FLUID IMBIBITION, CLAY MINERALOGY, AND PORE STRUCTURE OF VARIOUS SHALES

The current success of hydrocarbon exploration of unconventional resources in the US has been credited to the increasingly improved techniques of hydraulic fracturing and horizontal drilling of shale plays. However, high production cost and low overall recovery affect a sustainable development. The sharp decline in hydrocarbon production of tight shale plays is related to the macroscopic manifestation of fluid flow from the nano-scale pore structure of the shale matrix. Fluid flow and hydrocarbon production in shale is controlled by geometric and topological characteristics of nanopores, which is further impacted by the abundance and types of clay minerals. To address these issues, we have collected core samples from different shale basins (Barnett, Barkken, and Eagle Ford) and studied how fluid imbibition is linked to pore structure and clay mineralogy of those shale samples. We performed wettability-fluid (API brine, n-decane and acetone with a different hydrophobicity) and tracer imbibition into shales to examine the association of wettability-tracers with minerals. Clay minerals were identified using X-Ray Diffraction (XRD) on powdered shale samples. This study demonstrates the utility of using wettability fluids, nano-sized tracers, elemental laser ablation-ICP-MS mapping, and XRD techniques to investigate the pore size distribution and connectivity of clay minerals of tight shales. These advanced approaches bridge the knowledge gap between pore structure, fluid behavior, and clay mineralogy of different shales, which overall affect the migration of hydrocarbon molecules from the shale matrix into the stimulated fractures for recovery.