A Laboratory Protocol to Evaluate Effective Permeability Alteration by Adding Surfactants in Fracturing Fluids

Abstract

Adding chemical additives such as surfactants and nanoparticles to the fracturing fluid is a common field practice for enhanced water and oil recovery. However, measuring the multiphase permeability of ultratight rocks is challenging, due to the extremely long time required to reach flow rate and pressure equilibration. This paper aims at understanding the effects of surfactant polarity on regained permeability of tight-rock samples, as functions of reservoir brine salinity and rock mineralogy, by utilizing a modified core-flooding device. We propose a laboratory protocol to screen different surfactants used in hydraulic fracturing operations to reduce interfacial tension (IFT) and alter wettability from oil-wet to water-wet conditions. The effects of different surfactants on the relative permeability shift of rock samples are also investigated. We used tight-core plugs from the Montney Formation and surfactants with different polarities for conducting experiments. First, we measured the physical properties of surfactant solutions, including surface tension, IFT, viscosity, and particle size. Then, we assessed the effectiveness of different surfactants for wettability alteration and quantify their adsorption on the rock surface. Next, we simulated the leak-off, soaking, and flowback processes under reservoir conditions using a modified core-flooding apparatus designed for ultralow permeability samples. The results show that, for Montney cores, although nonionic surfactants show higher adsorption, their regained liquid permeability (k L) is relatively higher, compared with anionic surfactants. The measured regained k L for nonionic and anionic surfactants were equal to the initial permeability before the leak-off stage, suggesting that the surfactant adsorption was not detrimental to the surfactant’s functionality in maintaining the rock permeability. This phenomenon suggests that adsorption of some surfactants may be reversible. However, all the anionic surfactants reduced the regained k L. The results show that if a reservoir is at subirreducible water saturation conditions, the leak-off of surfactant solutions may reduce the regained permeability by increasing the water saturation near the fracture face after leak-off and flowback processes. Combining the effects of IFT and wettability alterations in the dimensionless parameter of capillary number (N ca) shows that, above a threshold N ca value, the regained permeability remains unchanged, indicating no fracture-face damage.