Effective development of oil fields with low-permeability reservoirs is an urgent task for most oil companies due to the fact that a significant part of current and future reserves belong to this category. Relative phase permeability is the most important parameter of multiphase flow through a porous medium, characterizing the effective permeability for each phase. When determining relative permeability using standard methods, there are a number of methodological risks, which can significantly affect the results of experiments and their applicability. The objective of the study was the laboratory determination of the relative permeability in core samples of low-permeability rock of the Achimov Formation (permeability less than 1 mD) for the fluid-gas system using the method of stationary filtration with X-ray control of saturation, as well as by the method of non-stationary filtration in order to improve the quality of results using this type of data. For analytical modeling of phase permeabilities, a number of correlation models (Corey, Honarpour, LET) were used to accurately describe the obtained curves and select approximation coefficients for the target object. A core-scale hydrodynamic model, tuned to the results of single tests of displacement efficiency was used to predict the relative permeability curves. Generalization of the data obtained enabled creating the methodological approaches to reconstructing phase permeability in low-permeability rocks of the Achimov deposits. This approach will increase the accuracy of determining the dynamics of fluid flow and optimize field development scenarios and risk assessments.
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