Mitigating Stick-Slip in an Extended-Reach Lateral Through Parameter Optimization 

Field Context & Problem Statement 

On a challenging onshore extended-reach directional well, the drilling team was working its way toward a total measured depth of 16,800 ft, drilling the final 8½-inch lateral section with 13.2 ppg oil-based mud. The well was equipped with a high-torque top drive and a rotary steerable system (RSS), giving the crew the control and torque capacity needed to navigate the long lateral.  

While drilling through an interbedded anhydrite and dolomite formation, the team began to see a repeating and increasingly concerning torque response. What looked like an intermittent torque fluctuation on the surface was much more than a routine drilling response. The bit stalled intermittently, and continuous rotation from the top drive caused the drill string to wind up. The bit would accelerate as soon as it freed.    

Root Cause Analysis

AIt was found to be a stick-slip cycle, where energy builds up as the bit stalls and is violently released once the bit breaks free, creating a significant dynamic load on the drill string, BHA, and surface equipment. Moving from a soft rock layer into a harder or inhomogeneous formation causes the bit to lose its steady depth of cut, increasing resistance torque. The continuous rotation of the high-torque top drive continues to twist the drill string while the bit is stalled at the bottom, winding up the string.  

Primary reasons for stick-slip are:  

  • An aggressive PDC bit generating high reactive torque 

  • High WOB, increasing cutter depth of cut and torque demand 

  • Changes in formation strength across the interbedded lithology 

  • BHA and drill string friction against the wellbore 

Highly aggressive fixed-cutter bits, such as Polycrystalline Diamond Compact (PDC) bits, generate immense frictional torque when interacting with certain rock profiles. Applying too much downward force pushes the cutters too deeply into the rock, generating reactive torque that the surface drive cannot immediately overcome. Physical friction from the bottom hole assembly (BHA) or drill string rubbing against the wellbore walls, especially in highly deviated or horizontal wells. 

When the bit encounters harder or more heterogeneous rock, its rotation slows or stops. Meanwhile, the top drive continued applying torque, winding up the drill string. Once the bit overcomes the resistance, it releases the stored energy, producing a high-speed slip. Repeated stick-slip result in 𝐥𝐨𝐰𝐞𝐫 𝐑𝐎𝐏, 𝐩𝐫𝐞𝐦𝐚𝐭𝐮𝐫𝐞 𝐛𝐢𝐭/𝐁𝐇𝐀 𝐝𝐚𝐦𝐚𝐠𝐞, 𝐢𝐧𝐜𝐫𝐞𝐚𝐬𝐞𝐝 𝐟𝐚𝐭𝐢𝐠𝐮𝐞 𝐥𝐨𝐚𝐝𝐢𝐧𝐠, 𝐝𝐨𝐰𝐧𝐡𝐨𝐥𝐞 𝐭𝐨𝐨𝐥 𝐢𝐬𝐬𝐮𝐞𝐬, 𝐚𝐧𝐝 𝐚𝐝𝐝𝐢𝐭𝐢𝐨𝐧𝐚𝐥 𝐭𝐫𝐢𝐩𝐬, all contributing to invisible lost time. 

Mitigation Strategy 

1. Next-Generation Switched Hybrid Bit Architecture 

Shifted the drilling envelope to higher surface RPM (from 110 RPM to 160 RPM) and systematically reduced Weight on Bit (WOB), breaking the drill string's torsional resonance frequency. 

This was an effective immediate approach to handle stick-slip. Reducing WOB reduces the depth of cut and, therefore, the reactive torque. The bit cutters take smaller bites, and the torque is enough to remove those small rock segments. Whereas increasing RPM delivers the benefits of lower dynamic friction. At low rotational speeds, minor variations in rock hardness can easily slow the bit down enough for it to transition from dynamic friction to static friction. Once it stops, it requires massive torque to break free again. Higher RPM keeps the bit rotating continuously. 

What additional measures can be taken to manage stick-slip?