Novel Evaluation Method of Fracturing Fluid Additives on Barnett and Marcellus Outcrop Shale Cores Using NMR Technique

Abstract

Abstract Because of the unique characteristics of shale formations including low permeability, existence of micro-fractures, and sensitivity to the contact fluids, it is difficult to evaluate the complex microscopic interactions between fracturing fluids and the formation in a traditional laboratory setting. Prior work (SPE 174186) demonstrated the value of using Nuclear Magnetic Resonance (NMR) to evaluate the interaction between a shale formation and fracturing fluid components, such as clay control agents and surfactants. In this work, we expand the research to study more fluids and better understand why the performance of surfactants and clay inhibitors vary in a particular shale sample. The current work builds on the prior study by adding more fluid variations and further analyses of the fluids' surface tension, micelle size, and the core samples' mineral composition. Outcrop cores from the Barnett and Marcellus shales were evaluated in this study. Cores were submerged in various fracturing fluids under different experimental conditions: pressure of 400 psi, temperatures from 150 to 250 °F, and fluid contact times from 2 to 16 days. Due to the variations of mineral composition and reservoir properties in different shale formations, the selection of surfactants used in the fracturing fluids can be optimized based on the characteristics of each shale reservoir. For example, for the Barnett outcrop cores tested, the majority of the tested surfactants increased flowback recovery, which indicates that a reduction in surface tension is more influential. For a clay-rich core like the Barnett, the use of permanent clay inhibitors was critical to inhibit clay damage more permanently for treatments that last longer. In contrast, the Marcellus cores tested did not indicate clay damage with any type of clay inhibitor tested. However, a low molecular-weight clay inhibitor is recommended for maximum flowback recovery bcause of the extremely low permebility. This work extends understanding of fracturing fluid additives that, in many cases, are currently selected solely based on minimal testing and experience gained from conventional formations, rather than demonstrated performance in a particular shale formation. Moreover, this work opens an opportunity to customize fracturing fluids and services for enhanced fluid recovery by evaluating actual reservoir core from the given area of interest.