SLB kicked off a 17½ in section from a 20 in vertical casing and drilled to section TD in one run using OptiDrill™ real-time drilling intelligence service.

Drill a large-hole section through interbeded formation in one run

Total was drilling an offshore field development well from a semisubmersible rig in the Laggan field of the North Sea. The operator planned to kick off from a 20-in vertical casing and drill a 17½-in section to TD in one run. The wellplan called for a dogleg severity (DLS) of 2º/30 m. Drilling the 17½-in section in offset wells in this field had required two bit runs, and Total expected to encounter interbedded higher-strength formations while drilling this section.

Manage drilling risks with OptiDrill service to extend life of BHA

SLB used OptiDrill service to preserve the life of the bit and minimize risk. We drilled to section TD with PowerDrive X6™ RSS and roller cone bit.

We drilled large hole section to TD in one run, increased overall ROP, and achieved smooth wellbore.

SLB recommended using the PowerDrive X6 RSS and a roller cone bit, complemented by the OptiDrill real-time drilling intelligence service, to drill the section in one run. Prejob modeling using the IDEAS™ integrated drillbit design platform helped to define suggested drilling parameters for each type of formation Total was anticipating.

The OptiDrill service would enable the rigsite team to monitor downhole BHA dynamics and quickly adjust drilling parameters to preserve the life of the BHA, decreasing the severity of an event.

Reached section TD in one run while achieving smooth wellbore

Total drilled to section TD in one run, eliminating the second run that is typically required to drill the 17½-in section in offset wells in the field. On-bottom ROP was comparable to that of offset wells, and overall section ROP was significantly better because the second run was eliminated.

The section of the well crossed three faults and was drilled in inclination-hold mode, a feature of the PowerDrive X6 RSS, which resulted in a smooth wellbore. The smoothness was confirmed by real-time bending moment information from the OptiDrill service.

The roller cone bit rotated 802,000 times while drilling the hole section and encountered brief instances of bit bounce, which were detected and mitigated. Average downhole WOB and downhole torque on bit measurements from the OptiDrill service indicated the bit was performing as expected. Postrun observation of the bit confirmed the diagnosis.