Advances in Understanding Wettability of Tight Oil Formations: A Montney Case Study

Abstract

Summary This paper presents comprehensive rock/fluid experiments, by use of reservoir rock and fluids, to investigate wetting affinity of the Montney (MT) tight oil play in the Western Canadian Sedimentary Basin. Wettability characterization is essential for selecting optimum fracturing and treatment fluids by completion engineers and for selecting appropriate relative permeability and capillary pressure curves by reservoir engineers. Application of the conventional techniques for wettability evaluation of tight rocks is challenging primarily because of their extremely low permeability and complex pore structure. The objective of this paper is to develop an alternative laboratory protocol for evaluating the wettability of tight oil rocks reliably. First, we conducted systematic spontaneous-imbibition tests on fresh core samples from two different wells drilled in the MT formation. We measured the air/brine, air/oil, and brine/oil contact angles for all samples. We used the end pieces of the samples to conduct scanning electron microscopy (SEM) and analysis of the elemental mapping, or energy-dispersive X-ray spectroscopy (EDS). Finally, we investigated the spontaneous imbibition of brine (or oil) into the samples partly saturated with oil (or brine). Both oil and brine spontaneously imbibe into the fresh samples, composed of quartz, carbonates (dolomite/calcite), clay minerals, feldspars, and organic matter. The results indicate that the effective pore network exhibits a mixed-wet behavior. Moreover, brine spontaneously imbibes into and forces the oil out of the oil-saturated samples, whereas oil cannot imbibe into the brine-saturated samples. This indicates that in the presence of both oil and brine, the rock affinity to brine is higher than that to oil.

Wetting Behavior of Tight Rocks: From Core Scale to Pore Scale

“…Calculated oil and water CAs suggest higher wetting affinity toward oil. This is in agreement with the measured wetting affinity indices calculated based on the spontaneous imbibition of oil and water into the MT core plugs (Habibi et al, ). The oil wetting indices for all samples are slightly higher than those for the water.…”

“…To explain the observation of water imbibition into the oil‐saturated core plugs (Habibi et al, ), we apply the DLVO theory and assume that (1) the oil covers the rock surface and there is no thin film of water on the rock surface and (2) the electrostatic interactions (double‐layer forces) within the oil film are neglected (Hirasaki, ).…”

“…To explain why the oil cannot imbibe into the water‐saturated core plugs during the spontaneous imbibition tests (Habibi et al, ), we evaluate the stability of the water film covering the rock grains when the water‐saturated core plugs are exposed to the oil. To calculate the disjoining pressure of a rock/water/oil system, we first measure the zeta potential of rock/water and water/oil pairs; then we calculate the double‐layer forces (equation ) using the reduced surface potentials calculated for each pair (equation ).…”

“…Small pores and corners of the pore space remain water-wet due to the high capillary pressure required for the water displacement, leading to mixed-wet conditions. Although fluid flow in mixed-wet systems has been extensively modeled for estimation of capillary pressure and relative permeabilities (Bradford & Leij, 1996;Bultreys, Stappen, et al, 2016;Landry et al, 2014;Ryazanov et al, 2014;Valvatne & Blunt, 2004;van Dijke et al, 2001), limited studies investigated experimentally multiphase flow in mixed-wet synthetic rocks (Al-Raoush, 2009;Mirzaei et al, 2010) and real rocks (Habibi et al, 2016;M. Kumar et al, 2009;Schmatz et al, 2015;K Singh et al, 2016).…”

“…Small pores and corners of the pore space remain water‐wet due to the high capillary pressure required for the water displacement, leading to mixed‐wet conditions. Although fluid flow in mixed‐wet systems has been extensively modeled for estimation of capillary pressure and relative permeabilities (Bradford & Leij, ; Bultreys, Stappen, et al, ; Landry et al, ; Ryazanov et al, ; Valvatne & Blunt, ; van Dijke et al, ), limited studies investigated experimentally multiphase flow in mixed‐wet synthetic rocks (Al‐Raoush, ; Mirzaei et al, ) and real rocks (Habibi et al, ; M. Kumar et al, ; Schmatz et al, ; K Singh et al, ). Different methods have been implemented to prepare a mixed‐wet system including (1) mixing the oil‐wet sands treated with octadecyltrichlorosilane solutions and water‐wet sands at different ratios (Al‐Raoush, ; Mirzaei et al, ), (2) freezing the initial water followed by flushing with a stable chemical group to make the pore surface hydrophobic (M. Kumar et al, ), and (3) doping the oil with fatty acids and aging the cores overnight to make them mixed‐wet (K. Singh et al, ).…”