Water channels are formed in highly permeable thief zones or in situations with a strong adverse mobility ratio, such as waterflood in heavy oil reservoirs. This paper discusses the effect of tertiary polymer injection on oil mobilization in already established water channels generated by viscous unstable flow in apparent homogeneous rock material. Polymers may accelerate oil production by moving oil into water channels, known as crossflow. The conditions for crossflow to occur are discussed and quantified by key parameters for maximizing crossflow. Crossflow in layered rock with permeability contrast has been studied extensively. We have also studied permeability contrast in conventional thief zones for comparison. Recently published experimental studies, including in situ saturation maps, have proven acceleration of heavy oil production by injection of polymer in rather homogeneous sandstones. The simulation study involves computation of saturation-induced crossflow, in particular with respect to wettability, relative permeability hysteresis, capillary pressure, oil viscosity, mobility ratio, and polymer viscosity. To have a realistic representation of channeling, the water channels are constructed from waterflooding saturation data at adverse mobility. Saturation-induced crossflow into water channels at homogeneous permeability is found to be strongly affected by wettability, viscosity ratio (oil/water), and width of water channels.

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Summary In traditional flow simulation, compaction is modeled as a function of fluid pressure, whereas in reality, it is dependent on effective stress (e.g., mean effective and shear stress). Therefore, although compaction computed by a flow simulator may be correct on a regional average basis, the true variation throughout the reservoir (both spatial and temporal) cannot be accounted for by a traditional approach. A stress simulator (i.e., geomechanics model) honoring material properties, rock mechanical boundary conditions, and material-to-material interaction is needed to achieve this compaction. Especially for sands, chalk, and other weak materials, which in general, have a compaction-dependent permeability, the spatial variation of compaction may have a significant impact on the flow pattern. The industry standard approach for computing true compaction is by either doing a fully coupled simulation or by using partial coupling with pore-volume iterations, both typically being expensive in terms of computer processor time. For this reason, the simplified compaction calculations are often used in practice thus disregarding actual physics in the reservoir simulation. In this paper, we describe a procedure whereby a modified (pseudo) material definition is constructed and used to improve compaction calculations by the flow simulator. The construction is based on results from a simplified, coupled flow-stress simulation, typically consisting of three to six explicit stress steps. The resulting compaction field is comparable to the true one and represents a significant improvement over the traditional approach. This compaction state is the optimal input to the stress simulator in a coupled scheme and, therefore, assures the rock mechanics calculations can be performed with maximum efficiency. By using our suggested procedure, the pore-volume iterations in a coupled scheme are eliminated or significantly reduced, and the simulated reservoir state is accurate at all times--not only when stress simulations are performed. Our main goal is to reduce the total computer time in iterative-coupled simulations without loss of accuracy, especially focusing on two mechanistic models from the Valhall field, which is a highly compacting chalk reservoir in the North Sea. We also demonstrate benefits of using the procedure in a simplified form to increase accuracy in reservoir simulation for reservoirs in which coupled simulation is traditionally not seen as needed because of either a perceived lack of complexity or the computing costs. In this paper, we demonstrate that the developed construction methodology is general in use. Further, the maximum permitted difference between flow-simulator calculated compaction and true compaction (i.e., computed from strain using a geomechanics simulator) is user-controlled, such that by proper definition of this parameter, the coupled simulation in most cases can be guaranteed to converge at the first pore-volume iteration.

Based 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.

Many people had a hand in forming this dissertation one way or another, either by direct contribution, giving input into the research, or keeping me motivated to finish the work. First and foremost, I thank my supervisors, Jan Tveranger and William Helland-Hansen, for their encouragement, guidance, and advice throughout my time as a PhD student. I thank Jan for sharing his insight and ideas on reservoir modelling. Our collaborations during the writing stages of the papers have significantly improved my writing skill. Jan's constant challenges to most research works I brought to his desk have helped elevating the quality of this dissertation and, I believe, making me a better scientist.