ИСТИНА

Geological heterogeneities affect the flow of reservoir fluids. However, different levels of heterogeneity are important for different types of fluid (e.g., dry gas, wet gas, light oil, heavy oil) and production mechanisms. This fact underlies a simple rule of thumb – ‘Flora’s Rule’ – which determines the critical level of permeability contrast for a given fluid type and displacement process. For example, according to this rule, gas reservoirs are only sensitive to 3 orders of magnitude of permeability variation. This means that less detailed reservoir models with relatively coarse grid are useful to predict fluid flow in gas reservoirs under depletion. Since ‘Flora’s Rule’ has the status of a rule of thumb, it seems promising to bring a fundamental basis under these statements. Here we consider fluid flow in macroscopically heterogeneous porous media (the standard Darcy law controls the flow). We model spatially heterogeneous permeability of a porous medium using geostatistical algorithm. We demonstrate that our approach allows us to generate spatially heterogeneous petrophysical properties with a given variogram function and anisotropy. Then we simulate numerically the fluid flow in the generated heterogeneous porous media. We analyze spatial properties of the simulated flow: we calculate empirical variogram for fluid velocity components, estimate its anisotropy, etc. Since we control the spatial heterogeneity of porous medium properties, our approach enables us to link spatial heterogeneity of permeability to the resulting heterogeneity of flow, thus, we test ‘Flora’s Rule’ for a series of simulations. https://geodatascience.hw.ac.uk/geoscience-meets-data-science-abstracts/#Isaeva