The ability of pure CO₂ injection into an oil reservoir to bring about CO₂ storage is hindered by the fact that CO₂ is more mobile than oil. Most “mobility control” methods (such as foam injection) work only at low temperatures. This study investigates whether water-saturated CO₂ injection can provide mobility control at high pressures and temperatures. In this study, CO₂ and water-saturated CO₂ are injected into a Bentheimer sandstone core. Experimental runs are performed at 70 ℃ to simulate a low-temperature reservoir and 116 ℃ to simulate a high-temperature reservoir. The selected pressure ranges from 10.3 to 18.6 MPa. Results show that water-saturated CO₂ consistently exhibits lower mobility than pure CO₂. Hence, water-saturated CO₂ injection provides effective mobility control for both low- and high-temperature reservoirs, especially at higher pressure. The effectiveness of water-saturated CO₂ in reducing mobility compared to pure CO₂ increases exponentially with pressure. Despite the improved mobility control provided by water-saturated CO₂ injection, experimental observation finds net CO₂ stored and oil recovery to be similar to that of pure CO₂ injection, as CO₂ sweep efficiency is already high in experimental runs. However, at field-scale sweep efficiency is low. Therefore, field-scale simulations reveal a 19%-47% increase in net CO₂ stored during water-saturated CO₂ injection compared to pure CO₂ injection.

The occurrence of multi-phase flows in porous media is a complex phenomenon that involves multiple scales, ranging from individual pores to larger continuum scales. Upscaling frameworks have emerged as a response to the need for addressing the disparity between micro-scale processes and macroscopic modelling. Determination of the representative elementary volume is important for understanding fluid dynamics in micro-porous materials. The size of the representative elementary volume for multiphase flow in porous media is significantly affected by wettability and fluid saturations. Previous studies have overlooked this aspect by conducting simulations under conditions of constant medium wettability and fluid saturations. This study uses finite volume simulations with a volume of fluid approach for two distinct asymptotic homogenization methods, namely hydrodynamic bounds of relative permeability and thermodynamic bounds of entropy production. Strong wetting conditions with high wetting phase saturation were found to require a smaller sample size to establish representative elementary volume, while mixed-wettability scenarios necessitate the largest sample sizes. These findings improve our understanding of multiphase fluid flow behaviour in micro-porous materials and aid in enhancing techniques for scaling up observations and predictive modelling in engineering and environmental fields.

This paper presents a novel technique for upscaling multiphase fluid flow in complex porous materials that combines asymptotic homogenization approach with hydrodynamic- and thermodynamic bounds. Computational asymptotic homogenization has been widely utilised in solid mechanics as a method for analysing multiscale expansion and convergence coefficients in heterogeneous systems. Computations are performed over several volumes by increasing the size until convergence of the material parameters under different load scenarios is achieved. It works by simplifying the problem with a homogenization method and is ideally suited for estimating the representative elementary volume of microporous material by expanding algorithms. The validity of the method to include complex multi-phase hydrodynamic processes and their interaction with the matrix structure of porous media lacks a sound theoretical foundation. To overcome this problem, a variational thermodynamic approach is used. Upper and lower bounds of entropy production are proposed to provide effective material properties with uncertainties. This allows multiple possibilities to address dynamics via thermodynamically linked processes. This work utilizes volume of fluid approach to model multiphase porous media flow in models based on micro-computerized tomography x-ray data of Bentheimer sandstone and Savonnieres carbonate. It is found that the representative elementary volume sizes obtained by the conventional asymptotic homogenization methods do not satisfy thermodynamic bounds which consistently require larger representative elementary volume sizes. For the Savonnieres carbonate the entropic bounds have not converged fully questioning the reliability of the effective properties obtained from the classical method.

We perform single-phase and two-phase flooding on Edwards Brown rock samples. The single-phase injection was of seawater or CaCl₂ brine,at successive salinities 0.63,0.21,0.07,0.05,and 0 mol/L (distilled water). For CaCl₂ brine experimental run,no significant fines migration or permeability decrease is observed. For seawater experimental run,distilled water injection is found to bring about the highest concentration of produced fines and most of the permeability decrease,with the ultimate permeability decrease being 99.94%. Therefore,distilled water injection is used to stimulate fines migration in the following two-phase experimental runs. Two-phase experiments are performed on four Edwards Brown rock samples using seawater or CaCl₂ brine as the aqueous phase,and Soltrol? 130 or crude oil as the oleic phase. Rock samples are initially fully saturated with 0.63 mol/L of the selected aqueous solution. This is followed by injecting the selected oil at a constant rate for at least 20 pore volumes to displace brine. Next,selected brine is injected to displace oil,and finally distilled water. For CaCl₂ brine,distilled water injection is found to recover no additional oil of either type of oil. However,for seawater,the fines production observed during distilled water injection is found to reduce water relative permeability by two orders of magnitude when Soltrol? 130 is used and by three orders of magnitude when crude oil is used. The seawater experimental runs also brought about additional oil recovery during distilled water injection: 18% when Soltrol? 130 is used and 3.4% when crude oil is used. This last result can be attributed to the plugging of pores due to fines migration,which can divert further injected water into previously unswept pores.

This paper investigates the extent to which alcohol-treated carbon dioxide (CO₂), a mixture of alcohol and CO₂ equilibrated at experimental pressure and temperature, can lead to greater interfacial tension reduction and greater oil swelling than can pure CO₂. Experimental measurements of interfacial tension and swelling behavior are made using a high-pressure, high-temperature visual cell at 70 °C. Two sets of fluid pairs are used: pure CO₂ and oil, and alcohol-treated CO₂ and oil. Two types of oil are used: a mixture of 35% hexane and 65% decane (C ${}_6$-C ${}_{10}$ mixture), and pure decane (pure C ${}_{10}$). Ethanol and methanol are used to prepare alcohol-treated CO₂. Numerical simulations are used to estimate a reduction in the minimum miscibility pressure when using alcohol-treated CO₂. Interfacial tension between alcohol-treated CO₂ and oil is found to be 0.02 to 2.2 mN/m less than that between pure CO₂ and oil. Simulation results suggest that alcohol-treated CO₂ yields 0.2 to 1.2 MPa lower minimum miscibility pressure compared to pure CO₂. Alcohol-treated CO₂ also is found to cause 6% to 43% more swelling of oil than does pure CO₂. Interfacial tension and swelling results suggest that alcohol-treated CO₂ yields better miscibility with oil compared to pure CO₂.