In tight reservoirs, the invasion of water-based fracturing fluids into the rock matrix may reduce hydrocarbon relative permeability and consequently oil production rate. This paper aims at investigating the change in oil effective-permeability () during the flowback processes after hydraulic fracturing operations.
We perform a series of core flooding tests on core plugs collected from Midale tight carbonate reservoir to simulate fracturing fluid leak-off and flowback processes. First, we clean, saturate the plugs with reservoir brine and filtered oil, then age them in oil for 14 days under reservoir conditions (P=2500 psig and T=60°C) to restore reservoir conditions and define baseline . Second, we measure before and after fluid leak-off for (i) different fracturing fluids (i.e. freshwater and a mixture of three nonionic surfactants), and (ii) different shut-in times (3 and 14 days). The results show that regained permeability after the fracturing fluid leak-off in a high-permeability plug indicates a two-fold increase (from 1.4 to 0.7 md) compared to the freshwater case. The improved in this high-permeability plug is due to the effects of interfacial tension reduction (from 26.07 mN/m for freshwater-oil to 5.79 mN/m for fracturing fluid-oil) by surfactants. In terms of shut-in times, measured after 3- and 14-day shut-in times in high permeability plugs indicate a reduction of 5.71% to 17.98% compared to the baseline values. This means that there is no significant change in regained permeability by increasing the shut-in time from 3 to 14 days. We also observe that of a low-permeability plug show 29% and 65% higher than corresponding baseline values after 3- and 14-day shut-in periods, respectively. The regained permeability strongly depends on porosity, permeability and irreducible water saturation of the plugs.