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- Volume 2, Issue 3, 1996
Petroleum Geoscience - Volume 2, Issue 3, 1996
Volume 2, Issue 3, 1996
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Caucasus wedge-thrust structures and oil-gas potential
More LessStructural elements with an arched shape in plan occur in the Great and Lesser Caucasus foothills. Their formation is due to the presence of transverse buried rifts, which are overthrust by foreland folds having the form of a wedge in plan. The resulting structures are favourable for the presence of oil and gas accumulations. The Daghestan wedge-nappe (DWN), named by Shatskiy in 1925, is a tectonotype for such structures. The DWN has been thrust over a large rift trough with a transverse orientation to the strike of the Eastern Caucasus folds. Sedimentation and intensive heating through the Mesozoic and Cenozoic resulted in this trough becoming an area of hydrocarbon generation. Wedge-nappe structures are likely to occur widely in all fold belts, such as the Ural and Verhoyansk belts in Russia, the Bulgarian Eastern Balkans and the Suleyman Mountains in Pakistan.
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Factors controlling the destruction or preservation of giant light oilfields
More LessStudy of a database of 350 giant oilfields show these to be dynamic short-lived phenomena, with a median age of 35 Ma. A third show evidence for post-entrapment destructive processes, particularly erosion, fault leakage, gas flushing and biodegradation. Many cases of biodegradation may occur prior to complete filling of the oilfield. Re-entrapment of oil released from spilling or breached traps is common. The main controls on oilfield preservation are post-entrapment tectonism and seal type, with temperature and hydrodynamic regimes being secondary factors. Destructive processes are concentrated in shallow and deep zones and in seepage-prone traps such as compressional anticlines. Such factors strongly influence the distribution of preserved light oilfields, with preservation potential maximized in tectonically quiescent basins with evaporite seals, e.g. the Middle East and the Permian Basin. More attention is required, particularly in older petroleum systems, to models involving post-entrapment leakage and re-migration.
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Development of the slumped crestal area of the Brent reservoir, Brent Field; an integrated approach
Authors S. D. Coutts, S. Y. Larsson and R. RosmanThe Brent Field consists of a major, westerly dipping fault block, with a crestal area broken up into a series of slumped fault blocks. The primary phase of development has concentrated on water flooding the West Flank, but effort is now being applied to recover the oil in the slumped blocks. This paper describes the various studies undertaken to formulate a development plan for the estimated 13 x 10 6 m 3 (80 MMSTB) of oil reserves in the slumps of the Brent Reservoir and presents initial well results. A valid geological interpretation was crucial to successful development planning for the slumps. Structural interpretation is difficult due to limited seismic resolution, but the geological model has been supported by a review of structural analogues and by the limited well performance data. The slump faults are interpreted as running predominantly north-south. As such, they provide a significant barrier to west-east flow, while allowing better communication in the north-south direction. Development options have been evaluated by reservoir simulation based on this geological interpretation. East-west communication will be too poor to enable the slumps to be developed at reasonable rates by relying solely on pressure support from West Flank water injection. In addition, the use of horizontal wells, as compared with conventional deviated wells, has been shown to give significant benefits by providing offtake points in several slump blocks with one well, thereby improving the sweep efficiency and increasing the recovery whilst optimizing rig usage. A development plan has been formulated on this basis with a series of roughly parallel east-west horizontal oil producers, interspersed with horizontal water injectors. This plan is now being implemented and the first wells are now on production.
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Spontaneous imbibition in two different chalk facies
Authors J. Milter and I. E. I. OxnevadAn evaluation is made of the imbibition potential of two different chalk facies from outcrops in England and Denmark. Both chalk facies have low permeability, moderate to high porosity, and comparable low insoluble residues (< 5%), but different texture, depositional origin and diagenetic history. Spontaneous imbibition experiments were carried out on plugs with low initial water saturation and North Sea dead oil. Distinctly different production rates and production plateaus were observed for the two chalk facies. Careful investigations of the rock framework and pore system of the sample material form the basis for a theoretical description of wettability alteration and possible imbibition processes in the two chalks. The theoretical descriptions are used to rationalize the results from the spontaneous imbibition experiments. The results suggest that by knowing lithology, depositional history and degree of diagenetic alteration a relative potential of spontaneous imbibition in different chalk facies may be elucidated.
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Hydrocarbon generation modelling in the west of the Moesian Platform, Romania
More LessSilurian, Middle Carboniferous, Middle Jurassic and Sarmatian shales as well as Devonian bituminous limestones are thought to be main the source rocks in the study area. The thermal maturation level of the source rocks was computed using burial history curves for 175 wells. Maps of isoreflectance show that all the source rocks are mature in the north of the study area. The onset of oil generation from most of the source rocks took place during Sarmatian and Pliocene times, after most traps were formed. The calculations suggest that the volumes of hydrocarbons available to be reservoired are much greater than the volumes discovered to date.
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Draugen Field development; the role of gravity drainage and horizontal wells
More LessThe Draugen Field is an elongate, low relief, anticline containing mainly multi-Darcy sandstones. Oil initially in-place (STOOIP) is 182 x 10 6 Sm 3 . The 1987 Plan for Development and Operation (PDO) assumed a central cluster of 6 deviated production wells and 3 subsea water injectors at each end of the field. In addition two subsea wells would provide early production. Unsteady state relative permeability data indicate a residual oil saturation of 35%. In the full field simulation model this was increased to 40% to account for small-scale heterogeneity. The model yielded a recovery of some 67 x 10 6 Sm 3 . Modern steady state and centrifuge techniques have since demonstrated a long tail of very low oil relative permeability before reaching a residual oil saturation of some 15%. Fine grid simulations translated this into a gravity segregation process behind the displacement front. Other fine grid models reveal that horizontal wells will yield a slower build up of water cut than vertical wells. The increased productivity of the horizontal wells reduced the required number of platform producers from 6 to 5. Pseudo-relative permeabilities were developed to represent fine grid model performance in a new sophisticated full field model. This model predicted an ultimate recovery of 94 x 10 6 Sm 3 (40% increase). The additional predicted recovery is attributed to a reduction of the effective residual saturation and delayed water production associated with horizontal wells. In October 1993 Draugen started production from one horizontal subsea well, which has since demonstrated a better than expected coning performance. Production from platform wells was initiated in June 1994 with initial well rates up to 8000 Sm 3 per day, confirming the expected high productivity of horizontal wells. Optimization and tuning of facilities has since allowed the peak production rate for the field to be increased from the planned 17 500 Sm 3 per day to a present actual level of 24 600 Sm 3 per day. Further de-bottlenecking is ongoing with the aim of increasing process capacity.
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A generalized streamline method to predict reservoir flow
Authors Martin J. Blunt, Kuiran Liu and Marco R. ThieleWe present a generalized streamline method to model flow in porous media, including the effects of gravity and dispersion. We first describe the theory and discuss the approximations of the method, and then compare the predictions using the streamline technique against two-dimensional numerical simulations of incompressible miscible flow. In the cases we studied, the streamline method predicts recovery with an average error of at most 5%, where the principal flow directions are governed by the pattern of permeability, and for gravity numbers less than or equal to 1 and mobility ratios of 10 or less. The streamline method does not suffer from numerical dispersion and is more than 100 times faster than conventional simulation.
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Alluvial architecture and differential subsidence in the Statfjord Formation, North Sea; prediction of reservoir potential
Authors Alf Ryseth and Mogens RammStatfjord Formation sandstones (Rhaetian-Sinemurian) form important reservoirs in the North Viking Graben, and are still a target for exploration drilling. Sedimentological analyses from the Tampen Spur and Horda Platform show that the reservoir potential is controlled by the distribution, density and stacking pattern of multistorey/multilateral fluvial channel sandstones within successions of interbedded fluvial and interfluvial deposits. Formation thicknesses vary from about 50 m to more than 500 m within the study area. Empirical relationships linking the sandstone content to succession thickness, show that the proportion of channel deposits varies systematically with thickness, and indicate that the most sandstone-prone reservoirs associate with low to moderately high formation thickness. This suggests that differential subsidence influenced the architecture of the Statfjord Formation. Sandstone body stacking patterns derived from correlation panels show a sequential ordering of multilateral/multistorey sandstone sheets and intervals with a higher portion of mudrock and more isolated sandstone bodies. Sequence stratigraphic boundaries are recognized at the bases of multilateral sandstone sheets, and stacking patterns form a basis for detailed correlations within structural compartments with constant formation thickness. However, the number of recognizable sequences increases with increasing succession thickness, and the correct correlation of sequences across major fault systems pose major problems to stratigraphic studies.
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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)