The article is devoted to accounting the scale effect, reservoir heterogeneity and, as a result, improving the quality of integral adaptation in the hydrodynamic modeling of the oil displacement process. The theoretical foundations of the problem of determining the permeability of a productive formation are presented. The weaknesses of the traditional approach to calculating the permeability from porosity, based on laboratory core tests, are shown. The authors note the issue of heterogeneity averaging in the study of the physical properties of the reservoir is more fundamental than the problem of effective average parameters, because as the size of the sample volume increases, the difference between the measured properties in the sample and the infinite volume decreases monotonically to the required accuracy. Based on the hydrodynamic model of one of the oil fields in the Volga-Ural region, it was confirmed that the use of the basic petrophysical dependence of permeability on porosity can lead to unreliable ideas about well flow rates. Due to the analysis and ranking of the input data, using the Python programming language, an algorithm has been implemented to improve the accuracy of estimating the reservoir productivity by taking into account information on the spatial distribution of porosity, which is a reflection of reservoir heterogeneity. The algorithm is based on a series of multivariate calculations of the sector hydrodynamic model of an oil reservoir. This approach allowed obtaining a new permeability-porosity point cloud and correcting the petrophysical curve. In addition, a series of calculations was carried out to assess the sensitivity of the results to the size of the hydrodynamic grid cell using the local cell refinement option. Based on the results of the work performed, it was noted that the presented algorithm makes it possible to more accurately reproduce the integral adaptation of the hydrodynamic model in comparison with the traditional approach, as well as to correct the permeability-porosity trend to improve the reproduction of well productivity, and thereby more correctly accounting the influence of reservoir heterogeneity and the scale effect.
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