene sand were the products of similar geological processes that controlled their respective composition. In spite of such similarities, a significant difference in composition is observed. We propose that the unexpected immaturity in second-cycle Holocene sand may be due to mechanical disintegration of coarse-grained feldspar and feldspar-rich rock fragments into relatively smaller fractions. Results presented in this paper are the first quantitative estimation of recycling of parent sandstone into daughter sand, and the first observed reverse maturity trend in second-cycle sand. These unexpected results suggest the need for further research to quantitatively understand the recycling process. ?? 2005 Elsevier B.V. All rights reserved.

Mercury isotope constraints on the source for sediment-hosted lead-zinc deposits in the Changdu area, southwestern China

NASA Astrophysics Data System (ADS)

Xu, Chunxia; Yin, Runsheng; Peng, Jiantang; Hurley, James P.; Lepak, Ryan F.; Gao, Jianfeng; Feng, Xinbin; Hu, Ruizhong; Bi, Xianwu

2018-03-01

The Lanuoma and Cuona sediment-hosted Pb-Zn deposits hosted by Upper Triassic limestone and sandstone, respectively, are located in the Changdu area, SW China. Mercury concentrations and Hg isotopic compositions from sulfide minerals and potential source rocks (e.g., the host sedimentary rocks and the metamorphic basement) were investigated to constrain metal sources and mineralization processes. In both deposits, sulfide minerals have higher mercury (Hg) concentrations (0.35 to 1185 ppm) than the metamorphic basement rocks (0.05 to 0.15 ppm) and sedimentary rocks (0.02 to 0.08 ppm). Large variations of mass-dependent fractionation (3.3‰ in δ202Hg) and mass-independent fractionation (0.3‰ in Δ199Hg) of Hg isotopes were observed. Sulfide minerals have Hg isotope signatures that are similar to the hydrothermal altered rocks around the deposit, and similar to the metamorphic basement, but different from barren sedimentary rocks. The variation of Δ199Hg suggests that Hg in sulfides was mainly derived from the underlying metamorphic basement. Mercury isotopes could be a geochemical tracer in understanding metal sources in hydrothermal ore deposits.

2D seismic interpretation and characterization of the Hauterivian-Early Barremian source rock in Al Baraka oil field, Komombo Basin, Upper Egypt

NASA Astrophysics Data System (ADS)

Ali, Moamen; Darwish, M.; Essa, Mahmoud A.; Abdelhady, A.

2018-03-01

Komombo Basin is located in Upper Egypt about 570 km southeast of Cairo; it is an asymmetrical half graben and the first oil producing basin in Upper Egypt. The Six Hills Formation is of Early Cretaceous age and subdivided into seven members from base to top (A-G); meanwhile the B member is of Hauterivian-Early Barremian and it is the only source rock of Komombo Basin. Therefore, a detailed study of the SR should be carried out, which includes the determination of the main structural elements, thickness, facies distribution and characterization of the B member SR which has not been conducted previously in the study area. Twenty 2D seismic lines were interpreted with three vertical seismic profiles (VSP) to construct the depth structure-tectonic map on the top of the B member and to highlight the major structural elements. The interpretation of depth structure contour map shows two main fault trends directed towards the NW-SE and NE to ENE directions. The NW-SE trend is the dominant one, creating a major half-graben system. Also the depth values range from -8400 ft at the depocenter in the eastern part to -4800 ft at the shoulder of the basin in the northwestern part of the study area. Meanwhile the Isopach contour map of the B member shows a variable thickness ranging between 300 ft to 750 ft. The facies model shows that the B member SR is composed mainly of shale with some sandstone streaks. The B member rock samples were collected from Al Baraka-1 and Al Baraka SE-1 in the eastern part of Komombo Basin. The results indicate that the organic matter content (TOC) has mainly good to very good (1-3.36 wt %), The B member samples have HI values in the range 157-365 (mg HC/g TOC) and dominated by Type II/III kerogen, and is thus considered to be oil-gas prone based on Rock-Eval pyrolysis, Tmax values between 442° and 456° C therefore interpreted to be mature for hydrocarbon generation. Based on the measured vitrinite equivalent reflectance values, the B member SR samples have a range 0.7-1.14%Ro, in the oil generation window.

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.

Myosin IXa Regulates Epithelial Differentiation and Its Deficiency Results in Hydrocephalus

PubMed Central

Abouhamed, Marouan; Grobe, Kay; Leefa Chong San, Isabelle V.; Thelen, Sabine; Honnert, Ulrike; Balda, Maria S.; Matter, Karl

2009-01-01

The ependymal multiciliated epithelium in the brain restricts the cerebrospinal fluid to the cerebral ventricles and regulates its flow. We report here that mice deficient for myosin IXa (Myo9a), an actin-dependent motor molecule with a Rho GTPase–activating (GAP) domain, develop severe hydrocephalus with stenosis and closure of the ventral caudal 3rd ventricle and the aqueduct. Myo9a is expressed in maturing ependymal epithelial cells, and its absence leads to impaired maturation of ependymal cells. The Myo9a deficiency further resulted in a distorted ependyma due to irregular epithelial cell morphology and altered organization of intercellular junctions. Ependymal cells occasionally delaminated, forming multilayered structures that bridged the CSF-filled ventricular space. Hydrocephalus formation could be significantly attenuated by the inhibition of the Rho-effector Rho-kinase (ROCK). Administration of ROCK-inhibitor restored maturation of ependymal cells, but not the morphological distortions of the ependyma. Similarly, down-regulation of Myo9a by siRNA in Caco-2 adenocarcinoma cells increased Rho-signaling and induced alterations in differentiation, cell morphology, junction assembly, junctional signaling, and gene expression. Our results demonstrate that Myo9a is a critical regulator of Rho-dependent and -independent signaling mechanisms that guide epithelial differentiation. Moreover, Rho-kinases may represent a new target for therapeutic intervention in some forms of hydrocephalus. PMID:19828736

Maturity of nearby faults influences seismic hazard from hydraulic fracturing.

PubMed

Kozłowska, Maria; Brudzinski, Michael R; Friberg, Paul; Skoumal, Robert J; Baxter, Nicholas D; Currie, Brian S

2018-02-20

Understanding the causes of human-induced earthquakes is paramount to reducing societal risk. We investigated five cases of seismicity associated with hydraulic fracturing (HF) in Ohio since 2013 that, because of their isolation from other injection activities, provide an ideal setting for studying the relations between high-pressure injection and earthquakes. Our analysis revealed two distinct groups: ( i ) deeper earthquakes in the Precambrian basement, with larger magnitudes (M > 2), b-values < 1, and many post-shut-in earthquakes, versus ( ii ) shallower earthquakes in Paleozoic rocks ∼400 m below HF, with smaller magnitudes (M < 1), b-values > 1.5, and few post-shut-in earthquakes. Based on geologic history, laboratory experiments, and fault modeling, we interpret the deep seismicity as slip on more mature faults in older crystalline rocks and the shallow seismicity as slip on immature faults in younger sedimentary rocks. This suggests that HF inducing deeper seismicity may pose higher seismic hazards. Wells inducing deeper seismicity produced more water than wells with shallow seismicity, indicating more extensive hydrologic connections outside the target formation, consistent with pore pressure diffusion influencing seismicity. However, for both groups, the 2 to 3 h between onset of HF and seismicity is too short for typical fluid pressure diffusion rates across distances of ∼1 km and argues for poroelastic stress transfer also having a primary influence on seismicity.

Maturity of nearby faults influences seismic hazard from hydraulic fracturing

NASA Astrophysics Data System (ADS)

Kozłowska, Maria; Brudzinski, Michael R.; Friberg, Paul; Skoumal, Robert J.; Baxter, Nicholas D.; Currie, Brian S.

2018-02-01

Understanding the causes of human-induced earthquakes is paramount to reducing societal risk. We investigated five cases of seismicity associated with hydraulic fracturing (HF) in Ohio since 2013 that, because of their isolation from other injection activities, provide an ideal setting for studying the relations between high-pressure injection and earthquakes. Our analysis revealed two distinct groups: (i) deeper earthquakes in the Precambrian basement, with larger magnitudes (M > 2), b-values < 1, and many post–shut-in earthquakes, versus (ii) shallower earthquakes in Paleozoic rocks ˜400 m below HF, with smaller magnitudes (M < 1), b-values > 1.5, and few post–shut-in earthquakes. Based on geologic history, laboratory experiments, and fault modeling, we interpret the deep seismicity as slip on more mature faults in older crystalline rocks and the shallow seismicity as slip on immature faults in younger sedimentary rocks. This suggests that HF inducing deeper seismicity may pose higher seismic hazards. Wells inducing deeper seismicity produced more water than wells with shallow seismicity, indicating more extensive hydrologic connections outside the target formation, consistent with pore pressure diffusion influencing seismicity. However, for both groups, the 2 to 3 h between onset of HF and seismicity is too short for typical fluid pressure diffusion rates across distances of ˜1 km and argues for poroelastic stress transfer also having a primary influence on seismicity.

The mesoproterozoic midcontinent rift system, Lake Superior region, USA

USGS Publications Warehouse

Ojakangas, R.W.; Morey, G.B.; Green, J.C.

2001-01-01

Exposures in the Lake Superior region, and associated geophysical evidence, show that a 2000 km-long rift system developed within the North American craton ??? 1109-1087 Ma, the age span of the most of the volcanic rocks. This system is characterized by immense volumes of mafic igneous rocks, mostly subaerial plateau basalts, generated in two major pulses largely by a hot mantle plume. A new ocean basin was nearly formed before rifting ceased, perhaps due to the remote effect of the Grenville continental collision to the east. Broad sagging/subsidence, combined with a system of axial half-grabens separated along the length of the rift by accommodation zones, provided conditions for the accumulation of as much as 20 km of volcanic rocks and as much as 10 km of post-rift clastic sediments, both along the rift axis and in basins flanking a central, post-volcanic horst. Pre-rift mature, quartzose sandstones imply little or no uplift prior to the onset of rift volcanism. Early post-rift red-bed sediments consist almost entirely of intrabasinally derived volcanic sediment deposited in alluvial fan to fluvial settings; the exception is one gray to black carbon-bearing lacustrine(?) unit. This early sedimentation phase was followed by broad crustal sagging and deposition of progressively more mature red-bed, fluvial sediments with an extra-basinal provenance. ?? 2001 Elsevier Science B.V. All rights reserved.

A geothermal AMTEC system

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

Schuller, M.J.; LeMire, R.A.; Horner-Richardson, K.

1995-12-31

The Phillips Laboratory Power and Thermal Management Division (PL/VTP), with the support of ORION International Technologies, is investigating new methods of advanced thermal to electric power conversion for space and terrestrial applications. The alkali metal thermal-to-electric converter (AMTEC), manufactured primarily by Advanced Modular Power Systems (AMPS) of Ann Arbor, MI, has reached a level of technological maturity which would allow its use in a constant, unattended thermal source, such as a geothermal field. Approximately 95,000 square miles in the western United States has hot dry rock with thermal gradients of 60 C/km and higher. Several places in the United Statesmore » and the world have thermal gradients of 500 C/km. Such heat sources represent an excellent thermal source for a system of modular power units using AMTEC devices to convert the heat to electricity. AMTEC cells using sodium as a working fluid require heat input at temperatures between 500 and 1,000 C to generate power. The present state of the art is capable of 15% efficiency with 800 C heat input and has demonstrated 18% efficiency for single cells. This paper discusses the basics of AMTEC operation, current drilling technology as a cost driver, design of modular AMTEC power units, heat rejection technologies, materials considerations, and estimates of power production from a geothermal AMTEC concept.« 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.

Reservoir and Source Rock Identification Based on Geologycal, Geophysics and Petrophysics Analysis Study Case: South Sumatra Basin

NASA Astrophysics Data System (ADS)

Anggit Maulana, Hiska; Haris, Abdul

2018-05-01

Reservoir and source rock Identification has been performed to deliniate the reservoir distribution of Talangakar Formation South Sumatra Basin. This study is based on integrated geophysical, geological and petrophysical data. The aims of study to determine the characteristics of the reservoir and source rock, to differentiate reservoir and source rock in same Talangakar formation, to find out the distribution of net pay reservoir and source rock layers. The method of geophysical included seismic data interpretation using time and depth structures map, post-stack inversion, interval velocity, geological interpretations included the analysis of structures and faults, and petrophysical processing is interpret data log wells that penetrating Talangakar formation containing hydrocarbons (oil and gas). Based on seismic interpretation perform subsurface mapping on Layer A and Layer I to determine the development of structures in the Regional Research. Based on the geological interpretation, trapping in the form of regional research is anticline structure on southwest-northeast trending and bounded by normal faults on the southwest-southeast regional research structure. Based on petrophysical analysis, the main reservoir in the field of research, is a layer 1,375 m of depth and a thickness 2 to 8.3 meters.

Publications - GMC 209 | Alaska Division of Geological & Geophysical

Science.gov Websites

DGGS GMC 209 Publication Details Title: Source rock potential and geochemical characterization of OCS Y Reference DGSI, Inc., 1993, Source rock potential and geochemical characterization of OCS Y-0943-1 (Aurora

Impact of dia- and catagenesis on sulphur and oxygen sequestration of biomarkers as revealed by artificial maturation of an immature sedimentary rock

USGS Publications Warehouse

Koopmans, M.P.; De Leeuw, J. W.; Lewan, M.D.; Sinninghe, Damste J.S.

1996-01-01

Hydrous pyrolysis of an immature (R(a)??? 0.25%) sulphur-rich marl from the Gessoso-solfifera Formation (Messinian) in the Vena del Gesso Basin was carried out at 160C ??? T ???330 C for 72 h, to study the effect of progressive diagenesis and early catagenesis on the abundance and distribution of sulphur-containing and sulphur- and oxygen-linked carbon skeletons in low-molecular-weight and highmolecular-weight fractions (e.g. kerogen). To this end, compounds in the saturated hydrocarbon fraction, monoaromatic hydrocarbon fraction, polyaromatic hydrocarbon fraction, alkylsulphide fraction and ketone fraction were quantified, as well as compounds released after desulphurisation of the polar fraction and HI/LiAIH4 treatment of the desulphurised polar fraction. Sulphur-bound phytane and (20R)-5??,14??,17??(H) and (20R)-5??,14??,17??(H) C27 C29 steranes in the polar fraction become less abundant with increasing maturation temperature, whereas the amount of their corresponding hydrocarbons increases in the saturated hydrocarbon fraction. Carbon skeletons that are bound in the kerogen by multiple bonds (e.g. C38 n-alkane and isorenieratane) are first released into the polar fraction, and then as free hydrocarbons. These changes occur at relatively low levels of thermal maturity (R(a) <0.6%), as evidenced by the 'immature' values of biomarker maturity parameters such as the ????/(????+ ???? + ????) C35 hopane ratio and the 22S/(22S + 22R)-17??,21??(H) C35 hopane ratio. Sulphur- and oxygen-bound moieties, present in the polar fraction, are not stable with increasing thermal maturation. However, alkylthiophenes, ketones. 1,2-di-n-alkylbenzenes and free n-alkanes seem to be stable thermal degradation products of these sulphur- and oxygen-bound moieties. Thus, apart from free n-alkanes, which are abundantly present in more mature sedimentary rocks and crude oils, alkylthiophenes, 1,2-di-n-alkylbenzenes and ketones can also be expected to occur. The positions of the thiophene moiety and the carbonyl group coincide with the original positions of the functional groups of their precursors. Thus, important information about palaeobiochemicals is retained throughout the sequestration/degradation process.

Vitrinite reflectance data for the Permian Basin, west Texas and southeast New Mexico

USGS Publications Warehouse

Pawlewicz, Mark; Barker, Charles E.; McDonald, Sargent

2005-01-01

This report presents a compilation of vitrinite reflectance (Ro) data based on analyses of samples of drill cuttings collected from 74 boreholes spread throughout the Permian Basin of west Texas and southeast New Mexico (fig. 1). The resulting data consist of 3 to 24 individual Ro analyses representing progressively deeper stratigraphic units in each of the boreholes (table 1). The samples, Cambrian-Ordovician to Cretaceous in age, were collected at depths ranging from 200 ft to more than 22,100 ft.The R0 data were plotted on maps that depict three different maturation levels for organic matter in the sedimentary rocks of the Permian Basin (figs. 2-4). These maps show depths at the various borehole locations where the R0 values were calculated to be 0.6 (fig. 2), 1.3 (fig. 3), and 2.0 (fig. 4) percent, which correspond, generally, to the onset of oil generation, the onset of oil cracking, and the limit of oil preservation, respectively.The four major geologic structural features within the Permian Basin–Midland Basin, Delaware Basin, Central Basin Platform, and Northwest Shelf (fig. 1) differ in overall depth, thermal history and tectonic style. In the western Delaware Basin, for example, higher maturation is observed at relatively shallow depths, resulting from uplift and eastward basin tilting that began in the Mississippian and ultimately exposed older, thermally mature rocks. Maturity was further enhanced in this basin by the emplacement of early and mid-Tertiary intrusives. Volcanic activity also appears to have been a controlling factor for maturation of organic matter in the southern part of the otherwise tectonically stable Northwest Shelf (Barker and Pawlewicz, 1987). Depths to the three different Ro values are greatest in the eastern Delaware Basin and southern Midland Basin. This appears to be a function of tectonic activity related to the Marathon-Ouachita orogeny, during the Late-Middle Pennsylvanian, whose affects were widespread across the Permian Basin. The Central Basin Platform has been a positive feature since the mid to-late Paleozoic, during which time sedimentation occurred along its flanks. This nonsubsidence, along with the lack of supplemental heating (volcanism), implies lower maturation levels.

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

A feasibility study of prepubertal and over mature aged local goat in relation to results of In Vitro growth culture to obtain additional M-II oocyte resources

NASA Astrophysics Data System (ADS)

Ciptadi, Gatot; Ihsan, M. Nur; Rahayu, Sri; Widjaja, D. H. K.; Mudawamah, Mudawamah

2017-11-01

The aims of this research are to study the potential source of mature (M-II) oocytes of domestic animals using follicles isolated from prepubertal and over mature aged Indonesian local goats, resulting from an in vitro growth (IVG) method. This method of IVG could provide a new source of M-II oocytes for embryo production. In Indonesia, a very limited number of a good quality oocytes are available for research purposes, as there is a limited number of reproductive females slaughtered, which is dominated by prepubertal and old mature aged animals. IVG culture systems could be improved as an alternative method to provide a new source of a good quality oocytes for in vitro maturation of M-II oocytes. From a number of prepubertal and mature aged goats slaughtered in a local abattoir, the small oocytes in the preantral follicles were cultured in vitro to normal oocyte growth. The methods used in this research are experimental. Follicles were isolated, cultured in vitro for 14 days individually using a sticky medium containing 4% (w/v) polyvinylpyrrolidone in TCM 199 10% Fetal Bovine Serum supplemented with Follicle Stimulating Hormone, which was then evaluated for their follicle development and oocyte quality. The research results showed that a minimum follicle size and oocyte diameter is needed (>100 um) for early evaluation of maturation to be achieved, meanwhile oocytes recovered from IVG after being cultured in vitro for maturation resulted in a very low rate of maturation. However, in the future, IVG of the preantral follicles of Indonesian local goat could be considered as an alternative source of oocytes for both research purposes and embryo production in vitro.

Evaluation of kinetic uncertainty in numerical models of petroleum generation

USGS Publications Warehouse

Peters, K.E.; Walters, C.C.; Mankiewicz, P.J.

2006-01-01

Oil-prone marine petroleum source rocks contain type I or type II kerogen having Rock-Eval pyrolysis hydrogen indices greater than 600 or 300-600 mg hydrocarbon/g total organic carbon (HI, mg HC/g TOC), respectively. Samples from 29 marine source rocks worldwide that contain mainly type II kerogen (HI = 230-786 mg HC/g TOC) were subjected to open-system programmed pyrolysis to determine the activation energy distributions for petroleum generation. Assuming a burial heating rate of 1??C/m.y. for each measured activation energy distribution, the calculated average temperature for 50% fractional conversion of the kerogen in the samples to petroleum is approximately 136 ?? 7??C, but the range spans about 30??C (???121-151??C). Fifty-two outcrop samples of thermally immature Jurassic Oxford Clay Formation were collected from five locations in the United Kingdom to determine the variations of kinetic response for one source rock unit. The samples contain mainly type I or type II kerogens (HI = 230-774 mg HC/g TOC). At a heating rate of 1??C/m.y., the calculated temperatures for 50% fractional conversion of the Oxford Clay kerogens to petroleum differ by as much as 23??C (127-150??C). The data indicate that kerogen type, as defined by hydrogen index, is not systematically linked to kinetic response, and that default kinetics for the thermal decomposition of type I or type II kerogen can introduce unacceptable errors into numerical simulations. Furthermore, custom kinetics based on one or a few samples may be inadequate to account for variations in organofacies within a source rock. We propose three methods to evaluate the uncertainty contributed by kerogen kinetics to numerical simulations: (1) use the average kinetic distribution for multiple samples of source rock and the standard deviation for each activation energy in that distribution; (2) use source rock kinetics determined at several locations to describe different parts of the study area; and (3) use a weighted-average method that combines kinetics for samples from different locations in the source rock unit by giving the activation energy distribution for each sample a weight proportional to its Rock-Eval pyrolysis S2 yield (hydrocarbons generated by pyrolytic degradation of organic matter). Copyright ?? 2006. The American Association of Petroleum Geologists. All rights reserved.

A four-dimensional petroleum systems model for the San Joaquin Basin Province, California: Chapter 12 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.; Lampe, Carolyn; Scheirer, Allegra Hosford; Lillis, Paul G.; Gautier, Donald L.

2008-01-01

A calibrated numerical model depicts the geometry and three-dimensional (3-D) evolution of petroleum systems through time (4-D) in a 249 x 309 km (155 x 192 mi) area covering all of the San Joaquin Basin Province of California. Model input includes 3-D structural and stratigraphic data for key horizons and maps of unit thickness, lithology, paleobathymetry, heat flow, original total organic carbon, and original Rock-Eval pyrolysis hydrogen index for each source rock. The four principal petroleum source rocks in the basin are the Miocene Antelope shale of Graham and Williams (1985; hereafter referred to as Antelope shale), the Eocene Kreyenhagen Formation, the Eocene Tumey formation of Atwill (1935; hereafter referred to as Tumey formation), and the Cretaceous to Paleocene Moreno Formation. Due to limited Rock-Eval/total organic carbon data, the Tumey formation was modeled using constant values of original total organic carbon and original hydrogen index. Maps of original total organic carbon and original hydrogen index were created for the other three source rocks. The Antelope shale was modeled using Type IIS kerogen kinetics, whereas Type II kinetics were used for the other source rocks. Four-dimensional modeling and geologic field evidence indicate that maximum burial of the three principal Cenozoic source rocks occurred in latest Pliocene to Holocene time. For example, a 1-D extraction of burial history from the 4-D model in the Tejon depocenter shows that the bottom of the Antelope shale source rock began expulsion (10 percent transformation ratio) about 4.6 Ma and reached peak expulsion (50 percent transformation ratio) about 3.6 Ma. Except on the west flank of the basin, where steep dips in outcrop and seismic data indicate substantial uplift, little or no section has been eroded. Most petroleum migration occurred during late Cenozoic time in distinct stratigraphic intervals along east-west pathways from pods of active petroleum source rock in the Tejon and Buttonwillow depocenters to updip sandstone reservoirs. Satisfactory runs of the model required about 18 hours of computation time for each simulation using parallel processing on a Linux-based cluster.

Publications - GMC 54 | Alaska Division of Geological & Geophysical Surveys

Science.gov Websites

DGGS GMC 54 Publication Details Title: Source rock evaluation/TAI for ARCO Itkillik River Unit #1 information. Bibliographic Reference Texaco, Inc., [n.d.], Source rock evaluation/TAI for ARCO Itkillik River

Publications - GMC 249 | Alaska Division of Geological & Geophysical

Science.gov Websites

DGGS GMC 249 Publication Details Title: Source rock geochemical and visual kerogen data from cuttings Reference Unknown, 1995, Source rock geochemical and visual kerogen data from cuttings (2,520-8,837') of the

Changes in polyphenolics during maturation of Java plum (Syzygium cumini Lam.).

PubMed

Lestario, Lydia Ninan; Howard, Luke R; Brownmiller, Cindi; Stebbins, Nathan B; Liyanage, Rohana; Lay, Jackson O

2017-10-01

Java plum (Syzygium cumini Lam.) is a rich source of polyphenolics with many purported health benefits, but the effect of maturation on polyphenolic content is unknown. Freeze-dried samples of Java plum from seven different maturity stages were analyzed for anthocyanin, flavonol, flavanonol and hydrolysable tannin composition by HPLC. Anthocyanins were first detected at the green-pink stage of maturity and increased throughout maturation with the largest increase occurring from the dark purple to black stages of maturation. Levels of gallotannins, ellagitannins, flavonols, gallic acid and ellagic acid were highest at early stages of maturation and decreased as the fruit ripened. For production of antioxidant-rich nutraceutical ingredients, fruit should be harvested immature to obtain extracts rich in hydrolysable tannins and flavonols. The exceptional anthocyanin content of black fruit may prove useful as a source of a natural colorant. Copyright © 2017 Elsevier Ltd. All rights reserved.

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.

Advances in carbonate exploration and reservoir analysis

USGS Publications Warehouse

Garland, J.; Neilson, J.; Laubach, S.E.; Whidden, Katherine J.

2012-01-01

The development of innovative techniques and concepts, and the emergence of new plays in carbonate rocks are creating a resurgence of oil and gas discoveries worldwide. The maturity of a basin and the application of exploration concepts have a fundamental influence on exploration strategies. Exploration success often occurs in underexplored basins by applying existing established geological concepts. This approach is commonly undertaken when new basins ‘open up’ owing to previous political upheavals. The strategy of using new techniques in a proven mature area is particularly appropriate when dealing with unconventional resources (heavy oil, bitumen, stranded gas), while the application of new play concepts (such as lacustrine carbonates) to new areas (i.e. ultra-deep South Atlantic basins) epitomizes frontier exploration. Many low-matrix-porosity hydrocarbon reservoirs are productive because permeability is controlled by fractures and faults. Understanding basic fracture properties is critical in reducing geological risk and therefore reducing well costs and increasing well recovery. The advent of resource plays in carbonate rocks, and the long-standing recognition of naturally fractured carbonate reservoirs means that new fracture and fault analysis and prediction techniques and concepts are essential.

Mineralogy and source rock evaluation of the marine Oligo-Miocene sediments in some wells in the Nile Delta and North Sinai, Egypt

NASA Astrophysics Data System (ADS)

El sheikh, Hassan; Faris, Mahmoud; Shaker, Fatma; Kumral, Mustafa

2016-06-01

This paper aims to study the mineralogical composition and determine the petroleum potential of source rocks of the Oligocene-Miocene sequence in the Nile Delta and North Sinai districts. The studied interval in the five wells can be divided into five rock units arranged from the top to base; Qawasim, Sidi Salem, Kareem, Rudeis, and Qantara formations. The bulk rock mineralogy of the samples was investigated using X-Ray Diffraction technique (XRD). The results showed that the sediments of the Nile Delta area are characterized by the abundance of quartz and kaolinite with subordinate amounts of feldspars, calcite, gypsum, dolomite, and muscovite. On the other hand, the data of the bulk rock analysis at the North Sinai wells showed that kaolinite, quartz, feldspar and calcite are the main constituents associated with minor amounts of dolomite, gypsum, mica, zeolite, and ankerite. Based on the organic geochemical investigations (TOC and Rock-Eval pyrolysis analyses), all studied formations in both areas are thermally immature but in the Nile delta area, Qawasim, Sidi Salem and Qantara formations (El-Temsah-2 Well) are organically-rich and have a good petroleum potential (kerogen Type II-oil-prone), while Rudeis Formation is a poor petroleum potential source rock (kerogen Type III-gas-prone). In the North Sinai area, Qantara Formation has a poor petroleum potential (kerogen Type III-gas-prone) and Sidi Salem Formation (Bardawil-1 Well) is a good petroleum potential source rock (kerogen Type II-oil-prone).

Source rock potential of an Eocene carbonate slope: The Armancies Formation of the south-Pyrenean basin, northeast Spain

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

Permanyer, A.; Valles, D.; Dorronsorro, C.

1988-08-01

The Armancies Formation is an Eocene carbonate slope succession in the Catalonian South Pyrenean basin. It ranges from 500 to 700 m in thickness. The first 200 m are made of a thin-bedded facies of wackestones alternating with dark pelagic fauna of miliolid, ostracods, bryozoans, and planktonic foraminifers and show significant bioturbation. They also show a low organic content (< 0.5% TOC). The lime-mudstone beds show a massive structure or planar millimeter laminations. They may contain sparse pelagic fossils of planktonic foraminifers, ostracods, and dinoflagellates; they do not show any bioturbation, and have high TOC values, which can reach individualmore » scores of about 14%. They qualify, therefore, as a typical oil shale. Rock-Eval Pyrolysis analysis affords a mean S{sub 2} value of 25 mg HC/g. Mean S{sub 1} value is around 1.0 mg HC/g. As is typical of an initial oil window, T{sub max} maturity parameter ranges from 432 to 440{degree}C (mean = 434{degree}C). This degree of evolution is in accordance with the very low value of carbonyl and carboxyl groups, as determined by IR spectrometry and NMR on Fischer assay extract. The proton NMR shows an aromatic/aliphatic hydrocarbon ratio of 1:4, as expected in earlier stages of catagenesis. N-alkane gas chromatography profiles show n-C{sub 15} to n-C{sub 19} prevalence and that neither even nor odd carbon numbers prevail. This distribution perfectly matches that of typical sediments of marine origin and also agrees with obtained hydrogen index values (mean HI = 500 mg HC/g TOC). Sedimentological and geochemical results indicate an autochthonous marine organic matter and the potential of these slope shales is good oil-prone source beds.« less

Seismic based characterization of total organic content from the marine Sembar shale, Lower Indus Basin, Pakistan

NASA Astrophysics Data System (ADS)

Aziz, Omer; Hussain, Tahir; Ullah, Matee; Bhatti, Asher Samuel; Ali, Aamir

2018-02-01

The exploration and production of unconventional resources has increased significantly over the past few years around the globe to fulfill growing energy demands. Hydrocarbon potential of these unconventional petroleum systems depends on the presence of significant organic matter; their thermal maturity and the quality of present hydrocarbons i.e. gas or oil shale. In this work, we present a workflow for estimating Total Organic Content (TOC) from seismic reflection data. To achieve the objective of this study, we have chosen a classic potential candidate for exploration of unconventional reserves, the shale of the Sembar Formation, Lower Indus Basin, Pakistan. Our method includes the estimation of TOC from the well data using the Passey's ΔlogR and Schwarzkofp's methods. From seismic data, maps of Relative Acoustic Impedance (RAI) are extracted at maximum and minimum TOC zones within the Sembar Formation. A geostatistical trend with good correlation coefficient (R2) for cross-plots between TOC and RAI at well locations is used for estimation of seismic based TOC at the reservoir scale. Our results suggest a good calibration of TOC values from seismic at well locations. The estimated TOC values range from 1 to 4% showing that the shale of the Sembar Formation lies in the range of good to excellent unconventional oil/gas play within the context of TOC. This methodology of source rock evaluation provides a spatial distribution of TOC at the reservoir scale as compared to the conventional distribution generated from samples collected over sparse wells. The approach presented in this work has wider applications for source rock evaluation in other similar petroliferous basins worldwide.

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

40 CFR 60.401 - Definitions.

Code of Federal Regulations, 2011 CFR

2011-07-01

... PERFORMANCE FOR NEW STATIONARY SOURCES Standards of Performance for Phosphate Rock Plants § 60.401 Definitions. (a) Phosphate rock plant means any plant which produces or prepares phosphate rock product by any or..., calcining, and grinding. (b) Phosphate rock feed means all material entering the process unit, including...

40 CFR 60.401 - Definitions.

Code of Federal Regulations, 2012 CFR

2012-07-01

... PERFORMANCE FOR NEW STATIONARY SOURCES Standards of Performance for Phosphate Rock Plants § 60.401 Definitions. (a) Phosphate rock plant means any plant which produces or prepares phosphate rock product by any or..., calcining, and grinding. (b) Phosphate rock feed means all material entering the process unit, including...

40 CFR 60.401 - Definitions.

Code of Federal Regulations, 2013 CFR

2013-07-01

... PERFORMANCE FOR NEW STATIONARY SOURCES Standards of Performance for Phosphate Rock Plants § 60.401 Definitions. (a) Phosphate rock plant means any plant which produces or prepares phosphate rock product by any or..., calcining, and grinding. (b) Phosphate rock feed means all material entering the process unit, including...

40 CFR 60.401 - Definitions.

Code of Federal Regulations, 2014 CFR

2014-07-01

... PERFORMANCE FOR NEW STATIONARY SOURCES Standards of Performance for Phosphate Rock Plants § 60.401 Definitions. (a) Phosphate rock plant means any plant which produces or prepares phosphate rock product by any or..., calcining, and grinding. (b) Phosphate rock feed means all material entering the process unit, including...

Identification of sulfur sources and isotopic equilibria in submarine hot-springs using multiple sulfur isotopes

NASA Astrophysics Data System (ADS)

McDermott, Jill M.; Ono, Shuhei; Tivey, Margaret K.; Seewald, Jeffrey S.; Shanks, Wayne C.; Solow, Andrew R.

2015-07-01

Multiple sulfur isotopes were measured in metal sulfide deposits, elemental sulfur, and aqueous hydrogen sulfide to constrain sulfur sources and the isotopic systematics of precipitation in seafloor hydrothermal vents. Areas studied include the Eastern Manus Basin and Lau Basin back-arc spreading centers and the unsedimented basalt-hosted Southern East Pacific Rise (SEPR) and sediment-hosted Guaymas Basin mid-ocean ridge spreading centers. Chalcopyrite and dissolved hydrogen sulfide (H2S) δ34S values range from -5.5‰ to +5.6‰ in Manus Basin samples, +2.4‰ to +6.1‰ in Lau Basin samples, and +3.7‰ to +5.7‰ in SEPR samples. Values of δ34S for cubic cubanite and H2S range from -1.4‰ to +4.7‰ in Guaymas Basin samples. Multiple sulfur isotope systematics in fluid-mineral pairs from the SEPR and Lau Basin show that crustal host rock and thermochemical reduction of seawater-derived dissolved sulfate (SO4) are the primary sources of sulfur in mid-ocean ridge and some back-arc systems. At PACMANUS and SuSu Knolls hydrothermal systems in the Eastern Manus Basin, a significant contribution of sulfur is derived from disproportionation of magmatic sulfur dioxide (SO2), while the remaining sulfur is derived from crustal host rocks and SO4 reduction. At the sedimented Guaymas Basin hydrothermal system, sulfur sources include crustal host rock, reduced seawater SO4, and biogenic sulfide. Vent fluid flow through fresher, less-mature sediment supplies an increased quantity of reactant organic compounds that may reduce 34S-enriched SO4, while fluid interaction with more highly-altered sediments results in H2S characterized by a small, but isotopically-significant input of 34S-depleted biogenic sulfides. Near-zero Δ33S values in all samples implicate the abiotic processes of SO4 reduction and leaching of host rock as the major contributors to sulfur content at a high temperature unsedimented mid-ocean ridge and at a back-arc system. Δ33S values indicate that SO2 disproportionation is an additional process that contributes sulfur to a different back-arc system and to acid spring-type hydrothermal fluid circulation. At the sedimented Guaymus Basin, near-zero Δ33S values are also observed, despite negative δ34S values that indicate inputs of biogenic pyrite for some samples. In contrast with previous studies reporting isotope disequilibrium between H2S and chalcopyrite, the δ34S values of chalcopyrite sampled from the inner 1-2 mm of a chimney wall are within ±1‰ of δ34S values for H2S in the paired vent fluid, suggesting equilibrium fluid-mineral sulfur isotope exchange at 300-400 °C. Isotopic equilibrium between hydrothermal fluid H2S and precipitating chalcopyrite implies that sulfur isotopes in the chalcopyrite lining across a chimney wall may accurately record past hydrothermal activity.

Discrepancies between anomalously low reflectance of vitrinite and other maturation indicators from an upper Miocene oil source rock, Los Angeles basin, California

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

Walker, A.L.; McCulloch, T.H.; Petersen, N.F.

1983-03-01

Forty-four subsurface samples of the nodular shale were collected from 14 selected wells located mostly between the Playa del Rey and Crescent Heights oil fields. Sites were selected to give the widest available range of sample depth and temperature where present burial depths are maximal, and where geothermal gradients are firmly established. Median random reflectance (%R/sub 0/) of first-cycle vitrinite is least in the shallowest samples, clusters about 0.24% in the deeper samples, and exceeds 0.30% only in the deepest and hottest samples. Extremes in the range of measured median %R/sub 0/ are tabulated below with corresponding extremes of samplemore » temperatures, depths, Time-Temperature Indices (TTI), and calculated %R/sub 0/ equivalents of the TTI values. All measured values of R/sub 0/ are significantly depressed compared to other maturity criteria. Significantly, second-cycle and oxidized vitrinite from these same samples show normally elevated reflectance. Eight of the samples processed for reflectance measurements were analyzed for total organic carbon content, which ranges from 2.21 to 9.41%. Most of the organic detritus is amorphous degraded algal material; less than 10% is structured vitrinite. Thermal alteration index values for the amorphous material range from 2 to 2 1/2, corresponding with hypothetical conversion R/sub 0/ values between 0.45 and 0.75%, again notably higher than the measured values. The ratios of extractable hydrocarbons to TOC in the 8 samples suggest mature levels of thermal evolution, as do carbon preference indices of 0.93 and 1.14 from extracts of 2 samples.« less

Jurassic Paleolatitudes, Paleogeography, and Climate Transitions In the Mexican Subcontinen

NASA Astrophysics Data System (ADS)

Molina-Garza, R. S.; Geissman, J. W.; Lawton, T. F.

2014-12-01

Jurassic northward migration of Mexico, trailing the North America plate, resulted in temporal evolution of climate-sensitive depositional environments. Lower-Middle Jurassic rocks in central Mexico contain a record of warm-humid conditions, which are indicated by coal and compositionally mature sandstone deposited in continental environments. Preliminary paleomagnetic data indicate that these rocks were deposited at near-equatorial paleolatitudes. The Middle Jurassic (ca. 170 Ma) Diquiyú volcanic sequence in central Oaxaca give an overall mean of D=82.2º/ I= +4.1º (n=10; k=17.3, α95=12º). In the Late Jurassic, the Gulf of Mexico formed as a subsidiary basin of the Atlantic Ocean, when the supercontinent Pangaea ruptured. Upper Jurassic strata, including eolianite and widespread evaporite deposits, across Mexico indicate dry-arid conditions. Available paleomagnetic data (compaction-corrected) from eolianites in northeast Mexico indicate deposition at ~15-20ºN. As North America moved northward during Jurassic opening of the Atlantic, different latitudinal regions experienced coeval Late Jurassic climatic shifts. Climate transitions have been widely recognized in the Colorado plateau region. The plateau left the horse-latitudes in the late Middle Jurassic to reach temperate humid climates at ~40ºN in the latest Jurassic. In turn, the southern end of the North America plate (central Mexico) reached arid horse-latitudes in the Late Jurassic. At that time, epeiric platforms developed in the circum-Gulf region after a long period of margin extension. We suggest that Upper Jurassic hydrocarbon source rocks in the circum-Gulf region accumulated on these platforms as warm epeiric hypersaline seas and the Gulf of Mexico itself were fertilized by an influx of wind-blown silt from continental regions. Additional nutrients were brought to shallow zones of photosynthesis by ocean upwelling driven by changes in the continental landmass configuration.

Tectonic framework of northeast Egypt and its bearing on hydrocarbon exploration

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

Khalil, M.; Moustafa, A.R.

1995-08-01

Detailed structural study of northern and central Sinai, the northern Eastern Desert, and the northern Gulf of Suez clarified the tectonic framework of northeast Egypt. This framework is related to the movements between the African Plate and the Eurasian and Arabian Plates. Late Cretaceous folding and thrusting in response to oblique convergence between the African and Eurasian Plates formed NE-ENE oriented, doubly plunging, en echelon folds of the northern Egypt fold belt. This fold belt is well exposed in northern Sinai and a few other places but is concealed under younger sediments in the other parts of northern Egypt. Youngermore » folding of local importance is related to dextral slip on the Themed Fault (Central Sinai) in post Middle Eocene-pre Miocene time. Early Miocene rifting of the Afro-Arabian Plate led to the opening of the Suez rift and deposition of significant syn-rift facies. Half grabens and tilted fault blocks dominate the rift. Slightly tilted fault blocks characterize the competent Middle Eocene limestones of the Eastern Desert south of the Cairo-Suez road but north of this road, Middle Eocene rocks are locally dragged on nearby E-W and NW-SE oriented faults forming fault-drag folds. Ductile Upper Eocene and Miocene rocks are also folded about gentle NW-SE oriented doubly plunging folds. The different stages of tectonic activity in northern Egypt contributed to the development of different types of structural traps as well as different source, reservoir, and cap rocks. The sedimentary history of the region indicates well developed marine sediments of Jurassic, Cretaceous, Eocene, and Miocene ages. Basin development in structurally low areas provided good sites for hydrocarbon generation and maturation.« less

Noble gases fingerprint a metasedimentary fluid source in the Macraes orogenic gold deposit, New Zealand

NASA Astrophysics Data System (ADS)

Goodwin, Nicholas R. J.; Burgess, Ray; Craw, Dave; Teagle, Damon A. H.; Ballentine, Chris J.

2017-02-01

The world-class Macraes orogenic gold deposit (˜10 Moz resource) formed during the late metamorphic uplift of a metasedimentary schist belt in southern New Zealand. Mineralising fluids, metals and metalloids were derived from within the metasedimentary host. Helium and argon extracted from fluid inclusions in sulphide mineral grains (three crush extractions from one sample) have crustal signatures, with no evidence for mantle input (R/Ra = 0.03). Xenon extracted from mineralised quartz samples provides evidence for extensive interaction between fluid and maturing organic material within the metasedimentary host rocks, with 132Xe/36Ar ratios up to 200 times greater than air. Similarly, I/Cl ratios for fluids extracted from mineralised quartz are similar to those of brines from marine sediments that have interacted with organic matter and are ten times higher than typical magmatic/mantle fluids. The Macraes mineralising fluids were compositionally variable, reflecting either mixing of two different crustal fluids in the metasedimentary pile or a single fluid type that has had varying degrees of interaction with the host metasediments. Evidence for additional input of meteoric water is equivocal, but minor meteoric incursion cannot be discounted. The Macraes deposit formed in a metasedimentary belt without associated coeval magmatism, and therefore represents a purely crustal metamorphogenic end member in a spectrum of orogenic hydrothermal processes that can include magmatic and/or mantle fluid input elsewhere in the world. There is no evidence for involvement of minor intercalated metabasic rocks in the Macraes mineralising system. Hydrothermal fluids that formed other, smaller, orogenic deposits in the same metamorphic belt have less pronounced noble gas and halogen evidence for crustal fluid-rock interaction than at Macraes, but these deposits also formed from broadly similar metamorphogenic processes.

Lunar "dunite", "pyroxenite" and "anorthosite"

USGS Publications Warehouse

Wilshire, H.G.; Jackson, E.D.

1972-01-01

Monomineralic aggregates of olivine, clinopyroxene, orthopyroxene and plagioclase with granoblastic textures are widespread minor constituents of Apollo 14 breccias. Recrystallization is commonly incomplete within these aggregates, leaving relict material that clearly indicates single-mineral-grain sources for the aggregates. The aggregates are not, therefore, properly characterized by igneous rock names, nor can any conclusions regarding differentiation be drawn from them. Average sizes of the aggregates indicate source rocks with grain sizes mostly larger than 1 to 5 mm, a few clasts of which occur in the breccias; the proportions of the different types of aggregates suggest dominantly feldspathic source rocks. ?? 1972.

Geochemical constraints on the petrogenesis of the pyroclastic rocks in Abakaliki basin (Lower Benue Rift), Southeastern Nigeria

NASA Astrophysics Data System (ADS)

Chukwu, Anthony; Obiora, Smart C.

2018-05-01

The pyroclastic rocks in the Cretaceous Abakaliki basin occur mostly as oval-shaped bodies, consisting of lithic/lava and vitric fragments. They are commonly characterized by parallel and cross laminations, as well contain xenoliths of shale, mudstone and siltstones from the older Asu River Group of Albian age. The rocks are basic to ultrabasic in composition, comprising altered alkali basalts, altered tuffs, minor lapillistones and agglomerates. The mineral compositions are characterized mainly by laths of calcic plagioclase, pyroxene (altered), altered olivines and opaques. Calcite, zeolite and quartz represent the secondary mineral constituents. Geochemically, two groups of volcaniclastic rocks, are distinguished: alkaline and tholeiitic rocks, both represented by fresh and altered rock samples. The older alkali basalts occur within the core of the Abakaliki anticlinorium while the younger tholeiites occur towards the periphery. Though most of the rocks are moderate to highly altered [Loss on ignition (LOI, 3.43-22.07 wt. %)], the use of immobile trace element such as Nb, Zr, Y, Hf, Ti, Ta and REEs reflect asthenospheric mantle source compositions. The rocks are enriched in incompatible elements and REEs (∑REE = 87.98-281.0 ppm for alkaline and 69.45-287.99 ppm for tholeiites). The ratios of La/Ybn are higher in the alkaline rocks ranging from 7.69 to 31.55 compared to the tholeiitic rocks which range from 4.4 to 16.89 and indicating the presence of garnet-bearing lherzolite in the source mantle. The spidergrams and REEs patterns along with Zr/Nb, Ba/Nb, Rb/Nb ratios suggest that the rocks were generated by a mantle plume from partial melting of mixed enriched mantle sources (HIMU, EMI and EMII) similar to the rocks of the south Atlantic Ocean such as St. Helena (alkaline rocks) and Ascension rocks (tholeiitic rocks). The rocks were formed in a within-plate setting of the intra-continental rift type similar to other igneous rocks in the Benue Rift and are not related to any subduction event as previously suggested.

Fluid inclusions and biomarkers in the Upper Mississippi Valley zinc-lead district; implications for the fluid-flow and thermal history of the Illinois Basin

USGS Publications Warehouse

Rowan, E. Lanier; Goldhaber, Martin B.

1996-01-01

The Upper Mississippi Valley zinc-lead district is hosted by Ordovician carbonate rocks at the northern margin of the Illinois Basin. Fluid inclusion temperature measurements on Early Permian sphalerite ore from the district are predominantly between 90?C and I50?C. These temperatures are greater than can be explained by their reconstructed burial depth, which was a maximum of approximately 1 km at the time of mineralization. In contrast to the temperatures of mineral formation derived from fluid inclusions, biomarker maturities in the Upper Mississippi Valley district give an estimate of total thermal exposure integrated over time. Temperatures from fluid inclusions trapped during ore genesis with biomarker maturities were combined to construct an estimate of the district's overall thermal history and, by inference, the late Paleozoic thermal and hydrologic history of the Illinois Basin. Circulation of groundwater through regional aquifers, given sufficient flow rates, can redistribute heat from deep in a sedimentary basin to its shallower margins. Evidence for regional-scale circulation of fluids is provided by paleomagnetic studies, regionally correlated zoned dolomite, fluid inclusions, and thermal maturity of organic matter. Evidence for igneous acti vity contemporaneous with mineralization in the vicinity of the Upper Mississippi Valley district is absent. Regional fluid and heat circulation is the most likely explanation for the elevated fluid inclusion temperatures (relative to maximum estimated burial depth) in the Upper Mississippi Valley district. One plausible driving mechanism and flow path for the ore-forming fluids is groundwater recharge in the late Paleozoic Appalachian-Ouachita mountain belt and northward flow through the Reelfoot rift and the proto- Illinois Basin to the Upper Mississippi Valley district. Warm fluid flowing laterally through Cambrian and Ordovician aquifers would then move vertically upward through the fractures that control sphalerite mineralization in the Upper Mississippi Valley district. Biomarker reactant-product measurements on rock extracts from the Upper Mississippi Valley district define a relatively low level ofthermal maturity for the district, 0.353 for sterane and 0.577 for hopane. Recently published kinetic constants permit a time-temperature relationship to be determined from these biomarker maturities. Numerical calculations were made to simulate fluid heat flow through the fracture-controlled ore zones of the Thompson-Temperly mine and heat transfer to the adjacent rocks where biomarker samples were collected. Calculations that combine the fluid inclusion temperatures and the biomarker constraints on thermal maturity indicate that the time interval during which mineralizing fluids circulated through the Upper Mississippi Valley district is on the order of 200,000 years. Fluid inclusion measurements and thermal maturities from biomarkers in the district reflect the duration of peak temperatures resulting from regional fluid circulation. On the basis of thermal considerations, the timing of fluorite mineralization in southern Illinois, and the northward-decreasing pattern of fluorine enrichment in sediments, we hypothesize that the principal flow direction was northward through the Cambrian and Ordovician aquifers of the Illinois Basin. A basin-scale flow system would result in mass transport (hydrocarbon migration, transport of metals in solution) and energy (heat) transport, which would in turn drive chemical reactions (for example, maturation of organic matter, mineralization, diagenetic reactions) within the Illinois Basin and at its margins.

Sedimentary records of the Yangtze Block (South China) and their correlation with equivalent Neoproterozoic sequences on adjacent continents

NASA Astrophysics Data System (ADS)

Wang, Wei; Zhou, Mei-Fu

2012-07-01

The Neoproterozoic Danzhou Group, composed of siliciclastic sedimentary rocks interbedded with minor carbonate and volcanic rocks in the southeastern Yangtze Block, South China, is thought to be related to the breakup of Rodinia. Detrital zircon ages constrain the deposition of the Danzhou Group at ~ 770 Ma and ~ 730 Ma. The Danzhou Group contains dominant Neoproterozoic detrital zircon grains (~ 740-900 Ma) with two major age groups at ~ 740-790 Ma and ~ 810-830 Ma, suggesting the detritus was largely sourced from the widely distributed Neoproterozoic igneous plutons within the Yangtze Block. The sedimentary rocks from the lower Danzhou Group, including sandstones, siltstone and pelitic rocks, have UCC-like chemical signatures, representing mixed products of primary sources. The upper Danzhou Group received more recycled materials because the rocks have relatively higher Zr/Sc ratios, Hf contents and a greater influx of Pre-Neoproterozoic zircons. All of the rocks have high La/Sc, low Sc/Th and Co/Th ratios, consistent with sources dominantly composed of granitic to dioritic end-members from the western and northwestern Yangtze Block. Chemical compositions do not support significant contributions of mafic components. Most Neoproterozoic zircons have positive ɛHf(t) (0-17) indicative of sediments derived mainly from the western and northwestern Yangtze Block. The uni-modal Neoproterozoic zircons and felsic igneous source rocks for the Danzhou Group suggest that the Yangtze Block was an independent continent in the peripheral part of Rodinia.

Middle and upper Miocene natural gas sands in onshore and offshore Alabama

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

Mink, R.M.; Mancini, E.A.; Bearden, B.L.

1988-09-01

Thirty Miocene natural gas fields have been established in onshore and offshore Alabama since the discovery of Miocene gas in this area in 1979. These fields have produced over 16 bcf of natural gas from the middle Miocene Amos sand (24 fields) and upper Miocene Luce (3 fields), Escambia (1 field), and Meyer (3 fields) sands. Production from the Amos transgressive sands represents over 92% of the cumulative shallow Miocene natural gas produced in onshore and offshore Alabama. In addition, over 127 bcf of natural gas has been produced from upper Miocene sands in the Chandeleur area. The productive Miocenemore » section in onshore and coastal Alabama is interpreted to present transgressive marine shelf and regressive shoreface sands. The middle Miocene Amos sand bars are the most productive reservoirs of natural gas in onshore and coastal Alabama, principally due to the porous and permeable nature of these transgressive sands and their stratigraphic relationship to the underlying basinal clays in this area. In offshore Alabama the upper Miocene sands become thicker and are generally more porous and permeable than their onshore equivalents. Because of their deeper burial depth in offshore Alabama, these upper Miocene sands are associated with marine clays that are thermally more mature. The combination of reservoir grade lithologies associated with moderately mature petroleum source rocks enhances the natural gas potential of the upper Miocene sands in offshore Alabama.« less

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.

Crustal thickness control on Sr/Y signatures of recent arc magmas: an Earth scale perspective

PubMed Central

Chiaradia, Massimo

2015-01-01

Arc magmas originate in subduction zones as partial melts of the mantle, induced by aqueous fluids/melts liberated by the subducted slab. Subsequently, they rise through and evolve within the overriding plate crust. Aside from broadly similar features that distinguish them from magmas of other geodynamic settings (e.g., mid-ocean ridges, intraplate), arc magmas display variably high Sr/Y values. Elucidating the debated origin of high Sr/Y signatures in arc magmas, whether due to mantle-source, slab melting or intracrustal processes, is instrumental for models of crustal growth and ore genesis. Here, using a statistical treatment of >23000 whole rock geochemical data, I show that average Sr/Y values and degree of maturation (MgO depletion at peak Sr/Y values) of 19 out of 22 Pliocene-Quaternary arcs correlate positively with arc thickness. This suggests that crustal thickness exerts a first order control on the Sr/Y variability of arc magmas through the stabilization or destabilization of mineral phases that fractionate Sr (plagioclase) and Y (amphibole ± garnet). In fact, the stability of these mineral phases is function of the pressure at which magma evolves, which depends on crustal thickness. The data presented show also that high Sr/Y Pliocene-Quaternary intermediate-felsic arc rocks have a distinct origin from their Archean counterparts. PMID:25631193

Basin deconstruction-construction: Seeking thermal-tectonic consistency through the integration of geochemical thermal indicators and seismic fault mechanical stratigraphy ​- Example from Faras Field, North Western Desert, Egypt

NASA Astrophysics Data System (ADS)

Pigott, John D.; Abouelresh, Mohamed O.

2016-02-01

To construct a model of a sedimentary basin's thermal tectonic history is first to deconstruct it: taking apart its geological elements, searching for its initial conditions, and then to reassemble the elements in the temporal order that the basin is assumed to have evolved. Two inherent difficulties implicit to the analysis are that most organic thermal indicators are cumulative, irreversible and a function of both temperature and time and the non-uniqueness of crustal strain histories which complicates tectonic interpretations. If the initial conditions (e.g. starting maturity of the reactants and initial crustal temperature) can be specified and the boundary conditions incrementally designated from changes in the lithospheric heat engine owing to stratigraphic structural constraints, then the number of pathways for the temporal evolution of a basin is greatly reduced. For this investigation, model input uncertainties are reduced through seeking a solution that iteratively integrates the geologically constrained tectonic subsidence, geochemically constrained thermal indicators, and geophysically constrained fault mechanical stratigraphy. The Faras oilfield in the Abu Gharadig Basin, North Western Desert, Egypt, provides an investigative example of such a basin's deconstructive procedure. Multiple episodes of crustal extension and shortening are apparent in the tectonic subsidence analyses which are constrained from the fault mechanical stratigraphy interpreted from reflection seismic profiles. The model was iterated with different thermal boundary conditions until outputs best fit the geochemical observations. In so doing, the thermal iterations demonstrate that general relationship that basin heat flow increases decrease vertical model maturity gradients, increases in surface temperatures shift vertical maturity gradients linearly to higher values, increases in sediment conductivities lower vertical maturities with depth, and the addition of ;ghost; layers (those layers removed) prior to the erosional event increase maturities beneath, and conversely. These integrated constraints upon the basin evolution model indicate that the principal source rocks, Khatatba and the lowest part of the Alam El Bueib formations, entered the oil window at approximately 95 Ma and the gas window at approximately 25 Ma. The upper part of the Alam El Bueib Formation is within the oil window at the present day. Establishing initial and boundary value conditions for a basin's thermal evolution when geovalidated by the integration of seismic fault mechanical stratigraphy, tectonic subsidence analysis, and organic geochemical maturity indicators provides a powerful tool for optimizing petroleum exploration in both mature and frontier basins.

Comparison of GC-MS, GC-MRM-MS, and GC × GC to characterise higher plant biomarkers in Tertiary oils and rock extracts

NASA Astrophysics Data System (ADS)

Eiserbeck, Christiane; Nelson, Robert K.; Grice, Kliti; Curiale, Joseph; Reddy, Christopher M.

2012-06-01

Higher plant biomarkers occur in various compound classes with an array of isomers that are challenging to separate and identify. Traditional one-dimensional (1D) gas chromatographic (GC) techniques achieved impressive results in the past, but have reached limitations in many cases. Comprehensive two-dimensional gas chromatography (GC × GC) either coupled to a flame ionization detector (GC × GC-FID) or time-of-flight mass spectrometer (GC × GC-TOFMS) is a powerful tool to overcome the challenges of 1D GC, such as the resolution of unresolved complex mixture (UCM). We studied a number of Tertiary, terrigenous oils, and source rocks from the Arctic and Southeast Asia, with special focus on angiosperm biomarkers, such as oleanoids and lupanoids. Different chromatographic separation and detection techniques such as traditional 1D GC-MS, metastable reaction monitoring (GC-MRM-MS), GC × GC-FID, and GC × GC-TOFMS are compared and applied to evaluate the differences and advantages in their performance for biomarker identification. The measured 22S/(22S + 22R) homohopane ratios for all applied techniques were determined and compare exceptionally well (generally between 2% and 10%). Furthermore, we resolved a variety of angiosperm-derived compounds that co-eluted using 1D GC techniques, demonstrating the superior separation power of GC × GC for these biomarkers, which indicate terrigenous source input and Cretaceous or younger ages. Samples of varying thermal maturity and biodegradation contain higher plant biomarkers from various stages of diagenesis and catagenesis, which can be directly assessed in a GC × GC chromatogram. The analysis of whole crude oils and rock extracts without loss in resolution enables the separation of unstable compounds that are prone to rearrangement (e.g. unsaturated triterpenoids such as taraxer-14-ene) when exposed to fractionation techniques like molecular sieving. GC × GC-TOFMS is particularly valuable for the successful separation of co-eluting components having identical molecular masses and similar fragmentation patterns. Such components co-elute when analysed by 1D GC and cannot be resolved by single-ion-monitoring, which prevents accurate mass spectral assessment for identification or quantification.

Geochemical, oxygen, and neodymium isotope compositions of metasediments from the Abitibi greenstone belt and Pontiac Subprovince, Canada: Evidence for ancient crust and Archean terrane juxtaposition

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

Feng, R.; Kerrich, R.; Maas, R.

1993-02-01

The Abitibi greenstone belt (AGB) and Pontiac Subprovince (PS) in the southwestern Superior Province are adjacent greenstone-plutonic and metasedimentary-dominated terranes, respectively, separated by a major fault zone. Metasediments from these two contrasting terranes are compared in terms of major- and trace-element and O- and Nd-isotope compositions, and detrital zircon ages. The following two compositional populations of metasediments are present in the low-grade, Abitibi southern volcanic zone: (1) a mafic-element-enriched population (MEP) characterized by flat, depleted REE patterns; enhanced Mg, Cr, Co, Ni, and Sc; low-incompatible-element contents; and minor or absent normalized negative troughs at Nb, Ta, and Ti; and (2)more » a low-mafic-element population (LMEP) featuring LREE-enriched patterns; enhanced Rb, Cs, Ba, Th, and U contents; and pronounced normalized negative troughs at Nb, Ta, and Ti. These geochemical features are interpreted to indicate that the MEP sediments were derived from an ultramafic- and mafic-dominated oceanic provenance, whereas the LMEP sediments represent mixtures of mafic and felsic are source rocks. The PS metasediments are essentially indistinguishable from Abitibi LMEP on the basis of major-element and transition metal abundances, suggesting comparable types of source rocks and degrees of maturity, but are distinct in terms of some trace elements and O-isotope compositions. The Pontiac metasediments are depleted in [sup 18]O and enriched in Cs, Ba, Pb, Th, U, Nb, Ta, Hf, Zr, and total REE and also have higher ratios of Rb/K, Cs/Rb, Ba/Rb, Ta/Nb, Th/La, and Ba/La relative to the Abitibi LMEP. Two subtypes of REE patterns have been identified in PS metasediments. The first subtype is interpreted to be derived from provenances of mixed mafic and felsic volcanic rocks, whereas the Eu-depleted type has features that are typical of post-Archean sediments or Archean K-rich granites and volcanic equivalents. 100 refs., 9 figs., 4 tabs.« less

Expectations of Rock Music Consumption for Entertainment and Information Relative to the Active Involvement of the User.

ERIC Educational Resources Information Center

Rouner, Donna; Noyes, Amy

Before examining potentially negative effects of rock music on adolescents, it is necessary to demonstrate links between adolescent motivations for consuming rock music and active involvement relative to that use and also to consider how much rock listeners rely on rock music as a source for information about values, beliefs, and social…

1. EXTERIOR OVERVIEW SHOWING FRONT (EAST) END AND SOUTH SIDE ...

Library of Congress Historic Buildings Survey, Historic Engineering Record, Historic Landscapes Survey

1. EXTERIOR OVERVIEW SHOWING FRONT (EAST) END AND SOUTH SIDE OF BUILDING 103, ROCK WALL AND MATURE COTTONWOOD TREES IN FOREGROUND, CONTROL SUBSTATION BEHIND BUILDING 103, AND BUILDING 106 BEHIND THE COTTONWOOD TREE IN THE NORTH BACKGROUND. VIEW TO NORTH. - Bishop Creek Hydroelectric System, Control Station, Worker Cottage, Bishop Creek, Bishop, Inyo County, CA

Stratigraphy, petrography, and provenance of Archean sedimentary rocks of the Nsuze Group, Pongola Supergroup, in the Wit M'folozi Inlier, South Africa

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

Gamero de Villarroel, H.; Lowe, D.R.

1993-02-01

The Upper Archean Pongola Supergroup is a succession of clastic and volcanic rocks that represents the oldest relatively unmetamorphosed sedimentary sequence deposited on the basement of the 3.5-3.2 Ga-old Kaapvaal Craton. The Pongola Supergroup includes two subdivisions, the Nsuze and the Mozaan Groups. The Nsuze Group is composed of clastic rocks, minor carbonate units, and basalt. Nsuze sandstones are dominated by granite-derived sediments, and minor basaltic-derived detritus. Most Nsuze sedimentary rocks are sandstones that include both quartz-fieldspar and lithic-rich varieties. The mineralogy of Nsuze sandstones reflects the mixing of debris derived from two distinctive sources: (1) a sialic plutonic sourcemore » yielding quartz and microcline and (2) a basaltic source yielding basaltic lithic detritus and plagioclase. The most likely source rocks for the Nsuze sandstones in the Wit M'folozi Inlier were Archean granitic basement, represented by the Mpuluzi batholith, and Nsuze basaltic volcanic rocks. Both continental arc and rift settings have been proposed for the Pongola Supergroup. Nsuze sandstones show similarities to continental arc sandstone suites. However, there is no report of the existence of high standing stratovolcanoes, calc-alkaline plutonism, or contact and regional metamorphism of the intruded volcanic-sedimentary and basement rocks in the Pongola basin, features that are typically associated with continental arcs. The dominance of continent-derived detritus in the Nsuze Group argues that volcanic rocks made up a minor part of the exposed source area and that volcanism was largely restricted to the basin of deposition. Collectively, available evidence favors an intracratonic rift for the depositional setting of the Nsuze Group.« less

Maturation during short-duration heating of carbonaceous material: A new indicator for frictional heat during earthquake slip

NASA Astrophysics Data System (ADS)

Mukoyoshi, H.; Hirono, T.

2016-12-01

Estimation of frictional heating of deep to shallow portion of ancient megasplay fault is important for understanding of weakening mechanism (e.g., thermal pressurization, melt lubrication) of present plate boundary fault and megasplay fault. Raman spectroscopy has recently been used to estimate the thermal metamorphic grade of organic matter in sedimentary rocks and applying the method in order to estimate the temperature of fast heating like frictional heating during earthquake. We performed microstructural observation and Raman spectroscopic analyses of carbonaceous materials (CM) in the fault rock of 2.5-5.5 km depth of an ancient megasplay fault (an out-of sequence thrust in the Shimant accretionary complex) and 1-4 km depth of a thrust in the Emi group, Hota accretionary complex, exposed on Japan. We also conducted heating experiment of CM in host rock of these fault with anaerobic condition (range: 100-1300ºC, intervals: 100ºC, rate of temperature increase: 20 K/min) in order to investigate the effects of fast heating rate like frictional heating during earthquake. Raman spectrum of CM of both fault is similar to spectrum of 400˜600 ºC heating experiment of CM. This result shows that both fault had heating history of 400˜600 ºC by frictional heating. To evaluate the levels of friction, Raman spectrum of the short time maturated experimented CM is useful as calibration tool.

Oxidation state inherited from the magma source and implications for mineralization: Late Jurassic to Early Cretaceous granitoids, Central Lhasa subterrane, Tibet

NASA Astrophysics Data System (ADS)

Cao, MingJian; Qin, KeZhang; Li, GuangMing; Evans, Noreen J.; McInnes, Brent I. A.; Li, JinXiang; Zhao, JunXing

2018-03-01

Arc magmas are more oxidized than mid-ocean ridge basalts; however, there is continuing debate as to whether this higher oxidation state is inherited from the source magma or developed during late-stage magmatic differentiation processes. Well-constrained Late Jurassic to Early Cretaceous arc-related intermediate to felsic rocks derived from distinct magma sources provide us with a good opportunity to resolve this enigma. A series of granitoids from the western Central Lhasa subterrane were analyzed for whole-rock magnetic susceptibility, Fe2O3/FeO ratios, and trace elements in zircon. Compared to Late Jurassic samples (1.8 ± 2.0 × 10-4 emu g-1 oe-1, Fe3+/Fetotal = 0.32 ± 0.07, zircon Ce4+/Ce3+* = 15.0 ± 13.4), Early Cretaceous rocks show higher whole-rock magnetic susceptibility (5.8 ± 2.5 × 10-4 emu g-1 oe-1), Fe3+/Fetotal ratios (0.43 ± 0.04), and zircon Ce4+/Ce3+* values (23.9 ± 22.3). In addition, positive correlations among whole-rock magnetic susceptibility, Fe3+/Fetotal ratios, and zircon Ce4+/Ce3+* reveal a slight increase in oxidation state from fO2 = QFM to NNO in the Late Jurassic to fO2 = ˜NNO in the Early Cretaceous. Obvious linear correlation between oxidation indices (whole-rock magnetic susceptibility, zircon Ce4+/Ce3+*) and source signatures (zircon ɛHf(t), TDM C ages) indicates that the oxidation state was predominantly inherited from the source with only a minor contribution from magmatic differentiation. Thus, the sources for both the Late Jurassic and Early Cretaceous rocks were probably influenced by mantle wedge-derived magma, contributing to the increased fO2. Compared to ore-forming rocks at giant porphyry Cu deposits, the relatively low oxidation state (QFM to NNO) and negative ɛHf(t) (-16 to 0) of the studied granitoids implies relative infertility. However, this study demonstrates two potential fast and effective indices ( fO2 and ɛHf(t)) to evaluate the fertility of granitoids for porphyry-style mineralization. In an exploration context for the west Central Lhasa subterrane, features indicative of potential fertility might include more oxidized, positive ɛHf(t), young rocks (<130 Ma).

8. Photographic copy of photograph. (Source: Department of Interior. Bureau ...

Library of Congress Historic Buildings Survey, Historic Engineering Record, Historic Landscapes Survey

8. Photographic copy of photograph. (Source: Department of Interior. Bureau of Reclamation. Bitterroot Project History 1931-1962. National Archives, Denver, RG 115, Accession #115-90-039, Box 243) Photographer unknown. View of original rock-fill crib diversion structure, September 13, 1949. Diversion and head works for big ditch on Rock Creek. - Bitter Root Irrigation Project, Rock Creek Diversion Dam, One mile east of Como Dam, west of U.S. Highway 93, Darby, Ravalli County, MT

Extraction of Iodine from Source Rock and Oil for Radioiodine Dating Final Report CRADA No. TC-1550-98

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

Moran, J. E.; Summa, L.

This was a collaborative effort between the University of California, Lawrence Livermore National Laboratory (LLNL) and Exxon Production Research Company (EPR) to develop improved techniques for extracting, concentrating, and measuring iodine from large volumes of source rock and oil. The purpose of this project was to develop a technique for measuring total iodine extracted from rock, obtain isotopic ratios, and develop age models for samples provided by EPR.

Paleofacies of Eocene Lower Ngimbang Source Rocks in Cepu Area, East Java Basin based on Biomarkers and Carbon-13 Isotopes

NASA Astrophysics Data System (ADS)

Devi, Elok A.; Rachman, Faisal; Satyana, Awang H.; Fahrudin; Setyawan, Reddy

2018-02-01

The Eocene Lower Ngimbang carbonaceous shales are geochemically proven hydrocarbon source rocks in the East Java Basin. Sedimentary facies of source rock is important for the source evaluation that can be examined by using biomarkers and carbon-13 isotopes data. Furthermore, paleogeography of the source sedimentation can be reconstructed. The case study was conducted on rock samples of Lower Ngimbang from two exploration wells drilled in Cepu area, East Java Basin, Kujung-1 and Ngimbang-1 wells. The biomarker data include GC and GC-MS data of normal alkanes, isoprenoids, triterpanes, and steranes. Carbon-13 isotope data include saturate and aromatic fractions. Various crossplots of biomarker and carbon-13 isotope data of the Lower Ngimbang source samples from the two wells show that the source facies of Lower Ngimbang shales changed from transitional/deltaic setting at Kujung-1 well location to marginal marine setting at Ngimbang-1 well location. This reveals that the Eocene paleogeography of the Cepu area was composed of land area in the north and marine setting to the south. Biomarkers and carbon-13 isotopes are powerful data for reconstructing paleogeography and paleofacies. In the absence of fossils in some sedimentary facies, these geochemical data are good alternatives.

Partitioning of 13C-photosynthate from Spur Leaves during Fruit Growth of Three Japanese Pear (Pyrus pyrifolia) Cultivars Differing in Maturation Date

PubMed Central

ZHANG, CAIXI; TANABE, KENJI; TAMURA, FUMIO; ITAI, AKIHIRO; WANG, SHIPING

2005-01-01

• Background and Aims In fruit crops, fruit size at harvest is an important aspect of quality. With Japanese pears (Pyrus pyrifolia), later maturing cultivars usually have larger fruits than earlier maturing cultivars. It is considered that the supply of photosynthate during fruit development is a critical determinant of size. To assess the interaction of assimilate supply and early/late maturity of cultivars and its effect on final fruit size, the pattern of carbon assimilate partitioning from spur leaves (source) to fruit and other organs (sinks) during fruit growth was investigated using three genotypes differing in maturation date. • Methods Partitioning of photosynthate from spur leaves during fruit growth was investigated by exposure of spurs to 13CO2 and measurement of the change in 13C abundance in dry matter with time. Leaf number and leaf area per spur, fresh fruit weight, cell number and cell size of the mesocarp were measured and used to model the development of the spur leaf and fruit. • Key Results Compared with the earlier-maturing cultivars ‘Shinsui’ and ‘Kousui’, the larger-fruited, later-maturing cultivar ‘Shinsetsu’ had a greater total leaf area per spur, greater source strength (source weight × source specific activity), with more 13C assimilated per spur and allocated to fruit, smaller loss of 13C in respiration and export over the season, and longer duration of cell division and enlargement. Histology shows that cultivar differences in final fruit size were mainly attributable to the number of cells in the mesocarp. • Conclusions Assimilate availability during the period of cell division was crucial for early fruit growth and closely correlated with final fruit size. Early fruit growth of the earlier-maturing cultivars, but not the later-maturing ones, was severely restrained by assimilate supply rather than by sink limitation. PMID:15655106

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.

Geochemistry of the Neoproterozoic metabasic rocks from the Negele area, southern Ethiopia: Tectonomagmatic implications

NASA Astrophysics Data System (ADS)

Yihunie, Tadesse; Adachi, Mamoru; Yamamoto, Koshi

2006-03-01

Neoproterozoic metabasic rocks along with metasediments and ultramafic rocks constitute the Kenticha and Bulbul lithotectonic domains in the Negele area. They occur as amphibolite and amphibole schist in the Kenticha, and amphibole schist and metabasalt in the Bulbul domains. These rocks are dominantly basaltic in composition and exhibit low-K tholeiitic characteristics. They are slightly enriched in large ion lithophile (LIL) and light rare earth (LRE) elements and depleted in high field strength (HFS) and heavy rare earth (HRE) elements. They exhibit chemical characteristics similar to back-arc basin and island-arc basalts, but include a few samples with slightly higher Y, Zr and Nb contents. Initial Sr isotopic ratios and ɛNd values for the Kenticha metabasic rocks range from 0.7048 to 0.7051 and from 4.7 to 9.6 whereas for the Bulbul metabasic rocks they range from 0.7032 to 0.7055 and from -0.1 to 5.5, respectively. The trace elements and Sr-Nd isotope compositions of samples from the Kenticha and Bulbul domains suggest similar, but isotopically heterogeneous magma sources. The magma is inferred to have derived from depleted source with a contribution from an enriched mantle source component.

Coupled petrological-geodynamical modeling of a compositionally heterogeneous mantle plume

NASA Astrophysics Data System (ADS)

Rummel, Lisa; Kaus, Boris J. P.; White, Richard W.; Mertz, Dieter F.; Yang, Jianfeng; Baumann, Tobias S.

2018-01-01

Self-consistent geodynamic modeling that includes melting is challenging as the chemistry of the source rocks continuously changes as a result of melt extraction. Here, we describe a new method to study the interaction between physical and chemical processes in an uprising heterogeneous mantle plume by combining a geodynamic code with a thermodynamic modeling approach for magma generation and evolution. We pre-computed hundreds of phase diagrams, each of them for a different chemical system. After melt is extracted, the phase diagram with the closest bulk rock chemistry to the depleted source rock is updated locally. The petrological evolution of rocks is tracked via evolving chemical compositions of source rocks and extracted melts using twelve oxide compositional parameters. As a result, a wide variety of newly generated magmatic rocks can in principle be produced from mantle rocks with different degrees of depletion. The results show that a variable geothermal gradient, the amount of extracted melt and plume excess temperature affect the magma production and chemistry by influencing decompression melting and the depletion of rocks. Decompression melting is facilitated by a shallower lithosphere-asthenosphere boundary and an increase in the amount of extracted magma is induced by a lower critical melt fraction for melt extraction and/or higher plume temperatures. Increasing critical melt fractions activates the extraction of melts triggered by decompression at a later stage and slows down the depletion process from the metasomatized mantle. Melt compositional trends are used to determine melting related processes by focusing on K2O/Na2O ratio as indicator for the rock type that has been molten. Thus, a step-like-profile in K2O/Na2O might be explained by a transition between melting metasomatized and pyrolitic mantle components reproducible through numerical modeling of a heterogeneous asthenospheric mantle source. A potential application of the developed method is shown for the West Eifel volcanic field.

Lead in the Getchell-Turquoise ridge Carlin-type gold deposits from the perspective of potential igneous and sedimentary rock sources in Northern Nevada: Implications for fluid and metal sources

USGS Publications Warehouse

Tosdal, R.M.; Cline, J.S.; Fanning, C.M.; Wooden, J.L.

2003-01-01

Lead isotope compositions of bulk mineral samples (fluorite, orpiment, and realgar) determined using conventional techniques and of ore-stage arsenian pyrite using the Sensitive High Resolution Ion-Microprobe (SHRIMP) in the Getchell and Turquoise Ridge Carlin-type gold deposits (Osgood Mountains) require contribution from two different Pb sources. One Pb source dominates the ore stage. It has a limited Pb isotope range characterized by 208Pb/206Pb values of 2.000 to 2.005 and 207Pb/206Pb values of 0.8031 to 0.8075, as recorded by 10-??m-diameter spot SHRIMP analyses of ore-stage arsenian pyrite. These values approximately correspond to 206Pb/204Pb of 19.3 to 19.6, 207Pb/204Pb of 15.65 to 15.75, and 208Pb/204Pb of 39.2 to 39.5. This Pb source is isotopically similar to that in average Neoproterozoic and Cambrian elastic rocks but not to any potential magmatic sources. Whether those clastic rocks provided Pb to the ore fluid cannot be unequivocally proven because their Pb isotope compositions over the same range as in ore-stage arsenian pyrite are similar to those of Ordovician to Devonian siliciclastic and calcareous rocks. The Pb source in the calcareous rocks most likely is largely detrital minerals, since that detritus was derived from the same sources as the detritus in the Neoproterozoic and Cambrian clastic rocks. The second Pb source is characterized by a large range of 206Pb/204Pb values (18-34) with a limited range of 208Pb/204Pb values (38.1-39.5), indicating low but variable Th/U and high and variable U/Pb values. The second Pb source dominates late and postore-stage minerals but is also found in preore sulfide minerals. These Pb isotope characteristics typify Ordovician to Devonian siliciclastic and calcareous rocks around the Carlin trend in northeast Nevada. Petrologically similar rocks host the Getchell and Turquoise Ridge deposits. Lead from the second source was either contributed from the host sedimentary rock sequences or brought into the hydrothermal system by oxidized ground water as the system collapsed. Late ore- and postore-stage sulfide minerals (pyrite, orpiment, and stibnite) from the Betze-Post and Meikle deposits in the Carlin trend and from the Jerritt Canyon mining district have Pb isotope characteristics similar to those determined in Getchell and Turquoise Ridge. This observation suggests that the Pb isotope compositions of their ore fluids may be similar to those at Getchell and Turquoise Ridge. Two models can explain the Pb isotope compositions of the ore-stage arsenian pyrite versus the late ore or postore sulfide minerals. In either model, Pb from the Ordovician to Devonian siliciclastic and calcareous rock source enters the hydrothermal system late in the ore stage but not to any extent during the main stage of ore deposition. In one model, ore-stage Pb was derived from a source with Pb isotope compositions similar to those of the Neoproterozoic and Cambrian clastic sequence, transported as part of the ore fluid and then deposited in the ore-stage arsenian pyrite and fluorite. The second model is based on the observation that the Pb isotope characteristics of the ore-stage minerals also are found in some Ordovician to Devonian calcareous and siliciclastic rocks. Hence, ore-stage Pb could have been derived locally and simply concentrated during the ore stage. Critical to the second model is the removal of all high 206Pb/204Pb (>20) material during alteration. It Also requires the retention of only the low 206Pb/204Pb component of the Ordovician to Devonian sedimentary rocks. This critical step is possible only if the high 206Pb/204Pb values are contained in readily dissolvable mineral phases, whereas the low 206Pb/204Pb values are found only in refractory minerals that released Pb during a final alteration stage just prior deposition of auriferous arsenian pyrite. Distinguishing between Pb transported with the ore fluid or inherited from the site of mineral deposition is not straightforward

Sr-Nd-Hf-O isotope geochemistry of the Ertaibei pluton, East Junggar, NW China: Implications for development of a crustal-scale granitoid pluton and crustal growth

NASA Astrophysics Data System (ADS)

Tang, Gong-Jian; Wang, Qiang; Zhang, Chunfu; Wyman, Derek A.; Dan, Wei; Xia, Xiao-Ping; Chen, Hong-Yi; Zhao, Zhen-Hua

2017-09-01

To better understand the compositional diversity of plutonic complexes and crustal growth of the Central Asian Orogenic Belt (CAOB), we conducted an integrated study of the Ertaibei pluton, which obtained geochronological, petrological, geochemical, and isotopic (including whole rock Sr-Nd, in situ zircon Hf-O) data. The pluton (ca. 300 Ma) is composed of granodiorites that contain mafic microgranular enclaves (MMEs), dolerite dikes, and granite dikes containing quartz-tourmaline orbicules. The dolerite dikes were possibly generated by melting of an asthenospheric mantle source, with discrete assimilation of lower crustal components in the MASH (melting, assimilation, storage, and homogenization) zone. The MMEs originated from hybridization between mantle and crust-derived magmas, which spanned a range of melting depths (˜25-30 km) in the MASH zone and were episodically tapped. Melting of the basaltic lower crust in the core of the MASH zone generated magmas to form the granodiorites. The granite dikes originated from melting of an arc-derived volcanogenic sedimentary source with a minor underplated basaltic source in the roof of the MASH zone (˜25 km). The compositional diversity reflects both the magma sources and the degree of maturation of the MASH zone. Although having mantle-like radiogenic isotope compositions, the Ertaibei and other postcollisional granitoids show high zircon δ18O values (mostly between +6 and +9‰), indicating a negligible contribution to the CAOB crustal growth during the postcollisional period.

Isotopic data for Late Cretaceous intrusions and associated altered and mineralized rocks in the Big Belt Mountains, Montana

USGS Publications Warehouse

du Bray, Edward A.; Unruh, Daniel M.; Hofstra, Albert H.

2017-03-07

The quartz monzodiorite of Mount Edith and the concentrically zoned intrusive suite of Boulder Baldy constitute the principal Late Cretaceous igneous intrusions hosted by Mesoproterozoic sedimentary rocks of the Newland Formation in the Big Belt Mountains, Montana. These calc-alkaline plutonic masses are manifestations of subduction-related magmatism that prevailed along the western edge of North America during the Cretaceous. Radiogenic isotope data for neodymium, strontium, and lead indicate that the petrogenesis of the associated magmas involved a combination of (1) sources that were compositionally heterogeneous at the scale of the geographically restricted intrusive rocks in the Big Belt Mountains and (2) variable contamination by crustal assimilants also having diverse isotopic compositions. Altered and mineralized rocks temporally, spatially, and genetically related to these intrusions manifest at least two isotopically distinct mineralizing events, both of which involve major inputs from spatially associated Late Cretaceous igneous rocks. Alteration and mineralization of rock associated with the intrusive suite of Boulder Baldy requires a component characterized by significantly more radiogenic strontium than that characteristic of the associated igneous rocks. However, the source of such a component was not identified in the Big Belt Mountains. Similarly, altered and mineralized rocks associated with the quartz monzodiorite of Mount Edith include a component characterized by significantly more radiogenic strontium and lead, particularly as defined by 207Pb/204Pb values. The source of this component appears to be fluids that equilibrated with proximal Newland Formation rocks. Oxygen isotope data for rocks of the intrusive suite of Boulder Baldy are similar to those of subduction-related magmatism that include mantle-derived components; oxygen isotope data for altered and mineralized equivalents are slightly lighter.

Organic Geochemistry of the Hamersley Province: Relationships Among Organic Carbon Isotopes, Molecular Fossils, and Lithology

NASA Technical Reports Server (NTRS)

Eigenbrode, Jennifer L.

2012-01-01

Molecular fossils are particularly valuable ancient biosignatures that can provide key insight about microbial sources and ecology in early Earth studies. In particular, hopanes carrying 2-methyl or 3-methyl substituents are proposed to be derived from cyanobacteria and oxygen-respiring methanotrophs, respectively, based on both their modem occurrences and their Proterozoic and Phanerozoic sedimentary distributions. Steranes are likely from ancestral eukaryotes. The distribution of methylhopanes, steranes, and other biomarkers in 2.72-2.56 billion-year-old rocks from the Hamersley Province, Western Australia show relationships to lithology, facies, and isotopes of macromolecular carbon, and other biomarkers. These observations support biomarker syngenicity and thermal maturity. Moreover, ecological signatures are revealed, including a surprising relationship between isotopic values for bulk macromolecular carbon and the biomarker for methanotrophs. The record suggests that cyanobacteria were likely key organisms of shallow-water microbial ecosystems providing molecular oxygen, fixed carbon, and possibly fixed nitrogen, and methanotrophs were not alone in recycling methane and other C-13-depleted substrates.

Thermal regimes of Malaysian sedimentary basins

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

Abdul Halim, M.F.

1994-07-01

Properly corrected and calibrated thermal data are important in estimating source-rock maturation, diagenetics, evolution of reservoirs, pressure regimes, and hydrodynamics. Geothermal gradient, thermal conductivity, and heat flow have been determined for the sedimentary succession penetrated by exploratory wells in Malaysia. Geothermal gradient and heat-flow maps show that the highest average values are in the Malay Basin. The values in the Sarawak basin are intermediate between those of the Malay basin and the Sabah Basin, which contains the lowest average values. Temperature data were analyzed from more than 400 wells. An important parameter that was studied in detail is the circulationmore » time. The correct circulation time is essential in determining the correct geothermal gradient of a well. It was found that the most suitable circulation time for the Sabah Basin is 20 hr, 30 hr for the Sarawak Basin and 40 hr for the Malay Basin. Values of thermal conductivity, determined from measurement and calibrated calculations, were grouped according to depositional units and cycles in each basin.« less

Effect of Thermal Maturation on n-alkanes and Kerogen in Preserved Organic Matter: Implications for Paleoenvironment Biomarkers

NASA Astrophysics Data System (ADS)

Craven, O. D.; Longbottom, T. L.; Hockaday, W. C.; Blackaby, E.

2017-12-01

Understanding the effects of maturity on biomarkers is vital in assessing biomarker reliability in mature sediments. It is well known for n-alkanes that increased maturity shortens chain lengths and decreases the odd over even preference however, the amount of change in these variables has not been determined for different maturities and types of preserved organic matter. For this reason, it is difficult to judge the trustworthiness of even lightly matured samples for paleoenvironment reconstruction. Another complication is the difficulty of accurately determining maturity as many maturity indicators are error-prone or not appropriate at low maturities. Using hydrous pyrolysis, we artificially matured black shale samples with type I (lacustrine) and type II (marine) kerogen to measure changes in n-alkane length and odd over even preference. Whole rock samples underwent hydrous pyrolysis for 72 hours, at 250 °C, 300 °C, 325 °C, 350 °C, and 375 °C to cover a wide maturity range. From the immature and artificially matured samples, the bitumen was extracted and the saturate fraction was separated using column chromatography. The saturate fraction was analyzed for n-alkanes using gas chromatography-mass spectroscopy. Kerogen structural changes were also measured using solid-state 13C NMR to relate changes in n-alkane biomarkers to changes in kerogen structure. Results show that for type I bitumen the n-alkanes did not change at low maturities considered premature in terms of oil generation (<325 °C). The NMR spectra of the type I kerogen support the lack of change, at low maturities no changes in the aliphatic portion (Fal) were observed, however, after 325 °C Fal decreased with increasing maturity. The loss of Fal indicates kerogen contributing hydrocarbons to bitumen that cause changes in n-alkane measurements. The type II kerogen's Fal also decreased with increasing maturity, but unlike the type I kerogen Fal loss started at low maturities. The differences between the matured type I and II organic matter indicate that organic matter type affects when n-alkane measurements change due to maturity. Additionally, the kerogen carbonyl functional group (FaC) decreases greatly from immature to low maturities, leveling off between 300 °C and 325 °C, allowing FaC to be a tool for determining low maturities.

New Advances in Re-Os Geochronology of Organic-rich Sedimentary Rocks.

NASA Astrophysics Data System (ADS)

Creaser, R. A.; Selby, D.; Kendall, B. S.

2003-12-01

Geochronology using 187Re-187Os is applicable to limited rock and mineral matrices, but one valuable application is the determination of depositional ages for organic-rich clastic sedimentary rocks like black shales. Clastic sedimentary rocks, in most cases, do not yield depositional ages using other radioactive isotope methods, but host much of Earth's fossil record upon which the relative geological timescale is based. As such, Re-Os dating of black shales has potentially wide application in timescale calibration studies and basin analysis, if sufficiently high precision and accuracy could be achieved. This goal requires detailed, systematic studies and evaluation of factors like standard compound stoichiometry, geologic effects, and the 187Re decay constant. Ongoing studies have resulted in an improved understanding of the abilities, limitations and systematics of the Re-Os geochronometer in black shales. First-order knowledge of the effects of processes like hydrocarbon maturation and low-grade metamorphism is now established. Hydrocarbon maturation does not impact the ability of the Re-Os geochronometer to determine depositional ages from black shales. The Re-Os age determined for the Exshaw Fm of western Canada is accurate within 2σ analytical uncertainty of the known age of the unit (U-Pb monazite from ash, conodont biostratigraphy). This suggests that the large improvement in precision attained for Re-Os dating of black shales by Cohen et al (ESPL 1999) over the pioneering work of Ravizza & Turekian (GCA 1989), relates to advances in analytical methodologies and sampling strategies, rather than a lack of disturbance by hydrocarbon maturation. We have found that a significant reduction in isochron scatter can be achieved by using an alternate dissolution medium, which preferentially attacks organic matter in which Re and Os are largely concentrated. This likely results from a more limited release of detrital Os and Re held in silicate materials during dissolution, compared with the inverse aqua regia medium used for Carius tube analysis. Using these "organic-selective" dissolution techniques, precise depositional ages have now been obtained from samples with very low TOC contents ( ˜0.5%), meaning that a greater range of clastic sedimentary rocks is amenable for Re-Os age dating. Well-fitted Re-Os isochrons of plausible geological age have also been determined from low-TOC shales subjected to chlorite-grade regional metamorphism. These results further illustrate the wide, but currently underutilized, potential of the Re-Os geochronometer in shales. The precision of age data attainable by the Re-Os system directly from black shales can be better than +/- 1% uncertainty (2σ , derived from isochron regression analysis), and the derived ages are demonstrably accurate.

Synchrotron quantification of fracturing during maturation of shales

NASA Astrophysics Data System (ADS)

Figueroa Pilz, Fernando; Fauchille, Anne-Laure; Dowey, Patrick; Courtois, Loic; Bay, Brian; Ma, Lin; Taylor, Kevin; Mecklenburgh, Julian; Lee, Peter

2017-04-01

To understand both the hydrocarbon migration within and from shale rocks, and during hydraulic fracturing, is needed to evaluate and predict its environmental footprint. As a consequence, the time characterization of fracture networks in shale is particularly important. Time resolved synchrotron X-ray tomography was used to quantify the initiation and propagation of fractures during the simulated maturation of an organic-rich Kimmeridge Clay shale from the µm to mm scales. Scanning electron microscopy (SEM) observations were performed before and after maturation in order to compare the microstructure evolution and better understand the fracture location. Fracture and strain development during heating was quantified in 3D by Digital Volume Correlation (DVC) (Bay et al., 1999). The combination of DVC, X-Ray tomography and SEM obtained direct 4D strain measurements of the anisotropic mechanical behaviour of Kimmeridge shale with the temperature during an accelerated thermal maturation (Figueroa Pilz et al.). Such a combination has rarely been investigated in 4D at these scales in the past. In the study conditions, the results demonstrated the anisotropy in thermal expansion and the aperture fracture pathways through organic matter and clay matrix.

Provenance of the Walash-Naopurdan back-arc-arc clastic sequences in the Iraqi Zagros Suture Zone

NASA Astrophysics Data System (ADS)

Ali, Sarmad A.; Sleabi, Rajaa S.; Talabani, Mohammad J. A.; Jones, Brian G.

2017-01-01

Marine clastic rocks occurring in the Walash and Naopurdan Groups in the Hasanbag and Qalander areas, Kurdistan region, Iraqi Zagros Suture Zone, are lithic arenites with high proportions of volcanic rock fragments. Geochemical classification of the Eocene Walash and Oligocene Naopurdan clastic rocks indicates that they were mainly derived from associated sub-alkaline basalt and andesitic basalt in back-arc and island arc tectonic settings. Major and trace element geochemical data reveal that the Naopurdan samples are chemically less mature than the Walash samples and both were subjected to moderate weathering. The seaway in the southern Neotethys Ocean was shallow during both Eocene and Oligocene permitting mixing of sediment from the volcanic arcs with sediment derived from the Arabian continental margin. The Walash and Naopurdan clastic rocks enhance an earlier tectonic model of the Zagros Suture Zone with their deposition occurring during the Eocene Walash calc-alkaline back-arc magmatism and Early Oligocene Naopurdan island arc magmatism in the final stages of intra-oceanic subduction before the Miocene closure and obduction of the Neotethys basin.

Simulation of ground-water flow to assess geohydrologic factors and their effect on source-water areas for bedrock wells in Connecticut

USGS Publications Warehouse

Starn, J. Jeffrey; Stone, Janet Radway

2005-01-01

Generic ground-water-flow simulation models show that geohydrologic factors?fracture types, fracture geometry, and surficial materials?affect the size, shape, and location of source-water areas for bedrock wells. In this study, conducted by the U.S. Geological Survey in cooperation with the Connecticut Department of Public Health, ground-water flow was simulated to bedrock wells in three settings?on hilltops and hillsides with no surficial aquifer, in a narrow valley with a surficial aquifer, and in a broad valley with a surficial aquifer?to show how different combinations of geohydrologic factors in different topographic settings affect the dimensions and locations of source-water areas in Connecticut. Three principal types of fractures are present in bedrock in Connecticut?(1) Layer-parallel fractures, which developed as partings along bedding in sedimentary rock and compositional layering or foliation in metamorphic rock (dips of these fractures can be gentle or steep); (2) unroofing joints, which developed as strain-release fractures parallel to the land surface as overlying rock was removed by erosion through geologic time; and (3) cross fractures and joints, which developed as a result of tectonically generated stresses that produced typically near-vertical or steeply dipping fractures. Fracture geometry is defined primarily by the presence or absence of layering in the rock unit, and, if layered, by the angle of dip in the layering. Where layered rocks dip steeply, layer-parallel fracturing generally is dominant; unroofing joints also are typically well developed. Where layered rocks dip gently, layer-parallel fracturing also is dominant, and connections among these fractures are provided only by the cross fractures. In gently dipping rocks, unroofing joints generally do not form as a separate fracture set; instead, strain release from unroofing has occurred along gently dipping layer-parallel fractures, enhancing their aperture. In nonlayered and variably layered rocks, layer-parallel fracturing is absent or poorly developed; fracturing is dominated by well-developed subhorizontal unroofing joints and steeply dipping, tectonically generated fractures and (or) cooling joints. Cross fractures (or cooling joints) in nonlayered and variably layered rocks have more random orientations than in layered rocks. Overall, nonlayered or variably layered rocks do not have a strongly developed fracture direction. Generic ground-water-flow simulation models showed that fracture geometry and other geohydrologic factors affect the dimensions and locations of source-water areas for bedrock wells. In general, source-water areas to wells reflect the direction of ground-water flow, which mimics the land-surface topography. Source-water areas to wells in a hilltop setting were not affected greatly by simulated fracture zones, except for an extensive vertical fracture zone. Source-water areas to wells in a hillside setting were not affected greatly by simulated fracture zones, except for the combination of a subhorizontal fracture zone and low bedrock vertical hydraulic conductivity, as might be the case where an extensive subhorizontal fracture zone is not connected or is poorly connected to the surface through vertical fractures. Source-water areas to wells in a narrow valley setting reflect complex ground-water-flow paths. The typical flow path originates in the uplands and passes through either till or bedrock into the surficial aquifer, although only a small area of the surficial aquifer actually contributes water to the well. Source-water areas in uplands can include substantial areas on both sides of a river. Source-water areas for wells in this setting are affected mainly by the rate of ground-water recharge and by the degree of anisotropy. Source-water areas to wells in a broad valley setting (bedrock with a low angle of dip) are affected greatly by fracture properties. The effect of a given fracture is to channel the

Growing Pebbles and Conceptual Prisms - Understanding the Source of Student Misconceptions about Rock Formation.

ERIC Educational Resources Information Center

Kusnick, Judi

2002-01-01

Analyzes narrative essays--stories of rock formation--written by pre-service elementary school teachers. Reports startling misconceptions among preservice teachers on pebbles that grow, human involvement in rock formation, and sedimentary rocks forming as puddles as dry up, even though these students had completed a college level course on Earth…

Distribution and geological sources of selenium in environmental materials in Taoyuan County, Hunan Province, China.

PubMed

Ni, Runxiang; Luo, Kunli; Tian, Xinglei; Yan, Songgui; Zhong, Jitai; Liu, Maoqiu

2016-06-01

The selenium (Se) distribution and geological sources in Taoyuan County, China, were determined by using hydride generation atomic fluorescence spectrometry on rock, soil, and food crop samples collected from various geological regions within the county. The results show Se contents of 0.02-223.85, 0.18-7.05, and 0.006-5.374 mg/kg in the rock, soil, and food crops in Taoyuan County, respectively. The region showing the highest Se content is western Taoyuan County amid the Lower Cambrian and Ediacaran black rock series outcrop, which has banding distributed west to east. A relatively high-Se environment is found in the central and southern areas of Taoyuan County, where Quaternary Limnetic sedimentary facies and Neoproterozoic metamorphic volcanic rocks outcrop, respectively. A relatively low-Se environment includes the central and northern areas of Taoyuan County, where Middle and Upper Cambrian and Ordovician carbonate rocks and Cretaceous sandstones and conglomerates outcrop. These results indicate that Se distribution in Taoyuan County varies markedly and is controlled by the Se content of the bedrock. The Se-enriched Lower Cambrian and Ediacaran black rock series is the primary source of the seleniferous environment observed in Taoyuan County. Potential seleniferous environments are likely to be found near outcrops of the Lower Cambrian and Ediacaran black rock series in southern China.

Maturation history of Neogene-Quaternary sediments, Nile delta basin, Egypt

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

Ramadan Abu El-Ella

1990-01-01

The present Nile delta area covers approximately 60,000 km{sup 2}. Fields in this area provide two-thirds of the gas production in Egypt. Geological knowledge of the Nile delta is still limited because of insufficient subsurface data. Gas is generated and accumulates at stratigraphic levels ranging from the lower Miocene to the lower Pliocene. The highest levels of organic maturation in the Neogene-Quaternary section are in the northern part of the onshore area, such as in the Abu Madi well, and in the eastern part of the offshore area, such as in the El Temsah well, where gas reservoirs occur inmore » the lower Pliocene sandstones (Abu Madi Formation), and in the underlying Sidi Salem Formation and lower Miocene rocks. Here, the Sidi Salem Formation is probably generative, having an R{sub 0} of approximately 0.65%, LOM (levels of organic metamorphism) of 9.5 to 9.7, and TTI (time-temperature index) of 9.7 to 15.2. By contrast, a different thermal history clearly existed in the western and eastern parts of the onshore area, such as in the Monaga and Damanhur wells, where the organic maturities are significantly lower than maturities elsewhere in the basin (R{sub 0} = 0.38 and 0.29%, respectively). The predicted maturities obtained by using the LOM method seem to fit much closer to the observed maturities than the predicted maturities obtained by using the Lopatin TTI method. 5 figs.« less

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 influence of geology and land use on arsenic in stream sediments and ground waters in New England, USA

USGS Publications Warehouse

Robinson, G.R.; Ayotte, J.D.

2006-01-01

Population statistics for As concentrations in rocks, sediments and ground water differ by geology and land use features in the New England region, USA. Significant sources of As in the surficial environment include both natural weathering of rocks and anthropogenic sources such as arsenical pesticides that were commonly applied to apple, blueberry and potato crops during the first half of the 20th century in the region. The variation of As in bedrock ground water wells has a strong positive correlation with geologic features at the geologic province, lithology group, and bedrock map unit levels. The variation of As in bedrock ground water wells also has a positive correlation with elevated stream sediment and rock As chemistry. Elevated As concentrations in bedrock wells do not correlate with past agricultural areas that used arsenical pesticides on crops. Stream sediments, which integrate both natural and anthropogenic sources, have a strong positive correlation of As concentrations with rock chemistry, geologic provinces and ground water chemistry, and a weaker positive correlation with past agricultural land use. Although correlation is not sufficient to demonstrate cause-and-effect, the statistics favor rock-based As as the dominant regional source of the element in stream sediments and ground water in New England. The distribution of bedrock geology features at the geologic province, lithology group and map unit level closely correlate with areas of elevated As in ground water, stream sediments, and rocks. ?? 2006 Elsevier Ltd. All rights reserved.

The information content of high-frequency seismograms and the near-surface geologic structure of "hard rock" recording sites

USGS Publications Warehouse

Cranswick, E.

1988-01-01

Due to hardware developments in the last decade, the high-frequency end of the frequency band of seismic waves analyzed for source mechanisms has been extended into the audio-frequency range (>20 Hz). In principle, the short wavelengths corresponding to these frequencies can provide information about the details of seismic sources, but in fact, much of the "signal" is the site response of the nearsurface. Several examples of waveform data recorded at "hard rock" sites, which are generally assumed to have a "flat" transfer function, are presented to demonstrate the severe signal distortions, including fmax, produced by near-surface structures. Analysis of the geology of a number of sites indicates that the overall attenuation of high-frequency (>1 Hz) seismic waves is controlled by the whole-path-Q between source and receiver but the presence of distinct fmax site resonance peaks is controlled by the nature of the surface layer and the underlying near-surface structure. Models of vertical decoupling of the surface and nearsurface and horizontal decoupling of adjacent sites on hard rock outcrops are proposed and their behaviour is compared to the observations of hard rock site response. The upper bound to the frequency band of the seismic waves that contain significant source information which can be deconvolved from a site response or an array response is discussed in terms of fmax and the correlation of waveform distortion with the outcrop-scale geologic structure of hard rock sites. It is concluded that although the velocity structures of hard rock sites, unlike those of alluvium sites, allow some audio-frequency seismic energy to propagate to the surface, the resulting signals are a highly distorted, limited subset of the source spectra. ?? 1988 Birkha??user Verlag.

Geochemistry and source waters of rock glacier outflow, Colorado Front Range

USGS Publications Warehouse

Williams, M.W.; Knauf, M.; Caine, N.; Liu, F.; Verplanck, P.L.

2006-01-01

We characterize the seasonal variation in the geochemical and isotopic content of the outflow of the Green Lake 5 rock glacier (RG5), located in the Green Lakes Valley of the Colorado Front Range, USA. Between June and August, the geochemical content of rock glacier outflow does not appear to differ substantially from that of other surface waters in the Green Lakes Valley. Thus, for this alpine ecosystem at this time of year there does not appear to be large differences in water quality among rock glacier outflow, glacier and blockslope discharge, and discharge from small alpine catchments. However, in September concentrations of Mg2+ in the outflow of the rock glacier increased to more than 900 ??eq L-1 compared to values of less than 40 ??eq L-1 at all the other sites, concentrations of Ca2+ were greater than 4,000 ??eq L-1 compared to maximum values of less than 200 ??eq L-1 at all other sites, and concentrations of SO42- reached 7,000 ??eq L-1, compared to maximum concentrations below 120 ??eq L-1 at the other sites. Inverse geochemical modelling suggests that dissolution of pyrite, epidote, chlorite and minor calcite as well as the precipitation of silica and goethite best explain these elevated concentrations of solutes in the outflow of the rock glacier. Three component hydrograph separation using end-member mixing analysis shows that melted snow comprised an average of 30% of RG5 outflow, soil water 32%, and base flow 38%. Snow was the dominant source water in June, soil water was the dominant water source in July, and base flow was the dominant source in September. Enrichment of ?? 18O from - 10??? in the outflow of the rock glacier compared to -20??? in snow and enrichment of deuterium excess from +17.5??? in rock glacier outflow compared to +11??? in snow, suggests that melt of internal ice that had undergone multiple melt/freeze episodes was the dominant source of base flow. Copyright ?? 2005 John Wiley & Sons, Ltd.

Hydrogen in rocks: an energy source for deep microbial communities

NASA Technical Reports Server (NTRS)

Freund, Friedemann; Dickinson, J. Thomas; Cash, Michele

2002-01-01

To survive in deep subsurface environments, lithotrophic microbial communities require a sustainable energy source such as hydrogen. Though H2 can be produced when water reacts with fresh mineral surfaces and oxidizes ferrous iron, this reaction is unreliable since it depends upon the exposure of fresh rock surfaces via the episodic opening of cracks and fissures. A more reliable and potentially more voluminous H2 source exists in nominally anhydrous minerals of igneous and metamorphic rocks. Our experimental results indicate that H2 molecules can be derived from small amounts of H2O dissolved in minerals in the form of hydroxyl, OH- or O3Si-OH, whenever such minerals crystallized in an H2O-laden environment. Two types of experiments were conducted. Single crystal fracture experiments indicated that hydroxyl pairs undergo an in situ redox conversion to H2 molecules plus peroxy links, O3Si/OO\\SiO3. While the peroxy links become part of the mineral structure, the H2 molecules diffused out of the freshly fractured mineral surfaces. If such a mechanism occurred in natural settings, the entire rock column would become a volume source of H2. Crushing experiments to facilitate the outdiffusion of H2 were conducted with common crustal igneous rocks such as granite, andesite, and labradorite. At least 70 nmol of H2/g diffused out of coarsely crushed andesite, equivalent at standard pressure and temperature to 5,000 cm3 of H2/m3 of rock. In the water-saturated, biologically relevant upper portion of the rock column, the diffusion of H2 out of the minerals will be buffered by H2 saturation of the intergranular water film.

Capillary Trapping of CO2 in Oil Reservoirs: Observations in a Mixed-Wet Carbonate Rock.

PubMed

Al-Menhali, Ali S; Krevor, Samuel

2016-03-01

Early deployment of carbon dioxide storage is likely to focus on injection into mature oil reservoirs, most of which occur in carbonate rock units. Observations and modeling have shown how capillary trapping leads to the immobilization of CO2 in saline aquifers, enhancing the security and capacity of storage. There are, however, no observations of trapping in rocks with a mixed-wet-state characteristic of hydrocarbon-bearing carbonate reservoirs. Here, we found that residual trapping of supercritical CO2 in a limestone altered to a mixed-wet state with oil was significantly less than trapping in the unaltered rock. In unaltered samples, the trapping of CO2 and N2 were indistinguishable, with a maximum residual saturation of 24%. After the alteration of the wetting state, the trapping of N2 was reduced, with a maximum residual saturation of 19%. The trapping of CO2 was reduced even further, with a maximum residual saturation of 15%. Best-fit Land-model constants shifted from C = 1.73 in the water-wet rock to C = 2.82 for N2 and C = 4.11 for the CO2 in the mixed-wet rock. The results indicate that plume migration will be less constrained by capillary trapping for CO2 storage projects using oil fields compared with those for saline aquifers.

Geochemical evidence for African dust and volcanic ash inputs to terra rossa soils on carbonate reef terraces, northern Jamaica, West Indies

USGS Publications Warehouse

Muhs, D.R.; Budahn, J.R.

2009-01-01

The origin of red or reddish-brown, clay-rich, "terra rossa" soils on limestone has been debated for decades. A traditional qualitative explanation for their formation has been the accumulation of insoluble residues as the limestone is progressively dissolved over time. However, this mode of formation often requires unrealistic or impossible amounts of carbonate dissolution. Therefore, where this mechanism is not viable and where local fluvial or colluvial inputs can be ruled out, an external source or sources must be involved in soil formation. On the north coast of the Caribbean island of Jamaica, we studied a sequence of terra rossa soils developed on emergent limestones thought to be of Quaternary age. The soils become progressively thicker, redder, more Fe- and Al-rich and Si-poor with elevation. Furthermore, although kaolinite is found in all the soils, the highest and oldest soils also contain boehmite. Major and trace element geochemistry shows that the host limestones and local igneous rocks are not likely source materials for the soils. Other trace elements, including the rare earth elements (REE), show that tephra from Central American volcanoes is not a likely source either. However, trace element geochemistry shows that airborne dust from Africa plus tephra from the Lesser Antilles island arc are possible source materials for the clay-rich soils. A third, as yet unidentified, source may also contribute to the soils. We hypothesize that older, more chemically mature Jamaican bauxites may have had a similar origin. The results add to the growing body of evidence of the importance of multiple parent materials, including far-traveled dust, to soil genesis.

The Influence of Lithology on the Formation of Reaction Infiltration Instabilities in Mantle Rocks

NASA Astrophysics Data System (ADS)

Pec, M.; Holtzman, B. K.; Zimmerman, M. E.; Kohlstedt, D. L.

2017-12-01

The formation of oceanic plates requires extraction of large volumes of melt from the mantle. Several lines of evidence suggest that melt extraction is rapid and, therefore, necessitates high-permeability pathways. Such pathways may form as a result of melt-rock reactions. We report the results of a series of Darcy-type experiments designed to study the development of channels due to melt-solid reactions in mantle lithologies. We sandwiched a partially molten rock between a melt source and a porous sink and annealed it at high pressure (P = 300 MPa) and high temperatures (T = 1200° or 1250°C) with a controlled pressure gradient (∂P/∂z = 0-100 MPa/mm). To study the influence of lithology on the channel formation, we synthesized partially molten rocks of harzburgitic (40:40:20 Ol - Opx - basalt), wehrlitic (40:40:20 Ol - Cpx - basalt) and lherzolitic (65:25:10 Ol - Opx - Cpx) composition. The melt source was a disk of alkali basalt. In all experiments, irrespective of the exact mineralogy, melt - undersaturated in silica - from the source dissolved pyroxene in the partially molten rock and precipitated olivine ( Fo82), thereby forming a dunite reaction layer at the interface between the source and the partially molten rock. In samples annealed under a small pressure gradient, the reaction layer was roughly planar. However, if the velocity of melt due to porous flow exceeded 0.1 µm/s, the reaction layer locally protruded into the partially molten rock forming finger-like, melt-rich channels in rocks of wehrlitic and harzburgitic composition. The lherzolitic rocks were generally impermeable to the melt except at highest-pressure gradients where a narrow fracture developed, forming a dyke which drained the melt reservoir. Three-dimensional reconstructions using micro-CT images revealed clear differences between the dyke (a narrow, through-going planar feature) and the channels formed by reactive infiltration (multiple sinuous finger-like features). Apparently, the fraction of soluble minerals together with the melt fraction in the partially molten rock control whether dykes or reactive channels develop. Our experiments demonstrate that melt-rock reactions can lead to channelization in mantle lithologies, and the observed lithological transformations broadly agree with those observed in nature

Origin of sulfur for elemental sulfur concentration in salt dome cap rocks, Gulf Coast Basin, USA

NASA Astrophysics Data System (ADS)

Hill, J. M.; Kyle, R.; Loyd, S. J.

2017-12-01

Calcite cap rocks of the Boling and Main Pass salt domes contain large elemental sulfur accumulations. Isotopic and petrographic data indicate complex histories of cap rock paragenesis for both domes. Whereas paragenetic complexity is in part due to the open nature of these hydrodynamic systems, a comprehensive understanding of elemental sulfur sources and concentration mechanisms is lacking. Large ranges in traditional sulfur isotope compositions (δ34S) among oxidized and reduced sulfur-bearing phases has led some to infer that microbial sulfate reduction and/or influx of sulfide-rich formation waters occurred during calcite cap rock formation. Ultimately, traditional sulfur isotope analyses alone cannot distinguish among local microbial or exogenous sulfur sources. Recently, multiple sulfur isotope (32S, 33S, 34S, 36S) studies reveal small, but measurable differences in mass-dependent behavior of microbial and abiogenic processes. To distinguish between the proposed sulfur sources, multiple-sulfur-isotope analyses have been performed on native sulfur from the Boling and Main Pass cap rocks. Similarities or deviations from equilibrium relationships indicate which pathways were responsible for native sulfur precipitation. Pathway determination provides insight into Gulf Coast cap rock development and potentially highlights the conditions that led to anomalous sulfur enrichment in Boling and Main Pass Domes.

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; Paul Aharon; Donald A. Goddard

2006-05-26

The principal research effort for Phase 1 (Concept Development) of the project has been data compilation; determination of the tectonic, depositional, burial, and thermal maturation histories of the North Louisiana Salt Basin; basin modeling (geohistory, thermal maturation, hydrocarbon expulsion); petroleum system identification; comparative basin evaluation; and resource assessment. Existing information on the North Louisiana Salt Basin has been evaluated, an electronic database has been developed, and regional cross sections have been prepared. Structure, isopach and formation lithology maps have been constructed, and burial history, thermal maturation history, and hydrocarbon expulsion profiles have been prepared. Seismic data, cross sections, subsurface mapsmore » and burial history, thermal maturation history, and hydrocarbon expulsion 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 include Upper Jurassic and Cretaceous fluvial-deltaic sandstone facies; shoreline, marine bar and shallow shelf sandstone facies; and carbonate shoal, shelf and reef 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 during the Early to Late Cretaceous. The geohistory of the North Louisiana Salt Basin is comparable to the Mississippi Interior Salt Basin with the major difference being the elevated heat flow the strata in the North Louisiana Salt Basin experienced in the Cretaceous due primarily to reactivation of upward movement, igneous activity, and erosion associated with the Monroe and Sabine Uplifts. Potential undiscovered reservoirs in the North Louisiana Salt Basin are Triassic Eagle Mills sandstone and deeply buried Upper Jurassic sandstone and limestone. Potential underdeveloped reservoirs include Lower Cretaceous sandstone and limestone and Upper Cretaceous sandstone.« less

Intra-population trends in the maturation and reproduction of a temperate marine herbivore Girella elevata across latitudinal clines.

PubMed

Stocks, J R; Gray, C A; Taylor, M D

2015-01-23

Latitudinal variation in the reproductive characteristics of a temperate marine herbivore, rock blackfish Girella elevata, was examined from three regions of the south-eastern Australian coast. Biological sampling covered 780 km of coastline, including the majority of the species distribution. The sampling range incorporated three distinct oceanographic regions of the East Australian Current, a poleward-flowing western boundary current of the Southern Pacific Gyre and climate-change hotspot. Girella elevata are a highly fecund, group synchronous (multiple batch)-spawner. Mean fork length (L F ) and age at maturity were greater for females than males within all regions, with both male and female G. elevata of the southern region maturing at a greater size and age than those from the central region. Estimates of batch fecundity (F B ) were greatest in the northern and southern regions, relative to the central region where growth rates were greatest. Significant positive relationships were observed between F B and L F , and F B and total fish mass. Gonado-somatic indices indicated latitudinal synchrony in spawning seasonality between G. elevata at higher latitudes, spawning in the late austral spring and summer. A late or prolonged spawning period is evident for G. elevata from the northern region. Juvenile recruitment to intertidal rock pools within the central and southern regions was synchronous with the spawning season, however, no juveniles were found within the northern region. The implications of latitudinal variation in reproductive characteristics are discussed in the context of climate and oceanographic conditions of south-east Australia. © 2015 The Fisheries Society of the British Isles.

Occurrence of Mesocestoides canislagopodis (Rudolphi, 1810) (Krabbe, 1865) in mammals and birds in Iceland and its molecular discrimination within the Mesocestoides species complex.

PubMed

Skirnisson, Karl; Jouet, Damien; Ferté, Hubert; Nielsen, Ólafur K

2016-07-01

The life cycle of Mesocestoides tapeworms (Cestoda: Cyclophyllidea: Mesocestoididae) requires three hosts. The first intermediate host is unknown but believed to be an arthropod. The second intermediate host is a vertebrate. The primary definitive host is a carnivore mammal, or a bird of prey, that eats the tetrathyridium-infected second intermediate host. One representative of the genus, Mesocestoides canislagopodis, has been reported from Iceland. It is common in the arctic fox (Vulpes lagopus) and has also been detected in domestic dogs (Canis familiaris) and cats (Felis domestica). Recently, scolices of a non-maturing Mesocestoides sp. have also been detected in gyrfalcon (Falco rusticolus) intestines, and tetrathyridia in the body cavity of rock ptarmigan (Lagopus muta). We examined the taxonomic relationship of Mesocestoides from arctic fox, gyrfalcon, and rock ptarmigan using molecular methods, both at the generic level (D1 domain LSU ribosomal DNA) and at the specific level (cytochrome c oxidase subunit I (COI) and 12S mitochondrial DNA). All stages belonged to Mesocestoides canislagopodis. Phylogenetic analysis of the combined 12S-COI at the specific level confirmed that M. canislagopodis forms a distinct clade, well separated from three other recognized representatives of the genus, M. litteratus, M. lineatus, and M. corti/vogae. This is the first molecular description of this species. The rock ptarmigan is a new second intermediate host record, and the gyrfalcon a new primary definitive host record. However, the adult stage seemed not to be able to mature in the gyrfalcon, and successful development is probably restricted to mammalian hosts.

Pb, Sr, and Nd isotopic compositions of a suite of Late Archean, igneous rocks, eastern Beartooth Mountains: implications for crust-mantle evolution

USGS Publications Warehouse

Wooden, J.L.; Mueller, P.A.

1988-01-01

A series of compositionally diverse, Late Archean rocks (2.74-2.79 Ga old) from the eastern Beartooth Mountains, Montana and Wyoming, U.S.A., have the same initial Pb, Sr, and Nd isotopic ratios. Lead and Sr initial ratios are higher and Nd initial ratios lower than would be expected for rocks derived from model mantle sources and strongly indicate the involvement of an older crustal reservoir in the genesis of these rocks. Crustal contamination during emplacement can be ruled out for a variety of reasons. Instead a model involving subduction of continental detritus and contamination of the overlying mantle as is often proposed for modern subduction environments is preferred. This contaminated mantle would have all the isotopic characteristics of mantle enriched by internal mantle metasomatism but would require no long-term growth or changes in parent to daughter element ratios. This contaminated mantle would make a good source for some of the Cenozoic mafic volcanics of the Columbia River, Snake River Plain, and Yellowstone volcanic fields that are proposed to come from ancient, enriched lithospheric mantle. The isotopic characteristics of the 2.70 Ga old Stillwater Complex are a perfect match for the proposed contaminated mantle which provides an alternative to crustal contamination during emplacement. The Pb isotopic characteristics of the Late Archean rocks of the eastern Beartooth Mountains are similar to those of other Late Archean rocks of the Wyoming Province and suggest that Early Archean, upper crustal rocks were common in this terrane. The isotopic signatures of Late Archean rocks in the Wyoming Province are distinctive from those of other Archean cratons in North America which are dominated by a MORB-like, Archean mantle source (Superior Province) and/or a long-term depleted crustal source (Greenland). ?? 1988.

The geochemistry of primitive volcanic rocks of the Ankaratra volcanic complex, and source enrichment processes in the genesis of the Cenozoic magmatism in Madagascar

NASA Astrophysics Data System (ADS)

Melluso, L.; Cucciniello, C.; le Roex, A. P.; Morra, V.

2016-07-01

The Ankaratra volcanic complex in central Madagascar consists of lava flows, domes, scoria cones, tuff rings and maars of Cenozoic age that are scattered over 3800 km2. The mafic rocks include olivine-leucite-nephelinites, basanites, alkali basalts and hawaiites, and tholeiitic basalts. Primitive samples have high Mg# (>60), high Cr and Ni concentrations; their mantle-normalized patterns peak at Nb and Ba, have troughs at K, and smoothly decrease towards the least incompatible elements. The Ankaratra mafic rocks show small variation in Sr-Nd-Pb isotopic compositions (e.g., 87Sr/86Sr = 0.70377-0.70446, 143Nd/144Nd = 0.51273-0.51280, 206Pb/204Pb = 18.25-18.87). These isotopic values differ markedly from those of Cenozoic mafic lavas of northern Madagascar and the Comoro archipelago, typical Indian Ocean MORB and oceanic basalt end-members. The patterns of olivine nephelinitic magmas can be obtained through 3-10% partial melting of a mantle source that was enriched by a Ca-rich alkaline melt, and that contained garnet, carbonates and phlogopite. The patterns of tholeiitic basalts can be obtained after 10-12% partial melting of a source enriched with lower amounts of the same alkaline melt, in the spinel- (and possibly amphibole-) facies mantle, hence in volumes where carbonate is not a factor. The significant isotopic change from the northernmost volcanic rocks of Madagascar and those in the central part of the island implicates a distinct source heterogeneity, and ultimately assess the role of the continental lithospheric mantle as source region. The source of at least some volcanic rocks of the still active Comoro archipelago may have suffered the same time-integrated geochemical and isotopic evolution as that of the northern Madagascar volcanic rocks.

Uranium enrichment in lacustrine oil source rocks of the Chang 7 member of the Yanchang Formation, Erdos Basin, China

NASA Astrophysics Data System (ADS)

Yang, Hua; Zhang, Wenzheng; Wu, Kai; Li, Shanpeng; Peng, Ping'an; Qin, Yan

2010-09-01

The oil source rocks of the Chang 7 member of the Yanchang Formation in the Erdos Basin were deposited during maximum lake extension during the Late Triassic and show a remarkable positive uranium anomaly, with an average uranium content as high as 51.1 μg/g. Uranium is enriched together with organic matter and elements such as Fe, S, Cu, V and Mo in the rocks. The detailed biological markers determined in the Chang 7 member indicate that the lake water column was oxidizing during deposition of the Chang 7 member. However, redox indicators for sediments such as S 2- content, V/Sc and V/(V + Ni) ratios demonstrate that it was a typical anoxic diagenetic setting. The contrasted redox conditions between the water column and the sediment with a very high content of organic matter provided favorable physical and chemical conditions for syngenetic uranium enrichment in the oil source rocks of the Chang 7 member. Possible uranium sources may be the extensive U-rich volcanic ash that resulted from contemporaneous volcanic eruption and uranium material transported by hydrothermal conduits into the basin. The uranium from terrestrial clastics was unlike because uranium concentration was not higher in the margin area of basin where the terrestrial material input was high. As indicated by correlative analysis, the oil source rocks of the Chang 7 member show high gamma-ray values for radioactive well log data that reflect a positive uranium anomaly and are characterized by high resistance, low electric potential and low density. As a result, well log data can be used to identify positive uranium anomalies and spatial distribution of the oil source rocks in the Erdos Basin. The estimation of the total uranium reserves in the Chang 7 member attain 0.8 × 10 8 t.

Seismological evidence for monsoon induced micro to moderate earthquake sequence beneath the 2011 Talala, Saurashtra earthquake, Gujarat, India

NASA Astrophysics Data System (ADS)

Singh, A. P.; Mishra, O. P.

2015-10-01

In order to understand the processes involved in the genesis of monsoon induced micro to moderate earthquakes after heavy rainfall during the Indian summer monsoon period beneath the 2011 Talala, Saurashtra earthquake (Mw 5.1) source zone, we assimilated 3-D microstructures of the sub-surface rock materials using a data set recorded by the Seismic Network of Gujarat (SeisNetG), India. Crack attributes in terms of crack density (ε), the saturation rate (ξ) and porosity parameter (ψ) were determined from the estimated 3-D sub-surface velocities (Vp, Vs) and Poisson's ratio (σ) structures of the area at varying depths. We distinctly imaged high-ε, high-ξ and low-ψ anomalies at shallow depths, extending up to 9-15 km. We infer that the existence of sub-surface fractured rock matrix connected to the surface from the source zone may have contributed to the changes in differential strain deep down to the crust due to the infiltration of rainwater, which in turn induced micro to moderate earthquake sequence beneath Talala source zone. Infiltration of rainwater during the Indian summer monsoon might have hastened the failure of the rock by perturbing the crustal volume strain of the causative source rock matrix associated with the changes in the seismic moment release beneath the surface. Analyses of crack attributes suggest that the fractured volume of the rock matrix with high porosity and lowered seismic strength beneath the source zone might have considerable influence on the style of fault displacements due to seismo-hydraulic fluid flows. Localized zone of micro-cracks diagnosed within the causative rock matrix connected to the water table and their association with shallow crustal faults might have acted as a conduit for infiltrating the precipitation down to the shallow crustal layers following the fault suction mechanism of pore pressure diffusion, triggering the monsoon induced earthquake sequence beneath the source zone.

Re-Os systematics of komatiites and komatiitic basalts at Dundonald Beach, Ontario, Canada: Evidence for a complex alteration history and implications of a late-Archean chondritic mantle source

NASA Astrophysics Data System (ADS)

Gangopadhyay, Amitava; Sproule, Rebecca A.; Walker, Richard J.; Lesher, C. Michael

2005-11-01

Osmium isotopic compositions, and Re and Os concentrations have been examined in one komatiite unit and two komatiitic basalt units at Dundonald Beach, part of the 2.7 Ga Kidd-Munro volcanic assemblage in the Abitibi greenstone belt, Ontario, Canada. The komatiitic rocks in this locality record at least three episodes of alteration of Re-Os elemental and isotope systematics. First, an average of 40% and as much as 75% Re may have been lost due to shallow degassing during eruption and/or hydrothermal leaching during or immediately after emplacement. Second, the Re-Os isotope systematics of whole rock samples with 187Re/ 188Os ratios >1 were reset at ˜2.5 Ga, possibly due to a regional metamorphic event. Third, there is evidence for relatively recent gain and loss of Re in some rocks. Despite the open-system behavior, some aspects of the Re-Os systematics of these rocks can be deciphered. The bulk distribution coefficient for Os (D Ossolid/liquid) for the Dundonald rocks is ˜3 ± 1 and is well within the estimated D values obtained for komatiites from the nearby Alexo area and stratigraphically-equivalent komatiites from Munro Township. This suggests that Os was moderately compatible during crystal-liquid fractionation of the magmas parental to the Kidd-Munro komatiitic rocks. Whole-rock samples and chromite separates with low 187Re/ 188Os ratios (<1) yield a precise chondritic average initial 187Os/ 188Os ratio of 0.1083 ± 0.0006 (γ Os = 0.0 ± 0.6) for their well-constrained ˜2715 Ma crystallization age. The chondritic initial Os isotopic composition of the mantle source for the Dundonald rocks is consistent with that determined for komatiites in the Alexo area and in Munro Township, suggesting that the mantle source region for the Kidd-Munro volcanic assemblage had evolved with a long-term chondritic Re/Os before eruption. The chondritic initial Os isotopic composition of the Kidd-Munro komatiites is indistinguishable from that of the projected contemporaneous convective upper mantle. The uniform chondritic Os isotopic composition of the Kidd-Munro komatiites contrasts with the typical large-scale Os isotopic heterogeneity in the mantle sources for ca. 89 Ma komatiites from the Gorgona Island, arc-related rocks and present-day ocean island basalts. This suggests that the Kidd-Munro komatiites sampled a late-Archean mantle source region that was significantly more homogeneous with respect to Re/Os relative to most modern mantle-derived rocks.

40 CFR 412.30 - Applicability.

Code of Federal Regulations, 2012 CFR

2012-07-01

... CONCENTRATED ANIMAL FEEDING OPERATIONS (CAFO) POINT SOURCE CATEGORY Dairy Cows and Cattle Other Than Veal... operations (CAFOs) under 40 CFR 122.23 and includes the following animals: mature dairy cows, either milking or dry; cattle other than mature dairy cows or veal calves. Cattle other than mature dairy cows...

40 CFR 412.30 - Applicability.

Code of Federal Regulations, 2014 CFR

2014-07-01

... CONCENTRATED ANIMAL FEEDING OPERATIONS (CAFO) POINT SOURCE CATEGORY Dairy Cows and Cattle Other Than Veal... operations (CAFOs) under 40 CFR 122.23 and includes the following animals: mature dairy cows, either milking or dry; cattle other than mature dairy cows or veal calves. Cattle other than mature dairy cows...

40 CFR 412.30 - Applicability.

Code of Federal Regulations, 2013 CFR

2013-07-01

... CONCENTRATED ANIMAL FEEDING OPERATIONS (CAFO) POINT SOURCE CATEGORY Dairy Cows and Cattle Other Than Veal... operations (CAFOs) under 40 CFR 122.23 and includes the following animals: mature dairy cows, either milking or dry; cattle other than mature dairy cows or veal calves. Cattle other than mature dairy cows...

40 CFR 412.30 - Applicability.

Code of Federal Regulations, 2011 CFR

2011-07-01

... CONCENTRATED ANIMAL FEEDING OPERATIONS (CAFO) POINT SOURCE CATEGORY Dairy Cows and Cattle Other Than Veal... operations (CAFOs) under 40 CFR 122.23 and includes the following animals: mature dairy cows, either milking or dry; cattle other than mature dairy cows or veal calves. Cattle other than mature dairy cows...

Physical abrasion of mafic minerals and basalt grains: application to Martian aeolian deposits

USGS Publications Warehouse

Cornwall, Carin; Bandfield, Joshua L.; Titus, Timothy N.; Schreiber, B. C.; Montgomery, D.R.

2015-01-01

Sediment maturity, or the mineralogical and physical characterization of sediment deposits, has been used to locate sediment source, transport medium and distance, weathering processes, and paleoenvironments on Earth. Mature terrestrial sands are dominated by quartz, which is abundant in source lithologies on Earth and is physically and chemically stable under a wide range of conditions. Immature sands, such as those rich in feldspars or mafic minerals, are composed of grains that are easily physically weathered and highly susceptible to chemical weathering. On Mars, which is predominately mafic in composition, terrestrial standards of sediment maturity are not applicable. In addition, the martian climate today is cold, dry and sediments are likely to be heavily influenced by physical weathering rather than chemical weathering. Due to these large differences in weathering processes and composition, martian sediments require an alternate maturity index. Abrason tests have been conducted on a variety of mafic materials and results suggest that mature martian sediments may be composed of well sorted, well rounded, spherical basalt grains. In addition, any volcanic glass present is likely to persist in a mechanical weathering environment while chemically altered products are likely to be winnowed away. A modified sediment maturity index is proposed that can be used in future studies to constrain sediment source, paleoclimate, mechanisms for sediment production, and surface evolution. This maturity index may also provide details about erosional and sediment transport systems and preservation processes of layered deposits.

Genetic transformation of mature citrus plants.

PubMed

Cervera, Magdalena; Juárez, José; Navarro, Luis; Peña, Leandro

2005-01-01

Most woody fruit species have long juvenile periods that drastically prolong the time required to analyze mature traits. Evaluation of characteristics related to fruits is a requisite to release any new variety into the market. Because of a decline in regenerative and transformation potential, genetic transformation procedures usually employ juvenile material as the source of plant tissue, therefore resulting in the production of juvenile plants. Direct transformation of mature material could ensure the production of adult transgenic plants, bypassing in this way the juvenile phase. Invigoration of the source adult material, establishment of adequate transformation and regeneration conditions, and acceleration of plant development through grafting allowed us to produce transgenic mature sweet orange trees flowering and bearing fruits in a short time period.

Variations of DNA methylation in Eucalyptus urophylla×Eucalyptus grandis shoot tips and apical meristems of different physiological ages.

PubMed

Mankessi, François; Saya, Aubin R; Favreau, Bénédicte; Doulbeau, Sylvie; Conéjéro, Geneviève; Lartaud, Marc; Verdeil, Jean-Luc; Monteuuis, Olivier

2011-10-01

Global DNA methylation was assessed by high-performance liquid chromatography (HPLC) for the first time in Eucalyptus urophylla×Eucalyptus grandis shoot tips comparing three outdoor and one in vitro sources of related genotypes differing in their physiological age. The DNA methylation levels found were consistent with those reported for other Angiosperms using the same HPLC technology. Notwithstanding noticeable time-related fluctuations within each source of plant material, methylation rate was overall higher for the mature clone (13.7%) than for the rejuvenated line of the same clone (12.6%) and for the juvenile offspring seedlings (11.8%). The in vitro microshoots of the mature clone were less methylated (11.3%) than the other outdoor origins, but the difference with the juvenile seedlings was not significant. Immunofluorescence investigations on shoot apices established that the mature source could be distinguished from the rejuvenated and juvenile origins by a higher density of cells with methylated nuclei in leaf primordia. Shoot apical meristems (SAMs) from the mature clone also showed a greater proportion and more methylated cells than SAMs from the rejuvenated and juvenile origins. The nuclei of these latter were characterized by fewer and more dispersed labeled spots than for the mature source. Our findings establish that physiological ageing induced quantitative and qualitative variations of DNA methylation at shoot tip, SAM and even cellular levels. Overall this DNA methylation increased with maturation and conversely decreased with rejuvenation to reach the lower scores and to show the immunolabeling patterns that characterized juvenile material nuclei. Copyright © Physiologia Plantarum 2011.