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Zhou, Zhicheng, Wenlong Ding, Ruifeng Zhang, Mingwang Xue, Baocheng Jiao, Chenlin Wu, Yuting Chen, Liang Qiu, Xiaoyu Du, and Tianshun Liu. "Structural styles and tectonic evolution of Mesozoic–Cenozoic faults in the Eastern Depression of Bayanhaote Basin, China: implications for petroleum traps." Geological Magazine 159, no. 5 (January 20, 2022): 689–706. http://dx.doi.org/10.1017/s0016756821001242.
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AbstractThe Eastern Depression in the Bayanhaote Basin in western Inner Mongolia has experienced multi-stage Meso-Cenozoic tectonic events and possesses considerable exploration potential. However, structural deformation patterns, sequences and the genesis of oil-bearing structures in the basin are still poorly understood. In this study, based on high-quality 2D seismic data and drilling and well-logging data, we elucidate the activities and structural styles of faults, the tectonic evolution and the distribution characteristics of styles, as well as assessing potential petroleum traps in the Eastern Depression. Five types of faults that were active at different stages of the Meso-Cenozoic faults have been recognized: long-lived normal faults active since the late Middle Jurassic; reverse faults and strike-slip faults active in the late Late Jurassic; normal faults active in the Early Cretaceous; normal faults active in the Oligocene; and negative inverted faults active in the Early Cretaceous and Oligocene. These faults constituted 12 geometric styles in NE-trending belts at various stratigraphic levels, and were formed by compression, strike-slip, extension and inversion. The temporal development of structural styles promoted the formation and reconstruction and finalization of structural traps, while regional unconformities and open reverse and strike-slip faults provided migration pathways for petroleum to fill the traps. In general, potential traps that formed by compressional movement and strike-slip movement in the late Late Jurassic are primarily faulted anticlines. Those traps developed in Carboniferous rocks and are located in the southwestern region of the Eastern Depression, being controlled by NNE-NE-striking reverse and transpressive faults.
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Lambiase, J. J. "Structural Traps VII. Treatise of petroleum geology, Atlas of Oil and Gas Fields." Marine and Petroleum Geology 11, no. 2 (April 1994): 247. http://dx.doi.org/10.1016/0264-8172(94)90100-7.
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Terken, Jos M. J. "The Natih Petroleum System of North Oman." GeoArabia 4, no. 2 (April 1, 1999): 157–80. http://dx.doi.org/10.2113/geoarabia0402157.
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ABSTRACT The Cretaceous Natih petroleum system is one of the smaller petroleum systems in Oman, measuring only some 20,000 square kilometers in areal extent. Resource volumes of oil initially in-place, however, are significant and amount to 1.3x109 cubic meters (equivalent to 8.2 billion barrels). Most of the recoverable oil is concentrated in two giant fields that were discovered in the early 1960s. Since that prolific time no new major discoveries have been made, except some marginally economic accumulations in the early 1980s. To evaluate the remaining hydrocarbon potential of the system, the oil kitchen was mapped and its generation and migration histories modeled and integrated with the regional setting to outline the geographical and stratigraphical extent of the petroleum system. The volume of liquid hydrocarbons generated by Natih source rocks was calculated and compared to the estimated oil-in-place to determine the generation-trapping efficiency of the petroleum system. Some 100x109 cubic meters of source rock is currently mature and produced a cumulative volume of 14x109 cubic meters (88 billion barrels) oil. Of this volume 9% has actually been discovered and 0.25x109 cubic meters (1.57 billion barrels) are currently booked as recoverable reserves, equivalent to 1.8% of the total generated volume. Both percentages classify the Natih petroleum system as the most efficient system in Oman. This extreme efficiency results from several factors, such as: (1) modest structural deformation in the foreland basin, which permits lateral migration to remain the dominant style; (2) abundant and uninterrupted access to oil charge from an active kitchen in the foreland basin; and (3) excellent intra-formational source rocks, which is retained by thick Fiqa shales. Most structural prospects have been tested in four decades of exploration. The remaining hydrocarbon potential is anticipated to exist mainly in stratigraphic traps in Fiqa turbidites in the foreland basin, and truncation traps across the northern flank of the peripheral bulge.
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McLennan, Jeanette M., John S. Rasidi, Richard L. Holmes, and Greg C. Smith. "THE GEOLOGY AND PETROLEUM POTENTIAL OF THE WESTERN ARAFURA SEA." APPEA Journal 30, no. 1 (1990): 91. http://dx.doi.org/10.1071/aj89005.
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The northern Bonaparte Basin and the Arafura-Money Shoal Basins lie along Australia's offshore northern margin and offer significantly different exploration prospects resulting from their differing tectonic and burial histories. The Arafura Basin is dominated by a deep, faulted and folded, NW-SE orientated Palaeozoic graben overlain by the relatively flat-lying Jurassic-Tertiary Money Shoal Basin. The north-eastern Bonaparte Basin is dominated by the deep NE-SW orientated Malita Graben with mainly Jurassic to Recent basin-fill.A variety of potential structural and stratigraphic traps occur in the region especially associated with the grabens. They include tilted or horst fault blocks and large compressional, drape and rollover anticlines. Some inversion and possibly interference anticlines result from late Cenozoic collision between the Australian plate and Timor and the Banda Arc.In the Arafura-Money Shoal Basins, good petroleum source rocks occur in the Cambrian, Carboniferous and Jurassic-Cretaceous sequences although maturation is biassed towards early graben development. Jurassic-Neocomian sandstones have the best reservoir potential, Carboniferous clastics offer moderate prospects, and Palaeozoic carbonates require porosity enhancement.The Malita Graben probably contains good potential Jurassic source rocks which commenced generation in the Late Cretaceous. Deep burial in the graben has decreased porosity of the Jurassic-Neocomian sandstones significantly but potential reservoirs may occur on the shallower flanks.The region is sparsely explored and no commercial discoveries exist. However, oil and gas indications are common in a variety of Palaeozoic and Mesozoic sequences and structural settings. These provide sufficient encouragement for a new round of exploration.
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Suslova, Anna A., Antonina V. Stoupakova, Alina V. Mordasova, and Roman S. Sautkin. "Structural reconstructions of the Eastern Barents Sea at Meso-Tertiary evolution and influence on petroleum potential." Georesursy 23, no. 1 (March 30, 2021): 78–84. http://dx.doi.org/10.18599/grs.2021.1.8.
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Barents Sea basin is the most explored and studied by the regional and petroleum geologists on the Russian Arctic shelf and has approved gas reserves. However, there are many questions in the petroleum exploration, one of them is the structural reconstruction. During its geological evolution, Barents Sea shelf was influenced by the Pre-Novaya Zemlya structural zone that uplifted several times in Mesozoic and Cenozoic. The main goal of the research is to clarify the periods of structural reconstructions of the Eastern Barents shelf and its influence on the petroleum systems of the Barents Sea shelf. A database of regional seismic profiles and offshore borehole data collected over the past decade on the Petroleum Geology Department of the Lomonosov Moscow State University allows to define main unconformities and seismic sequences, to reconstruct the periods of subsidence and uplifts in Mesozoic and Cenozoic. The structural reconstructions on the Eastern Barents Sea in the Triassic-Jurassic boundary led to intensive uplifts and formation of the huge inversion swells, which is expressed in erosional truncation and stratigraphic unconformity in the Upper Triassic and Lower Jurassic strata. In the Jurassic period, tectonic subsidence reigned on the shelf, when the uplifts including the highs of Novaya Zemlya were partially flooded and regional clay seal and source rocks – Upper Jurassic «black clays» – deposited on the shelf. The next contraction phase manifested itself as a second impulse of the growth of inversion swells in the Late Jurassic-Early Cretaceous. Cenozoic uplift of the Pre-Novaya Zemlya structural zone and the entire Barents Sea shelf led to significant erosion of the Mesozoic sediments, on the one hand, forming modern structural traps, and on the other, significantly destroying the Albian, once regional seal.
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Selley, R. C. "E. A. Beaumont & N. H. Foster (compilers) 1990. Structural Traps I: Tectonic Fold Traps, x + 232 pp.; Structural Traps II: Traps Associated with Tectonic Faulting, xii + 267 pp.; Structural Traps III: Tectonic Fold and Fault Traps, x + 235 pp.; Structural Traps IV: Tectonic and Nontectonic Fold Traps, xii + 382 pp. American Association of Petroleum Geologists, Treatise of Petroleum Geology. Atlas of Oil and Gas Fields. Tulsa. Prices US $38, 38, 30, 39 respectively (hard covers). ISBNs 0 89181 850 5; 0 089181 581 3; 0 089181 583 X; 0 089181 584 8." Geological Magazine 128, no. 6 (November 1991): 678. http://dx.doi.org/10.1017/s001675680001983x.
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Vuong, Hoang Van, Tran Van Kha, Pham Nam Hung, and Nguyen Kim Dung. "Research on deep geological structure and forecasting of some areas with petroleum prospects in the Red river delta coastal strip according to geophysical data." Tạp chí Khoa học và Công nghệ biển 19, no. 3B (October 21, 2019): 71–89. http://dx.doi.org/10.15625/1859-3097/19/3b/14516.
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The coastal areas of the Red River Delta are the transition areas from the continent to the sea and have great mineral prospects, especially petroleum prospects. In this area, a lot of topics and projects in geology and geophysics have been conducted for many different purposes such as studying the deep structure, tectonic - geological features, seismic reflection - refraction to identify petroleum traps in the Cenozoic sediments... However there are very few studies on deep structure features, using the results of processing and meta-analysis of gravity, magnetotelluric, tectonic - geological data to detect the direct and indirect relations to the formation of structures with petroleum potential. The authors have researched, tested and applied an appropriate methodology of processing and analysis, to overcome the shortfall of gravity data as well as the nonhomogeneity in details of seismic and geophysical surveys. The obtained results are semi-quantitative and qualitative characteristics of structure of deep boundary surfaces, structural characteristics of fault systems and their distribution in the study area, calculation of the average rock density of pre-Cenozoic basement... From these results, the authors established the zoning map of the areas with petroleum potential in the Red river delta coastal strip according to geophysical data.
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Wender, Lawrence E., Jeffrey W. Bryant, Martin F. Dickens, Allen S. Neville, and Abdulrahman M. Al-Moqbel. "Paleozoic (Pre-Khuff Hydrocarbon Geology of the Ghawar Area, Eastern Saudi Arabia." GeoArabia 3, no. 2 (April 1, 1998): 273–302. http://dx.doi.org/10.2113/geoarabia0302273.
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ABSTRACT Saudi Aramco is conducting an exploration program to discover additional non-associated gas reserves in the Ghawar Area. The program has successfully discovered significant sweet gas and condensate reserves in the pre-Khuff siliciclastics and has further increased our understanding of the Paleozoic petroleum system. The Lower Permian Unayzah Formation is the principal pre-Khuff hydrocarbon reservoir in the Southern Ghawar Area, where it contains both oil and gas. The Unayzah consists of fluvial to marginal marine sandstones. The Devonian Jauf Formation is the principal pre-Khuff reservoir in the Northern Ghawar Area, where it hosts the recently discovered giant Hawiyah gas-condensate field. The Jauf consists of shallow marine sandstones that exhibit unusually high porosities considering the burial depths. The primary source rock for pre-Khuff hydrocarbons is the basal “hot shale” of the Lower Silurian Qalibah Formation. Maturation modeling of these shales indicates hydrocarbon generation began in the Middle Triassic (oil) and continues to the present (dry gas). Pre-Khuff hydrocarbon traps are found in simple four-way closures as well as more complex structural-stratigraphic traps on the flanks of Hercynian structures. Trap formation and modification occurred in four main phases: (1) Carboniferous (Hercynian Orogeny); (2) Early Triassic (Zagros Rifting); (3) Late Cretaceous (First or Early Alpine Orogeny); and (4) Tertiary (Second or Late Alpine Orogeny). Structures in the Ghawar Area show differences in growth histories, which have impacted the amount and type of hydrocarbons contained.
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Sapyanik, V. V., E. Yu Lapteva, E. V. Lyubutina, A. I. Nedospasov, P. I. Novikov, N. V. Petrova, A. V. Fateev, and A. P. Khilko. "GEODYNAMICS OF THE SEDIMENTARY COVER AND OIL-AND-GAS PROSPECTS OF THE TOMSK REGION EASTERN TERRITORY." Geology and mineral resources of Siberia, no. 3 (2021): 21–30. http://dx.doi.org/10.20403/2078-0575-2021-3-21-30.
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The article deals with geodynamic processes of the plicative tectonics of the Mesozoic-Cenozoic development stage in the southeastern territory of the West Siberian hemisyneclise, which allowed scientists to significantly clarify the configuration of multi-ordinal structures, to identify the second-order negative structure in the territory of the Baraba-Pikhtovka monocline, and to offer a new view of the structural-tectonic zoning of the Tomsk region eastern territory sedimentary cover. To substantiate the prospects of Jurassic petroleum plays, their resource potential is estimated using the basin modeling method. Based on an integrated analysis of structural imagings, history of the territory tectonic development, calculated maps of effective capacities, test results and WL conclusions, 42 traps of structural, structural-lithological, structural-stratigraphic types were mapped and their assessment by the volume-statistic method by Dl category [inferred resources] was given. The results obtained significantly expand the prospects for peripheral territories of the West Siberian Plate, where it is necessary to complete regional geological exploration.
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Abdullah, Rashed, Md Shahadat Hossain, Md Soyeb Aktar, Mohammad Moinul Hossain, and Farida Khanam. "Structural initiation along the frontal fold-thrust system in the western Indo-Burman Range: Implications for the tectonostratigraphic evolution of the Hatia Trough (Bengal Basin)." Interpretation 9, no. 3 (July 27, 2021): SF1—SF10. http://dx.doi.org/10.1190/int-2020-0227.1.
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The Bengal Basin accommodates an extremely thick Cenozoic sedimentary succession that derived from the uplifted Himalayan and Indo-Burman Orogenic Belts in response to the subduction of the Indian Plate beneath the Eurasian and Burmese Plates. The Hatia Trough is a proven petroleum province that occupies much of the southern Bengal Basin. However, the style of deformation, kinematics, and possible timing of structural initiation in the Hatia Trough and the relationship of this deformation to the frontal fold-thrust system in the outer wedge (namely, the Chittagong Tripura Fold Belt) of the Indo-Burman subduction system to the east are largely unknown. Therefore, we have carried out a structural interpretation across the eastern Hatia Trough and the western Chittagong Tripura Fold Belt based on 2D seismic reflection data. Our result suggests that the synkinematic packages correspond to the Pliocene Tipam Group and the Pleistocene Dupitila Formation. This implies that the structural development in the western Chittagong Tripura Fold Belt took place from the Pliocene. In the Hatia Trough, the timing of structural activation is slightly later (since the Plio-Pleistocene). In general, fold intensity and structural complexity gradually increase toward the east. The presence of reverse faults with minor strike-slip motion along the frontal thrust system in the outer wedge is also consistent with the regional transpressional structures of the Indo-Burman subduction system. However, to the west, there is no evidence for strike-slip deformation in the Hatia Trough. The restored sections indicate that the amount of east–west shortening in the Hatia Trough is very low (maximum 1.2%). In contrast, to the east, the amount of shortening is high (maximum 13.5%) in the western margin of the Chittagong Tripura Fold Belt. In both areas, the key trapping mechanism includes anticlinal traps, although stratigraphic and combinational traps are possible, but this requires further evaluation.
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Ward, Kelsey L., and Frank O. Folorunso. "The Corringham, Gainsborough–Beckingham, Glentworth, Nettleham, Stainton and Welton fields, UK Onshore." Geological Society, London, Memoirs 52, no. 1 (2020): 45–54. http://dx.doi.org/10.1144/m52-2018-21.
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AbstractThis paper focuses on the southern part of the East Midlands oil province, in which most hydrocarbon reservoirs are in Carboniferous strata and are primarily oil producing. The oils are predominantly sourced from the Namurian interbedded shales in the Gainsborough Trough and are trapped within anticlinal structures.Oil and gas exploration and production in the UK was marked by the Hardstoft-1 discovery in 1919. Since this discovery, more than 33 fields have been discovered in the East Midlands oil province, including the fields studied in this paper: Egmanton (in 1955), Bothamsall and Corringham (in 1958), Gainsborough and Beckingham (in 1959), South Leverton (in 1960), Glentworth (in 1961), and, the UK's second largest onshore field, Welton (in 1981). All of these fields produce from a Carboniferous petroleum system, sourced from Pendleian-age shales, reservoired in Namurian- and Westphalian-age sands, and trapped predominantly via structural, anticlinal traps.
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Marlow, Lisa, Kristijan Kornpihl, and Christopher G. St C. Kendall. "2-D Basin modeling study of petroleum systems in the Levantine Basin, Eastern Mediterranean." GeoArabia 16, no. 2 (April 1, 2011): 17–42. http://dx.doi.org/10.2113/geoarabia160217.
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ABSTRACT The Levantine Basin has proven hydrocarbons, yet it is still a frontier basin. There have been significant oil and gas discoveries offshore the Nile Delta, e.g. several Pliocene gas plays and the Mango Well with ca. 10,000 bbls/day in Lower Cretaceous rocks and recently, Noble Energy discovered two gas “giants” (> 5 TCF and one estimated at 16 TFC) one of which is in a pre-Messinian strata in ca. 1,700 m (5,577 ft) water depth. Regional two-dimensional (2-D) petroleum system modeling suggests that source rocks generated hydrocarbons throughout the basin. This paper provides insight into the petroleum systems of the Levantine Basin using well and 2-D seismic data interpretations and PetroMod2D. Tectonics followed the general progression of the opening and closing of the Neo-Tethys Ocean: rift-extension, passive margin, and compression. The stratal package is up to 15 km thick and consists of mixed siliciclastic-carbonate-evaporite facies. Five potential source rock intervals (Triassic – Paleocene) are suggested. Kerogen in the older source rocks is fully transformed, whereas the younger source rocks are less mature. There are several potential reservoir and seal rocks. The model suggests that oil and gas accumulations exist in both structural and stratigraphic traps throughout the basin.
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Davidson, John K. "Plate tectonic structural geology to detailed field and prospect stress prediction." APPEA Journal 48, no. 1 (2008): 153. http://dx.doi.org/10.1071/aj07010.
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Arguably the first successful application of the theory of continental drift to petroleum exploration was in 1959 by the pioneers S. W. Carey and L. G. Weeks whose collaboration led to the discovery of the world class Gippsland Basin. Plate tectonics, as the theory is now known, was still nascent and not prominent during peak global oil exploration success in the 1960s. As discovery rates continue to decline, large scale description of separating and colliding continents has become increasingly impotent in the ever more complex hunt for the next barrel. Emphasis is turning from new basins and plays to smaller intra-basin discoveries related to a more detailed understanding of basin forming faults and their local stress effects on traps and trap geometries. Improved oil recovery is not only about finding new fields, but also demands detailed stress information for horizontal wellbore stability to economically and effectively increase reserves and recovery rates by extracting new oil from old fields. As a result, expensive wellbore based measurements have been deployed in the past 15 years. These precision measurements have then been averaged between wells for stress prediction but stress directions are known to vary abruptly by up to 90° over distances of less than 3 km. A solution lies in the seismic recognition of globally synchronous compressional pulses which, like a heartbeat, have added predictability of stress fields hence to stress analysis. This repetition of stress provides a workflow for stress consistent seismic interpretation that can predict horizontal and vertical changes in the direction of the maximum horizontal compressional component of a stress SH (SHD) and also in the magnitude of the stress, SHM. It is now possible to derive pre-drill at any desired point, important exploration and production variables such as stress related fault seal and open fracture orientation. Similarly, important reservoir development parameters such as fracture gradients and wellbore stability prediction will maximise recovery efficiencies and reduce development costs. This technique will also aid in effective carbon dioxide sequestration, a challenging new field of endeavour.
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Sales, Mark, Malcolm Altmann, Glen Buick, Claire Dowling, John Bourne, and Alexandra Bennett. "Subtle oil fields along the Western Flank of the Cooper/Eromanga petroleum system." APPEA Journal 55, no. 2 (2015): 440. http://dx.doi.org/10.1071/aj14075.
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Oil production from Cooper/Eromanga started in 1978, peaked in the 1980s and began a steady decline. Oil production from the Western Flank commenced in 2002 and has steadily increased. In the year until July 2014, a total of 8.6 million BBL of oil was produced from 16 active fields along the Western Flank, bringing the cumulative total to 24 million BBL. Western Flank oil has underpinned a ten-fold growth in market capitalisation in four listed Australian companies: Beach Energy, Drillsearch Ltd, Senex Energy and Cooper Energy. Two sandstone plays dominate the Western Flank petroleum geology: the Namur Sandstone low-relief structural play and the mid-Birkhead stratigraphic play. The use of 3D seismic has improved the definition of both plays, increased exploration success and optimised field appraisal and development drilling. Success rates have improved despite most Namur structural closures being close to the resolution margin for depth conversions (less than 8 m). Seismic attribute mapping is being refined in the more difficult search for mid-Birkhead stratigraphic traps with recent exploration discoveries indicating improved success. Reservoir properties in the Namur are excellent with multi-Darcy permeability, unlimited aquifer strength, low gas/oil ratio (GOR) and low residual oil saturation. This combination leads to an oil recovery factor greater than 75%. Initial free-flow production rates commonly exceed 6,000 BBL per a day. The mid-Birkhead reservoir is also of high quality but the lack of a strong aquifer drive reduces primary recovery. New and re-processed 3D seismic and water-flood projects are expected to drive further discoveries, reserve and production growth.
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Ambrose, G., M. Scardigno, and A. J. Hill. "PETROLEUM GEOLOGY OF MIDDLE–LATE TRIASSIC AND EARLY JURASSIC SEQUENCES IN THE SIMPSON BASIN AND NORTHERN EROMANGA BASIN OF CENTRAL AUSTRALIA." APPEA Journal 47, no. 1 (2007): 127. http://dx.doi.org/10.1071/aj06007.
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Prospective Middle–Late Triassic and Early Jurassic petroleum systems are widespread in central Australia where they have only been sparsely explored. These systems are important targets in the Simpson/Eromanga basins (Poolowanna Trough and surrounds), but the petroleum systems also extend into the northern and eastern Cooper Basin.Regional deposition of Early–Middle Triassic red-beds, which provide regional seal to the Permian petroleum system, are variously named the Walkandi Formation in the Simpson Basin, and the Arrabury Formation in the northern and eastern Cooper Basin. A pervasive, transgressive lacustrine sequence (Middle–Late Triassic Peera Peera Formation) disconformably overlies the red-beds and can be correlated over a distance of 500 km from the Poolowanna Trough into western Queensland, thus providing the key to unravelling Triassic stratigraphic architecture in the region. The equivalent sequence in the northern Cooper Basin is the Tinchoo Formation. These correlations allow considerable simplification of Triassic stratigraphy in this region, and demonstrate the wide lateral extent of lacustrine source rocks that also provide regional seal. Sheet-like, fluvial-alluvial sands at the base of the Peera Peera/Tinchoo sequence are prime reservoir targets and have produced oil at James–1, with widespread hydrocarbon shows occurring elsewhere including Poolowanna–1, Colson–1, Walkandi–1, Potiron–1 and Mackillop–1.The Early Jurassic Poolowanna Formation disconformably overlies the Peera Peera Formation and can be subdivided into two transgressive, fluvial-lacustrine cycles, which formed on a regional scale in response to distal sea level oscillations. Early Jurassic stratigraphic architecture in the Poolowanna Trough is defined by a lacustrine shale capping the basal transgressive cycle (Cycle 1). This shale partitions the Early Jurassic aquifer in some areas and significant hydrocarbon shows and oil recoveries are largely restricted to sandstones below this seal. Structural closure into the depositional edge of Cycle 1 is an important oil play.The Poolowanna and Peera Peera formations, which have produced minor oil and gas/condensate on test respectively in Poolowanna–1, include lacustrine source rocks with distinct coal maceral compositions. Significantly, the oil-bearing Early Jurassic sequence in Cuttapirrie–1 in the Cooper Basin correlates directly with the Cycle–1 oil pool in Poolowanna–1. Basin modelling in the latter indicates hydrocarbon expulsion occurred in the late Cretaceous (90–100 Ma) with migration into a subtle Jurassic age closure. Robust Miocene structural reactivation breached the trap leaving only minor remnants of water-washed oil. Other large Miocene structures, bound by reverse faults and some reflecting major inversion, have failed to encounter commercial hydrocarbons. Future exploration should target subtle Triassic to Jurassic–Early Cretaceous age structural and combination stratigraphic traps largely free of younger fault dislocation.
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Tari, Gábor, Didier Arbouille, Zsolt Schléder, and Tamás Tóth. "Inversion tectonics: a brief petroleum industry perspective." Solid Earth 11, no. 5 (October 21, 2020): 1865–89. http://dx.doi.org/10.5194/se-11-1865-2020.
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Abstract. Inverted structures provide traps for petroleum exploration, typically four-way structural closures. As to the degree of inversion, based on a large number of worldwide examples seen in various basins, the most preferred petroleum exploration targets are mild to moderate inversion structures, defined by the location of the null points. In these instances, the closures have a relatively small vertical amplitude but are simple in a map-view sense and well imaged on seismic reflection data. Also, the closures typically cluster above the extensional depocenters which tend to contain source rocks providing petroleum charge during and after the inversion. Cases for strong or total inversion are generally not that common and typically are not considered as ideal exploration prospects, mostly due to breaching and seismic imaging challenges associated with the trap(s) formed early on in the process of inversion. Also, migration may become tortuous due to the structural complexity or the source rock units may be uplifted above the hydrocarbon generation window, effectively terminating the charge once the inversion has occurred. Cases of inversion tectonics can be grouped into two main modes. A structure develops in Mode I inversion if the syn-rift succession in the preexisting extensional basin unit is thicker than its post-rift cover including the pre- and syn-inversion part of it. In contrast, a structure evolves in Mode II inversion if the opposite syn- versus post-rift sequence thickness ratio can be observed. These two modes have different impacts on the petroleum system elements in any given inversion structure. Mode I inversion tends to develop in failed intracontinental rifts and proximal passive margins, and Mode II structures are associated with back-arc basins and distal parts of passive margins. For any particular structure the evidence for inversion is typically provided by subsurface data sets such as reflection seismic and well data. However, in many cases the deeper segments of the structure are either poorly imaged by the seismic data and/or have not been penetrated by exploration wells. In these cases the interpretation in terms of inversion has to rely on the regional understanding of the basin evolution with evidence for an early phase of crustal extension by normal faulting.
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Farooqui, Mohammed Y., Khamis Farhoud, Dia Mahmoud, and Ahmed N. El-Barkooky. "Petroleum potential of the interpreted Paleozoic geoseismic sequences in the South Diyur Block, Western Desert of Egypt." GeoArabia 17, no. 3 (July 1, 2012): 133–76. http://dx.doi.org/10.2113/geoarabia1703133.
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ABSTRACT The South Diyur exploration block of nearly 38,000 sq km is located in the Farafra Oasis region in the Western Desert of Egypt. It is a frontier exploration area, the nearest well being Ammonite-1, a dry hole drilled by Conoco in 1979 immediately outside the southwestern corner of the block. The South Diyur Block is located on the probable northeast extension of the Kufra Basin in southeast Libya. Although prolific reserves of oil and gas occur in Paleozoic basins in North Africa and throughout the Middle East, to date, the targets for petroleum exploration in the northern Western Desert have been in Jurassic and Cretaceous rocks. The regional structural surface features in the South Diyur Block are the NE-trending Bahariya and Farafra anticlines interpreted as a deeply eroded and inverted Late Cretaceous structure on the southern extension of the Syrian Arc system. The oldest exposed rocks are a Cretaceous sequence of sublittoral sediments (the Campanian Wadi Hennis Formation) in the core of the anticline. The interpretation of the subsurface is based on 1,175 line-km of reprocessed 1970s-vintage 2-D seismic. Four sequence boundaries have been identified from the seismic data. SB-1 correlates with the Jurassic/Cretaceous boundary in Ammonite-1. SB-2 is regionally correlated with the Late Devonian to Early Carboniferous Hercynian unconformity that overlies deeply eroded and truncated Paleozoic sequences and possibly marks the regionally extensive Late Paleozoic basin inversion. SB-3 near the base of the interpreted Silurian sequence coincides with the ‘hot shale’ petroleum source rock that is present throughout North Africa and the Middle East. SB-4 is interpreted as a major unconformity at the top of an Upper Proterozoic sedimentary section that was misinterpreted as the Precambrian acoustic basement in Ammonite-1. Five seismic sequences relate to the seismic boundaries. SS-1, from the surface to SB-1 is characterized by subparallel seismic stratification and is composed mainly of sandstone with shale interbeds in Ammonite-1. SS-2, bounded by SB-1 and SB-2, is distinguished by parallel to subparallel seismic stratification. In Ammonite-1, the sequence of interbedded sandstone and shale is fresh-water bearing and lacking in top seals, thus reducing its prospectivity. The underlying SS-3 (SB-2 to SB-3) directly underlies the Hercynian unconformity and is characterized by semi-transparent seismic facies that may correspond to a thick Silurian shale sequence. SS-4 (SB-3 to SB-4) of probable Cambrian–Ordovician age has parallel seismic stratification. Deep channels are interpreted as evidence of a Late Ordovician–Early Silurian glacial phase that is present throughout North Africa and the Middle East. SS-5 (below SB-4) is marked by partial subparallel seismic stratification and block faulting. It probably belongs to the Late Proterozoic (Pan-African) phase of block faulting and pull-apart basins. Similar seismic geometries and facies occur in the Kufra Basin in southeast Libya and in many parts of the Arabian Plate, including the prolific petroleum systems of Oman. Exploration plays in the South Diyur Block are a combination of Paleozoic structural and stratigraphic traps associated with prospective fairways, and possible stratigraphic traps in the Late Ordovician–Early Silurian glacial channels. In addition, the interpreted Late Proterozoic sequences (SS-5) warrant further evaluation. In order to identify future exploration plays and drill targets, additional 2-D seismic (4,490 line-km), aeromagnetic and airborne gravity surveys will be integrated with the present seismic data and drilling results from Ammonite-1. This will allow a proper assessment of the magnetic basement, basin configuration and prospective fairways.
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DeVito, Steve, and Hannah Kearns. "Overview of the exploration potential of offshore Argentina – insight from new seismic interpretations." Petroleum Geoscience 28, no. 2 (January 19, 2022): petgeo2020–132. http://dx.doi.org/10.1144/petgeo2020-132.
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Argentina's offshore sedimentary basins cover a vast area on one of the widest continental margins on the planet, yet they remain underexplored today. Previous exploration drilling has failed to encounter commercial volumes of hydrocarbons, in part due to the poor seismic imaging of legacy 1960s–1990s 2D seismic data, and to the majority of wells being drilled on structural highs outside of the source rock kitchens. In this study, we reviewed 52 000 km of recently acquired (2017–2018) regional 2D long-offset seismic data with broadband pre-stack time (PSTM) and depth migration (PSDM) processing. We identified five major structural domains with hydrocarbon prospectivity on the Northern Margin of Argentina and four on the Southern Margin, and the presence of previously unseen structural and stratigraphic traps involving sequences assigned to proven regional source rocks and reservoirs in Permian, Jurassic and Cretaceous rocks. The source and reservoir rocks, petroleum systems, and play types present in the deepwater of the undrilled Argentina Basin represent a true frontier for hydrocarbon exploration. Pseudo relief attribute seismic displays and amplitude v. angle (AVA) analysis are demonstrated to be valuable tools in predicting the stratigraphy of the basins. A new framework for understanding the oil and gas prospectivity of the study area is presented.
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Bischoff, Alan Patrick, Andrew Nicol, and Mac Beggs. "Stratigraphy of architectural elements in a buried volcanic system and implications for hydrocarbon exploration." Interpretation 5, no. 3 (August 31, 2017): SK141—SK159. http://dx.doi.org/10.1190/int-2016-0201.1.
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The interaction between magmatism and sedimentation creates a range of petroleum plays at different stratigraphic levels due to the emplacement and burial of volcanoes. This study characterizes the spatio-temporal distribution of the fundamental building blocks (i.e., architectural elements) of a buried volcano and enclosing sedimentary strata to provide insights for hydrocarbon exploration in volcanic systems. We use a large data set of wells and seismic reflection surveys from the offshore Taranaki Basin, New Zealand, compared with outcropping volcanic systems worldwide to demonstrate the local impacts of magmatism on the evolution of the host sedimentary basin and petroleum system. We discover the architecture of Kora volcano, a Miocene andesitic polygenetic stratovolcano that is currently buried by more than 1000 m of sedimentary strata and hosts a subcommercial discovery within volcanogenic deposits. The 22 individual architectural elements have been characterized within three main stratigraphic sequences of the Kora volcanic system. These sequences are referred to as premagmatic (predate magmatism), synmagmatic (defined by the occurrence of intrusive, eruptive, and sedimentary architectural elements), and postmagmatic (degradation and burial of the volcanic structures after magmatism ceased). Potential petroleum plays were identified based on the distribution of the architectural elements and on the geologic circumstances resulting from the interaction between magmatism and sedimentation. At the endogenous level, emplacement of magma forms structural traps, such as drag folds and strata jacked up above intrusions. At the exogenous level, syneruptive, intereruptive, and postmagmatic processes mainly form stratigraphic and paleogeomorphic traps, such as interbedded volcano-sedimentary deposits, and upturned pinchout of volcanogenic and nonvolcanogenic coarse-grained deposits onto the volcanic edifice. Potential reservoirs are located at systematic vertical and lateral distances from eruptive centers. We have determined that identifying the architectural elements of buried volcanoes is necessary for building predictive models and for derisking hydrocarbon exploration in sedimentary basins affected by magmatism.
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Lyatsky, Henry V., and James W. Haggart. "Petroleum exploration model for the Queen Charlotte Basin area, offshore British Columbia." Canadian Journal of Earth Sciences 30, no. 5 (May 1, 1993): 918–27. http://dx.doi.org/10.1139/e93-077.
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A potential oil-bearing region lies on the west coast of Canada, in the Queen Charlotte Basin area. Upper Triassic – Lower Jurassic source and Cretaceous reservoir rocks are capped by thick Tertiary volcanic and sedimentary strata. The traps are large block structures, and oil generation and migration took place principally in the Tertiary.Previous hypotheses of Queen Charlotte Basin evolution assumed high regional Tertiary heat flow and large tectonic extension; older rocks would have been overheated, and their oil destroyed. New data largely nullify such an interpretation. Miocene positive thermal anomalies were caused by magmatism, hence were local, and Mesozoic rocks may have retained their petroleum prospects. Regional structural style of the area has been dominated by repeated movements of fault-bounded crustal blocks since the Late Jurassic, and the structure of the Cenozoic basin was inherited largely from this older template.The new interpretation of the geologic evolution of the region permits a fresh assessment of its petroleum potential: Cretaceous strata beneath Queen Charlotte Sound are a prime exploration target. Caution is recommended when quantitative basin-formation models are applied to oil exploration; the best exploration model is one that incorporates the maximum geological and geophysical data.
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Jackson, Christopher A. L., Craig Magee, and Carl Jacquemyn. "Rift-related magmatism influences petroleum system development in the NE Irish Rockall Basin, offshore Ireland." Petroleum Geoscience 26, no. 4 (January 9, 2020): 511–24. http://dx.doi.org/10.1144/petgeo2018-020.
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Large volumes of hydrocarbons reside in volcanically influenced sedimentary basins. Despite having a good conceptual understanding of how magmatism impacts the petroleum systems of such basins, we still lack detailed case studies documenting precisely how intrusive magmatism influences, for example, trap development and reservoir quality. Here we combine 3D seismic reflection, borehole, petrographical and palaeothermometric data to document the geology of borehole 5/22-1, NE Irish Rockall Basin, offshore western Ireland. This borehole (Errigal) tested a four-way dip closure that formed to accommodate emplacement of a Paleocene–Eocene igneous sill-complex during continental break-up in the North Atlantic. Two water-bearing turbidite-sandstone-bearing intervals occur in the Upper Paleocene; the lowermost contains thin (c. 5 m), quartzose-feldspathic sandstones of good reservoir quality, whereas the upper is dominated by poor-quality volcaniclastic sandstones. Palaeothermometric data provide evidence of anomalously high temperatures in the Paleocene–Eocene succession, suggesting the poor reservoir quality within the target interval is likely to reflect sill-induced heating, fluid flow, and related diagenesis. The poor reservoir quality is also probably the result of the primary composition of the reservoir, which is dominated by volcanic grains and related clays derived from an igneous-rock-dominated, sediment source area. Errigal appeared to fail due to a lack of hydrocarbon charge: that is, the low bulk permeability of the heavily intruded Cretaceous mudstone succession may have impeded the vertical migration of sub-Cretaceous-sourced hydrocarbons into supra-Cretaceous reservoirs. Break-up-related magmatism did, however, drive the formation of a large structural closure, with data from Errigal at least proving high-quality, Upper Paleocene deep-water reservoirs. Future exploration targets in the NE Irish Rockall Basin include: (i) stratigraphically trapped Paleocene–Eocene deep-water sandstones that onlap the flanks of intrusion-induced forced folds; (ii) structurally trapped, intra-Cretaceous, deep-water sandstones incorporated within intrusion-induced forced folds; and (iii) more conventional, Mesozoic fault-block traps underlying the heavily intruded Cretaceous succession (e.g. Dooish). Similar plays may exist on other continental margins influenced by break-up magmatism.Supplementary material: Borehole-related reports, and litho- and composite logs are available at https://doi.org/10.6084/m9.figshare.c.4803267
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Al-Ameri, Thamer K., Amer Jassim Al-Khafaji, and John Zumberge. "Petroleum system analysis of the Mishrif reservoir in the Ratawi, Zubair, North and South Rumaila oil fields, southern Iraq." GeoArabia 14, no. 4 (October 1, 2009): 91–108. http://dx.doi.org/10.2113/geoarabia140491.
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ABSTRACT Five oil samples reservoired in the Cretaceous Mishrif Formation from the Ratawi, Zubair, Rumaila North and Rumaila South fields have been analysed using Gas Chromatography – Mass Spectroscopy (GC-MS). In addition, fifteen core samples from the Mishrif Formation and 81 core samples from the Lower Cretaceous and Upper Jurassic have been subjected to source rock analysis and palynological and petrographic description. These observations have been integrated with electric wireline log response. The reservoirs of the Mishrif Formation show measured porosities up to 28% and the oils are interpreted as being sourced from: (1) Type II carbonate rocks interbedded with shales and deposited in a reducing marine environment with low salinity based on biomarkers and isotopic analysis; (2) Upper Jurassic to Lower Cretaceous age based on sterane ratios, analysis of isoprenoids and isotopes, and biomarkers, and (3) Thermally mature source rocks, based on the biomarker analysis. The geochemical analysis suggests that the Mishrif oils may have been sourced from the Upper Jurassic Najma or Sargelu formations or the Lower Cretaceous Sulaiy Formation. Visual kerogen assessment and source rock analysis show the Sulaiy Formation to be a good quality source rock with high total organic carbon (up to 8 wt% TOC) and rich in amorphogen. The Lower Cretaceous source rocks were deposited in a suboxic-anoxic basin and show good hydrogen indices. They are buried at depths in excess of 5,000 m and are likely to have charged Mishrif reservoirs during the Miocene. The migration from the source rock is likely to be largely vertical and possibly along faults before reaching the vuggy, highly permeable reservoirs of the Mishrif Formation. Structural traps in the Mishrif Formation reservoir are likely to have formed in the Late Cretaceous.
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Selly, R. C. "N. H. Foster, & E. A. Beaumont, (compilers) 1993. Structural Traps VIII. Treatise of Petroleum Geology, Atlas of Oil and Gas Fields Series, xii + 328 pp. Tulsa: American Association of Petroleum Geologists. Price not stated (hard covers). ISBN 0 08918 590 2." Geological Magazine 132, no. 3 (May 1995): 361–62. http://dx.doi.org/10.1017/s0016756800013728.
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Jnawali, Bharat Mani. "Tectonic setting of the Nepal Himalaya and its potential for hydrocarbon exploration." Journal of Nepal Geological Society 39 (September 25, 2009): 77–84. http://dx.doi.org/10.3126/jngs.v39i0.31490.
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Nepal lies at the collision zone between the Indian subcontinent and the Tibetan Plateau of the Eurasian continent. It is made up of enormous tectonic stacking of sedimentary and metamorphic rocks with granite intrusions that resulted from the collision and under-plating of the Indian Craton with the Lhasa block of Tibet. The five major tectonic zones separated from each other by thrust contacts from south to north are the Terai, Siwalik or Sub Himalaya, Lesser Himalaya, Higher Himalaya and Tibetan Tethys. On the northern margin of the Indian subcontinent, foreland sedimentary basins began to develop immediately after the terminal collision between the northward drifting Indian Plate and relatively passive Eurasian Plate in Late Eocene time. The southern part of Nepal known as the Terai and Siwalik foothill, lies in the northern margin of the Ganga Basin and Purnea Basin that extend from India. Such basins with thick accumulation of sediments are considered as the potential area for petroleum exploration.
Regional scale seismic reflection, gravity and magnetic data combined with surface mapping and basin analysis have established the subsurface framework of southern Nepal. Geological settings potential for hydrocarbon prospects recognized in Nepal include structural traps related to normal faulting involving pre-Siwalik formation and thrusting involving Siwaliks, structural traps associated with frontal blind thrusts, anticlines and thrust-faults, basement controlled structures and stratigraphic pinchouts.
Drilling data consists of only one well drilled in the eastern part of Nepal. Oil and gas seeps have been observed in Dailekh area emanating through deep faults. Geochemical analyses of these seep samples indicate that these oil and gas have geologic origin from mature source rocks. Various outcrop samples from different parts of the country have been found rich in organic carbon. Source-rock maturity basin modeling constructed for various sections indicates that the level of thermal maturity is within oil and gas generating window. The Potwar Basin to the west in Pakistan and Assam Basin to the east in India having similar geologic setting to that of Nepal are producing oil and gas for a long time. In the Indo-Gangetic Plain across the border on Indian side, many deep wells have recorded the presence of gas and high content of organic carbon. Assessment of the available data acquired so far indicate that there is a fairly good possibility of discovering petroleum resource in Nepal.
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Li, Xiaoshan, Hong Pan, Yuxiao Wu, Guanxing Luo, Junqiang Song, Liu Yang, Kaifang Gu, et al. "Main Control Factors and Hydrocarbon Accumulation Model of Volcanic Oil Reservoirs with Complex Oil–Water Relationships: A Case Study of the Carboniferous in the Chepaizi Uplift, the Junggar Basin, China." Minerals 12, no. 11 (October 26, 2022): 1357. http://dx.doi.org/10.3390/min12111357.
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In order to study the main control factors of volcanic reservoirs with complex oil–water relationships, the Carboniferous in the Chepaizi Uplift of the Junggar Basin was taken as an example and the lithofacies characteristics, main control factors, and hydrocarbon accumulation model of volcanic reservoirs were investigated by combining the petroleum geology with field testing (data of core analysis, well logging, formation testing, and production testing). The results show that the Carboniferous in the Chepaizi Uplift experienced three stages of volcanic activities and developed seven volcanic lithofacies bodies, distributed in a bead-string connected planar form along the Hongche fault. There is no unified oil–water interface across the whole study area and there are multiple oil–water systems within one fault block. The Carboniferous volcanic reservoir experienced two stages of hydrocarbon accumulation from two different source rocks. The distribution of faults penetrating hydrocarbon kitchens and source rocks controls the macro-scale distribution of reservoirs. The physical properties of reservoirs affect the pattern of oil and water differentiation in volcanic rock bodies, while the lithofacies body-controlled hydrocarbon accumulation mode highlighting “one rock body for one reservoir” determines the distribution of reservoirs. The matching between the paleo-structure and hydrocarbon accumulation stage controls the accumulation and adjustment of hydrocarbon distribution. The Permian source rocks in the Shawan Sag serve as the lateral hydrocarbon supply and hydrocarbons accumulate in the Carboniferous structural-lithologic traps, which are summarized as the two stages of hydrocarbon accumulation of newly generated hydrocarbons into older reservoir rocks. This study of the hydrocarbon accumulation pattern in volcanic rocks aims at guiding the development of Carboniferous reservoirs with complex oil and water relationships in this area.
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Wecker, H. R. B. "THE EROMANGA BASIN." APPEA Journal 29, no. 1 (1989): 379. http://dx.doi.org/10.1071/aj88032.
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The Eromanga Basin, encompassing an area of approximately 1 million km2 in Central Australia, is a broad intracratonic downwarp containing up to 3000 m of Middle Triassic to Late Cretaceous sediments.Syndepositional tectonic activity within the basin was minimal and the main depocentres largely coincide with those of the preceding Permo- Triassic basins. Several Tertiary structuring phases, particularly in the Early Tertiary, have resulted in uplift and erosion of the Eromanga Basin section along its eastern margin, and the development of broad, northwesterly- to northeasterly- trending anticlines within the basin. In some instances, high angle faults are associated with these features. This structural deformation occurred in an extensional regime and was strongly influenced by the underlying Palaeozoic structural grain.The Eromanga Basin section is composed of a basal, dominantly non- marine, fluvial and lacustrine sequence overlain by shallow marine deposits which are in turn overlain by another fluvial, lacustrine and coal- swamp sequence. The basal sequence is the principal zone of interest to petroleum exploration. It contains the main reservoirs and potential source rocks and hosts all commercial hydrocarbon accumulations found to date. While the bulk of discovered reserves are in structural traps, a significant stratigraphic influence has been noted in a number of commercially significant hydrocarbon accumulations.All major discoveries have been in the central Eromanga Basin region overlying and adjacent to the hydrocarbon- productive, Permo- Triassic Cooper Basin. The mature Permian section is believed to have contributed a significant proportion of the Eromanga- reservoired hydrocarbons. Accordingly, structural timing and migration pathways within the Permian and Middle Triassic- Jurassic sections are important factors for exploration in the central Eromanga Basin region. Elsewhere, in less thermally- mature areas, hydrocarbon generation post- dates Tertiary structuring and thus exploration success will relate primarily to source- rock quality, maturity and drainage factors.Although exploration in the basin has proceeded spasmodically for over 50 years, it has only been in the last decade that significant exploration activity has occurred. Over this recent period, some 450 exploration wells and 140 000 km of seismic acquisition have been completed in the pursuit of Eromanga Basin oil accumulations. This has resulted in the discovery of 227 oil and gas pools totalling an original in- place proved and probable (OOIP) resource of 360 MMSTB oil and 140 BCF gas.Though pool sizes are generally small, up to 5 MMSTB OOIP, the attractiveness of Eromanga exploration lies in the propensity for stacked pools at relatively shallow depths, moderate to high reservoir productivity, and established infrastructure with pipelines to coastal centres. Coupled with improved exploration techniques and increasing knowledge of the basinal geology, these attributes will undoubtedly ensure the Eromanga Basin continues to be a prime onshore area for future petroleum exploration in Australia.
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Cosgrove, J. L., and W. G. Mogg. "RECENT EXPLORATION AND HYDROCARBON POTENTIAL OF THE ROMA SHELF, QUEENSLAND." APPEA Journal 25, no. 1 (1985): 216. http://dx.doi.org/10.1071/aj84019.
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The probability of finding additional gas reserves on the Roma Shelf within Authority to Prospect 336P and Petroleum Leases 3-13 is assessed as being very high. There is a 50 per cent probability that 80 billion cubic feet (2250 million cubic metres) will be found and a 20 per cent probability that 290 billion cubic feet (8170 million cubic metres) will be discovered.Recent seismic information together with geologic models developed for the Roma Shelf, Queensland have refined the settings of various plays of this important hydrocarbon province. Despite the large number of wells drilled in the region, it is still relatively unexplored considering the small size of economic accumulations and when compared to other sedimentary basins containing similar play types, elsewhere in the world.Modern regional seismic coverage has lead to an improved understanding of the basin's structural history. Tectonic events such as strike-slip faulting and compression commencing in the Early Carboniferous and continuing into the Tertiary have formed several structural traps in the area.Recognition of the importance of reservoir horizons such as the Lower Triassic Rewan Formation and the Upper Permian Tinowon Formation has added to the prospectivity of this area.Recent exploration has been highly successful with 67 per cent of the exploration drilling resulting in new field discoveries. This success rate has stemmed from finer spaced grids of high resolution seismic which has provided accurate prospect mapping. Refinements to exploration concepts have also resulted from an integrated geological and geophysical approach.
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Bodard, J. M., J. G. Creer, and M. W. Asten. "Next Generation High Resolution Airborne Gravity Reconnaissance in Oil Field Exploration." Energy Exploration & Exploitation 11, no. 3-4 (July 1993): 198–234. http://dx.doi.org/10.1177/0144598793011003-402.
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Simple modelling studies of gravity fields using elementary structural forms, oilfield-type structures and geological reconnaissance situations, show that gravity gradiometry technology offers significant petroleum exploration potential. In geological environments of interest, gravity gradients are primarily due to density displacement along (near) vertical boundaries. Gradient images therefore reveal the edges and corners of intrusions, faults, fault intersections, and other such structures often associated with hydrocarbon migration pathways and traps, and/or significant basinal trends. Recent technological advances may make gravity gradiometry an airborne reconnaissance tool capable of providing sensitivity and resolution superior to the best gravimetry available today. This capacity, and the array of gradient components that may be measured, will embellish aspects of the gravity field important to developing regional geologic interpretations. While the potential advantage of gravity gradiometry is greater lateral resolution and sensitivity from a moving platform, the disadvantage is the high sensitivity to topographic and shallow buried irregularities unrelated to the deeper geological structures of interest. A further difficulty is the complex gravity field representations produced for density structures of certain geometries. Buried features that have near surface expressions will be easiest to map. However, full use of gravity gradient technology will require application-focused data processing techniques and new interpretation skills. When the technology becomes commercially available it could find application in preseismic reconnaissance, structural (and possibly stratigraphic) mapping, acreage management and assessment, and in the evolution and mapping of controls on oilfield distribution. The technology could help develop exploration in remote and inaccessible areas, and provide a new look at well-explored regions. An immediate practical implementation appears to be in offshore exploration applications, possibly linked to deepwater exploitation strategies.
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Komatsu, Yuhei, Kiyofumi Suzuki, and Tetsuya Fujii. "Sequence stratigraphy and controls on gas hydrate occurrence in the eastern Nankai Trough, Japan." Interpretation 4, no. 1 (February 1, 2016): SA73—SA81. http://dx.doi.org/10.1190/int-2015-0024.1.
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The first offshore gas hydrate production test was conducted within the gas-hydrate-concentrated zone (reservoir) of the eastern Nankai Trough, which is considered to be a stratigraphic accumulation. However, the accumulation mechanism for this concentrated zone was not yet well understood. We used core and geophysical log data sets to determine the subsurface geologic architecture and stratigraphic evolution most likely responsible for the stratigraphic accumulation of gas hydrate in the eastern Nankai Trough. Seven depositional sequences were identified based on grain size, bed thickness, sedimentary structure, and stacking patterns. The sequence boundaries were also identified by terminations of seismic reflection. These sequences were attributed to a fourth to fifth-order eustatic sea-level changes because the stacking pattern cycle was in phase with global oxygen isotope curves; the cycle was also identified in the onshore formation during the same period. The reservoir was interpreted as falling-stage systems tract (FSST) and lowstand systems tract (LST). FSST and LST consisted mostly of trough-fill channel deposits. The deposits were represented by alternations of very fine- to fine-grained sand and silt. The reservoir is located in association with the structural wing of the Daini-Atsumi Knoll. The uplift of the knoll was strongly controlled by tectonic events associated with subduction of the pacific plate during Pleistocene time. The muddy deposits above the reservoir were interpreted as condensed section. We identified channel facies pinched out against structural highs, and together, these result in stratigraphic traps. Consequentially, the gas hydrate trapping system was constrained by sedimentary facies, systems tracts, and geographic and tectonic setting. Concepts and data generated in this study can be used for gas hydrate petroleum system analysis such as basin simulation.
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Gibson, George M., and Sally Edwards. "Basin inversion and structural architecture as constraints on fluid flow and Pb–Zn mineralization in the Paleo–Mesoproterozoic sedimentary sequences of northern Australia." Solid Earth 11, no. 4 (July 7, 2020): 1205–26. http://dx.doi.org/10.5194/se-11-1205-2020.
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Abstract. As host to several world-class sediment-hosted Pb–Zn deposits and unknown quantities of conventional and unconventional gas, the variably inverted 1730–1640 Ma Calvert and 1640–1575 Ma Isa superbasins of northern Australia have been the subject of numerous seismic reflection studies with a view to better understanding basin architecture and fluid migration pathways. These studies reveal a structural architecture common to inverted sedimentary basins the world over, including much younger examples known to be prospective for oil and gas in the North Sea and elsewhere, with which they might be usefully compared. Such comparisons lend themselves to suggestions that the mineral and petroleum systems in Paleo–Mesoproterozoic northern Australia may have spatially, if not temporally overlapped and shared a common tectonic driver, consistent with the observation that basinal sequences hosting Pb–Zn mineralization in northern Australia are bituminous or abnormally enriched in hydrocarbons. Sediment-hosted Pb–Zn mineralization coeval with basin inversion first occurred during the 1650–1640 Ma Riversleigh Tectonic Event towards the close of the Calvert Superbasin with further pulses taking place during and subsequent to the onset of the 1620–1580 Ma Isa Orogeny and final closure of the Isa Superbasin. Mineralization is typically hosted by the post-rift or syn-inversion fraction of basin fill, contrary to existing interpretations of Pb–Zn ore genesis where the ore-forming fluids are introduced during the rifting or syn-extensional phase of basin development. Mineralizing fluids were instead expelled upwards during times of crustal shortening into structural and/or chemical traps developing in the hangingwalls of inverted normal faults. Inverted normal faults predominantly strike NNW and ENE, giving rise to a complex architecture of compartmentalized sub-basins whose individual uplifted basement blocks and doubly plunging periclinal folds exerted a strong control not only on the distribution and preservation of potential trap rocks but the direction of fluid flow, culminating in the co-location and trapping of mineralizing and hydrocarbon fluids in the same carbonaceous rocks. An important case study is the 1575 Ma Century Pb–Zn deposit where the carbonaceous host rocks served as both a reductant and basin seal during the influx of more oxidized mineralizing fluids, forcing the latter to give up their Pb and Zn metal. A transpressive tectonic regime in which basin inversion and mineralization were paired to folding, uplift, and erosion during arc–continent or continent–continent collision, and accompanied by orogen-parallel extensional collapse and strike-slip faulting best accounts for the observed relationships.
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Mandelbaum, M. M., and A. I. Shamal. "Geophysical methods of oil and gas exploration in cambrian and precambrian sedimentary rocks of the Siberian Platform." Exploration Geophysics 20, no. 2 (1989): 37. http://dx.doi.org/10.1071/eg989037a.
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The Siberian Platform is the largest hydrocarbon-bearing sedimentary basin in the USSR. The conditions encountered in geophysical exploration in this basin are uniquely difficult. This very old sedimentary complex is characterised by abrupt changes in physical properties reflecting the presence of dolerites and tuffs, changes in salt thickness, and complex structure. Petroleum traps are controlled by low amplitude structures in the salt complex, although reservoir properties are variable, so that most traps are stratigraphic. This leads to the use of frequency content of seismic data to identify traps and electrical and time domain EM techniques to confirm the presence of the traps.
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Nazarov, D. A., and B. S. Chernobrov. "PREDICTING STRUCTURAL-HYDRODYNAMIC TRAPS FOR HYDROCARBONS." International Geology Review 30, no. 7 (July 1988): 756–62. http://dx.doi.org/10.1080/00206818809466056.
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Nguyen, Chuc Dinh, Hiep Quoc Cao, Huy Nhu Tran, and Xuan Van Tran. "Oligocene stratigraphic traps at the SouthEastern, Cuu Long basin." Science and Technology Development Journal - Natural Sciences 1, T5 (November 29, 2018): 234–50. http://dx.doi.org/10.32508/stdjns.v1it5.557.
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Up to recent years, major targets of oil and gas exploration in Cuu Long basin have been carried ort at structural traps in anticlines or basement highs in PreTertiary basement, Oligocene / Miocene clastics. As petroleum resources from reservoirs of traditional types become exhausted after many years of production (the remaining unexplored potential targets do not have sufficient reserves for development and production), exploration activities in Cuu Long basin have being focused in Oligocene stratigraphic/combination traps that have been discovered in recent years. Since the 1980s, petroleum explorers have identified oil in pinchouts trap in the Southeastern Cuu Long basin. However, these prospects have been evaluated to be of low potential due to be concerned of poor reservoir quality or incomplete petroleum system (lacking of source rocks or seals). Recent exploration activities in the region have identified several stratigraphic/ combination traps not only as pinch-outs but also as traps formed by appropriate facies changes. This article discusses types of stratigraphic traps that have been recently discovered in the studied area as well as exploration methods for predicting the distribution of these traps.
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Bui, Luan Thi. "PETROLEUM POTENTIAL OF SOURCE BEDS IN THE CUU LONG BASIN." Science and Technology Development Journal 14, no. 4 (December 30, 2011): 31–45. http://dx.doi.org/10.32508/stdj.v14i4.2025.
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In the Cuu Long basin, three source beds are identified: lower Miocene, Upper Oligocene, upper Eocene + lower Oligocene. They are separated from each other by sand-clay layers. Only Upper Oligocene and Upper Eocene + Lower Oligocene source beds are two main source beds supplying a great part of organic matter into traps. Petroleum source potential of Upper Oligocene source bed (66.30 billion tons) is greater than Upper Eocene + Lower Oligocene bed (29.88 billion tons). Total amount of hydrocarbon has ability to take part in accumulation process at the petroleumbearing traps from Upper Oligocene and Upper Eocene + Lower Oligocene source beds is over 2.19 billion tons and below 1.16 billion tons respectively. Thus, in whole CuuLong basin, source rocks have capacity to produce 96.18 billion tons of hydrocacbon in which accumulation is 3.35 billion tons making up 3.35% production quantity. Applying Monte - Carlo simulation method, using Crystal Ball software to calculate production potential and total amount of organic matter taking part into migration and accumulation process give rather appropriate result with difference level ≤ 1.25%.. Prospecting levels are in the following order: (i)Central lift zone has the greatest prospects, next is Dong Nai lift zone, graben located in north west inclined slope, south east inclined slope, north east area of Tam Dao lift zone finally. (2)Petroleum does not only accumulate in structural, combination traps but also in non-structural traps.
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Stoneley, R. "AAPG Atlas of Oil and Gas Fields–Structural Traps III: Tectonic fold and fault traps. Structural Traps IV: Tectonic and Nontectonic Fold Traps E. A. Beaumont and N. H. Foster (Eds)." Basin Research 3, no. 3 (September 1991): 175. http://dx.doi.org/10.1111/j.1365-2117.1991.tb00126.x.
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Hughes, J. K. "Examination of Seismic Repeatability as a Key Element of Time-Lapse Seismic Monitoring." SPE Reservoir Evaluation & Engineering 3, no. 06 (December 1, 2000): 517–24. http://dx.doi.org/10.2118/68246-pa.
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Summary The propagation of elastic waves in rocks is determined by the bulk modulus, shear modulus, and bulk density of the rock. In porous rocks all these properties are affected by the distribution of pore space, the geometry and interconnectivity of the pores, and the nature of the fluid occupying the pore space. In addition, the bulk and shear moduli are also affected by the effective pressure, which is equivalent to the difference between the confining (or lithostatic) pressure and pore pressure. During production of hydrocarbons from a reservoir, the movement of fluids and changes in pore pressure may contribute to a significant change in the elastic moduli and bulk density of the reservoir rocks. This phenomenon is the basis for reservoir monitoring by repeated seismic (or time-lapse) surveys whereby the difference in seismic response during the lifetime of the field can be directly related to changes in the pore fluids and/or pore pressure. Under suitable conditions, these changes in the reservoir during production can be quantitatively estimated by appropriate repeat three-dimensional (3D) seismic surveys which can contribute to understanding of the reservoir model away from the wells. The benefit to reservoir management is a better flow model which incorporates the information derived from the seismic data. What are suitable conditions? There are two primary factors which determine whether the reservoir changes we wish to observe will be detectable in the seismic data:the magnitude of the change in the elastic moduli (and bulk density) of the reservoir rocks as a result of fluid displacement, pressure changes, etc.;the magnitude of the repeatability errors between time-lapse seismic surveys. This includes errors associated with seismic data collection, ambient noise and data processing. The first is the signal component and the second the noise component. Previous reviews of seismic monitoring suggest that for 3D seismic surveys a signal-to-noise (S/N) ratio of 1.0 is sufficient for qualitative estimation of reservoir changes. Higher S/N ratios may allow quantitative estimates. After a brief examination of the rock physics affecting the seismic signal, we examine the second factor, repeatability errors, and use a synthetic seismic model to illustrate some of the factors which contribute to repeatability error. We also use two land 3D surveys over a Middle East carbonate reservoir to illustrate seismic repeatability. The study finds that repeatability errors, while always larger than desired, are generally within limits which will allow production-induced changes in seismic reflectivity to be confidently detected. Introduction Seismic data have been used successfully for many decades in the petroleum industry and have contributed significantly to the discovery of new fields throughout the world. Initially, seismic surveys were primarily an exploration tool, assisting in the identification of potential hydrocarbon structural and stratigraphic traps for drilling targets. With the introduction of 3D seismic surveys in the 1970's, accurate geological structural mapping became possible while the use of new seismic attributes as hydrocarbon indicators improved the success rate of discovery wells. More recently seismic data have also contributed to a better reservoir description away from the wells by making use of the correlation between suitable seismic attributes and petrophysical quantities such as porosity and net to gross, and by incorporating robust geostatistical methods for estimating the static reservoir model. Better seismic acquisition technology, improved seismic processing methods and an overall improvement in signal to noise have led to further 3D seismic surveys over producing fields primarily for better imaging of the reservoir and improved reservoir characterization. The concept of using repeated seismic surveys (time-lapse seismic) for monitoring changes in the reservoir due to production was suggested in the 1980's,1-3 and early tests were done by Arco in the Holt Sand fireflood4 from 1981-83. Over the last few years, the number of publications relating to time-lapse seismic [often referred to as four-dimensional (4D) seismic] has increased dramatically. Prior to time-lapse seismic monitoring, seismic data have been the domain of geologists and geophysicists, but the possibility of monitoring fluid displacements and pressure changes in a producing reservoir, away from the wells, has direct relevance to reservoir engineers and reservoir management. More exciting possibilities have been introduced by the use of time-lapse seismic data in combination with production history matching5 for greater refinement in optimization of the reservoir model. It is important, however, that reliable criteria are used to assess the feasibility of seismic monitoring.6
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Sangree, John B. "Stratigraphic traps I: Treatise of petroleum geology, Atlas of oil and gas fields." Marine and Petroleum Geology 9, no. 5 (October 1992): 573. http://dx.doi.org/10.1016/0264-8172(92)90068-p.
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Charlton, T. R. "THE PETROLEUM POTENTIAL OF EAST TIMOR." APPEA Journal 42, no. 1 (2002): 351. http://dx.doi.org/10.1071/aj01019.
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The hydrocarbon prospectivity of East Timor is widely considered to be only moderate due to Timor island’s well-known tectonic complexity, but in the present study a much higher potential is interpreted, with structures capable of hosting giant hydrocarbon accumulations. High quality source rocks are found in restricted marine sequences of Upper Triassic-Jurassic age. The most likely reservoir target is shallow marine siliciclastics of Upper Triassic-Middle Jurassic age encountered in the Banli–1 well in West Timor, comparable to the Malita and Plover Formations of the northern Bonaparte Basin, and sealed by Middle Jurassic shales of the Wai Luli Formation. The Wai Luli Formation also forms a major structural décollement level which detaches shallow level structural complexity from a simpler structural régime beneath.The principal exploration targets are large, structurally simple inversion anticlines developed beneath the complex shallow-level fold and thrust/mélange terrain. Eroded-out examples of inversion anticlines, such as the Cribas, Aitutu and Bazol anticlines, are typically several tens of kilometres long and up to 10 km broad. Comparable structures in the subsurface of southern East Timor are interpreted north of Betano, and probably also near Suai, Beaco, Aliambata and Iliomar. Other potential targets include a possible non-inverted rollover anticline at Pualaca, stratigraphic and structural traps in the south coast syn/postorogenic basins, and possibly large structural domes beneath extensive Quaternary reef plateaux in the extreme east of the island.
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Zhong, Guang Jian, Da Meng Liu, and Guang Hong Tu. "Petroleum Exploration Potential of Xisha Trough Basin in SCS." Advanced Materials Research 734-737 (August 2013): 1230–34. http://dx.doi.org/10.4028/www.scientific.net/amr.734-737.1230.
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Nowadays oil-gas exploration make a great contribution to the world oil-gas reserve increase. A series of deepwater passive continental margin basins are found in Northern Continental Slope of South China Sea. These basins consisted of thick Mesozoic and Cenozoic sedimentary strata with the characteristics of the major world deepwater oil-gas basins. As one of Cenozoic sedimentary basins in deepwater area of Northern Slope of South China Sea, Xisha Trough Basin developed 1500-8000m thick sedimentary strata, which are north-south zoning characteristics of thicker in the center and thinner both in the north and south sides of basin. In its evolutionary history there are two stages: One is Paleocene-Oligocene Rift with Continental River-Lake Facies sedimentary and the other is Miocene-Quaternary Depression with shallow sea-hemiplegic sedimentary. It has good petroleum geological conditions that source rocks consist of lacustrine mudstones, paralic mudstone, and marine mudstone, Tertiary high porosity and permeability deepwater fan reservoirs are the main reservoir, and structural traps and lithologic traps developed. In a word, it has good oil-gas exploration potential.
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Vilesov, Aleksandr P., Viktor S. Ledenev, Danil V. Solodov, Aleksandr V. Filichev, Natalya V. Bogomolova, Lyubov I. Makarova, Natalya Ju Grebenkina, Anna G. Kazachkova, and Aleksandr S. Sidubaev. "Upper Paleozoic reef systems of the Rubezhinsky Trough (southern part of the Buzuluk Depression)." PROneft’. Proffessional’no o nefti 6, no. 3 (October 5, 2021): 30–42. http://dx.doi.org/10.51890/2587-7399-2021-6-3-30-42.
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Background. The Rubezhinsky Trough has been remained one of the most poorly studied petroleum areas of the Orenburg region to date. At present, Gazprom Neft conducts systematic exploration work within the trough at five license areas of the South Orenburg Cluster. Aim. The purpose of this article is representation of preliminary new dates on a geological structure of paleozoic reef systems within the Rubezhinsky Trough. Materials and methods. The main original materials for the work are the results of the interpretation of the 3D seismic carried out at four license areas. In addition, results drilling and regional sedimentation models were involved for analysis. Results. Regional models of Upper Paleozoic reef systems of the Rubezhinsky Trough have been extensively detailed as a result of the interpretation of 3-D seismic data within the South Orenburg cluster. It was first established that isolated reefs were formed in the interval of the Ardatovian and Mullinian regional stages (Givetian Stage of Middle Devonian) of the research area. Ardatovian-mullinian isolated reefs are covered with clay deposits and represent potential lithological traps for petroleum deposits. Isolated reefs, isolated carbonate platforms and the southern margin of the vast South-Buzuluk carbonate platform with barrier reef systems have been identified for the Frasnian Stage. Isolated frasnian reefs are potential hydrocarbon traps. Barrier frasnian reefs together with increasing them early famennian ones form a series of structural hydrocarbon traps in the overlapping complexes. The significant progradation of the margin of the famennian carbonate platform towards the Pre-Caspian paleobasin is established. Famennian progradation complexes form several large clinoforms which are potentially forward looking for the search for structural-lithological petroleum traps. The barrier reef system has been confirmed for the evaporite-carbonate complex of the Okskian regional stage. Okskian reefs border the late visean epicratonic carbonate platform. Relatively large reefs of the carbonate platform barrier system were identified in the interval from Podolskian regional stage (Carboniferous) to Asselian Stage (Permian). This barrier system has progradational architectures towards the Pre-Caspian paleobasin that was formed from the end of the Middle Carboniferous to the end of the Artinskian Age of the Early Permian. Podolskian-asselian barrier buildings predefine the development of structural hydrocarbon traps of various sizes in overlapping Lower Permian deposits. Conclusions. A preliminary analysis of 3-D seismic data indicates the significant role of the paleozoic reef systems in the formation of the sedimentary complex of the Rubezhinsky trough.
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Vilesov, Aleksandr P., Viktor S. Ledenev, Danil V. Solodov, Aleksandr V. Filichev, Natalya V. Bogomolova, Lyubov I. Makarova, Natalya Ju Grebenkina, Anna G. Kazachkova, and Aleksandr S. Sidubaev. "Upper Paleozoic reef systems of the Rubezhinsky Trough (southern part of the Buzuluk Depression)." PROneft’. Proffessional’no o nefti 6, no. 3 (October 5, 2021): 30–42. http://dx.doi.org/10.51890/2587-7399-2021-6-3-30-42.
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Background. The Rubezhinsky Trough has been remained one of the most poorly studied petroleum areas of the Orenburg region to date. At present, Gazprom Neft conducts systematic exploration work within the trough at five license areas of the South Orenburg Cluster. Aim. The purpose of this article is representation of preliminary new dates on a geological structure of paleozoic reef systems within the Rubezhinsky Trough. Materials and methods. The main original materials for the work are the results of the interpretation of the 3D seismic carried out at four license areas. In addition, results drilling and regional sedimentation models were involved for analysis. Results. Regional models of Upper Paleozoic reef systems of the Rubezhinsky Trough have been extensively detailed as a result of the interpretation of 3-D seismic data within the South Orenburg cluster. It was first established that isolated reefs were formed in the interval of the Ardatovian and Mullinian regional stages (Givetian Stage of Middle Devonian) of the research area. Ardatovian-mullinian isolated reefs are covered with clay deposits and represent potential lithological traps for petroleum deposits. Isolated reefs, isolated carbonate platforms and the southern margin of the vast South-Buzuluk carbonate platform with barrier reef systems have been identified for the Frasnian Stage. Isolated frasnian reefs are potential hydrocarbon traps. Barrier frasnian reefs together with increasing them early famennian ones form a series of structural hydrocarbon traps in the overlapping complexes. The significant progradation of the margin of the famennian carbonate platform towards the Pre-Caspian paleobasin is established. Famennian progradation complexes form several large clinoforms which are potentially forward looking for the search for structural-lithological petroleum traps. The barrier reef system has been confirmed for the evaporite-carbonate complex of the Okskian regional stage. Okskian reefs border the late visean epicratonic carbonate platform. Relatively large reefs of the carbonate platform barrier system were identified in the interval from Podolskian regional stage (Carboniferous) to Asselian Stage (Permian). This barrier system has progradational architectures towards the Pre-Caspian paleobasin that was formed from the end of the Middle Carboniferous to the end of the Artinskian Age of the Early Permian. Podolskian-asselian barrier buildings predefine the development of structural hydrocarbon traps of various sizes in overlapping Lower Permian deposits. Conclusions. A preliminary analysis of 3-D seismic data indicates the significant role of the paleozoic reef systems in the formation of the sedimentary complex of the Rubezhinsky trough.
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Sobolev, P. N., and S. V. Dykhan. "OIL-AND-GAS SOURCE ROCKS AND THE PROBLEM OF PETROLEUM POTENTIAL OF THE ALDAN-MAYA DEPRESSION (SOUTH-EAST OF THE SIBERIAN PLATFORM)." Geology and mineral resources of Siberia, no. 3 (October 2022): 30–38. http://dx.doi.org/10.20403/2078-0575-2022-3-30-38.
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The analysis of existing understandings about distribution of oil-and-gas source rocks was performed for sedimentary section of the Aldan-Maya depression, the large margin structure in the south-east of the Siberian Platform. Taking into account new materials, the oil-and-gas generating potential of these strata was critically examined, and the ideas of previous research period were defined more precisely. On this basis, the sketch map of oil-and-gas bearing stratigraphic breakdown of the Aldan-Maya depression sedimentary cover was compiled. The main elements of hydrocarbon systems, including predicted petroleum plays and petroleum bearing strata were identified, forecast of possible types of traps for various parts of the depression was given. Based on this experience, the contour map of the petroleum potential forecast for the Aldan-Maya depression and adjacent territories was compiled.
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Mukhopadhyay, Dilip K. "Petroleum System in Indian Collision Zone: Perspective from Structural Geology." Journal of the Geological Society of India 94, no. 5 (November 2019): 549. http://dx.doi.org/10.1007/s12594-019-1356-9.
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Carlsen, G. M., A. P. Simeonova, and S. N. Apak. "PETROLEUM SYSTEMS AND EXPLORATION POTENTIAL IN THE OFFICER BASIN, WESTERN AUSTRALIA." APPEA Journal 43, no. 1 (2003): 473. http://dx.doi.org/10.1071/aj02025.
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The Officer Basin in Western Australia contains a variety of hydrocarbon plays associated with compressional, halokinetic, unconformity and stratigraphic traps. Five distinct structural zones have been defined in the basin—a northeastern Marginal Overthrusted Zone, a northeastern Salt-ruptured Zone, a central Thrusted Zone, a Western Platform and a complex salt-dominated Minibasins Zone. These zones, together with salt-associated and sub-salt structure, are well delineated on about 2,900 km of reprocessed 1980s vintage seismic data, now publicly released.Neoproterozoic rocks are marginally to fully mature for oil generation on the Western Platform and immature to overmature for different levels of the succession in the Salt-ruptured and Thrusted zones. Geochemical modelling indicates that the main phases of oil generation vary from different stratigraphic intervals and different parts of the Neoproterozoic basin with peaks during the latest Neoproterozoic, Cambrian, and Permian–Triassic. A variety of hydrocarbon shows have been recorded in each of the structural zones. The most recent, a gas show recorded in the stratigraphic well Vines–1 indicates the presence of potentially effective petroleum systems in the unexplored Waigen area of the Marginal Overthrusted Zone.A wide variety of trap styles have been identified, associated with normal faults, thrust faults, thrust ramp folds, compressive folds, fault tip folds, sub-salt plays, unconformity truncations, pinchouts, lateral facies changes, erosive channels and valleys, fractured carbonates and halokinetic traps. Most of these trap styles are poorly tested or untested.
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Köster, J., and H. Kulke. "Structural and tectonic modelling and its application to petroleum geology." Tectonophysics 227, no. 1-4 (November 1993): 226–27. http://dx.doi.org/10.1016/0040-1951(93)90098-5.
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Sidorchuk, E. A., and M. E. Seliverstova. "Evaporite rocks as a factor in formation of non-structural traps." SOCAR Proceedings, SI2 (December 30, 2021): 59–65. http://dx.doi.org/10.5510/ogp2021si200547.
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The paper considers the improvement in classification of oil and gas traps formed in non-anticlinal conditions. The relevant aim is to expand the areas where hydrocarbon accumulations are searched for and to take into account the new search attributes. Evaporite rocks, widely developed in many oil and gas basins, have properties that contribute to the preservation of hydrocarbon deposits. Depending on the structural features of the salt formations, their impact on the location of oil and gas deposits varies. The deposits associated with the evaporite rocks are analyzed. Types of traps, the main factor in formation of which are evaporites, are defined. Such traps are proposed to be treated as a separate category. Keywords: evaporite rocks; non-structural and combined traps; hydrocarbon accumulations; classifications of traps; tectonic style; sealed reservoirs.
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Sitnikov, V. S., R. F. Sevostyanova, and K. A. Pavlova. "EVOLUTION OF CONCEPTS ABOUT THE STRUCTURE OF OIL AND GAS TRAPS IN THE STUDY OF PETROLEUM BEARING SUBSURFACE RESOURCES IN WESTERN YAKUTIA." Geology and mineral resources of Siberia, no. 1 (2021): 49–55. http://dx.doi.org/10.20403/2078-0575-2021-1-49-55.
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The article presents the development history of the oil and gas industry in the Republic of Sakha (Yakutia). It is shown that during the first seismic exploration, prospecting for fields was carried out exclusively in the lower reaches of the Vilyui River. These works made it possible to identify the large Khapchagai gas region in Mesozoic deposits in the eastern Vilyui syneclise and discover a number of gas fields. Traps on them are typical platform structures - brachyanticlines with first degrees of dips, without any traces of disjunctive tectonic dislocations. The latter are predicted here lower in the section, starting from the Permian top. Scientific concepts of oil and gas traps revealed in various years in Western Yakutia in the course of geological exploration, from the period of inition of the oil and gas geophysical service in the republic (1950) to the present, are considered. The evolution of concepts of the oil and gas trap structure is shown, using the example of Srednebotuobinskoye and Verkhnevilyuchanskoye fields. This evolution was carried out in the process of geological exploration due to a more complete record-keeping of disjunctive disllocations and their role in the structure of traps.
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Pitman, Janet K., Douglas Steinshouer, and Michael D. Lewan. "Petroleum generation and migration in the Mesopotamian Basin and Zagros Fold Belt of Iraq: results from a basin-modeling study." GeoArabia 9, no. 4 (October 1, 2004): 41–72. http://dx.doi.org/10.2113/geoarabia090441.
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ABSTRACT A regional 3-D total petroleum-system model was developed to evaluate petroleum generation and migration histories in the Mesopotamian Basin and Zagros fold belt in Iraq. The modeling was undertaken in conjunction with Middle East petroleum assessment studies conducted by the USGS. Regional structure maps, isopach and facies maps, and thermal maturity data were used as input to the model. The oil-generation potential of Jurassic source-rocks, the principal known source of the petroleum in Jurassic, Cretaceous, and Tertiary reservoirs in these regions, was modeled using hydrous pyrolysis (Type II-S) kerogen kinetics. Results showed that oil generation in source rocks commenced in the Late Cretaceous in intrashelf basins, peak expulsion took place in the late Miocene and Pliocene when these depocenters had expanded along the Zagros foredeep trend, and generation ended in the Holocene when deposition in the foredeep ceased. The model indicates that, at present, the majority of Jurassic source rocks in Iraq have reached or exceeded peak oil generation and most rocks have completed oil generation and expulsion. Flow-path simulations demonstrate that virtually all oil and gas fields in the Mesopotamian Basin and Zagros fold belt overlie mature Jurassic source rocks (vertical migration dominated) and are situated on, or close to, modeled migration pathways. Fields closest to modeled pathways associated with source rocks in local intrashelf basins were charged earliest from Late Cretaceous through the middle Miocene, and other fields filled later when compression-related traps were being formed. Model results confirm petroleum migration along major, northwest-trending folds and faults, and oil migration loss at the surface.
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Apak, S. N., W. J. Stuart, and N. M. Lemon. "STRUCTURAL-STRATIGRAPHIC DEVELOPMENT OF THE GIDGEALPA-MERRIMELIA-INNAMINCKA TREND WITH IMPLICATIONS FOR PETROLEUM TRAP STYLES, COOPER BASIN, AUSTRALIA." APPEA Journal 33, no. 1 (1993): 94. http://dx.doi.org/10.1071/aj92008.
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A successful approach to basin analysis requires the broad-scale reconstruction of the three dimensional depositional systems in relation to concurrent structural development of the basin. The Gidgealpa-Merrimelia-lnnamincka (GMI) Trend is a prominent, asymmetric, mildly compressional anticlinal trend located in the Late Carboniferous to Triassic Cooper Basin. Its northwest flank is controlled by high angle thrust faults which were reactivated repeatedly throughout geological time. The present study addresses both the structural style and depositional character of the GMI Trend, focusing on selected areas. It is an integrated approach utilising wire-line logs, seismic interpretation, isopach and structural maps and detailed palynology. This approach has produced a detailed chronostratigraphic subdivision of the Permo-Triassic sequence, particularly the Patchawarra Formation, which points to evidence of synsedimentary tectonics. Evidence from crestal unconformities suggests that the GMI Trend was uplifted during at least four distinct structural episodes. These phases of uplift result from the rejuvenation of pre-Permian faults. Regional investigation of chronostratigraphic units incorporating palynological information, clearly demonstrates the palaeogeography and the presence of internal unconformities within the Patchawarra Formation. Subsurface distribution of hydrocarbon pools and improved definition of areas of prospectivity relate to the episodic uplifts. Although known hydrocarbon reserves have largely accumulated in structural traps, additional potential exploration targets in the Permian sequence exist in stratigraphic, combination, pinchout and downflank fault traps as well as onlap plays along the mid flank areas of the GMI Trend.
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Botor, Dariusz. "Burial and Thermal History Modeling of the Paleozoic–Mesozoic Basement in the Northern Margin of the Western Outer Carpathians (Case Study from Pilzno-40 Well, Southern Poland)." Minerals 11, no. 7 (July 6, 2021): 733. http://dx.doi.org/10.3390/min11070733.
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Hydrocarbon exploration under thrust belts is a challenging frontier globally. In this work, 1-D thermal maturity modeling of the Paleozoic–Mesozoic basement in the northern margin of the Western Outer Carpathians was carried out to better explain the thermal history of source rocks that influenced hydrocarbon generation. The combination of Variscan burial and post-Variscan heating due to elevated heat flow may have caused significant heating in the Paleozoic basement in the pre-Middle Jurassic period. However, the most likely combined effect of Permian-Triassic burial and Late Triassic–Early Jurassic increase of heat flow caused the reaching of maximum paleotemperature. The main phase of hydrocarbon generation in Paleozoic source rocks developed in pre-Middle Jurassic times. Therefore, generated hydrocarbons from Ordovician and Silurian source rocks were lost before reservoirs and traps were formed in the Late Mesozoic. The Miocene thermal overprint due to the Carpathian overthrust probably did not significantly change the thermal maturity of organic matter in the Paleozoic–Mesozoic strata. Thus, it can be concluded that petroleum accumulations in the Late Jurassic and Cenomanian reservoirs of the foreland were charged later, mainly by source rocks occurring within the thrustbelt, i.e., Oligocene Menilite Shales. Finally, this work shows that comprehensive mineralogical and geochemical studies are an indispensable prerequisite of any petroleum system modelling because their results could influence petroleum exploration of new oil and gas fields.