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- Volume 7, Issue 4, 2001
Petroleum Geoscience - Volume 7, Issue 4, 2001
Volume 7, Issue 4, 2001
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Application of quantitative palaeobathymetry in basin modelling, with reference to the northern North Sea
Authors Tomas Kjennerud and Øyvind SyltaThe effect of using quantitative palaeobathymetric input in 1D tectonic modelling, 2D forward siliciclastic depositional modelling and 3D hydrocarbon migration modelling has been tested and quantified for northern North Sea datasets. In order to perform the latter, a 3D method for restoring palaeobathymetry has been developed, based on a previously documented 2D geometrical approach. Quantitative palaeobathymetry constrains the basin shape through geological time. Bathy-metric input has been shown to be important in defining tectonic phases in the post-rift phase in the northern North Sea and to constrain the possibility for slope failure and mass flows. In hydrocarbon migration modelling, it has been shown that palaeobathymetric input may change the migration direction through time, compared to modelling runs performed with no palaeobathymetric input.
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The geological structure and petroleum potential of the Kola-Kanin Monocline, Russian Barents Sea
More LessThe Kola-Kanin Monocline has been recently recognized as a potentially prospective region for hydrocarbon discoveries. There may be good generating potential within Riphean grabens. Sedimentary sequences of the Riphean subplatform and Vendian terrigenous deposits could contain hydrocarbons. The top of the Riphean section is now a monoclinal surface dipping NE towards the South Barents Basin. The surface of the monocline is complicated by highs and ridges, which trend NW along the coast of the Kola Peninsula. Here, prospective plays may be present in the form of anticlinal and fault-controlled traps in Riphean to Carboniferous rocks, as well as in pinch-outs of Devonian and Carboniferous clastic rocks. In the central and northern parts of the monocline, prospects can be expected at accessible depths, mainly in Carboniferous to Permian carbonate build-ups, but also in Upper Devonian and Silurian build-ups: the Permian carbonates are the main exploratory targets. In the basinward part of the monocline, stratigraphic and lithologic traps may occur in Upper Permian clinoform sandstones and in Triassic sandbars.
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A log correlation of the Rotliegend of the northern Cleaver Bank High: the search for controls on reservoir sand distribution
Authors R. J. Bailey and D. A. LloydGamma ray log correlations of some 50 Open File wells were used to investigate the distribution and relative age of aeolian Leman Sandstone developments across the northern Cleaver Bank High. The correlations led to a sequence stratigraphic interpretation based on a depositional record of climatically forced fluctuations in the level of the Silverpit Formation playa lake system. This confirmed the widely reported diachroneity of the Leman Sandstone and identified the onlapped Base Permian palaeotopography and climatically forced, generally positive, changes in the water budget of the Silverpit Lake as the chief controls on aeolian sand distribution. However, a ‘1/fn’ power law distribution of changes in water budget is preferred to the idea of strictly cyclic climatic control. On this basis, the transgression of the northern Cleaver Bank High and the occurrence of aeolian and lacustrine end-member facies within depositional sequences of uniform thickness can be understood. Interval isochores were used to derive palaeotopographic maps of the Base Permian. Taken in conjunction with the observed facies of the onlapping depositional sequences, the maps locate under-explored basal aeolian Leman Sandstone play fairways.
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Factor analysis of seismic multiattributes for predicting porosities using sequential nonlinear regression: the thin carbonates of the BMB Field, Poland
Authors Raef A. Elsayed and Ryszard SlusarczykFor a thin reservoir, such as the Zechstein Main Dolomite (generally 33–83 m thick) of the BMB oil and gas field of Poland, where the thickness (c. 40 m) is often around a quarter of the dominant wavelength, the composite seismic response results from variations in the petrophysical properties, thickness, lithology, effective pressure and temperature, as well as in the acoustic impedance of the encasing materials. To use the BMB Field 3D seismic data for porosity prediction, 20 post-stack attributes were extracted from a seismic volume, defined by two zero-crossing time horizons that bound the reflections of the Main Dolomite. Because of the large number and the interdependency of the extracted attributes, principal component factor analysis was applied, resulting in the coding of 70% of the variability of the extracted attributes, in six orthogonal factors. Sequential nonlinear regression revealed that the first three factors, F1, F2 and F3, are the significant predictors of porosity. Cross-validation indicated a class of poorly estimated porosities resulting from poor quality/complexities in the seismic data, and a class of good porosity estimates that were subsequently used in a final cross-validation for establishing optimum weights and orders of porosity prediction polynomials. The final cross-validation indicated optimum orders of five, three and two for polynomials in F1, F2 and F3, respectively and optimum weights corresponding to validation well No. 1 (MO-3).
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Sequential dip-slip fault movement during rifting: a new model for the evolution of the Jurassic trilete North Sea rift system
Authors R. J. Davies, J. D. Turner and J. R. UnderhillControversy has long surrounded the kinematics of faulting in the Middle–Late Jurassic North Sea trilete rift system. Integration of structural styles and subsidence analysis derived from well-constrained seismic interpretation enables a new, unified model to be proposed in which strike-slip was negligible, dip-slip extension predominated throughout the rifting episode and normal faults were active sequentially not synchronously. Extension was initiated on N–S and NNE–SSW trending faults during the Bathonian and Callovian, NE–SW and E–W structures during the Oxfordian and NW–SE faults during the Kimmeridgian and Volgian. The results allow us to speculate that fault activity was driven by variations in the prevailing far-field stress regime that were superimposed upon a trilete junction that formed as consequence of Middle Jurassic thermal doming. Significantly, rotation of the stress field during rifting is similar in other rifts, such as the Afro-Arabian system.
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Overpressure phenomena in the Precaspian Basin
More LessOverpressured zones in the Precaspian Basin occur at depths below 4000 m. The most extensive zone is in the subsalt reservoirs throughout the basin. In spite of the extended literature database on overpressure phenomena, the Precaspian Basin and its Palaeozoic rock sequence is of a special interest because of its long geological history. The delineation of overpressure generation in the completely compacted sediments is very important in order to exclude disequilibrium compaction as the most significant overpressure mechanism for the Tertiary basins. Seal effectiveness and pressure compartment longevity have mainly resulted from other processes: origin of secondary minerals, hydrocarbon saturation and bitumen incorporation in mudrocks. Solid bitumen precipitation in clays forms a more perfect seal than the capillary pressure. The Astrakhan gas field is the best example, where the compositional evolution of formation fluids has changed the clay permeability.
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The distribution of Cretaceous and Paleocene deep-water reservoirs in the Norwegian Sea basins
Authors Luis Vergara, Ian Wreglesworth, Mark Trayfoot and Geir RichardsenFacies maps for selected Cretaceous and Paleocene deep-water sandstone reservoirs in the Norwegian Sea constitute an exploration tool and allow description of the basin infill in relation to tectonic phases. Sequences K40 (middle–late Albian) and K60 (middle–late Cenomanian) formed in an immature basin where most of the fan systems and slumps were derived from local highs. Sequence K80 (Coniacian–late Santonian) contains sandstones interpreted to be slumped deposits in parts of the Halten and Dønna terraces (Lysing Formation), but with fans of widespread extent in the Vøring and northern Møre Basin. The K85–K90 sequence set (early Santonian–late Campanian) contains sandstones equivalent to the Nise Formation that are the main potential reservoirs in the Vøring Basin; they were fed by multiple entry points and developed into areally extensive basin floor thicks. Sequence Pg10 (Danian–Selandian: ‘Egga’ Member) is interpreted to comprise a basin floor fan in the Ormen Lange discovery. During this cycle the Halten Terrace rotated eastwards exposing Upper Cretaceous mudstones. Vast amounts of sediment were deposited in the western Møre and Vøring Basin around new exposed areas.
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Source potential of the Mesozoic–Cenozoic rocks in the South Caspian Basin and their role in forming the oil accumulations in the Lower Pliocene reservoirs
Authors Akper A. Feyzullayev, Ibrahim S. Guliyev and Mushfig F. TagiyevThe source potential and organic maturity of the shales alternating with the reservoir beds in the Lower Pliocene Productive Series – the major oil-bearing unit in the South Caspian Basin – are inadequate to have formed the observed petroleum accumulations. A geochemical study of rocks collected from wells and outcrop localities has been carried out to assess the oil- and gas-generative properties of the Middle Jurassic to Lower Pliocene sediments of the basin. On the whole the section under review is characterized by poor to good organic richness and low hydrogen index, suggesting type 2 and 3 kerogens. Organic-rich sediments are relatively frequent in parts of the Oligocene–Miocene interval. Source-to-oil correlation based on carbon isotope signatures points to a largely epigenetic origin for the oils reservoired in the Lower Pliocene. Isotopically, the oils in these Productive Series reservoirs are best correlated with organic matter contained in the Miocene sediments.
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Coupled changes in pore pressure and stress in oil fields and sedimentary basins
More LessRepeated pressure measurements undertaken throughout the depletion of oil fields demonstrate that reduction in pore pressure is accompanied by a reduction in total minimum horizontal stress (σh), a phenomenon described herein as oil field-scale pore pressure/stress (P p/σh) coupling. Virgin pressure measurements (i.e. those unaffected by depletion) through normally and overpressured sequences in sedimentary basins demonstrate that overpressure development is accompanied by an increase in σh, described herein as sedimentary basin-scale P p/σh coupling. With depletion of the Ekofisk Field, North Sea, minimum horizontal stress decreased at approximately 80% of the rate of reduction of reservoir pore pressure (i.e. Δσh/ΔP p≈0.8). Virgin pressures measured in exploration wells surrounding the Ekofisk Field (Norwegian quadrants 1 and 2) indicate that with overpressure development Δσh/δP p≈0.73 (assuming shallow, normally pressured sequences are representative of overpressured sequences prior to overpressure development). Hence, despite the different temporal and spatial scales, the rate of decrease of minimum horizontal stress with pore pressure due to depletion of the Ekofisk Field is similar to the rate of increase of minimum horizontal stress with pore pressure due to overpressure development in the surrounding region. Basin-scale exploration pressure data in the Ekofisk region may thus provide an indication of the reservoir stress changes associated with depletion. Knowledge of such stress changes is critical because they can lead to the collapse of uncased wellbores, sand production and to faulting/fracturing and seismicity with field development.
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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)
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