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- Volume 9, Issue 3, 2003
Petroleum Geoscience - Volume 9, Issue 3, 2003
Volume 9, Issue 3, 2003
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Cenozoic basin development and stratigraphy of the Faroes area
More LessThe present paper reviews the geological development of the Faroes part of the NE Atlantic Margin in the Cenozoic Era. The Faroes area is located west of the post-Caledonian rift basin system formed in the Devonian after the collapse of the Caledonian mountains. Tectonic movements and plate reorganizations during several phases have strongly influenced sedimentation and erosion along the Caledonian front. During the Cenozoic four main tectonic phases with uplift, non-deposition or erosion, had a major influence on basin development and structural setting. First, the arrival of the Icelandic plume to the Faroes area caused a series of uplift phases, which are recorded in the Selandian–Early Ypressian sedimentary succession. Second, tectonic uplift in the Middle Eocene ended the period of almost continuous subsidence of the Judd Basin since the Danian. In the Middle and Late Eocene new depocentres formed in the northern part of the Faroe–Shetland Trough and in the Faroe Bank Basin. Third, due to uplift and sea-level fall in the Late Oligocene, widespread erosion of the Eocene and Oligocene successions resulted in a major unconformity on the shelf. Finally, in Neogene times, folding and uplift of the Fugloy Ridge occurred contemporaneously with renewed subsidence in the northern part of the Faroe–Shetland Trough and the Faroe Bank Basin.
Maps of Cenozoic key horizons illustrate this geological development from the start of the Palaeogene volcanism to the present day. Four regional maps are presented, two maps showing depths to Top Basalt and Top Palaeogene, and two isochore maps of the corresponding post-Basalt sediment sequences, the Palaeogene and the Neogene.
The petroleum system in the Judd Basin was strongly influenced by inversion in Middle Eocene to Recent times. Reservoirs and source rocks were uplifted up to about 600 m, with gas flushing, seal breakage and interruption in petroleum generation as consequences. Petroleum systems may also exist in the Faroe Bank Basin and in the northern part of the Faroe–Shetland Trough.
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Controls on facies architecture in the Brent Group, Strathspey Field, UK North Sea: implications for reservoir characterization
Authors Jenny Morris, Gary J. Hampson and Gregor MaxwellThe Brent Group reservoir in the Strathspey Field, UK North Sea comprises shallow marine, marginal marine and non-marine strata of variable reservoir character. Controls on the distribution, geometry, connectivity and orientation of sandbodies within the reservoir have been assessed via the application of high-resolution sequence stratigraphic methods to an integrated dataset comprising core, wireline log, 3D seismic and reservoir production data. The base of the Brent Group is a major sequence boundary overlain by weakly wave-influenced, shallow marine sandstones of the lowstand-to-transgressive Broom Formation. The overlying Rannoch Formation represents highstand progradation of a wave-dominated shoreface, which is truncated across a sequence boundary by a near-field-wide fluvio-estuarine complex (Etive Formation). Marginal-marine strata of the overlying Ness Formation are divided into field-wide units bounded by mudstones that form vertical pressure barriers. Major, oil-bearing fluvial sandbodies overlie sequence boundaries and the widths and orientations of two such sandbodiesare controlled by syn-depositional, intra-reservoir faults. The distribution of these sandbodies is therefore predictable. The Ness Formation is truncated by a major sequence boundary overlain by stacked, tidally influenced, shallow marine sandstones of the Tarbert Formation. The resulting facies architecture has been successfully used to refine reservoir models, identify bypassed oil and target infill wells.
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Syn-sedimentary shear zones
Authors I. Moretti, S. Calassou, P. Victor, M. Molinaro and L. MaertenIn deltaic and turbiditic deposits along passive margins, such as the Lower Congo basin on the West African margin, the main deformation is not induced by a regional tectonic stress field but by the increase of the sedimentary load leading to gravitational instabilities. The local stress field in such an environment is drastically influenced by the lithological discontinuities, which can reorientate the principal stresses induced by sedimentary loading. In this paper we document the localization of particular faults, called sedimentary shear zones (SSZ); these are formed along the borders of a sandy channel embedded in more fine-grained sediments, as a function of the lithological contrast. Furthermore we describe the reorientation of the stress field, perpendicular to the channel borders in the channel interior. Examples from 3D seismic lines and field studies in SW Ireland and Tunisia are compared with results from analogue and geomechanical models, leading to an integrated interpretation for the formation of the SSZ.
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Reservoir stress path during depletion of Norwegian chalk oilfields
By N. R. GoultyPore pressure drawdown during reservoir depletion results in reduced horizontal principal stresses within a reservoir due to three distinct mechanisms: normal compaction, poroelastic behaviour and normal faulting. Established relationships, based on simplifying assumptions, give the ratio of the change in minimum horizontal stress, S h, to the change in pore pressure, P, in terms of sediment properties for each mechanism. In spite of the approximations introduced by the assumptions, these relationships may be useful for discriminating between the mechanisms that control the reservoir stress path. For the Norwegian chalk oilfields, it is important to know whether normal faulting, in particular, is the governing mechanism because slip on active faults can shear well casings, and active faulting and fracturing can increase reservoir permeability. Previously reported field observations and laboratory measurements on chalk samples are compared to infer the mechanisms governing the reservoir stress path for the Ekofisk and Valhall fields. The amount of subsidence at the seabed observed at Ekofisk is evidence that the weaker horizons within the reservoirs are yielding plastically through pore collapse. Nevertheless, the reservoir stress path corresponds to that expected for poroelastic behaviour or normal faulting, and not that expected for plastic yielding.
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Estimation of oil and gas column heights in prospects using probabilistic basin modelling methods
Authors Øyvind Sylta and Wenche KrokstadSource rock and reservoir rock properties are often poorly constrained in the exploration for oil and gas. Geological analogues may be used to create source rock and reservoir rock models in areas with only sparse well data coverage. Exploration risks are often influenced by uncertainties in the rock facies models. This paper outlines a methodology for assessing the consequences of using two or more source and reservoir models on hydrocarbon phase distributions in prospects.
Each source rock and reservoir rock scenario is represented by computerized maps (grids) of thickness, porosities and other properties. The uncertainties of each scenario are described using probabilistic properties. The reservoir thickness may be represented by a uniform distribution with the mean described using a map (grid) with a standard deviation of, for example, 50 m. A Monte Carlo simulation is carried out for this part of the petroleum system and the resulting probabilities of oil and gas in prospects are compiled by weighting each run to calibration wells. The results can be plotted as a map of most likely oil and gas column heights. An uncertainty map is also plotted. The results can be used to rank drilling locations with respect to large oil columns and low uncertainties. The oil and gas column probabilities can be estimated for each well location.
As (more) wells are drilled within a petroleum system the best match simulations can be used to further refine predictions as well as to create an updated map of the petroleum system.
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Geomechanical properties related to top seal leakage in the Carnarvon Basin, Northwest Shelf, Australia
Authors David N. Dewhurst and Allison L. HennigThe Muderong Shale is the regional top seal in the Carnarvon Basin on the Northwest Shelf of Australia. Evidence for top seal breach in this area comes from post-Muderong plays and hydrocarbon shows. Capillary pressure tests show this shale has the capability of restraining gas columns in excess of 250 m height, a value which is unlikely to be reached due to the intrinsic weakness of the Muderong Shale. Apart from one example, all hydrocarbon columns so far encountered in the Carnarvon Basin are well below this limit. Geomechanical testing of the Muderong Shale indicates it is a weak rock, commensurate with its high illite–smectite content. Comparison of laboratory-generated failure envelopes with in situ stress conditions suggest that intact Muderong Shale is not generally at risk of hydrofracture but that pre-existing faults and fractures may well be critically stressed in the present-day stress field. It is postulated that such faults and fractures may be responsible for top seal failure in the Muderong Shale and the resultant presence of hydrocarbons in the post-Muderong succession.
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Multi-disciplinary study of the heavy-oil reservoirs in the Armatella Field, Sicily
Authors L. Ruvo, A. Aldegheri, R. Galimberti, E. Nembrini, L. Rossi and R. RuspiThe Armatella Field in SE Sicily is structurally complex with two fractured, carbonate reservoirs containing heavy-oils, with the heavier hydrocarbon overlying the lighter one. One well has been drilled in the field – a vertical pilot completed with two opposite, stacking, open-hole horizontal drains. A complex compositional evolution of the fluids produced has been observed. A reservoir study integrating geophysics, geochemistry, petrophysics and reservoir engineering assessed the reservoir geometry and the field production behaviour. This allowed the identification of two different phases of hydrocarbon migration that were geologically constrained according to the structural evolution of SE Sicily. The 3D structural reconstruction of the field, built with a Shared Earth Model, was utilized as input to a 3D dual porosity numerical model. The dynamic simulation allowed identification of the drilling location of an additional non-conventional well aimed at draining undeveloped reserves. The study used advanced laboratory methodologies for fluid characterization, state-of-the-art methods for analysing the reservoir fracture network and properly designed modules for simulating non-conventional completions in a 3D dynamic model.
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Stratigraphic–structural interpretation and hydrocarbon potential of the Alaşehir Graben, western Turkey
Authors M. Yilmaz and K. GelisliTwo different graben sets were developed in western Anatolia (Turkey) under the influence of Neogene extension. NE–SW orientated grabens formed during the Miocene and provided suitable environments for the deposition of lacustrine bituminous shales and fan delta sediments. Younger E–W orientated grabens formed during the Pliocene and locally intersected the older NE–SW grabens. Such intersecting graben areas are characterized by superimposed graben fills. The Alaşehir Graben is an example of such a configuration within the E–W orientated Gediz Graben. The hydrocarbon potential and superimposed configuration of the Alaşehir Graben were examined using seismic, gravity and magnetic data. Seismic data were interpreted in an interactive interpretation system, using additional physical parameters generated by calculating instantaneous attributes on time-migrated seismic sections, aiding determinations of lithology and seismic facies. The Alaşehir Graben contains four sedimentary units developed under an extensional tectonic regime and is a superimposed graben containing possible traps as well as a high potential for hydrocarbon generation.
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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)