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NARROW
GeoRef Subject
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all geography including DSDP/ODP Sites and Legs
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Africa
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Gabon
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Oklo (1)
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North Africa
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Primary terms
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Africa
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Tertiary
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Paleogene
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lower Paleocene
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Chordata
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polycyclic aromatic hydrocarbons
Esterification of naphthenic acids with various structures over tungstophosphoric acid-intercalated layer double hydroxide catalysts with various interlayer spacings
Geochemistry of the Organic Matter of Ulug-Khem Basin Coals
The Theory of Naphthidogenesis: A Quantitative Model of the Catagenetic Evolution of Aquatic Organic Matter
A comparison of three methods to assess natural source zone depletion at paved fuel retail sites
A New Indicator of the Maturity of Organic Matter from Domanik Deposits
Geochemistry of high-maturity crude oil and gas from deep reservoirs and their geological significance: A case study on Shuntuoguole low uplift, Tarim Basin, western China
Formation of bitumen in the Elgin–Franklin complex, Central Graben, North Sea: implications for hydrocarbon charging
Abstract The Elgin–Franklin complex contains gas condensates in Upper Jurassic reservoirs in the North Sea Central Graben. Upper parts of the reservoirs contain bitumens, which previous studies have suggested were formed by the thermal cracking of oil as the reservoirs experienced temperatures of >150°C during rapid Plio-Pleistocene subsidence. Bitumen-stained cores contaminated by oil-based drilling muds have been analysed by hydropyrolysis. Asphaltene-bound aliphatic hydrocarbon fractions were dominated by n -hexadecane and n -octadecane originating from fatty acid additives in the muds. Uncontaminated asphaltene-bound aromatic hydrocarbon fractions, however, contained a PAH distribution very similar to normal North Sea oils, suggesting that the bitumens may not have been derived from oil cracking. 1D basin models of well 29/5b-6 and a pseudo-well east of the Elgin–Franklin complex utilize a thermal history derived from the basin's rifting and subsidence histories, combined with the conservation of energy currently not contained in the thermal histories. Vitrinite reflectance values predicted by the conventional kinetic models do not match the measured data. Using the pressure-dependent PresRo ® model, however, a good match was achieved between observed and measured data. The predicted petroleum generation is combined with published diagenetic cement data from the Elgin and Franklin fields to produce a composite model for petroleum generation, diagenetic cement and bitumen formation.
Making oil from magma
Abstract Petroleum systems within rifted margin basins affected by volcanism continue to remain challenging for the exploration of hydrocarbons, most notably owing to the volume of intrusions that pose imaging, drilling and exploration problems. Typically, intrusions possess small thermal aureoles, but despite this, there is evidence that intrusions could none the less be responsible for the generation of commercial volumes of hydrocarbons. Here we shed new light on this petroleum systems challenge by integrating organic geochemical and Raman spectroscopic techniques to produce potential volumetric data for hydrocarbons generated as a result of igneous intrusion. The results indicate that, in areas with immature source rock intervals, it may be possible for intrusions to generate volumes of oil that would be capable of comfortably filling likely known oil reservoirs. This is a critical step forward in integrating several analytical techniques, indicating that under the right conditions there is the potential for hydrocarbon generation as a result of igneous intrusion.
The Effectiveness of Reactive Materials for Contaminant Removal in the Process of Coal Conversion
Current State of Deep Oil Seepage Near Cape Gorevoi Utes (Central Baikal)
Origin and migration of oil and natural gas in the central part of the Ukrainian outer Carpathians: Geochemical and geological approach
Geochemical characterization of the Upper Mississippian Goddard Formation, Noble Ranch Group, and related oils in the Anadarko Basin of Oklahoma
Oil families and inferred source rocks of the Woodford–Mississippian tight oil play in northcentral Oklahoma
Geochemical characteristics and resource potential analysis of Chang 7 organic-rich black shale in the Ordos Basin
Phenanthrene biomarkers in the organic matter of Precambrian and Phanerozoic deposits and in the oils of the Siberian Platform
Organic geochemistry of the Eagle Ford Group in Texas
ABSTRACT A migration geochemical study was conducted over an area of approximately 15,000 km 2 (5792 mi 2 ) in northeast Saudi Arabia to define regional migration patterns and de-risk oil charge away from the Late Jurassic source kitchen of the Gotnia Basin to prospects further to the south and west on the shelf margin and Summan Platform. Discovered accumulations range in depth from more than 10,000 ft (3048 m) subsea on the shelf margin in the north to around 5000 ft (1524 m) on the Summan Platform in the south. Shallowing south/southwestward is associated with a wide API gravity variation (15–35°) and gentler molecular and isotopic maturity trends. Defining migration patterns based on bulk, isotopic, and saturated and aromatic hydrocarbon distributions alone proved ineffective, especially given that all oils examined from the target Arab-A reservoir have a narrow peak-oil window maturity and a largely common source, that is sulfur-rich (up to 6.1 wt.%) anoxic marine carbonate, presumably within the Hanifa/Tuwaiq Mountain formations or their equivalent Najmah/Sargelu formations in the Gotnia Basin. Molecular geotracers, based primarily on compositional correlation coefficients of aromatic nitrogen compounds, identified several southwest-trending migration pathways that have charged traps in the Late Jurassic Arab Formation. Prospects falling along inferred migration pathways or entry/spill routes are therefore high-graded.