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- Volume 4, Issue 4, 1998
Petroleum Geoscience - Volume 4, Issue 4, 1998
Volume 4, Issue 4, 1998
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Biomarker oil-to-source rock correlation in the Western Carpathians and their foreland, Czech Republic
Authors Frank J. Picha and Kenneth E. PetersBiomarker analyses indicate that at least two petroleum systems operate in the Vienna basin, Carpathian thrust belt and the European foreland plate in Moravia--one associated with Jurassic and the other with Palaeogene organic-rich rocks. Four oils from the sub-Carpathian foreland plate and one sample from the Vienna basin were analysed and geochemically compared to extracts from Jurassic and Palaeogene source rocks. Two oils from the subthrust foreland plate Lubna-18 and Dolni Lomna-1) are genetically related based on similar geochemical compositions. These oils show high oleanane and 24-nordiacholestane ratios, age-related biomarker ratios that are consistent with an origin from Palaeogene organic-rich rocks. These rocks are inferred to be either the Menilitic shales of the Carpathian thrust belt or autochthonous Palaeogene deposits buried below the thrust belt. Two other oils from the subthrust plate (Zdanice-7 and Damborice-16 correlate geochemically with extracts from Jurassic source rocks in the Sedlec-1 and Nemcicky-1 wells. Like the oil extracts, these oils lack oleanane and show low 24-nordiacholestane ratios, supporting an origin from Jurassic organic-rich marls. The oil sample from the Vienna basin (Tynec-34) appears to be a mixture of the two oil groups.
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Rejuvenating marginal, aging oil fields; is it profitable?
Authors Robert M. Sneider and John S. SneiderSmall multidisciplinary geoscience-engineering teams of 5 to 10 professionals searched for large volumes of low risk reserves in poorly performing oil fields. Between 1981-1996 over 350 mature fields in the Permian and Gulf of Mexico basins were scanned looking for fields to purchase. Forty-six fields were purchased. The purchased fields include those producing by (1) primary recovery without secondary recovery potential, (2) primary recovery with supplemental recovery potential and (3) those undergoing waterflooding. Finding large volumes of low risk, presently non-producing reserves within fields involves several steps. First, the team searches in reservoir systems that appear more massive and homogeneous than they are. Second, the team scans the geoscience and engineering data to quickly estimate original oil-in-place, percent recovery, remaining reserves and potential bypassed reserves. Third, the team makes an economic analysis including recovery cost estimates for the volume of missed low and high-risk reserves. Candidate fields for purchase all have new low to moderate risk reserves amounting to at least 5% of the cumulative reserves already produced. Forty-one fields are economically successful with an after-tax rate of return (ATROR) of 12 to 41% (average 21%) and three fields made 5-7% ATROR. Two fields are economic failures. Payout for the 44 economically successful fields ranged from 11 months to 5.8 years.
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Temperature and heat flow in the Celtic Sea basins
Authors Dympna Corry and Colin BrownHydrocarbon exploration wells provide sufficient information to analyse the present-day thermal regime in the Celtic Sea basins. This information consists of bottom hole temperatures (BHTs), geophysical well logs, composite logs and rock cuttings from the major formations. The BHTs provide numerous but low-quality data which require extensive processing before they provide reliable estimates of formation temperature. Standard corrections (Horner plots) to multiple BHTs can be modified to correct single BHT measurements. A least-squares inversion based on a thermal resistance (Bullard) model for conductive heat flow can map many noisy Horner-corrected BHTs into a set of formation temperature estimates with relatively small errors. The average geothermal gradient is 32 degrees C km (super -1) . Laboratory measurements of the thermal conductivity of rock cuttings taken from representative formations in selected wells give matrix conductivities at room temperature. These sample measurements are combined with information about formation porosity and temperature to give in situ thermal conductivities for each formation in each well. These are then used with formation temperature gradients from the BHT analysis to estimate heat flow. The heat flow obtained for the Celtic Sea basins varies between 59 and 81 mW m (super -2) . The highest values appear to be where sediments are thickest.
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2D flexural backstripping of extensional basins; the need for a sideways glance
Authors Alan M. Roberts, Nick J. Kusznir, Graham Yielding and Peter StylesBackstripping is a technique employed to analyse the subsidence history of extensional basins, and involves the progressive removal of sediment loads, incorporating the isostatic and sediment decompaction responses to this unloading. The results of backstripping calculations using 1D models employing local (Airy) isostasy and 2D models employing "flexural" isostasy are compared for three cross-sections of the North Sea rift basin. Backstripping is commonly used to estimate stretching factor (beta ) across extensional basins. At structural highs 1D Airy backstripping will overestimate beta by comparison with predictions from 2D flexural backstripping, because Airy isostasy fails to acknowledge the effects of lateral differential loading. Predictions of beta from 2D flexural backstripping are closer to those derived from forward modelling. 1D Airy backstripping also produces unrealistic internal deformation of individual fault-blocks and overestimates beta when the pre-rift sequence is not fully decompacted. The palaeobathymetric data required by 1D Airy backstripping are often inaccurate, which yields misleading results. 2D flexural backstripping has been formulated as reverse post-rift modelling, which is used to produce sequential (isostatically balanced) palinspastic post-rift cross-sections. These are calibrated using only high-quality palaeobathymetric data, allowing 2D flexural backstripping to be used to predict palaeobathymetry away from the calibration points.
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The petroleum systems of the Pechora Platform Foreland, Russia
Authors V. Martirosyan, L. Popova and M. VeprevaThe Timan-Pechora hydrocarbon basin is one of the most petroliferous provinces of Russia. It is at a mature stage of exploration onshore but is still poorly explored offshore. The exploration within the offshore extension of the Pechora Platform commenced in 1988 and has resulted in five commercial discoveries of oil and gas/condensate, the Severo-Gulyaevskoye, Pomorskoye, Prirazlomnoye, Varandey-More and Medyn-More fields. Hydrocarbon accumulations within the offshore extension of the Pechora Platform are related to at least two petroleum systems: the Domanik-Permo-Carboniferous and the Silurian-Lower Devonian. Reservoir rocks range from the Lower Devonian to the Upper Permian and are mostly carbonates. Throughout the onshore area of the Pechora Platform, Silurian-Lower Devonian formations and Domanik shales are known as the main source rocks. This paper concerns the easternmost petroleum systems of the Pechora Platform that stretch west of the Novaya Zemlya Orogen and encompass more than 100 oil and gas fields.
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Finding a regular geometry for an irregular reservoir shape for well performance calculations
Authors D. H. Tehrani, G. Chen and J. M. PedenThe shape and geometry of the reservoir play an important role in well pressure performance calculations by analytical methods. Dietz (1965) reported analytical solutions for a variety of regular shape reservoirs. He presented a table of shape factors for different geometries circle, square, triangle etc.) and different locations of the well within the reservoir. However, no solution is available for an irregular geometry or for any shape that is not covered in the Dietz shape factor table. This paper presents a method in which a numerical simulator is used for an irregular shape reservoir to obtain an equivalent regular geometry that produces the same well performance as that of the real irregular reservoir. The well can be slanted or horizontal and can be situated anywhere within the reservoir. To do this an optimization routine is used which minimizes the sum squared deviations between the well block pressures as obtained by the numerical simulators for both shapes. Once the nearest regular shape has been identified, well performance calculations can be carried out using an analytical method selected from those presented by Dietz or by the same authors in their recent papers.
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Structure of the East Shetland Platform, northern North Sea
Authors Nigel H. Platt and Joseph A. CartwrightThe East Shetland Platform formed a regional high throughout the Mesozoic and Tertiary with only a thin Triassic to Recent succession preserved. Seismic data reveal the underlying structure and stratigraphy. Complex seismic reflections are seen within the basement and may indicate basement thrust duplexes and lateral ramps, recording Caledonide deformation. A distinctive change in seismic character, traceable over the entire area, marks the base of a sedimentary package >7.5 km thick which overlies and locally onlaps a regionally persistent top basement reflector. This package is thought to be Devonian. The recognition of several internal discontinuities within it may permit subdivision into tectono-stratigraphic units. Local divergence of the reflectors within the Devonian succession provides evidence of syn-sedimentary growth faulting, perhaps due to extension in the hanging wall of reactivating, rolled back Caledonide thrust faults. The Devonian sequence is locally deformed into symmetrical to eastward-vergent folds, these marking a pre-Mesozoic compressional deformation phase of probable Variscan age. The Devonian strata on the East Shetland Platform may provide local hydrocarbon charge from oil-prone lacustrine source rocks, as well as fluvial sandstones with moderate reservoir potential. Dipping and locally intensely folded Devonian strata can offer a range of structural and stratigraphic traps in this poorly explored area.
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Geological controls on remaining oil in Miocene fluvial and shoreface reservoirs in the Mioceno Norte area, Lake Maracaibo, Venezuela
Authors W. A. Ambrose, M. Mendez, M. Saleem Akhter, F. P. Wang and R. AlvarezFacies architecture and structure are the primary controls on reservoir geometry, fluid-flow pathways, and distribution of remaining oil in fluvial and shoreface reservoirs of Miocene age in the 46.7 km 2 Mioceno Norte area in northern Lake Maracaibo. This mature field is undergoing depletion and nearing the final stages of primary recovery. Although the area has produced oil since the 1940s, appreciable volumes of oil (commonly 400 to 1200X10 3 STB (stock tank barrels)/20-acre drainage area) remain in multiple, poorly contacted reservoir sandstones at the current 984 ft (300 m) well spacing. Detailed lithofacies maps document the control of sandstone architecture on hydrocarbon distribution and demonstrate that the current well spacing on a grid pattern is too large to recover efficiently the remaining oil. Moreover, the facies architecture influences water-cut patterns and the irregular advancement of inferred oil-water contacts on the western margin of the field. A wide variety of infill wells, recompletions, redrilled wells, horizontal wells, and water-injection wells is proposed. Approximately 80X10 6 STB of remaining oil will be produced by maintaining the current 984 ft (300 m) well spacing. However, an additional 46.5X10 6 STB can be produced with geologically targeted infill wells, recompletions and horizontal wells. In addition, new water-injection wells can appreciably increase oil recovery by enhancing sweep efficiency and providing pressure support.
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Volumes & issues
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Volume 30 (2024)
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Volume 29 (2023)
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Volume 28 (2022)
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Volume 27 (2021)
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Volume 26 (2020)
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Volume 25 (2019)
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Volume 24 (2018)
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Volume 23 (2017)
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Volume 22 (2016)
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Volume 21 (2015)
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Volume 20 (2014)
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Volume 19 (2013)
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Volume 18 (2012)
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Volume 17 (2011)
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Volume 16 (2010)
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Volume 15 (2009)
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Volume 14 (2008)
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Volume 13 (2007)
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Volume 12 (2006)
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Volume 11 (2005)
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Volume 10 (2004)
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Volume 9 (2003)
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Volume 8 (2002)
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Volume 7 (2001)
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Volume 6 (2000)
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Volume 5 (1999)
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Volume 4 (1998)
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Volume 3 (1997)
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Volume 2 (1996)
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Volume 1 (1995)