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- Volume 8, Issue 1, 2002
Petroleum Geoscience - Volume 8, Issue 1, 2002
Volume 8, Issue 1, 2002
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Integrated scenario and probabilistic analysis for asset decision support
Authors Frans J. T. Floris and Martin R. H. E. PeersmannIn recent years, much effort has been spent in integration of the hydrocarbon E&P business processes. The new challenge lies in the use of the generated data for decision-making. In particular, in hydrocarbon assets, where large uncertainties occur, it is important to include the formal quantification of these uncertainties in the integrated workflow and allow for a decision framework based on a full characterization of these uncertainties.
For quantification of uncertainties two classes of approach are currently in use –the probabilistic approach based on the description of a stochastic model for capturing all uncertainty and the scenario approach based on a definition of a number of conceptually different models expressing the uncertainty. Some hybrid versions of the approaches exist as well. The pros and cons of these approaches are discussed. Following this, an extended statistical framework is presented in which the previous approaches to subsurface uncertainty modelling have been combined. The framework is not limited to subsurface uncertainties, but can also be applied to the other uncertainties and decisions in the asset model. In the integrated framework several scenarios may be identified for the static earth model, the dynamic earth model, the drilling model, the surface facilities model and the economic model. A scenario tree can represent the combination of all these scenarios.
Within each scenario a stochastic model can be applied to capture the within-scenario uncertainty. Calculation rules for the integration of the stochastic and scenario uncertainties are presented. Finally, decision rules are given that allow for decision-making based on the full uncertainty span in the integrated asset framework.
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The structure of western Sicily, central Mediterranean
Authors R. Catalano, S. Merlini and A. SulliWestern Sicily is part of the Sicilian chain, a sector of the SE-verging Alpine orogenic belt in the central Mediterranean. Interpretation of seismic reflection profiles, boreholes and recent inland geological data, have enabled us to assess the deep structural grain. A wedge of flat-lying Mesozoic–Miocene carbonate and terrigenous rocks (pre-Panormide nappes) is superimposed on NW-trending, 7–8 km thick, Mesozoic–Paleogene carbonate thrust ramps (Trapanese units), arranged in two structural levels extending from the Tyrrhenian coast to western offshore Sicily. Upper Miocene to Pleistocene terrigenous strata, often deformed, fill syntectonic basins above the thrust pile. The main tectonic transport of the thrust pile, developing from Early Miocene to Early–Middle Pleistocene times, was towards the east and southeast.
Initial stacking and deformation of the pre-Panormide allochthon is bracketed between Early and Late Miocene. The Late Miocene–Early Pleistocene underthrusting of the Trapanese–Saccense units, that acted through more recent deep-seated thrusts in the carbonate platform layer, induced late stage refolding and further shortening in the early emplaced pre-Panormide nappe. Previously formed structures appear to have been dissected or reactivated by a right oblique transpression during the Late Pliocene–Pleistocene. The geometry of the carbonate bodies opens new potential perspectives on the existence of structural traps, but the uncertainties of source rock occurrence remain.
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Synthetic well test modelling in a high net-to-gross outcrop system for turbidite reservoir description
Authors Ewan Robertson, Patrick W. M. Corbett, Andrew Hurst, Nick Satur and Bryan T. CroninSynthetic well tests have been produced using a 3D model of an outcropping turbidite sandstone unit from the Cingöz region in southern Turkey. The model contains realistic sand sheet, tongue, lobe and background sand facies architecture (i.e. geometry and stacking) mapped from an outcrop study. The geometric information is useful as an analogue for high net-to-gross turbidite oil fields. The facies have been assigned petrophysical properties from a subsurface analogue. There is little shale in this system. Well test responses were then derived from the high net-to-gross turbidite model using various architectural, porosity–permeability scenarios and completion strategies. The impact on well test derivatives of various sand body geometries and permeability contrasts could then be determined. Two completion strategies – partial penetration and fully perforated intervals – were assessed for their applicability in the high net-to-gross system.
The geological model is effectively a sandbox, and shows a very uniform testing response from the rather uniform property distributions. However, when the level of permeability heterogeneity is increased by populating the model with varying contrasts of permeability and porosity, the sand body geometry can be seen to influence the well tests. Partial completions in sand bodies are particularly effective in detecting sand body geometry. The geometry controls the flow regimes in a well test response despite variations in the permeability contrasts. The effect of varying geometry is illustrated and an external linear flow regime is identified. Where there is sufficient sand body thickness, partial perforation results in spherical flow, from which a vertical permeability can be obtained. In the model, the vertical permeability thus obtained is a local (to the volume investigated) effective permeability of stacked isotropic facies.
This work was undertaken to give guidance on the description of hydrocarbon reservoirs by well testing. If well testing is to be used in high net-to-gross turbidite systems for the purposes of reservoir characterization, then partial perforation of the system should be planned. Interpreted vertical permeabilities should be applied with careful consideration of the stacked pattern of sand bodies.
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Multi-target wells: a new concept to improve well economics
More LessThe Vienna Basin is a sedimentary basin more than 10 km in thickness and composed of more than a dozen hydrocarbon layers. Since the area has been intensively explored in the past 50 years, future exploration can expect to find only small reservoirs or compartments of already existing reservoirs. However, the existing infrastructure, such as pipelines, facilities and a nearby refinery, would make even small finds attractive. In this light it is of vital importance to reduce risk and costs in hydrocarbon exploration and production.
Multi-target wells were found to be an adequate answer to these problems: the chance of discovery increases more or less directly with the number of targets included in the well trajectory; and several small reservoirs can, in total, provide positive well economics. Moreover, by including exploration, appraisal and production targets into one well path a substantial contribution to improve economic hydrocarbon recovery from existing fields can be made. To further reduce drilling costs a new casing philosophy was established. By skipping the intermediate casing across the build-up section substantial savings could be made.
To plan and execute these challenging projects efficiently a multidisciplinary team has to be set up at an early stage of the drilling project. In this way the number of targets, the actual well path and well construction with respect to production requirements can be optimized. An example of a recently drilled multi-target horizontal well, including one primary and five secondary targets, is given. By applying this new concept drilling costs could be reduced by more than 30%.
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3D oil migration modelling of the Jurassic petroleum system of the Statfjord area, Norwegian North Sea
Authors J. Johannesen, S. J. Hay, J. K. Milne, C. Jebsen, S. C. Gunnesdal and A. Vayssaire3D oil migration modelling of the Statfjord area of the Northern North Sea has led to increased understanding of the migration routes and definition of oil migration fairways. The majority of discovered fields in the Statfjord area lie on fault block ridges. Migration modelling demonstrates that they were filled by oil generated from the Viking Graben, East Shetland and Marulk basins, migrating stratigraphically downwards from the Upper Jurassic Draupne Formation source rock into the Middle Jurassic Brent Group sandstones. Thereafter, lateral migration in a fill–spill manner occurred along the axes of the ridges. Locally, petroleum also migrated laterally through both Upper and Lower Jurassic sandstones. The migration modelling has been combined with geochemical source rock and oil correlation resulting in increased confidence. For the first time we have been able to quantitatively model and visualize the complex petroleum system of the area and gain an insight into its development through geological time.
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Lithofacies characterization of fluvial sandstones from outcrop gamma-ray logs (Loranca Basin, Spain): the influence of provenance
Authors A. W. Martinius, C. R. Geel and J. ArribasNatural gamma spectral (NGS) log motifs and cluster analysis were used to characterize outcropping sandstone bodies formed in braided and high-sinuosity streams of the Tertiary Tórtola fluvial system of the Loranca Basin (Spain). Five coarse-grained lithofacies comprise these deposits and determine distinct NGS log motif. Cross-plots and cluster analysis of NGS log data of the lithofacies suggest three distinct clusters. These clusters reflect distinct values for sandstones with small sets of ripple lamination, cross-stratification, and conglomerates and pebbles. Ripple-laminated sandstones show the most variability in NGS signature, whereas conglomeratic sandstones show the most uniform signature. Such cluster analysis may be used to assign NGS log data points of unknown origin to a specific fluvial lithofacies under conditions of equal rock provenance and diagenetic history. A sedimentaclastic (i.e. sedimentary parent rock) origin of sediments appears to be the main control on detrital composition that, in turn, varies with grain size.
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Reservoir parameters estimation from well log and core data: a case study from the North Sea
By Jun YanIn this paper we present an integrated approach to derive reservoir parameters from core and well-log data in clay–sand mixtures. This method is based on matching core and log data, and the linear and non-linear regressions are then used to build respective relationships between core and log data to determine formation parameters such as porosity, shale volume, clay content, permeability and fluid saturation. This information is then fed into a velocity prediction model to estimate seismic parameters such as elastic moduli, shear wave velocity and anisotropy coefficients. Finally, we test the method on real data from the North Sea and show that reservoir parameters can be accurately predicted.
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Reservoir characterization of the Roar Gas Field, Danish North Sea
More LessThe Roar Field consists of a gentle inversion anticline in which porosity, permeability and hydrocarbon saturation distributions in the Danian–Upper Cretaceous Chalk reservoir have been mapped using seismic data. The seismic data are inverted to support porosity prediction in a stochastic modelling approach. The uniform chalk matrix causes seismic impedance to correlate mainly with porosity and fluid content. Replacement of oil by water has negligible effect on seismic impedance but correction for fluid content in the gas cap is needed to increase correlation between seismic impedance and porosity. Porosity in excess of 40% is characteristic, probably reflecting early invasion of hydrocarbons. A slight tilting since Miocene times is suggested by higher porosity on the southwest flank. Permeability is generally below 10 mD in the reservoir and around 1 mD below. A slight south-dipping free water level is consistent with a regional water zone pressure gradient, if local high permeability is considered. A gas cloud that produces a velocity anomaly not apparent in well velocity data hampers depth conversion. The velocity anomaly is revealed from horizontal wells and has led to the identification of a new culmination at the north end 15 m shallower than the culmination at the south end; this has increased the estimated initial hydrocarbons in place from around 510 to 720×109 SCF gas. Analysis of uncertainty on hydrocarbon in-place calculations resulting from the characterization is limited to studying the effects of the gas cloud anomaly and the value added by the two horizontal wells on porosity field determination.
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Cyclic water injection: improved oil recovery at zero cost
Cyclic injection is a process that improves waterflooding efficiency in heterogeneous reservoirs. The concept of cyclic injection is based on (1) pulsed injection and (2) alternating waterflood patterns. Cyclic injection has been successfully applied in a number of sandstone and carbonate oil fields in Russia. In the rest of the world, pulsed injection has had limited application, and only in naturally fractured reservoirs. Although changing the waterflood patterns is a common approach to deal with increasing water cuts, a more systematic approach with both pulsed injection and alternating flow directions is not.
Cyclic injection has the greatest potential for improved recovery in heterogeneous, high-permeability-contrast sandstones and in naturally fractured carbonates and dolomites. The efficiency of the process is high in preferentially water-wet rocks saturated with compressible fluids. Capillary pressures and relative permeability effects are responsible for the improved cyclic oil displacement at the micro level. Improved sweep of the less permeable layers in communication with more permeable thief zones, better horizontal sweep achieved by changing waterflood patterns, and alternating the dominance between gravity and viscous forces are the key effects of cyclic injection on the macro level.
The potential of cyclic injection at the Lower Tilje/Åre formations of the Heidrun Field in the Norwegian Sea has been evaluated. Some of the reservoir levels are highly heterogeneous, with large permeability contrasts vertically and horizontally. The current drainage strategy for these formations is water injection, with gas lift in producers when needed. Cyclic injection will improve waterflooding efficiency at virtually zero additional cost. Improved sweep, accelerated oil production, and reduced water cut are the main positive effects expected from cyclic waterflooding. The reserves are predicted to increase by 5 to 6% from the targeted reservoirs at Heidrun after 10 years of cyclic waterflooding.
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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)