Abstract
Relative permeability and capillary pressure are key properties within special core analysis and provide crucial information for full field simulation models. These properties are traditionally obtained by multi-phase flow experiments, however pore scale modelling has during the last decade shown to add significant information as well as being less time-consuming to obtain. Pore scale modelling has been performed by using the lattice-Boltzmann method directly on the digital rock models obtained by high resolution micro-CT images on end-trims available when plugs are prepared for traditional SCAL-experiments. These digital rock models map the pore-structure and are used for direct simulations of two-phase flow to relative permeability curves. Various types of wettability conditions are introduced by a wettability map that opens for local variations of wettability on the pore space at the pore level. Focus have been to distribute realistic wettabilities representative for the Norwegian Continental Shelf which is experiencing weakly-wetting conditions and no strong preference neither to water nor oil. Spanning a realistic wettability-map and enabling flow in three directions, a large amount of relative permeability curves is obtained. The resulting relative permeabilities hence estimate the uncertainty of the obtained flow properties on a spatial but specific pore structure with varying, but realistic wettabilities. The obtained relative permeability curves are compared with results obtained by traditional SCAL-analysis on similar core material from the Norwegian Continental Shelf. The results are also compared with the SCAL-model provided for full field simulations for the same field. The results from the pore scale simulations are within the uncertainty span of the SCAL models, mimic the traditional SCAL-experiments and shows that pore scale modelling can provide a time- and cost-effective tool to provide SCAL-models with uncertainties.
Highlights
Wettability is a key factor for multiphase flow behaviour in porous media in general, and for reservoir rocks especially
The benefit of the first approach is that the wetting preference is well defined, the major – and crucial - drawback is that the measurements must be done on a flat surface with a geometry far from the geometry and shape of the pore structure in porous media
We provide the results obtained by combining Micro-CT images, spatially pore scale simulations combined with wettability distribution within the porous structure. 3.1 Models and Set-up We have used the workflow and tools listed in Section 2 to build pore scale models and run two-phase direct flow simulations with LBSIM
Summary
Wettability is a key factor for multiphase flow behaviour in porous media in general, and for reservoir rocks especially. In the origin of the petroleum industry, clastic reservoir rocks where assumed to behave waterwet due to the water-wetting minerals composing the rock and pore surface. It is well acknowledged that the wettability of clastic reservoir rocks experiences weakly wetting behaviour and generally no strong preference to neither oil nor water. The benefit of the first approach is that the wetting preference is well defined, the major – and crucial - drawback is that the measurements must be done on a flat surface with a geometry far from the geometry and shape of the pore structure in porous media. Macroscopic measurements are done on core samples exposed to real fluids at reservoir conditions, the measurements are not regarded as well-suited to define the specific wettability where limited preferences to neither of the phases are experienced – which is the case for most clastic reservoir rocks. Even though the macroscopic approach has its limitation, it is the most used method by the industry due to its pragmatic approach and it provides reliable quality information of the wettability preference
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