RELATIVE PERMEABILITY IMPLEMENTATION INSIDE TERRIGENEOUS OIL FIELD RESERVOIR

• Main Author: Mikhail O. Korovin
• Format: Article
• Language: Russian
• Published: Tomsk Polytechnic University 2021-04-01
• Series: Известия Томского политехнического университета: Инжиниринг георесурсов
• Subjects: permeability anisotropy; anisotropy scale; simulation modeling; relative permeabilities; properties distribution
• Online Access: http://izvestiya.tpu.ru/archive/article/view/3161/2457

The relevance of the research lies in an important fact related to the depletion of hydrocarbon reserves. The main task for researchers now is to extract as much hydrocarbons as possible from the reservoirs. There are two ways to solve this problem: create a new technology (mathematical model) or a new (alternative) approach to processing existing data. It is necessary to analyze the application of current data, which radically affect the hydrodynamic characteristics and to study in detail the possibilities of their alternative accounting in existing mathematical models implemented in modern software products. An additional support factor is that all studies and results are controlled by the geological conditions of reservoir formation and their saturation. Relative phase permeability curves are one of the main datasets that critically affect hydrocarbon filtration. The coefficient of residual oil, water, the point of transition of filtration from the zone of predominance of oil to the zone of penetration of water are the most important parameters on which the displacement coefficient ultimately depends. The aim of this work is to study the possibility of using curves of relative phase permeabilities without additional modifications and recalculations. It is expected to obtain additional simulations of hydrodynamic models and compare these results with actual production results. The study object is a field geographically located in Western Siberia. Reservoir type is terrigenous. Stratigraphically, the stratum is confined to the Upper Jurassic deposits. The inhomogeneous distribution of filtration properties allows us to consider the effect of relative phase permeabilities on the calculation of production characteristics. Methods: creation of a hydrodynamic model of the field using unchanged curves of relative phase permeabilities. The main idea is to study the possibility and feasibility of using unmodified curves for calculating production parameters. The final step is a comparison of production characteristics from hydrodynamic models and actual development data. Results. The filtration model of the studied field was refined. It was possible to get the most accurate idea of the filtration of hydrocarbons. It becomes possible to take into account the structure of the pore space more detailed than previously. This is very important, since it is the structure of the threshold space and the distribution of the properties of rocks that are the predetermining factors according to which the filtration of hydrocarbons will take place. The resulting laboratory measurements provide information about the state that is closest to the original pore space. It was found that the relative permeabilities of the phase critically affect the calculation of cumulative oil production. A large number of studies make it possible to characterize each facies and all filtration features of the vertical section. The use of the initial curves of relative phase permeabilities makes it possible to assess the need to apply modification of the curves and to bring the mathematical description of the reservoir properties closer to the real geological picture.