Oil and gas productivity from shale formations can be dependent on the flow behavior of the hydraulic fracturing fluids used in stimulation treatments. Because of the unique characteristics of shale formations, including low permeability, existence of micro-fractures, and sensitivity to contacting fluids, it is difficult to evaluate the complex microscopic interactions occurring between the fracturing fluids and the reservoir rock using traditional laboratory methods. Therefore, the objective of this study is to evaluate the interaction between fracturing fluid and representative shale cores by quantifying the invaded fluid volume during the treatment and shut-in time as a function of pore geometry using nuclear magnetic resonance (NMR) technology.
Shale outcrop cores from the Eagle Ford, Barnett, Marcellus, and Mancos were evaluated in this study. Cores were submerged in various fracturing fluids under pressure and temperature for two days. The increase in the volume of the fluid invaded into the cores was quantified using NMR as a function of the average pore radius. To mimic the flowback recovery process, the cores were placed in a vacuum cell for an hour, and the decreased fluid volumes within the cores were measured. Test conditions in this study investigated the effects of clay control additives and surfactants. Furthermore, the effect of operating parameters such as the pressure and fracturing fluid contact time was investigated.
NMR techniques enable the effective evaluation of additives, such as surfactants and clay control additives, which until now may have been selected solely based on best practices established from stimulating local conventional formations. Additionally, this comprehensive fluid evaluation technology supports the creation of customized fracturing fluids, targeted for individual shale formations, to maximize factors such as post-fracturing load recovery, and to aid in the advancement of the industry's understanding of new fracture modeling concepts.