Hydrocarbon Potential Of Basin Research Articles

Optical and geochemical assessment of petroleum source rock potential and palaeodepositional environments of Cretaceous mudstones, Koum Basin, North Cameroon

Limited organic matter (OM) characterisation studies on Cretaceous mudstone successions in the Koum Basin have resulted in a significant knowledge gap in the source rock potential; a petroleum system prerequisite. Field mapping and lithofacies analysis of outcrop sections point to fluvial channel and marginal to profundal lake deposits. Representative mudstone samples were evaluated using multiproxy organo-petrographic and bulk geochemical analyses to assess the kerogen type, thermal maturity, hydrocarbon generation potential, and deduce the paleodepositional environment. Results reveal that ∼90% of the samples are organic-lean and ∼10% organic-rich with TOC content of 2.81–6.91 wt%. Rock-Eval pyrolysis S2 yields of 14.50–54.18 mg HC/g rock and hydrogen index (HI) 784–846 mgHC/gTOC, suggest excellent potential for oil generation. High S1 values of 1.18–1.45 mg HC/g rock and low production indices (PI) of 0.02–0.03 indicate in situ generated free hydrocarbons. PI and Tmax of 438°C–443 °C, consistent with measured vitrinite reflectance (Ro% = 0.28–0.53%), Spore Colour Index (SCI = yellow to golden brown) and Thermal Alteration Index (TAI = 1.5 to 2.6) on the Chevron scale, portraying an immature to marginally mature OM. Oil-prone kerogen Type I-II dominates and to a lesser extent gas-prone Type III, derived from algal-terrestrial organic facies, typified by the predominance of amorphous OM 51.2%, liptinites 24.6%, vitrinite 16.4% and inertinite 7.8%. Based on lithofacies, and palynological evidence, a fluvio-lacustrine depositional setting with limited marine influence, under fluctuating warm humid to hot semi-arid paleoclimates, is inferred. A comparison with surrounding petroleum-producing basins further enhances the understanding of the Koum Basin's hydrocarbon potential within the West Central African rift system context.

A quantitative approach to regional screening of petroleum systems, Westralian Superbasin

The greater Westralian Superbasin comprises multiple petroleum systems ranging in age from the Early Paleozoic to the Paleogene (Bradshaw et al, 1994). A subset of these systems is typified by marine incursions with a deposition of liquids-prone source rocks. Variability in Westralian sediment fill and source rock stratigraphic position can be demonstrated on a continuous mega-regional 2D deep reflection seismic line that extends from Carnarvon through Browse and into the Bonaparte Basin. Beginning in 2013, BHP Billiton initiated a comprehensive regional study of the Westralian margin to better risk existing and new play fairways. From this work, a hydrocarbon systems analysis from the Dampier Sub-basin and its application for exploration as a regional analogue is described. From a compilation of both open-file and proprietary data, a subset of Dampier well penetrations was chosen, based on the quality of available source rock data. 1D models were constructed and thermally calibrated to BHP Billiton’s recent re-interpretation of the sub-regional crustal architecture. The ultimate expelled petroleum (UEP) was calculated at each well and then extrapolated regionally to determine the total basin hydrocarbon potential. Maturity of the source rock is described using the state of thermal stress (STS) parameter (Pepper and Corvi, 1995). Compared with more data- and labour-intensive 3D basin modelling, integration of 1D basin models, UEP and STS parameters allow for a rapid quantitative and regional-scale basin analysis. Using this workflow in data-constrained basins like the Dampier Sub-basin serves as an important analogue for assessing and risking petroleum systems in both of the established and frontier portions of the Australian margin.

ABSTRACT: The Peruvian Marañon Basin Hydrocarbon Potential. Petroleum Systems Evaluation Based on New Chronostratigraphy and Sourcing Framework

ABSTRACT: The Peruvian Marañon Basin Hydrocarbon Potential. Petroleum Systems Evaluation Based on New Chronostratigraphy and Sourcing Framework

Hydrocarbon Potential of Basins along Australia's Southern Margin

Seven discrete sedimentary basins are recognized along the southern margin of the Australian continent; namely, from east to west, the Gippsland, Bass, Sorell, Otway, Duntroon, Bight, and Bremer. All formed since the Late Jurassic in response to the separation of Australia and Antarctica, and to the opening of the Tasman Sea. Only the Gippsland basin, which has proved initial oil reserves exceeding 3.6 billion barrels, is a prolific oil province. The search for oil in the other basins has been virtually fruitless despite many similarities between these basins and the Gippsland in terms of stratigraphy and structural geology. Rift and drift components are discernible in the sedimentary successions of all basins but the precise tectonic controls on respective basin formation remain conjectural. The lack of drilling success in the Bremer, Bight, Duntroon, Otway, and Sorell basins has been attributed mainly to the paucity of mature, oil-prone source rocks. The common occurrence of stranded bitumens along the entire coastline, however, indicates oil generation. The Bass and Gippsland basins are both characterized by excellent oil-prone source rocks developed in Late Cretaceous to Early Tertiary sediments. Limited exploration success in the Bass basin is due to poorer reservoir development. The Gippsland basin ismore » at a mature stage of exploration whereas the other basins are moderately to very sparsely explored. Consequently, there is a comparable potential for undiscovered hydrocarbons in all basins. Success in the under-explored basins will come only to those prepared to challenge the perception of low prospectivity. Many play types remain to be tested by the drill.« less

Hydrocarbon Potential of an Alkaline Lake Basin

The Biyan basin is an oil-rich intermountain basin in the central part of China. It is a half graben with a marginal normal fault in the south and a slope in the north. The thickest Eogene reaches 7 km in the center of the depression. This basin became a typical alkaline lake with specific sedimentary sequences composed of oil shale, trona, dolomite, and dark mudstone during Early Tertiary because of dry climate and peripheral source areas rich in Na-containing minerals. The source rock is characterized by abundant organic matter with a mean TOC of 2.5% and kerogen of good quality with H/C 1.4-1.7, and IH up to 800 mg/g. The study of biomarkers reveals a low Pr/Ph ratio and an abundant gammacerane and {minus}carotane, thus indicating an environment of high salinity and reduction. All geochemical data demonstrate multiple provinces of primary organic matter, of which halophilous prokaryotic organisms are likely contributors. Crude oil in the Biyan oil field contains high wax and low sulfur. The low-mature oil is discovered in dolomite beds. The high hydrocarbon potential of this basin is due to particularly favorable conditions for preservation and transformation of organic matter and high subsidence rates.

Hydrocarbon Potential of Aleutian Basin, Bering Sea: ABSTRACT

The Aleutian basin is the deep-water (more than 3,000 m) basin that lies north of the Aleutian Islands adjacent to the Bering Sea continental shelf. The basin, about the size of Texas, is underlain by a flat-lying sequence of mostly Cenozoic sediment 2 to 9 km thick that rests on an igneous oceanic crustal section. Prior to 1974, marine investigations in the Aleutian basin were directed at understanding the basin's regional geologic and geophysical framework; more recent investigations by the U.S. Geological Survey have been aimed at assessing the basin's hydrocarbon potential. Preliminary results suggest that the four major requirements for hydrocarbon accumulations may be present--structural and stratigraphic traps, source rocks, reservoir beds, and an adequate thermal nd sedimentation history. The recent energy resource studies indicate that: (1) numerous structural features (gentle folds, diapirs, basement ridges) are present in the central and eastern parts of the basin; (2) acoustic features called VAMPs (velocity amptitude features) are common (over 350 identified) in the central basin; these features may be caused by pockets of gases and possibly other hydrocarbons that have been trapped in the sedimentary section; (3) the sedimentary section consists of diatomaceous sediment overlying indurated mudstones; high porosities (58 to 85%) and good permeabilities (10 to 35 md) in the diatomaceous sediment suggest that it is a potential reservoir unit and the thick section of underlying mudstone may contain the source beds; (4) concentrations of organic gases, primarily metha e, in the upper 1 to 3 m beneath the seafloor are very small, increase with depth, and are highest in areas near VAMPs; (5) the thermal gradient and the sediment thickness are sufficiently End_Page 439------------------------------ large to allow hydrocarbon maturation at depth, if suitable organic material is present. Our initial results suggest that the Aleutian basin deserves further exploration as a site for possible hydrocarbon accumulations. End_of_Article - Last_Page 440------------

Hydrocarbon Potential of Aleutian Basin, Bering Sea

The Aleutian basin is the deep-water (more than 3,000 m) basin that lies north of the Aleutian Islands adjacent to the Bering Sea continental shelf. The basin, about the size of Texas, is underlain by a flat-lying sequence of mostly Cenozoic sediment 2 to 9 km thick that rests on an igneous oceanic crustal section. Prior to 1974, marine investigations in the Aleutian basin were directed at understanding the basin's regional geologic and geophysical framework; more recent investigations by the U.S. Geological Survey have been aimed at assessing the basin's hydrocarbon potential. Preliminary results suggest that the four major requirements for hydrocarbon accumulations may be present--structural and stratigraphic traps, source rocks, reservoir beds, and an adequate thermal nd sedimentation history. The recent energy-resource studies indicate that: (1) numerous structural features (gentle folds, diapirs, basement ridges) are present in the central and eastern parts of the basin; (2) acoustic features called VAMPs (velocity amplitude features) are common (over 350 identified) in the central basin; these features may be caused by pockets of gases and possibly other hydrocarbons that have been trapped in the sedimentary section; (3) the sedimentary section consists of diatomaceous sediment overlying indurated mudstones; high porosities (58 to 85%) and good permeabilities (10 to 35 md) in the diatomaceous sediment suggest that it is a potential reservoir unit and the thick section of underlying mudstone may contain the source beds; (4) concentrations of organic gases, primarily metha e, in the upper 1 to 3 m beneath the seafloor are very small, increase with depth, and are highest in areas near VAMPs; (5) the thermal gradient and the sediment thickness are sufficiently large to allow hydrocarbon maturation at depth, if suitable organic material is present. Our initial results suggest that the Aleutian basin deserves further exploration as a site for possible hydrocarbon accumulations.

Hydrocarbon potential of marginal basins bounded by an island arc

The Japan Basin is an example of a western Pacific marginal basin that is bounded by an island arc. Such basins were produced by an extensional process that involves formation of new, hot sea floor below basins that are opening as newly created arc systems migrate away from the continental borderland or older arcs. Rapid deposition of sediment on the hot basin floors allows development of steep geothermal gradients in these sedimentary prisms. In these sedimentary basins, the relationship between temperature and strata age is such that the kerogen-hydrocarbon transformation occurs in young, shallow strata. The sealing effect of turbidite deposits and the presence of numerous gravity faults ensures entrapment conditions. Hydrocarbon potential of these basins can be evaluated by considering the age of basin opening, sedimentation rates adjusted for compaction, and heat-flow data.