3D Visualization of Film Flow During Three-Phase Displacement in Water-Wet Rocks via Microtomography Method

Spatial image resolution has limited previous attempts to characterize the thin film flow of oil sandwiched in-between gas and water in a three-phase fluid system This paper describes how a systematically designed displacement experiment can produce imagery to define the film flow process in a 3D pore space of water-wet sandstone rocks. We image multiphase flow at the pore scale through three displacement experiments conducted on water-wet outcrop rock with variable spreading tendencies. The experiment has been formulated to observe the relationship between fluid spreading, phase saturations, and pore-scale displacement mechanisms. We provide exhaustive evidence of the three-phase fluid configurations that serve as a proxy mechanism assisting the fluid displacement process in a three-phase system, which includes the oil sandwiches in-between water and gas, the flow of oil via clay fabrics, and the double-displacement process that generates oil and water film in 3D pore spaces. Further, we show evidence that the stable thin-oil film has enhanced the gas trapping mechanism in the water-wet rocks. We observed that the oil layer had covered the isolated and trapped gas blobs, enhancing their stability. As a result, the trapped gas in the positive and zero spreading systems is slightly higher than in the negative spreading system due to a stable oil film. We analyze the Euler characteristic of the individual fluid phases and the interface pair of the fluids during waterflooding, gas injection, and chase water flooding. The comparison of the Euler characteristic for the connected and disconnected fluid phases between three different spreading systems (i.e., positive, zero, and negative) shows that the oil layer's connectivity is highest in the positive spreading system and lowest in the negative spreading system. The oil layer in the positive spreading system is also thicker than in the negative spreading system.

Numerical modeling of multiphase mass transfer processes in fractured-porous reservoirs

The paper presents an algorithm for solving the problem of the process of mass transfer of a two-phase fluid in a fractured-porous reservoir in a one-dimensional formulation. The presence of natural fractures in such reservoirs impedes various types of exploration and field development. Fractured-porous reservoirs are characterized by intense exchange fluid flow between fractures and porous blocks. Each system has its own individual set of filtration-capacity parameters, and this fact complicates the problem under consideration. To study the mass transfer of a two-phase fluid in a medium with double porosity, a four-block mathematical model with splitting by physical processes is proposed. The model is described by a system of partial differential equations. The splitting method forms two functional blocks on the water saturation and the piezoconductivity. For the numerical solution of this system, an absolutely stable implicit finite-difference scheme is constructed in the one-dimensional case. On the basis of the proposed difference scheme, pressures and saturations in the fracture system and matrix are obtained.

On one method of numerical modeling of piezoconductive processes of a two-phase fluid system in a fractured-porous reservoir

A method of numerical modeling based on splitting by physical processes of two-phase fluid transfer in a formation with fractured-porous reservoirs is described. Reservoirs of this type have a natural fracture system and are described by the dual porosity model. A four-block mathematical model of the fluid redistribution between a pore-type matrix and a natural fracturing pattern is proposed and studied. The resulting system is complex and entails a number of difficulties associated with a large number of variables and the absence of important properties of a linearized system of equations, such as self-adjointness and symmetry, which are present in the description of piezoconductive processes. The complete splitting by physical processes is carried out to solve this problem. The resulting split model is differentially equivalent to the discrete initial balance equations of the system (conservation of the mass components of the fluids and the total energy of the system), written in divergent form. This approach is associated with a nonlinear approximation of the grid functions in time, which depends on the fraction of the volume occupied by the fluids in the pores, and is easy to implement.

The investigation of the efficiency of oil displacing from the pore in the rock formation depending on the width and height of the pore using nanosuspension as a displacing agent

The numerical investigation of the two-phase fluid flow in a microchannel was carried out. The effect of the pore width and height on the oil displacing efficiency by nanofluids for various Reynolds numbers was studied. The computational domain was a T-shaped microchannel with a horizontal main flow channel and a vertical channel that imitated the pore in the rock formation, called a pore channel. The main channel width and height were 200 µm, and the pore channel width and height were varied in the range from 100 µm to 800 µm. The Reynolds number was varied from 0.1 to 100. The main studied characteristic was the oil recovery coefficient, defined as the ratio of the volume of oil remaining in the pore to the volume of the pore. That characteristic, obtained for a case, when the nanofluid was used as a displacing agent, was compared to the similar one obtained for a case, when pure water was used as a displacing agent. A single-phase fluid with properties, determined experimentally, was considered the nanofluid. The mass concentrations of SiO2 nanoparticles were 0.25% and 0.5%. The average diameter of nanoparticles was equal to 5 nm. It was found, that the oil recovery coefficient increased with an increase in width of the pore channel and a decrease in its height. It was obtained that the nanofluid can enhance the oil recovery in several times as compared to pure water. It was also found that the main factor affecting the efficiency of oil recovery is the contact angle of wetting.