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Sample records for oil source rocks

  1. Oil source rocks in the Adiyaman area, southeast Turkey

    NASA Astrophysics Data System (ADS)

    Soylu, Cengiz

    In the Adiyaman area, southeast Turkey, two carbonate source rock units, the Karababa-A Member and the Karabogaz Formation, are identified. The maturity levels of the source rock units increase towards the north and the west. Both the Karababa-A Member and the Karabogaz Formation are good to excellent oil-source rocks with widespread "kitchen areas".

  2. Oils and hydrocarbon source rocks of the Baltic syneclise

    SciTech Connect

    Kanev, S.; Margulis, L. ); Bojesen-Koefoed, J.A. ); Weil, W.A.; Merta, H. ); Zdanaviciute, O. )

    1994-07-11

    Prolific source rock horizons of varying thickness, having considerable areal extent, occur over the Baltic syneclise. These source sediments are rich and have excellent petroleum generation potential. Their state of thermal maturity varies form immature in the northeastern part of the syneclise to peak generation maturity in the southwestern part of the region-the main kitchen area. These maturity variations are manifest in petroleum composition in the region. Hence, mature oils occur in the Polish and Kaliningrad areas, immature oils in small accumulations in Latvian and central Lithuanian onshore areas, and intermediate oils in areas between these extremes. The oil accumulations probably result from pooling of petroleum generated from a number of different source rocks at varying levels of thermal maturity. Hence, no single source for petroleum occurrences in the Baltic syneclise may be identified. The paper describes the baltic syneclise, source rocks, thermal maturity and oils and extracts.

  3. New oil source rocks cut in Greek Ionian basin

    SciTech Connect

    Karakitsios, V.; Rigakis, N.

    1996-02-12

    The Ionian zone of Northwest Greece (Epirus region) constitutes part of the most external zones of the Hellenides (Paxos zone, Ionian zone, Gavrovo Tripolitza zone). The rocks of the Ionian zone range from Triassic evaporites and associated breccias through a varied series of Jurassic through Upper Eocene carbonates and lesser cherts and shales followed by Oligocene flysch. The surface occurrences of petroleum in the Ionian zone are mainly attributed to Toarcian Lower Posidonia beds source rocks and lesser to late Callovian-Tithonian Upper Posidonia beds and to the Albian-Cenomanian Upper Siliceous zone or Vigla shales of the Vigla limestones. Oil that could not be attributed to the above source rocks is believed to have an origin from Triassic formations that contain potential source rocks in Albania and Italy. However, several samples of the shales of Triassic breccias from outcrops and drillholes were analyzed in the past, but the analytical results were not so promising since their hydrocarbon potential was low. In this article, the authors will present their analytical results of the Ioannina-1 well, where for the first time they identified some very rich source beds in the Triassic breccias formation of Northwest Greece.

  4. Extraction of whole versus ground source rocks: Fundamental petroleum geochemical implications including oil-source rock correlation

    USGS Publications Warehouse

    Price, L.C.; Clayton, J.L.

    1992-01-01

    In petroleum geochemistry, extractable hydrocarbons (HCs) in source rocks have typically been studied by grinding the rock to a fine powder (???100 mesh) and then extracting the HCs from the rock with a solvent. This procedure carries the implicit assumption that the HCs are homogeneously distributed throughout the rock. However, sequential Soxhlet extractions of whole (unpowdered) source rocks have shown that progressive extracts from the same rock can be quite different and may not even correlate with each other. A crude oil-like material clearly has been fractionated from indigenous bitumen in these rocks, has moved to cracks and parting laminae in the rocks, is ready for expulsion from the rocks, and is thus most accessible to the first extracting solvents. This process, which we believe is largely due to HC gases and carbon dioxide generated over all maturation ranks in source rocks, carries petroleum geochemical implications of a fundamental nature for oil-source rock correlations and gives insight into primary migration mechanisms, origin of oil deposits, and use of maturity and organic-facies indices. ?? 1992.

  5. Geochemistry of Eagle Ford group source rocks and oils from the first shot field area, Texas

    USGS Publications Warehouse

    Edman, Janell D.; Pitman, Janet K.

    2010-01-01

    Total organic carbon, Rock-Eval pyrolysis, and vitrinite reflectance analyses performed on Eagle Ford Group core and cuttings samples from the First Shot field area, Texas demonstrate these samples have sufficient quantity, quality, and maturity of organic matter to have generated oil. Furthermore, gas chromatography and biomarker analyses performed on Eagle Ford Group oils and source rock extracts as well as weight percent sulfur analyses on the oils indicate the source rock facies for most of the oils are fairly similar. Specifically, these source rock facies vary in lithology from shales to marls, contain elevated levels of sulfur, and were deposited in a marine environment under anoxic conditions. It is these First Shot Eagle Ford source facies that have generated the oils in the First Shot Field. However, in contrast to the generally similar source rock facies and organic matter, maturity varies from early oil window to late oil window in the study area, and these maturity variations have a pronounced effect on both the source rock and oil characteristics. Finally, most of the oils appear to have been generated locally and have not experienced long distance migration. 

  6. Source rock identification and oil generation related to trap formation: Southeast Constantine oil field

    SciTech Connect

    Boudjema, A.; Rahmani, A.; Belhadi, E.M.; Hamel, M.; Bourmouche, R. )

    1990-05-01

    Petroleum exploration began in the Southeast Constantine basin in the late 1940s. Despite the very early discovery of Djebel Onk field (1954), exploration remains very sparse and relatively unsuccessful due mainly to the geological complexity of the region. The Ras-Toumb oil field was discovered only twenty years later. In 1988, a new discovery, the Guerguit-El-Kihal oil field renewed the interest of explorationists in this region. The Southeast Constantine Mesozoic-Cenozoic basin has a sedimentary sequence of shales and carbonates with a thickness exceeding 7,000 m. Structural traps are related to pyrenean and post-Villafranchian phases. Potential reservoirs with good petrophysical characteristics and seals can be found throughout the section and are mainly Cenomanian-Turonian and Coniacian limestones and dolomites. The known source rocks are Cenomanian-Turonian and Campanian carbonate shales. Kerogen is a mixture of type II and type III for the Campanian. The kerogen has a fair petroleum potential and is often immature or low mature. The Cenomanian-Turonian kerogen is type II amorphous, with a variable but important petroleum potential. Total organic carbon values range from 1.5% to 7%. Maturity corresponds to the oil window. This source rock is well known throughout the Mediterranean region and is related to the oceanic anoxic event. Kinetic modeling of this organic matter evolution indicates favorable oil generation timing related to trap formation ages.

  7. Prediction of source rock characteristics based on terpane biomarkers in crude oils: a multivariate statistical approach

    SciTech Connect

    Zumberge, J.E.

    1987-06-01

    The distributions of eight tricyclic and eight pentacyclic terpanes were determined for 216 crude oils located worldwide with subsequent simultaneous RQ-mode factor analysis and stepwise discriminate analysis for the purpose of predicting source rock features or depositional environments. Five categories of source rock beds are evident: nearshore marine; deeper-water marine; lacustrine; phosphatic-rich source beds; and Ordovician age source rocks. The first two factors of the RQ-mode factor analysis describe 45 percent of the variation in the data set; the tricyclic terpanes appear to be twice as significant as pentacyclic terpanes in determining the variation among samples. Lacustrine oils are characterized by greater relative abundances of C/sub 21/ diterpane and gammacerane; nearshore marine sources by C/sub 19/ and C/sub 20/ diterpanes and oleanane; deeper-water marine facies by C/sub 24/ and C/sub 25/ tricyclic and C/sub 31/ plus C/sub 32/ extended hopanes; and Ordovician age oils by C/sub 27/ and C/sub 29/ pentacyclic terpanes. Although thermal maturity trends can be observed in factor space, the trends to do necessarily obscure the source rock interpretations. Also, since bacterial degradation of crude oils rarely affects tricyclic terpanes, biodegraded oils can be used in predicting source rock features. The precision to which source rock depositional environments are determined might be increased with the addition of other biomarker and stable isotope data using multivariate statistical techniques.

  8. Petroleum source rock potential and crude oil correlation in Great Basin

    SciTech Connect

    Poole, F.G.; Claypool, G.E.

    1985-05-01

    Petroleum source beds in the Great Basin region include marine Paleozoic rocks and nonmarine upper Mesozoic and lower Cenozoic rocks. Potential source beds have been identified in continental-rise deposits of the Ordovician Vinini and Devonian Woodruff formations if the eastern part of the Roberts Mountains allochthon (Antler orogene), in central and north-central Nevada; in flysch-trough and prodelta-basin deposits of the Mississippian Chainman Shale and equivalent rocks of the Antler foreland basin, in Nevada and western Utah; and in lake-basin deposits of the Cretaceous Neward Canyon Formation and the Paleogene Sheep Pass and Elko formations and equivalent rocks, in central and eastern Nevada. Oil fields in the Great Basin are located with Neogene-Quaternary basins that formed during neogene basin-range block faulting. Most of the oil shows and crude oils analyzed can be correlated with Mississippian or paleogene source rocks. The Mississippian Chainman Shale is confirmed as the major petroleum source rock, having generated the oil in the Trap Spring, Bacon Flat, and Grant Canyon fields in Railroad Valley and the Blackburn field in Pine Valley. The Paleogene Sheep Pass Formation is the source of the oil in the Eagle Springs field and probably the Current field in Railroad Valley. Oil occurrences in the northern Great Basin are believed to be derived from two or more other Tertiary lacustrine sequences.

  9. The oil and gas potential of southern Bolivia: Contributions from a dual source rock system

    SciTech Connect

    Hartshorn, K.G.

    1996-08-01

    The southern Sub-Andean and Chaco basins of Bolivia produce oil, gas and condensate from reservoirs ranging from Devonian to Tertiary in age. Geochemical evidence points to contributions from two Paleozoic source rocks: the Devonian Los Monos Formation and the Silurian Kirusillas Formation. Rock-Eval pyrolysis, biomarker data, microscopic kerogen analysis, and burial history modeling are used to assess the quality, distribution, and maturity of both source rock systems. The geochemical results are then integrated with the structural model for the area in order to determine the most likely pathways for migration of oil and gas in the thrust belt and its foreland. Geochemical analysis and modeling show that the primary source rock, shales of the Devonian Los Monos Formation, entered the oil window during the initial phase of thrusting in the sub-Andean belt. This provides ideal timing for oil accumulation in younger reservoirs of the thrust belt. The secondary source rock, although richer, consumed most of its oil generating capacity prior to the development of the thrust related structures. Depending on burial depth and location, however, the Silurian source still contributes gas, and some oil, to traps in the region.

  10. Assessment of potential oil and gas resources in source rocks of the Alaska North Slope, 2012

    USGS Publications Warehouse

    Houseknecht, David W.; Rouse, William A.; Garrity, Christopher P.; Whidden, Katherine J.; Dumoulin, Julie A.; Schenk, Christopher J.; Charpentier, Ronald R.; Cook, Troy A.; Gaswirth, Stephanie B.; Kirschbaum, Mark A.; Pollastro, Richard M.

    2012-01-01

    The U.S. Geological Survey estimated potential, technically recoverable oil and gas resources for source rocks of the Alaska North Slope. Estimates (95-percent to 5-percent probability) range from zero to 2 billion barrels of oil and from zero to nearly 80 trillion cubic feet of gas.

  11. 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.

  12. Oil source rocks in the Romanian area of the Moesian platform

    SciTech Connect

    Baltes, N.; Matracaru, C.; Petrom, R.A.

    1995-08-01

    The Romanian area of the Moesian Platform (north of the Danube-Black Sea and east and South Carpathians Foredeep to north) represents a very important intra-plate with some new real oil prospects. With a thick sedimentary cover, especially in its northern, deepest area, the Moesian Platform offers favorable geological conditions of oil systems in the whole stratigraphic column, from Paleozoic to Upper Cenozoic (Pliocene). Having a few rich oil source rocks both in carbonatic facies (Devonian-Carboniferous, Middle Triassic, Neocomian) and argillitic ones (Silurian, early Carboniferous, Lias-Dogger, Mid-Upper Miocene), the Moesian Platform also contains very good oil reservoirs: Mid-Upper Paleozoic, Triassic, Lower Cretaceous, Upper Miocene and Pliocene. Geochemical studies on kerogen and bitumen have pointed out the most important oil source rocks, as well as the quality and quantity of expelled hydrocarbons and their relationships with oil reservoirs. Geochemical correlations between oils and source rocks have led to a better understanding of the oil pool formation with some interesting goals in the Romanian exploration strategy.

  13. Recognition of an infracambrian source rock based on biomarkers in the Baghewala-1 oil, India

    SciTech Connect

    Peters, K.E.; Clark, M.E.; Lee, C.Y.

    1995-10-01

    Heavy, sulfur-rich oil produced from the Infra-cambrian (540-640 Ma) Jodhpur Formation in the Baghewala-1 well represents a new exploration play in the Bikaner-Nagaur basin in India and the punjab basin in Pakistan. The Baghewala-1 oil is nonbiodegraded, and thermal-maturation-dependent biomarker ratios indicate generation from the source rock within the early oil window. Age-diagnostic and source-dependent biomarkers indicate that the oil originated from algal and bacterial organic matter with no higher plant input in an Infracambrian, carbonate-rich source rock deposited under anoxic marine conditions. These characteristics support a local origin of the Baghewala-1 oil from organic-rich laminated dolomites in the Infracambrian Bilara Formation. Significant amounts of petroleum could originate from equivalents of the proposed Bilara source rock in the Punjab basin, Pakistan, where the Precambrian to lower Paleozoic section is thicker and more deeply buried than in India. Deeper burial of the source rock in the Punjab basin than in the Bikaner-Nagaur basin could generate more mature equivalents of the Baghewala-1 oil. The Baghewala-1 oil is geochemically similar to another heavy oil from the Infracambrian Salt Range Series in the nearby Karampur-1 well in Pakistan and to oils derived from carbonate-evaporite facies of the Infracambrian Huqf Group about 2000 km (1243 mi) to the southwest in the Eastern Flank province of southern Oman. These findings are consistent with published evidence that subsiding rift basins in northwest India, Pakistan, and southern Oman were in close proximity during the Infracambrian along the Middle Eastern edge of Gondwanaland.

  14. Oils and source rocks from the Anadarko Basin: Final report, March 1, 1985-March 15, 1995

    SciTech Connect

    Philp, R. P.

    1996-11-01

    The research project investigated various geochemical aspects of oils, suspected source rocks, and tar sands collected from the Anadarko Basin, Oklahoma. The information has been used, in general, to investigate possible sources for the oils in the basin, to study mechanisms of oil generation and migration, and characterization of depositional environments. The major thrust of the recent work involved characterization of potential source formations in the Basin in addition to the Woodford shale. The formations evaluated included the Morrow, Springer, Viola, Arbuckle, Oil Creek, and Sylvan shales. A good distribution of these samples was obtained from throughout the basin and were evaluated in terms of source potential and thermal maturity based on geochemical characteristics. The data were incorporated into a basin modelling program aimed at predicting the quantities of oil that could, potentially, have been generated from each formation. The study of crude oils was extended from our earlier work to cover a much wider area of the basin to determine the distribution of genetically-related oils, and whether or not they were derived from single or multiple sources, as well as attempting to correlate them with their suspected source formations. Recent studies in our laboratory also demonstrated the presence of high molecular weight components(C{sub 4}-C{sub 80}) in oils and waxes from drill pipes of various wells in the region. Results from such a study will have possible ramifications for enhanced oil recovery and reservoir engineering studies.

  15. 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

  16. Tectonic control in source rock maturation and oil migration in Trinidad

    SciTech Connect

    Persad, K.M.; Talukdar, S.C.; Dow, W.G. )

    1993-02-01

    Oil accumulation in Trinidad were sourced by the Upper Cretaceous calcareous shales deposited along the Cretaceous passive margin of northern South America. Maturation of these source rocks, oil generation, migration and re-migration occurred in a foreland basin setting that resulted from interaction between Caribbean and South American plates during Late Oligocene to recent times. During Middle Miocene-Recent times, the foreland basin experienced strong compressional events, which controlled generation, migration, and accumulation of oil in Trinidad. A series of mature source rock kitchens formed in Late Miocene-Recent times in the Southern and Colombus Basins to the east-southeast of the Central Range Thrust. This thrust and associated fratured developed around 12 m.y.b.p. and served as vertical migration paths for the oil generated in Late Miocene time. This oil migrated into submarine fans deposited in the foreland basin axis and older reservoirs deformed into structural traps. Further generation and migration of oil, and re-migration of earlier oil took place during Pliocene-Holocene times, when later thrusting and wrench faulting served as vertical migration paths. Extremely high sedimentation rates in Pliocene-Pleistocene time, concurrent with active faulting, was responsible for very rapid generation of oil and gas. Vertically migrating gas often mixed with earlier migrated oil in overlying reservoirs. This caused depletion of oil in light hydrocarbons with accompanied fractionation among hydrocarbon types resulting in heavier oil in lower reservoirs, enrichment of light hydrocarbons and accumulation of gas-condensates in upper reservoirs. This process led to an oil-gravity stratification within about 10,000 ft of section.

  17. Lower Tertiary and Upper Cretaceous source rocks in Louisiana and Mississippi: Implications to Gulf of Mexico crude oil

    SciTech Connect

    Sassen, R. )

    1990-06-01

    The Lower Tertiary Sparta Formation, Wilcox Group, and the Midway Group in southern Louisiana include organic-rich source facies that generate crude oil at relatively high thermal maturities. The Wilcox Group is an important source of Wilcox crude oil, and regional kerogen variations explain two crude oil subfamilies. Wilcox crude oils in downdip areas of southern Louisiana migrated short distances, but long-range lateral migration (about 150 km) best explains Wilcox crude oils far updip from mature source rocks. Crude oils in Oligocene and younger reservoirs in southern Louisiana migrated vertically from deep lower Tertiary source rocks. Some crude oils in Upper Cretaceous Tuscaloosa reservoirs were emplaced by long-range lateral migration from Tuscaloosa source rocks. Given little evidence of upper Tertiary source rocks and the overmaturity problems of Mesozoic source rocks, most crude oils in upper Tertiary and Pleistocene reservoirs of the Gulf continental shelf are best explained by vertical migration from deep lower Tertiary source rocks. Even so, it is simplistic to assume an exclusive lower Tertiary origin. Many Tertiary and Pleistocene crude oils of this study probably include an overprint of high-maturity hydrocarbons from Mesozoic sources. 12 figs., 7 tabs.

  18. Origin of crude oil in eastern Gulf Coast: Upper Jurassic, Upper Cretaceous, and lower Tertiary source rocks

    SciTech Connect

    Sassen, R.

    1988-02-01

    Analysis of rock and crude oil samples suggests that three source rocks have given rise to most crude oil in reservoirs of the eastern Gulf Coast. Carbonate source rocks of the Jurassic Smackover Formation are characterized by algal-derived kerogen preserved in an anoxic and hypersaline environment, resulting in crude oils with distinct compositions. Migration commenced during the Cretaceous, explaining the emplacement of Smackover-derived crude oil in Jurassic and in some Cretaceous reservoirs. Upper Cretaceous clastic and carbonate source rocks are also present. Much crude oil in Upper Cretaceous reservoirs has been derived from organic-rich marine shales of the Tuscaloosa Formation. These shales are characterized by algal and higher plant kerogen, resulting in distinct crude oil compositions. Migration commenced during the Tertiary, but was mostly focused to Upper Cretaceous reservoirs. Lower Tertiary shales, including those of the Wilcox Formation, are quite organic-rich and include downdip marine facies characterized by both algal and higher plant kerogen. Crude oils in lower Tertiary reservoirs are dissimilar to crude oils from deeper and older source rocks. Migration from lower Tertiary shales commenced during the late Tertiary and charged Tertiary reservoirs. Although most crude oil in the eastern Gulf Coast has been emplaced by short-range migration, often with a strong vertical component, some long-range lateral migration (> 100 km) has occurred along lower Tertiary sands. The framework of crude oil generation and migration onshore has important implications with respect to origin of crude oil in the Gulf of Mexico.

  19. Oil-source rock correlation using carbon isotope data and biological marker compounds, Cook Inlet-Alaska Peninsula, Alaska

    SciTech Connect

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

    1990-05-01

    Rock and oil samples from the Cook Inlet-Alaska Peninsula area were analyzed to determine the source of the commercial hydrocarbons produced in the Cook Inlet basin from lower Tertiary nonmarine sandstone reservoirs. Rock-Eval (hydrogen index) analysis and organic carbon content were used to identify the most favorable rock samples for solvent extraction and carbon isotope, gas-chromatographic (GC), and gas-chromatrographic/mass-spectrometric (GCMS) analyses. On the basis of organic-matter richness, five nonmarine Tertiary coal and shale samples and 12 marine Mesozoic (Upper Triassic and Middle Jurassic) shale samples were selected. A total of 28 oil and condensate samples from producing wells, oil-stem tests, field separators, and seeps were used for oil-oil and oil-source rock correlation. On the basis of biomarker and carbon isotope data, four of the shallower oils and condensates are from nonmarine source rocks, and 24 of the deeper oils are sourced from marine shales. Geochemical and regional geologic considerations indicate the following conclusions. The upper Tertiary nonmarine oils and condensates associated with commercial microbial gas accumulations are geochemically similar to the immature organic matter in the Tertiary nonmarine rocks. In the upper Cook Inlet, marine oils in lower Tertiary nonmarine reservoirs originated from Middle Jurassic rocks that matured during the Pliocene to Holocene; in the lower Cook Inlet-Alaska Peninsula area, oils migrated from both Upper Triassic and Middle Jurassic source rocks during the Late Cretaceous to early Tertiary. Although three petroleum systems are identified, this study on the petroleum potential in a convergent-margin setting indicates that only one of these three systems was responsible for the 1.2 billion bbl of recoverable oil in the lower Tertiary nonmarine reservoirs.

  20. Application of a new preparative pyrolysis technique for the determination of source-rock types and oil/source-rock correlations

    NASA Astrophysics Data System (ADS)

    Lafargue, E.; Behar, F.

    1989-11-01

    A new preparative pyrolysis technique enabling the recovery and fractionation (into saturated hydrocarbons, unsaturated hydrocarbons, and aromatic hydrocarbons) of the total C 6+ hydrocarbon fraction (instead of the C 13+ fraction usually recovered) has been applied to different types of source-rocks. The composition of the C 7-C 13 hydrocarbon fraction in the pyrolysate, particularly the amount of aromatic hydrocarbons as compared to alkanes, was found to be characteristic of each type of kerogen, with the alkane/aromatic ratio consistently decreasing in the progression from Type I to Type III kerogens. While the C 13+ fraction is useful in kerogen typing, it was found that the C 7-C 13 hydrocarbon fraction, which represents 40 to 50% of the total recovered pyrolysate, was the most signficant in emphasizing differences between kerogen types, allowing a rapid and precise estimation of the source-rock type. This new technique was applied to potential source-rocks of the Viking Graben, North Sea (Draupne formation, Heather formation, Brent coals, and Dunlin group). In each case, the pyrolysates allowed us to determine whether the organic matter was Type II, Type III, or a mixture of both. Pyrolysis of asphaltenes from crude oils from the various regions was conducted and potential applications of our technique to studies of oil/source-rock correlations were examined.

  1. Preliminary investigation of oil and source rock organic geochemistry from selected Tertiary basins of Thailand

    NASA Astrophysics Data System (ADS)

    Lawwongngam, Kulwadee; Philp, R. P.

    Selected samples of crude oils and extracts from source rocks obtained from six Thailand Tertiary basins of the central plain and of the Gulf of Thailand regions were examined for geochemical properties and molecular compositions. Analyses were performed using GC, CGCMS and carbon isotope mass spectrometry. Though these results should be viewed as preliminary, the results are significant in terms of a regional understanding of the petroleum geochemistry of Thailand. Results from bulk geochemical properties and biomarker assemblages characterize derivatives of organic sources deposited in lacustrine environments. The organic matter is mainly derived from algae with varying amounts of higher plant material. However, an observed variation in the pristane/phytane ratios among the samples may imply differences in depositional oxicity. On the other hand, basinal differences in sedimentation rates, or in the oxygen concentration of the varying waters and/or sediment pore-waters resulted in spatial heterogeneities in the quantity and degree of preservation of the organic matter. In addition, a degree of physical separation between these paleo-lacustrine environments is indicated by differences in paleosalinity, e.g. the hypersaline biomarker, gammacerane, which is restricted to samples from the offshore Gulf of Thailand basins. Maturity parameters for these Tertiary oils and source rock extracts were determined using biomarker analyses of T s/T m, 22S/22S + 22R C 31 hopane, C 30 moretane/hopane, 20R/20S + 20R C 29 sterane, and aromatic compounds. Though the samples demonstrate an overall relatively low level of maturity as specified by the biomarker index, a degree of individual basinal variability is also distinguishable. The observed differences in the maturity values indicate regional heterogeneity among the basin thermal histories, suggesting differences in geothermal gradients and/or in the basin subsidence rates.

  2. Characteristics of biomarkers from light oils and their source rocks in the northern continental shelf of the South China Sea

    NASA Astrophysics Data System (ADS)

    An Qiao, Wang; Bao Ming, Zheng

    Light oil occurs in oil-bearing basins at the northern continental shelf of the South China Sea. They are of three types (A-C), based on their biomarker characteristics. The light oil of type A exhibits abundant C 30-4-methyl sterane, and a minority of tricyclic terpanes. It therefore has an affinity to Eocene lacustrine source rock with a richness of algae and pinus pollen. However, the light oil of type B is charaterized by a pronounced peak of C 19-tricyclic terpane. It also contains extremely abundant Tm. The oil of this type has characteristics identical to that of Oligocene coal and paludal mudstone. The light oil of type C shows the relatively high peak of γ-lupane and Ts as its characterization. Therefore, this type of oil is correlated to Oligocene lacustrine source rock which contains comparatively rich angiosperm pollen. The conclusion made is that light oil (including condensate), and natural gas, can originate from source rocks at different maturities in different sedimentary facies.

  3. Source rock potential in Pakistan

    SciTech Connect

    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 Cretaceous 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.

  4. Kerogen to oil conversion in source rocks. Pore-pressure build-up and effects on seismic velocities

    NASA Astrophysics Data System (ADS)

    Pinna, Giorgia; Carcione, José M.; Poletto, Flavio

    2011-08-01

    The aim of this work is to obtain a model for source rocks relating to kerogen-oil conversion and pore pressure to seismic velocity and anisotropy. The source rock is described by a porous transversely isotropic medium composed of illite/smectite and organic matter. The rock has a very low permeability and pore-pressure build-up occurs. We consider a basin-evolution model with constant sedimentation rate and geothermal gradient. Kerogen-oil conversion starts at a given depth in a volume whose permeability is sufficiently low so that the increase in pressure due to oil generation greatly exceeds the dissipation of pressure by flow. Assuming a first-order kinetic reaction, with a reaction rate satisfying the Arrhenius equation, the kerogen-oil conversion fraction is calculated. Pore-pressure changes affect the dry-rock stiffnesses, which have an influence on seismic velocities. The properties of the kerogen-oil mixture are obtained with the Kuster and Toksöz model, assuming that oil is the inclusion in a kerogen matrix. We use Gassmann's equations generalized to the anisotropic case to obtain the seismic velocities of the source rock as a function of depth, pressure and oil saturation. The procedure is to obtain the dry-rock stiffnesses by assuming a Poisson medium for the mineral material constrained by the physical stability conditions at the calibration confining pressures. The example considers a sample of the North-Sea Kimmeridge shale. At a given depth, the conversion increases with increasing geothermal gradient and decreasing sedimentation rate, and the porosity increases with depth due to the conversion. As expected, the horizontal velocities are greater than the vertical velocities and the degree of anisotropy increases with depth. The analysis reveals that the vertical P-wave velocity is the main indicator of overpressure.

  5. 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

  6. 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

  7. 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.

  8. Geochemical evidence for mudstone as the possible major oil source rock in the Jurassic Turpan Basin, Northwest China

    USGS Publications Warehouse

    Chen, J.; Qin, Yelun; Huff, B.G.; Wang, D.; Han, D.; Huang, D.

    2001-01-01

    Geologists and geochemists have debated whether hydrocarbons from Jurassic coal measures are derived from the mudstones or the coals themselves. This paper identifies mudstones as the possible major source rock of hydrocarbons in the Jurassic basins in Northwest China. The Turpan Basin is used as a representative model. Mudstones in the Middle-Lower Jurassic are very well developed in the basin and have an average genetic potential from 2 to 4 mg/g. The vitrinite reflectance of the source rocks ranges from 0.6 to 1.3%, exhibiting sufficient thermal maturity to generate oil and gas. Biomarkers in crude oils from the basin are similar to those in mudstones from the coal-bearing strata, with a low tricyclic terpane (cheilanthane) content, a relatively high content of low carbon number (less than C22) tricyclic terpanes and a low content of high carbon number tricyclic terpanes, relatively high ratios of Ts/Tm, and C29 Ts/17?? (H)-C29 norhopane, and low ratios of Tm/17?? (H)-C30 hopane and 17?? (H)-C31 homohopane/17?? (H)-C30 hopane. These characteristics and the distribution of steranes and terpanes in the crude oil and mudstone differ significantly from those of the Jurassic coals and carbonaceous shales of the basin, indicating mudstone is possibly the major source rock of the oils in the Turpan Basin. ?? 2001 Elsevier Science Ltd. All rights reserved.

  9. Cretaceous source rocks in Pakistan

    SciTech Connect

    Kari, I.B. )

    1993-02-01

    Pakistan is located at the converging boundaries of the Indian, Arabian, and Eurasian plates. Evolution of this tectonic setting has provided an array of environmental habitats for deposition of petroleum source rocks and development of structural forms. The potential Cretaceous source rocks in Central and South Indus Basin are spread over an area of about 300,000 km[sup 2]. With 2% cutoff on Total Organic Carbon, the average source rock thickness is 30-50 m, which is estimated to have generated more than 200 billion bbl of oil equivalent. To date, production of more than 30,000 bbl of oil and about 1200 million ft[sup 3] of gas per day can be directly attributed to Cretaceous source. This basin was an area of extensional tectonics during the Lower to Middle Cretaceous associated with slightly restricted circulation of the sea waters at the north-western margin of Indian Plate. Lower Cretaceous source rocks (Sembar Formation) were deposited while the basin was opening up and anoxia was prevailing. Similarly Middle to Upper Cretaceous clastics were deposited in setting favorable for preservation of organic matter. The time and depth of burial of the Cretaceous source material and optimum thermal regime have provided the requisite maturation level for generation of hydrocarbons in the basin. Central Indus basin is characterized by Cretaceous source rocks mature for gas generation. However, in South Indus Basin Cretaceous source rocks lie within the oil window in some parts and have gone past it in others.

  10. U-Th-Pb in petroleum by LA-ICP-MS: Source rocks-crude oils comparison.

    NASA Astrophysics Data System (ADS)

    Gourlan, Alexandra T.; Ricard, Estelle; Prinzhofer, Alain; Christophe, Pecheyran; Donard, Olivier X. C.

    2010-05-01

    The U, Th elemental and Pb isotopic ratios in petroleum source rocks have been determined for the first time and compared with crude oils from different regions in the World using a femtosecond laser ablation (high ablation rates) coupled to an ICP-MS and direct analysis of digested samples on ICP-MS. The advantage of femtosecond compared to nanosecond laser ablation is that it drastically reduces thermal effects, minimizes isotope and elemental fractionation and matrix effects during chemical analysis of solid samples. Fs-Laser Ablation coupled to an ICP-MS is therefore a potentially valuable tool for the determination of trace metals in crude oils as well as in solid samples such as source rocks. The principal problems encountered arise from the lack of isotopic lead standards in organic matrixes and the heterogeneity of source rocks which contain sulphides with high natural U and Th concentrations. Therefore, to determine exactly the U, Th and Pb contents in source rocks, two analytical techniques have to be compared. In one, the use of the laser ablation allows us to analyze in-situ small parts of the organic materials and to determine the proportions of two end members: pure kerogene and pure sulphides. In the other, the use of the conventional dissolution of the same pellets involves total consumption of the sample and gives an average value of the isotopic lead ratios and U, Th and Pb concentrations of the bulk sample. For the two cases a "sample-standard bracketing" procedure was applied using NIST 612 glass standard for ablation and NIST 981 in aqueous solution for the mineralization. Due to the lack of organic matrix standards, the fs-LA-ICP-MS technique produces only qualitative trace element (U, Th and Pb) and isotopic analysis of source rocks. Our results obtained on both crude oils and associated source rocks have shown that Th, U, Pb systematics determined using the two analytical methods (mineralization of kerogen directly analyzed on ICP-MS or MC

  11. Estimates of Oil and Gas Potential of Source Rock by 13C Nuclear Magnetic Resonance (NMR) Spectroscopy

    NASA Astrophysics Data System (ADS)

    Longbottom, T. L.; Hockaday, W. C.; Boling, K. S.; Dworkin, S. I.

    2014-12-01

    Kerogen is defined as the insoluble fraction of organic matter preserved in sediments. Due to its structural complexity, kerogen is poorly understood, yet it holds vast economic importance as petroleum source rock, and represents the largest organic carbon pool on earth. Kerogen originates from a mixture of organic biomolecules and tends to be dominated by the polymeric components of cell walls and cellular membranes, which undergo interactions with sedimentary minerals at elevated temperature and pressure upon burial. Due to the importance of burial diagenesis to petroleum formation, much of our knowledge of chemical properties of kerogens is related to diagenetic and catagenetic effects. The more common geochemical evaluations of the oil and gas potentials of source rock are based upon proximate analyses such as hydrogen and oxygen indices and thermal stability indices, such as those provided by Fisher assay and Rock Eval®. However, proximate analyses provide limited information regarding the chemical structure of kerogens, and therefore provide little insight to the processes of kerogen formation. NMR spectra of kerogen have been previously shown to be useful in estimating oil and gas potential, and the proposed study seeks to refine nuclear magnetic resonance spectroscopy as a tool in kerogen characterization, specifically for the purpose of oil and gas potential calculations.

  12. Oil source rocks in lacustrine sequences from Tertiary grabens, western Mediterranean rift system, northeast Spain

    SciTech Connect

    Anadon, P.; Cawley, S.J.; Julia, R.

    1988-08-01

    Lacustrine sequences, 100-250 m thick, containing oil-prone, organic-rich mudstones (ORM) are exposed in five Tertiary basins in northeastern Spain. They were deposited in small lacustrine basins (up to 50 km/sup 2/) that developed in grabens of the western Mediterranean rift system. ORMs from the Rubielos basin comprise laminated gray mudstones with interbedded rhythmite intervals (up to 2.5 m thick) formed by couplets of organic- and carbonate-rich laminae (< 1 mm thick). In marginal zones, ORMs (up to 10 m thick) alternate with lean, bioturbated green marls (up to 5 m thick). ORMs (Rock-Eval yields /approximately/ 40 kg/MT, HI /approximately/ 850 mg HC/g TOC) had a dominant waxy terrestrial plant input, with significant and variable algal/bacterial input. ORMs in these basins are immature for petroleum generation. Larger lacustrine basins similar to those described above, in more appropriate burial/thermal situations, can be envisioned as zones of potential interest for lacustrine oil exploration in the western Mediterranean.

  13. World petroleum systems with Jurassic source rocks

    SciTech Connect

    Klemme, H.D. )

    1993-11-08

    Fourteen petroleum systems with Upper Jurassic source rocks contain one quarter of the world's discovered oil and gas. Eleven other systems with Lower and Middle Jurassic source rocks presently have a minor but significant amount of discovered oil and gas. The purpose of this article is to review the systems geologically, describe their location in space and time on a continental scale, estimate their relative petroleum system recovery efficiencies, and outline the effect their essential elements and processes have on their petroleum plumbing.

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

    USGS Publications Warehouse

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

    2012-01-01

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

  15. Marine source rocks of New Zeland

    SciTech Connect

    Murray, A.P.; Norgate, C.; Summons, R.E.

    1996-12-31

    Exploration in New Zealand is moving beyond the Taranaki Basin with its mainly terrestrial source rocks. Good to excellent quality marine source rocks exist and have generated oil in the Northland, East Coast W North Taranaki Basins. These high quality source rocks are Wespread throughout the late Cretaceous - Paleocene passive margin sequence in these basins as well in offshore Canterbury and the Great South Basin. This paper details the character, distribution, generative capacity and maturation behavior of the two main source units and shows how they can be correlated to the numerous seeps and oil impregnations found in the East Coast and Northland Basins. As well as being useful in basin modelling, kinetic maturation parameters for these two source rock facies help to explain differences in the biomarker and isotopic composition of seep oils and also explain trends in Rock Eval Tmax which are unrelated to maturity. In the East Coast Basin alone, the raw oil potential of the Waipawa Black Shale approaches 80 billion barrels. An understanding of the marine source rocks described here is crucial to evaluating the hydrocarbon prospectivity of New Zealand away from the Taranaki Basin.

  16. Marine source rocks of New Zeland

    SciTech Connect

    Murray, A.P.; Norgate, C.; Summons, R.E. )

    1996-01-01

    Exploration in New Zealand is moving beyond the Taranaki Basin with its mainly terrestrial source rocks. Good to excellent quality marine source rocks exist and have generated oil in the Northland, East Coast W North Taranaki Basins. These high quality source rocks are Wespread throughout the late Cretaceous - Paleocene passive margin sequence in these basins as well in offshore Canterbury and the Great South Basin. This paper details the character, distribution, generative capacity and maturation behavior of the two main source units and shows how they can be correlated to the numerous seeps and oil impregnations found in the East Coast and Northland Basins. As well as being useful in basin modelling, kinetic maturation parameters for these two source rock facies help to explain differences in the biomarker and isotopic composition of seep oils and also explain trends in Rock Eval Tmax which are unrelated to maturity. In the East Coast Basin alone, the raw oil potential of the Waipawa Black Shale approaches 80 billion barrels. An understanding of the marine source rocks described here is crucial to evaluating the hydrocarbon prospectivity of New Zealand away from the Taranaki Basin.

  17. Middle Triassic source rocks in north Lombardy

    SciTech Connect

    Gnaccolini, M.; Gaetani, M.; Mattavelli, L.; Leoni, C.; Poliani, G.; Riva, A.

    1988-08-01

    Using molecular geochemistry techniques, we established that the Perledo-Verenna and Meride Formations (Middle Triassic, southern Alps) represent the source rocks of the Gaggiano and Villafortuna deep oil fields discovered 40 km northwest of Milan. To find the geological factors which control the areal extent thickness and organic matter distribution relative to these sequences, a sedimentological and geochemical study was undertaken.

  18. 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

  19. Genesis of oil and hydrocarbon gases within Mars and carbonaceous chondrites from our solar system: organic origin (source rocks or direct biogenic sink?)

    NASA Astrophysics Data System (ADS)

    Mukhopadhyay, Prasanta K.

    2011-10-01

    The petroleum hydrocarbons (oil and gas) and kerogen macromolecules are abundant within the extraterrestrial atmospheric particles. These hydrocarbons occur as reservoir of lakes and oceans or in hydrate forms on various planets (Earth, Mars, moons of Saturn and Jupiter), asteroid belts, carbonaceous chondrites, and as solid residue within the planets or moons in the Solar System and beyond. The abundance of PAHs in the outer Solar System may indicate that the genesis of these primitive biomarker hydrocarbons may have formed abiogenically much earlier (> 5Ga) than the formation of our Solar System (~ 5 Ga). However, the origin of petroleum on Earth is overwhelmingly connected to the biogenic organic matter that is related to source rocks (thermal degradation of macromolecular kerogen). This may show a similar genesis of the kerogen macromolecules and petroleum hydrocarbons (oil and gas) within the carbonaceous chondrites (CCs), Mars, and selected moons from Saturn and Jupiter. They may be biologically and genetically related. Recent evidence of the possible presence of source rocks (organic rich black carbonaceous rocks) and associated petroleum system elements within Eberswalde and Holden areas of Mars may indicate similar terrestrial associations. Similarly, studies of Carbonaceous Chondrites using biological, petrological, SEM/EDS, and petroleum geochemical methods may also indicate the presence of source rock macromolecule within the CCs. These studies pointed out two new issues: (1) approximately, the major part of the CCs possibly originated from archaea, bacteria, and primitive algal remains; and (2) three types of temperature events affecting the petroleum generation within these carbonaceous chondrites: (i) lower temperature events (<200oC) in comets and cooler asteroids or planets (examples: Murchison, Tagish Lake, Orgueil); (ii) intermediate temperature events (200 - 300oC) as associated within the deeper section of the comets, asteroids or planets

  20. 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.

  1. 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.

  2. Dispersivity as an oil reservoir rock characteristic

    SciTech Connect

    Menzie, D.E.; Dutta, S.

    1989-12-01

    The main objective of this research project is to establish dispersivity, {alpha}{sub d}, as an oil reservoir rock characteristic and to use this reservoir rock property to enhance crude oil recovery. A second objective is to compare the dispersion coefficient and the dispersivity of various reservoir rocks with other rock characteristics such as: porosity, permeability, capillary pressure, and relative permeability. The dispersivity of a rock was identified by measuring the physical mixing of two miscible fluids, one displacing the other in a porous medium. 119 refs., 27 figs., 12 tabs.

  3. Source rock maturation, San Juan sag

    SciTech Connect

    Gries, R.R.; Clayton, J.L.

    1989-09-01

    Kinetic modeling for thermal histories was simulated for seven wells in the San Juan sag honoring measured geochemical data. Wells in the area of Del Norte field (Sec. 9, T40N, R5E), where minor production has been established from an igneous sill reservoir, show that the Mancos Shale source rocks are in the mature oil generation window as a combined result of high regional heat flow and burial by approximately 2,700 m of Oligocene volcanic rocks. Maturation was relatively recent for this area and insignificant during Laramide subsidence. In the vicinity of Gramps field (Sec. 24, T33N, R2E) on the southwest flank of the San Juan sag, these same source rocks are exposed due to erosion of the volcanic cover but appear to have undergone a similar maturation history. At the north and south margins of the sag, two wells (Champlin 34A-13, Sec. 13, T35N, R4.5E; and Champlin 24A-1, Sec. 1, T44N, R5E) were analyzed and revealed that although the regional heat flow was probably similar to other wells, the depth of burial was insufficient to cause maturation (except where intruded by thick igneous sills that caused localized maturation). The Meridian Oil 23-17 South Fork well (Sec. 17, T39N, R4E) was drilled in a deeper part of the San Juan sag, and source rocks were intruded by numerous igneous sills creating a complex maturation history that includes overmature rocks in the lowermost Mancos Shale, possible CO{sub 2} generation from the calcareous Niobrara Member of the Mancos Shale, and mature source rocks in the upper Mancos Shale.

  4. Basin richness and source rock disruption - a fundamental relationship

    USGS Publications Warehouse

    Price, L.C.

    1994-01-01

    Primary petroleum migration (expulsion from source rocks) remains the least understood parameter controlling the genesis of oil deposits. It is hypothesised that source rocks must be physically disrupted before meaningful expulsion can occur. Faulting, with accompanying significant fracturing, would appear to be the optimum naturally-occurring process for physical disruption of source rocks. If these hypotheses are valid, intensity of faulting in deeply-buried HC "kitchens' containing mature source rocks should strongly correlate with increasing basin richness. This possible relationship is examined in this paper; it is found that there is a strong correlation of increasing basin richness with increasing structural intensity over and adjacent to basin depocentres. This correlation thus supports the hypothesis that physical disruption of mature source rocks is a necessary, and previously unappreciated, controlling parameter for oil expulsion. -from Author

  5. Possible late middle Ordovician organic carbon isotope excursion: evidence from Ordovician oils and hydrocarbon source rocks, Mid-Continent and east-central United States

    SciTech Connect

    Hatch, J.R.; Jacobson, S.R.; Witzke, B.J.; Risatti, J.B.; Anders, D.E.; Watney, W.L.; Newell, K.D.; Vuletich, A.K.

    1987-11-01

    A possible coeval excursion in organic-matter delta/sup 13/C is recognized in different late Middle Ordovician lithologic facies over a distance of 480 mi (770 km), perhaps 930 mi (1500 km), in the Mid-Continent and east-central US. The large variability in the carbon isotope compositions of Ordovician oils from the Mid-Continent and east-central US is a direct result of the variable carbon isotope composition of organic matter in the Middle Ordovician hydrocarbon source rocks. The excursion in organic-matter delta/sup 13/C in late Middle Ordovician rocks may reflect significantly increased organic matter productivity and/or preservation. The excursion is not directly related to maceral composition of the organic matter. Limited dissolved CO/sub 2/ availability, possibly a result of continued high organic matter productivity, and limited circulation in the Middle Ordovician seas may have increased the size of the excursion in organic matter delta/sup 13/C. 5 figures, 4 tables.

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

    SciTech Connect

    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 basin has been poorly explored so far, but it is highly promising for natural gas.

  7. POSSIBLE LATE MIDDLE ORDOVICIAN ORGANIC CARBON ISOTOPE EXCURSION: EVIDENCE FROM ORDOVICIAN OILS AND HYDROCARBON SOURCE ROCKS, MID-CONTINENT AND EAST-CENTRAL UNITED STATES.

    USGS Publications Warehouse

    Hatch, Joseph R.; Jacobson, Stephen R.; Witzke, Brian J.; Risatti, J. Bruno; Anders, Donald E.; Watney, W. Lynn; Newell, K. David; Vuletich, April K.

    1987-01-01

    Oils generated by Middle Ordovician rocks are found throughout the Mid-Continent and east-central regions of the United States. Gas chromatographic characteristics of these oils include a relatively high abundance of n-alkanes with carbon numbers less than 20, a strong predominance of odd-numbered n-alkanes between C//1//0 and C//2//0, and relatively small amounts of branched and cyclic alkanes. The wide ranges in delta **1**3C for oils and rock extracts reflect a major, positive excursion(s) in organic matter delta **1**3C in late Middle Ordovician rocks. This excursion has at least regional significance in that it can be documented in sections 480 mi apart in south-central Kansas and eastern Iowa. The distance may be as much as 930 mi. The parallel shifts in organic and carbonate delta **1**3C in core samples from 1 E. M. Greene well, Washington County, Iowa, imply changes in the isotope composition of the ocean-atmosphere carbon reservoir. These and other aspects of the subject are discussed.

  8. Source apportionment in oil spill remediation.

    PubMed

    Muñoz, Jorge; Mudge, Stephen M; Loyola-Sepulveda, Rodrigo; Muñoz, Gonzalo; Bravo-Linares, Claudio

    2012-05-01

    A pipe rupture during unloading led to a spillage of 350-700 tonnes of Caño Limon, a light sweet crude oil, into San Vicente Bay in 2007. Initial clean-up methods removed the majority of the oil from the sandy beaches although some oil remained on the rocky shores. It was necessary for the responsible party to clean the spilled oil even though at this location there were already crude oil hydrocarbons from previous industrial activity. A biosolvent based on vegetable oil derivatives was used to solubilise the remaining oil and a statistical approach to source apportionment was used to determine the efficacy of the cleaning. Sediment and contaminated rock samples were taken prior to cleaning and again at the same locations two days after application of the biosolvent. The oil was extracted using a modified USEPA Method 3550B. The alkanes were quantified together with oil biomarkers on a GC-MS. The contribution that Caño Limon made to the total oil hydrocarbons was calculated from a Partial Least Squares (PLS) analysis using Caño Limon crude oil as the source. By the time the biosolvent was applied, there had already been some attenuation of the oil with all alkanes source of the oil in this case and the contribution that Caño Limon made to the total oil ranged from 0% to 74%. The total hydrocarbon concentrations were lower after cleaning indicating an efficacy of 90% although the reduction in Caño Limon oil was smaller. This was sufficient to make further remediation unnecessary. PMID:22588176

  9. Source rock evaluation of Cretaceous and Tertiary series in Tunisia

    SciTech Connect

    Oudin, J. )

    1988-08-01

    Tunisia represents a mature hydrocarbon province with a long exploration history. In the Sfax-Kerkennah and Gabes Gulf areas, the hydrocarbon accumulations are located in series of Cretaceous and Tertiary age. To estimate the petroleum potential of this region, an evaluation of the source rock quality of the Cretaceous and Tertiary series was undertaken. In the Sfax-Kerkennak area, most of the wells studied indicate that, in the Tertiary, Ypresian and lower Lutetian show good organic content but, taking into account the potential productivity, only the Ypresian can be considered as a potential source rock. In the Cretaceous, mainly studies in the offshore area of the Gabes Gulf, the amount of organic matter is fair and it is chiefly located in Albian and Cenomanian. The Vraconian with its quite good potential is a valuable source rock. Due to the difference in the environment of deposition for these two possible source rocks - the Ypresian with its lagoon facies being carbonate and the Vraconian shaly - variations in the type of organic matter can be noted, although both are of marine origin. The hydrocarbons generated from these source rocks reflect these variations and permit them to correlate the different crude oils found in this area with their original source beds.

  10. Petroleum source rocks of the Junggar, Tarim, and Turpan basins, northwest China

    SciTech Connect

    Graham, S.A.; Brassell, S.; Carroll, A.R.; McKnight, C.L.; Chu, J.; Hendrix, M.S. ); Xiao, X. ); Demaison, G. ); Liang, Y. )

    1990-05-01

    The sedimentary basins of Xinjiang Uygur Autonomous Region, China, are poorly explored for petroleum. Volumetric adequacy of petroleum source rocks is a critical exploration risk in these basins, particularly because source rock data are limited. However, recent studies provide new source rock data and permit speculative assessment of source rock potential of Xinjiang basins. The Junggar basin, best explored of Xinjiang basins and containing a giant oil field, is underlain over much of its extent by an Upper Permian lacustrine oil-shale sequence that is known for its organic richness and oil source quality. Depending on position in the basin, the Permian section ranges from immature to overmature and is inferred to be the principal source of oil in the basin. Upper Triassic-Middle Jurassic coal measures, including lacustrine rocks, constitute a secondary source rock sequence in the Junggar basin. The smaller intermontane Turpan basin contains a very similar Upper Triassic-Middle Jurassic sequence, which, where sufficiently deeply buried, probably comprises the only significant oil source sequence in the basin. The vast Tarim basin offers the greatest potential variety of petroleum source rocks of all Xinjiang basins, but remains the least well documented. From limited, but geologically planned and focused sampling, Cambrian, Carboniferous, and Permian strata are considered unlikely to be major oil source contributors in the dominantly shallow-marine Paleozoic section of the northern Tarim basin. Only Ordovician black shales appear to have significant oil source potential, and a lower Paleozoic source is confirmed for some Tarim oils by gas chromatography-mass spectrometry analysis. The Upper Triassic-Middle Jurassic sequence of northern Tarim basin, similar to that of the Junggar and Turpan basins in comprising a section rich in coal and lacustrine shale, constitutes another, potentially significant oil source.

  11. Source rock geochemistry and liquid and solid petroleum occurrences of the Ouachita Mountains, Oklahoma

    NASA Astrophysics Data System (ADS)

    Curiale, J. A.

    Crude oils, solid bitumens and potential oil source rocks of the frontal and central Ouachita Mountains of southeastern Oklahoma are examined. The organic matter in each of these materials is characterized, and oils are correlated to potential source rocks in the Ouachita Mountains. Four Ouachita Mountain oils and seven solid bitumens (grahamite and impsonite) are analyzed. The oils are paraffinic and range from 31.8 to 43.1 API gravity. The oils are thermally mature and generally unaltered. All four oils are commonly sourced, by n-alkane, sterane and hopane distributions, stable isotope ratios, infrared spectra and vanadium/nickel ratios. A common source for the solid bitumens is also suggested by isotope ratios and pyrolyzate characteristics. An origin due to crude oil biodegradation is suggested for these solids, based on carbon isotope ratios, elemental analyses, and sterane distributions of the solid bitumen pyrolyzates.

  12. Source rocks of the Sub-Andean basins

    SciTech Connect

    Raedeke, L.D. )

    1993-02-01

    Seven source rock systems were mapped using a consistent methodology to allow basin comparison from Trinidad to southern Chile. Silurian and Devonian systems, deposited in passive margin and intracratonic settings, have fair-good original oil/gas potential from central and northern Bolivia to southern Peru. Kerogens range from mature in the foreland to overmature in the thrust belt. Permian to Carboniferous deposition in local restricted basins formed organic-rich shales and carbonates with very good original oil/gas potential, principally in northern Bolivia and southern Peru. Late Triassic to early Jurassic marine shales and limestones, deposited in deep, narrow, basins from Ecuador to north-central maturity. Locally, in the Cuyo rift basin of northern Argentina, a Triassic lacustrine unit is a very good, mature oil source. Early Cretaceous to Jurassic marine incursions into the back-arc basins of Chile-Argentina deposited shales and limestones. Although time transgressive (younging to the south), this system is the principal source in southern back-arc basins, with best potential in Neuquen, where three intervals are stacked A late Cretaceous marine transgressive shale is the most important source in northern South America. The unit includes the La Luna and equivalents extending from Trinidad through Venezuela, Colombia, Ecuador, and into northern Peru. Elsewhere in South America upper Cretaceous marine-lacustrine rocks are a possible source in the Altiplano and Northwest basins of Bolivia and Argentina. Middle Miocene to Oligocene source system includes shallow marine, deltaic, and lacustrine sediments from Trinidad to northern Peru.

  13. Source rock potential of middle Cretaceous rocks in southwestern Montana

    SciTech Connect

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

    1996-08-01

    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 (S{sub 1}+S{sub 2}) 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% R{sub o}. Maturity is high in the Pioneer Mountains, where vitrinite reflectance averages 3.4% R{sub o}, and at Big Sky, Montana, where vitrinite reflectance averages 2.5% R{sub o}. At both localities, high R{sub o} values are due to local heat sources, such as the Pioneer batholith in the Pioneer Mountains.

  14. Effective petroleum source rocks of the world: Stratigraphic distribution and controlling depositional factors

    SciTech Connect

    Klemme, H.D. ); Ulmishek, G.F. )

    1991-12-01

    Six stratigraphic intervals, representing one-third of Phanerozoic time, contain petroleum source rocks that have provided more than 90% of the world's discovered original reserves of oil and gas (in barrels of oil equivalent). The six intervals are (1) Silurian (generated 9% of the world's reserves), (2) Upper Devonian-Tournaisian (8% of reserves), (3) Pennsylvanian-Lower Permian (8% of reserves), (4) Upper Jurassic (25% of reserves), (5) middle Cretaceous (29% of reserves), and (6) Oligocene-Miocene (12.5% of reserves). This uneven distribution of source rocks vary from interval to interval. Maps that show facies, structural forms, and petroleum source rocks were prepared for this study. Analysis of the maps indicates that several primary factors controlled the areal distribution of source rocks, their geochemical type, and their effectiveness (i.e., the amounts of discovered original conventionally recoverable reserves of oil and gas generated by these rocks). These factors are geologic age, paleolatitude of the depositional areas, structural forms in which the deposition of source rocks occurred, and the evolution of biota. The maturation time of these source rocks demonstrates that majority of discovered oil and gas is very young; almost 70% of the world's original reserves of oil and gas has been generated since the Coniacian, and nearly 50% of the world's petroleum{sup 4} has been generated and trapped since the Oligocene.

  15. 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

    2016-05-01

    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

  16. Petroleum source rock potential on Jamaica

    SciTech Connect

    Rodrigues, K.

    1983-01-10

    By means of standard geochemical techniques, geologists evaluated the hydrocarbon source rock potential of Jamaican shales and mudstones in terms of the amount, type, and maturity of the organic matter preserved in these sediments. Samples taken from outcrops and well cores revealed that shales from the Chapelton and Windsor formations may have the best potential for hydrocarbon generation.

  17. Source of oils in Gulf Coast Cenozoic reservoirs

    SciTech Connect

    Curtis, D.M. )

    1989-09-01

    Many Gulf Coast geologists have assumed that shales interbedded with or adjacent to the reservoir sandstones are source rocks for oils in Cenozoic reservoirs, but few source-rock quality shales have been identified in Cenozoic strata. Reservoirs and their associated shales are in thermally immature and organic-poor intervals. Based on geothermal gradient, age, and depth, it can be shown that thermally mature source rocks should be present in older slope shales beneath each producing trend. Assumptions regarding the source rock potential of the interbedded thermally immature shales derive from the fact that hydrocarbons migrated into traps soon after burial of the reservoir (early migration). Early migration from the source rock was therefore also assumed (shallow burial, early migration model). Review of the geochemical requirements for a source rock shows that geochemical constraints demand late migration from the source rock after many thousands of feet of burial (deep burial, late migration model). Geological and geochemical concepts are compatible, however, if migration out of the source rock was late (long after deposition and deep burial of the source rock) but migration into the reservoir was early (soon after shallow burial of the reservoir and trap system).

  18. Reservoir, seal, and source rock distribution in Essaouira Rift Basin

    SciTech Connect

    Ait Salem, A. )

    1994-07-01

    The Essaouira onshore basin is an important hydrocarbon generating basin, which is situated in western Morocco. There are seven oil and gas-with-condensate fields; six are from Jurassic reservoirs and one from a Triassic reservoir. As a segment of the Atlantic passive continental margin, the Essaouira basin was subjected to several post-Hercynian basin deformation phases, which resulted in distribution, in space and time, of reservoir, seal, and source rock. These basin deformations are synsedimentary infilling of major half grabens with continental red buds and evaporite associated with the rifting phase, emplacement of a thick postrifting Jurassic and Cretaceous sedimentary wedge during thermal subsidence, salt movements, and structural deformations in relation to the Atlas mergence. The widely extending lower Oxfordian shales are the only Jurassic shale beds penetrated and recognized as potential and mature source rocks. However, facies analysis and mapping suggested the presence of untested source rocks in Dogger marine shales and Triassic to Liassic lacustrine shales. Rocks with adequate reservoir characteristics were encountered in Triassic/Liassic fluvial sands, upper Liassic dolomites, and upper Oxfordian sandy dolomites. The seals are provided by Liassic salt for the lower reservoirs and Middle to Upper Jurassic anhydrite for the upper reservoirs. Recent exploration studies demonstrate that many prospective structure reserves remain untested.

  19. Laser cleaning of oil spill on coastal rocks

    NASA Astrophysics Data System (ADS)

    Kittiboonanan, Phumipat; Rattanarojpan, Jidapa; Ratanavis, Amarin

    2015-07-01

    In recent years, oil spills have become a significant environmental problem in Thailand. This paper presents a laser treatment for controlled-clean up oil spill from coastal rocks. The cleaning of various types of coastal rocks polluted by the spill was investigated by using a quasi CW diode laser operating at 808 nm. The laser power was attempted from 1 W to 70 W. The result is shown to lead to the laser removal of oil spill, without damaging the underlying rocks. In addition, the cleaning efficiency is evaluated using an optical microscope. This study shows that the laser technology would provide an attractive alternative to current cleaning methods to remove oil spill from coastal rocks.

  20. Northeast Kansas well tests oil, gas possibilities in Precambrian rocks

    USGS Publications Warehouse

    Merriam, D.F.; Newell, K.D.; Doveton, J.H.; Magnuson, L.M.; Lollar, B.S.; Waggoner, W.M.

    2007-01-01

    Tests for oil and gas prospects in Precambrian rocks in Northeast Kansas is currently being undertaken by WTW Operating LLC. It drilled in late 2005 the no.1 Wilson well with a depth of 5,772ft, 1,826ft into the Precambrian basement on a venture testing the possibility of oil and gas in the crystalline rocks. The basin extends northeast into Nebraska and Iowa and is a shallow cratonic basin filled with Paleozoic segments. The rocks have been previously though as not a potential for oil and gas due to the rocks' crystalline and nonporous character with the exception of the Midcontinent rift system (MRS). Later, though, small quantities of oil have been produced on the Central Kansas uplift from granite wash while the wells also produced low-Btu with swabbing operations. The recovered gas contained considerable nonflammable components of nitrogen, carbon dioxide and helium which equates to a low btu content of 283.

  1. Novel maturity parameters for mature to over-mature source rocks and oils based on the distribution of phenanthrene series compounds.

    PubMed

    Wang, Zixiang; Wang, Yongli; Wu, Baoxiang; Wang, Gen; Sun, Zepeng; Xu, Liang; Zhu, Shenzhen; Sun, Lina; Wei, Zhifu

    2016-03-01

    Pyrolysis experiments of a low-mature bitumen sample originated from Cambrian was conducted in gold capsules. Abundance and distribution of phenanthrene series compounds in pyrolysis products were measured by GC-MS to investigate their changes with thermal maturity. Several maturity parameters based on the distribution of phenanthrene series compounds have been discussed. The results indicate that the distribution changes of phenanthrene series compounds are complex, and cannot be explained by individual reaction process during thermal evolution. The dealkylation cannot explain the increase of phenanthrene within the EasyRo range of 0.9% ∼ 2.1%. Adding of phenanthrene into maturity parameters based on the methylphenanthrene isomerization is unreasonable, even though MPI 1 and MPI 2 could be used to some extent. Two additional novel and an optimized maturation parameters based on the distribution of phenanthrene series compounds are proposed and their relationships to EasyRo% (x) are established: log(MPs/P) = 0.19x + 0.08 (0.9% < EasyRo% < 2.1%); log(MPs/P) = 0.64x - 0.86 (2.1% < EasyRo% < 3.4%); log(DMPs/TMPs) = 0.71x - 0.55 (0.9% < EasyRo% < 3.4%); log(MTR) = 0.84x - 0.75 (0.9% < EasyRo% < 3.4%). These significant positive correlations are strong argument for using log(MPs/P), log(DMPs/TMPs) and log(MTR) as maturity parameters, especially for mature to over-mature source rocks. PMID:27441263

  2. Source rock, maturity data indicate potential off Namibia

    SciTech Connect

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

    1998-08-10

    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 offshore 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.

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

    PubMed

    Sen, Indra S; Peucker-Ehrenbrink, Bernhard

    2014-03-18

    The (187)Os/(188)Os ratio that is based on the β(-)-decay of (187)Re to (187)Os (t1/2 = 41.6 billion years) is widely used to investigate petroleum system processes. Despite its broad applicability to studies of hydrocarbon deposits worldwide, a suitable matrix-matched reference material for Os analysis does not exist. In this study, a method that enables Os isotope measurement of crude oil with in-line Os separation and purification from the sample matrix is proposed. The method to analyze Os concentration and (187)Os/(187)Os involves sample digestion under high pressure and high temperature using a high pressure asher (HPA-S, Anton Paar), sparging of volatile osmium tetroxide from the sample solution, and measurements using multicollector inductively coupled plasma mass spectrometry (MC-ICPMS). This methods significantly reduced the total procedural time compared to conventional Carius tube digestion followed by Os separation and purification using solvent extraction, microdistillation and N-TIMS analysis. The method yields Os concentration (28 ± 4 pg g(-1)) and (187)Os/(188)Os (1.62 ± 0.15) of commercially available crude oil reference material NIST 8505 (1 S.D., n = 6). The reference material NIST 8505 is homogeneous with respect to Os concentration at a test portion size of 0.2 g. Therefore, (187)Os/(188)Os composition and Os concentration of NIST 8505 can serve as a matrix-matched reference material for Os analysis. Data quality was assessed by repeated measurements of the USGS shale reference material SCo-1 (sample matrix similar to petroleum source rock) and the widely used Liquid Os Standard solution (LOsSt). The within-laboratory reproducibility of (187)Os/(188)Os for a 5 pg of LOsSt solution, analyzed with this method over a period of 12 months was ∼1.4% (1 S.D., n = 26), respectively. PMID:24552484

  4. Physics of oil entrapment in water-wet rock

    SciTech Connect

    Mohanty, K.K.; Davis, H.T.; Scriven, L.E.

    1987-02-01

    Displacement of oil from an initially oil-filled porous rock by water consists of advancement of menisci and rupture of oil connections. In displacements controlled by capillarity, which are typical of oil reservoir floods, these pore-level events are governed by the local pore geometry, pore topology, and fluid properties, but the pressure field initiates these pore-level events and integrates them with the externally imposed Darcy flow. This paper reports the physics of the pore-level and their integration on a computationally simple model of rock: a square network of pores. The novelty of the approach lies in keeping track of the evolution of the displacement front and in constructing an approximation of the entire pressure field that carries the information essential for predicting the evolution. The result gives insight into the state of the residual oil saturation and its dependence on pore geometry and the capillary number, N/sub ca/, of displacement. As the capillary number increases, the residual oil saturation decreases and the residual oil blobs tend to be smaller. As the pore size distribution becomes wider, the decrease of residual oil saturation with capillary number becomes smoother.

  5. Paleozoic source and reservoir rocks in unbreached thrust ramp anticlines, Millard County, Utah

    SciTech Connect

    Garrison, P.B.; Larsen, B.R. )

    1991-03-01

    Surface geology, source rock geochemistry, and seismic data indicate that substantial hydrocarbon reserves may occur beneath a regional detachment fault underlying Tule Valley and the Confusion Range in northern Millard County, west-central Utah. Paleozoic hydrocarbon source and reservoir rocks in Millard County are laterally equivalent to highly productive rocks in Railroad Valley, Nevada, oil fields. However, the volume of hydrocarbons trapped in thrust ramp duplex anticlines beneath a regional detachment fault is potentially much greater than that in established Nevada fields. The Devonian Guilmette Formation, which consists of interstratified brown, sucrosic dolomite and gray limestone, and the Mississippian Chainman Shale are exposed in the folded and thrusted Confusion Range. Regional geochemical analysis confirms that the Chainman Shale contains enough total organic carbon (TOC) to serve as an effective hydrocarbon source rock. Some surface samples exceed 3% TOC; average TOC is in excess of 1.5%. Thermal maturity of these source rock surface samples indicates that these rocks were subjected to deep burial during their geologic history and that they have generated the maximum amount of hydrocarbons. In addition, thermal maturity of these samples is consistent with hydrocarbon preservation at the 'floor' of the oil window and within the area of peak wet gas generation. Petrographic examination of potential reservoir facies in the Guilmette Formation confirms that liquid hydrocarbons were contained in porous, permeable dolomite. Petrographic examination of kerogen from these same facies also confirms the presence of solid bitumen (dead oil) in the surface samples.

  6. Source characteristics of marine oils as indicated by carbon isotopic ratios of volatile hydrocarbons

    SciTech Connect

    Chung, H.M.; Claypool, G.E.; Rooney, M.A. ); Squires, R.M. )

    1994-03-01

    Carbon isotopic ratios of volatile hydrocarbon fractions of marine oils are diagnostic of organic facies and depositional environments of source rocks. For carbonate oils, low-molecular-weight volatile hydrocarbons (< C[sub 9]) are isotopically lighter than high-molecular-weight volatile hydrocarbons (C[sub 9]-C[sub 17]). In contrast, for deltaic oils, low-molecular-weight volatile hydrocarbons are isotopically heavier than high-molecular-weight volatile hydrocarbons. Marine shale oils show patterns intermediate between carbonate and deltaic oils. This relative variation of carbon isotopic ratios among volatile hydrocarbons of oils is explained by earlier expulsion of marine oils derived from isotopically homogeneous (algal-bacterial) kerogens in rich source rocks, and secondary cracking of petroleum prior to expulsion for marine oils derived from isotopically heterogeneous (terrestrial) kerogens in lean source rocks. In basins with multiple source rocks, carbon isotopic ratios of volatile hydrocarbons are useful for determining oil-oil correlation and for inferring oil-source rock relationship. 67 refs., 5 figs., 2 tabs.

  7. Streaming Potential In Rocks Saturated With Water And Oil

    NASA Astrophysics Data System (ADS)

    Tarvin, J. A.; Caston, A.

    2011-12-01

    Fluids flowing through porous media generate electrical currents. These currents cause electric potentials, called "streaming potentials." Streaming potential amplitude depends on the applied pressure gradient, on rock and fluid properties, and on the interaction between rock and fluid. Streaming potential has been measured for rocks saturated with water (1) and with water-gas mixtures. (2) Few measurements (3) have been reported for rocks saturated with water-oil mixtures. We measured streaming potential for sandstone and limestone saturated with a mixture of brine and laboratory oil. Cylindrical samples were initially saturated with brine and submerged in oil. Saturation was changed by pumping oil from one end of a sample to the other and then through the sample in the opposite direction. Saturation was estimated from sample resistivity. The final saturation of each sample was determined by heating the sample in a closed container and measuring the pressure. Measurements were made by modulating the pressure difference (of oil) between the ends of a sample at multiple frequencies below 20 Hz. The observed streaming potential is a weak function of the saturation. Since sample conductivity decreases with increasing oil saturation, the electro-kinetic coupling coefficient (Pride's L (4)) decreases with increasing oil saturation. (1) David B. Pengra and Po-zen Wong, Colloids and Surfaces, vol., p. 159 283-292 (1999). (2) Eve S. Sprunt, Tony B. Mercer, and Nizar F. Djabbarah, Geophysics, vol. 59, p. 707-711 (1994). (3) Vinogradov, J., Jackson, M.D., Geophysical Res. L., Vol. 38, Article L01301 (2011). (4) Steve Pride, Phys. Rev. B, vol. 50, pp. 15678-15696 (1994).

  8. Controls on the distribution of Cretaceous source rocks in South America

    SciTech Connect

    Vear, A. )

    1993-02-01

    More than thirty South American basins, exhibiting a variety of structural styles, contain petroleum source rocks of Cretaceous age. However, the presence of truly [open quote]world-class[close quote] source rocks, capable of supplying multi-billion barrel oil provinces, is restricted to relatively few basins and appears to be primarily a function of large scale Cretaceous tectonic setting. In Early Cretaceous times the best source rocks were preserved in both a southern ocean and in the rift between South America and Africa. By the Late Cretaceous, these southern and eastern continental limits had become narrow passive margins. In contrast, on the northern continental margin a wide shelf to a restricted tropical sea was developing at this time. Periodic upwelling enhanced surface productivity on this shelf, which led to development of some of the world's richest source rocks. On the tectonically active western margin moderate quality source rocks were forming in a series of back-arc basins, whilst further west, in the Pacific fore-arc, organic-rich intervals were rarely deposited. This article documents what is known about each of the explored basins (including the volume and character of discovered petroleums), it investigates the geologic factors which governed the richness and quality of petroleum source rocks and it assesses how continued tectonic activity has modified or even destroyed primary source quality. Finally it predicts which of the as yet underexplored basins should contain good quality source rocks and could become prolific petroleum provinces of the future.

  9. Preliminary petroleum source rock assessment of upper Proterozoic Chuar group, Grand Canyon, Arizona

    SciTech Connect

    Palacas, J.G.; Reynolds, M.W.

    1989-03-01

    Strata in the Chuar Group, Grand Canyon, Arizona, are potential petroleum source rocks. This group, divided into the Galeros Formation below and the Kwagunt Formaton above, consists predominantly of very fine-grained siliciclastic rocks and thin sequences of sandstones and stromatolites and cryptalgal carbonate rocks. Over half the succession consists of organic-rich, gray to black mudstone and siltstone. Geochemical analyses indicate that the 281-m thick Walcott Member, the uppermost unit of the Kwagunt, has good to excellent petroleum source rock potential. The lower half of the Walcott is characterized by total organic carbon (TOC) contents as much as 7.0% (average /approximately/ 3.0%), hydrogen indices as much as 204 mg HC/g TOC (average 135 mg HC/g TOC), genetic potentials (S/sub 1/ + S/sub 2/) of nearly 16,000 ppm (average /approximately/ 6000 ppm), and extractable organic matter (EOM) as much as 4000 ppm. Data for the upper Walcott are incomplete but suggest that these rocks are as rich or richer than the lower Walcott. Maturity assessment indicates that source rocks of the Walcott are within the oil generation window. Strata of the thermally mature underlying Awatubi Member of the Kwagunt and the thermally mature to overmature Galeros Formation are, in general, rated as poor oil sources with genetic potentials generally less than 1000 ppm, but they are possible gas sources. Several thin sequences in these units, however, display good oil source characteristics, with EOM nearly 2000 ppm and genetic potentials nearly 7000 ppm. Chuar Group strata may be potential sources for economical accumulations of petroleum in upper Proterozoic or lower Paleozoic reservoir rocks in northwest Arizona and southwest Utah.

  10. Rock avalanches caused by earthquakes: Source characteristics

    USGS Publications Warehouse

    Keefer, D.K.

    1984-01-01

    Study of a worldwide sample of historical earthquakes showed that slopes most susceptible to catastrophic rock avalanches were higher than 150 meters and steeper than 25 degrees. The slopes were undercut by fluvial or glacial erosion, were composed ofintensely fractured rock, and exhibited at least one other indicator of low strength or potential instability.

  11. Rock avalanches caused by earthquakes: source characteristics.

    PubMed

    Keefer, D K

    1984-03-23

    Study of a worldwide sample of historical earthquakes showed that slopes most susceptible to catastrophic rock avalanches were higher than 150 meters and steeper than 25 degrees. The slopes were undercut by fluvial or glacial erosion, were composed of intensely fractured rock, and exhibited at least one other indicator of low strength or potential instability. PMID:17759365

  12. The overthrusted Zaza Terrane of middle Cretaceous over the North American continental carbonate rocks of upper Jurassic-Lower Cretaceous age - relationships to oil generation

    SciTech Connect

    Echevarria Rodriguez, G.; Castro, J.A.; Amaro, S.V.

    1996-08-01

    The Zaza Terrane is part of the Caribbean plate thrust over the southern edge of the North American basinal and platform carbonate rocks of upper Jurassic-Lower Cretaceous age. Zaza Terrane are volcanic and ophiolitic rocks of Cretaceous age. The ophiolites are mostly serpentines which behave as reservoirs and seals. All Cuban oil fields are either within Zaza Terrane or basinal carbonates underneath, or not far away to the north of the thrust contacts. It appears that the overthrusting of the Zaza Terrane caused the generation of oil in the basinal carbonate source rocks underneath, due to the increase of rock thickness which lowered the oil window to a deeper position and increased the geothermal gradient. Oil generation was after thrusting, during post-orogenic. API gravity of oil is light toward the south and heavy to very heavy to the north. Source rocks to the south are probably of terrigenous origin.

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

    SciTech Connect

    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 and 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.

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

    SciTech Connect

    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 interval 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.

  15. Source facies and oil families of the Malay Basin, Malaysia

    SciTech Connect

    Creaney, S.; Hussein, A.H. ); Curry, D.J.; Bohacs, K.M. ); Hassan, R. )

    1994-07-01

    The Malay Basin consists of a number of separate petroleum systems, driven exclusively by nonmarine source rocks. These systems range from lower Oligocene to middle Miocene and show a progression from lacustrine-dominated source facies in the lower Oligocene to lower Miocene section to coastal plain/delta plain coal-related sources in the lower to middle Miocene section. Two lacustrine sources are recognized in the older section, and multiple source/reservoir pairs are recognized in the younger coaly section. The lacustrine sources can be recognized using well-log analysis combined with detailed core and sidewall core sampling. Chemically, they are characterized by low pristane/phytane ratios, low oleanane contents, and a general absence of resin-derived terpanes. These sources have TOCs in the 1.0-4.0% range and hydrogen indices of up to 750. In contrast, the coal-related sources are chemically distinct with pristane/phytane ratios of up to 8, very high oleanane contents, and often abundant resinous compounds. All these sources are generally overmature in the basin center and immature toward the basin margin. The oils sourced from all sources in the Malay Basin are generally low in sulfur and of very high economic value. Detailed biomarker analysis of the oils in the Malay Basin has allowed the recognition of families associated with the above sources and demonstrated that oil migration has been largely strata parallel with little cross-stratal mixing of families.

  16. Subsalt source rock maturity in the Sudanese Red Sea

    SciTech Connect

    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 basin 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.

  17. Geochemical character and origin of oils in Ordovician reservoir rock, Illinois and Indiana, USA

    SciTech Connect

    Guthrie, J.M.; Pratt, L.M.

    1995-11-01

    Twenty-three oils produced from reservoirs within the Ordovician Galena Group (Trenton equivalent) and one oil from the Mississippian Ste. Genevieve Limestone in the Illinois and Indiana portions of the Illinois basin are characterized. Two end-member oil groups (1) and (2) and one intermediate group (1A) are identified using conventional carbon isotopic analysis of whole and fractionated oils, gas chromatography (GC) of saturated hydrocarbon fractions, isotope-ratio-monitoring gas chromatography/mass spectrometry (irm-GC/MS) of n-alkanes ranging from C{sub 15} to C{sub 25}, and gas chromatography/mass spectrometry (GC/MS) of the aromatic hydrocarbon fractions. Group 1 is characterized by high odd-carbon predominance in mid-chain n-alkanes (C{sub 15}-C{sub 19}), low abundance Of C{sub 20+}, n-alkanes, and an absence of pristane and phytane. Group IA is characterized by slightly lower odd-carbon predominance of mid-chain n-alkanes, greater abundance of C{sub 20+} n-alkanes compared to group 1, and no pristane and phytane. Conventional correlations of oil to source rock based on carbon isotopic-type curves and hopane (m/z 191) and sterane (m/z 217) distributions are of limited use in distinguishing Ordovician-reservoired oil groups and determining their origin. Oil to source rock correlations using the distribution and carbon isotopic composition of n-alkanes and the m/z 133 chromatograms of n-alkylarenes show that groups 1 and 1A originated from strata of the Upper Ordovician Galena Group. Group 2 either originated solely from the Upper Ordovician Maquoketa Group or from a mixture of oils generated from the Maquoketa Group and the Galena Group. The Mississippian-reservoired oil most likely originated from the Devonian New Albany Group. The use of GC, irm-GC/MS, and GC/MS illustrates the value of integrated molecular and isotopic approaches for correlating oil groups with source rocks.

  18. Correlation of crude oils with their oil source formation, using high resolution GLC C6-C7 component analyses

    NASA Astrophysics Data System (ADS)

    Philippi, G. T.

    1981-09-01

    A novel method based on high resolution gas liquid chromatography (GLC) component analyses of shale and crude oil C6-C7 hydrocarbons is reported, by means of which the composition parameters in an oil are compared with the corresponding parameters in a shale. A similarity coefficient has been devised to measure the degree of correlation between crude oil and source rock hydrocarbons and between the hydrocarbons from different groups of crude oils, having 1.00 as its theoretical maximum value and a fraction close to zero as its minimum. With values above 0.80, correlation between the given hydrocarbons is considered good, and poor below 0.73. It has been found that erroneous crude oil-source rock combinations from areas with more than one source formation have low similarity coefficients, indicating that the correlation method proposed is functioning properly.

  19. Volga-Ural basin, U. S. S. R. : Rich petroleum systems with a single source rock

    SciTech Connect

    Ulmishek, G.F. )

    1991-03-01

    The Volga-Ural basin has produced about 40 billion barrels of oil and still produces a billion barrels annually. The productive Middle Devonian-Lower Permian sequence is composed of various carbonate rocks (including reefs) with clastic intervals in the Middle Devonian-lower Frasnian, middle-upper Visean, and Middle Carboniferous. A single source-rock unit, the Frasnian Domanik Formation, 30-60 m thick, is responsible for productivity of the entire sedimentary section. The three clastic intervals and underlying carbonate strata contain the bulk of the hydrocarbon reserves. Widespread upward and downward vertical migration in this structurally simple basin is explained by imperfect regional seals. Imperfection of the seals has also resulted in a predominance of oil over gas. The best seal is the overpressured Domanik Formation itself; it separates the sedimentary section into two petroleum systems: one in underlying Middle Devonian-lower Frasnian clastics and the other in overlying clastic and carbonate rocks.

  20. Geochemical relationships of petroleum in Mesozoic reservoirs to carbonate source rocks of Jurassic Smackover Formation, southwestern Alabama

    SciTech Connect

    Claypool, G.E.; Mancini, E.A.

    1989-07-01

    Algal carbonate mudstones of the Jurassic Smackover Formation are the main source rocks for oil and condensate in Mesozoic reservoir rocks in southwestern Alabama. This interpretation is based on geochemical analyses of oils, condensates, and organic matter in selected samples of shale (Norphlet Formation, Haynesville Formation, Trinity Group, Tuscaloosa Group) and carbonate (Smackover Formation) rocks. Potential and probable oil source rocks are present in the Tuscaloosa Group and Smackover Formation, respectively. Extractable organic matter from Smackover carbonates has molecular and isotopic similarities to Jurassic oil. Although the Jurassic oils and condensates in southwestern Alabama have genetic similarities, they show significant compositional variations due to differences in thermal maturity and organic facies/lithofacies. Organic facies reflect different depositional conditions for source rocks in the various basins. The Mississippi Interior Salt basin was characterized by more continuous marine to hypersaline conditions, whereas the Manila and Conecuh embayments periodically had lower salnity and greater input of clastic debris and terrestrial organic matter. Petroleum and organic matter in Jurassic rocks of southwestern Alabama show a range of thermal transformations. The gas content of hydrocarbons in reservoirs increases with increasing depth and temperature. In some reservoirs where the temperature is above 266/degrees/F(130/degrees/C), gas-condensate is enriched in isotopically heavy sulfur, apparently derived from thermochemical reduction of Jurassic evaporite sulfate. This process also resulted in increase H/sub 2/S and CO in the gas, and depletion of saturated hydrocarbons in the condensate liquids.

  1. Thermal and petroleum-generation history of the Mississippian Eleana Formation and Tertiary source rocks, Yucca Mountain Area, Southern Nye County, Nevada

    SciTech Connect

    Barker, C.E.

    1995-06-01

    A geochemical and geologic assessment of petroleum potential in the Yucca Mountain area indicates little remaining potential for significant oil and gas generation in the Mississippian Eleana Formation or related Paleozoic rocks, and good but a really restricted potential in Tertiary rocks in Area 8 of the Nevada Test Site. Mesozoic source rocks are not present in the Yucca Mountain area. The Tertiary source rocks in Area 8 of the Nevada Test Site are typically carbon-rich, and where hydrogen-rich, they are good oil-prone source rocks that are immature to marginally mature with respect to oil and gas generation. A geologically similar occurrence of hydrothermally altered Tertiary source rocks at north Bare Mountain retains little hydrocarbon generation capacity. The implication is that hydrocarbons were generated during hydrothermal alteration and have since migrated out of the source rocks or alive been lost during exhumation. A reconstructed thermal history of the Yucca Mountain area, based on the Eleana Formation, indicates petroleum was generated in the Late Paleozoic and possibly Early Mesozoic and that the oil was lost or metamorphosed to pyrobitumen during later heating, probably related to igneous activity. The Tertiary rocks are still capable of generating oil and gas, but little potential exists for a major hydrocarbon discovery due to the restricted occurrence of good source rocks and their marginal thermal maturity when situated away from intrusions.

  2. Structural controls on source rock distribution and maturation in southeast Turkey

    SciTech Connect

    Reed, J.D.; Ottensman, V.V.; Cushing, G.W. ); Aytuna, S. )

    1990-05-01

    Production from the western part of the Zagros fold and thrust belt southeastern Turkey is characterized by high-sulfur (2-3%) oils from middle Cretaceous Mardin Formation. The oils are generated from two carbonate sources, one from the middle Cretaceous passive margin sequence and one deposited as a part of the Upper Cretaceous foreland basin sequence. Both sources are associated with transgressive events coincident with two recognized Cretaceous oceanic anoxic events in Cenomanian-Turonian and Coniacian-Santonian. Geochemical markers in the oils substantiate the restricted, anoxic conditions characteristic of their source rock deposition. During the Upper Cretaceous compressional event, horsts formed buttresses to advancing oceanic thrust sheets. The oceanic thrust sheets consisted of the Karadut and Kocali formations, oceanic equivalents of the Mesozoic shelf. The middle and Upper Cretaceous source facies were rapidly and deeply buried by the tectonically thickened thrust sheets adjacent to the buttresses. Thick burial by the oceanic rocks was critical for thermal maturation of the sources. Geohistory modeling shows generation occurred during the Tertiary coincidental with tectonic activity that probably allowed oil migration to occur along new or reactivated Cretaceous faults.

  3. Source-rock distribution model of the periadriatic region

    SciTech Connect

    Zappaterra, E. )

    1994-03-01

    The Periadriatic area is a mosaic of geological provinces comprised of spatially and temporally similar tectonic-sedimentary cycles. Tectonic evolution progressed from a Triassic-Early Jurassic (Liassic) continental rifting stage on the northern edge of the African craton, through an Early Jurassic (Middle Liassic)-Late Cretaceous/Eocene oceanic rifting stage and passive margin formation, to a final continental collision and active margin deformation stage in the Late Cretaceous/Eocene to Holocene. Extensive shallow-water carbonate platform deposits covered large parts of the Periadriatic region in the Late Triassic. Platform breakup and development of a platform-to-basin carbonate shelf morphology began in the Late Triassic and extended through the Cretaceous. On the basis of this paleogeographic evolution, the regional geology of the Periadriatic region can be expressed in terms of three main Upper Triassic-Paleogene sedimentary sequences: (A), the platform sequence; (B), the platform to basin sequence; and (C), the basin sequence. These sequences developed during the initial rifting and subsequent passive-margin formation tectonic stages. The principal Triassic source basins and most of the surface hydrocarbon indications and economically important oil fields of the Periadriatic region are associated with sequence B areas. No major hydrocarbon accumulations can be directly attributed to the Jurassic-Cretaceous epioceanic and intraplatform source rock sequences. The third episode of source bed deposition characterizes the final active margin deformation stage and is represented by Upper Tertiary organic-rich terrigenous units, mostly gas-prone. These are essentially associated with turbiditic and flysch sequences of foredeep basins and have generated the greater part of the commercial biogenic gases of the Periadriatic region. 82 refs., 11 figs., 2 tabs.

  4. Depositional environment of source beds of high-wax oils in Assam Basin, India

    SciTech Connect

    Saikia, M.M.; Dutta, T.K.

    1980-03-01

    The high-wax Assam oils are found in sand-shale rocks of Tertiary age. The association of the oils with coal and carbonaceous sediments suggests a nearshore or paralic environment in which substances relatively rich in wax and aromatic components were deposited. Sharp variations in wax content from field to field in the Assam basin indicate that little or no migration of oil occurred. Oligocene organic mudstones and shales, rather than the open-marine Eocene Jaintia formation, are the probable source rocks for these syngenetic oils. 1 figure, 2 tables.

  5. Neocomian source and reservoir rocks in the western Brooks Range and Arctic Slope, Alaska

    SciTech Connect

    Mull, C.G.; Reifenstuhl, R.R.; Harris, E.E.; Crowder, R.K.

    1995-04-01

    Detailed (1:63,360) mapping of the Tingmerkpuk sandstone and associated rocks in the Misheguk Mountain and DeLong Mountains guadrangles of the western Brooks Range thrust belt documents potential hydrocarbon source and reservoir rocks in the northern foothills of the western Delong Mountains and adjacent Colville basin of northwest Alaska. Neocomian (?) to Albian micaceous shale, litharenite, and graywacke that overlies the Tingmerkpuk represents the onset of deposition of orogenic sediments derived from the Brooks Range to the south, and the merging of northern and southern sediment sources in the Colville basin. Both the proximal and distal Tingmerkpuk facies contain clay shale interbeds and overlie the Upper Jurassic to Neocomian Kingak Shale. Preliminary geochemical data show that in the thrust belt, these shales are thermally overmature (Ro 1.4-1.6), but are good source rocks with total organic content (TOC) that ranges from 1.2 to 1.8 percent. Shale in the overlying Brookian rocks is also thermally overmature (Ro 1.2-1.5 percent), but contains up to 1.8 percent TOC from a dominantly terrigenous source, and has generated gas. In outcrops at Surprise Creek, in the foothills north of the thrust belt, the Kingak (1.9 percent TOC) and underlying Triassic Shublik Formation (4.6 percent TOC) are excellent oil source rocks with thermal maturity close to peak oil generation stage (Ro0.75-0.9 percent). These rocks have lower thermal maturity values than expected for their stratigraphic position within the deeper parts of the Colville basin and indicate anomalous burial and uplift history in parts of the basin. Preliminary apatite fission-track (AFTA) data from the thrust belt indicate a stage of rapid uplift and cooling at about 53.61 Ma.

  6. Ordovician petroleum source rocks and aspects of hydrocarbon generation in Canadian portion of Williston basin

    SciTech Connect

    Osadetz, K.G.; Snowdon, L.R.

    1988-07-01

    Accumulation of rich petroleum source rocks - starved bituminous mudrocks in both the Winnipeg Formation (Middle Ordovician) and Bighorn Group (Upper Ordovician) - is controlled by cyclical deepening events with a frequency of approximately 2 m.y. Tectonics control both this frequency and the location of starved subbasins of source rock accumulation. Deepening cycles initiated starvation of offshore portions of the inner detrital and medial carbonate facies belts. Persistence of starved offshore settings was aided by marginal onlap and strandline migration in the inner detrital facies belt, and by low carbonate productivity in the medial carbonate facies belt. Low carbonate productivity was accompanied by high rates of planktonic productivity. Periodic anoxia, as a consequence of high rates of planktonic organic productivity accompanying wind-driven equatorial upwellings, is the preferred mechanism for suppressing carbonate productivity within the epeiric sea. The planktonic, although problematic, form Gloecapsamorpha prisca Zalesskey 1917 is the main contributing organism to source rock alginites. A long-ranging alga (Cambrian to Silurian), it forms kukersites in Middle and Upper Ordovician rocks of the Williston basin as a consequence of environmental controls - starvation and periodic anoxia. Source rocks composed of this organic matter type generate oils of distinctive composition at relatively high levels of thermal maturity (transformation ratio = 10% at 0.78% R/sub o/). In the Canadian portion of the Williston basin, such levels of thermal maturity occur at present depths greater than 2950 m within a region of geothermal gradient anomalies associated with the Nesson anticline. Approximately 193 million bbl (30.7 x 10/sup 6/ m/sup 3/) of oil has been expelled into secondary migration pathways from thermally mature source rocks in the Canadian portion of the basin.

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

    USGS Publications Warehouse

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

    2003-01-01

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

  8. 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.

  9. Factors affecting the pore space transformation during hydrocarbon generation in source rock (shales): laboratory experiment

    NASA Astrophysics Data System (ADS)

    Giliazetdinova, D. R.; Korost, D. V.

    2014-12-01

    Oil and gas generation is a set of processes which taking place in the interior, the processes can't be observable in nature. In the process of dumping the source rock, organic matter is transformed into a complex of high-molecular compounds - precursors of oil and gas (kerogen). Entering of a source column for specific thermobaric conditions, triggers the formation of low molecular weight hydrocarbon compounds. Generation of sufficient quantities of hydrocarbons leads to the primary fluid migration within the source rock. For the experiment were selected mainly siliceous-carbonate composition rocks from Domanic horizon South-Tatar arch. The main aim of experiment was heating the rocks in the pyrolyzer to temperatures which correspond katagenes stages. For monitoring changes in the morphology of the pore space X-ray microtomography method was used. As a result, when was made a study of the composition of mineral and organic content of the rocks, as well as textural and structural features, have been identified that the majority of the rock samples within the selected collection are identical. However, characteristics such as organic content and texture of rocks are different. Thus, the experiment was divided into two parts: 1) the study of the influence of organic matter content on the morphology of the rock in the process of thermal effects; 2) study the effect of texture on the primary migration processes for the same values of organic matter. Also, an additional experiment was conducted to study the dynamics of changes in the structure of the pore space. At each stage of the experiment morphology of altered rocks characterized by the formation of new pores and channels connecting the primary voids. However, it was noted that the samples with a relatively low content of the organic matter had less changes in pore space morphology, in contrast to rocks with a high organic content. At the second stage of the research also revealed that the conversion of the pore

  10. Evaporites as a source for oil

    SciTech Connect

    Schreiber, B.C.; Benalihioulhaj, S. . Dept. of Geology); Philp, R.P. . School of Geology and Geophysics)

    1993-02-01

    Organic matter, present in some sediments, acts as the source for hydrocarbons and has been studied at great length, but organic-rich sediments from hypersaline environments are just beginning to be understood. Many types of organic matter from such restricted environments have been identified, and in this study their maturation pathways and products are being explored. By collecting biologically-identified organic matter produced within modern evaporative environments from a number of different marine and nonmarine settings and carrying out detailed geochemical examination of samples we are gradually beginning to understand these materials. The organic samples collected were from evaporative marine, sabkha, and lacustrine deposits, and have been subjected to two types of artificial maturation, hydrous and confined pyrolysis, over a fairly wide range of temperatures (1500 to 350[degrees]C). The biomarker products of these treatments are being analyzed and followed in great detail. Analyses of saturate and aromatic hydrocarbons as well as sulfur compounds in the original and the matured samples provide a comprehensive view of the biomarker assemblages associated with these different depositional environments at different stages of maturity. Infrared spectroscopy and Rock Eval pyrolysis of both the isolated kerogens from both the original and pyrolyzed samples has permitted us to clearly characterize the functional groupings on the one hand and the free hydrocarbons, the potential hydrocarbons, and the oxygenated compounds on the other hand. We have thus been able to demonstrate the potential of the organic matter associated with the different evaporitic environments to act as a good source for oil generation.

  11. Geology, thermal maturation, and source rock geochemistry in a volcanic covered basin: San Juan sag, south-central Colorado

    SciTech Connect

    Gries, R.R.; Clayton, J.L.; Leonard, C.

    1997-07-01

    The San Juan sag, concealed by the vast San Juan volcanic field of south-central Colorado, has only recently benefited from oil and gas wildcat drilling and evaluations. Sound geochemical analyses and maturation modeling are essential elements for successful exploration and development. Oil has been produced in minor quantities from an Oligocene sill in the Mancos Shale within the sag, and major oil and gas production occurs from stratigraphically equivalent rocks in the San Juan basin to the southwest and in the Denver basin to the northeast. The objectives of this study were to identify potential source rocks, assess thermal maturity, and determine hydrocarbon-source bed relationships. Source rocks are present in the San Juan sag in the upper and lower Mancos Shale (including the Niobrara Member), which consists of about 666 m (2184 ft) of marine shale with from 0.5 to 3.1 wt. % organic carbon. Pyrolysis yields (S{sub 1} + S{sub 2} = 2000-6000 ppm) and solvent extraction yields (1000-4000 ppm) indicate that some intervals within the Mancos Shale are good potential source rocks for oil, containing type II organic matter, according to Rock-Eval pyrolysis assay.

  12. Depositional features and source and reservoir rocks of Tertiary age in northern part of South China Sea

    SciTech Connect

    Wang, S.

    1986-07-01

    The northern part of the South China Sea covers an area of about 400,000 km/sup 2/. Tertiary deposits more than 10,000 m in thickness are widely distributed there. The area has sedimentary rocks more than 1000 m thick covers more than 300,000 km/sup 2/. Five sedimentary basins have been established in this area: Beibu Bay, Yinggehai, Southeastern Qiong, Pearl River Mouth, and Southwestern Taiwann basins. The primary source and reservoir rocks for oil and gas prospects are of Tertiary age. Tertiary rocks underwent three stages of development, each forming a specific sedimentation system: (1) a system of fluviolacustrine deposits in rift depressions from the Paleocene to early Oligocene; (2) a system of semiclosed-sea deposits from the late Oligocene to early Miocene; and (3) a system of deltaic open-sea deposits from the middle Miocene to Pliocene. These three sedimentation systems resulted in three suites of source rocks, three suites of reservoir rocks, and three groups of independent oil pools, complete with source, reservoir, and cap rocks. The three suites of source rocks are as follows: (1) the Eocene Liushagang Formation in the Beibu Bay basin, which is believed to be the best source rock discovered in the area; (2) the Oligocene Zhuhai Formation in the Pearl River Mouth basin; and (3) the lower Miocene series in the Pearl River Mouth basin. The Eocene formation is probably the principal source rock of regional scale in the northern part of the South China Sea. The three suites of reservoir rocks are as follows: (1) the fluviolacustrine sandstone bodies in the Liushagang Formation; (2) the fluviolacustrine sand bodies and shallow-sea sandstone bodies in the Zhuhai Formation and Lingshu Formation; (3) the deltaic, littoral, and shallow-sea sand bodies and bioherms of Neogene age, with the middle Miocene sandstone reservoirs having the best physical properties.

  13. A regional appraisal of source rocks north and west of Britain and Ireland

    SciTech Connect

    Scotchman, I.C.; Dore, A.G.

    1995-08-01

    Potential source rocks in the string of basins on the Atlantic Margin north and west of Britain and Ireland range in age from Devonian to Tertiary, although the Jurassic appears to have been effective. In the Palaeozoic, thick developments of lacustrine Type I kerogen rich shales occur in the Lower and Middle Devonian of the Orcadian Basin in northeast Scotland while Carboniferous coals and coaly shales are known from well and outcrop in basins flanking the Rockall Trough. The Jurassic contains major source rock developments, the Lias Portree and Pabba and the Upper Jurassic Kimmeridge Clay Formation shales which have been correlated to oil shows in the Slyne Trough, and oil discoveries in the West of Shetlands respectively. Anoxic black shales are also tentatively developed in the early Cretaceous. In the younger section, developments of gas-prone, organic poor basinal shales are known in the Upper Cretaceous and Paleocene while coals provide a minor gas source in the topmost Palaeocene and Eocene. Regionally, effective source rocks appear to be concentrated in the Jurassic rift basins extending known trends from the Jeanne D`Arc basin through East Greenland to the North Sea/Mid-Norway through the largely unexplored Atlantic Margin area NW of Britain and Ireland.

  14. Oil and gas in carbonate rocks of the CIS basins

    SciTech Connect

    Kuznetsov, V. )

    1993-09-01

    In petroleum basins of the Commonwealth of Independent States (CIS), oil and gas fields in carbonate reservoirs have been discovered in rocks ranging from the Riphean to the Eocene. Most fields are found in cratonic carbonate formations deposited under arid climatic conditions. Regional seals are formed by salt, anhydrite, and dolomicrite. Multilayer reservoirs predominate, but massive reservoirs are common also. The distribution of reservoir types and their quality are strongly uneven. Many fields, including giant fields, are controlled by reefs. Depending on the paleoclimatic zone, the seals are composed of salt or, rarely, of shale. Massive reservoirs predominate, but the distribution of porosity and localization of zones of improved reservoir properties are variable and controlled by the morphogenetic types of the reefs. Carbonate formations deposited under humid climatic conditions contain much less hydrocarbon reserves. The seals are generally composed of shale. The reservoirs are stratal, rarely multilayer, and the fields are usually small. A number of fields, some of them highly productive, are present in Upper Cretaceous carbonate rocks of the North Caucasus region. The carbonates consist of the remains of planktonic organisms. Seals for the hydrocarbon pool are composed of shale. The reservoirs are massive and layered-massive. Fractures and stylolites play a leading role in controlling the reservoir properties.

  15. Potential petroleum source rocks in a tertiary sequence of the Eastern Venezuelan Basin

    NASA Astrophysics Data System (ADS)

    Quintero, K.; Lo Mónaco, G.; López, L.; Lo Mónaco, S.; Escobar, G.; Peralba, M. C. R.; Franco, N.; Kalkreuth, W.

    2012-08-01

    A core of a Tertiary age sequence from the Eastern Venezuelan Basin was analyzed in order to determine its potential for petroleum generation. Conventional geochemical methods, like Rock-Eval pyrolysis, biomarkers from saturated fractions and aromatic hydrocarbon ratios were used for assessing source-rock quality. The application of such methods indicated predominantly the presence of terrigenous organic matter with marine influence, deposited under suboxic to oxic conditions typical of continental environments. Thermal maturation in the range from beginning to mid oil window and organic matter type indicate that the sequence could have generated mainly gaseous hydrocarbons. Analysis by electron probe microanalyses (EPMA) indicates that sulfur is associated to both organic (bitumen and kerogen) and inorganic (mineral) phases and organic matter is observed filling fractures in the rocks.

  16. Geology, thermal maturation, and source rock geochemistry in a volcanic covered basin: San Juan sag, south-central Colorado

    USGS Publications Warehouse

    Gries, R.R.; Clayton, J.L.; Leonard, C.

    1997-01-01

    The San Juan sag, concealed by the vast San Juan volcanic field of south-central Colorado, has only recently benefited from oil and gas wildcat drilling and evaluations. Sound geochemical analyses and maturation modeling are essential elements for successful exploration and development. Oil has been produced in minor quantities from an Oligocene sill in the Mancos Shale within the sag, and major oil and gas production occurs from stratigraphically equivalent rocks in the San Juan basin to the south-west and in the Denver basin to the northeast. The objectives of this study were to identify potential source rocks, assess thermal maturity, and determine hydrocarbon-source bed relationships. Source rocks are present in the San Juan sag in the upper and lower Mancos Shale (including the Niobrara Member), which consists of about 666 m (2184 ft) of marine shale with from 0.5 to 3.1 wt. % organic carbon. Pyrolysis yields (S1 + S2 = 2000-6000 ppm) and solvent extraction yields (1000-4000 ppm) indicate that some intervals within the Mancos Shale are good potential source rocks for oil, containing type II organic matter, according to Rock-Eval pyrolysis assay. Oils produced from the San Juan sag and adjacent part of the San Juan basin are geochemically similar to rock extracts obtained from these potential source rock intervals. Based on reconstruction of the geologic history of the basin integrated with models of organic maturation, we conclude that most of the source rock maturation occurred in the Oligocene and Miocene. Little to no maturation took place during Laramide subsidence of the basin, when the Animas and Blanco Basin formations were deposited. The timing of maturation is unlike that of most Laramide basins in the Rocky Mountain region, where maturation occurred as a result of Paleocene and Eocene basin fill. The present geothermal gradient in the San Juan sag is slightly higher (average 3.5??C/100 m; 1.9??F/100 ft) than the regional average for southern Rocky

  17. 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.

  18. Sedimentation, zoning of reservoir rocks in W. Siberian basin oil fields

    SciTech Connect

    Kliger, J.A. )

    1994-02-07

    A line pattern of well cluster spacing was chosen in western Siberia because of taiga, marshes, etc., on the surface. The zoning of the oil pools within productive Upper Jurassic J[sub 3] intervals is complicated. This is why until the early 1990s almost each third well drilled in the Shaimsky region on the western edge of the West Siberian basin came up dry. The results of development drilling would be much better if one used some sedimentological relationships of zoning of the reservoir rocks within the oil fields. These natural phenomena are: Paleobasin bathymetry; Distances from the sources of the clastic material; and Proximity of the area of deposition. Using the diagram in this article, one can avoid drilling toward areas where the sandstone pinch out, area of argillization of sand-stones, or where the probability of their absence is high.

  19. 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.

  20. Hydrogen in rocks: an energy source for deep microbial communities.

    PubMed

    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. PMID:12449857

  1. Stratigraphic controls on the source rock distribution, Llanos Orientales Basin, Colombia

    SciTech Connect

    Ramon, J.C.; Fajardo, A.; Rubiano, J.; Reyes, A.

    1996-12-31

    All available rock and oil geochemistry analyses were tied to a high-resolution stratigraphic framework for more than 50 wells in the Central Llanos Orientates Basin. New Tertiary generation input is proposed. The best source rock intervals are at the base and top of the Gacheta Formation (Upper Cretaceous) and in the middle of the Barco-Cuervos (Paleocene) and Mirador (Eocene) formations. These organic-rich zones contain type II and III kerogen. TOC contents range from about 1% up to 15%. The four source rock intervals occur within marine shales near condensed sections, at the position maximum accommodation/sediment-supply (A/S) ratios. The development of conditions that allow accumulation and preservation of anomalously high fractions of organic matter might be explained by two mechanisms. Increased A/S ratio results in retention of more sediment in the coastal plain, thus reducing the tendency for siliciclastic sediment to dilute the organic matter accumulating on the shelf. Also, deeper water might restrict circulation, enhancing bottom anoxic conditions. In the more transitional and continental sequences, increased A/S ratio is associated with higher phreatic water level. A high ground water table enhances preservation of coaly intervals. The sea-level rise brings marine water into valleys and low-gradient coastal plains. The resulting embayments, marsh and swampy areas are organic-prone, contributing to the source rock potential of strata associated with high conditions and base-level rise-to-fall turnaround positions.

  2. Stratigraphic controls on the source rock distribution, Llanos Orientales Basin, Colombia

    SciTech Connect

    Ramon, J.C.; Fajardo, A.; Rubiano, J.; Reyes, A. )

    1996-01-01

    All available rock and oil geochemistry analyses were tied to a high-resolution stratigraphic framework for more than 50 wells in the Central Llanos Orientates Basin. New Tertiary generation input is proposed. The best source rock intervals are at the base and top of the Gacheta Formation (Upper Cretaceous) and in the middle of the Barco-Cuervos (Paleocene) and Mirador (Eocene) formations. These organic-rich zones contain type II and III kerogen. TOC contents range from about 1% up to 15%. The four source rock intervals occur within marine shales near condensed sections, at the position maximum accommodation/sediment-supply (A/S) ratios. The development of conditions that allow accumulation and preservation of anomalously high fractions of organic matter might be explained by two mechanisms. Increased A/S ratio results in retention of more sediment in the coastal plain, thus reducing the tendency for siliciclastic sediment to dilute the organic matter accumulating on the shelf. Also, deeper water might restrict circulation, enhancing bottom anoxic conditions. In the more transitional and continental sequences, increased A/S ratio is associated with higher phreatic water level. A high ground water table enhances preservation of coaly intervals. The sea-level rise brings marine water into valleys and low-gradient coastal plains. The resulting embayments, marsh and swampy areas are organic-prone, contributing to the source rock potential of strata associated with high conditions and base-level rise-to-fall turnaround positions.

  3. A rich Middle Triassic source rock in the Barents Sea Area

    SciTech Connect

    Bjoroy, M.; Hall, P.B.

    1983-05-01

    The scope of the work presented in this paper is an evaluation of the petroleum potential of the source rock which shows most promise for the Barents Sea Area. The evaluation is based on analysis of a large number of samples from a Middle Triassic black shale deposit on the various islands of the Svalbard Archipelago. This investigation has shown that the shale is an oil-prone source rock. Analysis of samples taken from areas in the Barents Sea, indicates that this shale sequence has similar potential as a source rock throughout the area south of Svalbard. Integration of this data with the available geophysical and geological data allows the authors to propose that the rich, oilprone Middle Triassic shale sequence also has a widespread distribution throughout the Norwegian Arctic. The results of the geochemical analysis undertaken on Mesozoic deposits of Svalbard and from subsea outcrops in the Barents Sea area is presented. In addition the significant geological data for the region are included. The geochemical data includes; total organic carbon content, Rock-Eval pyrolysis values, vitrinite reflectance and kerogen analysis in transmitted light. In addition some data on the amount and composition of extractable organic matter in the Triassic shales are mentioned.

  4. Source rock in the lower Tertiary and Cretaceous, deep-water Gulf of Mexico

    SciTech Connect

    Wagner, B.E.; Sofer, Z.; Claxton, B.L.

    1994-12-31

    The MC-84 (King) well was drilled in the deep-water Gulf of Mexico in 1993, in Mississippi Canyon Block 84 in a water depth of 5,149 ft. This well drilled an anticlinal feature. The well penetrated an Upper Cretaceous section and crossed Middle Cretaceous Unconformity with final total depth in the Lower Cenomanian. Numerous sidewall cores were taken throughout the Lower Tertiary and Cretaceous. Six of the sidewall cores (from 14,230 to 15,170 ft subsea) are organic rich and contain Type II oil-prone kerogen (TOC values from 2.6 to 5.2% and hydrogen indices from 360 to 543 ppm). The Lower Tertiary through Lower Cenomianian section is thermally immature for oil generation, on the basis of biomarker ratios and vitrinite reflectance measurements. Organic extracts from cores in the Cretaceous section had biomarker characteristics similar to oil recovered from the Miocene in the MC-84 well. The oil was generated from a similar but more mature source rock, probably of Early Cretaceous age. Results of thermal modeling indicate that the only section thermally mature for oil generation is in the lower portion of the Lower Cretaceous, below the total depth of the well. The model also indicates that the organic-rich section equivalent to that penetrated by the MC-84 well could be mature farther to the north, where water depths are shallower, overburden thickness is greater, and heat flow is higher. Late Tertiary sediment loading in this area, primarily during the Miocene, is probably the driving mechanism for hydrocarbon generation from the Cretaceous (and possibly the Lower Tertiary) potential source rocks. This offers a favorable geological setting for capturing hydrocarbons because reservoirs and traps associated with Miocene deposition and subsequent loading-induced salt movement had formed prior to the onset of oil generation and migration.

  5. 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

  6. Application of sesquiterpanes to the study of oil-gas source—the gas-rock correlation in the Qiongdongnan Basin

    NASA Astrophysics Data System (ADS)

    Keming, Cheng; Weiming, Jin; Zhonghua, He; Jianping, Chen

    There are abundant sesquiterpane compounds in terrestrial source rocks and oils. During the thermal evolution, the relative concentration of bicyclic terpanes (C 14) decreases with increasing maturation of organic matters. The concentrations of drimane and homo-drimane increase owing to the dehydroxylation and chemo-dynamics of precursors. Their sharp changes begin around the threshold. The lower the maturity, the more obvious the predominance of homo-drimanes. The crude oils in the Ya13-1 gas field, Qiongdongnan Basin, belong to condensate oils. The "counting vitrinite reflectances" range from 0.8 to 1.10%. The maturity indices, such as paraffin index and hopane value, show that the condensate oils are low mature, which are possibly generated from the resin matter of higher plants at lower temperatures. The aromatic contents of Ya13-1 condensate oils amount to 50%. The Pr/Ph ratios are between 6 and 10. It is shown that the oils are an aromatic base coal generated from coal-bearing strata. The main source rocks for the gas field are the coal-bearing Yacheng Formation (E) based on the oil-rock correlation by bicyclic terpanes. Condensate oil, especially with bicyclic sesquiterpanes, is of importance for the gas-rock correlation, which expands the application range of biomarkers in petroleum exploration.

  7. DEVELOPING A SAFE SOURCE OF CASTOR OIL

    Technology Transfer Automated Retrieval System (TEKTRAN)

    Castor bean (Ricinus communis L.) is an important oilseed crop with significant industrial value. However, the production of castor oil is hampered by the presence of the toxin ricin and hyper-allergenic 2S albumins in its seed. We are thus investigating the possibility of developing a safe source...

  8. Rock comminution as a source of hydrogen for subglacial ecosystems

    NASA Astrophysics Data System (ADS)

    Telling, J.; Boyd, E. S.; Bone, N.; Jones, E. L.; Tranter, M.; Macfarlane, J. W.; Martin, P. G.; Wadham, J. L.; Lamarche-Gagnon, G.; Skidmore, M. L.; Hamilton, T. L.; Hill, E.; Jackson, M.; Hodgson, D. A.

    2015-11-01

    Substantial parts of the beds of glaciers, ice sheets and ice caps are at the pressure melting point. The resulting water harbours diverse subglacial microbial ecosystems capable of affecting global biogeochemical cycles. Such subglacial habitats may have acted as refugia during Neoproterozoic glaciations. However, it is unclear how life in subglacial environments could be supported during glaciations lasting millions of years because energy from overridden organic carbon would become increasingly depleted. Here we investigate the potential for abiogenic H2 produced during rock comminution to provide a continual source of energy to support subglacial life. We collected a range of silicate rocks representative of subglacial environments in Greenland, Canada, Norway and Antarctica and crushed them with a sledgehammer and ball mill to varying surface areas. Under an inert atmosphere in the laboratory, we added water, and measured H2 production with time. H2 was produced at 0 °C in all silicate-water experiments, probably through the reaction of water with mineral surface silica radicals formed during rock comminution. H2 production increased with increasing temperature or decreasing silicate rock grain size. Sufficient H2 was produced to support previously measured rates of methanogenesis under a Greenland glacier. We conclude that abiogenic H2 generation from glacial bedrock comminution could have supported life and biodiversity in subglacial refugia during past extended global glaciations.

  9. Hydrocarbon generation and expulsion in shale Vs. carbonate source rocks

    SciTech Connect

    Leythaeuser, D. ); Krooss, B.; Hillebrand, T.; Primio, R. di )

    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, 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.

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

    NASA Astrophysics Data System (ADS)

    Zhang, S.; Hefter, J.

    2009-05-01

    Hudson Bay Basin is one of the largest Paleozoic sedimentary basins in North America, with Southampton Island on its north margin. The lower part of the basin succession comprises approximately 180 to 300 m of Upper Ordovician strata including Bad Cache Rapids and Churchill River groups and Red Head Rapids Formation. These units mainly comprise carbonate rocks consisting of alternating fossiliferous limestone, evaporitic and reefal dolostone, and minor shale. Shale units containing extremely high TOC, and interpreted to have potential as petroleum source rocks, were found at three levels in the lower Red Head Rapids Formation on Southampton Island, and were also recognized in exploration wells from the Hudson Bay offshore area. A study of conodonts from 390 conodont-bearing samples from continuous cores and well cuttings from six exploration wells in the Hudson Bay Lowlands and offshore area (Comeault Province No. 1, Kaskattama Province No. 1, Pen Island No. 1, Walrus A-71, Polar Bear C-11 and Narwhal South O-58), and about 250 conodont-bearing samples collected from outcrops on Southampton Island allows recognition of three conodont zones in the Upper Ordovician sequence, namely (in ascendant sequence) Belodina confluens, Amorphognathus ordovicicus, and Rhipidognathus symmetricus zones. The three conodont zones suggest a cycle of sea level changes of rising, reaching the highest level, and then falling during the Late Ordovician. Three intervals of petroleum potential source rock are within the Rhipidognathus symmetricus Zone in Red Head Rapids Formation, and formed in a restricted anoxic and hypersaline condition during a period of sea level falling. This is supported by the following data: 1) The conodont Rhipidognathus symmetricus represents the shallowest Late Ordovician conodont biofacies and very shallow subtidal to intertidal and hypersaline condition. This species has the greatest richness within the three oil shale intervals to compare other parts of Red

  11. Diagenesis in halite-cemented source rocks, Middle Devonian, Saskatchewan

    SciTech Connect

    Kendall, A.C. ); Abbott, G.D.; D'Elia, V.A.A. )

    1990-05-01

    Porosity in Dawson Bay carbonates is halite plugged and the formation is sandwiched between thick units of bedded halite. The presence of displacive halite crystals within fine-grained carbonates (implying sediment plasticity during halite emplacement) and uncompacted organic-rich, carbonate-poor stromatolites indicate halite cementation occurred at an early stage. Also, halite cementation must have been completed prior to porosity loss in overlying bedded halites. By comparison with Holocene/Pleistocene bedded halites, this cementation occurred with only tens of meters of overburden. Early complete halite cementation should have converted Dawson Bay carbonates into virtually a closed system and greatly curtailed or inhibited organic-matter maturation within them Organic-rich carbonates occur immediately below Dawson Bay evaporites as rocks containing an anomalously abundant benthos (stromatoporoids, brachiopods) or as a more restricted facies, lacking megafossils or containing gastropods. Some restricted carbonates contain more than 2% extractable organic carbon. The n-alkane, pentacyclic triterpane, nonrearranged sterane and disterane distributions suggest two distinct populations of samples are present. Biomarker distributions are difficult to interpret in terms of estimating organic maturity because of source rock environmental factors (hypersalinity), but appear to be inconsistent with the geological prognosis that these source rocks would have been isolated early in their diagenesis. The problem of how kerogens can be altered in an apparently closed system has yet to be resolved.

  12. Methane and carbon at equilibrium in source rocks

    PubMed Central

    2013-01-01

    Methane in source rocks may not exist exclusively as free gas. It could exist in equilibrium with carbon and higher hydrocarbons: CH4 + C < = > Hydrocarbon. Three lines of evidence support this possibility. 1) Shales ingest gas in amounts and selectivities consistent with gas-carbon equilibrium. There is a 50% increase in solid hydrocarbon mass when Fayetteville Shale is exposed to methane (450 psi) under moderate conditions (100°C): Rock-Eval S2 (mg g-1) 8.5 = > 12.5. All light hydrocarbons are ingested, but with high selectivity, consistent with competitive addition to receptor sites in a growing polymer. Mowry Shale ingests butane vigorously from argon, for example, but not from methane under the same conditions. 2) Production data for a well producing from Fayetteville Shale declines along the theoretical curve for withdrawing gas from higher hydrocarbons in equilibrium with carbon. 3) A new general gas-solid equilibrium model accounts for natural gas at thermodynamic equilibrium, and C6-C7 hydrocarbons constrained to invariant compositions. The results make a strong case for methane in equilibrium with carbon and higher hydrocarbons. If correct, the higher hydrocarbons in source rocks are gas reservoirs, raising the possibility of substantially more gas in shales than analytically apparent, and far more gas in shale deposits than currently recognized. PMID:24330266

  13. Natural gas outstrips oil as energy source

    SciTech Connect

    Not Available

    1981-06-01

    Natural gas (all of it domestically produced) was the largest single source of Pakistan's 1980 energy supply, contributing 40.1% of the total, compared with 37.4% for oil, 16.6% for hydroelectricity, 5.6% for coal, and 0.3% for LP-gas, plus a very small amount of nuclear power. In 1979, gas accounted for 37.6% of the total and oil for 38.9%. Eighty percent of Pakistan's total natural gas production of nearly 300 billion CF came from the Sui field in central Pakistan, which is being developed by Pakistan Petroleum Ltd. The balance was produced in Esso's Mari field and the Oil and Gas Development Commission's Sari and Hundi fields.

  14. Interplay of bacteria, bacteriophage, and Berea sandstone rock in relation to enhanced oil recovery

    SciTech Connect

    Chang, P.L.

    1986-01-01

    Much research and development is needed to recovery oil reserves presently unattainable, and biologically enhanced oil recovery is a technology that may be used for this purpose. To address the problem of bacterial contamination in an oil field injection well region, each end of a Teflon-sleeved Berea sandstone rock was connected to a flask containing nutrient medium. By inoculation one flask with Escherichia coli B, observations of the bacterial growth in the uninoculated flask resulting from the transport and establishment of cells across the rock could be made. Differences in bacterial populations occurred depending on whether bacteriophage T4D was first adsorbed to the rock. The results of these experiments indicate that the inhibition of bacterial establishment within a rock matrix is possible via lytic interaction. Some nonlytic effects are also implied by experiments with B/4 cells, which are T4D-resistant mutants of E. coli B. A 10 to 40% retention of T4 by the rock occurred when it was loaded with 10/sup 5/ to 10/sup 6/ PFU. Also proposed is a lysogenic system for possible use in biologically enhanced oil recovery techniques. In addition to the model bacteria and phage system described above, measurements of the passage of Pseudomonas putida. 12633 and a phage-resistant mutant through Berea sandstone rock were also made. When bacteriophage gh-1 was adsorbed within the rock matrix, a reduction in the passage of the susceptible but no the resistant cells through the rock was observed. The use of P. putida and gh-1 represents a more realistic group of experiments since these pseudomonas are ubiquitous soil bacteria commonly found in oil rock regions. Preliminary work on the degradation of certain nitrogen compounds in the context of biologically enhanced oil recovery is also described in this dissertation.

  15. Devonian Novaculites as source of oil in Marathon-Ouachita thrust system

    SciTech Connect

    Zemmels, I.; Grizzle, P.L.; Walters, C.C.; Haney, F.R.

    1985-02-01

    The Arkansas Novaculite of southern Oklahoma and the Caballos Novaculite of west Texas (both Devonian) form fractured reservoirs in the Marathon-Ouachita thrust system. These formations were examined to ascertain their petroleum potential. Findings include the following. (1) The thermal maturity of the thrust system conforms to the maturity of the sequence that it has overthrust, suggesting that this allochthonous facies is not anomalously mature. (2) Shale units within the novaculites contain oil-prone organic matter in sufficient concentrations to constitute source rocks. (3) The composition of oils from Isom Springs field in southern Oklahoma and from McKay Creek field in west Texas is virtually identical and generally resembles Devonian oils in Oklahoma and west Texas. The authors concluded that the Devonian novaculites of the Marathon-Ouachita thrust system are self sourcing and do not require a fortuitous juxtaposition of source rocks of a different age to produce a commercial deposit.

  16. Preliminary hydrocarbon source rock assessment of the Paleozoic and Mesozoic formations of the western Black Sea region of Turkey

    SciTech Connect

    Harput, B.O.; Demirel, I.H.; Karayigit, A.I.; Aydin, M.; Sahintuerk, O.; Bustin, R.M.

    1999-12-01

    Source rock maturity and potential of Paleozoic and Mesozoic formations in the Eregli, Zonguldak, Bartin, Ulus, and Eflani subregions of the western Black Sea region (WBSR), have been investigated by rock-eval pyrolysis, reflected-light microscopy, and palynofacies analyses. The % Ro values of dispersed organic matter of the Paleozoic formations primarily range from 0.72 to 1.8%, but values as high as 2.6% occur locally in the Silurian Findikli Formation in the Eregli subregion. The % Ro values of Namurian-Westphalian coal seams in the K20/H well drilled in the Zonguldak subregion range from 0.87 to 1.52%, with increasing depth consistent with sedimentary depth of burial. Most Cretaceous age samples have reflectance values ranging from 0.44 to 1.6% Ro that indicates they are marginally mature to mature with respect to the oil window. Rock-eval pyrolysis demonstrates that the Paleozoic formations have limited oil-generation potential (HI values {le} 200 mg HC/g C{sub org}), but good gas potential (TOC values up to 3%). Cretaceous formations have better petroleum source rock characteristics, but they too are primarily gas prone. Variations in the source rock maturity probably reflect variable burial histories in different localities of the WBSR.

  17. Source-rock evaluation of the Dakhla Formation black shale in Gebel Duwi, Quseir area, Egypt

    NASA Astrophysics Data System (ADS)

    El Kammar, M. M.

    2015-04-01

    A relatively thick Upper Cretaceous-Lower Tertiary sedimentary succession is exposed in Gebel Duwi, Red Sea area, through an almost horizontal tunnel cutting the NE dipping strata from Quseir to Thebes formations. The black shale belonging to Dakhla Formation represents a real potential for future energy resource for Egypt. Dakhla Formation consists mainly of organic-rich calcareous shale to argillaceous limestone that can be considered as a good to excellent source rock potential. The total organic carbon (TOC) content ranges from 2.04% to 12.08%, and the Hydrogen Index (HI) values range from 382 to 1024 mg HC/g TOC. Samples of the Dakhla Formation contain mostly kerogen of types I and II that prone oil and oil-gas, indicating marine organic matter derived mainly from algae and phytoplankton organisms and proposing typical oil source kerogen. The average of the potential index (PI) value is 0.02 mg HC/g rock, which indicates the beginning of a considerable amount of oil generation from the Dakhla Formation. The Tmax values range from 427 to 435 °C. Based on the Tmax data and PI values, the studied black shale samples are immature to early mature for hydrocarbon generation in the Duwi area. The data reduction suggests four main factors covering about 91% of the total variances. The average of the calorific value (459 kcal/kg) indicates unworkable efficiency of such black shale for direct combustion use in power stations. However, selective operation of specific horizons having the highest calorific values may provide viable resources.

  18. Precambrian Chuar source rock play: An exploration case history in southern Utah

    SciTech Connect

    Uphoff, T.L.

    1997-01-01

    Source rock potential of the Upper Proterozoic Chuar Group, specifically the Walcott Member of the Kwagunt Formation, provides the basis for a petroleum play in southern Utah. Analyses of Chuar black shales from outcrops in the Grand Canyon show total organic carbon values of 3-9%, hydrogen indices up to 255, and maximum maturity within the oil window. Modeling indicates a potential 150 mi{sup 2} (400 km{sup 2}) area with a minimum generative potential of 2700 MBO{sup *}. Chuar source rocks are proposed as one part of a petroleum system that includes reservoirs in the Cambrian Tapeats Sandstone and seal in the overlying Bright Angel Shale. Prospective structures include anticlines of Laramide age not drilled through the Tapeats interval. One such structure is the Circle Cliffs uplift, which exhibits an area under closure of 9000 mi{sup 2} (2300 km{sup 2}) at the top of the Devonian. In 1994, BHP Petroleum drilled the 28-1 Federal well on the Circle Cliffs structure. The well logged 142 ft (43 m) of Tapeats porosity (>7%) and flowed CO{sub 2} gas at rates up to 5.0 Mcf{sup *} per day. Analysis of bitumen in the reservoir indicated an earlier hydrocarbon charge and suggested a new oil type for the region.

  19. Surface potential and permeability of rock cores under asphaltenic oil flow conditions

    SciTech Connect

    Alkafeef, S.F.; Gochin, R.J.; Smith, A.L.

    1995-12-31

    The surface properties, wetting behaviour and permeability of rock samples are central to understanding recovery behaviour in oil reservoirs. This paper will present a method new to petroleum engineering to show how area/length ratios for porous systems can be obtained by combining streaming potential and streaming current measurements on rock cores. This has allows streaming current measurements (independent of surface conductivity errors) to be made on rock samples using hydrocarbon solvents with increasing concentrations of asphaltene. Negative surface potentials for the rock became steadily more positive as asphaltene coated the pore surfaces, with permeability reduction agreeing well with petrographic analysis.

  20. Importance of Neogene siliceous rocks as the source of petroleum in Japan

    SciTech Connect

    Aoyagi, K. ); Omokawa, M. )

    1989-01-01

    Major oil and gas fields in Japan are located in the area from the central Hokkaido through northeast Honshu. Most productive horizons are generally found in formations of the late Middle Miocene (approximately 12-10 Ma) Onnagawa provincial stage of Japan. These formations are composed mainly of hard mudstone, siliceous shale, diatomaceous mudstone, marlite, and acidic pyroclastic rocks. Source rock potentials in argillaceous rocks of the Miocene Ohdoji Formation in Aomori, the Onnagawa Formation in Akita, and the Lower Teradomari Formation in Niigata show the highest values as compared with other formations in these areas. Average contents of organic carbon and hydrocarbons of siliceous sediments such as diatomite, siliceous shale, and chert in the Aomori basin indicate the higher values as compared with other argillaceous sediments. Diatoms, which appeared in the later Cretaceous, are the principal primary producers of organic matter in the marine environment during the Cenozoic. Organic components and biological productivity show that diatoms have been the most important source of petroleum during the Neogene in Japan.

  1. Loma Chumico Shale: A super-rich source rock with unusual geochemical characteristics

    SciTech Connect

    Walters, C.C.; Rooney, M.A. ); Pierce, S.E.; Gormly, J.R.

    1993-02-01

    The Loma Chumico Shales occur in the Late Cretaceous ophiolitic Nicoya Complex in western Costa Rica. The shales are included in the sedimentary part of the complex that overlies igneous pillow basalts, volcanic agglomerates with interbedded sedimentary rocks, and intrusives. Samples of Loma Chumico Shale (approx. 480 m) were analyzed. The shales are exceptionally rich in organic matter (24 to 29% TOC) and contain kerogen that is rich in hydrogen (Hydrogen Indices = approximately 800 mg hydrocarbons/g of rock, HIC = 1.397) and sulfur (9.7% S, S/C=0.048). The Loma Chumico Shales in the Morote-1 well are immature. This is supported by petrographic, Rock-Eval (Tmax approximately 415[degrees]C), and biomarker analyses. Nevertheless, the shales have a high concentration of extractable organic matter (EOM approximately 30,000 ppm) and suggest that early oil generation has occurred. Saturated hydrocarbons account for less than 8% of the EOM and are predominantly composed of a C[sub 25] tail-to-tail isoprenoid and novel C[sub 27] and C[sub 28] isoprenoid hydrocarbons with pentacyclic rings. These compounds are believed to be derived from thermophilic archaebacteria. The saturated biomarkers form an incomplete picture of the depositional setting as many compounds are sulfur-sequestered; however, the presence of thermophilic archaebacteria suggests that deposition occurred in a hydrothermal environment. Pyrolysis and chemical degradation studies of kerogen and polar compounds liberate a more typical distribution of n-alkanes, isoprenoids, and biomarker compounds. The Loma Chumico Shales could be a major source unit for petroleum in Costa Rica if the super-rich facies has a wide areal extent and the shales obtain sufficient thermal maturity. The Loma Chumico Shales in the Morote-1 well could generate more than three barrels of oil/m[sup 3](approximately 4000 bbl/ac-ft-ft). The oil would be heavy and sulfur-rich.

  2. Hydrocarbon potential of hydrocarbon source rocks of the New Siberian Islands, Russian Arctic

    NASA Astrophysics Data System (ADS)

    Gaedicke, Christoph; Sobolev, Peter; Franke, Dieter; Piepjohn, Karsten; Brandes, Christian; Kus, Jolanta; Scheeder, Georg

    2016-04-01

    The New Siberian Islands are bridging the Laptev Sea with the East Siberian Sea. The Laptev and East Siberian Seas cover large areas of the continental margin of northeastern Arctic Russia. The East Siberian Shelf encompassing an area of 935.000 km2 is still virtually unexplored and most of the geological models for this shelf are extrapolations of the geology of the New Siberian Islands, the Wrangel Island and the northeast Siberian landmass. Apart from few seismic reflection lines, airborne magnetic data were the primary means of deciphering the structural pattern of the East Siberian Shelf. The Laptev Shelf covers an area of about 66.000 km2 and occupies a shelf region, where the active mid-oceanic spreading ridge of the Eurasian Basin hits the slope of the continental margin. During the joint VSEGEI/BGR field expedition CASE 13 (Circum Arctic Structural Events) in summer 2011 we sampled outcrops from the New Siberian Archipelago including the De Long Islands. 102 samples were collected and the Upper Palaeozoic to Lower Cenozoic units are found to be punctuated by several organic-rich intervals. Lithology varies from continental dominated clastic sedimentary rocks with coal seams to shallow marine carbonates and deep marine black shales. Rock-Eval pyrolysis, gas chromatography/mass spectrometry and organic petrography studies were performed to estimate organic matter contents, composition, source, and thermal maturity. According to the results of our analyses, samples from several intervals may be regarded as potential petroleum source rocks. The Lower Devonian shales have the highest source rock potential of all Paleozoic units. Triassic samples have a good natural gas potential. Cretaceous and Cenozoic low-rank coals, lignites, and coal-bearing sandstones display some gas potential. The kerogen of type III (humic, gas-prone) dominates. Most of the samples (except some of Cretaceous and Paleogene age) reached the oil generation window.

  3. 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

  4. Kuwait oil fires - Compositions of source smoke

    NASA Technical Reports Server (NTRS)

    Cofer, Wesley R., III; Stevens, Robert K.; Winstead, Edward L.; Pinto, Joseph P.; Sebacher, Daniel I.; Abdulraheem, Mahmood Y.; Al-Sahafi, Mohammed; Mazurek, Monica A.; Rasmussen, Rei A.; Cahoon, Donald R.

    1992-01-01

    While the Kuwait oil-fire smoke plumes manifested a pronounced impact on solar radiation in the Gulf region (such as visibility and surface temperatures), smoke plume concentrations of combustion-generated pollutants suggest that the overall chemical impact on the atmosphere of the smoke from these fires was probably much less than anticipated. Combustion in the Kuwaiti oil fires was surprisingly efficient, releasing on average more than 93 percent of the combusted hydrocarbon fuels as CO2. Correspondingly, combustion-produced quantities of carbon monoxide (CO) and carbonaceous particles were low, each about 2 percent by weight. The fraction of CH4 produced by the fires was also relatively low (about 0.2 percent), but source emissions of nonmethane hydrocarbons were high (about 2 percent). Processes other than combustion (e.g., volatilization) probably contributed significantly to the measured in-plume hydrocarbon concentrations. Sulfur emissions (particulate and gaseous) measured at the source fires were lower (about 0.5 percent) than predicted based on average sulfur contents in the crude. N2O emissions from the Kuwaiti oil fires were very low and often could not be distinguished from background concentrations.

  5. Log evaluation of oil-bearing igneous rocks

    SciTech Connect

    Khatchikian, A.

    1983-12-01

    The evaluation of porosity, water saturation and clay content of oilbearing igneous rocks with well logs is difficult due to the mineralogical complexity of this type of rocks. The log responses to rhyolite and rhyolite tuff; andesite, dacite and zeolite tuff; diabase and basalt have been studied from examples in western Argentina and compared with values observed in other countries. Several field examples show how these log responses can be used in a complex lithology program to make a complete evaluation.

  6. Detection of Oil Pollution Hotspots and Leak Sources Through the Quantitative Assessment of the Persistence and Temporal Repetition of Regular Oil Spills in the Caspian Sea Using Remote Sensing and GIS

    NASA Astrophysics Data System (ADS)

    Bayramov, E. R.; Buchroithner, M. F.; Bayramov, R. V.

    2015-08-01

    The main goal of this research was to detect oil spills, to determine the oil spill frequencies and to approximate oil leak sources around the Oil Rocks Settlement, the Chilov and Pirallahi Islands in the Caspian Sea using 136 multi-temporal ENVISAT Advanced Synthetic Aperture Radar Wide Swath Medium Resolution Images acquired during 2006-2010. The following oil spill frequencies were observed around the Oil Rocks Settlement, the Chilov and Pirallahi Islands: 2-10 (3471.04 sq. km.), 11-20 (971.66 sq. km.), 21-50 (692.44 sq. km.), 51-128 (191.38 sq. km.). The most critical oil leak sources with the frequency range of 41-128 were observed at the Oil Rocks Settlement. The exponential regression analysis between wind speeds and oil slick areas detected from 136 multi-temporal ENVISAT images revealed the regression coefficient equal to 63%. The regression model showed that larger oil spill areas were observed with decreasing wind speeds. The spatiotemporal patterns of currents in the Caspian Sea explained the multi-directional spatial distribution of oil spills around Oil Rocks Settlement, the Chilov and Pirallahi Islands. The linear regression analysis between detected oil spill frequencies and predicted oil contamination probability by the stochastic model showed the positive trend with the regression coefficient of 30%.

  7. Interaction between Fingering and Heterogeneity during Viscous Oil Recovery in Carbonate Rocks (Invited)

    NASA Astrophysics Data System (ADS)

    Mohanty, K. K.; Doorwar, S.

    2013-12-01

    Due to the fast depleting conventional oil reserves, research in the field of petroleum engineering has shifted focus towards unconventional (viscous and heavy) oils. Many of the viscous oil reserves are in carbonate rocks. Thermal methods in carbonate formations are complicated by mineral dissolution and precipitation. Non-thermal methods should be developed for viscous oils in carbonates. In viscous oil reservoirs, oil recovery due to water flood is low due to viscous fingering. Polymer flood is an attractive process, but the timing of the polymer flood start is an important parameter in the optimization of polymer floods. Vuggy Silurian dolomite cores were saturated with formation brine and reservoir oil (150-200 cp). They were then displaced by either a polymeric solution (secondary polymer flood) or brine followed the polymeric solution (tertiary polymer flood). The amount of brine injection was varied as a parameter. Oil recovery and pressure drop was monitored as a function of the starting point of the polymer flood. To visualize the displacement at the pore-scale, two types of micromodels were prepared: one with isolated heterogeneity and the other with connected heterogeneity. The wettability of the micromodels was either water-wet or oil-wet. The micromodels were saturated with formation brine and oil. A series of water flood and polymer flood was conducted to identify the mechanism of fluid flow. Dolomite corefloods show that a tertiary polymer flood following a secondary water flood recovers a substantial amount of oil unlike what is observed in typical sandstone cores with light oil. The tertiary oil recovery plus the secondary waterflood recovery can exceed the oil recovery in a secondary polymer flood in dolomite-viscous oil-brine system. These experiments were repeated in a Berea-oil-brine system which showed that the oil recovered in the secondary polymer flood was similar to the cumulative oil recovery in the tertiary polymer flood. The high

  8. Petroleum evaluation of Ordovician black shale source rocks in northern Appalachian basin

    SciTech Connect

    Wallace, L.G.; Roen, J.B.

    1988-08-01

    A preliminary appraisal of the Ordovician black shale source beds in the northern part of the Appalachian basin shows that the sequence is composed of the Upper Ordovician Utica Shale and its correlatives. The shales range in thickness from less than 200 ft in the west to more than 600 ft in the east along the Allegheny Front. Structure contours indicate that the shales plunge from 2,000 ft below sea level in central Ohio and to about 12,000 ft below sea level in central and northeastern Pennsylvania. Geochemical analyses of 175 samples indicate that the sequence has an average total organic carbon content (TOC) of 1.34%. Conodont alteration indices (CAI) and production indices indicate that the stages of maturation range from diagenetic in the less deeply buried western part of the basin, which probably produced mostly oil, to catagenetic in the more deeply buried eastern part of the basin, which probably produced mostly gas. Potential for continued hydrocarbon generation is poor in the east and fair to moderate in the western part of the basin. If the authors assume that these rocks have produced hydrocarbons, the hydrocarbons have since migrated. Using an average TOC of 1%, an organic carbon to hydrocarbon conversion factor of 10%, and a volume of rock within the oil and gas generation range as defined by CAI values of 1.5-4, the Ordovician shale could have generated 165 billion bbl of oil or equivalent. If only 1% of the 165 billion bbl was trapped after migration, then 1.65 billion bbl of oil or equivalent would be available for discovery.

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

    SciTech Connect

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

    1996-08-01

    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 the 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.

  10. Significance of oil-like hydrocarbons in metamorphic and ore-deposit rocks

    SciTech Connect

    Price, L.C.

    1996-10-01

    Carbonaceous rocks (0.7-45.0% carbon content) from both greenschist metamorphism and hydrothermal-ore deposition were solvent-extracted and the resulting extracts characterized by standard analyses. Blank runs showed no contamination from laboratory procedures. The recovered HCS are in low, but significant, concentrations (0.5-50 ppm, rock weight). Moreover, the composition of these HCS (including biomarkers) resemble that of mature crude oils and do not have the ultra-mature characteristics expected from their high temperature environs. This strongly suggests that HCS will survive in even higher-rank rocks. These data contradict petroleum-geochemical paradigm regarding an inferred thermal instability of HCS and also bear on natural gas origins (e.g. - the hypothesized cracking of oil to gas), rock-water-HC interactions, petroleum-geochemical models, and other related topics.

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

    USGS Publications Warehouse

    U.S. Geological Survey San Juan Basin Assessment Team

    2013-01-01

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

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

    SciTech Connect

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

    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. When 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.

  13. Characterizing flow in oil reservoir rock using SPH: absolute permeability

    NASA Astrophysics Data System (ADS)

    Holmes, David W.; Williams, John R.; Tilke, Peter; Leonardi, Christopher R.

    2016-04-01

    In this paper, a three-dimensional smooth particle hydrodynamics (SPH) simulator for modeling grain scale fluid flow in porous rock is presented. The versatility of the SPH method has driven its use in increasingly complex areas of flow analysis, including flows related to permeable rock for both groundwater and petroleum reservoir research. While previous approaches to such problems using SPH have involved the use of idealized pore geometries (cylinder/sphere packs etc), in this paper we detail the characterization of flow in models with geometries taken from 3D X-ray microtomographic imaging of actual porous rock; specifically 25.12 % porosity dolomite. This particular rock type has been well characterized experimentally and described in the literature, thus providing a practical `real world' means of verification of SPH that will be key to its acceptance by industry as a viable alternative to traditional reservoir modeling tools. The true advantages of SPH are realized when adding the complexity of multiple fluid phases, however, the accuracy of SPH for single phase flow is, as yet, under developed in the literature and will be the primary focus of this paper. Flow in reservoir rock will typically occur in the range of low Reynolds numbers, making the enforcement of no-slip boundary conditions an important factor in simulation. To this end, we detail the development of a new, robust, and numerically efficient method for implementing no-slip boundary conditions in SPH that can handle the degree of complexity of boundary surfaces, characteristic of an actual permeable rock sample. A study of the effect of particle density is carried out and simulation results for absolute permeability are presented and compared to those from experimentation showing good agreement and validating the method for such applications.

  14. Red Sea/Gulf of Aden source rock geochemical evaluation

    SciTech Connect

    Ducreux, C.; Mathurin, G.; Latreille, M. )

    1991-08-01

    The potential of hydrogen generation in the Red Sea and Gulf of Aden was studied by geochemical analyses of 2,271 samples from 23 wells drilled in 6 countries within the area. Selection of candidate source beds was primarily a function of the sedimentary column penetrated by drilling (i.e., whereas sub-Tertiary sediments are accessible in Somalia and Yemen in the Gulf of Aden, sampling below the thick Neogene evaporitic sequence in the Red Sea could not be achieved due to a general lack of penetration to such levels). Organic matter content and type, maturity levels, petroleum potential of the rock analyzed, and its capacity to have generated liquid or gaseous hydrocarbons are the basic results provided by the analyses. Geochemical well correlations within and between subbasins are presented using the two most representative parameters: total organic carbon (TOC) and Petroleum Potential (PP = S{sub 1} + S{sub 2}), expressed in kilograms of hydrocarbons per ton of rock. In general, results obtained in the two rift basins, with sampling mostly in Neogene sediments in the Red Sea and in sub-Tertiary and Tertiary sediments in the Gulf of Aden, indicate the presence of favorable sources preferentially in this sub-Tertiary succession. It is stressed that geochemical analysis results are from wells whose locations are generally on structural highs and, therefore, are not representative (especially in terms of maturation) of conditions in adjacent depressions, particularly where the difference in structural level is great. Sound simulation modeling makes possible the reconstruction regional thermal and burial history and, thus, identification of maturation kitchens.

  15. Pulse-echo probe of rock permeability near oil wells

    NASA Technical Reports Server (NTRS)

    Narasimhan, K. Y.; Parthasarathy, S. P.

    1978-01-01

    Processing method involves sequential insonifications of borehole wall at number of different frequencies. Return signals are normalized in amplitude, and root-mean-square (rms) value of each signal is determined. Values can be processed to yield information on size and number density of microfractures at various depths in rock matrix by using averaging methods developed for pulse-echo technique.

  16. Seismic monitoring of heavy oil reservoirs: Rock physics and finite element modelling

    NASA Astrophysics Data System (ADS)

    Theune, Ulrich

    In the past decades, remote monitoring of subsurface processes has attracted increasing attention in geophysics. With repeated geophysical surveys one attempts to detect changes in the physical properties in the underground without directly accessing the earth. This technique has been proven to be very valuable for monitoring enhanced oil recovery programs. This thesis presents an modelling approach for the feasibility analysis for monitoring of a thermal enhanced oil recovery technique applied to heavy oil reservoirs in the Western Canadian Sedimentary Basin. In order to produce heavy oil from shallow reservoirs thermal oil recovery techniques such as the Steam Assisted Gravity Drainage (SAGD) are often employed. As these techniques are expensive and technically challenging, early detection of operational problems is without doubt of great value. However, the feasibility of geophysical monitoring depends on many factors such as the changes in the rock physical properties of the target reservoir. In order to access the feasibility of seismic monitoring for heavy oil reservoirs, a fluid-substitutional rock physical study has been carried out to simulate the steam injection. The second modelling approach is based on a modified finite element algorithm to simulate the propagation of elastic waves in the earth, which has been developed independently in the framework of this thesis. The work summarized in this thesis shows a possibility to access the feasibility of seismic monitoring for heavy oil reservoirs through an extensive rock-physical study. Seismic monitoring is a useful tool in reservoir management decision process. However, the work reported here suggests that seismic monitoring of SAGD processes in the heavy oil reservoirs of the Western Canadian Sedimentary Basin is only feasible in shallow, unconsolidated deposits. For deeper, but otherwise geological similar reservoirs, the SAGD does not create a sufficient change in the rock physical properties to be

  17. Source rock in the Lower Tertiary and Cretaceous, deep-water Gulf of Mexico

    SciTech Connect

    Wagner, B.E.; Sofer, Z.; Claxton, B.L.

    1994-09-01

    Amoco drilled three wells in the deep-water Gulf of Mexico in 1993. One well, in Mississippi Canyon Block 84 (W.D. 5200 ft), drilled a structural feature. The well penetrated Cretaceous section and crossed the middle Cenomanian unconformity. Six sidewall cores from 14,230-15,200 ft (subsea) contained TOC values from 2.6 to 5.2% with hydrogen indices front 360 to 543 ppm in lower Tertiary and Cretaceous shales. All six cores were thermally immature, for oil generation, based on biomarker ratios and vitrinite reflectance measurements. Organic extracts from cores in the Cretaceous had biomarker characteristics similar to oil reservoired in the Miocene. The oil was probably generated from a similar, but more mature, source rock. The high structural position of the well prevented the lower Tertiary and Upper Cretaceous section from entering the oil window at this location. There are over 2000 ft of structural relief and an additional 6000-8000 ft of Lower Cretaceous section below the level penetrated by the well. It is probable that an equivalent section off structure is in the oil window. Prior to drilling, estimates of expected thermal maturities and temperatures were made using {sub BASINMOD}, a hydrocarbon generation/expulsion modeling package. The model predicted higher well temperatures (e,g., 225{degrees}F vs. 192{degrees}F) and lower vitrinite maturity (0.44% vs. 0.64%) than encountered in the well. Vitrinite reflectance equivalents of 0.41% and 0.43% were calculated from biomarker ratios of the Cretaceous core extracts, matching the {sub BASINMOD} predicted value of 0.44%.

  18. Enigmatic organosiliceous rocks in the 2000 Ma petrified oil field in Russian Fennoscandia

    NASA Astrophysics Data System (ADS)

    Deines, Yu.; Melezhik, V.; Lepland, A.; Filippov, M.; Romashkin, A.; Rychanchik, D.

    2009-04-01

    could explain the source, and joint transport of two major components, namely silica and OM. We propose a model involving a hydrothermal system initiated by heat produced during the emplacement of numerous mafic intrusive bodies. Such heat may have created the necessary temperature gradient for earlier oil generation, thermal oil to gas cracking, and initiation of shallow-seated, sub-surface, hydrothermal circulation. The proposed result would have been the mingling of silica leached from mafic rocks with hydrocarbon, and gas (primarily CO2, CH4) extracted from the host sedimentary rocks. Such a gas-rich C-Si-H2O substance would have migrated into permeable beds. A high sedimentation rate, as expected in many turbiditic depositional environments, would have produced a high lithostatic pressure on to unlithified beds during the course of the basin subsidence. This would have forced gas-rich C-Si-H2O fluids that moved either laterally along permeable beds or vertically along zones of weakness. In the first case, sediments 'impregnated' with gas-rich C-Si-H2O fluids would have formed stratigraphic beds of OSR, whereas in the second case the result would been crosscutting veins. Beds may retain some primary layering, whereas veins do not. If veins reached the seafloor, the sediment - C-Si-H2O mush would have extruded in the form of a mud volcano / hydrothermal mound, and thus formed a cupola-like morphology. During the course of compression, the sediment - C-Si-H2O mush might have experienced several stages of partial lithification, as well as fluidisation processes leading to the formation of several generations of micro- and macro-brecciated rocks. The large d13C range of reduced carbon in the OSR suggests a complex maturation process of the biogenic OM. Further detailed microstructural, geochemical, isotopic and biomarker studies are planned for distinguishing between biological and abiological processes involved in the formation of the enigmatic OSR.

  19. 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. PMID:26812184

  20. Oil biodegradation by Bacillus strains isolated from the rock of an oil reservoir located in a deep-water production basin in Brazil.

    PubMed

    da Cunha, Claudia Duarte; Rosado, Alexandre S; Sebastián, Gina V; Seldin, Lucy; von der Weid, Irene

    2006-12-01

    Sixteen spore forming Gram-positive bacteria were isolated from the rock of an oil reservoir located in a deep-water production basin in Brazil. These strains were identified as belonging to the genus Bacillus using classical biochemical techniques and API 50CH kits, and their identity was confirmed by sequencing of part of the 16S rRNA gene. All strains were tested for oil degradation ability in microplates using Arabian Light and Marlin oils and only seven strains showed positive results in both kinds of oils. They were also able to grow in the presence of carbazole, n-hexadecane and polyalphaolefin (PAO), but not in toluene, as the only carbon sources. The production of key enzymes involved with aromatic hydrocarbons biodegradation process by Bacillus strains (catechol 1,2-dioxygenase and catechol 2,3-dioxygenase) was verified spectrophotometrically by detection of cis,cis-muconic acid and 2-hydroxymuconic semialdehyde, and results indicated that the ortho ring cleavage pathway is preferential. Furthermore, polymerase chain reaction (PCR) products were obtained when the DNA of seven Bacillus strains were screened for the presence of catabolic genes encoding alkane monooxygenase, catechol 1,2-dioxygenase, and/or catechol 2,3-dioxygenase. This is the first study on Bacillus strains isolated from an oil reservoir in Brazil. PMID:16896598

  1. Characteristics of the Middle Jurassic marine source rocks and prediction of favorable source rock kitchens in the Qiangtang Basin of Tibet

    NASA Astrophysics Data System (ADS)

    Ding, Wenlong; Wan, Huan; Zhang, Yeqian; Han, Guangzhi

    2013-04-01

    We have evaluated the hydrocarbon-bearing potential of Middle Jurassic marine source rocks in the Qiangtang Basin, Tibet, through a comprehensive study of samples from a large number of surface outcrops in different structural units, and from the Qiang-D2 Well in the southern Qiangtang Depression. Data that were acquired, including the depositional environment, thickness of sedimentary units, and organic geochemistry, are used to identify the principal controlling factors and predict the location of favorable hydrocarbon kitchens. The source rocks are mainly platform limestone of the Middle Jurassic Buqu Formation. This formation comprises a suite of intra-platform sag marls, micrites, and black shales that were deposited in a deep-water and restricted depositional environment. The marls form hydrocarbon-rich source rocks with organic matter that is mainly type II and in the mature to highly mature stage. In the Dongco-Hulu Lake and Tupoco-Baitan Lake deep sags, limestone also forms a medium-level source rock. In the Qiangtang Basin, limestone is the favorable source rock kitchen and is more significant in this regard than mudstone. The results provide important constraints on evaluating the hydrocarbon potential of Jurassic marine source rocks and for locating petroleum resources in the Qiangtang Basin.

  2. 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).

  3. Rocks.

    ERIC Educational Resources Information Center

    Lee, Alice

    This science unit is designed for limited- and non-English speaking students in a Chinese bilingual education program. The unit covers rock material, classification, characteristics of types of rocks, and rock cycles. It is written in Chinese and simple English. At the end of the unit there is a list of main terms in both English and Chinese, and…

  4. An investigation into the removal of oil from rock utilising magnetic particle technology.

    PubMed

    Orbell, John D; Dao, Hien V; Kapadia, Jignesh; Ngeh, Lawrence N; Bigger, Stephen W; Healy, Margaret; Jessop, Rosalind; Dann, Peter

    2007-12-01

    The application of magnetic particle technology to environmental remediation has tended to focus, up to now, upon the removal of oil contamination from plumage and fur. The present research demonstrates the potential of this technology to remove oil contamination from the surface of rock. Specifically, a single treatment has been demonstrated to remove more than 80% by weight of heavy bunker oil from the surface of a common foreshore rock type. A further three treatments have been shown to result in an optimum removal of up to 94% by weight. The results are highly reproducible and offer the possibility of achieving up to 100% removal with the appropriate use of pre-conditioners. PMID:17967468

  5. Characterization of pyrolysis oils obtained from non-conventional sources

    SciTech Connect

    Houde, J. Jr.; Charland, J.P.

    1995-12-31

    Research in the field of recycling which focusses on generating oil by pyrolysis or thermal conversion has increased considerably, in recent years. CANMET has developed an application for oil for use as an additive in the manufacture of asphalt. The oil is obtained by thermal conversion of municipal sewage sludge. A program is now under way to examine oils obtained from other sources. The project characterizes pyrolysis oils from automobile shredder residue and pulp and paper mill sludge. Analytical results will be presented as well as a comparison of these oils with those obtained from tires and municipal sewage sludge.

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

    USGS Publications Warehouse

    U.S. Geological Survey San Juan Basin Assessment Team

    2013-01-01

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

  7. Imaging of oil layers, curvature and contact angle in a mixed-wet and a water-wet carbonate rock

    NASA Astrophysics Data System (ADS)

    Singh, Kamaljit; Bijeljic, Branko; Blunt, Martin J.

    2016-03-01

    We have investigated the effect of wettability of carbonate rocks on the morphologies of remaining oil after sequential oil and brine injection in a capillary-dominated flow regime at elevated pressure. The wettability of Ketton limestone was altered in situ using an oil phase doped with fatty acid which produced mixed-wet conditions (the contact angle where oil contacted the solid surface, measured directly from the images, θ=180°, while brine-filled regions remained water-wet), whereas the untreated rock (without doped oil) was weakly water-wet (θ=47 ± 9°). Using X-ray micro-tomography, we show that the brine displaces oil in larger pores during brine injection in the mixed-wet system, leaving oil layers in the pore corners or sandwiched between two brine interfaces. These oil layers, with an average thickness of 47 ± 17 µm, may provide a conductive flow path for slow oil drainage. In contrast, the oil fragments into isolated oil clusters/ganglia during brine injection under water-wet conditions. Although the remaining oil saturation in a water-wet system is about a factor of two larger than that obtained in the mixed-wet rock, the measured brine-oil interfacial area of the disconnected ganglia is a factor of three smaller than that of oil layers.

  8. Extended 3{beta}-alkyl steranes and 3-alkyl triaromatic steroids in crude oils and rock extracts

    SciTech Connect

    Dahl, J.; Moldowan, J.M.; Summons, R.E.

    1995-09-01

    In oils and Precambian- to Miocene-age source rocks from varying depositional environments, we have conclusively identified several novel 3-alkyl sterane and triaromatic steroid series, including (1) 3{beta}-n-pentyl steranes, (2) 3{beta}-isopentyl steranes, (3) 3{beta}-n-hexyl steranes, (4) 3{beta}-n-hepatyl steranes, (5) 3,4-dimethyl steranes, (6) 3{beta}-butyl,4-methyl steranes, (7) triaromatic 3-n-pentyl steroids, and (8) triaromatic 3-isopentyl steroids. We have also tentatively identified additional homologs with 3-alkyl substituents as large as C{sub 11}. The relative abundances of these compounds vary substantially between samples, as indicated by (1) the ratio of 3{beta}-n-pentyl steranes to 3{beta}-isopentyl steranes and (2) the ratio of 3-n-pentyl triaromatic steroids to 3-isopentyl triaromatic steroids. These data suggest possible utility for these parameters as tools for oil-source rock correlations and reconstruction of depositional environments. Although no 3-alkyl steroid natural products are currently known, several lines of evidence suggest that 3{beta}-alkyl steroids result from bacterial side-chain additions to diagenetic {delta}{sup 2}-sterenes.

  9. Depositional environments and source rock investigations of the Oligocene to Middle Miocene deposits in the Ardjuna Basin, offshore Northwest Java, Indonesia

    SciTech Connect

    Wu Chiahsin Charlie.

    1991-01-01

    Investigations of depositional environments, paleogeographic evolution, source rock potential/maturity, and petroleum generation, expulsion, migration and accumulation were performed on the Oligocene to Middle Miocene deposits in the Ardjuna Basin, offshore Northwest Java, using integrated geologic, seismic and geochemical approaches. The Oligocene to Middle Miocene sediments were deposited in a generally transgressive sequence. It is the most prospective stratigraphic unit for petroleum exploration in the Ardjuna Basin. The rocks comprise three Formations: Talang Akar, Baturaja and Cibulakan. Paleogeography of six stages within the study interval, showing the degree of marine transgression were mapped based on integrated biostratigraphic, paleoenvironmental, and seismic-stratigraphic data. The coals and carbonaceous shales deposited in the deltaic and nearshore environment of the Talang Akar Formation are petroleum source rocks for the waxy oils produced in the Ardjuna Basin. The organic matter contains predominantly vitrinite maceral and up to 30% exinite maceral. Source rock temperature, after calibration with vitrinite reflectance, provides an accurate quantitative measurement for predicting the level of thermal maturation. Two geochemical approaches were used and compared in petroleum resource assessment: petroleum yield (S1) method and genetic potential (S2) method. The oil generative kitchen, the Ardjuna depocenter, has the best opportunity for new oil discovery. This model has since been proved by subsequent drilling leading to several oil discoveries in the last two years.

  10. VOC signatures from North American oil and gas sources (Invited)

    NASA Astrophysics Data System (ADS)

    Simpson, I. J.; Marrero, J.; Blake, N. J.; Barletta, B.; Hartt, G.; Meinardi, S.; Schroeder, J.; Apel, E. C.; Hornbrook, R. S.; Blake, D. R.

    2013-12-01

    Between 2008 and 2013 UC Irvine has used its whole air sampling (WAS) technique to investigate VOC source signatures from a range of oil and gas sources in North America, including five separate field campaigns at the Alberta oil sands (1 airborne, 4 ground-based); the 2010 Deepwater Horizon oil spill (airborne and ship-based); the 2012 airborne Deep Convective Clouds and Chemistry Project (DC3) mission over oil and gas wells in Colorado, Texas and Oklahoma; and the 2013 ground-based Barnett Shale Campaign in Texas. Each campaign has characterized more than 80 individual C1-C10 VOCs including alkanes, alkenes and aromatics. For example, oil sands are an extra-heavy, unconventional crude oil that is blended with diluent in order to flow, and upgraded into synthetic crude oil. The VOC signature at the oil sands mining and upgrading facilities is alkane-rich, and the fuel gas associated with these operations has an i-butane/n-butane ratio similar to that of liquefied petroleum gas (LPG). In addition to light alkanes, enhanced levels of benzene were observed over US oil and natural gas wells during DC3, likely because of its use in hydrofracking fluid. A series of VOC emission ratios from North American petrochemical sources will be presented and compared, including oil sands, conventional oil and hydrofracking operations.

  11. A measurement method and system of the thermal properties of rocks under high pressure without heat source

    NASA Astrophysics Data System (ADS)

    Yang, Xiaoqiu; Lin, Weiren; Tadai, Osamu; Zeng, Xin; Xu, Ziying; Shi, Xiaobin; Yu, Chuanhai

    2016-04-01

    Thermal properties of rocks under high pressure are very important for us to understand the thermal structure and state of earth. Basing on the classical thermo-elastic theory, we can know that the temperature of an elastic substance will change when it is compressed or stretched under adiabatic condition. Our measurement results show that the adiabatic stress derivative of temperature (dT/dP) of rocks ranges from 1 to 6 mK/MPa. But the result of silicone oil is up to about 140 mK/MPa. So, we developed a measurement method and system of the thermal properties of rocks under high pressure. In the hydrostatic compression system, the confining pressure can rapidly increase to high pressure within 1~2 s by controlling the value. By monitoring the temperature changes in center and on surface of rock sample during the rapidly loading process, the thermal properties, including thermal conductivity, thermal diffusivity and volumetric heat capacity, can be resolved by our finite element numerical inversion method. We measured several representative rocks from Longmenshan Fault Zone and Chelungpu Fault Zone (TCDP Hole-A), such as sandstone, siltstone, limestone, granite, basalt, tuff and so on. The results indicate that this method and system is suitable for thermal properties measurement under high pressure even though there is without heat source.

  12. Transgenic plants as a sustainable, terrestrial source of fish oils

    PubMed Central

    Usher, Sarah; Haslam, Richard P.; Ruiz‐Lopez, Noemi; Sayanova, Olga

    2015-01-01

    1 An alternative, sustainable source of omega‐3 long chain polyunsaturated fatty acids is widely recognized as desirable, helping to reduce pressure on current sources (wild capture fisheries) and providing a de novo source of these health beneficial fatty acids. This review will consider the efforts and progress to develop transgenic plants as terrestrial sources of omega‐3 fish oils, focusing on recent developments and the possible explanations for advances in the field. We also consider the utility of such a source for use in aquaculture, since this industry is the major consumer of oceanic supplies of omega‐3 fish oils. Given the importance of the aquaculture industry in meeting global requirements for healthy foodstuffs, an alternative source of omega‐3 fish oils represents a potentially significant breakthrough for this production system. Transgenic Camelina seeds engineered to accumulate the omega‐3 fatty acids EPA and DHA, represent a sustainable alternative to fish oils. PMID:26900346

  13. Oil source bed distribution in upper Tertiary of Gulf Coast

    SciTech Connect

    Dow, W.G.

    1985-02-01

    Effective oil source beds have not been reported in Miocene and younger Gulf Coast sediments and the organic matter present is invariably immature and oxidized. Crude oil composition, however, indicates origin from mature source beds containing reduced kerogen. Oil distribution suggests extensive vertical migration through fracture systems from localized sources in deeply buried, geopressured shales. A model is proposed in which oil source beds were deposited in intraslope basins that formed behind salt ridges. The combination of silled basin topography, rapid sedimentation, and enhanced oxygen-minimum zones during global warmups resulted in periodic anoxic environments and preservation of oil-generating organic matter. Anoxia was most widespread during the middle Miocene and Pliocene transgressions and rare during regressive cycles when anoxia occurred primarily in hypersaline conditions such as exist today in the Orca basin.

  14. Paleocene-Eocene potential source rocks in the Avengco Basin, Tibet: Organic geochemical characteristics and their implication for the paleoenvironment

    NASA Astrophysics Data System (ADS)

    Han, Zhongpeng; Xu, Ming; Li, Yalin; Wei, Yushuai; Wang, Chengshan

    2014-10-01

    The Avengco Basin is located in the western part of the Tibetan Plateau and is similar to the Nima Basin in the central part of the plateau and the Lunpola Basin in the eastern part in terms of sedimentary characteristics and tectonic settings, which are well known to provide a good source rock potential. However, the organic geochemical characteristics of the Paleocene-Eocene potential source rocks in the Avengco Basin have been under debate. Thirty-four marl and mudstone outcrop samples of the Niubao Formation in the Avengco Basin were collected and subjected to the following analyses: total organic carbon (TOC), Rock-Eval pyrolysis, stable carbon isotopes of kerogen, gas chromatography (GC) and gas chromatography-mass spectrometry (GC-MS). Here, we present the results indicating the organic matter of the upper Niubao Formation is mainly composed of Type II kerogen with a mixed source, which is dominated by algae. However, the lower Niubao Formation has the less oil-prone Type II-III kerogen, and the sources of the organic matter are mainly terrestrial plants with less plankton. In addition, the samples are thermally immature to marginally mature. The Niubao Formation was deposited in an anoxic-oxic environment which was brackish with an imperceptible stratified water column. The upper Niubao Formation has a medium to good hydrocarbon-generating potential. However, the lower Niubao Formation has a zero to poor hydrocarbon-generating potential.

  15. 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.

  16. Reasons for production decline in the diatomite, Belridge oil field: a rock mechanics view

    SciTech Connect

    Strickland, F.G.

    1982-01-01

    This work summarized research conducted on diatomite cores from the Belridge oil field in Kern County. The study was undertaken to try to explain the rapid decline in oil production in diatomite wells. Characterization of the rock showed that the rock was composed principally of amorphous opaline silica diatoms with only a trace of crystoballite quartz or chert quartz. Physical properties tests showed the diatomite to be of low strength and plastic. Finally, it was established that long-term creep of diatomite into a propped fracture proceeds at a rate of approximately 6 x 10-5 in./day, a phenomenon which may be a primary cause of rapid production declines. The testing program also revealed a matrix stength for the formation of calculated 1325 PSI, a value to consider when depleting the reservoir. This also may help to explain the phase transformation of opal ct at calculated 2000 to 2500 ft depth.

  17. Acid rock drainage and rock weathering in Antarctica: important sources for iron cycling in the Southern Ocean.

    PubMed

    Dold, B; Gonzalez-Toril, E; Aguilera, A; Lopez-Pamo, E; Cisternas, M E; Bucchi, F; Amils, R

    2013-06-18

    Here we describe biogeochemical processes that lead to the generation of acid rock drainage (ARD) and rock weathering on the Antarctic landmass and describe why they are important sources of iron into the Antarctic Ocean. During three expeditions, 2009-2011, we examined three sites on the South Shetland Islands in Antarctica. Two of them displayed intensive sulfide mineralization and generated acidic (pH 3.2-4.5), iron-rich drainage waters (up to 1.78 mM Fe), which infiltrated as groundwater (as Fe(2+)) and as superficial runoff (as Fe(3+)) into the sea, the latter with the formation of schwertmannite in the sea-ice. The formation of ARD in the Antarctic was catalyzed by acid mine drainage microorganisms found in cold climates, including Acidithiobacillus ferrivorans and Thiobacillus plumbophilus. The dissolved iron (DFe) flux from rock weathering (nonmineralized control site) was calculated to be 0.45 × 10(9) g DFe yr(-1) for the nowadays 5468 km of ice-free Antarctic rock coastline which is of the same order of magnitude as glacial or aeolian input to the Southern Ocean. Additionally, the two ARD sites alone liberate 0.026 and 0.057 × 10(9) g DFe yr(-1) as point sources to the sea. The increased iron input correlates with increased phytoplankton production close to the source. This might even be enhanced in the future by a global warming scenario, and could be a process counterbalancing global warming. PMID:23682976

  18. Hydrodynamic thickness of petroleum oil adsorbed layers in the pores of reservoir rocks.

    PubMed

    Alkafeef, Saad F; Algharaib, Meshal K; Alajmi, Abdullah F

    2006-06-01

    The hydrodynamic thickness delta of adsorbed petroleum (crude) oil layers into the pores of sandstone rocks, through which the liquid flows, has been studied by Poiseuille's flow law and the evolution of (electrical) streaming current. The adsorption of petroleum oil is accompanied by a numerical reduction in the (negative) surface potential of the pore walls, eventually stabilizing at a small positive potential, attributed to the oil macromolecules themselves. After increasing to around 30% of the pore radius, the adsorbed layer thickness delta stopped growing either with time or with concentrations of asphaltene in the flowing liquid. The adsorption thickness is confirmed with the blockage value of the rock pores' area determined by the combination of streaming current and streaming potential measurements. This behavior is attributed to the effect on the disjoining pressure across the adsorbed layer, as described by Derjaguin and Churaev, of which the polymolecular adsorption films lose their stability long before their thickness has approached the radius of the rock pore. PMID:16414057

  19. Thermal maturation and organic richness of potential petroleum source rocks in Proterozoic Rice Formation, North American Mid-Continent rift system, northeastern Kansas

    SciTech Connect

    Newell, K.D. ); Burruss, R.C.; Palacas, J.G. )

    1993-11-01

    A recent well in northeastern Kansas penetrated 296 ft (90.2 m) of dark gray siltstone in the Precambrian Mid-Continent rift (Proterozoic Rice Formation). Correlations indicate this unit may be as thick as 600 ft (183 m) and is possibly time-equivalent to the Nonesuch Shale (Middle Proterozoic) in the Lake Superior region. The upper half of this unit qualifies as a lean source rock (averaging 0.66 wt.% TOC), and organic matter in it is in the transition stage between oil and wet gas generation. The presence of the gray siltstone in this well and similar lithologies in other wells is encouraging because it indicates the source rock deposition may be common along the Mid-Continent rift, and that parts of the rift may remain thermally within the oil and gas window. Microscopic examination of calcite veins penetrating the dark gray siltstone reveals numerous oil-filled and subordinate aqueous fluid inclusions. Homogenization temperatures indicate these rocks have been subjected to temperature of at least 110-115[degrees]C (230-239[degrees]F). Burial during the Phanerozoic is inadequate to account for the homogenization temperatures and thermal maturity of the Precambrian rocks. With the present geothermal gradient, at least 8250 ft (2.5 km) of burial is necessary, but lesser burial may be likely with probably higher geothermal gradients during rifting. Fluorescence colors and gas chromatograms indicate compositions of oils in the fluid inclusions vary. However, oils in the fluid inclusions are markedly dissimilar to the nearest oils produced from Paleozoic rocks.

  20. Groundwater compatibility with formation water and pay zone rocks in Pervomaysk oil-gas-condensate field to maintain formation pressure

    NASA Astrophysics Data System (ADS)

    Trifonov, N.; Nazarov, A.; Alekseev, S.

    2016-03-01

    The paper describes the research results in determining the compatibility of groundwater from Aptain-Albian-Cenomanian aquifer with formation water and pay zone rocks in U1 layer sediments, Pervomaysk oil field.

  1. Diffusion and spatially resolved NMR in Berea and Venezuelan oil reservoir rocks.

    PubMed

    Murgich, J; Corti, M; Pavesi, L; Voltini, F

    1992-01-01

    Conventional and spatially resolved proton NMR and relaxation measurements are used in order to study the molecular motions and the equilibrium and nonequilibrium diffusion of oils in Berea sandstone and Venezuelan reservoir rocks. In the water-saturated Berea a single line with T*2 congruent to 150 microseconds is observed, while the relaxation recovery is multiexponential. In an oil reservoir rock (Ful 13) a single narrow line is present while a distribution of relaxation rates is evidenced from the recovery plots. On the contrary, in the Ful 7 sample (extracted at a deeper depth in a different zone) two NMR components are present, with 3.5 and 30 KHz linewidths, and the recovery plot exhibits biexponential law. No echo signal could be reconstructed in the oil reservoir rocks. These findings can be related to the effects in the micropores, where motions at very low frequency can occur in a thin layer. From a comparison of the diffusion constant in water-saturated Berea, D congruent to 5*10(-6) cm2/sec, with the ones in model systems, the average size of the pores is estimated around 40 A. The density profiles at the equilibrium show uniform distribution of oils or of water, and the relaxation rates appear independent from the selected slice. The nonequilibrium diffusion was studied as a function of time in a Berea cylinder with z axis along H0, starting from a thin layer of oil at the base, and detecting the spin density profiles d(z,t) with slice-selection techniques. Simultaneously, the values of T1's were measured locally, and the distribution of the relaxation rates was observed to be present in any slice.(ABSTRACT TRUNCATED AT 250 WORDS) PMID:1461080

  2. 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.

  3. Coals as source rocks for hydrocarbon generation in the Taranaki Basin, New Zealand: a geochemical biomarker study

    NASA Astrophysics Data System (ADS)

    Johnston, J. H.; Collier, R. J.; Maidment, A. I.

    The Taranaki Basin area provides the only source of commercial hydrocarbons in New Zealand. These are contained in the offshore Maui (gas-condensate) and onshore Kapuni (gas-condensate), Kaimiro (gas-condensate), and McKee (oil) fields. In addition a number of other smaller onshore fields have been discovered recently. The terrestrial coal measures of the Kapuni Group (Eocene) are now considered to be the source rocks for the onshore fields. The generated hydrocarbons are generally reservoired in the upper Kapuni Group sands. A summary of the results of the biomarker study of the triterpane hopanes and steranes extracted from coals in the deeper region of a selection of wells from the onshore Stratford, Kaimiro, Mangahewa and McKee fields and also from the produced condensates and oils, are presentedhere. These results show that the produced hydrocarbons have thermal maturities comparable to or approaching those of the deepest coals encountered on drilling within the Kapuni Group. Thus although the hydrocarbons may be generated within the Kapuni Group coals they are expelled only from the deepest coals within this Group or possibly the older (Paleocene-Upper Cretaceous) coals of the underlying Pakawau Formation, thereby exhibiting higher maturity levels. The presence of specific biomarkers in the produced hydrocarbons suggests the possibility of multiple source rocks and that the hydrocarbons have migrated to their present shallower reservoirs.

  4. An experimental and theoretical study to relate uncommon rock/fluid properties to oil recovery. Final report

    SciTech Connect

    Watson, R.

    1995-07-01

    Waterflooding is the most commonly used secondary oil recovery technique. One of the requirements for understanding waterflood performance is a good knowledge of the basic properties of the reservoir rocks. This study is aimed at correlating rock-pore characteristics to oil recovery from various reservoir rock types and incorporating these properties into empirical models for Predicting oil recovery. For that reason, this report deals with the analyses and interpretation of experimental data collected from core floods and correlated against measurements of absolute permeability, porosity. wettability index, mercury porosimetry properties and irreducible water saturation. The results of the radial-core the radial-core and linear-core flow investigations and the other associated experimental analyses are presented and incorporated into empirical models to improve the predictions of oil recovery resulting from waterflooding, for sandstone and limestone reservoirs. For the radial-core case, the standardized regression model selected, based on a subset of the variables, predicted oil recovery by waterflooding with a standard deviation of 7%. For the linear-core case, separate models are developed using common, uncommon and combination of both types of rock properties. It was observed that residual oil saturation and oil recovery are better predicted with the inclusion of both common and uncommon rock/fluid properties into the predictive models.

  5. The ratios of dibenzothiophene to phenanthrene and pristane to phytane as indicators of depositional environment and lithology of petroleum source rocks

    NASA Astrophysics Data System (ADS)

    Hughes, William B.; Holba, Albert G.; Dzou, Leon I. P.

    1995-09-01

    The ratio of dibenzothiophene to phenanthrene and the ratio of pristane to phytane, when coupled together, provide a novel and convenient way to infer crude oil source rock depositional environments and lithologies. Such knowledge can significantly assist in identifying the source formation(s) in a basin thereby providing valuable guidance for further exploration. The ability to infer this information from analysis of a crude oil is especially valuable as frequently the earliest samples in a new area may be shows and/or drill stem test samples from exploratory wells which are characteristically drilled on structural highs stratigraphically remote from the source formation(s). A cross-plot of dibenzothiophene/phenanthrene versus the pristane/phytane ratios measured on seventy-five crude oils from forty-one known source rocks ranging in age from Ordovician to Miocene consistently classified the oils into the following environment/ lithology groups: marine carbonate; marine carbonate/ mixed and lacustrine sulfate-rich; lacustrine sulfate-poor; marine and lacustrine shale; and fluvial/deltaic carbonaceous shale and coal. The dibenzothiophene/phenanthrene ratio alone is an excellent indicator of source rock lithology with carbonates having ratios > 1 and shales having ratios < 1. The dibenzothiophene to phenanthrene and the pristane to phytane ratios can also be used to classify source rock paleodepositional environments. The classification scheme is based on the premise that these ratios reflect the different Eh-pH regimes resulting from the significant microbiological and chemical processes occurring during deposition and early diagenesis of sediments. The dibenzothiophene/phenanthrene ratio assesses the availability of reduced sulfur for incorporation into organic matter and the pristane/phytane ratio assesses the redox conditions within the depositional environment. Interpretation of these ratios has been aided by quantitative biomarker analysis and by carbon

  6. Strontium isotopic evidence for an enriched source for post-subduction volcanic rocks, Dominican Republic

    SciTech Connect

    Wertz, W.K.; Perfit, M.R.; Shuster, R.D.

    1985-01-01

    Later Cenozoic volcanic rocks from the eastern Las Cuevas region (ELCR), Dominican Republic are dominantly shoshonitic and are associated with a series of east-west trending faults. The ELCR rocks are highly enriched in Sr, Ba, and light REE, but contain relatively low amounts of Rb and HFS ions. Several basalts appear to be unfractionated and have Mg-numbers of >75. These transitional to alkalic volcanic rocks are atypical of Caribbean igneous rocks and are more similar to alkaline centers associated with late-stage, island arc volcanism in other regions. Elevated /sup 87/Sr//sup 86/Sr ratios (0.7041-0.7048) are high in comparison to most other igneous rocks from the Caribbean region and indicate that they were derived from a source relatively enriched in LIL and REE in comparison to the sources which gave rise to the majority of Caribbean igneous rocks. /sup 87/Sr//sup 86/Sr values increase linearly with increasing Sr contents, suggesting mixing of sources with relatively low Sr contents and depleted /sup 87/Sr//sup 86/Sr with material that is highly enriched in Sr and with /sup 87/Sr//sup 86/Sr values around 0.706. This enriched component may be a fluid derived from melting/dehydrating subducted oceanic crust and sediment which metasomatically veined the sub-arc mantle. Small degrees of partial melting (<7%) of this source may be responsible for the unusual and enriched chemical composition of the ELCR volcanic rocks.

  7. Real-time oil-saturation monitoring in rock cores with low-field NMR.

    PubMed

    Mitchell, J; Howe, A M; Clarke, A

    2015-07-01

    Nuclear magnetic resonance (NMR) provides a powerful suite of tools for studying oil in reservoir core plugs at the laboratory scale. Low-field magnets are preferred for well-log calibration and to minimize magnetic-susceptibility-induced internal gradients in the porous medium. We demonstrate that careful data processing, combined with prior knowledge of the sample properties, enables real-time acquisition and interpretation of saturation state (relative amount of oil and water in the pores of a rock). Robust discrimination of oil and brine is achieved with diffusion weighting. We use this real-time analysis to monitor the forced displacement of oil from porous materials (sintered glass beads and sandstones) and to generate capillary desaturation curves. The real-time output enables in situ modification of the flood protocol and accurate control of the saturation state prior to the acquisition of standard NMR core analysis data, such as diffusion-relaxation correlations. Although applications to oil recovery and core analysis are demonstrated, the implementation highlights the general practicality of low-field NMR as an inline sensor for real-time industrial process control. PMID:25996514

  8. Petroleum source rock evaluation of the Sebahat and Ganduman Formations, Dent Peninsula, Eastern Sabah, Malaysia

    NASA Astrophysics Data System (ADS)

    Mustapha, Khairul Azlan; Abdullah, Wan Hasiah

    2013-10-01

    The Sebahat (Middle Miocene to Early Pliocene) and Ganduman (Early Pliocene to Late Pliocene) Formations comprise part of the Dent Group. The onshore Sebahat and Ganduman Formations form part of the sedimentary sequence within the Sandakan sub-basin which continues offshore in the southern portion of the Sulu Sea off Eastern Sabah. The Ganduman Formation lies conformably on the Sebahat Formation. The shaly Sebahat Formation represents a distal holomarine facies while the sandy Ganduman Formation represents the proximal unit of a fluvial-deltaic system. Based on organic geochemical and petrological analyses, both formations posses very variable TOC content in the range of 0.7-48 wt% for Sebahat Formation and 1-57 wt% for Ganduman Formation. Both formations are dominated by Type III kerogen, and are thus considered to be gas-prone based on HI vs. Tmax plots. Although the HI-Tmax diagram indicates a Type III kerogen, petrographic observations indicate a significant amount of oil-prone liptinite macerals. Petrographically, it was observed that significant amounts (1-17% by volume) of liptinite macerals are present in the Ganduman Formation with lesser amounts in the Sebahat Formation. Both formations are thermally immature with vitrinite reflectance values in the range of 0.20-0.35%Ro for Ganduman Formation and 0.25-0.44%Ro for Sebahat Formation. Although these onshore sediments are thermally immature for petroleum generation, the stratigraphic equivalent of these sediments offshore are known to have been buried to deeper depth and could therefore act as potential source rocks for gas with minor amounts of oil.

  9. Cretaceous source rock sedimentation and its relation to transgressive peaks and geodynamic events for the Central Tethys

    SciTech Connect

    Flexer, A. ); Honigstein, A.; Rosenfeld, A. ); Lipson, S. ); Tarnenbaum, E. )

    1993-02-01

    The reconstruction of the Mesozoic continents shows a wide triangle-shaped Tethys (or Neotethys) between Africa and Eurasia. The Arabian Craton comprised the central part of its southern margins. The Cretaceous period started with extension, volcanism, continued by accelerated divergence during Aptian-Turonian and terminated by convergence and folding. The sea level stand, after a major fall at the commencement, is characterized by a steady stepwise rise with some minor retreats. The global oceanic anoxic events correspond to large-extent transgressions and associated with organic rich sedimentation. The accelerated building up of mid-oceanic ridges is possibly connected to a mantle plume, active around 120-80 Ma. Sea level rise and sea floor spreading is felt mainly at these times in the passive southern margins of the central Tethys. The Senonian compressive tectonic regime transforms them into active margins (destruction of oceanic crust, obduction and thrusting); sea level highstands control dysoxic sedimentation. Dysoxic sediments were observed in the Gevaram shales (Tithonian-Hauterivian). Talme Yafe marls (Late Aptian-Albian), Daliyya Formation (latest Cenomanian-Turonian) and the Mount Scopus Group (Santonian-Maastrichtian). The organic matter in the Gevaram shales is mixed marine and terrestrial (2.6% TOC) and in the Daliyya marls mostly marine (2.5% TOC). Both units have source rock possibilities and yield petroleum upon appropriate burial. The Senonian bituminous rocks (oil shales) are rich in marine organic matter (20% TOC) and are excellent source rocks in the Dead Sea area.

  10. 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, J.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

  11. Primary migration of hydrocarbon fluids through invasion-percolation cracking in a source rock

    NASA Astrophysics Data System (ADS)

    Kobchenko, M.; Panahi, H.; Renard, F.; Malthe-Sorenssen, A.; Scheibert, J.; Dysthe, D.; Meakin, P.

    2010-12-01

    A petroleum source rock is a tightly bound mixture of highly viscous, high molecular weight, organics (kerogen) and inorganic sedimentary material. During burial, as the temperature and pressure increase, kerogen decomposes, and low viscosity, low molecular weight, hydrocarbons are generated. Primary migration has been studied for decades, but it still remains an enigma how the generated gas and oil escape from very low permeable shales into secondary migration pathways. There is strong evidence that microfractures play an important role in this process. In order to observe crack nucleation and development we performed high resolution x-ray microtomography experiments on samples of Mahogany Zone Green River Shale (Peance Basin, Colorado, USA). One sample was exposed to a gradual rising temperature under atmospheric pressure and time-lapse 3D images of void formation and cracking were acquired. We show that crack formation occurs via nucleation of small cracks/voids located on kerogen patches initially present in the samples. Then these cracks propagate through an invasion percolation-like process in which the fracture front incrementally moves by local stress relaxation. Finally, the small cracks merge progressively until they span the whole sample.

  12. Biodegradation reduces magnetization in oil bearing rocks: magnetization results of a combined chemical and magnetic study

    NASA Astrophysics Data System (ADS)

    Emmerton, S.; Muxworthy, A. R.; Sephton, M. A.; Williams, W.

    2012-12-01

    A relationship between hydrocarbons and their magnetic signatures has been alluded to for decades but this is the first study to combine geochemical and magnetic data. We report an extended study that identifies a definitive connection between magnetic mineralogy and biodegradation within oil-bearing rocks. Samples from Colombia, Canada Indonesia and the UK were collected and magnetically characterized. A negative linear regression in log space between magnetic susceptibility and the percentage of extractable organic matter was observed for individual reservoirs. To determine if this relationship is due to the activity of bacteria or migration of the oil, the percentage of oil components; aliphatic, aromatics, polars and resins and the biodegradation state of the samples were compared to the magnetic susceptibility and magnetic mineralogy of the samples. Geochemical biomarker data revealed that all oil samples were derived from mature type-II kerogen, which was deposited in oxygen-poor environments allowing for an investigation into biodegradation variations. Biodegradation is the decrease of oil quality through the conversion of aliphatic hydrocarbons to polar constituents mainly through the activity of bacteria. A distinct decrease in magnetic susceptibility was correlated to decreasing oil quality (loss of aliphatic hydrocarbons, more biodegraded), which cannot be rejected at 99% confidence. Further magnetic characterization revealed that the high quality, low biodegradation oils from Colombia have a higher magnetic susceptibility (10-3-10-4 m3kg-1) and are dominated by pseudo-single domain grains of magnetite. The lower quality oils i.e., the UK, Canadian and Indonesian samples, displayed decreased magnetic susceptibility (10-5-10-6 m3kg-1) and pseudo-single domain to multidomain grains of magnetite and hematite. Magnetite and pyrrhotite framboidal material were found in all but the Canadian samples. Therefore, with decreasing oil quality there is a progressive

  13. Major element variation and possible source materials of apollo 12 crystalline rocks.

    PubMed

    Kushiro, I; Haramura, H

    1971-03-26

    Nine different crystalline rocks of the Apollo 12 samples have been analyzed with conventional chemical rock analysis methods. Five of the rocks have normative quartz, whereas the others have normative olivine and hypersthene. The rocks show a wide range in the ratio of iron to magnesium, and their compositions fall on relatively smooth curves in the oxide variation diagram. It is suggested that these rocks, with one exception, represent different parts of a differentiated magmatic body, in which magmatic differentiation by crystallization and settling of olivine was most effective. The source material of the original magma may be peridotite with or without minor amounts of plagioclase or spinel or garnet, with the presence or absence of these minerals dependent on the depth of magma generation. PMID:17742570

  14. Influence of different laser operation regimes on the specific energy required for rock removal in oil and gas well drilling applications

    NASA Astrophysics Data System (ADS)

    Albert, Florian; Grimm, Alexander; Schmidt, Michael; Cournoyer, Alain; Briand, Martin; Galarneau, Pierre

    2009-06-01

    Although many practical hurdles remain to be addressed in the future, laser oil and gas well drilling has potential advantages over the conventional rotary drilling approach, such as a smaller footprint of the drilling rig, higher rates of penetration, reduction of downtime due to dull bits, reduction of waste caused by drilling mud, creation of a natural casing while drilling, and ability to drill in hard rock formations. One of the most promising applications is downhole laser perforation for well completion as an alternative to explosive technologies currently in use. In order to establish both the technical and economic feasibility of using lasers in oil and gas drilling operations, one can measure the laser energy required to remove a unit volume of rock. The resulting specific energy is a measure of the efficiency of the laser drilling process and depends on the rock type and the laser operation regime that determines the laser-rock interaction mechanism. In the present feasibility study, we compare the results of laser drilling tests conducted in two types of reservoir rocks, namely limestone and sandstone, at different laser wavelengths and for different laser operation regimes (continuous wave and pulsed regimes, different repetition rates and duty cycles) in terms of specific energy. We also discuss preliminary results on the influence of the temporal shape of the laser pulses in the nanosecond regime on the rock removal process as obtained with INO pulse-shaping fiber laser platform, with the objective to take advantage of the flexibility and the agility of such a laser source for drilling operations in different rock types.

  15. A mathematical model of microbial enhanced oil recovery (MEOR) method for mixed type rock

    SciTech Connect

    Sitnikov, A.A.; Eremin, N.A.; Ibattulin, R.R.

    1994-12-31

    This paper deals with the microbial enhanced oil recovery method. It covers: (1) Mechanism of microbial influence on the reservoir was analyzed; (2) The main groups of metabolites affected by the hydrodynamic characteristics of the reservoir were determined; (3) The criterions of use of microbial influence method on the reservoir are defined. The mathematical model of microbial influence on the reservoir was made on this basis. The injection of molasse water solution with Clostridium bacterias into the mixed type of rock was used in this model. And the results of calculations were compared with experimental data.

  16. Levels of bioactive lipids in cooking oils: olive oil is the richest source of oleoyl serine

    PubMed Central

    Leishman, Emma

    2016-01-01

    Background Rates of osteoporosis are significantly lower in regions of the world where olive oil consumption is a dietary cornerstone. Olive oil may represent a source of oleoyl serine (OS), which showed efficacy in animal models of osteoporosis. Here, we tested the hypothesis that OS as well as structurally analogous N-acyl amide and 2-acyl glycerol lipids are present in the following cooking oils: olive, walnut, canola, high heat canola, peanut, safflower, sesame, toasted sesame, grape seed, and smart balance omega. Methods Methanolic lipid extracts from each of the cooking oils were partially purified on C-18 solid-phase extraction columns. Extracts were analyzed with high-performance liquid chromatography-tandem mass spectrometry, and 33 lipids were measured in each sample, including OS and bioactive analogs. Results Of the oils screened here, walnut oil had the highest number of lipids detected (22/33). Olive oil had the second highest number of lipids detected (20/33), whereas grape-seed and high-heat canola oil were tied for lowest number of detected lipids (6/33). OS was detected in 8 of the 10 oils tested and the levels were highest in olive oil, suggesting that there is something about the olive plant that enriches this lipid. Conclusions Cooking oils contain varying levels of bioactive lipids from the N-acyl amide and 2-acyl glycerol families. Olive oil is a dietary source of OS, which may contribute to lowered prevalence of osteoporosis in countries with high consumption of this oil. PMID:26565552

  17. Unconventional neutron sources for oil well logging

    NASA Astrophysics Data System (ADS)

    Frankle, C. M.; Dale, G. E.

    2013-09-01

    Americium-Beryllium (AmBe) radiological neutron sources have been widely used in the petroleum industry for well logging purposes. There is strong desire on the part of various governmental and regulatory bodies to find alternate sources due to the high activity and small size of AmBe sources. Other neutron sources are available, both radiological (252Cf) and electronic accelerator driven (D-D and D-T). All of these, however, have substantially different neutron energy spectra from AmBe and thus cause significantly different responses in well logging tools. We report on simulations performed using unconventional sources and techniques to attempt to better replicate the porosity and carbon/oxygen ratio responses a well logging tool would see from AmBe neutrons. The AmBe response of these two types of tools is compared to the response from 252Cf, D-D, D-T, filtered D-T, and T-T sources.

  18. Detailed Study of Seismic Wave Attenuation in Carbonate Rocks: Application on Abu Dhabi Oil Fields

    NASA Astrophysics Data System (ADS)

    Bouchaala, F.; Ali, M. Y.; Matsushima, J.

    2015-12-01

    Seismic wave attenuation is a promising attribute for the petroleum exploration, thanks to its high sensitivity to physical properties of subsurface. It can be used to enhance the seismic imaging and improve the geophysical interpretation which is crucial for reservoir characterization. However getting an accurate attenuation profile is not an easy task, this is due to complex mechanism of this parameter, although that many studies were carried out to understand it. The degree of difficulty increases for the media composed of carbonate rocks, known to be highly heterogeneous and with complex lithology. That is why few attenuation studies were done successfully in carbonate rocks. The main objectives of this study are, Getting an accurate and high resolution attenuation profiles from several oil fields. The resolution is very important target for us, because many reservoirs in Abu Dhabi oil fields are tight.Separation between different modes of wave attenuation (scattering and intrinsic attenuations).Correlation between the attenuation profiles and other logs (Porosity, resistivity, oil saturation…), in order to establish a relationship which can be used to detect the reservoir properties from the attenuation profiles.Comparison of attenuation estimated from VSP and sonic waveforms. Provide spatial distribution of attenuation in Abu Dhabi oil fields.To reach these objectives we implemented a robust processing flow and new methodology to estimate the attenuation from the downgoing waves of the compressional VSP data and waveforms acquired from several wells drilled in Abu Dhabi. The subsurface geology of this area is primarily composed of carbonate rocks and it is known to be highly fractured which complicates more the situation, then we separated successfully the intrinsic attenuation from the scattering. The results show that the scattering is significant and cannot be ignored. We found also a very interesting correlation between the attenuation profiles and the

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

    USGS Publications Warehouse

    Lewan, Michael D.; Birdwell, Justin E.

    2013-01-01

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

  20. Oil layer as source of hydrocarbon emissions in SI engines

    SciTech Connect

    Min, K.; Cheng, W.K.

    1998-07-01

    The role of lubrication oil film on the cylinder liner as a source of hydrocarbon emissions in spark-ignition engines is assessed. First, the source strength is examined via an analytical model of the gasoline vapor absorption/desorption process. The solution shows that depending on engine operating conditions, there are three regimes. The process could be (1) limited by the gas side diffusion process, (2) limited by the liquid phase diffusion process, with the absorbed fuel fully penetrating the oil layer thickness (thin oil film regime), and (3) again limited by the liquid phase diffusion process, but with the absorbed fuel penetration depth small compared to the oil layer thickness (thick oil film regime). In regime (1), the source strength (the integrated absorption or desorption flux over one cycle) is proportional to the inverse of the square root of the rpm, but independent of oil layer parameters. In regimes (2), the strength is proportional to the oil film thickness divided by the Henry`s constant. In regime (3), the strength is independent of the oil film thickness, but is proportional to the fuel penetration depth divided by the Henry`s constant. Then, the oxidation of the desorbed fuel (using iso-octane as fuel) is examined with a one-dimensional reaction/diffusion model. The novel feature of the model is that the desorbed fuel is being exposed to the piston crevice hydrocarbon, which is laid along the liner as the piston descends. At stoichiometric conditions, the oxidation of the crevice HC is reduced by the presence of the desorbed HC from the oil layer.

  1. Oil layer as source of hydrocarbon emissions in SI engine

    SciTech Connect

    Min, K.; Cheng, W.K.

    1996-12-31

    The role of lubrication oil film on the cylinder liner as a source of hydrogen emissions in spark ignition engines is assessed. First, the source strength is examined via an analytical model of the gasoline vapor absorption/desorption process. The solution shows that depending on engine operating conditions, there are three regimes. The process could be (i) limited by the gas side diffusion process; (ii) limited by the liquid phase diffusion process, with the absorbed fuel fully penetrating the oil layer thickness (thin oil film regime); and (iii) again limited by the liquid phase diffusion process, but with the absorbed fuel penetration depth small compared to the oil layer thickness (thick oil film regime). In regime (i), the source strength (the integrated absorption or desorption flux over one cycle) is proportional to the square root of the rpm but independent of oil layer parameters. In regime (ii), the strength is proportional to the oil film thickness divided by the Henry`s constant. In regime (iii), the strength is independent of the oil film thickness, but is proportional to the fuel penetration depth divided by the Henry`s constant. Then the oxidation of the desorbed fuel (using iso-octane as fuel) is examined with a one dimensional reaction/diffusion model. The novel feature of the model is that the desorbed fuel is being exposed to the piston crevice hydrogen which is laid along the liner as the piston descends. At stoichiometric condition, the oxidation of the crevice HC is reduced by the presence of the desorbed HC from the oil layer.

  2. Mesozoic hydrocarbon source rock studies of north Tarim, south Junggar, and Turpan basins, Xinjiang Uygur autonomous region, northwestern China

    SciTech Connect

    Hendrix, M.S.; Xiao, Z.; Liang, Y.; Graham, S.A.; Carroll, A.R.; Chu, J.; McKnight, C.

    1989-03-01

    Ongoing outcrop and accompanying pyrolysis studies of Mesozoic strata of the north Tarim, south Junggar, and Turpan retroarc foreland basins, northwestern China, have demonstrated the existence of potential oil-prone and gas-prone petroleum source rocks. Lithologies include Jurassic coals from all three basins and Triassic coals from Tarim. Jurassic coals collected from the Mesozoic depocenters of the Junggar and Tarim basins are oil prone, yielding S/sub 2//S/sub 2+3/ values that range from 0.80 to 0.99 and average 0.96, hydrogen index (HI) values that range from 117.9 to 213.4 and average 150.8, and oxygen index (OI) values that range from 1.1 to 31.6 and average 7.67. In contrast, Triassic coals of Tarim and Jurassic coals of Turpan contain more conventional type III gas-prone kerogens and yield S/sub 2//S/sub 2+3/ values ranging from 0.04 to 0.52 and averaging 0.22, HI values ranging from 3.2 to 130.2 with a mean of 33.6, and OI values ranging from 30.9 to 223.7 and averaging 115.9. Coals of all three basins are slightly immature to mature with respect to oil generation, as indicated by T/sub max/ values ranging from 425/degrees/ to 449/degrees/C (average = 343/degrees/C) and vitrinite reflectance values ranging from 0.51 to 0.64 (average = 0.57). Thus, given the widespread abundance and significant thicknesses of Mesozoic and especially Jurassic coals in all three basins, it is very likely that Mesozoic contributions to Xinjiang's oil and gas reserves are significant. This is particularly important in the north Tarim basin, where recent Chinese oil and gas discoveries have been made and the existence of significant pre-Mesozoic source beds remains unproven.

  3. Geochemical modelling of the principal source rocks of the Barinas and Maracaibo basins, western Venezuela

    SciTech Connect

    Tocco, R.; Gallango, O.; Parnaud, F.

    1996-08-01

    This study presents a geochemical modelling of the principal source rocks in the western Venezuelan Basins. The area covers more than 100,000 km{sup 2}, and includes Lake Maracaibo and Barinas Basins. The geochemical modelling recognizes three source rocks: (1) A principal, K3-K4-K5 Cretaceous sequences, represented by La Luna, Capacho and Navay formations, (2) a secondary, corresponding to the T4 Oligocene sequence, represent by the Carbonera Formation, and (3) an accessory source rock, K7-K8 Paleocene sequences, represented by the carbonaceous shales and coals of the Orocue Group and Marcelina Formation. Three periods of hydrocarbon expulsion were defined for La Luna Formation (Early Eocene-Late Eocene, Middle Miocene-Early Miocene and Early Miocene-Holocene) and a principal period of hydrocarbon expulsion for Orocue Group and Carbonera Formation (Plio-Pleistocene and Middle Miocene Plio-Pleistocene). The 90% of hydrocarbons generated correspond to the principal source rock La Luna Formation, and the 10% to Tertiary source rocks (Carbonera Formation and Orocue Group). Five petroleum systems were identified: Lake Maracaibo, southwest of the Lake Maracaibo Basin, the Lara nappes, the extensive basins of eastern Zulia and the Barinas subbasin.

  4. 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

  5. Palaeoenvironment and its control on the formation of Miocene marine source rocks in the Qiongdongnan Basin, northern South China Sea.

    PubMed

    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

  6. Evidence for Cambrian petroleum source rocks in the Rome trough of West Virginia and Kentucky, Appalachian basin: Chapter G.8 in Coal and petroleum resources in the Appalachian basin: distribution, geologic framework, and geochemical character

    USGS Publications Warehouse

    Ryder, Robert T.; Harris, David C.; Gerome, Paul; Hainsworth, Timothy J.; Burruss, Robert A.; Lillis, Paul G.; Jarvie, Daniel M.; Pawlewicz, Mark J.

    2014-01-01

    The bitumen extract from the Rogersville Shale compares very closely with oils or condensates from Cambrian reservoirs in the Carson Associates No. 1 Kazee well, Homer gas field, Elliott County, Ky.; the Inland No. 529 White well, Boyd County, Ky.; and the Miller No. 1 well, Wolfe County, Ky. These favorable oil-source rock correlations suggest a new petroleum system in the Appalachian basin that is characterized by a Conasauga Group source rock and Rome Formation and Conasauga Group reservoirs. This petroleum system probably extends along the Rome trough from eastern Kentucky to at least central West Virginia.

  7. Reasons for production decline in the diatomite, Belridge oil field: a rock mechanics view

    SciTech Connect

    Strickland, F.G.

    1985-03-01

    This paper summarizes research conducted on diatomite cores from the Belridge oil field in Kern County, CA. The study was undertaken to explain the rapid decline in oil production in diatomite wells by investigating three of six possible reasons. Characterization of the rock indicated that the rock was composed of principally amorphous opaline silica diatoms with only a trace of crystoballite quartz or chert quartz. Physical properties tests showed the diatomite to be of very low strength and plastic. It was established that longterm creep of diatomite into a propped fracture proceeds at a rate of approximately 1.5 microns/D (1.5 ..mu..m/d), a phenomenon that may contribute to rapid production declines. Also revealed was a matrix strength for the formation of about 1,325 psi (9136 kPa), a critical value to consider when depleting the reservoir. This also may help to explain the phase transformation to Opal CT around 2,000to 2,500-ft (610- to 762-m) depth.

  8. Combining molecular fingerprints with multidimensional scaling analyses to identify the source of spilled oil from highly similar suspected oils.

    PubMed

    Zhou, Peiyu; Chen, Changshu; Ye, Jianjun; Shen, Wenjie; Xiong, Xiaofei; Hu, Ping; Fang, Hongda; Huang, Chuguang; Sun, Yongge

    2015-04-15

    Oil fingerprints have been a powerful tool widely used for determining the source of spilled oil. In most cases, this tool works well. However, it is usually difficult to identify the source if the oil spill accident occurs during offshore petroleum exploration due to the highly similar physiochemical characteristics of suspected oils from the same drilling platform. In this report, a case study from the waters of the South China Sea is presented, and multidimensional scaling analysis (MDS) is introduced to demonstrate how oil fingerprints can be combined with mathematical methods to identify the source of spilled oil from highly similar suspected sources. The results suggest that the MDS calculation based on oil fingerprints and subsequently integrated with specific biomarkers in spilled oils is the most effective method with a great potential for determining the source in terms of highly similar suspected oils. PMID:25765488

  9. Loss of volatile hydrocarbons from an LNAPL oil source

    USGS Publications Warehouse

    Baedecker, M.J.; Eganhouse, R.P.; Bekins, B.A.; Delin, G.N.

    2011-01-01

    The light nonaqueous phase liquid (LNAPL) oil pool in an aquifer that resulted from a pipeline spill near Bemidji, Minnesota, was analyzed for volatile hydrocarbons (VHCs) to determine if the composition of the oil remains constant over time. Oil samples were obtained from wells at five locations in the oil pool in an anaerobic part of the glacial outwash aquifer. Samples covering a 21-year period were analyzed for 25 VHCs. Compared to the composition of oil from the pipeline source, VHCs identified in oil from wells sampled in 2008 were 13 to 64% depleted. The magnitude of loss for the VHCs analyzed was toluene ≫ o-xylene, benzene, C6 and C10–12n-alkanes > C7–C9n-alkanes > m-xylene, cyclohexane, and 1- and 2-methylnaphthalene > 1,2,4-trimethylbenzene and ethylbenzene. Other VHCs including p-xylene, 1,3,5- and 1,2,3-trimethylbenzenes, the tetramethylbenzenes, methyl- and ethyl-cyclohexane, and naphthalene were not depleted during the time of the study. Water–oil and air–water batch equilibration simulations indicate that volatilization and biodegradation is most important for the C6–C9n-alkanes and cyclohexanes; dissolution and biodegradation is important for most of the other hydrocarbons. Depletion of the hydrocarbons in the oil pool is controlled by: the lack of oxygen and nutrients, differing rates of recharge, and the spatial distribution of oil in the aquifer. The mass loss of these VHCs in the 5 wells is between 1.6 and 7.4% in 29 years or an average annual loss of 0.06–0.26%/year. The present study shows that the composition of LNAPL changes over time and that these changes are spatially variable. This highlights the importance of characterizing the temporal and spatial variabilities of the source term in solute-transport models.

  10. True in situ oil shale retorting experiment at Rock Springs site 12

    SciTech Connect

    Long, A. Jr.; Merriam, N.W.; Virgona, J.E.; Parrish, R.L.

    1980-05-01

    A true in situ oil shale fracturing and retorting experiment was conducted near Rock Springs, Wyoming in 1977, 1978, and 1979. A 20-foot (6.1 m) thick zone of oil shale located 200 feet (61 m) below surface was hydraulically and explosively fractured. The fractured oil shale was extensively evaluated using flow tests, TV logging, caliper logging, downhole flow logging, core samples, and tracer tests. Attempts to conduct true in situ retorting tests in portions of the pattern with less than 5 percent void space as measured by caliper logs and less than 1 percent active void space measured by tracer test were curtailed when air could not be injected at desired rates. It is thought the fractures plugged as a result of thermal swelling of the oil shale. Air was injected at programmed rates in an area with 10 percent void measured by caliper log and 1.4 pecent active void measured by tracer test. A burn front was propagated in a narrow path moving away from the location of the production well. The vertical sweep of the burn front was measured at less than 4 feet (1.3 m). The burn front could not be sustained beyond 10 days without use of supplemental fuel. The authors recommend a minimum of 5 percent well-distributed void for attempts to retort 20 gpt (81 L/m ton) oil shale in confined beds. A void space of 5 percent may be roughly equivalent to 5 to 10 percent measured by caliper log and 1.4 percent or more by tracer test.

  11. Investigation of conjugated soybean oil as drying oils and CLA sources

    Technology Transfer Automated Retrieval System (TEKTRAN)

    A promising pound-scale production method for the conjugation of soybean oil (SBO) using iodine under photochemical reaction conditions is reported. Variations in catalyst loading, SBO concentration, light source, free radical catalyst source, solvent, and temperature were studied. A quantitative ...

  12. Basin center - fractured source rock plays within tectonically segmented foreland (back-arc) basins: Targets for future exploration

    SciTech Connect

    Weimer, R.J.

    1994-09-01

    Production from fractured reservoirs has long been an industry target, but interest in this type play has increased recently because of new concepts and technology, especially horizontal drilling. Early petroleum exploration programs searched for fractured reservoirs from shale, tight sandstones, carbonates, or basement in anticlinal or fault traps, without particular attention to source rocks. Foreland basins are some of the best oil-generating basins in the world because of their rich source rocks. Examples are the Persian Gulf basin, the Alberta basin and Athabasca tar sands, and the eastern Venezuela basin and Orinoco tar sands. Examples of Cretaceous producers are the wrench-faulted La Paz-Mara anticlinal fields, Maracaibo basin, Venezuela; the active Austin Chalk play in an extensional area on the north flank of the Gulf of Mexico continental margin basin; and the Niobrara Chalk and Pierre Shale plays of the central Rocky Mountains, United States. These latter plays are characteristic of a foreland basin fragmented into intermontane basins by the Laramide orogeny. The Florence field, Colorado, discovered in 1862, and the Silo field, Wyoming, discovered in 1980, are used as models for current prospecting and will be described in detail. The technologies applied to fracture-source rock plays are refined surface and subsurface mapping from new log suites, including resistivity mapping; 3D-3C seismic, gravity, and aeromagnetic mapping; borehole path seismic mapping associated with horizontal drilling; fracture mapping with the Formation MicroScanner and other logging tools; measurements while drilling and other drilling and completion techniques; surface geochemistry to locate microseeps; and local and regional lineament discrimination.

  13. Diagenesis and primary migration in Upper Jurassic claystone source rocks in North Sea

    SciTech Connect

    Lindgreen, H.

    1985-04-01

    Carbonate bands are common in Central graben Kimmeridgian (Upper Jurassic) claystone that is mature for oil generation. X-ray diffraction, thermal analysis, Mossbauer spectroscopy, thin-section studies, scanning microscopy, and electron microprobe investigations showed that the bands are composed of claystone fragments, coarse grains of dolomite, quartz, and siderite, and diagenetic layer-silicates, all cemented to a certain degree by ankerite. The diagenetic layer-sillicates are kaolinite being neoformed into muscovite. In claystones adjacent to the carbonate bands, ankerite fills pores about 50 /sigma phi/m in diameter; however, claystone further away from the bands contains little ankerite. Gas adsorption with N/sub 2/, Kr, and H/sub 2/O together with microscopy showed porosity in the claystone is composed of a large amount of micropores and mesopores, possibly with inlet constrictions, and a few macropores with diameters of about 50 ..mu..m. In the carbonate bands, microporosity and mesoporosity are probably located in the claystone fragments, whereas several pores with diameters of about 50 ..mu..m are present in the carbonate matrix. The presence of claystone fragments, fluid release structures, and large amounts of diagenetic carbonates indicates that carbonate bands formed through fracturing, possibly as a result of overpressuring. Porosity parameters indicate that fluid transport occurred by diffusion in the claystone matrix to claystone macropores and further through macropores in the carbonate bands, out of the source rock. The diagenesis of carbonates and clay minerals in the carbonate bands and in the claystone points to two migration stages: an early migration of fresh, neutral fluids, and a later migration in connection with hydrocarbon migration of saline-alkaline fluids.

  14. Fluorescence analysis can identify movable oil in self-sourcing reservoirs

    SciTech Connect

    Calhoun, G.G.

    1995-06-05

    The recent surge of activity involving self-sourcing reservoirs and horizontal drilling recognizes a little tapped niche in the domestic energy mix. Such prolific pays as the Cretaceous Bakken and Austin Chalk have drawn research interest and large amounts of investment capital. Fluorescence analysis can discern movable oil--as opposed to exhausted source rock--in such reservoirs with an inexpensive test. Other potential targets are the Cretaceous Mesaverde in the Piceance basin, Devonian New Albany shale in Kentucky, Devonian Antrim shale in the Michigan basin, and the Cretaceous Niobrara, Mancos, and Pierre formations in Colorado and New Mexico. To insure success in this niche this key question must be answered positively: Is movable oil present in the reservoir? Even if tectonic studies verify a system of open fractures, sonic logs confirm overpressuring in the zone, and resistivity logs document the maturity of the source, the ultimate question remains: Is movable oil in the fractures available to flow to the borehole? The paper explains a technique that will answer these questions.

  15. Production of polyhydroxyalkanoates (PHAs) with canola oil as carbon source.

    PubMed

    López-Cuellar, M R; Alba-Flores, J; Rodríguez, J N Gracida; Pérez-Guevara, F

    2011-01-01

    Wautersia eutropha was able to synthesize medium chain length polyhydroxyalkanoates (PHAs) when canola oil was used as carbon source. W. eutropha was cultivated using fructose and ammonium sulphate as carbon and nitrogen sources, respectively, for growth and inoculum development. The experiments were done in a laboratory scale bioreactor in three stages. Initially, the biomass was adapted in a batch culture. Secondly, a fed-batch was used to increase the cell dry weight and PHA concentration to 4.36 g L(-1) and 0.36 g L(-1), respectively. Finally, after the addition of canola oil as carbon source a final concentration of 18.27 g L(-1) PHA was obtained after 40 h of fermentation. With canola oil as carbon source, the polymer content of the cell dry matter was 90%. The polymer was purified from dried cells and analyzed by FTIR, NMR and DSC using PHB as reference. The polymer produced by W. eutropha from canola oil had four carbon monomers in the structure of the PHA and identified by 1H and 13C NMR analysis as 3-hydroxybutyrate (3HB), 3-hydroxyvalerate (3HV), 3-hydroxyoctanoate (3HO), and 3-hydroxydodecanoate (3HDD). PMID:20933541

  16. Plant Oils as Potential Sources of Vitamin D.

    PubMed

    Baur, Anja C; Brandsch, Corinna; König, Bettina; Hirche, Frank; Stangl, Gabriele I

    2016-01-01

    To combat vitamin D insufficiency in a population, reliable diet sources of vitamin D are required. The recommendations to consume more oily fish and the use of UVB-treated yeast are already applied strategies to address vitamin D insufficiency. This study aimed to elucidate the suitability of plant oils as an alternative vitamin D source. Therefore, plant oils that are commonly used in human nutrition were first analyzed for their content of vitamin D precursors and metabolites. Second, selected oils were exposed to a short-term UVB irradiation to stimulate the synthesis of vitamin D. Finally, to elucidate the efficacy of plant-derived vitamin D to improve the vitamin D status, we fed UVB-exposed wheat germ oil (WGO) for 4 weeks to mice and compared them with mice that received non-exposed or vitamin D3 supplemented WGO. Sterol analysis revealed that the selected plant oils contained high amounts of not only ergosterol but also 7-dehydrocholesterol (7-DHC), with the highest concentrations found in WGO. Exposure to UVB irradiation resulted in a partial conversion of ergosterol and 7-DHC to vitamin D2 and D3 in these oils. Mice fed the UVB-exposed WGO were able to improve their vitamin D status as shown by the rise in the plasma concentration of 25-hydroxyvitamin D [25(OH)D] and the liver content of vitamin D compared with mice fed the non-exposed oil. However, the plasma concentration of 25(OH)D of mice fed the UVB-treated oil did not reach the values observed in the group fed the D3 supplemented oil. It was striking that the intake of the UVB-exposed oil resulted in distinct accumulation of vitamin D2 in the livers of these mice. In conclusion, plant oils, in particular WGO, contain considerable amounts of vitamin D precursors which can be converted to vitamin D via UVB exposure. However, the UVB-exposed WGO was less effective to improve the 25(OH)D plasma concentration than a supplementation with vitamin D3. PMID:27570765

  17. Plant Oils as Potential Sources of Vitamin D

    PubMed Central

    Baur, Anja C.; Brandsch, Corinna; König, Bettina; Hirche, Frank; Stangl, Gabriele I.

    2016-01-01

    To combat vitamin D insufficiency in a population, reliable diet sources of vitamin D are required. The recommendations to consume more oily fish and the use of UVB-treated yeast are already applied strategies to address vitamin D insufficiency. This study aimed to elucidate the suitability of plant oils as an alternative vitamin D source. Therefore, plant oils that are commonly used in human nutrition were first analyzed for their content of vitamin D precursors and metabolites. Second, selected oils were exposed to a short-term UVB irradiation to stimulate the synthesis of vitamin D. Finally, to elucidate the efficacy of plant-derived vitamin D to improve the vitamin D status, we fed UVB-exposed wheat germ oil (WGO) for 4 weeks to mice and compared them with mice that received non-exposed or vitamin D3 supplemented WGO. Sterol analysis revealed that the selected plant oils contained high amounts of not only ergosterol but also 7-dehydrocholesterol (7-DHC), with the highest concentrations found in WGO. Exposure to UVB irradiation resulted in a partial conversion of ergosterol and 7-DHC to vitamin D2 and D3 in these oils. Mice fed the UVB-exposed WGO were able to improve their vitamin D status as shown by the rise in the plasma concentration of 25-hydroxyvitamin D [25(OH)D] and the liver content of vitamin D compared with mice fed the non-exposed oil. However, the plasma concentration of 25(OH)D of mice fed the UVB-treated oil did not reach the values observed in the group fed the D3 supplemented oil. It was striking that the intake of the UVB-exposed oil resulted in distinct accumulation of vitamin D2 in the livers of these mice. In conclusion, plant oils, in particular WGO, contain considerable amounts of vitamin D precursors which can be converted to vitamin D via UVB exposure. However, the UVB-exposed WGO was less effective to improve the 25(OH)D plasma concentration than a supplementation with vitamin D3. PMID:27570765

  18. Source of Mesozoic intermediate-felsic igneous rocks in the North China craton: Granulite xenolith evidence

    NASA Astrophysics Data System (ADS)

    Jiang, Neng; Carlson, Richard W.; Guo, Jinhui

    2011-07-01

    Four intermediate to felsic igneous rocks from the Zhangjiakou region, along the northern margin of the North China craton, have magmatic zircon U-Pb ages from 122 to 144 Ma. Two of these samples have inherited zircon U-Pb ages of ~ 2.5 Ga, similar to the zircon ages of rocks from the surrounding granulite terrain. Zircons from two intermediate composition granulite xenoliths (JN0811 and JN0919) in the nearby Cenozoic Hannuoba basalts yield two groups of ages. The rims have concordant Mesozoic ages mostly between 120 and 145 Ma, coeval with the Mesozoic intermediate-felsic magmatism in the region, while the cores have discordant U-Pb ages with upper-intercepts of ~ 2.5 Ga, overlapping the zircon ages of granulite terrain rocks, and lower-intercept ages of ~ 130 Ma, approximating the ages of the Mesozoic intermediate-felsic magmatism. The Sr-Nd isotopic compositions of the Mesozoic intermediate-felsic igneous rocks are completely different from those expected for basaltic melts from either the lithospheric mantle or the asthenospheric mantle, precluding a derivation by extensive fractional crystallization of mantle-derived magmas. The lack of correlation between (86Sr/87Sr)i, εNd(t) and SiO2 for the Mesozoic igneous rocks, the very narrow range of zircon εHf(t) for individual intermediate-felsic igneous rocks, and simple binary mixing calculations argue against them being formed by mixing between mantle-derived magma and preexisting crust that has extremely evolved Sr-Nd isotopic compositions like granulite xenoliths JN0811 and JN0919. Hf isotopic compositions of the Mesozoic zircons and whole-rock geochemistry show that the granulite xenoliths with extremely evolved Sr-Nd isotopic compositions have not undergone partial melting during the Mesozoic and thus do not contribute to the Mesozoic intermediate-felsic magmas. Further comparisons show that the source rocks for the Mesozoic intermediate-felsic magmas likely were late Archean lower crustal rocks similar in

  19. Rock glaciers as a source of nitrate to alpine streams, Green Lakes Valley, Colorado, USA.

    NASA Astrophysics Data System (ADS)

    Knauf, M.; Williams, M. W.; Caine, N.

    2003-12-01

    An ongoing concern in alpine areas of the western United States is the high concentrations of nitrate in surface waters. A number of research scientists have shown that talus areas are one source of this elevated nitrate (Williams et al., 1997; Campbell et al., 2002). Here we evaluate the potential contribution of nitrate to surface waters from a previously overlooked source: rock glaciers. Water draining from the Green Lake 5 rock glacier in the Colorado Front Range has been sampled for nitrate and ammonium since 1998 as part of the Niwot Ridge LTER program. The mean concentration of nitrate in stream waters in the Green Lakes Valley is 16.12 ueq/L, and for talus streams is 20 ueq/L. In comparison, the stream draining the rock glacier has an average nitrate concentration of 54 ueq/L. Moreover, nitrate values from the stream draining the rock glacier peak in the late summer at over 100 ueq/L. The sources of these high nitrate values from the rock glacier are unknown at this time; we evaluate several hypotheses. Increased nitrate could be a result of dry deposition on the rock glacier that is flushed during snowmelt and rain events. Another hypothesis is that microbial processes within the rock glacier have contribute to higher nitrate concentrations. Here we evaluate the sources and fate of nitrate in waters draining the Green Lake 5 rock glacier in 2003 using a combination of stable (delta O18) and radiogenic (tritium) water isotopes, fractionation of dissolved organic matter, fluorescence index of dissolved organic matter, and mineralization experiments. These site-specific results are then placed in a regional context through a synoptic sampling of streams draining rock glaciers throughout the Rocky Mountain region. Works Cited Williams, M. W., T. Davinroy, and P. D. Brooks. 1997. Organic and inorganic nitrogen pools in talus soils and water, Green Lakes Valley, Colorado Front Range, Hydrologic Processes, 11(13): 1747-1760. Campbell, Donald H., Carol Kendall

  20. A plate tectonic-paleoceanographic hypothesis for Cretaceous source rocks and cherts of northern South America

    SciTech Connect

    Villamil, T.; Arango, C. )

    1996-01-01

    New paleocontinental reconstructions show a northern migration of the South American Plate with respect to the paleoequator from the Jurassic to the Late Cretaceous. This movement caused the northern margin of South America to migrate from a position south to a position north of the paleoequator. Ekman transport generated net surface water movement towards the south during times when northern South America was south of the paleoequator. This situation favored downwelling and prevented Jurassic and earliest Cretaceous marine source rocks from being deposited. When northern South America was north of the paleoequator Ekman transport forced net water movement to the north favoring upwelling, paleoproductivity, and the deposition of one of the best marine source rocks known (the La Luna, Villeta, and equivalents). This plate tectonic paleoceanographic hypothesis explains the origin of hydrocarbons in northern South America. The stratigraphic record reflects this increase in paleoproductivity through time. This can be observed in facies (non-calcareous shales to calcareous shales to siliceous shales and finally to bedded cherts) and in changing planktic communities which were initially dominated by healthy calcareous foraminifer assemblages, followed by stressed foraminifer populations and finally by radiolarians. Total organic carbon and source rock quality were affected by this long term increase in paleoproductivity but also, and more markedly, by a punctuated sequence stratigraphic record dominated by low- frequency changes in relative sea level. The magnitude of transgressive episodes caused by rise in sea level determined the extent of source rock intervals and indirectly the content of organic carbon.

  1. A plate tectonic-paleoceanographic hypothesis for Cretaceous source rocks and cherts of northern South America

    SciTech Connect

    Villamil, T.; Arango, C.

    1996-12-31

    New paleocontinental reconstructions show a northern migration of the South American Plate with respect to the paleoequator from the Jurassic to the Late Cretaceous. This movement caused the northern margin of South America to migrate from a position south to a position north of the paleoequator. Ekman transport generated net surface water movement towards the south during times when northern South America was south of the paleoequator. This situation favored downwelling and prevented Jurassic and earliest Cretaceous marine source rocks from being deposited. When northern South America was north of the paleoequator Ekman transport forced net water movement to the north favoring upwelling, paleoproductivity, and the deposition of one of the best marine source rocks known (the La Luna, Villeta, and equivalents). This plate tectonic paleoceanographic hypothesis explains the origin of hydrocarbons in northern South America. The stratigraphic record reflects this increase in paleoproductivity through time. This can be observed in facies (non-calcareous shales to calcareous shales to siliceous shales and finally to bedded cherts) and in changing planktic communities which were initially dominated by healthy calcareous foraminifer assemblages, followed by stressed foraminifer populations and finally by radiolarians. Total organic carbon and source rock quality were affected by this long term increase in paleoproductivity but also, and more markedly, by a punctuated sequence stratigraphic record dominated by low- frequency changes in relative sea level. The magnitude of transgressive episodes caused by rise in sea level determined the extent of source rock intervals and indirectly the content of organic carbon.

  2. Source-rock evaluation of outcrop samples from Vanuatu (Malakula, Espiritu Santo, Maewo, and Pentecost)

    USGS Publications Warehouse

    Buchbinder, Binyamin; Halley, Robert B.

    1988-01-01

    The samples collected for the present study represent only a portion of the sedimentary column in the various sedimentary basins of Vanuatu.  The characterize only the outer margins of the sedimentary basins and do not necessarily reflect the source-rock potential of the deeper (offshore) parts of the basins.

  3. Petroleum source rock potential of Mesozoic condensed section deposits in southwestern Alabama

    SciTech Connect

    Mancini, E.A; Tew, B.H.; Mink, R.M. )

    1991-03-01

    Because condensed section deposits in carbonates and siliclastics are generally fine-grained lithologies often containing relatively high concentrations of organic matter, these sediments have the potential to be petroleum source rocks if buried under conditions favorable for hydrocarbon generation. In the Mesozoic deposits of southwestern Alabama, only the Upper Jurassic Smackover carbonate mudstones of the condensed section of the LZAGC-4.1 cycle have realized their potential as hydrocarbon source rocks. These carbonate mudstones contain organic carbon concentrations of algal and amorphous kerogen of up to 1.7% and have thermal alteration indices of 2- to 3+. The Upper Cretaceous Tuscaloosa marine claystones of the condensed section of the UZAGC-2.5 cycle are rich (up to 2.9%) in herbaceous and amorphous organic matter but have not been subjected to burial conditions favorable for hydrocarbon generation. The Jurassic Pine Hill/Norphlet black shales of the condensed section of the LZAGC-3.1 cycle and the Upper Jurassic Haynesville carbonate mudstones of the condensed section of the LZAGC-4.2 cycle are low (0.1%) in organic carbon. Although condensed sections within depositional sequences should have the highest source rock potential, specific environmental, preservational, and/or burial history conditions within a particular basin will dictate whether or not the potential is realized as evidenced by the condensed sections of the Mesozoic depositional sequences in southwestern Alabama. Therefore, petroleum geologists can use sequence stratigraphy to identify potential source rocks; however, only through geochemical analyses can the quality of these potential source rocks be determined.

  4. Water rock interaction during the process of steam stimulation exploitation of viscous crude oil in Liaohe Shuguang Oil Field, Liaoning, China

    NASA Astrophysics Data System (ADS)

    Hui, Qian; Zhenghua, Yang; Yunfeng, Li; Wancai, Xu; Yaqiao, Sun

    2006-05-01

    In the process of steam stimulation exploitation of viscous crude oil, the injected water, at high temperature and under high pressure, reacts intensively with the host rock. This kind of water rock interaction in Liaohe Shuguang Oil Field was studied on the basis of analysis of water composition changes, laboratory experiments, mineral saturation indices analysis, and mass balance calculation. Compared with the injected water, the changes of the composition of discharged water are mainly the distinct decrease of pH, Na+, SiO2 and Cl-, as well as the increase of K+, Ca2+, Mg2+, SO{4/2-} and HCO{3/-}. Laboratory experiments under field conditions showed: the dissolution sequence of minerals quantitatively is quartz>potassium feldspar>albite, and the main change of clay minerals is the conversion of kaolinite to analcime. Mass balance calculation indicated during the process of steam stimulation, large quantities of analcime are precipitated with the dissolution of large amounts of quartz, kaolinite, potassium feldspar, and CO2. These results correlated very well with the experimental results. The calculated results of Liaohe Shuguang Oil Field showed that during the steam stimulation for viscous crude oil, the amounts of minerals dissolved (precipitated) are huge. To control the clogging of pore spaces of oil reservoirs, increased study of water rock interaction is needed.

  5. Estimation of Physical Property Changes by Oil Saturation in Carbonates and Sandstone Using Computational Rock Physics Methods

    NASA Astrophysics Data System (ADS)

    Lee, M.; Keehm, Y.

    2010-12-01

    Carbonate Reservoirs are drawing a great attention as global energy demands and consumption increase rapidly, since more than 60% of oil and 40% of gas of world reserves are in carbonate rocks. However, most of them are hard to develop mainly due to their complexity and heterogeneity, especially at the pore scale. In this study, we perform computational rock physics modeling (numerical simulations on pore microstructures of carbonate rocks) and compare the results with those from sandstone. The brief procedure of the method is (1) to obtain high-resolution pore microstructure with a spatial resolution of 1-2 micron by X-ray microtomography technique, (2) to perform two-phase lattice-Boltzmann (LB) flow simulation to obtain various oil and water saturations, then (3) to calculate physical properties, such as P-wave velocity and electrical conductivity through pore-scale property simulation techniques. For the carbonate rock, we identified much more isolated pores than sandstone by investigating pore microstructures. Thus permeability and electrical conductivity were much smaller than those of sandstone. The electrical conductivity versus oil saturation curve of the carbonate rock showed sharper decrease at low oil saturation, but similar slope at higher oil saturation. We think that higher complexity of pore connectivity is responsible for this effect. The P-wave velocity of the carbonate rock was much higher than sandstone and the it did not show any significant changes during the change of oil saturation. Therefore, we think that fluid discrimination by seismic data with P-wave velocity alone would pose a greate challenge in most carbonate reservoirs. In addition, the S-wave velocity seems not to be sensitive either, which suggest that the AVO-type analysis would also be difficult, though requires more researches. On the other hand, our computational rock physics approach can be useful in preliminary analysis of carbonate reservoirs since it can determine the

  6. An analytical scheme for determining forms of sulphur in oil shales and associated rocks

    USGS Publications Warehouse

    Tuttle, M.L.; Goldhaber, M.B.; Williamson, D.L.

    1986-01-01

    An analytical scheme for determining various forms of sulphur in oil shales and associated rocks is presented. Acid-soluble sulphate, sulphur contained in monosulphide and in disulphide minerals, and organically-bound sulphur are all quantitatively recovered as separate fractions. Finely-ground oil-shale samples are treated in an inert atmosphere with 6M hydrochloric acid to dissolve the acid-soluble sulphate minerals and form H2S from the decomposition of monosulphide minerals. The acid-soluble sulphate is precipitated as barium sulphate and the H2S is collected and weighed as silver sulphide. Disulphide minerals in the solid residue from the acid treatment are reduced by an acidified Cr(II) solution in an inert atmosphere, releasing the sulphide as H2S. The H2S is collected as silver sulphide. An Eschka fusion oxidizes and solubilizes all sulphur remaining within the Cr(II)-treated residue. This sulphate represents organically-bound sulphur and is collected as barium sulphate. The analytical procedures have been verified by using 57Fe Mo??ssbauer spectroscopy. Good agreement between the chemical and Mo??ssbauer data substantiated the sequential removal of the forms of sulphur and also demonstrated the ability of Mo??ssbauer spectroscopy to determine the absolute quantities of iron present in specific minerals. ?? 1986.

  7. Source terrains and diagenetic imprints of Cretaceous marine rocks of the Cordillera Oriental, Colombia

    SciTech Connect

    Segall, M.P.; Allen, R.B. ); Rubiano, J.; Sarmiento, L. )

    1993-02-01

    Cretaceous marine rocks of the western Cordillera Oriental of Colombia are exposed in stratigraphic sections which reveal multiple source terrains and variable diagenetic histories that were imposed by later thrusting XRD and petrographic analyses indicate that earliest Cretaceous rocks were derived from a nearly plutonic source (Triassic-Jurassic Ibague Batholith of the Cordillera Central) which provided feldspathic lithic fragments and clay-sized illite. High smectite concentrations in the overlying Hauterivian-Barremian strata reflect contemporaneous volcanism, possibly in the Cordillera Central. This signal decreased upsection to the upper Aptian, where detrital clays (kaolinite, chlorite, feldspar, amphibole) indicate a shift to a cratonic source, probably the Guayana Shield. Cratonic detrital input continues into the Turonian-Coniacian and is accompanies by high concentrations of smectite representing another period of volcanic activity. Later tectonic activity divided the area into two regions, each with unique diagenetic signatures. Three primary clastic sources are inferred for the section east of the thrust belt, however, the mineral assemblage is masked by later diagenesis. Sediments within the thrust belt show greater variability in the relative abundance of mineral assemblages and more poorly crystallized illite than occurs to the east of the thrust section. The preservation of much of the original mineralogic components within the thrust section indicates that these sediments have experienced only limited diagenetic overprinting as a result of a relatively short burial history. These contrasting signatures have important implications for hydrocarbon maturation within Cretaceous source rocks in a structurally complex region.

  8. Trace metal mobilization from oil sands froth treatment thickened tailings exhibiting acid rock drainage.

    PubMed

    Kuznetsova, Alsu; Kuznetsov, Petr; Foght, Julia M; Siddique, Tariq

    2016-11-15

    Froth treatment thickened tailings (TT) are a waste product of bitumen extraction from surface-mined oil sands ores. When incubated in a laboratory under simulated moist oxic environmental conditions for ~450d, two different types of TT (TT1 and TT2) exhibited the potential to generate acid rock drainage (ARD) by producing acid leachate after 250 and 50d, respectively. We report here the release of toxic metals from TT via ARD, which could pose an environmental threat if oil sands TT deposits are not properly managed. Trace metal concentrations in leachate samples collected periodically revealed that Mn and Sr were released immediately even before the onset of ARD. Spikes in Co and Ni concentrations were observed both pre-ARD and during active ARD, particularly in TT1. For most elements measured (Fe, Cr, V, As, Cu, Pb, Zn, Cd, and Se), leaching was associated with ARD production. Though equivalent acidification (pH2) was achieved in leachate from both TT types, greater metal release was observed from TT2 where concentrations reached 10,000ppb for Ni, 5000ppb for Co, 3000ppb for As, 2000ppb for V, and 1000ppb for Cr. Generally, metal concentrations decreased in leachate with time during ARD and became negligible by the end of incubation (~450d) despite appreciable metals remaining in the leached TT. These results suggest that using TT for land reclamation purposes or surface deposition for volume reduction may unfavorably impact the environment, and warrants application of appropriate strategies for management of pyrite-enriched oil sands tailings streams. PMID:27443453

  9. Leachate migration from an in-situ oil-shale retort near Rock Springs, Wyoming

    USGS Publications Warehouse

    Glover, Kent C.

    1988-01-01

    Hydrogeologic factors influencing leachate movement from an in-situ oil-shale retort near Rock Springs, Wyoming, were investigated through models of ground-water flow and solute transport. Leachate, indicated by the conservative ion thiocyanate, has been observed ? mile downgradient from the retort. The contaminated aquifer is part of the Green River Formation and consists of thin, permeable layers of tuff and sandstone interbedded with oil shale. Most solute migration has occurred in an 8-foot sandstone at the top of the aquifer. Ground-water flow in the study area is complexly three dimensional and is characterized by large vertical variations in hydraulic head. The solute-transport model was used to predict the concentration of thiocyanate at a point where ground water discharges to the land surface. Leachate with peak concentrations of thiocyanate--45 milligrams per liter or approximately one-half the initial concentration of retort water--was estimated to reach the discharge area during January 1985. This report describes many of th3 advantages, as well as the problems, of site-specific studies. Data such as the distribution of thin, permeable beds or fractures might introduce an unmanageable degree of complexity to basin-wide studies but can be incorporated readily into site-specific models. Solute migration in the study area occurs primarily in thin, permeable beds rather than in oil-shale strata. Because of this behavior, leachate traveled far greater distances than might otherwise have been expected. The detail possible in site-specific models permits more accurate prediction of solute transport than is possible with basin-wide models. A major problem in site-specific studies is identifying model boundaries that permit the accurate estimation of aquifer properties. If the quantity of water flowing through a study area cannot be determined prior to modeling, the hydraulic conductivity and ground-water velocity will be poorly estimated.

  10. Leachate migration from an in situ oil-shale retort near Rock Springs, Wyoming

    USGS Publications Warehouse

    Glover, K.C.

    1986-01-01

    Geohydrologic factors influencing leachate movement from an in situ oil shale retort near Rock Springs, Wyoming, were investigated by developing models of groundwater flow and solute transport. Leachate, indicated by the conservative ion thiocyanate, has been observed 1/2 mi downgradient from the retort. The contaminated aquifer is part of the Green River Formation and consists of thin, permeable layers of tuff and sandstone interbedded with oil shale. Most solute migration has occurred in an 8-ft sandstone at the top of the aquifer. Groundwater flow in the study area is complexly 3-D and is characterized by large vertical variations in hydraulic head. The solute transport model was used to predict the concentration of thiocyanate at a point where groundwater discharges to the land surface. Leachates with peak concentrations of thiocyanate--45 mg/L or approximately one-half the initial concentration of retort water--were estimated to reach the discharge area during January 1985. Advantages as well as the problems of site specific studies are described. Data such as the distribution of thin permeable beds or fractures may introduce an unmanageable degree of complexity to basin-wide studies but can be incorporated readily in site specific models. Solute migration in the study area primarily occurs in thin permeable beds rather than in oil shale strata. Because of this behavior, leachate traveled far greater distances than might otherwise have been expected. The detail possible in site specific models permits more accurate prediction of solute transport than is possible with basin-wide models. A major problem in site specific studies is identifying model boundaries that permit the accurate estimation of aquifer properties. If the quantity of water flowing through a study area cannot be determined prior to modeling, the hydraulic conductivity and groundwater velocity will be estimated poorly. (Author 's abstract)

  11. 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

    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

  12. 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.

  13. Pore-space alteration in source rock (shales) during hydrocarbons generation: laboratory experiment

    NASA Astrophysics Data System (ADS)

    Giliazetdinova, D. R.; Korost, D. V.; Nadezhkin, D. V.

    2013-12-01

    Hydrocarbons (HC) are generated from solid organic matter (kerogen) due to thermocatalytic reactions. The rate of such reactions shows direct correlation with temperature and depends on the depth of source rock burial. Burial of sedimentary rock is also inevitably accompanied by its structural alteration owing to compaction, dehydration and re-crystallization. Processes of HC generation, primary migration and structural changes are inaccessible for direct observation in nature, but they can be studied in laboratory experiments. Experiment was carried out with a clayey-carbonate rock sample of the Domanik Horizon taken from boreholes drilled in the northeastern part of the south Tatar arch. The rock chosen fits the very essential requirements - high organic matter content and its low metamorphic grade. Our work aimed at laboratory modeling of HC generation in an undisturbed rock sample by its heating in nitrogen atmosphere based on a specified temperature regime and monitoring alterations in the pore space structure. Observations were carried out with a SkyScan-1172 X-ray microtomography scanner (resulting scan resolution of 1 μm). A cylinder, 44 mm in diameter, was prepared from the rock sample for the pyrolitic and microtomographic analyses. Scanning procedures were carried out in 5 runs. Temperature interval for each run had to match the most important stage of HC generation in the source rock, namely: (1) original structure; (2) 100-300°C - discharge of free and adsorbed HC and water; (3) 300-400°C - initial stage of HC formation owing to high-temperature pyrolysis of the solid organic matter and discharge of the chemically bound water; (4) 400-470°C - temperature interval fitting the most intense stage of HC formation; (5) 470-510°C - final stage of HC formation. Maximum sample heating in the experiment was determined as temperature of the onset of active decomposition of carbonates, i.e., in essence, irreversible metamorphism of the rock. Additional

  14. 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.

    2016-01-01

    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.

  15. Quantifying Sources of Methane in the Alberta Oil Sands

    NASA Astrophysics Data System (ADS)

    Baray, S.; Darlington, A. L.; Gordon, M.; Hayden, K.; Li, S. M.; Mittermeier, R. L.; O'brien, J.; Staebler, R. M.; McLaren, R.

    2015-12-01

    In the summer of 2013, an aircraft measurement campaign led by Environment Canada with participation from university researchers took place to investigate the sources and transformations of gas pollutants in the Alberta oil sands region close to Fort McMurray, Alberta. Apart from its ability to change the radiative forcing of the atmosphere, methane is also a significant precursor to the formation of formaldehyde, an important radical source. Thus, emissions of methane from facilities need to be understood since they can have air quality implications through alteration of the radical budget and hence, the oxidation capacity of the air mass. Methane was measured, along with other gases, via a cavity ring-down spectroscopy instrument installed on the Convair-580 aircraft. In total, there were 22 flights with 82 hours of measurements in the vicinity of oil sands facilities between August 13 and September 7, 2013. Various tools have been used to visualize the spatial and temporal variation in mixing ratios of methane and other trace gases in order to identify possible sources of methane. Enhancements of methane from background levels of 1.9 ppm up to ~4 ppm were observed close to energy mining facilities in the oil sands region. Sources of methane identified include open pit mining, tailings ponds, upgrader stacks and in-situ mining operations. Quantification of the emission rates of methane from distinct sources has been accomplished from box flights and downwind screen flights by identifying the ratios of trace gases emitted and through use of the Top-down Emission Rate Retrieval Algorithm (TERRA). Methane emission rates for some of these sources will be presented.

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

    SciTech Connect

    Moretti, I.; Montemurro, G.; Aguilera, E.; Perez, M.; Martinez, E.Diaz

    1996-08-01

    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 mg 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.

  17. Evaluating Local Elastic Anisotropy of Rocks and Sediments by Means of Optoacoustics While Drilling Oil and Gas Boreholes

    NASA Astrophysics Data System (ADS)

    Gladilin, A. V.; Egerev, S. V.; Ovchinnikov, O. B.

    2014-12-01

    The optoacoustic method is used to evaluate local elastic anisotropy of rocks and sediments. The method is based on laser sound generation by irradiating a spot on the wall of the oil or gas borehole. The optoacoustic method offers an advantage of precise non-contact placing of a short-pulse point sound source. Pulses of a compression wave, shear waves, and a surface wave are induced in the formation as a result of optoacoustic conversion. The surface trace of the bulk compression wave propagating along the borehole surface has a velocity corresponding to that of a bulk wave. Hence, measurements of the trace propagation time along several predetermined paths on the surface of a borehole provide evaluation of local elastic anisotropy in situ. The pick-up is provided with a piezoelectric ceramic transducer positioned at a predetermined point on the surface of the borehole. The optoacoustic conversion regime parameters were chosen to provide separation of the trace pulse of another surface perturbance at the travel distance of about 0.1 m. The local measurements on the borehole wall are aimed to support accurate depth imaging of seismic data. Understanding these common anisotropy effects is important when interpreting seismic data where they are present.

  18. The identification of possible hydrocarbon source rocks, using biomarker geochemistry, in the Taranaki basin, New Zealand

    NASA Astrophysics Data System (ADS)

    Collier, R. J.; Johnston, J. H.

    The sterane and triterpane biomarkers extracted from shales penetrated by the Maui-1, -2 and -3 wells show that even the deepest shales, near basement, are considerably less mature than the condensate held in the reservoir above. This indicates the source of these hydrocarbons is much deeper, probably within the Taranaki graben. Coal and shale samples from the Maui-4 exploration well, drilled within the graben, are significantly more mature, but only the deepest samples approach the maturity of the Maui-4 oil and Maui condensate. The Kapuni field has comparable biomarker extracts to the Maui condensate and oils, but Kapuni-8 coals from similar depths to the Maui-4 coals are much less mature and thus cannot have sourced the Kapuni condensate. The deeper Toko-1 well which penetrates deeper and more mature coasl and shales indicates a probable source depth of 4400-4900 m for Kapuni condensate. The diterpanes from the Maui-4 and Toko-1 wells indicate a terrestrial source and suggest significant conifer contribution to coals and shales in these wells. The diterpanes extracted from the Maui-4 oil and those from Maui-4 coals and shales show many similar characteristics, but because they do not match completely, it is proposed that multiple sourcing is likely. The diterpanes from Toko-1 coals and shales are more varied and only one coal matches the Kapuni condensate; hence a very similar source is proposed for the Kapuni condensate.

  19. Organic facies and systems tracts: Implications for source rock preservation and prediction

    SciTech Connect

    Kosters, E.C.; Vanderzwaan, F.J.; Gijsbert, J. )

    1993-09-01

    Sequence stratigraphy is concerned with making predictions about reservoirs ahead of the drill, however, little attention has been paid to the configuration of organic-rich facies of source rock quality. We suggest that preservation of source rock type facies in clastic systems is mutually exclusive and time successive. The main database is a collection of cores and other samples through the Holocene Rhone delta. The early Holocene Transgressive Systems Tract (TST) contains five levels of channelization. The most significant peat bed is located immediately landward of the shoreline of maximum transgression (SMT). The Highstand Systems Tract (HST) consists of two parasequences, containing mostly laterally continuous strandplain complexes without peat. In addition to sufficient accommodation space, an important control on formation of fresh-water peats and organic-rich shelf muds is availability of river-induced nutrients. Peat quality, however, is best without riverine clastics. In a delta plain, a balance between these two controls may be reached when river-fed nutrients are trapped there indirectly. The potential for such a condition arises in a TST setting. On the shelf, eutrophication of marine habitats is also controlled by river-fed nutrients, but excess river clastics are detrimental to marine source rock quality. A balance between these two controls may be reached in HST settings where fine-grained riverine clastics are forced onto the shelf rather than in the delta plain. In this case, nutrient supply to the shelf results in large quantities of marine biomass. This biomass becomes sufficiently concentrated due to moderate fine-grained riverine sedimentation which guarantees burial and preservation. Thus, varying river-water and nutrient supply in TST and HST settings seems to control large-scale preservation patterns of both continental and marine organics. This hypothesis suggests further potential for using sequence stratigraphy for source rock occurrence.

  20. Effects of Host-rock Fracturing on Deflation-related Volcano Deformation Sources

    NASA Astrophysics Data System (ADS)

    Holohan, Eoghan; Sudhaus, Henriette; Schöpfer, Martin; Walter, Thomas; Walsh, John

    2015-04-01

    Insights into the plumbing systems of active volcanoes are commonly gained by using continuum-based elastic modeling to resolve sources of volcano deformation. The geometries and depths of such deformation sources are commonly equated with those of volcano plumbing system elements, such as sills, dykes or magma chambers. We here examine how fracturing of the host rock - i.e. discontinuous inelastic deformation - may affect deformation source geometry and depth. We use two-dimensional Distinct Element Method (DEM) models to explicitly simulate fracture nucleation and development around a deflating magma body, and we then 'blindly' run the DEM model surface displacements through a typical elastic modelling scheme. The results show that host-rock fracturing may induce an asymmetric surface displacement profile that gives rise to an inclined deformation source geometry, even if the original magma body itself was not inclined. In addition, upward propagation of deformation toward the surface can, under certain conditions, cause a related upward movement of the deformation source. Consequently, the true magma body depth may be increasingly underestimated. These results may help explain upward migration and shape change in volcano deformation sources, as for example inferred for the March-April 2007 activity at Piton de la Fournaise volcano, La Reunion.

  1. Marine source rock prediction using a GCM - A look at the Paleozoic

    SciTech Connect

    Robinson, V.D.; Katz, B.J.; Kilgore, L.S. )

    1990-05-01

    Numerous investigators have examined the potential use of numeric climate models and paleogeographic reconstructions to predict the deposition and preservation of organic-rich sediments, which may ultimately develop into hydrocarbon source rocks. These studies have concentrated on the Mesozoic and Cenozoic eras. Although geologic conditions during these periods were different than that of today, they do have many similarities. In contrast, the boundary conditions associated with the Paleozoic are dramatically different. For example, no significant land plant cover is assumed in pre-Devonian simulations. In addition, for many of the simulations the bulk of the land mass was situated in the southern hemisphere at high latitudes. This compares with the Mesozoic and Cenozoic distributions that exhibit nearly coequal land-sea distributions in the two hemispheres. An examination of the results of paleoclimate simulations for time slices in the Paleozoic reveal significant changes in spatial distribution of marine conditions that would favor high levels of organic productivity and organic preservation through time. The authors study of the stratigraphic record, though incomplete, has revealed a favorable correlation between organic-rich black shales, capable of acting as hydrocarbon source rocks, and those regions that had both high preservation efficiencies and elevated levels of organic productivity. These results suggest that numeric climate models can be effectively used to predict source rock distribution throughout the Phanerozoic.

  2. Central graben (Norway) - Hydrocarbon distribution related to source rock maturation and pressure regimes

    SciTech Connect

    Chiarelli, A.; Issard, F. )

    1990-05-01

    This study of the Central graben was limited to the north by 57{degree}25'N, to the west by 4{degree}30', and to the east and south by the borders of the United Kingdom and Denmark, respectively. Several fields have been discovered within the Upper Cretaceous, Paleocene, and Jurassic strata for which the source rocks are Jurassic age. The amount and types of hydrocarbons generated from the source rocks have been estimated by accounting for their thickness, their initial potential, and their degree of maturation. The possibilities for hydrocarbon migration have been interpreted through an integration of the structural history and the hydrodynamic framework within the Central graben region. The hydrodynamic framework which appears to be a very important parameter in the study area, has been reconstructed from pressure measurements in the reservoirs, compaction profiles, and numerical modeling. It appears that vertical migration from the Jurassic source rocks toward the Upper Cretaceous and Paleocene reservoirs was mainly dependent on tectonics, salt diapirism and geopressuring. In the Central graben region the understanding of areal distribution and nature of hydrocarbons formed has been greatly improved by the integration of geochemistry and hydrodynamics. This conclusion could be extended to many other sedimentary basins in the world.

  3. Characterization and evolution of Paleozoic source rock organic matter in Algerian Central Sahara

    SciTech Connect

    Takherist, D.; Arezki, A.; Mouaici, R.

    1995-08-01

    The objective of the proposed poster is to provide a knowledge of the evolution history of organic matter in an intracratonic basin. The Paleozoic source rocks (Ordovician - Silurian - Upper Devonian and Carboniferous) of the Algerian Central Sahara (Ahnet and Timimoun basins) experienced severe conditions of maturation during the geological history, therefore, the source rocks intervals are presently mature to overmature and only dry gas has been descovered throughout this zone. The several geochemical models (Genex, Basimod, Matoil) in addition to Afta and Zafta Data show that regionaly significant heating event occured with maximum palaeo-temperature and maximum gas generation at 300 +/- 30 My. However, high palaeotemperatures can not be explained only by the significant burial. An important anomalous heat flow is needed to explain the geothermal history. In this case, there has been no significant petroleum from the Paleozoic source rocks in this zone since this age; but following some assumptions, a certain hypothesis about a recent generation (-60 to -30 My) is now in discussion.

  4. Structural factors affecting pore space transformation during hydrocarbon generation in source rock (shales): laboratory experiments and X-ray microtomography/SEM study

    NASA Astrophysics Data System (ADS)

    Giliazetdinova, Dina; Korost, Dmitry; Gerke, Kirill

    2015-04-01

    Oil and gas generation is a complex superposition of processes which take place in the interiors and are not readily observable in nature in human life time-frames. During burial of the source rocks organic matter is transformed into a mixture of high-molecular compounds - precursors of oil and gas (kerogen). Specific thermobaric conditions trigger formation of low molecular weight hydrocarbon compounds. Generation of sufficient quantities of hydrocarbons leads to the primary fluid migration. For series of our experiments we selected mainly siliceous-carbonate composition shale rocks from Domanic horizon of South-Tatar arch. Rock samples were heated in the pyrolyzer to temperatures closely corresponding to different catagenesis stages. X-ray microtomography method was used to monitor changes in the morphology of the pore space within studied shale rocks. By routine measurements we made sure that all samples (10 in total) had similar composition of organic and mineral phases. All samples in the collection were grouped according to initial structure and amount of organics and processed separately to: 1) study the influence of organic matter content on the changing morphology of the rock under thermal effects; 2) study the effect of initial structure on the primary migration processes for samples with similar organic matter content. An additional experiment was conducted to study the dynamics of changes in the structure of the pore space and prove the validity of our approach. At each stage of heating the morphology of altered rocks was characterized by formation of new pores and channels connecting primary voids. However, it was noted that the samples with a relatively low content of the organic matter had less changes in pore space morphology, in contrast to rocks with a high organic content. Second part of the study also revealed significant differences in resulting pore structures depending on initial structure of the unaltered rocks and connectivity of original

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

    NASA Astrophysics Data System (ADS)

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

    2016-06-01

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

  6. Coalbed gases and hydrocarbon source rock potential of upper Carboniferous coal-bearing strata in upper Silesian Coal Basin, Poland

    SciTech Connect

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

    1996-01-01

    The Upper Silesian Coal Basin (USCB) is one of the major Upper Carboniferous coal basins in the world. Its coalbed gas reserves to the depths of 1,000 m are estimated to be about 350 billion cubic meters (about 12.4 TCF). Coalbed gases in the USCB are variable in both molecular and stable isotope composition [[delta][sup 13]C(CH[sub 4]), [delta]D(CH[sub 4]), [delta][sup 13]C(C[sub 2]H[sub 6]), [delta][sup 13]C(C[sub 3]H[sub 8]), [delta][sup 13]C(CO[sub 2])]. Such variability suggests the effects of both primary reactions operating during the generation of gases and secondary processes such as mixing and migration. Coalbed gases are mostly thermogenic methane in which depth-related isotopic fractionation has resulted from migration but not from mixing with the microbial one. The stable carbon isotope composition indicates that the carbon dioxide, ethane and higher gaseous hydrocarbons were generated during the bituminous coal stage of the coalification process. The main stage of coalbed gas generation occurred during the Variscan orogeny, and generation was completed after the Leonian and Asturian phases of this orogeny. The coals and carbonaceous shales have high gas generation potential but low potential for generation and expulsion of oil compared to the known Type III source rocks elsewhere. In general, the carbonaceous shales have slightly higher potential for oil generation, but probably would not be able to exceed expulsion thresholds necessary to expel economic quantities of oil.

  7. Coalbed gases and hydrocarbon source rock potential of upper Carboniferous coal-bearing strata in upper Silesian Coal Basin, Poland

    SciTech Connect

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

    1996-12-31

    The Upper Silesian Coal Basin (USCB) is one of the major Upper Carboniferous coal basins in the world. Its coalbed gas reserves to the depths of 1,000 m are estimated to be about 350 billion cubic meters (about 12.4 TCF). Coalbed gases in the USCB are variable in both molecular and stable isotope composition [{delta}{sup 13}C(CH{sub 4}), {delta}D(CH{sub 4}), {delta}{sup 13}C(C{sub 2}H{sub 6}), {delta}{sup 13}C(C{sub 3}H{sub 8}), {delta}{sup 13}C(CO{sub 2})]. Such variability suggests the effects of both primary reactions operating during the generation of gases and secondary processes such as mixing and migration. Coalbed gases are mostly thermogenic methane in which depth-related isotopic fractionation has resulted from migration but not from mixing with the microbial one. The stable carbon isotope composition indicates that the carbon dioxide, ethane and higher gaseous hydrocarbons were generated during the bituminous coal stage of the coalification process. The main stage of coalbed gas generation occurred during the Variscan orogeny, and generation was completed after the Leonian and Asturian phases of this orogeny. The coals and carbonaceous shales have high gas generation potential but low potential for generation and expulsion of oil compared to the known Type III source rocks elsewhere. In general, the carbonaceous shales have slightly higher potential for oil generation, but probably would not be able to exceed expulsion thresholds necessary to expel economic quantities of oil.

  8. A plan for hydrologic investigations of in situ, oil-shale retorting near Rock Springs, Wyoming

    USGS Publications Warehouse

    Glover, Kent C.; Zimmerman, E.A.; Larson, L.R.; Wallace, J.C.

    1982-01-01

    The recovery of shale oil by the in-situ retort process may cause hydrologic impacts, the most significant being ground-water contamination and possible transport of contaminants into surrounding areas. Although these impacts are site-specific, many of the techniques used to investigate each retort operation commonly will be the same. The U.S. Geological Survey has begun a study of hydrologic impacts in the area of an in-situ retort near Rock Springs, Wyoming, as a means of refining and demonstrating these techniques. Geological investigations include determining the areal extent and thickness of aquifers. Emphasis will be placed on determining lithologic variations from geophysical logging. Hydrologic investigations include mapping of potentiometric surfaces, determining rates of ground-water discharge, and estimating aquifer properties by analytical techniques. Water-quality investigations include monitoring solute migration from the retort site and evaluating sampling techniques by standard statistical procedures. A ground-water-flow and solute-transport model will be developed to predict future movement of the water plume away from the retort. (USGS)

  9. Characterization of French Coriander Oil as Source of Petroselinic Acid.

    PubMed

    Uitterhaegen, Evelien; Sampaio, Klicia A; Delbeke, Elisabeth I P; De Greyt, Wim; Cerny, Muriel; Evon, Philippe; Merah, Othmane; Talou, Thierry; Stevens, Christian V

    2016-01-01

    Coriander vegetable oil was extracted from fruits of French origin in a 23% yield. The oil was of good quality, with a low amount of free fatty acids (1.8%) and a concurrently high amount of triacylglycerols (98%). It is a rich source of petroselinic acid (C18:1n-12), an important renewable building block, making up 73% of all fatty acids, with also significant amounts of linoleic acid (14%), oleic acid (6%), and palmitic acid (3%). The oil was characterized by a high unsaponifiable fraction, comprising a substantial amount of phytosterols (6.70 g/kg). The main sterol markers were β-sitosterol (35% of total sterols), stigmasterol (24%), and Δ⁷-stigmastenol (18%). Squalene was detected at an amount of 0.2 g/kg. A considerable amount of tocols were identified (500 mg/kg) and consisted mainly of tocotrienols, with γ-tocotrienol as the major compound. The phospholipid content was low at 0.3%, of which the main phospholipid classes were phosphatidic acid (33%), phosphatidylcholine (25%), phosphatidylinositol (17%), and phosphatidylethanolamine (17%). About 50% of all phospholipids were non-hydratable. The β-carotene content was low at 10 mg/kg, while a significant amount of chlorophyll was detected at about 11 mg/kg. An iron content of 1.4 mg/kg was determined through element analysis of the vegetable oil. The influence of fruit origin on the vegetable oil composition was shown to be very important, particularly in terms of the phospholipids, sterols, and tocols composition. PMID:27617992

  10. Assessment of Research Needs for Oil Recovery from Heavy-Oil Sources and Tar Sands (FERWG-IIIA)

    SciTech Connect

    Penner, S.S.

    1982-03-01

    The Fossil Energy Research Working Group (FERWG), at the request of J.W. Mares (Assistant Secretary for Fossil Energy) and A.W. Trivelpiece (Director, Office of Energy Research), has reviewed and evaluated the U.S. programs on oil recovery from heavy oil sources and tar sands. These studies were performed in order to provide an independent assessment of research areas that affect the prospects for oil recovery from these sources. This report summarizes the findings and research recommendations of FERWG.

  11. Soils, slopes and source rocks: Application of a soil chemistry model to nutrient delivery to rift lakes

    NASA Astrophysics Data System (ADS)

    Harris, Nicholas B.; Tucker, Gregory E.

    2015-06-01

    rift. These simulations demonstrate that evolving topography during rift development can significantly influence nutrient concentrations in groundwater and, if these nutrients flow into rift lakes and stimulate organic productivity, account for the deposition of rich oil-prone source rocks in late rift stages.

  12. Selection of Bacteria with Favorable Transport Properties Through Porous Rock for the Application of Microbial-Enhanced Oil Recovery

    PubMed Central

    Jang, Long-Kuan; Chang, Philip W.; Findley, John E.; Yen, Teh Fu

    1983-01-01

    This paper presents a bench-scale study on the transport in highly permeable porous rock of three bacterial species—Bacillus subtilis, Pseudomonas putida, and Clostridium acetobutylicum—potentially applicable in microbial-enhanced oil recovery processes. The transport of cells during the injection of bacterial suspension and nutrient medium was simulated by a deep bed filtration model. Deep bed filtration coefficients and the maximum capacity of cells in porous rock were measured. Low to intermediate (∼106/ml) injection concentrations of cellular suspensions are recommended because plugging of inlet surface is less likely to occur. In addition to their resistance to adverse environments, spores of clostridia are strongly recommended for use in microbial-enhanced oil recovery processes since they are easiest among the species tested to push through porous rock. After injection, further transport of bacteria during incubation can occur by growth and mobility through the stagnant nutrient medium which fills the porous rock. We have developed an apparatus to study the migration of bacteria through a Berea sandstone core containing nutrient medium. PMID:16346414

  13. Selection of bacteria with favorable transport properties through porous rock for the application of microbial-enhanced oil recovery.

    PubMed

    Jang, L K; Chang, P W; Findley, J E; Yen, T F

    1983-11-01

    This paper presents a bench-scale study on the transport in highly permeable porous rock of three bacterial species-Bacillus subtilis, Pseudomonas putida, and Clostridium acetobutylicum-potentially applicable in microbial-enhanced oil recovery processes. The transport of cells during the injection of bacterial suspension and nutrient medium was simulated by a deep bed filtration model. Deep bed filtration coefficients and the maximum capacity of cells in porous rock were measured. Low to intermediate ( approximately 10/ml) injection concentrations of cellular suspensions are recommended because plugging of inlet surface is less likely to occur. In addition to their resistance to adverse environments, spores of clostridia are strongly recommended for use in microbial-enhanced oil recovery processes since they are easiest among the species tested to push through porous rock. After injection, further transport of bacteria during incubation can occur by growth and mobility through the stagnant nutrient medium which fills the porous rock. We have developed an apparatus to study the migration of bacteria through a Berea sandstone core containing nutrient medium. PMID:16346414

  14. Well-log signatures of alluvial-lacustrine reservoirs and source rocks, Lagoa-Feia Formations, Lower Cretaceous, Campos Basin, offshore Brazil

    SciTech Connect

    Abrahao, D.; Warme, J.E.

    1988-01-01

    The Campos basin is situated in offshore southeastern Brazil. The Lagoa Feia is the basal formation in the stratigraphic sequence of the basin, and was deposited during rifting in an evolving complex of lakes of different sizes and chemical characteristics, overlying and closely associated with rift volcanism. The stratigraphic sequence is dominated by lacustrine limestones and shales (some of them organic-rich), and volcaniclastic conglomerates deposited on alluvial fans. The sequence is capped by marine evaporites. In the Lagoa Feia Formation, complex lithologies make reservoirs and source rocks unsuitable for conventional well-log interpretation. To solve this problem, cores were studied and the observed characteristics related to log responses. The results have been extended through the entire basin for other wells where those facies were not cored. The reservoir facies in the Lagoa Feia Formation are restricted to levels of pure pelecypod shells (''coquinas''). Resistivity, sonic, neutron, density, and gamma-ray logs were used in this work to show how petrophysical properties are derived for the unconventional reservoirs existing in this formation. The same suite of logs was used to develop methods to define geochemical characteristics where source rock data are sparse in the organic-rich lacustrine shales of the Lagoa Feia Formation. These shales are the main source rocks for all the oil discovered to date in the Campos basin.

  15. A review of applications of U-Th-Pb isotope systematics to investigations of uranium source rocks.

    USGS Publications Warehouse

    Stuckless, J.S.

    1987-01-01

    U, Th and Pb concentrations and the isotopic composition of Pb can be used to evaluate crystalline rocks as a source for U in sedimentary deposits. Under favourable geologic circumstances, the technique can yield information on both the timing and the amount of U released to the sedimentary environment. The technique is best suited to the study of Archean rocks that have high U/Pb, a known common Pb composition, and a simple two-stage history. Less ideal rock units can also be evaluated, but conclusions reached for rocks of Phanerozoic age or younger will generally be qualitative at best.-Author

  16. Rock Valley Source Physics Experiment Preparation: Earthquake Relocation and Attenuation Structure Characterization

    NASA Astrophysics Data System (ADS)

    Pyle, M. L.; Walter, W. R.; Myers, S.; Pasyanos, M. E.; Smith, K. D.

    2012-12-01

    The science of nuclear test monitoring relies on seismic methods to distinguish explosion from earthquakes sources. Unfortunately, the physics behind how an explosion generates seismic waves, particularly shear waves, remains incompletely understood. The Source Physics Experiments (SPE) are an ongoing series of chemical explosions designed to address this problem and advance explosion monitoring physics and associated simulation codes. The current series of explosions are located in the Climax Stock granite on the Nevada National Security Site (NNSS). A future candidate for the SPEs would allow us to make a direct comparison of earthquake and explosion sources by detonating an explosion at a well constrained earthquake hypocenter and recording the resulting signals from each source at common receivers. This possibility arises from an area of unusually shallow seismicity in the Rock Valley area of the southern NNSS. While most tectonic earthquakes occur at depths greater than 5 km, a sequence of unusually shallow earthquakes with depths of 1-2 km occurred in Rock Valley in May of 1993. The main shock had a magnitude of approximately 3.7 and 11 more events in the sequence had magnitudes over 2. The shallow depths of these events were well constrained by temporary stations deployed at the time by the University of Nevada-Reno (UNR). As part of a feasibility study for a future Rock Valley SPE, LLNL, UNR and NSTec are working to re-instrument and improve our understanding of the Rock Valley region. Rock Valley is a complex set of left oblique-slip segmented fault blocks; it is a regular source region for small magnitude shallow earthquakes. A dense seismic network was operated in the southern NNSS through the Yucca Mountain project (1992-2010). Although much of the older network has been removed, six new Rock Valley telemetered seismic stations located at both original 1993 sites and additional sites, have been installed and operating since early 2011. In order to

  17. Characterization of oil source strata organic matter of Jurassic age and its contribution to the formation of oil and gas deposits

    NASA Astrophysics Data System (ADS)

    Pronin, Nikita; Nosova, Fidania; Plotnikova, Irina

    2013-04-01

    Within the frames of this work we carried out comprehensive geochemical study of high-carbon rocks samples taken from the three segments of the Jurassic system - from the lower (Kotuhtinskaya suite), from the medium (Tyumenskaya suite) and from the upper (Vasyuganskaya, Georgievskaya and the Bazhenovskaya suites), all within the north-eastern part of the Surgut oil and gas region. Altogether we investigated 27 samples. The complex study of the organic matter (OM) of these strata included the following: chloroform extraction of bitumen, the determination of the group and element composition, gas chromatography (GC) and gas chromatomass-spectrometry (GC/MS). These methods allow giving high quality assessments of the potential oil and gas source strata and thus identifying the possible oil and gas generating strata among them, ie, those strata that could be involved in the formation of oil and gas within the area. As a result of this work we identified various biomarkers that allow characterizing each oil and gas source strata under the study in the open-cast of the Jurassic system: 1. Kotuhtinskaya Suite. The build-up of this suite took place in the coastal marine weakly reducing conditions. In their composition these deposits contain some highly transformed humus organic matter (gradation of catagenesis MK3). 2. Tyumenskaya Suite. Accumulation of OM in these deposits occured mainly in the coastal marine environment with the influx of a large number of terrestrial vegetation in the basin of deposition. As for the type of agents - it is a humus or sapropel-humus OM with a rich content of continental organics. Source type of this OM is mixed - bacterial and algal. OM of the rocks of Tyumenskaya suite is situated in the area of high maturity (stage of catagenesis at MK3 level). 3. Vasyuganskaya Suite. In this case the accumulation of OM occurred mainly in the laguna (lake-delta) weak-reduction close to oxidative conditions with the influx of bacterial matter and the

  18. Chemistry and mineralogy of natural bitumens and heavy oils and their reservoir rocks from the United States, Canada, Trinidad and Tobago, and Venezuela

    USGS Publications Warehouse

    Hosterman, John W.; Meyer, R.F.; Palmer, C.A.; Doughten, M.W.; Anders, D.E.

    1990-01-01

    Twenty-one samples from natural bitumen and heavy oil deposits in seven States of the United States and six samples from outside the United States form the basis of this initial study. This Circular gives the mineral content of the reservoir rock, the trace-element distribution in the reservoir rock and hydrocarbons, and the composition of the heavy oil and natural bitumen. The reservoir rock and sediment residues from California contain more trace-element maximum amounts than any of the other rock samples. These relatively high concentrations of trace elements may be due, in part, to the low quartz content of the rock and to the presence of heulandite, cristobalite, siderite, and pyrite. The reservoir rock and sediment residues from Oklahoma contain more minimum amounts of trace elements than any of the other rock samples. This pattern probably results from the large amount of quartz in four of the samples and a large amount of calcite in the other sample. The maximum and minimum amounts of trace elements in the bitumen and heavy oil do not correlate with those in the reservoir rocks. The bitumen from Utah contains the greatest number of trace-element maxima, whereas there is no trend in the trace-element minima in the bitumen and heavy oil.

  19. Oil sands thickened froth treatment tailings exhibit acid rock drainage potential during evaporative drying.

    PubMed

    Kuznetsov, Petr; Kuznetsova, Alsu; Foght, Julia M; Siddique, Tariq

    2015-02-01

    Bitumen extraction from oil sands ores after surface mining produces different tailings waste streams: 'froth treatment tailings' are enriched in pyrite relative to other streams. Tailings treatment can include addition of organic polymers to produce thickened tailings (TT). TT may be further de-watered by deposition into geotechnical cells for evaporative drying to increase shear strength prior to reclamation. To examine the acid rock drainage (ARD) potential of TT, we performed predictive analyses and laboratory experiments on material from field trials of two types of thickened froth treatment tailings (TT1 and TT2). Acid-base accounting (ABA) of initial samples showed that both TT1 and TT2 initially had net acid-producing potential, with ABA values of -141 and -230 t CaCO₃ equiv. 1000 t(-1) of TT, respectively. In long-term kinetic experiments, duplicate ~2-kg samples of TT were incubated in shallow trays and intermittently irrigated under air flow for 459 days to simulate evaporative field drying. Leachates collected from both TT samples initially had pH~6.8 that began decreasing after ~50 days (TT2) or ~250 days (TT1), stabilizing at pH~2. Correspondingly, the redox potential of leachates increased from 100-200 mV to 500-580 mV and electrical conductivity increased from 2-5 dS m(-1) to 26 dS m(-1), indicating dissolution of minerals during ARD. The rapid onset and prolonged ARD observed with TT2 is attributed to its greater pyrite (13.4%) and lower carbonate (1.4%) contents versus the slower onset of ARD in TT1 (initially 6.0% pyrite and 2.5% carbonates). 16S rRNA gene pyrosequencing analysis revealed rapid shift in microbial community when conditions became strongly acidic (pH~2) favoring the enrichment of Acidithiobacillus and Sulfobacillus bacteria in TT. This is the first report showing ARD potential of TT and the results have significant implications for effective management of pyrite-enriched oil sands tailings streams/deposits. PMID:25306090

  20. An innovative geostatistical approach to oil volumetric calculations: Rock Creek Field, West Virginia

    SciTech Connect

    McDowell, R.R.; Matchen, D.L.; Hohn, M.E.; Vargo, A.G. )

    1994-08-01

    Detailed analysis of production trends in heterogeneous reservoirs requires local estimates of production, original, oil in place (OOIP), and recovery efficiency. In older fields, calculating these values is hampered by incomplete well records, inconsistent reporting of production (well by well vs. lease by lease), unknown effective drainage radius, and poorly constrained completion interval. Accepted methods of estimation rely heavily on the use of average values for reservoir properties. The authors have developed the use of average values for calculating local and field-wide estimates, and have compared their results to published values. The study of the Lower Mississippian Big Injun sandstone reservoir in Rock Creek field, central West Virginia, used production data obtained from operators. Production for the first 10 yr was reconstructed, when necessary, by comparison to decline curves for 70 wells with complete production records. Similarly, curve fitting techniques were used to interpolate data for missing years. Cumulative production values for 667 producing wells were kriged over the extent of the field; the resulting grid was sampled to provide an estimate of cumulative production at each well location. Kriged estimates of pay thickness, porosity, and water saturation were used to calculate OOIP and recovery efficiency (cumulative production + OOIP), but not geographic distribution of these two parameters. An optimal radius of 270 ft gave recovery efficiencies ranging between 18.75% and 21.9%, comparing favorably with a published value of 22.3%. Summing the OOIP value for all producing wells in the field yields a value of 139.6 million bbl, significantly higher than the published value of 37.8 million bbl. The estimate reflects a more complete data set and revised values for reservoir parameters. Discussions with the principal operator in the field suggests that the higher figure is more correct.

  1. 70 million years of coastal upwelling in California; source rocks and paleoceanography

    SciTech Connect

    Fonseca, C.

    1996-12-31

    The Late Mesozoic-Cenozoic marine sequence of California displays a unique record of coastal upwelling and productivity in the form of distinctive diatomaceous and organic-rich deposits including the upper Cretaceous-lower Paleocene Moreno Formation, the Eocene Kreyenhagen Formation and the Miocene Monterey Formation. Unique sedimentological characteristics of these ancient upwelling systems include (a) Finely laminated biosiliceous-rich shales (>30% biogenic silica content), (b) Distinctive laminae composed by monospecific diatom resting spores, (c) Good source rock quality (>300 mg HC/mg org C), and (d) High accumulation rates in mid water anoxic conditions. Detailed study of individual laminae in sediments of these formations revealed concentration of monospecific diatom resting spores and an abundance of Stephanopyxis sp. and Coscinodiscus sp. Like Recent upwelling systems, preserved laminations of monospecific resting spores reflect strong seasonal upwelling that lead to high organic matter production and enhancement of anoxia. The presence of spores in the ancient and modern upwelling systems is evidence that diatoms have adapted and successfully competed in the highly productive California Margin since the Late Cretaceous. The Moreno, the Kreyenhagen and the Monterey Formation account for a significant portion of major petroleum source beds in California and contain an important record of coastal upwelling and paleoceanographic change in the northeastern Pacific Ocean over the past 70 million years. It is suggested that potential Late Maestrichtian source rocks could have been deposited along other favorable upwelling areas of the Eastern Pacific Rim.

  2. Compositions of biotite from granitoids of the Sierra Nevada batholith: constraints on magmatic source rocks

    SciTech Connect

    Ague, J.J.; Brimhall, G.H.

    1985-01-01

    Two compositional types of biotite from the Cretaceous Sierra Nevada batholith occur in a systematic regional pattern which reflects magmatic source material and correlates with tungsten mineralization. Biotite from each group may be characterized in terms of F/OH and Mg/Fe as follows. Type I biotites generally coexist with hornblende and magnetite + sphene. Type II biotites coexist with ilmenite +/- magnetite, but hornblende only occurs at contacts with Type I intrusives. Intrusives with Type IA biotite occur as a continuous belt along the entire western margin of the exposed batholith. Type IB biotite is found to the east of this belt, and Type IC biotite is confined to the eastern side of the Sierra. Type II biotite is present in the eastern and south-western portions of the Sierra, and sporadically in the metamorphic foothills belt. The two intrusive groups, here characterized by biotite compositions, correspond to two of the source rock and porphyry mineralization models of Burnham (1981). Type I rocks (Cu deposits) are derived from mafic amphiobolites whereas Type II (Sn-W deposits) form from relatively reduced muscovite-rich metasediments. The biotite compositions indicate that the majority of the batholith formed from amphibolite sources. Type II intrusives and W deposits occur in areas underlain by Precambrian crust as defined by radiogenic isotope studies.

  3. Evidence of oil and gas hydrates within planet Mars: early biogenic or thermogenic sources from the Martian soils and deeper sediments near the deltas

    NASA Astrophysics Data System (ADS)

    Mukhopadhyay, Prasanta K.

    2012-10-01

    The presence of water (in liquid form) within the gullies of the Newton Crater from Mars (near the equator), oil-like hydrocarbons on the surface, gas hydrates in the deeper zones on Mars, and a list of publications on the geochemistry and astrobiology of carbonaceous chondrites have indicated that these petroleum hydrocarbons are closely related to the complex biological species similar to our terrestrial environment. Recent evidence of the possible presence of bacterial globule associated with carbonate minerals in the geological history of Mars may have indicated the link between possible bacterial growth and generation of petroleum hydrocarbons on Mars. Recent evidence of the possible presence of bacterially derived source rocks (organic rich black carbonaceous rocks) and heat flow distribution within Eberswalde and Holden areas of Mars during the earlier Martian geological time (possibly within the first 2 Ga) may have been originated from both biogeneic and thermogenic oil and gas hydrates. The thermal evolution of this biological geopolymer (source rock) could be observed in our earlier findings within the carbonaceous chondrites which show three distinct thermal events. Based on the current knowledge gained from carbonaceous chondrites, deltas, and hydrocarbons present within Mars, the methane on Mars may have been derived from the following sources: (1) deeper gas hydrates; (b) from the cracking of oil to gas within deeper oil or gas bearing reservoirs from a higher reservoir temperature; and (c) the high temperature conversion of current bacterial bodies within the upper surface of Mars.

  4. Historic genetic analysis of oil generation using a model of uniform continuous subsidence of the oil-source layer

    SciTech Connect

    Lopatin, N.V.

    1980-02-01

    The geophysical position of the main zone of oil generation, using a model of uniform continuous subsidence of the oil-surface layer, is considered. The change in temperature, depth, and time at three levels of the main zone of petroleum generation and one level of the main zone of gas generation in association with the rate of subsidence of the oil-source layer and different geothermal gradients in the sedimentary basins has been analyzed. Other conditions being equal, the greater the rate of subsidence of the sedimentary basins, the earlier the main stage of oil generation begins under these more rigid thermobaric conditions. With equal rates of subsidence of the sedimentary basins, the greater the geothermal gradient, the greater the temperature and the lower the depth of the main zone of oil-generation levels; in this case, the oil-source layer appears earlier and the main source of petroleum generation passes more rapidly, and the thickness and temperature interval of the main zone of oil generation are increased. The space-time position of the main zone of oil generation model of uniform continuous subsidence has been compared with the present position and the paleo-reconstructions of the main source of oil generation in the various basins of the USSR, France, USA, Canada, Algeria, and West Germany.

  5. Geochemistry and argon thermochronology of the Variscan Sila Batholith, southern Italy: source rocks and magma evolution

    USGS Publications Warehouse

    Ayuso, R.A.; Messina, A.; de Vivo, B.; Russo, S.; Woodruff, L.G.; Sutter, J.F.; Belkin, H.E.

    1994-01-01

    The Sila batholith is the largest granitic massif in the Calabria-Peloritan Arc of southern Italy, consisting of syn to post-tectonic, calc-alkaline and metaluminous tonalite to granodiorite, and post-tectonic, peraluminous and strongly peraluminous, two-mica??cordierite??Al silicate granodiorite to leucomonzogranite. Mineral 40Ar/39Ar thermochronologic analyses document Variscan emplacement and cooling of the intrusives (293-289 Ma). SiO2 content in the granitic rocks ranges from ???57 to 77 wt%; cumulate gabbro enclaves have SiO2 as low as 42%. Variations in absolute abundances and ratios involving Hf, Ta, Th, Rb, and the REE, among others, identify genetically linked groups of granitic rocks in the batholith: (1) syn-tectonic biotite??amphibole-bearing tonalites to granodiorites, (2) post-tectonic two-mica??Al-silicate-bearing granodiorites to leucomonzogranites, and (3) post-tectonic biotite??hornblende tonalites to granodiorites. Chondrite-normalized REE patterns display variable values of Ce/Yb (up to ???300) and generally small negative Eu anomalies. Degree of REE fractionation depends on whether the intrusives are syn- or post-tectonic, and on their mineralogy. High and variable values of Rb/Y (0.40-4.5), Th/Sm (0.1-3.6), Th/Ta (0-70), Ba/Nb (1-150), and Ba/Ta (???50-2100), as well as low values of Nb/U (???2-28) and La/Th (???1-10) are consistent with a predominant and heterogeneous crustal contribution to the batholith. Whole rock ??18O ranges from ???+8.2 to +11.7???; the mafic cumulate enclaves have the lowest ??18O values and the two-mica granites have the highest values. ??18O values for biotite??honblende tonalitic and granodioritic rocks (9.1 to 10.8???) overlap the values of the mafic enclaves and two-mica granodiorites and leucogranites (10.7 to 11.7???). The initial Pb isotopic range of the granitic rocks (206Pb/204Pb ???18.17-18.45, 207Pb/204Pb ???15.58-15.77, 208Pb/204Pb ???38.20-38.76) also indicates the predominance of a crustal source

  6. A look at carbonate rocks

    SciTech Connect

    Bowsher, A.I. )

    1994-03-01

    Important ore deposits are found in carbonate rocks, and large volumes of oil and gas are also produced from carbonate rocks on a worldwide basis. Reservoir types and productive capability are most often related to rock type and the facies to which the rock belongs. Broad new understanding of carbonate rocks came with the publication of Classification of Carbonate Rocks-A Symposium (AAPG Memoir 1, 1962). The principal parameters of carbonate rocks are (1) chemical composition, (2) grade size, (3) sorting and packing, (4) identification of grains in the rock, (5) cement, (6) color, (7) alteration of recrystallization, and (8) porosity. Original porosity in carbonate rocks relates to kind and packing of original particles. Secondary porosity is reduced by infilling that usually relates to some particles, or is enhanced because some types of grains are dissolved. Carbonate sediments are organic detritus. The range of solubility of organic detritus is very large. Fossils present in the carbonates are clues as to the source of the detritus in the rock. Additional research is needed in faunal relations of facies and of rock types. Ore recovery, well completion, and EOR are more successful when the parameters of carbonate rocks are extensively studied. A simplified approach to carbonate description is discussed.

  7. Hydrocarbon prospectivity in the Hellenic trench system: organic geochemistry and source rock potential of upper Miocene-lower Pliocene successions in the eastern Crete Island, Greece

    NASA Astrophysics Data System (ADS)

    Zelilidis, A.; Tserolas, P.; Chamilaki, E.; Pasadakis, N.; Kostopoulou, S.; Maravelis, A. G.

    2015-12-01

    Results of the current and already published studies suggest that the Tortonian in age deposits could serve a major source rocks (for both oil and gas) beneath the Messinian evaporites in the Hellenic trench system. Additionally, the strong terrestrial input in Pliocene deposits could lead to the production of biogenic gas, similar to the Po basin in Adriatic Sea (Italy). In the current study, fourteen samples from late Miocene Faneromeni section and twelve samples from the early Pliocene Makrilia section in eastern Crete were collected in order to evaluate their hydrocarbon generation potential. For this purpose, Rock-Eval analysis and characterization of the organic matter were performed. The results document a clear distinction between the two sections. Faneromeni section contains organic matter of kerogen type III, whereas the Makrilia section contains organic matter of kerogen type IV. The HI/TOC plot diagram, in both sections, indicates poor oil generating potential, with the exception of several samples showing fair to good gas and oil potential. Although thermal maturities of the samples from the two successions are similar, according to the T max values, samples from Faneromeni succession exhibit higher hydrogen index values, indicating a better quality of organic matter in terms of hydrocarbon generation. Very low obtained concentrations of bitumen (mg/g of rock), as well as the predominance of NSO compounds, compared to the saturates and aromatics, indicate low maturation level. The n-alkanes profiles exhibit a bimodal distribution, indicating a mixed origin (marine and terrestrial) of the organic matter in both areas. Terrestrial organic matter input is more pronounced in Makrilia section. The analysis of saturated biomarkers indicates that Faneromeni deposits were accumulated under constant organic matter input in an environment influenced by cyclic changes (from marine to lagoon origin and vice versa). Faneromeni section corresponds to a restricted

  8. Thermochronology of lower Cretaceous source rocks in the Idaho-Wyoming thrust belt

    SciTech Connect

    Burtner, R.L.; Nigrini, A.; Donelick, R.A.

    1994-10-01

    Lower Cretaceous organic-rich source rocks that are thermally mature to postmature crop out on the Absaroka, Darby, and Prospect plates in linear belts that run parallel to the trace of the thrusts in the Idaho-Wyoming portion of the Idaho-Wyoming-Utah thrust belt. Although the common assumption is that burial by thrust plates and the synorogenic sediments derived from them have been responsible for thermal maturation of the organic-rich strata, commercial amounts of hydrocarbons have not been found in structural traps in this portion of the thrust belt. In a companion paper, Burtner and Nigrini demonstrated that gravity-driven fluid flow in the Idaho-Wyoming portion of the thrust belt was responsible for moving large amounts of heat from the depths of the Early Cretaceous foreland basin eastward toward the stable platform. In this paper we demonstrate, through the application of organic maturation indicators and a new refinement of the apatite fission track technique, that this process heated Lower Cretaceous organic-rich source rocks to temperatures sufficient to generate hydrocarbons. Hydrocarbon generation and migration occurred prior to the development of the thrusts that are often assumed to have played a major role in the generation and entrapment of hydrocarbons in this portion of the thrust belt.

  9. Wettability modification of rock cores by fluorinated copolymer emulsion for the enhancement of gas and oil recovery

    NASA Astrophysics Data System (ADS)

    Feng, Chunyan; Kong, Ying; Jiang, Guancheng; Yang, Jinrong; Pu, Chunsheng; Zhang, Yuzhong

    2012-07-01

    The fluorine-containing acrylate copolymer emulsion was prepared with butyl acrylate, methacrylic acid and 1H, 1H, 2H, 2H-perfluorooctyl acrylate as monomers. Moreover, the structure of the copolymer was verified by Fourier transform infrared (FTIR), nuclear magnetic resonance (1H NMR and 19F NMR) and X-ray photoelectron spectroscopy (XPS) analyses. The results showed that all the monomers had been copolymerized and the presence of fluorine moieties. The contact angle (CA) analyses, capillary rise and imbibition spontaneous tests were used to estimate the influence of the copolymer emulsion on the wettability of gas reservoirs. It was observed that the rock surface was of large contact angles of water, oilfield sewage, hexadecane and crude oil after treatment with the emulsion. The capillary rise results indicated that the contact angles of water/air and oil/air systems increased from 60° and 32° to 121° and 80°, respectively, due to the emulsion treatment. Similarly, because of wettability alteration by the fluoropolymer, the imbibition of water and oil in rock core decreased significantly. Experimental results demonstrated that the copolymer emulsion can alter the wettability of porous media from strong liquid-wetting to gas-wetting. This work provides a cost-effective method to prepare the fluoropolymer which can increase gas deliverability by altering the wettability of gas-condensate reservoirs and mitigating the water block effect.

  10. Searching for a Safe Source of Castor Oil Production through Metabolic Engineering

    Technology Transfer Automated Retrieval System (TEKTRAN)

    Castor oil contains 90% ricinoleate (12-hydroxy-oleate) which has numerous industrial uses. The production of castor oil is hampered by the presence of the toxin ricin and hyper-allergenic 2S albumins in its seed. We are developing a safe source of castor oil by two approaches: blocking gene expres...