Miscible Displacement Of Residual Oil - Effect Of Wettability On Dispersion In Porous Media
Authors: Maini B.B. , Ionescu E. , Batycky J.P. 
Published: March 2010

In miscible displacement of residual oil, the dispersion of injected fluid is an important consideration in determining the optimum slug size. The extent of dispersion depends, in addition to the flow rate and characteristics of the porous medium, on the wettability of the fluid-rock system. This work presents experimental evaluation of the effect of wettability on dispersion.

Three types of miscible displacement were performed in cores of differing wettability:displacement of water or oil at 100% saturation,displacement of residual oil with injected oil, anddisplacement of residual water with injected water.

Systematic differences in the shape of effluent concentration profiles and the values of dispersion coefficients calculated from them were observed. Miscible displacements of residual phases displayed considerably higher dispersion compared to displacements at 100% saturations in the same core. In strongly wetted media, the miscible displacement of the residual not-wetting phase showed very early breakthrough and poorer recovery efficiency when compared to miscible displacement of the residual welling phase. In the case of intermediately-wet media the dispersion characteristics observed during miscible displacement of the two residual phases were similar.

The observed relationship between wettability and dispersion in miscible displacements of residual phases was strong enough to suggest that such dispersion measurements can be used to assess and quantify wettability.

Introduction

In miscible displacement of residual oil the dispersion of injected fluids is an important consideration in determining the optimum slug size.

The extent of dispersion depends on a number of factors including the now rate, pore geometry of the medium, differences in density and viscosity of the displaced and displacing fluids, phase behaviour of the fluids and wettability of the fluid-rock system.

A number of studies of fluid dispersion in two-phase flow have been reported in a pioneering work, Brown(l) found that the displacement of connate water in the presence of and during the displacement of an immiscible non-wetting oil or gas phase was in many respects similar to single-phase miscible displacement, but the volume of the transition or mixed zone measured in total pore volumes increased rapidly with a decrease in the initial connate water content. Raimondi et al.(2) found that the longitudinal dispersion coefficient in the oil phase increased sharply with increasing water saturation. Stalkup(3) found that, at high water saturations, only part or the oil was flowable but that the rest, found to reside in locations that were blocked by water, could be recovered by molecular diffusion. Salter and Mohanty(4) were able to fit effluent concentration profiles obtained during steady-state two-phase now experiments with a tour-parameter capacitance dispersion model in which only a portion of the stagnant non wetting phase could be recovered through diffusion.

Sahimi et al.(5) used a network model of a porous medium and the Monte Carlo strategy of repeated computer experiments to evaluate the effect of saturation on dispersivity in two-phase flow.. They found agreement with Raimondi et al. that longitudinal dispersivity in a given phase rises sharply as the saturation of that phase approaches residual.