New insights into torsional BHA dynamics have been gained from high-frequency at-bit measurements when drilling with steerable mud motors in horizontal wells. Steerable mud motors are traditionally thought to decouple the bit from "sticking" as the BHA and drillstring are subject to torsional fluctuations. However, newly gathered data shows that the bit can actually come to a complete stop while the motor is forced into backwards rotation. Motor twist-offs and back-offs while drilling can be the costly consequence of such behavior. Using high-frequency, at-bit, measurements, dynamic and environmental characteristics of the bit were recorded in a dedicated bit sub at 200 Hz while drilling a horizontal well in the Granite Wash formation in the Texas Panhandle. The recorded variables include azimuthal-gamma, tri-axial accelerations, inclination, RPM, and temperature. Recorded data was examined, after each interval drilled, and correlated with standard MWD data (measured and recorded above the motor) as well as surface-recorded variables. Examination of the data revealed that the bit experienced full stick-slip behavior and, instead of being decoupled from the BHA as is traditionally thought, drove the BHA into backwards rotation via the action of the mud motor's power section. It is believed that, due to the tortuosity of the wellbore and the relative hardness of the formation being drilled, the lower end of the motor periodically "caught" and hung up while rotating, such that the negative driving torque generated in the power section (during the "bit-stick" intervals) loosened the connections below the motor's power section and ultimately led to back-offs of the connections downhole. This new high-frequency at-bit measurement tool has led to clear insights of the stick-slip behavior while drilling horizontal wells with steerable mud motors. As this new understanding contradicts traditional thinking of torsional oscillations in motor BHAs, the authors believe it is worth sharing with the industry as it can help prevent NPT related to this mechanism in the future.

Sudden growth of the Permian's Delaware Basin, exploiting multiple unconventional targets, has increased the number of drilling rigs in the area to well over 550. This rapid expansion of drilling rigs has diluted the pool of experienced drillers and operators in the region, which in turn has caused numerous drilling optimization problems such as poor penetration rates and accelerated wear on drillstring components. To enhance the learning curve and address these drilling practices, a number of operators have requested real-time downhole dynamics and mechanics information to improve drilling performance. Previously, a dedicated ‘down-hole drilling dynamics service’ was successfully deployed to the Permian for recording the down-hole drilling dynamics environment in memory mode. This service confirmed strong dynamic events occurring, and subsequently allowed adjustments to be made to the drill string components and operational parameters. However, the memory only approach meant a delayed improvement cycle, never reaching its full optimization potential or technical capabilities. Providing a ‘real-time down-hole drilling dynamics service’ delivered immediate improvements to performance through real-time drilling parameter adjustments, as well as enabling optimum bit and bottom hole assembly selection for subsequent wells. The continuous performance improvement loop highlighted the best drilling practices, permitting the development and implementation of refined drilling procedures, and further enhanced performance and safety. This paper addresses drilling dynamics challenges encountered and overcame while drilling vertical sections in six wells (on four rigs) by one operator in the Permian Basin. The data and examples presented in this paper provide an understanding of the benefits of managing drilling parameters in real-time and express the best drilling practices. Using a ‘real-time down-hole drilling dynamics service’ reduced overall operator costs by an average of 24% per well when compared to previous wells. Additionally, real-time down-hole weight on bit functionality offered an increased safety feature over a conventional drilling system, while the use of close-to-bit rotational inclination provided enhanced vertical control versus the standard survey system of a conventional straight-hole drilling assembly.