The Influence of Interfacial Tension on Water/Oil Two-Phase Relative Permeability

Water-oil relative permeability characterizes two-phase flow and displacement processes, and its functional form is difficult to determine in a particular reservoir study. Adding various chemical agents into the displacing aqueous phase during alkaline-surfactant-polymer combination chemical flooding in oil production significantly changes interfacial tension (σ) on water-oil interfaces, and also increases the degree of difficulty in measuring such changes in the laboratory or field. To overcome the limitations of the existing laboratory measurements of relative permeability (which are applicable only for high ranges of interfacial tension [e.g., σ > 10 mN/m], we present a comprehensive experimental study of two-phase relative-permeability functions in much lower, more realistic interfacial tension water-oil systems. In particular, we have (1) develop an improved steady-state method of measuring water-oil relative permeability curves; (2) proven that a critical interfacial tension value (σc) exists such that interfacial tension has little impact on relative permeability for σ > σc , while if σ < σc, relative permeabilities to both water and oil phases will increase with decreasing interfacial tension; and (3) shown that a logarithmic relationship exists between water-oil two-phase relative permeability and interfacial tensions. The experimental results reported here and conceptual models proposed here will be useful for feasibility studies, optimal designs, and numerical simulations of different chemical flooding operations in oil reservoirs. Introduction With simultaneous increasing demand for oil and large decreases worldwide in newly discovered oil reserves in the past few decades, more efficient development of oil and gas from existing reservoirs, using enhanced oil recovery (EOR) methods, has received greater attention, in the energy industry. As a result of industry-wide efforts to improve oil recovery rates, many EOR techniques have been developed and applied to various oil fields. In general, EOR methods, such as chemical flooding, miscible flooding, and thermal recovery techniques, rely on altering the mobility and/or the interfacial tension (IFT) between the displacing and displaced fluids to improve sweep or displacement efficiency. Among the various EOR approaches developed, chemical flooding, with various chemical surfactants added into injected fluids, is among the most promising, cost-effective, and widely used methods. To evaluate such chemically enhanced EOR approaches for their efficiency or suitability to a given reservoir, investigators resort to quantitative studies of laboratory experiments and field applications, requiring many physical parameters. Among these parameters and correlations, wateroil two-phase relative permeability is perhaps the most important constitutive relation that characterizes two-phase flow and displacement processes in porous media. Because of the additional interactions between fluid (water and oil) phases, chemical components, and solid porous rock, flow behavior within chemical flooding is in general more difficult to characterize than that within oil displacement in conventional water flooding. Even with the significant progress made in understanding chemical flooding over the past few decades, it remains a challenge to quantitatively assess such flow behavior. It is even more difficult to predict whether this technique can be successfully applied to a given field condition. One of the primary difficulties is the lack of physical insight or constitutive correlations (e.g., relative permeability curves) for describing mutual effects or interplay between phases during chemical flooding processes, a deficiency that hinders quantitative analysis (such as numerical modeling studies) of laboratory or field studies. The primary goals in reservoir EOR operations are to displace or mobilize more remaining oil from existing formations than can be achieved using conventional waterflooding techniques. Remaining oil left in reservoirs after long-time recovery operations is normally discontinuously distributed in pores. From the viewpoint of fluid flow mechanics, there are two main forces acting on residual oil drops: viscous and capillary forces. Microscopic displacement efficiency with an EOR method depends on the relative influence or ratio of these two forces, which is often described by defining a capillary number as the ratio of viscous forces and capillarity: SPE 95405 The Influence of Interfacial Tension on Water/Oil Two-Phase Relative Permeability P. Shen, SPE, B. Zhu, and X.-B. Li, PetroChina, and Y.-S. Wu, SPE, Lawrence Berkeley Natl. Laboratory