Influence of Very Low Interfacial Tensions on Relative Permeability

Abstract

Laboratory studies have been conducted to determine the influence of the composition of gas and oil phases on the parameters involved in the description of two-phase flow in porous media when the compositions of the phases vary over a wide range. Relative permeabilities to gas and oil were determined under high pressure and temperature for binary systems (methane/n-heptane, methane/n-decane, etc.), leading to very wide variations of the interfacial tensions values. Investigations were focused specifically on mixtures involving low interfacial tensions, down to 0.001 mN/m. This study has shown that residual oil saturations and relative permeabilities determined from the displacement tests with a filtration velocity of about 20 cm/hr are affected strongly by interfacial tension, especially when it is lower than 10-2 mN/m. Introduction This study deals with the influence of the compositions of the liquid and vapor phases in equilibrium on displacements of oil by gas in porous media. One of the goals of high-pressure or enriched-gas injection is to obtain low interfacial tensions between the in-place oil and injected gas. During the displacement of gas in oil-bearing formations, multiple exchanges may take place between the liquid and vapor phases so that complete miscibility may be achieved. This phenomenon generally is called thermodynamic miscibility. During this process the interfacial tension is reduced progressively to zero. The resulting reduction in capillary forces makes it possible to decrease the residual oil saturation considerably. The same goal also is sought by other enhanced recovery techniques not examined here i.e., surfactant flooding or microemulsion flooding. The purpose of this study is to examine the influence of the thermodynamic conditions on the relative permeabilities in displacements of a liquid phase by a vapor phase when both phases are at equilibrium. The Problem The general equations describing the flows of two phases are the relative permeability equations. They show, for each phase, that the flow rate in a porous medium is a function of the absolute permeability, relative permeability to the fluid involved, fluid viscosity, pressure gradient in this phase, and gravity. In fact, relative permeabilities depend on a greater number of parameters.1 Some of them are the ratio of viscosities, µ2/µ1; the ratio of gravity to capillary forces (Bond number), (?2-?1)gk]/s; the ratio of the inertia forces to the viscosity forces (Reynolds number), (?1·u·k)/µ1; the ratio of the viscosity forces to the capillary forces (capillary number), (µ1·u)/s; and wettability. When they exist, exchanges between the phases can modify the physical and chemical properties of the fluids, especially at the interfaces. Under such conditions the influence of the capillary number (µ1·u)/s is by no means negligible, with the decrease in interfacial tension causing an increase in oil recovery.2 It may be thought that relative permeability to oil is closely dependent on this capillary number,3 especially when the value of s is small, and that this influence is principally apparent with low oil-saturation levels.

Factors That Affect Gas-Condensate Relative Permeability

“…This differs from previously published tests with model fluids, which were conducted with single-pass flow systems (Nagarajan et al 2004;Kamath 2007), in which the phases may not be in equilibrium as they enter the rock. We found that model fluids are very sensitive to mass transfer and entrapment effects.…”

“…2 shows a schematic of the reservoir-condition apparatus. The system is similar to that described by Nagarajan et al (2004) with a few major upgrades. The system is simpler and more precise in measurement because of the state-of-the-art gas-condensate recirculating system.…”

Phase behavior and interfacial tension evaluation of a newly designed surfactant on heavy oil displacement efficiency; effects of salinity, wettability, and capillary pressure

“…Lefebvre du Prey [14] reported that the Kr value increases considerably for both the wetting phases in an oil-wet media. The relative permeability variation with Nc was also supported by other researchers like Bardon and Longeron [15], Amaefule and Handy [16], and Harbert [17] which confirms that Kr is a function of IFT, flow rate, absolute permeability and the fluids viscosity. On the other hand, the results of a series of steady state core flooding experiments by Fulcher et al [18] in water-wet sand stone rocks indicated that the water relative permeability was increased by Nc, however, the trend was not clear for the oil phase.…”

Investigation of Oil Recovery in Fractured Carbonate Rock by

“…However, the contribution of B o is minor due to small residual saturation and the change in IFT is more important since the recovery curve has a sharp increase. Bardon and Langeron (1980) also found a decreasing residual oil saturation using C 1 -C 7 mixtures at high pressures when measuring gas oil relative permeability.…”