Tracer‐Guided Characterization of Dominant Pore Networks and Implications for Permeability and Wettability in Shale

Abstract

Pore network characterization is an important aspect in unconventional reservoir evaluation. While application of the technique of scanning electron microscope (SEM) brings substantial advances in pore characterization in shale, understanding the connected pore network that dominates flow in shale samples is limited by using SEM alone because of small fields of view and lack of views of connectivity in 3D. In this research, a technique integrating tracer imbibition, micro‐computed tomography (CT) imaging, and SEM imaging was developed to provide a solution for multiscale imaging in shale. Tracer imbibition indicates pore connectivity; micro‐CT imaging after tracer imbibition thus provides an overview of the connected pore network at the millimeter scale. With guidance from micro‐CT images after tracer imbibition, a more accurate and detailed characterization of pore systems and related mineralogy can be conducted using higher‐resolution SEM. The method was applied to five samples from Wolfcamp and Eagle Ford Formations. Results reveal the effectiveness of the integrated method by showing different patterns of distribution of the dominant pore network and different controlling mineralogy. Dominant porosity, estimated from grayscale analyses, displays a good correlation with permeability. This result indicates that dominant porosity is more relevant to permeability than is total porosity. Results from imbibition tests are also compared with that from contact angle measurement, and important implications on wettability can be obtained. The integrated method thus has the capacity to link the dominant pore network and wettability with microscale to submicroscale mineralogy, which can help better understand the pore systems and fluid flow in shale.

A Multiscale Study on Shale Wettability: Spontaneous Imbibition Versus Contact Angle

“…However, it is still debatable to conclude, for unconventional rocks that have a very complex pore structure, whether a single average surface CA or even CA hysteresis can be representative of in situ pore-scale CAs. Hence, as is being increasingly realized (Peng et al, 2019;Siddiqui et al, 2018), SI seems more likely to be representative of fluid behavior in a rock as it considers the pore-scale mineral heterogeneity, pore morphology, and any clay mineral effects. In lieu of this, more advanced techniques such as SI combined with imaged in situ pore-scale CAs are gaining prominence (Alhammadi et al, 2017;AlRatrout et al, 2018), which give newer pore-scale insights.…”

Mechanism and Quantitative Characterization of Wettability on Shale Surfaces: An Experimental Study Based on Atomic Force Microscopy (AFM)

“…This underscores the direct influence of microscale wettability distribution on contact angle measurements and the limited representativeness of this method. Nevertheless, other methods, such as the Amott wettability index, USBM method, and spontaneous imbibition, face challenges in accurately characterizing neutral wettability, being influenced by pore-throat structures, surface roughness, and the fact that they are complex and time-consuming [20,26,[32][33][34][35][36]. Nevertheless, nuclear magnetic resonance only allows for the analysis of wettability variations between pore-throat channels of different diameters [20,[36][37][38].…”