CO2 injection process is of high interest in applications such as CO2 storage in reservoir rocks, enhanced oil recovery or soil remediation. The optimization of such a process requires a detailed reservoir petrophysical description but also representative three-phase transport properties in porous media. Imbibition and drainage processes are dominated by interfacial phenomena. The displacement mechanisms are affected by wettability and interfacial tensions.

A series of experiments were conducted in glass micromodels of varying wettability, aiming at describing three phase displacements involving brine, oil and CO2. They have been conducted under various conditions of pressure and temperature.

Experiments under varying thermodymic conditions (gaseous, liquid and supercritical CO2) were conducted on porous media of different wettabilities. Fluids distribution within the porous medium under reservoir conditions was visualized and conclusions concerning important parameters such as the spreading coefficient which plays a major role in oil recovery were drawn. These observations were confirmed by core scale experiments such as capillary pressure curves and displacements at the core scale.

Additionally, we observed the in situ formation of CO2 foams generated from surfactants dissolved in the aqueous phase. These foams (or emulsions) were also formed from gaseous, liquid or supercritical CO2. CO2 and surfactant solutions were co injected in the porous media. Foam formation and evolution from the inlet to the outlet of the porous medium was followed.

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