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.