| Wettability, the tendency of a surface to be preferentially wet by one fluid phase, is very important to multiphase transport properties and adsorption in microporous media. Wettability, in turn, is controlled by the surface charges and the fluids the surface is exposed to. In this work, the effect of wettability has been studied at three different scales: micro-scale (using Atomic Force Microscopy), macro-scale (using contact angles) and mega-scale (using reservoir simulations).;The polar components of crude oil can adsorb on rock/mineral surfaces and hence alter their wetting properties. One of the goals of this work is to study the role different SARA fractions (saturates, aromatics, resins and asphaltenes) play in the wettability of a mineral surface. Another objective of this work is to study the effect of solvents, namely toluene, decalin and cyclohexane, on the wettability of oil-aged mineral surfaces. Using AFM (Atomic Force Microscopy), the topography of the oil-aged, solvent-treated surfaces is studied and the degree of hydrophobicity is quantified by surface force measurements using specially coated cantilever tips. The topography images show that toluene is a better solvent than decalin and cyclohexane. It was also observed that the force of adhesion for minerals aged with just the asphaltene fraction is similar to that of the whole oil. The relation between the contact angle and the amount of adsorbed materials was investigated.;Surfactant injection is a well known enhanced oil recovery technique. In this study, a mechanism of wettability alteration by surfactants using AFM and parallel plate experiments is proposed. A few surfactants have been identified to alter the wettability of the mineral surfaces. The adhesion forces between modified AFM tips and the surfaces are measured before and after surfactant treatment to characterize the wettability of the surface.;A new four phase relative permeability model is proposed for compositional simulation of WAG (water alternating gas) injection in a medium-viscosity, low-temperature reservoir. The parameters of this model were obtained from core floods. The effect of WAG ratios and slug size were studied at laboratory and reservoir scale. WAG ratio of 0.5 gave higher rate of oil recovery. The minimum miscibility enrichment for Prudhoe Bay Gas (PBG)-Natural gas liquid (NGL) mixtures was found to be more sensitive to pressure as compared to CO2-NGL mixtures. |
