Study of the pore structure and calculation of macroscopic characteristics of rocks based on X-ray microcomputed tomography images

Abstract

Background: Absolute and relative phase permeability and capillary pressure are important parameters in predicting oil and gas production from reservoirs, especially when acidizing the bottomhole zone of a well. They are mainly determined during long and resource-intensive laboratory experiments. Thus, additional approaches are required for the operational determination of the above parameters. The pore-network modeling based on microcomputed tomography data allows, firstly, to study the pore space of rock samples taking into account rock dissolution, secondly, to calculate the main macroscopic properties of rock samples without destroying them, and thirdly, to create a database of digital cores for further research Aim: Study of the pore space of two carbonate rock samples and the flow of fluids in them using the General Electric V|tome|X S240 MT and using the Avizo and PNFLOW software package. Materials and methods: This article uses microcomputed tomography with a spatial resolution of ~19 m and pore-network modeling of fluid flow in porous media to study the pore space of carbonate rock samples and determine absolute and phase permeabilities, as well as capillary pressure. Results: It is shown that an increase in the value of the Marker Extent parameter leads to a decrease in the number of pores and an overestimated absolute permeability due to improper pore separation, while a decrease in the value of this parameter made it possible to identify smaller pores. It is also shown that absolute permeability and porosity have different relationships before and after rock dissolution with high correlation coefficients that range from 0.62 to 0.81. It has been shown that rock dissolution will significantly affect the relative phase permeability of the samples. Conclusion: The dissolution of the rock led to a decrease in the residual oil saturation in both samples. In the case of oil displacement by water, as a result of rock dissolution, the residual oil saturation decreased from 38% to 22% and from 53% to 43% for the two samples under study. These results are important for understanding the flow of fluids in carbonate samples.