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- Volume 13, Issue 4, 2007
Petroleum Geoscience - Volume 13, Issue 4, 2007
Volume 13, Issue 4, 2007
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A road map for improving the technical basis for the estimation of petroleum reserves
More LessReserves estimation can be based on one or more methodologies, each with its associated uncertainty. These include ‘static’ volumetrics, reservoir simulation, material-balance analysis, and/or projections of ultimate recovery according to production decline. The static volumetric method is in focus here, as the most commonly used approach during the development and early production stages when there has been limited petroleum recovery and the uncertainty associated with a reserves estimate can be considerable. There are several key technical aspects of the static volumetric process, including: the issue of minimum data requirements in relation to reservoir complexity; the upscaling of reservoir parameters and the interpretative algorithms through which they are interrelated; the identification of net reservoir and net pay; and the integration of data sources in a manner that is dynamically conditioned, i.e. tied back to permeation properties. This last point is especially important because reserves, by definition, are commercially recoverable. Suggested improvements reveal additional opportunities for cross-validation and groundtruthing. The approach is synthesized into a high-level, yet pragmatic workplan. It is proposed that the adoption of such a workplan will remove some of the uncertainty that is currently inherent in the technical process for estimating reserves.
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Sensitivity of fluid flow to fault core architecture and petrophysical properties of fault rocks in siliciclastic reservoirs: a synthetic fault model study
Authors Niclas Fredman, Jan Tveranger, Siv Semshaug, Alvar Braathen and Einar SverdrupFluid flow simulation models of faulted reservoirs normally include faults as grid offset in combination with 2D transmissibility multipliers. This approach tends to oversimplify the way effects caused by the actual 3D architecture of fault zones are handled. By representing faults as 3D rock volumes in reservoir models, presently overlooked structural features may be included and potentially yield a more realistic description of structural heterogeneities. This paper investigates how a volumetric fault zone description, will affect fluid flow in simulation models.
An experimental 3D model grid including a single normal fault, defined as a volumetric grid, was constructed. Subsequently, the fault grid was populated with two conceptual fault deformation products – sand lenses and fault rock – using an object-based stochastic facies modelling technique. In order to evaluate the effect of varying petrophysical properties, fault rock permeability and sand lens permeability were varied deterministically between 0.01 mD and 1 mD and 50 mD and 500 mD, respectively. The impact of fault core architecture was investigated by deterministically varying sand lens fraction and sand lens connectivity. This yielded 24 model configurations, executed in 20 stochastic realizations each. Fluid flow simulation was performed on 480 model realizations.
Simulation results show that the most important parameters influencing fluid flow across the fault were fault rock matrix permeability, and whether or not the sand lenses were connected to the undeformed host rock. Sand lens permeability and sand lens fraction turned out to be less important for fluid flow than fault rock matrix permeability and sand lens connectivity.
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Faulting and fault sealing in production simulation models: Brent Province, northern North Sea
Authors S. J. Jolley, H. Dijk, J. H. Lamens, Q. J. Fisher, T. Manzocchi, H. Eikmans and Y. HuangFaults can severely compartmentalize pressures and fluids in producing reservoirs, and it is therefore important to take these effects into account when modelling field production characteristics. The Brent Group fields, northern North Sea, contain a complex arrangement of fault juxtapositions of a well-layered sand-shale reservoir stratigraphy, and fault zones containing a variety of fluid flow-retarding fault rock products. It has been our experience that these fault juxtapositions impact the ‘plumbing’ of the faulted layering system in the reservoirs and the models that are built to mimic them – and are, in fact, a first-order sensitivity on compartmentalization of pressures and fluid flow during production simulation. It is important, therefore, to capture and validate the geological feasibility of fault- horizon geometries, from the seismic interpretation through to the static geocellular model, by model building in conjunction with the interpretation. It is then equally important to preserve this geometrical information during geocellular transfer to the simulation model, where it is critical input data used for calculation of fault zone properties and fault transmissibility multipliers, used to mimic the flow-retarding effects of faults. Application of these multipliers to geometrically weak models tends to produce ambiguous or otherwise potentially misleading simulation results. We have systematically modelled transmissibility multipliers from the upscaled cellular structure and property grids of geometrically robust models – with reference to data on clay content and permeability of fault rocks present within drill core from the particular reservoir under study, or from similar nearby reservoirs within the same stratigraphy. Where these transmissibility multipliers have been incorporated into the production simulation models, the resulting history matches are far better and quicker than had been achieved previously. The results are particularly enhanced where the fault rock data are drawn from rocks that have experienced a similar burial–strain history to the reservoir under study.
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Spatial pressure compartmentalization in faulted reservoirs as a consequence of fault connectivity: a fluid flow modelling perspective, Xaréu oil field, NE Brazil
Sealing faults may have a major impact on reservoir compartmentalization and play a key role in advanced oil recovery strategies. Because of the different approaches and scales used to characterize faults, a considerable gap remains between engineers’ and geologists’ conceptions of faulted reservoirs. The fundamental difficulty in integrating these views lies in constructing realistic reservoir-scale models incorporating relevant fault properties on several scales, so that fault connectivity and its impact on fluid flow can be simulated and quantified properly. This paper is a step towards examining quantitatively the impact of fault connectivity on fluid flow at a reservoir scale. A stochastic reservoir model incorporating sealing faults was constructed. The number of faults in the model were gradually increased and several fluid flow simulations performed in order to verify the impact of fault density and fault connectivity on the spatial pressure variation. Despite being synthetic, the model incorporates some properties of an actual carbonate reservoir, the Xaréu oil field (XOF) in the Ceará Basin, NE Brazil. In the XOF, thin (<15 m) oil-bearing carbonate layers are interlayered in a thick (>50 m) shale bed. Sealing effects may be caused by the faults because they usually have a normal slip component, so that the thick shale layer becomes juxtaposed against the thin carbonate layers, behaving as barriers to fluid flow in the carbonate layers. It appears that there is no reservoir compartmentalization in the carbonate layers because there is overall pressure depletion in XOF – all the new wells drilled in the carbonate layers, before starting production, showed formation pressure values smaller than the formation pressure measured in the first wells drilled in the field. Nevertheless, it was not understood how such communication throughout the entire reservoir (approx. 19 km2) could occur, given the presence of laterally extensive faults, with up to 5 km in strike and maximum vertical displacement greater than the reservoir thickness. In the synthetic model, fault population follows a displacement-length property derived from seismic data. Sub-seismic faults were also incorporated in the model using a downscaling law. The location, direction and length of each fault were also generated stochastically. In order to quantify the ‘degree of faulting’, two criteria were used: fault density (the fraction's ‘total fault length per occurrence area’; f 1) and fault connectivity (the fraction's ‘number of fault intercepts per occurrence area’; f 2). By comparing f 1 and f 2 for the real and simulated versions of the XOF carbonate reservoir it is concluded that the carbonate layers remain interconnected so that compartmentalization does not exist. From a methodological viewpoint, the most important aspect of the modelling is the change of focus regarding sealing. At least for the purposes of investigating interconnection, the adequate focus is on the ‘percolation core’ of the reservoir (its hydraulically connected and undamaged parts) and not on the faults themselves, regardless of their sealing nature.
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Cenozoic evolution of the Lariang and Karama regions, North Makassar Basin, western Sulawesi, Indonesia
Authors Stephen J. Calvert and Robert HallThe Lariang and Karama regions of western Sulawesi, an area of approximately 10 000 km2, were the subject of a field-based investigation with the aim of understanding the Cenozoic evolution of the North Makassar Basin. Western Sulawesi was influenced by the development of the Makassar Straits to the west and the collision of continental, ophiolitic and island-arc fragments to the east. The timing of these events has been the subject of considerable debate and it has been suggested that Neogene collisions in Sulawesi caused inversion in Borneo. A new stratigraphy for the Lariang and Karama regions of western Sulawesi, based on fieldwork, provides new and significant insights into the evolution of the Makassar Straits region. The oldest sediments are non-marine and could be as old as Paleocene; they include coals, sandstones and mudstones. Rifting had started by the Middle Eocene and continued into the Late Eocene. Syn-rift Eocene sediments were deposited in graben and half-graben in both marine and marginal marine environments. The Eocene Makassar Straits rift was highly asymmetrical; the Kalimantan margin was approximately twice the width of the Sulawesi margin. Thermal subsidence had started by the latest Eocene and by the end of the Oligocene most of western Sulawesi was an area of post-rift shelf carbonate and mudstone deposition. This shallow-marine depositional environment persisted throughout the Early Miocene and, in places, until the Middle or Late Miocene. In the Pliocene the character of sedimentation changed significantly. Uplift and erosion was followed by the deposition of coarse clastics derived from an orogenic belt to the east of the study area. The Palaeogene half-graben were inverted, there was localized detachment folding and the overlying Neogene section was folded, faulted and eroded in places. Contractional deformation in western Sulawesi dates from the Pliocene, whereas in eastern Kalimantan it dates from the Early Miocene.
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A drilling mud additive influencing the geochemical interpretations of hydrocarbon shows
Authors S. E. Ohm, D. A. Karlsen, K. Backer-Owe, J. H. Pedersen and H. S. BeeleyOil-based mud additives are used frequently during drilling for various purposes. The chemical compositions of these may interfere/overprint the chemical composition of hydrocarbon shows in the well and thereby complicate geochemical interpretations. This is likely to be an increasing problem as hydrocarbon findings become more subtle. It is important that the geochemist compiles a list of all additives used during drilling and obtains a sample of the pre-drill oil-based mud additives used. In the case of detailed geochemical analyses to be carried out post-drilling, it is then possible to check the influence/contamination of the additives on the hydrocarbons found.
The chemical composition of a frequently used oil-based mud additive is demonstrated to have overprinted the hopane signature of an oil-slick sample in well 35/1-1, northern North Sea. This could easily have resulted in erroneous interpretations regarding age and depositional environment of the source rock of the oil. However, the steranes used for interpretation of facies are shown to be unaffected by the mud additive. A study of shows from well 35/1-1 suggested the source of these to be an atypical developed Upper Jurassic source rock, despite the hopane signature suggesting a carbonaceous Permian source. The main argument was that a Permian source would imply higher maturities than observed. The present study reveals that the hopanes in the shows are contaminated completely by the mud additive used during drilling and, hence, a Permian source is ruled out successfully.
This paper demonstrates that if one biomarker group from the mud additive overprints that of the indigenous oil show this does not preclude other biomarker groups from truly representing the oil show.
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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)