Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 75–80. Abstract Two equations are compared for calculating imbibition rates of water into porous media. A linear relation was found to apply when the square of the volume of water imbibed was plotted against time for water imbibing in natural rock materials. The effect of absorbed organic materials on surface wettability was determined from measurements of rate of imbibition, water saturation and water permeability. Introduction An understanding of the mechanisms by which water displaces oil from porous media requires an understanding of the role of capillary forces in the displacement process. The capillary forces are determined by properties of the water-oil-solid surfaces. Consequently, some measure of the surface properties of reservoir rocks is necessary if displacement behavior in oil reservoirs is to be predicted from laboratory measurements. Several experimental procedures have been proposed to assign quantitative wettability indexes to reservoir rock surfaces. The most recent of these proposals are those of Bobek, Mattox and Denekas and Amott. These indexes are designed to show a continuous variation from the preferential oil-wet to the preferential water-wet systems. They require measuring some property of the rock which is a function of surface wettability. The quantities are measured on unaltered core material and compared with values obtained for known oil-wet and water-wet extremes on the same material. These methods are useful but are semi-empirical in nature. they have the disadvantage that the measured quantities may be functions of other variables in addition to surface wettability. Some understanding of the behavior of water-oil-rock systems may be obtained from studies of the simpler water-air-rock systems. Surfaces of a given wettability are more easily maintained for the latter. Also, certain approximations can be made for the flow of water and air which are not justified for water-oil flow. The theoretical and experimental work discussed in this paper is part of a study of the role of capillarity in the dynamic displacement of air by water. The expectation is that observations for the water-air system will lead to generalizations which are applicable to water-oil systems.

Relative penneabilities of systems containing lowtension additives are needed to develop mechanistic insights as to how injected aqueous chemicals affect fluid distribution and flow behavior. This paper presents results of an experimental investigation of the effect of low interfacial tensions (1FT's) on relative oil/water penneabilities of consolidated porous media.The steady-and unsteady-state displacement methods were used to generate relative penneability curves. Aqueous low-concentration surfactant systems were used to vary 1FT levels. Empirical correlations were developed that relate the imbibition relative penneabilities, apparent viscosity, residual oil, and water saturations to the interfacial tension through the capillary number (Nc =vp.,/a). They require two empirical, experimentally generated coefficients.The experimental results show that the relative oil/water penneabilities at any given saturation are affected substantially by 1FT values lower than 10 -I mN/m. Relative oil/water penneabilities increased with decreasing 1FT (increasing N c ). The residual oil and residual water saturations (Sor and S,,-r) decreased, while the total relative mobilities increased with decreasing 1FT. The correlations predict values of relative oil/water penneability ratios, fractional flow, and residual saturations that agree with our experimental data. Apparent mobility design viscosities decreased exponentially with the capillary number.The results of this study can be used with simulators to predict process perfonnance and efficiency for enhanced oil-recovery projects in which chemicals are considered for use either as waterflood or steam flood additives. However, the combined effect of decreased interfacial tension and increased temperature on relative penneabilities has not yet been studied.

Relative permeabilities of foaming-agent solution/nitrogen gas were measured by steady-and unsteady-state methods in Berea sandstones. Results show a significant difference between steady-and unsteady-state flow. Unsteady-state experiments show a small change of relative permeability to gas over a wide range of saturations and exhibit no complete blocking effect. In steady state, however, the simultaneous flow of liquid and gas could be stabilized only above a minimum gas saturation of about 35 to 40 %, probably because of the formation of a large number of foam lamellae by the continuous supply of foaming solution. The permeability reduction factor calculated from the ratio of the gas permeability in the presence of foaming agent to that in the absence of foaming agent is mainly a function of lamellae stability.Pressures as a function of distance were measured at three pressure taps spaced at equal distances along the core. The pressure history shows abrupt jumps in pressure with advancement of the gas phase owing to capillary pressure. After gas breakthrough, the pressures at each tap were stabilized. The results during steady-state flow showed that the pressure gradient increases with increasing distance from the inlet end of the core sample, indicating that the higher gas fraction results in a greater blocking effect.The surfactant effluent concentrations were measured by a UY spectrophotometer to calculate the adsorption isotherm of this foaming agent. The dynamic adsorption of Suntech IyTM showed a Langmuir-type isotherm. The adsorption was < 2 j.tmollg sand for up to 1.0% concentration.

To understand better the effect of interfacial tensions (1FT's) on gas/oil relative permeabilities, with particular emphasis on those effective in condensate reservoirs, an experimental procedure was developed and used with the highly volatile methane/propane system. The objective was to measure steady-state relative permeabilities as functions of 1FT. Thus the 1FT was varied from 0.03 to 0.82 dynes/cm [0.03 to 0.82 mN/m], corresponding to pressures near the critical at a constant temperature of 70 D F [21 DC].Individual relative permeability curves obtained as a function of gas saturation approach the 45 D [0.79-rad] diagonals for both gas and oil as the 1FT is lowered. This supports the expectation that relative permeability curves for both gas and oil become straight lines as the 1FT approaches zero. At the highest 1FT for which experiments were performed (0.82 dynes/cm [0.82 mN/m]), the relative permeability curves approached those obtained for a nitrogen/kerosene flood for which the 1FT is approximately 30 dynes/cm [30 mN/m].The most important conclusions derived from this work are that (I) the curvatures of the relative permeability curves diminish as the 1FT is reduced, (2) the irreducible gas and liquid saturations approach zero as the 1FT approaches zero, and (3) relative gas/oil permeabilities for gas-condensate reservoirs are altered from the normal relative permeabilities only at pressures, temperatures, and compositions close to the critical point.

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