Mixing During Two-Phase, Steady-State Laboratory Displacements in Sandstone Cores

Abstract

ABSTRACT This paper examines the changes in fluid distributions and the mixing that occurs in immiscible phases flowing in a porous medium with changes in phase saturations and flow rates. We report experimental results for steady-state displacements with saturations established by secondary drainage, for one outcrop and one reservoir sandstone. Displacements were performed using immiscible liquids of matched density and viscosity at six saturations ranging from residual oil to low initial water saturation. Flow rates at a given saturation were usually varied by more than an order of magnitude. Trapped, dendritic and flowing fractions were determined for each phase by fitting effluent composition data to the Coats-Smith model as modified by Salter and Mohanty. The oil phase and, contrary to previous investigations, the brine phase both exhibited trapped saturations. That for the brine phase was found to be independent of flow rate for both core samples. The volume of trapped oil phase was also independent of flow rate for the reservoir sample, but the outcrop sample showed velocity dependence at the higher values of oil saturation. The stagnant volume fraction at a given saturation was essentially independent of velocity. Thus, in cases where trapped oil saturation changed with velocity, there was an equal but opposite change in the flowing fraction. The fits of displacement results to the modified Coats-Smith model were also used to investigate changes in mixing as phase saturations and flow velocities changed. The parameters of that model represent mixing in terms of dispersion and mass transfer coefficients. Those parameters were determined as functions of displacement velocity at each saturation. Dispersion coefficients in both phases were linear functions of velocity at any given saturation. Brine dispersion coefficients were indistinguishable from those obtained in stable, single-phase displacements on the same core. Oil phase dispersion coefficients were, in general, greater than those for the brine phase, but decreased as oil saturation increased, and at low water saturation were the same or less than those for the brine phase. Mass transfer coefficients were also linear functions of displacement velocity and had similar values for both phases. The differences in displacement results between the two core samples are interpreted in terms of pore structure and changes in fluid distribution with changes in saturation and flow rate. Finally, we discuss the implications of the mixing results for the performance of EOR processes.