Hydraulics can significantly affect Polycrystalline Diamond Compact (PDC) bit performance in applications where cuttings volume, formation types, and rig pressure limitations lead to poor fluid dynamics that compromise cleaning and cooling, and result in lower ROP and higher bit wear. A key mitigation challenge is improving cleaning efficiency without experiencing a significant pressure drop across the bit. This paper studies hydraulic conditions affecting PDC bit performance, examines modeling and design steps to develop a curved nozzle design, and presents the nozzle's performance in the field. Research including computational fluid dynamics (CFD) modeling was conducted to better understand flow and velocity across the bit face. The resulting curved nozzle geometry was complex and required multiple iterations to achieve the desired effect. The nozzle design was applied in the field and its performance was compared to similar PDC bits with standard nozzles. The curved nozzle design redirects fluid flow and reduces distance from the nozzle outlet to cutting face while retaining the same total flow area (TFA). The change in flow characteristics increases fluid impact on the formation and velocity in the waterways to enhance cleaning efficiency and cooling. The carbide nozzles were manufactured and installed on standard PDC bits used in a series of Permian Basin vertical and lateral wells in the United States. Vertical applications in Canada's Viewfield field were also studied. Bits fitted with the curved nozzles demonstrated significant performance gains compared to bits with conventional nozzles. Field reports show higher ROP and less bit wear in formations where interbedded clays and reactive shales present hydraulic challenges. The insights gained into PDC bit hydraulics and the performance of the resulting curved nozzle design has enhanced the ability to mitigate many common hydraulics-related cleaning and cooling challenges.

Historically, everyday drilling dynamics measurements rely on the data captured at Measurement While Drilling (MWD) tools. These measurements only provide data at the location where the MWD is placed in the bottom-hole assembly (BHA). Embedding cost-effective sensors at the drill bit, bit box of steerable motor, top sub of the steerable motor and in the BHA provide data at point of insertion giving a much clearer understanding of downhole dynamics. The sensor package discussed in this paper contains 3-axis vibration, 3-axis shock, two temperature sensors and a new 3-axis gyro. The new 3-axis solid-state gyro sensors were added in the data recorder to measure accurate rotation speed, torsional oscillation and stick-slip at the bit, bit box and other parts of the BHA/drillstring. The data retrieved at the in-bit and bit-box drilling dynamics recorders, along with other points in the BHA, confirmed the effectiveness of "at-point" measurements for correlating bit conditions with downhole drilling dynamics. This granularity of the drilling dynamics data captured "at-point" is typically not seen from an MWD sensor. The in-bit and at-bit measurements revealed critical drilling dynamics dysfunctions that effected bit performance and life. Significant temperature increases at the bit were noted in certain formations where excessive dysfunctions were present. This paper describes the results obtained from "at-point" sensors while drilling in some of the harsher plays in North America Land (NAL). Using proprietary software, the downhole data was merged with EDR data to show the relationship between surface and downhole. Since the bit is typically semi-decoupled from the drillstring (through the mud motor power section), the data gathered from the in-bit and bit-box sensors provide a new dimension of data for bit and drilling tool development.