Wettability plays a crucial role on the performance of enhancing oil recovery techniques because of its effect on fluid saturations and flow behavior in porous medium. This study is directed toward determining contact angles (i.e., wettability) in systems with carbon dioxide, brine, and an oil-saturated rock system. Two situations are considered: Rock system I is partially water-wet, whereas rock system II is effectively oil-wet. Contact angles have been determined experimentally as a function of brine salinity and pressure using the pendant-drop shape analysis. The experiments were carried out at a constant temperature of 318 K and pressures varying between 0.1 up to 16.0 MPa in a pendant-drop cell. For rock system I, the partially water-wet substrate, brine, and CO 2 system, the dependence on the pressure at constant salinity is very small. For this system, at a constant pressure, the contact angle decreases for increasing brine salinity. The results show that the carbon dioxide is the nonwetting phase in the pressure and salinity range studied. This behavior can be quantitatively understood in terms of the expected dependencies of the three interfacial tensions (IFTs) in Young's equation on pressure and brine salinity. For rock system II, the effectively oil-wet substrate, brine, and CO 2 system, the dependency of contact angle on pressure is considerable. This study proves that carbon dioxide becomes the wetting phase at pressures higher than 10.0 MPa. Beyond 10.0 MPa (i.e., in the supercritical region), the contact angle remains practically constant. The effect of salinity on the contact angle of the oil-wet rock system II is small. The behavior can again be quantitatively understood based on expected trends of the three IFTs that determine the contact angle. It is also shown that use of the equation of state method makes it possible to approach the experimental data quantitatively. We conclude that contact angle measurements form an essential ingredient to determine the efficiency of carbon dioxide flooding and storage.

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Alkali Surfactant Polymer (ASP) flooding has traditionally been considered in tertiary mode, i.e., after a reservoir has been sufficiently water flooded. In screening studies experiments are usually conducted under two-phase flow conditions, i.e., in the absence of a gas phase in the rock. In practice, oil reservoirs might contain some gas. In areas in the world, where gas flaring is not allowed and an infrastructure for gas transportation is not present, reinjection of produced gas is a common practice. Moreover, when the reservoir is depressurized below bubble point a gas phase will be created. To the best of our knowledge, there are no data in the literature concerning the influence of in situ gas phase (continuous or trapped) on the performance of ASP floods. The main objective of this paper is to evaluate how the presence of a free (nondissolved) gas phase affects ASP flood performance. To this end, several experiments were carried out to evaluate different conditions, where free gas was present, either flowing or trapped. We found that the ultimate residual oil saturation in most experiments is similar to the case without gas. When free gas is present in the porous medium, the oil-bank production occurs earlier, because a large fraction of the gas remains trapped, and therefore the "effective" pore volume for liquid flow is reduced. When the gas and the ASP solution are coinjected, the oil is mostly produced in emulsion form as gas enhances mixing of the in situ fluids. Trapped gas could lead to an efficient oil recovery, depending on the amount of trapped gas: the lower the trapped gas saturation the better the oil recovery.

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