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- Volume 13, Issue 1, 2007
Petroleum Geoscience - Volume 13, Issue 1, 2007
Volume 13, Issue 1, 2007
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Using geological information to optimize fracture stimulation practices in the Cooper Basin, Australia
Authors Emma J. Nelson, Simon T. Chipperfield, Richard R. Hillis, John Gilbert and Jim McGowenFracture stimulation treatments of tight formations in the Cooper Basin can be associated with hydraulic fracture complexity that results in abnormally high treating pressures, low proppant placement and poor economic success. Pre-completion (image log and rock testing data) and post-completion data (fracture stimulation pressure decline plots) were reviewed in 13 treatment zones from the Cooper Basin. Rock strength, image log and stimulation data were available for seven of those zones.
From this analysis, a distinct relationship between rock properties (shear and tensile rock strength), geological weaknesses (natural fractures and other fabrics) and fracture stimulation complexity (net pressure, near-wellbore pressure loss and pressure-dependent leak-off) was observed. It is proposed that high in situ stress (S hmin≧0.8 psi ft−1; 18.1 MPa km−1), a large contrast in tensile strength between intact rock (T>1015 psi (7 MPa)) and pre-existing weaknesses in the reservoir (T∼0) promote the propagation of fracturing fluid along multiple fracture pathways, and thus abnormally high treating pressures, low proppant placement and poor economic success during fracture stimulation treatments in the Cooper Basin.
The methodology used to predict in situ stress and hydraulic fracture complexity herein presents a potential generic approach that can be used in similar basins where hydraulic fracture complexity is a problem or where conventional stimulation practices are unsuccessful.
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A new technique for evaluating coarse grids based on flow thresholding
Authors Pinggang Zhang, Gillian E. Pickup and Michael A. ChristieCurrent upgridding techniques usually require the scale-up factor to be known a priori and, in practice, the scale-up factor is selected rather subjectively. The main consideration is that the scale-up factor should be large enough for practical use and not so large that the results are likely to be very inaccurate. A more objective approach to selecting the scale-up factor is desirable. This paper proposes a novel approach to determine a more appropriate scale-up factor for a coarse model. The new approach is based on an analysis of the flows in the fine-scale model. The regions that make a significant contribution to the flow are identified using a thresholding technique. A range of scale-up factors is tested and high flow regions are identified in each case. The percentage overlap (denoted by R o) of the high flow regions in the coarse and fine grids is then calculated. The value of R o can be used as a predictor of the accuracy of upscaling and the appropriate coarse grid size can thus be evaluated. When the upscaling is performed using a global method, there is little extra computational cost. This method is suitable for use in multi-phase flow simulations of 3D heterogeneous reservoir models. The technique is demonstrated using a simulation of a waterflood in a highly heterogeneous 2D model.
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Hierarchical approach for simulating fluid flow in normal fault zones
Authors Silje Støren Berg and Erlend ØianTwo-phase flow in faults is complex and difficult to predict. To analyse the effect of fault zones on fluid flow, this article presents a hierarchical geological/numerical framework aimed at simulating two-phase flow. The starting point is that fault zones consist of structures at several length scales, with each scale represented by suitable techniques within the same numerical model. A series of two-phase flow simulation experiments was conducted on four geological cases: one reference case with undeformed host rock and three cases with increasingly more complexity added to them. All the structures consist of lower permeability fault rocks in a high permeability host rock. The simulations were performed using an in-house flow simulator. The fault core (large scale) was modelled explicitly through local grid refinement, the subsidiary faults (intermediate scale) were represented in a discrete manner, while an upscaling procedure captured the effect of the deformation bands (fine scale). The simulation results show that each scale has a significant effect on the saturation, pressure drop and oil production, and that capillary pressure and anisotropic permeability are important parameters. The results emphasize the importance of the scale-dependent approach for analysing the effect of faults on two-phase flow.
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Petroleum generation and migration in the ‘Tight Gas’ area of the German Rotliegend natural gas play: a basin modelling study
Authors D. Schwarzer and R. LittkeThe Northwest German Basin is an important hydrocarbon province with considerable reserves of natural gas accumulated at its centre. To unravel the thermal and maturation history of the Carboniferous source rocks, particularly gas generation and migration, a combined petrological–geochemical and numerical basin modelling study was performed. Generally two main phases of maturation can be assigned to the Triassic–Late Jurassic and latest Cretaceous–Present intervals. Maturity data reflect the latter event and are consistent with a variable heat flow of 60–63 mW m−2 during Cretaceous–Tertiary burial which accounts for considerable late gas generation. Vitrinite reflectance data and maturity modelling show the Top pre-Permian strata in the northern part of the basin to be in the gas window at present, with a rather uniform maturity of VRr = 1.5% to 2.0% (at 4600–5100 m). However, the important top coal marker is at different depth levels and reveals a more complex coalification pattern, suggesting a strong structural control on maturation of source rocks. This effect is influenced locally by the high thermal conductivity of large salt bodies in the overburden. A significant delay in gas generation from source rocks at elevated horst blocks can be observed. The generation and migration of pre-Westphalian gas started during Late Carboniferous times, when much of the gas was lost from the basin due to ineffective seals. With ongoing burial, gas migration from Westphalian source rocks started in Early Triassic times within Permian graben areas, but was actually delayed until the Late Cretaceous at highly elevated horst blocks. The gas from early migration phases was replaced almost entirely by successively younger Westphalian gas.
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Sandstone compaction, grain packing and Critical State Theory
More LessBased on the physics of grain packing in a granular material, this paper demonstrates that sands or sandstones are modelled most correctly by Critical State Theory, which can be used to define a consistent compaction relationship for use in rock mechanics or reservoir simulation. The theoretical model is compared with experimental data for volume and permeability variation during loading or unloading.
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Wettability of chalk: impact of silica, clay content and mechanical properties
Authors S. Strand, M. L. Hjuler, R. Torsvik, J. I. Pedersen, M. V. Madland and T. AustadThe success of improved oil recovery from natural fractured chalk fields by injection of water depends largely on the wetting conditions of the reservoir rock and also, to some extent, on the compaction due to water weakening of the formation. Samples from outcrops are often used to mimic the reservoir properties in laboratory work. The present study illustrates that care must be taken when selecting outcrop material; in particular, the content of silica will affect these important properties. Chalk samples from Aalborg, which contained significant amounts of silica and minor amounts of clay (6.3 wt% Si), were studied by SEM and the mineral properties of the silica characterized. The surface chemistry of the porous medium was different from chalk containing smaller amounts of silica and clay (1.4–2.8 wt%). In the presence of a crude oil with high acid number and initial formation water, the water-wet fraction of Aalborg chalk remained close to 1.0 after aging for four weeks at 90°C in the crude oil. The Amott–Harvey wetting index showed, however, the wetting condition to be close to neutral, and only small amounts of water and oil imbibed spontaneously at the residual saturations. The difference in wetting conditions due to different content of silica and clay is also reflected in differences in the mechanical properties. It appeared that the mechanical strength, as studied by a large number of tests, became weaker as the water wetness decreased. The effect of wettability on the water weakening of chalk is discussed in terms of chalk dissolution and the chemistry associated with thin water films. As an overall conclusion and recommendation, a careful comparison should be made of the Si-content in the reservoir rock and outcrop chalk when picking material for laboratory experiments.
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How depositional texture and diagenesis control petrophysical and elastic properties of samples from five North Sea chalk fields
Authors Ida L. Fabricius, Birte Røgen and Lars GommesenChalk samples from Dan, Tyra, South Arne, Valhall and Ekofisk fields were collected from hydrocarbon-bearing intervals in the Cretaceous Tor and Palaeogene Ekofisk formations in the central North Sea. The samples were compared with respect to stable isotope ratios, lithotype, texture, porosity, permeability, capillary entry pressure, as well as the dynamic elastic Biot's coefficient and Poisson's ratio. The depositional texture and present grain-size distribution were quantified by petrographic image analysis. Oxygen isotope ratio and Biot's coefficient were used as indicators of cementation.
Porosity varies more than 20 porosity units within each hydrocarbon field and is controlled by three parameters: (1) sorting as expressed by Dunham texture, so that mudstones tend to have highest porosity and packstones the lowest; (2) sorting of the carbonate mud, where a mixture of clay-size chalk particles and silicates tend to reduce porosity; and (3) by pore-filling cementation. The relative significance of these parameters varies with field and formation. The presence of chalk clasts as an indicator of re-deposited chalk seems to have no relationship to porosity. Permeability and capillary entry pressure depend on porosity and mineral content as expressed in specific surface. Prediction of permeability and capillary entry pressure may be aided by information on carbonate content or on Poisson's ratio.
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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)