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- Volume 8, Issue 2, 2002
Petroleum Geoscience - Volume 8, Issue 2, 2002
Volume 8, Issue 2, 2002
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Injected and remobilized Eocene sandstones from the Alba Field, UKCS: core and wireline log characteristics
Authors Davide Duranti, Andrew Hurst, Chris Bell, Sheila Groves and Rex HansonDepositional and remobilized sandstone units are identified in core from the Eocene sand-rich deep-water Nauchlan Member and termed stratified and unstratified facies, respectively. The unstratified facies association records an increased intensity of sand remobilization, and inferred fluidization, upward. Unstratified facies have lower average porosity and permeability than stratified facies. Bulk density and acoustic velocity are higher in unstratified facies than in stratified facies. The general geometric relations of the reservoir can be inferred from a correct identification of the facies. Correlation of borehole data with (3D PS) seismic data enables the seismic to be used as a lithology indicator. A modified interpretation of sandbody geometry is made that incorporates sand injection features and provides a more accurate reservoir model.
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Fluid saturation from well logs using committee neural networks
Authors Hans B. Helle and Alpana BhattNeural computing has made a major step forward by the introduction of multi-net systems in practical applications. In this study we developed and tested a modular artificial neural network system for predicting underground fluids, water, oil and gas, and their partial saturations, directly from well logs, without explicit knowledge of the fluid and rock properties as required by conventional methods. Based on laboratory data on relative permeability for alternative fluid systems –oil–water or gas–oil – respectively, relative permeability logs may also be provided for input to reservoir simulation while drilling.
Simple three-layer back-propagation artificial neural networks (ANN) constitute the building blocks of a modular system, where the input logs are sonic, density, neutron porosity and resistivity. By numerical experiments using synthetic logs we have determined the optimal architecture of the ANN. We find that the overtraining strategy is a suitable technique for bias reduction and an unconstrained optimal linear combination is the best method of combining outputs in the committee neural net. The accuracy of the net is restricted only by accuracy of data. Comparison between ANN predictions of fluid saturation with those of conventional petrophysical analysis, in wells unknown to the network, indicates a standard error of less than 0.03.
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The representation of two phase fault-rock properties in flow simulation models
Authors T. Manzocchi, A.E. Heath, J.J. Walsh and C. ChildsFaults are represented conventionally in production flow simulation models using transmissibility multipliers which capture the single phase, but not the two phase, fault-rock properties. Available data indicate that fault-rocks have similar two phase properties to sediments of the same permeability, hence existing methods can be applied to estimate two phase fault-rock properties from their intrinsic permeabilities. Two methods of representing the two phase fault-rock properties implicitly in the flow simulator are compared, using one-dimensional numerical flow models containing water-wet faults with imbibition capillary pressure curves. The method which is the closer two phase analogue of the single phase transmissibility multiplier is inappropriate, as the implementation is unreasonably unwieldy. A simpler implementation is to derive pseudo-relative permeability functions including the fault-rock properties in the upstream grid block; these properties are then incorporated directly in the simulator. Relative transmissibility multiplier functions can be back-calculated from the pseudo-relative permeability functions, and indicate how closely the single phase multiplier approximates two phase flow through the fault. Implementation in a 3D model with complex fault juxtapositions validates the approach, and a practical workflow for the routine inclusion of two phase fault-rock properties in conventional faulted flow simulation models is outlined.
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Scale-up of well performance for reservoir flow simulation
Authors A.H. Muggeridge, M. Cuypers, C. Bacquet and J.W. BarkerThe method of Ding for scaling-up in the near-well region is evaluated on a variety of two- and three-dimensional problems, including cases with partially penetrating wells and some with non-vertical wells. The method is found to work well for all cases tested although accuracy is in general lower for 3D cases and possibly for wells producing at constant bottom hole pressure. The computational effort involved in the scaling-up can be minimized by use of a reduced computational domain with only a slight degradation of the results. Both well index and modified horizontal transmissibility are required for satisfactory results, but use of modified vertical transmissibility appears to be unnecessary.
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Core and seismic observations of overpressure-related deformation within Eocene sediments of the Outer Moray Firth, UKCS
Authors R. D. Hillier and J. W. CosgroveCores from the Eocene Alba Field of the Outer Moray Firth, UKCS contain sandstone injections and bedding-parallel fibrous ‘beef’ veins. Both of these features are associated with high fluid pressure and the process of hydraulic fracturing. The orientation of the hydraulic fractures (along which sand injection occurred, or calcite precipitated) was controlled by the interplay of the stress field and the intrinsic anisotropy of the sediments. Seismic sections indicate that sand injection occurred on a larger scale than is apparent from the cores. Interpreted dykes (400 m long by 30 m wide) emanate from the margins of the Alba channel sandstone along fault planes. An analogy is drawn between these dykes, and the peripheral dykes formed at the margins of laccoliths as a result of the flexing and subsequent fracturing of the overlying strata. ‘Decompacting’ of ptygmatically folded dykes suggests that the process of hydraulic fracturing and sandstone intrusion initiated between burial depths of 40 to 400 m below seabed.
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Prediction of offshore viscous oil field performance using reservoir simulation
Authors E. F. Balbinski, D. J. Element, S. G. Goodyear and A. J. JayasekeraDevelopment plans for UKCS viscous oil reservoirs use production profiles predicted by full-field simulation models. The use of horizontal wells, possibly combined with other IOR techniques, and the unusually high vertical permeability of many of the fields, lead to a range of issues that need to be carefully considered when building simulation models.
The strengths and weaknesses of different gridding systems, and the level of areal and vertical grid refinement that is needed, are discussed and illustrated with a range of examples including: interpretation of Extended Well Test results and integration with full-field modelling; sensitivity to relative permeability assumptions; prediction of gas movement from primary gas caps; and the comparison of different IOR techniques.
Where horizontal wells are drilled to reduce gas coning, undulations in the well trajectory can cause local coning of free gas, giving significantly earlier breakthrough times compared to strictly horizontal wells. A good correlation is found between effective stand-off and breakthrough time. Where localized gas production occurs, scoping calculations suggest that inflow of oil from further down the wellbore may be significantly reduced by multi-phase friction effects and gravity potential terms not modelled in conventional simulators.
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Influence of fine-scale heterogeneity patterns on the large-scale behaviour of miscible transport in porous media
Authors A. M. M. Elfeki, F. M. Dekking, J. Bruining and C. KraaikampAn extensive series of numerical simulations on two-dimensional flow and miscible transport are carried out. The purpose of performing these simulations is to study the influence of fine-scale heterogeneity patterns (i.e. horizontal laminations, cross-bedding at 45°and 135°) with short range and long range correlation structure on large-scale behaviour of miscible transport in porous media. Synthetic heterogeneous structures have been generated using newly developed stochastic techniques (e.g. the coupled Markov chain method) to model the subsurface formations in various configurations, using realistic characteristics, and the tree-indexed Markov chain method to merge these heterogeneities at various scales. The results of the simulation are compared with simulations on a reference model of heterogeneity where there is no fine-scale heterogeneity. The simulations show that the variation in the fine-scale heterogeneity inside the large-scale lithological units has considerable impact on concentration distribution and the spreading of miscible plumes. The combination of the two stochastic techniques (the coupled Markov chain model and the tree-indexed Markov chain) is a useful tool to study multi-scale transport behaviour in heterogeneous media. The fine-scale heterogeneity enhances the mixing process, but the definition of an asymptotic giga-scopic dispersion at field scale is still questionable.
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Using Shale Gouge Ratio (SGR) to model faults as transmissibility barriers in reservoirs: an example from the Strathspey Field, North Sea
Authors D. Harris, G. Yielding, P. Levine, G. Maxwell, P. T. Rose and P. NellSince the onset of production in 1993, extraction and injection in Strathspey has focused on the central region of the field, around the ‘Central Fault’. Analysis of RFT measurements from intermittent, but regular drilling on either side of this fault has allowed reconstruction of footwall/hanging wall pore-pressure fields for particular time instances. Comparison of these similar age pressure fields shows the Central Fault capable of maintaining up to 1300 psi pressure differentials. The results of the pressure analysis were used to calibrate a fault seal attribute, termed Shale Gouge Ratio (SGR) which is an estimate of clay concentration within fault gouge, mapped across the surface of the Central Fault. The calibration showed that as SGR increases, so does the measured pressure differential across the fault. This positive relationship between SGR and pressure differential suggests SGR is a guide to potential fluid-flow resistance exerted by faults. We therefore suggest that SGR can potentially be used as a guide to defining differences in permeability within and between faults in a given field. This ‘scaleability’ of SGR as an indicator of fault permeability within a field could provide hitherto unachievable flexibility in the systematic modelling of the hydraulic behaviour of faults during fluid flow simulations.
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Sedimentation during halokinesis: Permo-Triassic reservoirs of the Saigak Field, Precaspian Basin, Kazakhstan
Permo-Triassic reservoirs of the Saigak Field, in the eastern part of the Precaspian Basin of Kazakhstan, produced oil at cumulative rates exceeding 3600 BOPD. This confirms the attractiveness of the post-salt play in this part of the basin. Core studies show that cross-bedded sandstones in braided fluvial channels, alluvial and delta plain deposits are the best reservoirs. Integration of topographic and geomorphological features with satellite and seismic data led to the identification of inter-dome depressions with present-day active subsidence and sedimentation. These depressions are analogues to Permo-Triassic mini-basins. In the wells, reservoirs deteriorate quickly as soon as depositional environments become evaporitic. Seismic inversion was applied on a small 3D data-set covering the Saigak Field. The reduction of porosity with depth correlates well with increasing acoustic impedance values. In the inverted volume, reservoirs were characterized in terms of porosity and connected bodies, an essential input into static and dynamic reservoir modelling.
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The use of leak-off tests as means of predicting minimum in-situ stress
Authors Adrian J. White, Martin O. Traugott and Richard E. SwarbrickLeak-off tests (LOTs) or, preferably, extended leak-off tests (XLOTs), can be successfully used in minimum in-situ stress, S 3, estimations. Selecting a point on the leak-off graph that represents the best proxy for S 3 can reduce inaccuracies in the use of LOTs as a means of determining S 3. If the testing procedure is well conducted and recorded, picking the leak-off pressure (LOP) or instantaneous shut-in pressure (ISIP) gives equally valid estimates of S 3. During testing, most of the pressure applied in the deduction of S 3 is exerted by the static mud column, particularly in overpressured settings where higher drilling mud weights are used. Since the mud column contributes such a large proportion of the applied pressure, estimating S 3 from tests conducted at greater depth means the observed small difference between LOP and ISIP has even less of an effect on the deduced S 3 value. The data used in this study show that LOP closely matches ISIP when considering multiple cycle XLOTs. It can therefore be inferred that the LOP is the fracture re-opening pressure and hence S h given that the assumptions made by the Kirsch equation for wellbore failure are upheld. This study also considers the implications for calculating the magnitude of S H.
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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)