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- Volume 9, Issue 2, 2003
Petroleum Geoscience - Volume 9, Issue 2, 2003
Volume 9, Issue 2, 2003
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2D modelling of hydrocarbon migration along and across growth faults: an example from Nigeria
Authors Gérard Caillet and Sébastien BatiotTemis 2D was used to study hydrocarbon migration and fluid distribution in an area of the Niger Delta. In this setting, high pressures are related to a high sedimentation rate, and pressure compartments are delineated by growth faults. A growth fault is regarded as a hydro-mechanically active zone contributing both to a release of high pressures and to hydrocarbon migration from the deep mature source rocks to shallower reservoirs.
Overpressures are generated in confined systems where water flow is extremely low. The most significant parameters causing the generation of overpressures are very low shale permeability and rapid burial. In 2D modelling, pressure calibration is obtained by adjusting cap-rock permeability and by properly simulating reservoir connectivity. The accuracy of fluid flow simulation is highly dependent on lateral transmissibility across reservoirs and/or faults. When pore pressure reaches fracture pressure, the vertical permeability in the model must be increased to simulate release of the excess pore pressure by fracturing. Simulating hydrocarbon migration, which is dependent on both permeability and capillary pressure, from a high-pressure domain to a lower pressure domain without losing the pressure distribution, requires a detailed geological model and a thorough calibration.
In a deltaic system, such as the Niger Delta, a growth fault behaves as a complex zone for fluid flow, due to a relatively low horizontal permeability and a significant transient vertical permeability. In detail, permeability and capillary pressures in the fault zone are dependent on clay content (clay smearing) along the fault, possible cataclasis reducing sandstone permeability, and lithology juxtaposition, forming a complex structure along which fluids have to move. In this approach the fault is considered as a permanent active zone with transient fluid and pressure transfers, implying hydro-mechanical coupling.
The aim of 2D basin modelling is to simulate the geological history of a petroleum system in order to understand and quantify the hydrocarbon generation, migration and trapping. As a control of a correct simulation, the main hydrocarbon-bearing reservoirs must be restored with correct temperature, pore pressure, saturation and gas:oil ratio (GOR). The results of the present simulation show that all these parameters, and particularly pore pressures and GOR, are in accordance with well data. Fluid flow modelling allows vertical migration of the hydrocarbons from the deep overpressured domain to the hydrostatic domain, and a partial lateral transfer between adjacent reservoirs, without full pressure equalization. The model correctly predicts hydrocarbons in the main reservoirs and the appropriate GOR, even though local variations are not well simulated. Abnormally high pressures are maintained within the system even though fluid flow and hydrocarbon migration are simulated in a dynamic mode. The thorough geological description of the fault zone, which allows a detailed input of petrophysical parameters, is the key to such a result.
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Integrated Palaeogene palaeobathymetry of the northern North Sea
Authors Tomas Kjennerud and Gavin K. GillmoreThis paper seeks to expand understanding by providing a wider and more integrated approach to the problem of palaeobathymetric reconstructions of the Palaeogene for the northern North Sea. This has been achieved by combining published and unpublished micropalaeontological studies from 12 wells between 58°N and 62°N, with regional reconstructed sections. These estimates were further integrated with regional seismic isopach maps to produce palaeobathymetric maps. The present results differ from previously published works in that they were integrated spatially, based on the type of regional depositional sequence they represent. The East Shetland Platform was uplifted and acted as a source area of sediment in the Palaeogene, with a palaeobathymetry of 800 m in the Viking Graben early in this period. During the Eocene, the deeper part of the generally N–S trending basin became narrower. A significant shallowing took place in the Oligocene, which was in part controlled by tectonic uplift of the basin.
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Alwyn North Triassic Main gas-condensate: drilling deeper promotes production
Authors S. D. Harker, G. Richardson, L. E. Sides and R. CooperProduction of oil and gas in the Alwyn North Field, UKCS, commenced in 1987 from Middle Jurassic Brent and Lower Jurassic Statfjord reservoirs. In 1988, a deepened Statfjord producer well (3/9a-N21) detected gas in the underlying Triassic, but testing was not possible at that time. The 3/10b-2 exploration well, drilled in 1992 to the east of the field, tested gas at low rates from a poor quality Triassic reservoir section. In 1995 well 3/9a-N33, a deviated well, was drilled from the Alwyn platform to evaluate the productivity of the deep Triassic. This well penetrated 770 m of Upper Lunde section, which was tested at 1.3×106 m3 per day of gas plus 4400 STB per day of condensate.
The Alwyn trap comprises a westerly dipping fault panel structure. Erosion over the crest of the tilted panel and the eastern-facing scarp slope by the Base Cretaceous Unconformity (BCU) truncates the Jurassic section down to the Upper Triassic. Sealing of the Triassic Main accumulation is by uppermost Triassic shales of the overlying Statfjord Formation and by Cretaceous mudrocks onlapping onto the BCU. Hydrocarbon charging of the Triassic Upper Lunde sandstones is from mature Late Jurassic Kimmeridge Clay source rocks that are juxtaposed against the reservoir along parts of the eastern frontal fault of the Alwyn panel.
The Upper Lunde (of Carnian to Rhaetian age) is a low net:gross reservoir section up to 800 m thick. The sediments are of semi-arid fluvial, floodplain and lacustrine origins, with the best reservoirs occurring in fluvial channel sandstones. The Late Triassic comprises four informal zones from A (top seal), through B and C to D reservoirs, above the Middle Lunde shale. The Triassic reservoir fluids are gas-condensate in the B and C units with an intraformational seal at the C–D boundary, beneath which lies volatile oil in the D unit.
A total of eight further Triassic production wells were added to the AlwynNorth Field by the end of 2001, as the development plan for Triassic Main progressed. These wells contribute in the order of 60% to the Alwyn North daily production.
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A 3D outcrop analogue model for Ypresian nummulitic carbonate reservoirs: Jebel Ousselat, northern Tunisia
A three-dimensional high resolution sequence stratigraphic model of an Ypresian nummulitic carbonate ramp and organic-rich basin is presented based on outcrops in Central Tunisia. The sedimentation pattern is influenced by the interplay of different orders of variations in eustatic sea-level (third to fifth order), the pre-existing palaeotopography, and probably some synsedimentary tectonism (differential subsidence). Time-equivalent rocks deposited in a comparable structural and depositional setting along the northern margin of the African plate are hydrocarbon bearing (Tunisia and Libya). This example may thus serve as an outcrop analogue for this petroleum system, providing valuable information on the sub-seismic-scale distribution pattern, geometries and heterogeneities of both the reservoir and source rock facies.
The studied outcrops cover an area of 10 by 20 km where present-day valleys provide three-dimensional access to the rocks. In addition, the transition from the inner/mid-ramp, with nummulitic reservoir facies, to the carbonate source rocks in the basin is exposed in continuous outcrops. This transition takes place in about 3 km, a distance generally beyond the resolution of well spacing. Based on the physical tracing of beds, and the recognition of three orders of depositional sequences (third to fifth) a high resolution time framework is constructed. The accumulation of large nummulites (best reservoir facies) is stratigraphically controlled, and occurs in the transgressive phases of the landward-stepping fourth order cycles (overall transgression). Carbonate production was at that time so high that aggrading geometries are observed during these transgressive pulses. Our observations show that size, morphology and reproduction strategy of foraminiferal assemblages and, particularly, nummulites and Discocyclina, are related to changes in water depth and, consequently, in accommodation space. A regional east–west cross-section shows significant thickness variations of the Ypresian succession that were probably controlled by synsedimentary differential subsidence. The detailed, sub-seismic-scale, geometrical information on stratal patterns and lateral facies change are quantified, and used in a 3D numerical stochastic modelling (HERESIM) of this petroleum system.
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Integrating production history into reservoir models using streamline-based time-of-flight ranking
Authors Y. Wang and A. R. KovscekThe reservoir models generated by geostatistical techniques, but unconstrained to production history, provide equally probable reservoir descriptions that honour observed geology. However, flow simulation results on these models may vary widely where there is geological uncertainty. Constraining geostatistical models to known production history reduces this uncertainty. To this end, a streamline-based algorithm is proposed for ranking geostatistical realizations with regard to production history. First, a rapid, streamline-based inversion method is applied to obtain a history-matched reservoir model. Then the streamline geometries and properties, such as the time-of-flight, are computed without full flow simulation for the history-matched model and the geostatistical models examined. Each model is compared to the history-matched model with regard to streamline properties. In this way, reservoir models that match production history and honour known geological information are obtained. Synthetic examples using up to 600 distinct reservoir models demonstrate computational efficiency and also show that the method readily selects the most appropriate permeability fields. Flow simulations confirm that the selected permeability fields are satisfactory. The technique also appears to be appropriate for downscaling history-matched reservoir models from coarse to fine grids.
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Flow characterization of glauconitic sandstones by integrated Dynamic Neutron Radiography and image analysis of backscattered electron micrographs
Authors Mikael Solymar, Ida L. Fabricius and Mike MiddletonThe effects of porosity and pore geometry on the fluid saturation and immiscible displacement of greensand reservoir rocks were investigated on eight samples from the North Sea basin. Dynamic Neutron Radiography (DNR) was used to image the front stability during displacement experiments where oil was infiltrating water-saturated samples. The flow characteristics were related to petrography and pore geometry, which may be determined by image analysis of backscattered electron (BSE) micrographs. The fluid saturation observed in each DNR image was modelled in a corresponding BSE image as a means of evaluating the effect of pore geometry on front stability. Piston-like displacement and channelling were observed and these flow patterns were found to reflect variations in pore geometry. The samples with piston-like displacement have homogeneous pore space, whereas the samples with channelling have heterogeneous pore space, with spatial variations in porosity and pore size. The modelled saturation distribution was interpreted using results from petrographic and petrophysical analyses. The results suggest that the micropores of the glauconite grains and clay minerals contain water, whereas the oil is moving through the intergranular pore space during the displacement experiment.
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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)