SLB reduced the number of trips to drill a 6½ in 1,261 ft section - characterized by hard and abrasive quartzite sandstone and interbedded shale - while dropping the well inclination from 11.8° back to vertical.

Run minimizing capability required

An operator planning to drill a 6½-in 1,261 ft section in Colombia's Barco and Guadalupe formations was facing multiple bit trips based on offset well information. The closest offset well in the same formation drilled a 6½-in 854 ft section, with a positive displacement motor (PDM) and tungsten carbide insert (TCI) bit assembly, took 24 runs and 62 operational days to complete.

The operator's planned section would have to be drilled through intervals of hard and abrasive quartzite sandstone containing mudstones and interbedded shale with a compressive strength of 25 to 30 kpsi. Additionally the well inclination had to be dropped from 11.8 degrees back to vertical.

SLB ran the 4¾ in T1XL FBS MK@ Neyrfor Traditional™ standard turbodrill with a diamond impregnated drill bit. The operator drilled the 6½ in 1,261 ft section in three runs at an average of 7.88 ft/h, saving USD 1.25 million and 50 operational days.

To drill this section, SLB recommended utilizing a 4¾-in Neyrfor Traditional turbodrill with an LC2 turbodrill locking clutch to prevent bit sticking, and a diamond impregnated drill bit. While the use of durable impregnated bits and a motor/turbine BHA increase drilling performance, they also bring an increased risk of leaving tools in the hole because the bit and driveshaft are able to rotate independently of the drillstring when the bit is stuck. A conventional motor has no reliable mechanism to transfer the available high torque from the drillstring to the bit, leaving axial force (pushing/pulling) as the only means to free a stuck bit/BHA. The Neyrfor Traditional turbodrill with an LC2 locking clutch locks the bit to the body of the drive-system in the event of stalling or bit sticking, so the drillstring torque can be applied to the bit. Transmission of drillstring torque to the bit significantly increases the chance of freeing a stuck bit/BHA. And, instantaneous locking while rotary drilling can reduce the risk of becoming stuck by keeping the bit in motion should the turbine stall.

The Neyrfor Traditional turbodrill and diamond impregnated drill bit assembly drilled the 6½-in 1,261 ft section in three runs at average rate of 7.88 ft/h reaching well TD in under 12 days. This saved the operator an estimated 50 operational days based on the nearest offset well performance, and reduced the risks associated with drillpipe trips in and out of the hole. After reaching TD the customer logged the well with wireline formation evaluation with little overpull, indicating excellent hole quality was delivered from the turbodrill system. The hole quality also helped ensure an effective liner running and cementing operation.