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- Volume 9, Issue 4, 2003
Petroleum Geoscience - Volume 9, Issue 4, 2003
Volume 9, Issue 4, 2003
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Multidisciplinary stochastic impedance inversion: integrating geological understanding and capturing reservoir uncertainty
Authors P. S. Rowbotham, D. Marion, P. Lamy, E. Insalaco, P. A. Swaby and Y. BoisseauStochastic (or geostatistical) impedance inversion techniques have great potential in addressing key questions in reservoir characterization. They work at the vertical scale of reservoir models and, therefore, at higher resolution than the seismic data. They produce multiple equiprobable results which provide an assessment of, the uncertainties, and they are ideally suited for integrating non-seismic information in the inversion process. However, two issues have slowed the acceptance of stochastic impedance inversion techniques. First, there is suspicion of‘ unconstrained random noise generators’, which appear to offer extra information for free, and, secondly, managing and extracting value from multiple realizations is difficult. For these reasons, faster deterministic inversion approaches, resulting in a single lower-resolution impedance volume, with less quantified uncertainty, are more commonly used when building reservoir models.
To address the first issue, we have developed ways of integrating 3D constraints from sedimentary modelling with the geostatistical impedance inversion method, since these two approaches bring complementary information on reservoir properties. The resulting high-resolution multiple realizations of impedance are combined with uncertainties from petrophysical regression analysis to produce multiple realizations of reservoir properties (e.g. porosity), and from each an estimate of total pore volume. We illustrate the benefits of this multiple realization work flow applied to data from a shallow marine siliciclastic reservoir. A comparison of the seismic/sedimentologically constrained reservoir models with those constrained by well data only has demonstrated more accuracy and better control on the spatial variability of reservoir properties. In this example, however, adding more constraints results in a broader range of possible reservoir models and a more meaningful uncertainty assessment. We conclude that our models constrained by well data only were derived with unrealistic simulation parameters and an over-optimistic assessment of a priori uncertainty.
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The Rotliegend reservoir in Block 30/24, UK Central North Sea: including the Argyll (renamed Ardmore) and Innes fields
Authors Alan P. Heward, Paul Schofield and Jon G. GluyasRotliegend Auk Formation sandstones form the second most productive reservoir in the 30/24 fields and the major source of aquifer pressure support. In the Argyll Field, where the Zechstein oversteps beyond the Rotliegend on to Devonian continental sandstones, there were initial difficulties distinguishingbetween the Rotliegend and the Devonian.
Four facies associations are present in the Rotliegend Auk Formation: aeolian slipface sands, aeolian wind-ripple sands, water-lain Weissliegend sands and other water-lain conglomerates, breccias and sands. Five reservoir zones consist of different proportions of these facies which infill topography and onlap the Argyll high. Their distribution and character reflect periods of sediment supply, subsidence and fluctuating climatic conditions towards the margin of an interior continental basin.
The Auk Formation as a whole forms a high quality reservoir at depths of 3000–4000 m. The best intervals, with Darcy permeabilities, consist of coarse-grained Weissliegend sands. Two of the four initial wells in the Ardmore (Argyll) Field redevelopment are planned to target the Rotliegend reservoir.
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Syn-sedimentary faulting and the formation of localized reservoir sands: Carboniferous examples from the Campine Basin, Belgium and the Dutch offshore
Authors M. Kosters and M. E. DonselaarThe Westphalian B in the Campine Basin in Belgium contains a low net-to-gross succession of fluvial channel and crevasse sandbodies embedded in lacustrine and floodplain claystone and siltstone. Study and correlation of closely spaced boreholes reveals a localized 15–25 m thick succession of stacked fluvial channel sandbodies in this overall low net-to-gross setting. This concentration of sandbodies is interpreted as the fill of a tectonically induced palaeo-valley based on the orientation of syn-sedimentary faults and the palaeogeographical setting of the Campine Basin, far away from the Westphalian sea. The depositional model was used to interpret stacks of fluvial sandstone of the Caister Sandstone (Westphalian B) in the Dutch offshore and may guide finding economic reservoirs in the overall low net-to-gross labyrinth-type fluvial architecture in this area and in comparable structural settings.
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Hydrocarbon leakage processes and trap retention capacities offshore Norway
Authors Hege M. Nordgård Bolås and Christian HermanrudAssociations between high overpressures and sparse hydrocarbon occurrence are commonly ascribed to hydrocarbon leakage through pressure-induced fractures in the cap rock. However, several hydrocarbon traps in the North Viking Graben area in the North Sea still contain abundant commercial volumes of hydrocarbons at very high pore pressures. By contrast, a majority of the overpressured structures at the Halten Terrace further to the north have leaked hydrocarbons, even at considerably lower overpressures.
A selection of wells in the North Viking Graben and the Halten Terrace areas was investigated to find possible explanations for these observations. Distinct regional differences emerged, as the emptied reservoirs at the Halten Terrace generally have higher retention capacities than the overpressured discoveries in the North Viking Graben area. Thus, there appears to be a lack of any clear relationship between structures emptied of hydrocarbons and low retention capacities, which could be expected if pressure-induced fracturing of the cap rock was the main process of the hydrocarbon leakage.
The regional differences in retention capacities were mainly attributed to different leakage processes in the two basins. Stress history variations are suggested to be the main controlling factor of these leakage processes.
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Thermal history modelling in the southern Faroe–Shetland Basin
Authors A. D. Carr and I. C. ScotchmanHydrocarbon generation is a temperature-dependent process and the prediction of hydrocarbon generation in basin modelling requires the crustal heat flow history to be predicted. Tectonically, the Faroe–Shetland Basin (FSB) has been subjected to a number of Cretaceous rifting events, followed in the Tertiary by Balder volcanism and, finally, by Oligo-Miocene inversion. In this study the thermal history of the FSB is derived using two independent methods (rifting–volcanic–subsidence history and maturation). The methodology is described using two wells (204/19-1 and 205/22-1) in the southern FSB. The vitrinite reflectance results predicted by the PresRo® model, which was devised for modelling maturation in overpressured basins such as the FSB, produced predicted vitrinite reflectances that matched the measured values. The method was then applied to a pseudowell within the Foinaven sub-basin, and the predicted vitrinite reflectance values for the Kimmeridge Clay Formation source at 8 km depth indicate that the source is still mature for oil generation due to the extensive retardation induced by the highly overpressured, argillaceous Mesozoic sediments.
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Potential source rocks for the crude oils in the Ikizce and Tokaris oil fields, SE Turkey
Authors A. Sari, I. Bahtiyar, R. L. Brenner and A. U. DoganThe source rock and reservoir characteristics of the Upper Cretaceous‘ A’ Member of the Karababa Formation (Santonian–Coniacian) and the Karabogaz Formation (Campanian) and their relationships to the crude oils produced from the Ikizce and the Tokaris oil fields, were studied using a variety of organic geochemical methods. The Karabogaz Formation is composed of limestone and chert, while the Karababa-A Member consists of clayey limestones. Both formations constitute important source rocks in the Adiyaman Basin. The crude oils examined in this study were produced from reservoir rocks of the same age in two adjacent oil fields. Biomarker characteristics in source rock samples from the Ikizce-A and Tokaris-A wells show that the Karababa-A Member and the Karabogaz Formation were deposited in reducing environments and are characteristic of carbonate facies. Correlations between the source rocks and the crude oils, based on qualitative and quantitative biomarker distributions, indicate that the oils from the Ikizce and Tokaris fields are mixed oils that were derived from both the Karababa-A Member and the Karabogaz Formation source rocks.
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Indicators of hot fluid migration in sedimentary basins: evidence from the UK Atlantic Margin
Authors H. L. Wycherley, J. Parnell, G. R. Watt, H. Chen and A. J. BoyceMicrothermometric, petrographic and isotopic methods have been used to detect evidence for hot fluid flow in Mesozoic and Tertiary sediments from the NW UK continental margin, West of Shetland. New data presented here show that temperatures are hotter by c. 40°C in Tertiary samples than in the underlying Jurassic and Cretaceous sediments in wells 204/28-1, 206/5-2, 208/27-1, especially in cements from samples as young as mid–upper Eocene in age. Paleocene samples can be discriminated from older (Jurassic and Cretaceous) and younger (Eocene) sandstones on the basis of silica cement morphology and cathodoluminescence zonation. Jurassic, Cretaceous and Eocene quartz cements show oscillatory zoning as a consequence of relatively slow burial cementation. In direct contrast, rapid precipitation of silica cements from the cooling of hot fluids has produced unzoned cements in all but one Paleocene sample. No evidence for unzoned quartz cements was noted in any pre-Paleocene or Eocene samples. The restriction of hot fluid inclusions and unzoned cements to the Paleocene and post-Paleocene is consistent with lateral focusing of hot fluids. Isotopic data from kaolinites indicate that these fluids are best represented by mixtures of Mesozoic or Tertiary meteoric waters and marine porewaters that have undergone isotopic alteration through interaction with volcanic material. Our results indicate that hot fluid flow occurred over a relatively long time-scale (i.e. several million years), which may have important consequences for the degradation of reservoired hydrocarbons in West of Shetland Paleocene plays.
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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)