Theoretical and Experimental Investigation of Water-in-Oil Transverse Dispersion in Porous Media

Abstract

Summary Water production is controlled by the size and distribution of water saturation around wells. A recent discovery shows that not employing hydrodynamic mixing in numerical simulators may underestimate the water transition zone (Duan and Wojtanowicz 2006). This paper reports continuing research into mechanisms causing expansion of the water-saturation transition zone (transverse dispersion) in a segregated flow of oil and water approaching a vertical well's completion. The mechanisms—including nonlinear flow, turbulence, shear rate, and flow baffling at grains—all contribute to the instability of the oil/water interface, resulting in hydrodynamic mixing. Interface instability because of shearing rate has been demonstrated in our recent study on the Hele-Shaw model (Duan and Wojtanowicz 2007). In this paper, we mathematically model the effect of flow baffling and demonstrate transverse dispersion experimentally using a linear physical sandpack. A simple model of tortuous flow was developed to demonstrate the effect of two-phase-flow baffling in granular porous media. The model shows that the change in flow momentum of the two fluids at the point of collision with rock grains becomes the major factor causing water dispersion. A series of segregated-flow runs (top, oil; bottom, water) was carried out using a physical model packed with different porous media at a constant pressure drop. The runs were videotaped and analyzed for saturation distribution using a color-intensity-recognition software. The results clearly demonstrate onset of transverse dispersion of water into the flowing oil. Further dispersion, however, was overshadowed by the dimensional and end-point effects of the model. With a numerical estimation procedure, the initial dispersion rate—computed from the 1D flow model—is the essential data needed to estimate total dispersion in radial inflow to wells.