Laboratory evaluation of mud systems for drilling high clay shales in dynamic conditions: Comparison of inhibitive systems

Wellbore instability is caused by the radical change in the mechanical strength as well as chemical and physical alterations when exposed to drilling fluids. Unscheduled events that are related to wellbore instability account for more than 10% of the drilling cost, which is estimated to one billion dollars per annual cost. Understanding shale-drilling fluid interaction plays a key role in minimizing drilling problems in unconventional resources. The need for providing a more suitable drilling fluid system for drilling operations in unconventional resources is growing. The major consequences of improper fluid selection include bit-balling, hole sloughing, and most importantly low drilling rates. This study will evaluate the effect of different inhibitive drilling fluid systems on shale drilling performance. The mud systems use in this study include cesium formate, KCl based mud systems, and a conventional water-based mud. The conventional water-based mud is used as reference fluid. An innovative HPHT drilling simulator is used to perform real-time drilling operations on cylindrical shale core samples obtained from the Tuscaloosa Marine Shale (TMS). The process involved simulating real-time drilling operation at downhole conditions where different fluids served as drilling fluid. A comparative analysis of the impact of each drilling fluid systems on the drilling performance as then performed. The analysis focused on drilling parameters such as rate of penetration, torque, and friction factor during drilling. This paper evaluates the compatibility between different fluid systems and shale formations. The paper also provides an overview of the effect of the inhibitive mud systems on drilling performance. The inhibitive muds systems (KCl based fluids and cesium formate) provided improved drilling performance compared to conventional water-based mud.