In-Depth Analysis of How Chemical Treatments Work to Improve Conductivity in Shale Formations

Abstract

Abstract To maintain open and conductive fractures in tight-rock shale formations, shale/water interactions should be controlled through chemical or brine treatments. Adequate treatment of an unconventional formation can mitigate or reduce the damaging effects induced by shale (swelling, sloughing, fines migration) or proppant (proppant embedment, breakage, fines migration), which leads to maximized conductivity. This study characterizes shale behaviors with various treatment fluids applied under simulated downhole conditions. Four source rock shale samples, Barnett, Eagle Ford, Mancos, and Marcellus, were characterized and evaluated in contact with chemical and brine treatments to determine the extent of swelling and mechanical stability imparted by each treatment. Conductivity measurements were taken on proppant packs between shale wafers under closure stresses from 2,000 to 10,000 psi. The wafers used during those tests were then analyzed using computed tomography (CT) imaging. Quantification and classification of the damage were used to evaluate the shale formations after application of fresh water and two chemical treatments—a small cationic oligomer and a large cationic polymer additive. Results suggested that chemical and brine treatments do not provide an all-inclusive mechanism to prevent damage for all shale samples, and total clay content or clay type was not the best predictor of water sensitivity. Barnett shale samples contained the most clay, had the highest conductivity, and were most resistant to fluid-induced damage using a small cationic oligomer additive. Conductivity loss for the other three shale formations was primarily attributed to fluid-induced formation damage. In each of these three shales, the mechanism for formation damage resulted from different causes. Clay-induced swelling for Mancos shale resulted in the most significant proppant embedment and was most effectively remedied using a large molecular weight polymer stabilizer treatment. Eagle Ford and Marcellus shales showed pockets of proppant embedment and significant fines migration. Generation of migrating fragment causality was different for these two shales; one contained migrating clays in its mineralogy, while the other was more mechanically brittle and prone to stress-induced fragmentation. The differing mechanism changed the effectiveness of the chemical treatments; Eagle Ford shales were most responsive to large molecular weight polymer stabilizers, whereas Marcellus shales did not change significantly with the chemical treatments evaluated. Selecting the optimal chemical treatment for each formation depends on the mechanism and type of damage. Each reservoir is unique, and improving production begins with customizing treatments to protect the formation materials against the specific damage mechanisms, thus minimizing the negative impact on propped fracture conductivity. Understanding the exact needs of each shale formation allows the treatment fluid to be tailored specifically for the formation as part of the fracturing treatment design, thereby optimizing the treatment effectiveness and cost.