Probing the archie's exponent under variable saturation conditions

The saturation exponent, n, is often assumed to be two in the absence of core data, but a variety of " values have been reported. This uncertainty in n may be due to pore geometrical and topological complexities, structural heterogeneities coupled with variations in wettability. As values of " are correlated to oil-in-place, good estimates of n are needed. Recently, an X-ray μ-CT imaging registration technique was developed where multiphase fluid saturations can be measured in-situ on a pore scale basis within reservoir miniplugs. Using this technique, one can obtain information on the relative fluid affinity for specific pore regions, as well as the connate wetting phase saturations and habitat of the hydrocarbon and wetting fluid within the rock at the pore scale. From the observed fluid saturations one may use numerical simulations to predict the value of n and better understand reasons for deviations in the saturation exponent from the conventional values. In this paper, we describe analyses undertaken on both clastic and carbonate samples under variable saturation conditions. Coupling 3D imaging, high-resolution SEM analysis, and in-situ observations of fluid saturation enables one to understand the observed resistivity response of various samples under different saturation conditions. In a first set of experiments, we discuss the observed behavior on a clean water-wet sandstone; in experiments, one observes n ≈ 2 at high to intermediate water saturations (Sw), but at lower Sw, " < 2. Using a combination of μ-CT, image registration and cryo-SEM analysis we observe that at low Sw water films in those clean sands concentrate at or on the perimeter of grain contacts. 3D analysis shows the grain contacts span the rock structure. Simulation results show that the inclusion of a realistic thin water film within grain contacts results in a match to the measured behavior for RI. Analyses are also performed on carbonates under variable wettability conditions. The role of microporosity, wettability, and saturation history on pore scale fluid distributions and thus resistivity response is discussed. The results underline the potential importance of microporosity in determining saturation exponents at low Sw. Capturing porosity information at all scales gives better estimation of original oil-in-place, particularly for carbonates displaying a wide variety of pore structure and wettability behaviors