The effect of stabilization has been investigated experimentally when a nonwetting fluid is displacing a wetting fluid with the same viscosity in a two-dimensional porous medium. Experiments were done at different injection rates, with capillary numbers ranging from 10 Ϫ7 to 10 Ϫ4 . The features of the front between the liquids were analyzed and found similar to those observed from invasion percolation models including a spatial gradient in the average pore threshold value, and gravitationally stabilized experiments. Front and structure of the trapped clusters of the invaded fluid at different capillary numbers are self-similar with the fractal dimensions D b ϭ1.33 and D b m ϭ1.85, respectively. The dependence of the front width w s on the capillary C a was found to be consistent with a power law w s ϳC a Ϫ␣ , with ␣ϭ0.6. The dynamic exponent ␤ d Ϸ0.8 describing front width evolution as a function of time was determined by collapsing the density-density correlation function data. An analytical argument is presented to support the stabilization of the front owing to the viscous effects. ͓S1063-651X͑96͒05012-X͔ PACS number͑s͒: 47.55.Mh, 05.40.ϩj, 47.55.Kf

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In this paper a method for the estimation of the curvature along a condensed phase interface is presented. In a previous paper in this journal [1] a mathematical relationship was established between this curvature and a template disk located at a given point along the interface. The portion of the computed area of the template disk covering one of the phases was shown to be asymptotically linear in the mean curvature. Instead of utilizing this relationship, an empirical approach was proposed in [1] in order to compensate for discrete uncertainties. In this paper, we show that this linear relationship can be used directly along the interface avoiding the empirical approach proposed earlier. Modifications of the algorithm are however needed, and with good data smoothing techniques, our method provides good quantitative curvature estimates.

Understanding reservoir wettability-including wettability alteration mechanisms-is important to model and to optimise oil recovery. When oil enters an originally water wet porous rock under primary drainage, the oil will gradually displace the water in the pores and a thin water film will be left between the pore walls and the oil. Under certain conditions, the water film may become unstable and collapse. Depending on the chemistry of the oil, water, and porous rock, this collapse may result in wettability alteration. Stability of the water film will control the wettability alteration of the porous rock. Equilibrium saturation configurations in the oil-water system at primary drainage are simulated in 2D for a realistic pore space geometry obtained directly from high resolution scanning electron microscope images and thus retaining geometric features of the porous rock under consideration. The eventual collapse of the wetting phase film is controlled by the curvature of the surface and the disjoining pressure isotherm. Given the critical disjoining pressure value depending on the temperature and the chemical properties of the system at hand, the model facilitates computation of the "wettability index", i.e., the fraction of the rock surface which will come in direct contact with oil and hence potentially become oil wet. Both synthetic and realistic images are analysed. The generic studies show the influence of the surface roughness of the pore walls on the fraction of the surface which can potentially be converted to oil wet for different drainage pressures. Introduction The reservoir rocks are filled with water and believed to be water-wet before oil enters these rocks during primary drainage (Tiab and Donaldson 2004, Dandekar 2006). This homogeneous wettability state may, however, change; either to a homogeneous oil-wet state, or to a heterogeneous state where some parts of the rock surface are water-wet while other parts are oil-wet (Donaldson and Alam 2008). A change in the wettability of a reservoir rock is caused by adsorption of components from the oil onto the grain surfaces of the rock. This adsorption is thus one necessary condition for wettability change. During primary drainage, oil has displaced most of the original water in place, leaving water only in crevices and corners and as a thin film along the pore surface of the reservoir rock. The stability of this water film depends on the disjoining pressure and the geometry of the pore surface. In order for the oil components to adsorb onto the rock surface, the water film must become unstable and collapse to a thin monolayer, providing direct access for the oil to the surface. The stability of the water film can be examined using the augmented Young-Laplace equation (Mohanty 1981, Hirasaki 1991a; Hirasaki 1991b; Hirasaki 1991c). This augmented version contains an extra term-the disjoining pressure-which incorporates the stabilizing forces in the film (Derjaguin and Churaev 1978; Derjaguin et al. 1987). When thin water films are present in a pore filled with oil and water, this equation is a requirement for equilibrium.

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