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1
Postma, George. "The geology of fluvial deposits, sedimentary facies, basin analysis and petroleum geology." Sedimentary Geology 110, no. 1-2 (May 1997): 149–50. http://dx.doi.org/10.1016/s0037-0738(96)00081-4.
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Roberts, David G. "Sedimentary basins and petroleum geology of the Middle East." Marine and Petroleum Geology 16, no. 4 (June 1999): 379. http://dx.doi.org/10.1016/s0264-8172(99)00008-2.
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Bosence, Dan. "Sedimentary basins and petroleum geology of the middle east." Journal of African Earth Sciences 28, no. 3 (April 1999): 769–71. http://dx.doi.org/10.1016/s0899-5362(99)00046-9.
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WANG, An Sheng, and Noriyuki SUZUKI. "Petroleum geology and geochemistry of Paleogene Nan Xiang lacustrine sedimentary basin, China." Journal of the Japanese Association for Petroleum Technology 57, no. 5 (1992): 415–26. http://dx.doi.org/10.3720/japt.57.415.
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Cook, R. A., E. M. Crouch, J. I. Raine, C. P. Strong, C. I. Uruski, and G. J. Wilson. "INITIAL REVIEW OF THE BIOSTRATIGRAPHY AND PETROLEUM SYSTEMS AROUND THE TASMAN SEA HYDROCARBON-PRODUCING BASINS." APPEA Journal 46, no. 1 (2006): 201. http://dx.doi.org/10.1071/aj05012.
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Understanding the genesis and habitat of hydrocarbons in a sedimentary basin takes knowledge of that basin at many levels, from basic infill geology to petroleum systems, plays, prospects and detailed sequence stratigraphy. While geophysics can define the basins and their internal structures, biostratigraphy and paleogeography provide greater understanding of basin geology. Micropaleontology and palynology are the chief tools that we need to define both the environment and dimension of time.As an example, the reconstruction of the Tasman Sea region to the mid-Cretaceous (ca 120 Ma) shows that the hydrocarbon-producing Gippsland and Taranaki petroleum basins developed at similar latitudes and in similar geological contexts. Other basins within the region have been lightly explored and need evaluation as to the value of further exploration.As paleontology has developed separately in Australia and New Zealand, comparison of biostratigraphic zones and their chronostratigraphy is critical to understand the similarity or otherwise of the sedimentary record of the two regions. Recent refinement of the NZ timescale and comparative studies on Gippsland Basin wells by NZ paleontologists have provided some key insights that enable us to compare the geological history of both regions more closely, and to recognise similarities in petroleum systems that may enhance petroleum prospects on both sides of the Tasman Sea.
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Drachev, Sergey S. "Chapter 25 Tectonic setting, structure and petroleum geology of the Siberian Arctic offshore sedimentary basins." Geological Society, London, Memoirs 35, no. 1 (2011): 369–94. http://dx.doi.org/10.1144/m35.25.
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Chalmers, J. A., T. Dahl-Jensen, K. J. Bate, and R. C. Whittaker. "Geology and petroleum prospectivity of the region offshore southern West Greenland – a summary." Rapport Grønlands Geologiske Undersøgelse 165 (January 1, 1995): 13–21. http://dx.doi.org/10.34194/rapggu.v165.8272.
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Since 1987, the Geological Survey of Greenland (GGU) has been engaged in a re-assessment of the geology and petroleum potential of the region offshore southern West Greenland. In I994, a milestone was reached in this study when, for the first time, a fairly complete understanding of the regional structure and stratigraphy of all of the sedimentary basins and the continental margin off shore southern West Greenland was achieved. This paper presents an account of how the work was carried out and gives a summary of the geological results. Due to the area being offshore, its investigation required the interpretation of geophysical data, primarily seismic data, tied to boreholes.
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Wang, Bing, Harry Doust, and Jingyan Liu. "Geology and Petroleum Systems of the East China Sea Basin." Energies 12, no. 21 (October 26, 2019): 4088. http://dx.doi.org/10.3390/en12214088.
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The back-arc East China Sea Basin lies on extended continental crust at the leading edge of the Eurasian plate. In this study, the basins are described and subdivided according to their tectono-stratigraphic evolution. In order to distinguish between different phases of deformation in basin development, standard basin evolution patterns related to geodynamic drivers are identified as a first step. On the basis of this, standard patterns are recognized in the sedimentary sequences that characterize the area and its tectonic evolution, and linking them to the petroleum systems present is attempted. This is achieved by characterizing and grouping them into basin cycle-related petroleum system types (PSTs). Finally, the development of plays is examined within the petroleum systems in the context of their tectono-stratigraphic evolution, and groups of sub-basins with similar geological history and, therefore, potentially similar petroleum prospectivity are identified. In the East China Sea Basin, four proven and potential PSTs were recognized: (1) Late Cretaceous to Paleocene oil/gas-prone early syn-rift lacustrine–deltaic PST; (2) Eocene gas/oil prone late syn-rift marine PST; (3) Oligocene to Middle Miocene gas/oil-prone early post-rift fluvial–deltaic PST; (4) gas-prone syn-rift turbiditic PST. The geology and petroleum systems of three major sub-basins of the East China Sea Basin, the Xihu Sub-basin, the Lishui Sub-basin, and Okinawa Trough, are discussed in detail, and their petroleum systems and play development are analyzed. Finally, the sub-basins are grouped into “basin families” distinguished by their tectono-stratigraphic development, namely, Northwest to Northeast Shelf Basin (NWSB–NESB), Southwest to Southeast Shelf Basin (SWSB–SESB), and Okinawa Trough basin families, respectively.
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Yarboboev, T., Sh Akhmedov, and K. Usmonov. "Features of Distribution of Oil and Gas Deposits in the Earth’s Crust." Bulletin of Science and Practice 6, no. 8 (August 15, 2020): 135–44. http://dx.doi.org/10.33619/2414-2948/57/11.
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Hydrocarbon deposits within oil and gas-bearing territories are distributed very unevenly both in area and in the section of sedimentary deposits, which is the main geological feature of oil and gas placement in the subsurface. The formation of hydrocarbon accumulations in the sedimentary cover is due to a set of genetic factors, which ultimately determines the patterns of placement of oil and gas accumulations along the section and area of the sedimentary cover. The study of the factors determining the zonation of oil and gas accumulation and genetically her condition, zoning of oil and gas formation, contributes not only to expanding our knowledge on the fundamental problems of petroleum geology, but also improve the efficiency of exploration.
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Drachev, Sergey S. "Erratum to Chapter 25 Tectonic setting, structure and petroleum geology of the Siberian Arctic offshore sedimentary basins." Geological Society, London, Memoirs 35, no. 1 (2011): 819. http://dx.doi.org/10.1144/m35.25err.
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Kivior, Irena, Stephen Markham, Leslie Mellon, and David Boyd. "Mapping geology beneath volcanics using magnetic data." APPEA Journal 58, no. 2 (2018): 821. http://dx.doi.org/10.1071/aj17205.
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Volcanic layers within sedimentary basins cause significant problems for petroleum exploration because the attenuation of the seismic signal masks the underlying geology. A test study was conducted for the South Australia Government to map the thickness of volcanics and sub-volcanic geology over a large area in the Gawler Range Volcanics province. The area is covered by good quality magnetic data. The thickness of volcanics and basement configuration was unknown as there has only been a limited amount of drilling. The Automatic Curve Matching (ACM) method was applied to located magnetic data and detected magnetic sources within different rock units, providing their depth, location, geometry and magnetic susceptibility. The magnetic susceptibilities detected by ACM allowed the differentiation of the volcanics and the underlying basement. The base of volcanics and the depth to the top of basement was mapped along 75 km NS profiles, that were spaced 1 km apart over a distance of 220 km. The volcanic and basement magnetic susceptibilities and the magnetic source distribution pattern were used as key determinants to interpret the depth to the two interfaces. The results for each interface were gridded, and images of the base of volcanics and depth to basement were generated. The mapped volcanics thickness was validated by comparison with the results from drilling, with the volcanics thickness matching very well. After project completion, a passive seismic survey was conducted in part of the test area, indicating a base of volcanics of ~4 km, which further confirmed the results.
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Mustaev, R. N., E. A. Lavrenova, V. Yu Kerimov, and R. A. Mamedov. "Peculiarities of Tertiary petroleum systems evolution under prograding shelf environment on the continental margin of the East Siberian Sea." Journal of Petroleum Exploration and Production Technology 11, no. 10 (September 4, 2021): 3617–26. http://dx.doi.org/10.1007/s13202-021-01280-5.
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AbstractThe upper part of the sedimentary cover within the East Siberian Sea shelf comprises Cenozoic clinoform deposits, which accumulated in passive continental margin settings. In the Eastern Arctic, the productivity of clinoform deposits has been proved on the Alaska North Slope and in the Beaufort–Mackenzie Basin. Considering that Cenozoic clinoform deposits are widely represented in the Russian part of the Eastern Arctic, they undoubtedly attract considerable interest from the standpoint of hydrocarbons prospecting. However, despite increasingly closer attention to this interval of the sedimentary section, it is still poorly understood due to its complicated geology. The lack of drilled wells in the region imposes a considerable limitation on an understanding of sedimentary basins development. In this situation, geophysical data become the primary source of information for building geologic models in the Russian sector of the Eastern Arctic. An assessment of hypothetical Cenozoic petroleum systems of the East Siberian Sea is the main objective of this paper. It is to be said research performed under high uncertainty of input data. The results obtained from basin analysis and numerical modeling indicate the possibility that an active petroleum system may exist in the Cenozoic sedimentary wedge of the East Siberian Sea. The outlook for the clinoform complex largely depends on the source rock maturity, i.e., higher prospects should be expected in areas where the prograding wedge has maximum thickness. Considering all factors (reservoir quality prediction, proximity to a hydrocarbon kitchen, timing), the Eocene–Oligocene part of the sedimentary section appears to offer the greatest promise within the study area. Here, predominantly oil accumulations may be expected at a depth of 2.5–3.5 km below sea bottom.
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Zhemchugova, Valentina A., Vadim V. Rybalchenko, and Tatiana A. Shardanova. "Sequence-stratigraphic model of the West Siberia Lower Cretaceous." Georesursy 23, no. 2 (May 25, 2021): 179–91. http://dx.doi.org/10.18599/grs.2021.2.18.
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Apparently, conceptual base of the sequence stratigraphy is one of the most acknowledged methodologies in the geological world at the present time for the sedimentary strata structure prediction. It is based on the complex analysis of the seismic, stratigraphic and sedimentary data on the depositional bodies where the structure and facies filling is regulated by the relative sea level changes. The Lower Cretaceous section of the Western Siberia in this regard is the unique object, as it is represented by the full range of the clastic depositional environments – from relatively deep-water to the continental, which are very sensitive to the conditions changes. Sequence-stratigraphic analysis results can be used to complete the pragmatic tasks in the petroleum geology as the analysis is based on the reconstruction of the sedimentogenesis processes in the past, and the understanding of that processes is the key to the generalized depositional model development. This model can be used to create the models, which can be applied to the unique local objects that occur in the Lower Cretaceous section.
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Fang, Xi Rui, and Shi Zhong Ma. "Hydrocarbon Accumulation Model of Four Blocks in Qijia-Gulong Depression." Advanced Materials Research 868 (December 2013): 207–11. http://dx.doi.org/10.4028/www.scientific.net/amr.868.207.
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Qijia-Gulong concave slope area is a succession nose shape structure slope as well as Qijia-Gulong depression of Songliao basin developing process, Putaohua formation is most important contains oil goal formation in this area center lower part to contain oil combines, since long ago, the forming law is not unclear to be recognized, based on the theories and means of sedimentology, sequence stratigraphy, petroleum geology and so on, from the fine research of palaeostructure, sequence frame work sedimentary facies, forming period, hydrocarbon water distribution, trap type, and generalize on hydrocarbon forming pattern and enrichment law, pointed out new objects and orientation of exploration and development, had important instruction significance of hydrocarbon genesis of Qijia-Gulong depression.
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Thanh, Nguyen Trung, Paul Jing Liu, Mai Duc Dong, Dang Hoai Nhon, Do Huy Cuong, Bui Viet Dung, Phung Van Phach, Tran Duc Thanh, Duong Quoc Hung, and Ngo Thanh Nga. "Late Pleistocene-Holocene sequence stratigraphy of the subaqueous Red River delta and the adjacent shelf." VIETNAM JOURNAL OF EARTH SCIENCES 40, no. 3 (June 4, 2018): 271–87. http://dx.doi.org/10.15625/0866-7187/40/3/12618.
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The model of Late Pleistocene-Holocene sequence stratigraphy of the subaqueous Red River delta and the adjacent shelf is proposed by interpretation of high-resolution seismic documents and comparison with previous research results on Holocene sedimentary evolution on the delta plain. Four units (U1, U2, U3, and U4) and four sequence stratigraphic surfaces (SB1, TS, TRS and MFS) were determined. The formation of these units and surfaces is related to the global sea-level change in Late Pleistocene-Holocene. SB1, defined as the sequence boundary, was generated by subaerial processes during the Late Pleistocene regression and could be remolded partially or significantly by transgressive ravinement processes subsequently. The basal unit U1 (fluvial formations) within incised valleys is arranged into the lowstand systems tract (LST) formed in the early slow sea-level rise ~19-14.5 cal.kyr BP, the U2 unit is arranged into the early transgressive systems tract (E-TST) deposited mainly within incised-valleys under the tide-influenced river to estuarine conditions in the rapid sea-level rise ~14.5-9 cal.kyr BP, the U3 unit is arranged into the late transgressive systems tract (L-TST) deposited widely on the continental shelf in the fully marine condition during the late sea-level rise ~9-7 cal.kyr BP, and the U4 unit represents for the highstand systems tract (HST) with clinoform structure surrounding the modern delta coast, extending to the water depth of 25-30 m, developed by sediments from the Red River system in ~3-0 cal.kyr BP.ReferencesBadley M.E., 1985. Practical Seismic Interpretation. International Human Resources Development Corporation, Boston, 266p.Bergh G.D. 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Journal of Asian Earth Sciences, 23, 113-126.Hanebuth T.J.J., Voris H.K.., Yokoyama Y., Saito Y., Okuno J., 2011. Formation and fate of sedimentary depocenteres on Southeast Asia’s Sunda Shelf over the past sea-level cycle and biogeographic implications. Eath-Science Reviews, 104, 92-110.Hanebuth T., Stattegger K and Grootes P. M., 2000. Rapid flooding of the Sunda Shelf: a late-glacial sea-level record. Science, 288, 1033-1035.Helland-Hansen W and Gjelberg, J.G., 1994. Conceptual basis and variability in sequence stratigraphy: a different perspective. Sedimentary Geology, 92, 31-52.Hori K., Tanabe S., Saito Y., Haruyama S., Nguyen V., Kitamura., 2004. Delta initiation and Holocene sea-level change: example from the Song Hong (Red River) delta, Vietnam. Sedimentary Geology, 164, 237-249.Hunt D. and Tucker M.E., 1992. Stranded parasequences and the forced regressive wedge systems tract: deposition during base-level fall. Sedimentology Geology, 81, 1-9.Hunt D. and Tucker M.E., 1995. Stranded parasequences and the forced regressive wedge systems tract: deposition during base-level fall-reply. Sedimentary Geology, 95, 147-160.Lam D.D. and Boyd W.E., 2000. Holocene coastal stratigraphy and model for the sedimentary development of the Hai Phong area in the Red River delta, north Vietnam. Journal of Geology (Series B), 15-16, 18-28.Lieu N.T.H., 2006. Holocene evolution of the Central Red River Delta, Northern Vietnam. PhD thesis of lithological and mineralogical in Germany, 130p.Luu T.N.M., Garnier J., Billen G., Orange D., Némery J., Le T.P.Q., Tran H.T., Le L.A., 2010. Hydrological regime and water budget of the Red River Delta (Northern Vietnam). Journal of Asian Earth Sciences, 37, 219-228.Mather S.J., Davies J., Mc Donal A., Zalasiewicz J.A., and Marsh S., 1996. The Red River Delta of Vietnam. British Geological Survey Technical Report WC/96/02, 41p.Mathers S.J. and Zalasiewicz J.A.,1999. Holocene sedimentary architecture of the Red River delta, Vietnam. Journal of Coastal Research, 15, 314-325.Milliman J.D. and Mead R.H., 1983. Worldwide delivery of river sediment to the oceans. Journal of Geology, 91, 1-21.Milliman J.D and Syvitski J.P.M., 1992. Geomorphic/tectonic control of sediment discharge to the Ocean: the importance of small mountainous rivers. Journal of Geology, 100, 525-544.Mitchum Jr. R.M., Vail P.R., 1977. Seismic stratigraphy and global changes of sea-level. Part 7: stratigraphic interpretation of seismic reflection patterns in depositional sequences. In: Payton C.E. (Ed.), Seismic Stratigraphy-Applications to Hydrocarbon Exploration, A.A.P.G. Memoir, 26, 135-144.Nguyen T.T., 2017. Late Pleistocene-Holocene sedimentary evolution of the South East Vietnam Shelf, PhD thesis (in Vietnamese), Hanoi University of Science, Vietnam, 169p.Nummedal D., Riley G.W., Templet P.T., 1993. High-resolution sequence architecture: a chronostratigraphic model based on equilibrium profile studies. 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Transgressive and highstand systems tracts and post-glacial transgression, the East China Sea. Sedimentary Geology, 122, 217-232.Stattegger K., Tjallingii R., Saito Y., Michelli M., Nguyen T.T., Wetzel A., 2013. Mid to late Holocene sea-level reconstruction of Southeast Vietnam using beachrock and beach-ridge deposits. Global and Planetary Change, 110, 214-222.Tanabe S., Hori K., Saito Y., Haruyama S., Doanh L.Q., Sato Y., Hiraide S., 2003a. Sedimentary facies and radiocarbon dates of the Nam Dinh-1 core from the Song Hong (Red River) delta, Vietnam. Journal of Asian Earth Sciences, 21, 503-513.Tanabe S., Hori K., Saito Y., Haruyama S., Phai V.V., Kitamura A., 2003b. Song Hong (Red River) delta evolution related to millennium-scale Holocene sea-level changes. Quaternary Science Reviews, 22(21-22), 2345-2361.Tanabe S., Saito Y., Lan V.Q., Hanebuth T.J.J., Lan N.Q., Kitamura A., 2006. Holocene evolution of the Song Hong (Red River) delta system, northern Vietnam. 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Handbook of geophysical exploration, Elsevier, Oxford, 37509p.Yoo D.G., Kim S.P., Chang T.S., Kong G.S., Kang N.K., Kwon Y.K., Nam S.L., Park S.C., 2014. Late Quaternary inner shelf deposits in response to late Pleistocene-Holocene sea-level changes: Nakdong River, SE Korea. Quaternary International, 344, 156-169.
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Stocklin, Jovan. "Developments in the geological exploration of Nepal." Journal of Nepal Geological Society 38 (November 2, 2008): 49–54. http://dx.doi.org/10.3126/jngs.v38i0.32642.
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Prior to 1950, only sporadic geological observations by a few visitors were made in Nepal. With the opening of the country to foreigners in 1950, Nepal soon came into the focus of interest in Himalayan geology. It was the time of the classical "descriptive geology" with mapping as the primary objective. Several excellent monographs and the first geological maps of different parts of the Nepal Himalaya were produced. The best results were obtained in the richly fossiliferous "Tibetan" sedimentary zone in the north, whereas descriptions of the Central Crystalline zone and of the thick, unfossiliferous metasediments of the Lesser Himalaya reflected mainly the widely differing interpretations and conflicting views of the investigators; nappe structure vs. block tectonics was the main issue. ..
With the advent of plate tectonics in the late 1960s, the Himalaya became the "collided range". Microstructural, mineralogical and geochemical studies in the search for stress and heat effects of subduction and collision on structure, metamorphism and magmatism became dominant and in Nepal concentrated on the Main Central Thrust, which was treated in terms of post collisional continental subduction. With it went a shift of emphasis from field to laboratory work, from observation to interpretation, from mapping to modelling, from fact to theory.
The last thirty years were characterised by the strengthening and diversification of geological institutions in Nepal with the creation of a National Seismological Centre, the beginning of petroleum exploration in the southern foreland of the Himalaya, an intensification and modernisation of classical geological surveying and a strong engagement in the application of geology for engineering and natural hazard assessment purposes.
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Alberts, L. J. H., C. R. Geel, and J. J. Klasen. "Reservoir characterisation using process-response simulations: the Lower Cretaceous Rijn Field, West Netherlands Basin." Netherlands Journal of Geosciences - Geologie en Mijnbouw 82, no. 4 (December 2003): 313–24. http://dx.doi.org/10.1017/s001677460002014x.
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AbstractPetroleum geologists always need to deal with large gaps in data resolution and coverage during reservoir characterisation. Seismic data show only large geological structures, whereas small-scale structures and reservoir properties can be observed only at well locations. In the area between wells, these properties are often estimated by means of geostatistics. Numerical simulation of sedimentary processes offers an alternative method to predict these properties and can improve the understanding of the controls on reservoir heterogeneity. Although this kind of modelling is widely used on basin scale in exploration geology, its application on field scale in production geology is virtually non-existent. We have assessed whether the recent developments in numerical modelling can also aid petroleum geologists in the interpretation of the reservoir geology.Seismic data, well data and a process-response model for coastal environments were used to characterise the Lower Cretaceous oil-bearing Rijn Field. Interpretation of seismic and well data led to a definition of the structural setting and the depositional model of the Rijn Member in the area. From the sedimentological interpretation the sea-level history could be estimated, which is the one of the most important input parameters for the process-response model.Application of the process-response simulator to the Rijn Field resulted in approval of the depositional model. The output was presented in a 2-dimensional north-south profile, which corresponds very well to the well logs along this section. The results demonstrate that numerical simulations of geological processes can be very useful as a tool to explore many likely geological scenarios. While it cannot be used to supply a unique solution in many cases, it forms a helpful guide during reservoir characterisation to find an optimal scenario of the controls on deposition of the Rijn Member, which contributes to the understanding of the inter-well reservoir heterogeneity.
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Nichols, Gary. "BIJU-DUVAL, B. 2002. Sedimentary Geology. Sedimentary Basins, Depositional Environments, Petroleum Formation. xiii + 642 pp. Paris: Editions Technip. Price Euros 139.00, US $139.00 (hard covers). ISBN 2 7108 0802 1." Geological Magazine 140, no. 5 (September 2003): 621–22. http://dx.doi.org/10.1017/s0016756803328341.
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Haworth, Jeffrey, and Richard Bruce. "Australian states and Northern Territory acreage update." APPEA Journal 54, no. 1 (2014): 421. http://dx.doi.org/10.1071/aj13042.
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It is encouraging to note that a number of international oil companies (IOCs) have taken an interest in Australian onshore exploration, including the following: Bowen-Surat Basin—BG, ConocoPhillips, CNOOC, PetroChina, Sinopec, KOGAS, Mitsui, Petronas, Shell, and Total.Canning Basin—Mitsubishi, ConocoPhillips, Hess, PetroChina, and Apache.Cooper-Eromanga Basin—BG, and Chevron.Galilee Basin—CNOOC.Georgina Basin—Statoil, and Total. There is now greater interest in Australian onshore exploration, including in a number of sedimentary basins that have previously largely been overlooked. New views on geology and the development of a commercial shale and tight gas sector in the US have prompted a reassessment of onshore petroleum potential, especially in SA, the NT and WA. Access to onshore acreage in Australia for petroleum exploration is, in most jurisdictions, by means of a formal release process with a work program bidding system. Acreage that is being made available for exploration will generally be accompanied by information regarding its geological setting and petroleum prospectivity. Previous exploration activity may be summarised (including information in relation to the amount of pre-existing data available to applicants for acreage), and relevant maps and figures may be included. The following is a compilation of material supplied by the states and NT in relation to onshore acreage being made available for petroleum exploration.
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Tang, Boning, Chuanqing Zhu, Nansheng Qiu, Yue Cui, Sasa Guo, Xin Luo, Baoshou Zhang, Kunyu Li, Wenzheng Li, and Xiaodong Fu. "Analyzing and Estimating Thermal Conductivity of Sedimentary Rocks from Mineral Composition and Pore Property." Geofluids 2021 (March 19, 2021): 1–19. http://dx.doi.org/10.1155/2021/6665027.
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In this study, thermal conductivities of 128 rock samples located in the Xiong’an New Area and Tarim Basin were measured using the optical scanning and transient plane source methods. The thermal conductivities of the Xiong’an New Area samples range from 1.14 to 6.69 W/(m·K), in which the mean thermal conductivities of dolomite and sandstone are 4.95 ± 1.19 and 1.80 ± 0.44 W / m · K , respectively. In the Tarim Basin, sandstone samples have thermal conductivities ranging from 1.21 to 3.56 W/(m·K) with a mean value of 2.51 ± 0.66 W / m · K . The results can provide helpful reference data for studies of geothermics and petroleum geology. Calculation correction and water-saturated measurements were conducted to acquire in situ rock thermal conductivity, and good consistency was found between both. Compaction diagenesis enhances bulk thermal conductivity of sedimentary rocks, particularly sandstones, by decreasing the rock porosity and mineral particle size. Finally, correction factors with respect to mineral grains were proposed to correct the thermal resistance of intergrain contacts and degree of intactness of crystals, and an optimized formula was adopted to calculate the thermal conductivity of sedimentary rock based on rock structure and mineral constituents.
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Kontorovich, V. A., В. V. Lunev, and V. V. Lapkovsky. "GEOLOGICAL AND GEOPHYSICAL CHARACTERISTICS OF THE ANABAR‐KHATANGA OIL AND GAS PROVINCE; NUMERICAL MODELING OF THE PROCESSES OF FORMATION OF SALT DOMES (SIBERIAN SECTOR OF THE RUSSIAN ARCTICS)." Geodynamics & Tectonophysics 10, no. 2 (June 24, 2019): 459–70. http://dx.doi.org/10.5800/gt-2019-10-2-0421.
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The article discusses the geological structure, oil‐and‐gas‐bearing capacities and salt tectogenesis of the Anabar‐Khatanga saddle located on the Laptev Sea shore. In the study area, the platform sediments are represented by the 14‐45 km thick Neoproterozoic‐Mesozoic sedimentary complexes. The regional cross‐sections show the early and middle Devonian salt‐bearing strata and associated salt domes in the sedimentary cover, which may be indicative of potential hydrocarbon‐containing structures. Diapirs reaching the ground surface can be associated with structures capable of trapping hydrocarbons, and typical anticline structures can occur above the domes buried beneath the sediments. In our study, we used the algorithms and software packages developed by A.A. Trofimuk Institute of Petroleum Geology and Geophysics (IPGG SB RAS). Taking into account the structural geological features of the study area, we conducted numerical simulation of the formation of salt dome structures. According to the numerical models, contrasting domes that reached the ground surface began to form in the early Permian and developed most intensely in the Mesozoic, and the buried diapirs developed mainly in the late Cretaceous and Cenozoic.
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Uruski, C., and P. Baillie. "MESOZOIC EVOLUTION OF THE GREATER TARANAKI BASIN AND IMPLICATIONS FOR PETROLEUM PROSPECTIVITY." APPEA Journal 44, no. 1 (2004): 385. http://dx.doi.org/10.1071/aj03014.
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A paradigm of New Zealand petroleum geology was that the oldest source rocks known in the region were of Cretaceous age, so any older sedimentary rocks were considered to be economic basement. Two major projects have revealed that this is not universally the case and that a Jurassic petroleum system should now be considered.Firstly, the Astrolabe 2D speculative survey, acquired by TGS-NOPEC in 2001, has revealed that a significant section underlies the traditional Cretaceous petroleum systems. Secondly, the Wakanui–1 well, drilled by Conoco, Inpex and Todd in 1999, which has recently become open-file, penetrated a Mid-Jurassic coal measure sequence.Jurassic rocks, including coal measure units, are known onshore in New Zealand, They are part of the Murihiku Supergroup, one of the basement terranes comprising the Permian to Cretaceous volcanic arc that forms the basement rocks of the present New Zealand landmass. Wherever they have been seen in outcrop, these rocks generally record low grade metamorphism and have been discounted as petroleum source rocks. Where rocks of the same age were deposited distal to the volcanic arc (and the effects of heat and pressure), however, they may form components of an effective petroleum system.The New Caledonia Basin, extending more than 2,000 km from Taranaki to New Caledonia, may have been the site of a Mesozoic back-arc basin. Jurassic coal measure successions and their equivalent marine units may be locally, or regionally important as source rocks. Implications of a Jurassic petroleum system for prospectivity of the region are investigated.
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Hashimoto, Takehiko, Karen Higgins, Nadege Rollet, Vaughan Stagpoole, Peter Petkovic, Jim Colwell, Ron Hackney, Graham Logan, R. Funnell, and George Bernardel. "Geology and prospectivity of the Capel and Faust basins in the deepwater Tasman Sea region." APPEA Journal 51, no. 2 (2011): 702. http://dx.doi.org/10.1071/aj10082.
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Geoscience Australia recently completed a petroleum prospectivity assessment of the Capel and Faust basins as part of the Australian government's energy security program. This pre-competitive study was carried out in collaboration with GNS Science and the government of New Caledonian, and was based on seismic, potential field, multibeam bathymetry and sample data acquired during marine surveys in 2006–7. The Capel and Faust basins are located in the Tasman Sea region, which contains a number of deepwater basins. There is little information about their geology. The Geoscience Australia study confirmed the existence of large compartmentalised depocentres containing sediments up to 6 km thick. The basins formed during two Cretaceous extensional episodes related to the final breakup of eastern Gondwana. Syn-rift deposition appears to have been initially dominated by volcanics and volcaniclastics, then dominated by non-marine to shallow marine clastics. The post-rift succession comprises upward-fining clastic to calcareous bathyal sediments. A pre-rift (?Mesozoic) sedimentary succession appears to underlie some depocentres. Mesozoic successions in nearby eastern Australian and New Zealand basins suggest that fluvio-deltaic potential source rocks (Triassic/Jurassic to Upper Cretaceous coals) may occur in the pre-rift and syn-rift successions of the Capel and Faust basins. Multi-1D basin modelling suggests that the deeper depocentres are presently within the oil or gas generation window and that expulsion occurred from the Early Cretaceous. Fluvio-deltaic, shoreline and turbiditic sandstones may provide potential reservoirs. Likely play types include large anticlines, fault blocks, unconformities, and stratigraphic pinchouts. The results will guide future exploration and reduce risk in this vast frontier region.
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Galvin, Cyril. "Hutton's Geological Ideas Based on a Sample from His 1795 Theory (Volume I)." Earth Sciences History 23, no. 1 (January 1, 2004): 41–74. http://dx.doi.org/10.17704/eshi.23.1.fq43190528873284.
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Sixty-two examples of Hutton's writing, collected at ten-page intervals from the first volume of his 1795 Theory of the Earth, are the basis of this study. James Hutton (1726-1797) described the planet which is the subject of geology primarily by three words: "earth," sometimes implying the earth of farmers, not the planet of Newton; "globe," often implying the outer spherical shell, rather than the sphere itself; and "world," usually described as the "living world." The most common technical phrase in the book is "bottom of the sea." The most common technical word is "stratum" (or strata). Three axioms guide Hutton's thought: a theoretical axiom that grants validity to knowledge from a metaphysical analysis of causes; an empirical axiom that grants validity to observations of things as they are; and a theological axiom that (combined with his theoretical axiom) requires geology to produce a world designed for farmers. The theoretical and empirical axioms produce conflicts that Hutton resolves by selecting the result that eliminates the importance of low-temperature chemical action. Hutton's empirical observations demonstrate a planet earth whose visible parts are dominated overwhelmingly by sedimentary rocks, but he mistakenly infers that most sedimentary rocks are produced in the deeps of the sea. Hutton emphasizes the process of consolidating sediments into rocks. His consolidation is the process of eliminating pore space from the sediments, primarily by heat and secondarily by pressure. Heat creates "fusion" of rock material, and the resulting liquid rock may be injected into the pore space of sediments. Heat also may soften the particles so that they deform under pressure. Neither consolidation process is valid to any significant extent, circa 2004. Hutton's book yields a synthesized petrology with four classes of rocks: (1) rocks, including solidified lava and unstratified granite, that had been made entirely liquid by heat; (2) rocks, including flint, salt, ironstone, agate, jasper, and some forms of granite and coal, that had achieved their present state from "fusion"; (3) rocks, including most sedimentary and metamorphic rocks, that had been consolidated by heat and pressure; and (4) rocks that had been distilled by heat and pressure (primarily coal, possibly petroleum). Hutton included limestones in (3), correctly considering them to be clastic. The dominance of heat and, secondarily, pressure in Hutton's geophysics reduced the importance of chemical precipitation from aqueous solutions, which Hutton viewed as evidence in favor of the geology of Abraham Gottlob Werner (1749-1817). Volume I of the 1795 Theory is unusually paginated in having five of eight chapters end with page numbers evenly divisible by ten, that is, their last digits are zero. Because there are ten possible last digits, having five out of eight be zero is a statistically rare event (one in 2500). Possibly, this rare event is the result of the publisher's actions. Hutton's 1785 Abstract, which does not bear his or a publisher's name, ends at page 30, and it is identical to both volumes of the 1795 Theory in beginning the text on page 3 and having the same typesetters' code at the base of pages 9, 17, and 25.
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Tooth, Stephen. "Arid geomorphology: emerging research themes and new frontiers." Progress in Physical Geography: Earth and Environment 33, no. 2 (April 2009): 251–87. http://dx.doi.org/10.1177/0309133309338135.
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Research conducted at the interfaces between traditionally disparate academic disciplines can provide fresh perspectives that catalyse novel research approaches and themes. With particular reference to publications from the last few years, this report focuses on a selection of emerging research themes that highlight the growing links between arid geomorphology and other disciplines, including ecology and soil science, sedimentology and petroleum geology, and planetary science. Three themes are addressed: (1) the role of fire in arid geomorphological systems, characterized by investigations that tend to focus on surface processes and landforms at relatively small spatial scales (plot to short channel reach) and short timescales (hours to years); (2) arid fluvial sedimentary systems, characterized by investigations that commonly focus on processes, landforms and sedimentary products at larger spatial scales (channel reach to basin) and longer timescales (years to millions of years); and (3) arid geomorphology on Mars, commonly characterized by process-landform investigations at very large spatial scales (entire physiographic regions to full planetary contexts) and yet longer timescales (millions to billions of years). For each theme, research gaps are identified, which provides an indication of where the research frontier currently lies. In particular, geomorphological research on Mars and other planetary bodies represents a new physical and intellectual frontier that offers great potential for further interplay with Earth landscape studies in arid and other climatic regions. While there are concerns about the present health and direction of geomorphology and physical geography, this rich diversity of themes provides evidence for vigorous and focused research in arid geomorphology.
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Ross, Gerald M. "Introduction to special issue of Canadian Journal of Earth Sciences: The Alberta Basement Transect of Lithoprobe." Canadian Journal of Earth Sciences 37, no. 11 (November 1, 2000): 1447–52. http://dx.doi.org/10.1139/e00-097.
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From outcrops in northeastern Alberta to exposures within structural culminations in the Canadian Cordillera, the crystalline basement that lies buried beneath the Phanerozoic Alberta Basin of western Canada represents a significant part of the Canadian Shield, ca. 750 000 km2. The advent of modern high resolution aeromagnetic data and UPb geochronology have opened the doors for the next era of investigation of the crystalline basement of the Alberta Basin. Aeromagnetic data and geochronology provided important physical and temporal links to the exposed Canadian Shield, which allowed its structural framework to be extrapolated into the subsurface. The most recent chapter in this evolving story has been the Alberta Basement Transects of Lithoprobe, a 12-year program, which has used multi disciplinary geoscience studies to further elucidate the nature, history, and geometric characteristics of basement domains beneath the Alberta Basin. This special issue is the second in a three issue set of publications that synthesize the results of over a decade of Lithoprobe research in the Alberta Basin. The first issue, published in the Bulletin of Canadian Petroleum Geology, concentrated on the shallow sedimentary record and new insights gained from linking deep seismic reflection profiles with the evolution of the sedimentary succession. The present issue presents a crustal perspective and concentrates on the results from mapping, geochronology, igneous petrology, and seismic investigation of the crystalline basement of the Alberta Basin. The diversity of disciplines covered in this issue address questions about the evolution of the crust and mantle of western Canada and offer unique perspectives on the insight gained from the merger of reflection seismology, magnetotellurics, potential field studies, and field based observations. New breakthroughs in mantle dynamics and its role in sedimentary basin formation, as well as our ability to image mantle structure and relate it to surface tectonic processes, are important steps forward.
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Khasanov, Rinat R., Rinat I. Safuanov, Vladislav A. Sudakov, Damir I. Khassanov, Bulat G. Ganiev, Azat A. Lutfullin, and Rinat R. Aflyatunov. "Factors of gas accumulations formation in oil-bearing sediments and in casing annulus of wells." Georesursy 22, no. 4 (December 2020): 22–29. http://dx.doi.org/10.18599/grs.2020.4.22-29.
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Gas component study is one of the important tasks of petroleum geology. Gas component can exist in various forms in sedimentary rocks. Of great interest is nitrogen, the gaseous accumulations of which are formed in oil-bearing strata, causing complications during the oilfield development. The problem of abnormal nitrogen accumulations had great relevance in the fields of the Volga-Ural petroleum province, which is one of the long-term developed with a large stock of wells for various purposes. This article discusses possible sources of gaseous nitrogen and the reasons for its accumulations in oil-bearing reservoirs. The main purpose of the article is to clarify the reasons for the gaseous nitrogen and its deposits formation. The main patterns of the areal distribution of nitrogen gas accumulations in oil-bearing strata are revealed on the basis of field, hydrogeological, geological and geophysical researches data analysis. It has been established that during the gas caps formation, the source of gaseous nitrogen is its dissolved compounds in groundwater and oil, biochemical decomposition of which leads to the dissolved molecular nitrogen accumulation in a liquid medium. The release of free gaseous nitrogen and the formation of its accumulations is associated with the decompression of formation waters for natural (geological) or man-made reasons (hydrocarbons extraction). Disturbance of the natural hydrodynamic regime in oil-bearing formations leads to the release of gaseous nitrogen and the formation of its accumulations under favorable conditions (the presence of reservoirs, structures and impermeable rocks in the top of the formation).
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Zang, Kai, Jiuchuan Wei, Linsong Yu, Fang Wan, Zunfang Hu, and Yang Li. "Calibration Method of Petroleum Underground Horizon Based on High Precision Gravity and Magnetic Exploration." Earth Sciences Research Journal 24, no. 3 (October 12, 2020): 345–55. http://dx.doi.org/10.15446/esrj.v24n3.90315.
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Because the high-precision calibration results of the petroleum underground layer are of great significance for oil production efficiency, research on the calibration method of the petroleum underground layer based on high precision gravity and magnetic exploration is researched. The gravity magnetic model is used to retrieve the bedrock depth, and the results of the basement structure and sedimentary rock distribution of the gravity and magnetic geology in the petroleum underground horizon of the Tongbai basin are obtained. On this basis, the geological data, logging data, seismic data, and VSP data are comprehensively used, and the layered calibration method is used to calibrate the petroleum underground layer of the Tongbai basin. Considering the seismic datum and the core elevation in the area, the rock formation is divided by various logging curves. The average time difference and density of the divided rock layers are interpolated at equal depth intervals to obtain velocity sequences and density sequences at equal time intervals and finally realize time-depth conversion. When the drilling geological horizon is unified, the synthetic record of the seismic reflection layer is compared with the geological horizon to realize the horizon calibration of the seismic reflection layer. When the local stratification is not uniform, the seismic reflection layer is calibrated by tracking the seismic reflection layer, high-precision velocity analysis, and various synthetic records to verify the reliability of the geological horizon. The results show that the proposed method can accurately survey the geological conditions of the Tongbai basin. It detected 14 basement faults, and the NW-trending and NE-trending faults controlled the basin, while the north-south faults controlled the later evolution of the basin. The method can be used for the horizon calibration of inclined wells, which is suitable not only for anisotropic media but also for formations with a less lateral variation of local formation lithology. Moreover, its usage is flexible, and it can be corrected by multiple speed data.
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Falvey, D. A., P. A. Symonds, J. B. Colwell, J. B. Willcox, J. F. Marshall, P. E. Williamson, and H. M. J. Stagg. "AUSTRALIA'S DEEPWATER FRONTIER PETROLEUM BASINS AND PLAY TYPES." APPEA Journal 30, no. 1 (1990): 239. http://dx.doi.org/10.1071/aj89015.
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Vast areas of Australia's continental margin sedimentary basins lying seawards of the 200 m water depth line, or shelf edge, are under-explored for petroleum. Indeed, most are essentially unexplored. However, recent advances in drilling and production technology, as well as recent reconnaissance seismic, geochemical, geothermal and seabed sampling data collected by the Bureau of Mineral Resources' (BMR) Marine Division, may reduce the perceived economic risk of many of these deepwater basins relative to their shelf counterparts. Triassic reefs have been identified off the northern Exmouth Plateau and possibly in the deepwater Canning Basin, locally within a predicted oil window. In the deepwater North Perth Basin, major wrench structures have been identified. The deepwater areas of the Great Australian Bight and Otway Basin are actually the main depocentres of a major basin complex lying along the almost totally unexplored southern Australian continental margin. The Latrobe Group in the outer Gippsland Basin is likely to have similar geology to the well explored and productive shelf basin, but remains untested. The Queensland and Townsville troughs, in deepwater off northeast Australia, contain many significant structures typical of unbreached rift systems.All these areas have been risked relative to each other and their prospectivity assessed. The most attractive frontier areas in terms of relative risk may be the Otway and North Perth basins. The highest potential may occur in the deepwater rift troughs off northeast Australia, although the relative risk is very high. Triassic reefs of the Northwest Shelf may have the best prospectivity in the shorter term, given that they are known from drilling in a region with proven source potential and a substantial exploration infrastructure.
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Friend, Peter F. "MIALL, A. D. 1996. The Geology of Fluvial Deposits. Sedimentary Facies, Basin Analysis, and Petroleum Geology. xvi + 582 pp. Berlin, Heidelberg, New York, London, Paris, Tokyo, Hong Kong: Springer-Verlag. Price DM 118.00 Ös 861.40, SFr 113.50 (hard covers). ISBN 3 540 59186 9." Geological Magazine 134, no. 3 (May 1997): 409–21. http://dx.doi.org/10.1017/s0016756897276983.
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Isaev, Valery I., Galina A. Lobova, Alexander N. Fomin, Valery I. Bulatov, Stanislav G. Kuzmenkov, Margarita F. Galieva, and Daniil S. Krutenko. "Heat flow and presence of oil and gas (the Yamal peninsula, Tomsk region)." Georesursy 21, no. 3 (September 1, 2019): 125–35. http://dx.doi.org/10.18599/grs.2019.3.125-135.
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The possibilities of Geothermy as a geophysical method are studied to solve forecast and prospecting problems of Petroleum Geology of the Arctic regions and the Paleozoic of Western Siberia. Deep heat flow of Yamal fields, whose oil and gas potential is associated with the Jurassic-Cretaceous formations, and the fields of Tomsk Region, whose geological section contents deposits in the Paleozoic, is studied. The method of paleotemperature modeling was used to calculate the heat flow density from the base of a sedimentary section (by solving the inverse problem of Geothermy). The schematization and mapping of the heat flow were performed, taking into account experimental determinations of the parameter. Besides, the correlation of heat flow features with the localization of deposits was revealed. The conceptual and factual basis of research includes the tectonosedimentary history of sedimentary cover, the Mesozoic-Cenozoic climatic temperature course and the history of cryogenic processes, as well as lithologic and stratigraphic description of the section, results of well testing, thermometry and vitrinite reflectivity data of 20 deep wells of Yamal and 37 wells of Ostanino group of fields of Tomsk region. It was stated that 80 % of known Yamal deposits correlate with anomalous features of the heat flow. Bovanenkovskoe and Arkticheskoe fields are located in positive anomaly zones. 75 % of fields of Ostanino group relate to anomalous features of the heat flow. It is shown that the fields, which are characterized by existence of commercial deposits in the Paleozoic, are associated with the bright gradient zone of the heat flow. The forecast of commercial inflows in the Paleozoic for Pindzhinskoe, Mirnoe and Rybalnoe fields is given. The correlation between the intensity of naftidogenesis and the lateral inhomogeneity of the deep heat flow is characterized as a probable fundamental pattern for Western Siberia.
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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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Hart, Bruce S., Joe H. S. Macquaker, and Kevin G. Taylor. "Mudstone (“shale”) depositional and diagenetic processes: Implications for seismic analyses of source-rock reservoirs." Interpretation 1, no. 1 (August 1, 2013): B7—B26. http://dx.doi.org/10.1190/int-2013-0003.1.
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Source-rock reservoirs are fine-grained petroleum source rocks (“shales” or “mudstones”) having geomechanical properties that allow those rocks to produce hydrocarbons at economic rates after stimulation by hydraulic fracturing. Many of the assumptions commonly adopted by geophysicists to characterize shales cannot be applied to source-rock reservoirs. For example, the mineralogies of many source-rock reservoirs are not dominated by clay minerals and so mathematical and/or conceptual models developed for clay-dominated mudstones are not appropriate and cannot be applied to them. Instead, mudstones of shale plays are generally dominated by biogenic calcite and/or quartz. We use terminology of sedimentary geology to show that anisotropy is scale-dependent in source-rock reservoirs, and we discuss the depositional and diagenetic processes that control these and other geophysical properties of interest. The mudstones of source-rock reservoirs may or may not be anisotropic at the lamination scale (i.e., millimeters), the scale commonly used to measure anisotropic parameters via core plugs, but they are nearly always anisotropic at the bedset (centimeters to several meters) and member (tens of meters) scales. Because of the anisotropic nature of mudstones, elastic properties are not scalars at the length/thickness scales that can be defined using seismic methods. Properties of interest are likely to be different parallel to bedding compared to perpendicular to bedding. Because of the subseismic scale of much of this variability, thin-bed effects are likely to influence the AVO behavior of source-rock reservoirs.
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Gay, S. Parker, and Bronson W. Hawley. "Syngenetic magnetic anomaly sources: Three examples." GEOPHYSICS 56, no. 7 (July 1991): 902–13. http://dx.doi.org/10.1190/1.1443124.
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Aeromagnetic anomalies encountered in three areas, two in the western United States and one in Central America, are shown to arise from magnetic sedimentary formations. These examples are selected from a larger number of similar areas surveyed by Applied Geophysics, Inc. in various places in the U.S. Midcontinent and Rocky Mountain regions. The first area discussed is the northwest corner of Nebraska where the Miocene Arikaree formation, comprised of magnetic airfall and windblown tuffs, causes anomalies in areas of incised topography. The second area is located in south central Utah, where the Upper Cretaceous Kaiparowits sandstones contain detrital magnetite that causes large anomalies in tilted structures and over incised topography. The third area treated covers over half of southern Belize in Central America, including much of the offshore portion. Here, the Toledo formation of Paleocene‐Eocene age contains a thick section of clastic detritus rich in lithic grains of volcanic rocks that produce magnetic highs over thrusted and folded anticlinal axes. These three examples of magnetic anomalies due to syngenetic magnetite in widely scattered areas and from different types of source materials bring into question the assumption of so‐called “diagenetic magnetite” (or other magnetic minerals) as a cause of magnetic anomalies in other petroleum basins. It is necessary in all cases to determine the magnetic source from surface or subsurface geology, as was done here, rather than making assumptions strictly from magnetic profiles or mathematical models.
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Xue, Yong Chao, and Lin Song Cheng. "Reservoir Modeling and Numerical Simulation Controlled by Flow Units." Advanced Materials Research 690-693 (May 2013): 3190–93. http://dx.doi.org/10.4028/www.scientific.net/amr.690-693.3190.
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Geological model controlled by sedimentary microfacies can not able to accurately reflect the actual seepage characteristic, How to apply the static flow units to the dynamic reservoir numerical simulation is the advancing edge of petroleum industry. The method of reservoir geological modeling controlled by flow units is proposed. Firstly, the 3D models of flow unit should be build, secondly, the 3D porosity and permeability model are established controlled by the model of flow unit, thirdly, the 3D fluids saturation model is calculated by Leverett J function based on porosity and permeability mode. Selecting different relative permeability curves according to different flow units in history matching. which realizes the dynamic (development geological) and static (reservoir engineering) combination. The oilfield examples shown that the velocity and precision of history matching can be significantly improved by using the method mentioned. Flow units were proposed by Hearn in 1984[. Study on flow units, which could not only deepen the understanding of reservoir geology, make reservoir evaluation more reasonable and reduce the heterogeneity impact on oil development, but also could be of great significance to improve oil field development effect especially for tertiary oil recovery[. Previous studies mainly focused on defining the concept of flow units, divide method of flow units and so on, but few studies on how to apply the study results of static flow units to the dynamic reservoir engineering and reservoir simulation[3-. Our research aimed at how to connect the static flow units and the dynamic reservoir simulation closely so as to achieve "dynamic and static combination".
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Uruski, Chris. "Exploring New Zealand's marine territory." APPEA Journal 51, no. 1 (2011): 549. http://dx.doi.org/10.1071/aj10039.
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Around the end of the twentieth century, awareness grew that, in addition to the Taranaki Basin, other unexplored basins in New Zealand’s large exclusive economic zone (EEZ) and extended continental shelf (ECS) may contain petroleum. GNS Science initiated a program to assess the prospectivity of more than 1 million square kilometres of sedimentary basins in New Zealand’s marine territories. The first project in 2001 acquired, with TGS-NOPEC, a 6,200 km reconnaissance 2D seismic survey in deep-water Taranaki. This showed a large Late Cretaceous delta built out into a northwest-trending basin above a thick succession of older rocks. Many deltas around the world are petroleum provinces and the new data showed that the deep-water part of Taranaki Basin may also be prospective. Since the 2001 survey a further 9,000 km of infill 2D seismic data has been acquired and exploration continues. The New Zealand government recognised the potential of its frontier basins and, in 2005 Crown Minerals acquired a 2D survey in the East Coast Basin, North Island. This was followed by surveys in the Great South, Raukumara and Reinga basins. Petroleum Exploration Permits were awarded in most of these and licence rounds in the Northland/Reinga Basin closed recently. New data have since been acquired from the Pegasus, Great South and Canterbury basins. The New Zealand government, through Crown Minerals, funds all or part of a survey. GNS Science interprets the new data set and the data along with reports are packaged for free dissemination prior to a licensing round. The strategy has worked well, as indicated by the entry of ExxonMobil, OMV and Petrobras into New Zealand. Anadarko, another new entry, farmed into the previously licensed Canterbury and deep-water Taranaki basins. One of the main results of the surveys has been to show that geology and prospectivity of New Zealand’s frontier basins may be similar to eastern Australia, as older apparently unmetamophosed successions are preserved. By extrapolating from the results in the Taranaki Basin, ultimate prospectivity is likely to be a resource of some tens of billions of barrels of oil equivalent. New Zealand’s largely submerged continent may yield continent-sized resources.
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Carpenter, Chris. "Geocognitive Technologies Improve Basin- and Petroleum-System Analyses." Journal of Petroleum Technology 73, no. 01 (January 1, 2021): 67–68. http://dx.doi.org/10.2118/0121-0067-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 197610, “Application of Geocognitive Technologies to Basin- and Petroleum-System Analyses,” by Paolo Ruffo, Marco Piantanida, SPE, and Floriana Bergero, Eni, et al., prepared for the 2019 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed. Eni and IBM developed a cognitive engine exploiting a deep-learning approach to scan documents searching for basin geology concepts, extracting information about petroleum system elements (e.g., formation name; geological age; and lithology of source rocks, reservoirs, and seals), and enabling basin geologists to perform automated queries to collect all information related to a basin of interest. The cognitive engine succeeded in identifying the correct formations, lithologies, and geological ages of the petroleum systems with an accuracy in the range of 75 to 90%. Introduction While commercial databases often provide summary information about basins that can be extracted easily with queries or even interactive tools, the explorationist needs to integrate such information with more up-to-date and in-depth descriptions of structural and sedimentary events occurring in the basin, descriptions that can be found only in unstructured documents. Key information about basins can be scattered across paragraphs, tables, and image captions of hundreds of technical articles, or can be embedded within pictures. Even when exploiting a traditional search engine with the name of the desired basin, the results can be unsatisfactory: first, not all the results might be relevant; second, many different variants of the basin name are often used within publications. In the optimistic hypothesis that the subset of relevant documents is found by the search engine, all key concepts related to a basin need to be understood by the geologist by careful examination of the paper text and images. Moreover, even if the published information (structured and unstructured) on a basin is found, there are different opinions expressed by different authors, in addition to the uncertainty of the data itself (such as the age of a formation or the details of the geological evolution of the basin), so that multiple conceptual models of the basin can be drawn from the uncertain and scarce information available. Some of these conceptual models are more probable while others are less probable, but sometimes the latter happen to be economically more valuable. Therefore, recovery of all relevant information about a basin is crucial, but also important is the preservation of differing opinions about the data - what might be termed minority reports.
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Abbaszadeh, Maghsood, Naoki Koide, and Yoya Murahashi. "Integrated Characterization and Flow Modeling of a Heterogeneous Carbonate Reservoir in Daleel Field, Oman." SPE Reservoir Evaluation & Engineering 3, no. 02 (April 1, 2000): 150–59. http://dx.doi.org/10.2118/62514-pa.
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Summary This article presents applications of deterministic and conditional geostatistical reservoir characterization methods to the heterogeneous carbonates of the upper Shuaiba formation in Daleel field, Oman. High-resolution reservoir descriptions based on the integration of logs, core, pressure transient tests, geology, and seismic data are constructed; and upscaled for use in reservoir simulation models to history match field performance data. Generally, geostatistical techniques combined with geology and proper upscaling of permeability heterogeneity yield best results without artificial alterations in various fluid and rock properties. Although acceptable history matches can be obtained with compromised less-detailed reservoir descriptions, these require modifications to reservoir data beyond reasonable ranges. Only detailed and concise reservoir descriptions result in history matches that are consistent with a variety of measured data sources. Introduction Reservoir characterization has gained a new momentum in the past decade, largely due to the introduction of geostatistical methods to the petroleum industry and rapid progress made in their advancement.1 The keen interest in reservoir characterization arises because it is well recognized that reservoir heterogeneity has a profound affect on all phases of hydrocarbon recovery, ranging from oil in-place calculations to sweep and conformance efficiency determination of various injection processes. Thus, any improved understanding of a reservoir will aid in better management and better exploitation of its hydrocarbon recovery potential. The challenge in understanding and predicting reservoir performance is two-fold: first, to describe reservoir geologic heterogeneities realistically and quantitatively, and second to model reservoir flow behavior in the presence of all heterogeneities accurately and efficiently.2 While large-scale reservoir features (such as main layers or major faults) can be described by deterministic techniques, less-correlated medium-scale and more-chaotic small-scale heterogeneities may be characterized by geostatistical methods or related interpolative techniques. This is especially true for estimating interwell reservoir properties based on a limited amount of information available at wells. The approaches to reservoir characterization fall into three categories: deterministic, stochastic, and combination of the two. The deterministic approach has been in use for several decades and ample success with it has been reported. The interwell properties are generally interpolated or extrapolated using algorithms based on the inverse-distance-square principle or variations of it. Usually, adjustments to the number of layers, gridblock properties, relative permeabilities, and even fluid properties are made in order to history match field performance. Some of these adjustments are warranted and some are solely knobs that are arbitrarily tuned in simulation models without physical bases. Thus, the resulting reservoir models may lack reliability and predictive capability. Geostatistical methods, however, generate multiple realizations of reservoir heterogeneity that honor available data, but differ from one another by interwell properties where direct information is not available. The data used in these models are by in large of static nature coming mainly from cores, logs, and seismic attribute extractions. Dynamic information, such as pressure transient tests and production data, are usually excluded from explicit use in geostatistical reservoir characterization, primarily due to difficulty on how to best integrate them a priori into such models. However, recent advances have been made for direct inclusion of this dynamic information through the techniques of simulated annealing3 or direct volume-averaged upscaling.4 Nevertheless, these geostatical reservoir descriptions are capable of capturing detailed geology more realistically and of producing acceptable history matches to field performance data without artificial alterations to various reservoir or fluid properties.5–10 This article applies both methods of deterministic and geostatistical reservoir characterizations to describe and history match the primary recovery performance of a complex carbonate reservoir in Daleel field, Oman. This is a comparative study in an attempt to identify an applicable description method for this field to aid in its exploitation. The deterministic model investigates effects of layering and fluid bubblepoint pressure on production performance. The geostatistical approaches model detailed reservoir heterogeneity and evaluate the importance of proper representation of heterogeneity in flow simulations. During the course of the study, new or alternate approaches for various elements of reservoir characterization techniques have been developed, which are also included. Background Field Description. The reservoir of Daleel field is an elongated carbonate shoal sands and back carbonates in the upper Shuaiba formation. Five geographical sedimentary environments of protected back shoal, shoal, shoal margin slope, inner shelf, and outer shelf comprise the formation. The productive portion of the reservoir is situated in the protected back shoal region (central part of the carbonate mound) and its marginal parts are located in regions with alternating cycles of shoal and shelf sequences. The reservoir is a stratigraphic-structural oil trap accumulation. Bioclastic peloidal packstone and wackstone form the main reservoir sedimentary material in this field. Repeated upward shallowing parasequence cycles, which relate to the geographical sedimentary environment, are recognized on wireline responses. These parasequence boundaries may be considered as synchronous surfaces for interwell correlation. Detailed core and thin section studies have identified 12 lithofacies in the upper Shuaiba, ranging from coarse grain porous limestone to argillaceous lime and lime mudstone. Microstylolites, burrowing and other forms of diagenesis are common. Therefore, pore/throat size distribution and their connectivity as influenced by secondary diagenesis processes mainly control porosity and permeability developments. Significant changes in these lithofacies occur laterally and vertically, and there is an important tightly consolidated discontinuous lime mudstone deposit in the middle of the productive upper zone in the central part of the field.
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Uruski, Chris, Callum Kennedy, Rupert Sutherland, Vaughan Stagpoole, and Stuart Henrys. "The discovery of a new sedimentary basin: offshore Raukumara, East Coast, North Island, New Zealand." APPEA Journal 48, no. 1 (2008): 53. http://dx.doi.org/10.1071/aj07006.
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The East Coast of North Island, New Zealand, is the site of subduction of the Pacific below the Australian plate, and, consequently, much of the basin is highly deformed. An exception is the Raukumara Sub-basin, which forms the northern end of the East Coast Basin and is relatively undeformed. It occupies a marine plain that extends to the north-northeast from the northern coast of the Raukumara Peninsula, reaching water depths of about 3,000 m, although much of the sub-basin lies within the 2,000 m isobath. The sub-basin is about 100 km across and has a roughly triangular plan, bounded by an east-west fault system in the south. It extends about 300 km to the northeast and is bounded to the east by the East Cape subduction ridge and to the west by the volcanic Kermadec Ridge. The northern seismic lines reveal a thickness of around 8 km increasing to 12–13 km in the south. Its stratigraphy consists of a fairly uniformly bedded basal section and an upper, more variable unit separated by a wedge of chaotically bedded material. In the absence of direct evidence from wells and samples, analogies are drawn with onshore geology, where older marine Cretaceous and Paleogene units are separated from a Neogene succession by an allochthonous series of thrust slices emplaced around the time of initiation of the modern plate boundary. The Raukumara Sub-basin is not easily classified. Its location is apparently that of a fore-arc basin along an ocean-to-ocean collision zone, although its sedimentary fill must have been derived chiefly from erosion of the New Zealand land mass. Its relative lack of deformation introduces questions about basin formation and petroleum potential. Although no commercial discoveries have been made in the East Coast Basin, known source rocks are of marine origin and are commonly oil prone, so there is good potential for oil as well as gas in the basin. New seismic data confirm the extent of the sub-basin and its considerable sedimentary thickness. The presence of potential trapping structures and direct hydrocarbon indicators suggest that the Raukumara Sub-basin may contain large volumes of oil and gas.
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Khuduzade, A., Sh Akhundov, S. Shabanova, T. Imamalili, and O. Ismaylov. "Modeling of the tectonic position and prediction of the spatial distribution of hydrocarbon deposits in the Middle Kura depression (examples from the Ganja oil and gas-bearing region)." Мінеральні ресурси України, no. 4 (January 15, 2020): 38–44. http://dx.doi.org/10.31996/mru.2019.4.38-44.
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The article continues the series of publications devoted to the forecast of oil and gas potential in the Middle Kura Depression. Systematization and analysis of published materials show that the effectiveness of prospecting and exploration for oil and gas depends on the fairness and accuracy of scientific ideas about the origin and patterns of hydrocarbon localization. The established heterogeneity of the structure of sedimentary basins and the uneven distribution of oil and gas deposits in them allows us to make a predictive assessment of territories based on historical-geological methods and a synthes analysis of criteria for assessing the prospects of oil and gas. These methods are based on fundamental research in geology, the most important of which are structural-tectonic analysis and the genesis of oil and gas-bearing structures, the study of geological and geochemical factors in the simulation model “Uniform continuous lowering”, the study of the staged conversion of organic matter in the catagenetic process and show the oil and gas windows, prediction of collector and overlying seal zones, study of organic substances dissolved in water and other hydrogeological factors contributing to the formation and prevent of oil and gas deposits. Analysis of the geological history of the first stage of research,the assessment of petroleum potential of the region. Based on the results of seismic surveys, we carried out paleotectonic reconstructions for the northwestern zone of the Ganja oil and gas-bearing region, which illustrate the maps of total thickness in the form of isopachic triangle, paleotectonic profiles and graphic of subsidence size. Modeling of structural surfaces made it possible to establish the historical development of not only local structures, but also to notice new features in the formation of chronostratigraphic surfaces, and to judge the tectonic regime of the sedimentation basin, to justify the mechanism of formation in the sedimentary cover of the Middle Kura depression, both of plicative dislocation and faulting as well as zones of oil and gas accumulation associated with them. The study can be considered as a positive argument when choosing the location of the prospecting well.
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Buchanan, Spencer J. "THE FOUNDATION PROBLEMS ON THE GULF COAST." Coastal Engineering Proceedings 1, no. 2 (January 1, 2000): 13. http://dx.doi.org/10.9753/icce.v2.13.
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The foundation problems of the coastal region of the Gulf of Mexico are unique. Normally, a coastal region is thought of as the land area, such as a plain, adjacent to a body of water. Such a region usually is somewhat regular in its geology and because of the natural resources, terrain or climate may be given to a relatively common industry involving a somewhat similar development throughout. The coastal region of the Gulf of Mexico, as regards the United States, violates this criterion in a multitude of ways. The region is not limited to the coastal plain bordering the Gulf of Mexico, by any means, but, rather has been broadened by our commerce and the need for the development of natural resources to also embrace, the delta areas and offshore belt extending to the limit of the continental shelf, lying as far as 70 miles from the shore. The delta areas have long been avoided in the past by industry of all types that is, with the exception of the fishing industry, because of the unstable nature of the foundation media. Likewise the continental shelf area normally is not considered for industrial development because of the availability of the more desirable coastal plain. However, the quest for natural resources, like sulphur and petroleum, in spite of the efforts toward Federal Control, has made necessary the solution of very extraordinary foundation problems in this offshore area. In addition to the foregoing unusual aspects of the foundation problems of the Gulf Coast, the coastal plain is unusual in itself because this region at one time formed the floor of the Gulf of Mexico and, as the sea receded or the land was uplifted, the residual sedimentary soils have been drained and desiccated to result in unusual formations that serve as foundation media for the industrial and domestic developments of the region. The foregoing factors combine to make the foundation problems of the Gulf of Mexico Coastal Region very interesting.
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Rodnikova, R. D. "GEODYNAMICS AND PETROLEUM FORMATION IN THE SEDIMENTARY BASINS OF SOUTHEAST ASIA." International Geology Review 28, no. 4 (April 1986): 435–43. http://dx.doi.org/10.1080/00206818609466283.
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Gardiner, David, Nick Schofield, Alex Finlay, Niall Mark, Liam Holt, Clayton Grove, Chris Forster, and Julian Moore. "Modeling petroleum expulsion in sedimentary basins: The importance of igneous intrusion timing and basement composition." Geology 47, no. 10 (August 12, 2019): 904–8. http://dx.doi.org/10.1130/g46578.1.
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Abstract The concept of a critical moment in a petroleum system (the time of highest probability of entrapment and preservation of oil and gas) has underlain petroleum exploration for over 25 years. However, one area where understanding the critical moment is challenging is the Faroe-Shetland Basin (FSB; offshore UK). Isotopic dating of oils suggests that petroleum generation began between ca. 68 and 90 Ma; however, most basin models invoke an earlier generation beginning in the mid-Cretaceous at ca. 100 Ma, predating deposition of Paleocene and Eocene reservoirs. This time discrepancy has previously been explained by remigration from intermediary accumulations (“motel” hypothesis) and/or overpressure retardation of kerogen maturation. The FSB is characterized by a thick Cretaceous stratigraphic package (up to 5 km) that includes a large net thickness (up to 2 km) of Paleogene igneous material. In our model, separating sedimentary and igneous material and adding the igneous material at the correct time between ca. 58 and 55 Ma shallows the modeled burial depth of the Upper Jurassic source rocks during the Cretaceous sufficiently to delay maturation by 17 m.y. in comparison to results of previous studies. Additionally, previous studies have invoked crustal radiogenic heat production (RHP) based on the Phanerozoic crust averaging ∼2.8 µW/m3 in the North Sea (300 km to the east). However, the FSB basement is composed of significantly older, colder Neoarchean orthogneisses (ca. 2.7–2.9 Ga), reducing RHP by up to 50% to ∼1.6 µW/m3 (σ = 0.74). For the first time, our model unifies geological, geochronological, and geochemical observations, delaying the onset of petroleum expulsion by up to 40 m.y. in comparison to previous models.
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Klimenko, S. S., L. A. Anischenko, and A. I. Antoshkina. "Chapter 13 The Timan–Pechora sedimentary basin: Palaeozoic reef formations and petroleum systems." Geological Society, London, Memoirs 35, no. 1 (2011): 223–36. http://dx.doi.org/10.1144/m35.13.
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JIANG, DE-XIN, YONG-DONG WANG, ELEANORA I. ROBBINS, JIANG WEI, and NING TIAN. "Mesozoic non-marine petroleum source rocks determined by palynomorphs in the Tarim Basin, Xinjiang, northwestern China." Geological Magazine 145, no. 6 (July 30, 2008): 868–85. http://dx.doi.org/10.1017/s0016756808005384.
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AbstractThe Tarim Basin in Northwest China hosts petroleum reservoirs of Cambrian, Ordovician, Carboniferous, Triassic, Jurassic, Cretaceous and Tertiary ages. The sedimentary thickness in the basin reaches about 15 km and with an area of 560000 km2, the basin is expected to contain giant oil and gas fields. It is therefore important to determine the ages and depositional environments of the petroleum source rocks. For prospective evaluation and exploration of petroleum, palynological investigations were carried out on 38 crude oil samples collected from 22 petroleum reservoirs in the Tarim Basin and on additionally 56 potential source rock samples from the same basin. In total, 173 species of spores and pollen referred to 80 genera, and 27 species of algae and fungi referred to 16 genera were identified from the non-marine Mesozoic sources. By correlating the palynormorph assemblages in the crude oil samples with those in the potential source rocks, the Triassic and Jurassic petroleum source rocks were identified. Furthermore, the palynofloras in the petroleum provide evidence for interpretation of the depositional environments of the petroleum source rocks. The affinity of the miospores indicates that the petroleum source rocks were formed in swamps in brackish to lacustrine depositional environments under warm and humid climatic conditions. The palynomorphs in the crude oils provide further information about passage and route of petroleum migration, which is significant for interpreting petroleum migration mechanisms. Additionally, the thermal alternation index (TAI) based on miospores indicates that the Triassic and Jurassic deposits in the Tarim Basin are mature petroleum source rocks.
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Underhill, John R. "The tectonic and stratigraphic framework of the United Kingdom's oil and gas fields." Geological Society, London, Memoirs 20, no. 1 (2003): 17–59. http://dx.doi.org/10.1144/gsl.mem.2003.020.01.04.
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AbstractOnshore exploration success during the first half of the 20th century led to petroleum production from many, relatively small oil and gas accumulations in areas like the East Midlands, North Yorkshire and Midland Valley of Scotland. Despite this, the notion that exploration of the United Kingdom's continental shelf (UKCS) might lead to the country having self-sufficiency in oil and gas production would have been viewed as extremely fanciful as recently as the late 1950s. Yet as we pass into the new century, only thirty-five years on from the drilling of the first offshore well, that is exactly the position Britain finds itself in. By 2001, around three million barrels of oil equivalent were being produced each day from 239 fields. The producing fields have a wide geographical distribution, occur in a number of discrete sedimentary basins and contain a wide spectrum of reservoirs that were originally deposited in diverse sedimentary and stratigraphic units ranging from Devonian to Eocene in age. Although carbonates are represented, the main producing horizons have primarily proved to be siliciclastic in nature and were deposited in environments ranging from aeolian and fluviatile continental red beds, coastal plain, nearshore beach and shelfal settings all the way through to deep-marine, submarine fan sediments. This chapter attempts to place each of the main producing fields into their proper stratigraphic, tectonic and sedimentological context in order to demonstrate how a wide variety of factors have successfully combined to produce each of the prospective petroleum play fairways and hence, make the UKCS such a prolific and important petroleum province.
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Artyushkov, E. V., I. V. Belyaev, G. S. Kazanin, S. P. Pavlov, P. A. Chekhovich, and S. I. Shkarubo. "Formation mechanisms of ultradeep sedimentary basins: the North Barents basin. Petroleum potential implications." Russian Geology and Geophysics 55, no. 5-6 (May 2014): 649–67. http://dx.doi.org/10.1016/j.rgg.2014.05.009.
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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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Mel’nikov, N. V., Yu A. Filiptsov, V. I. Valchak, E. V. Smirnov, and L. V. Borovikova. "Petroleum potential of the Riphean-Vendian Chunya sedimentary basin in the western Siberian Platform." Russian Geology and Geophysics 49, no. 3 (March 2008): 176–82. http://dx.doi.org/10.1016/j.rgg.2008.02.001.
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Burlin, Yu K., and Yu V. Shipel’kevich. "Principal features of the tectonic evolution of sedimentary basins in the Western Chukchi shelf and their petroleum resource potential." Geotectonics 40, no. 2 (March 2006): 135–49. http://dx.doi.org/10.1134/s0016852106020051.
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