A rigorous engineering and research effort combined with targeted field testing has delivered a new generation of PDC technology. This technology is intended to be used for the most technically challenging drilling applications across the globe.During the development of this technology, several new design features were successfully tested in Sultanate of Oman in traditional PDC applications. Once the new technologies were fully developed, an effort was made to test these PDC bits in historically non-PDC drillable applications.One of the first applications identified for the new technology was in Field-A, Sultanate of Oman. The 8 3/8-in. section at Field-A consists of abrasive sands and hard shales of the Haushi and Haima formation groups and is typically drilled using turbines and impregnated bits.Successful application of PDC bits in Field-A prompted a second application: Field-B. This application is drilled with the turbine/impregnated bit combination through the same formation groups. Penetration rates in Field-B are typically higher and run lengths longer.In both applications, testing started with the first bit out-of-the-shoe using a rotary assembly. The objective was to understand the capabilities of the new technology, then apply key learnings to the next design iterations.The authors will describe the technologies developed for the new PDC bits. These new technologies have been able to extend the typical PDC application range into harder abrasive rocks. Improvements in penetration rate of 25% to over 200% have been realized with run lengths competitive to impregnated bits resulting in substantial reduction in drilling cost. Additional cost reduction is achieved by replacing turbine with rotary. Thus far, savings of up to almost 200% have been realized in a single section compared with offsets and 11-day time savings compared to plan.

Reservoirs consisting of sandstone and conglomerates nature present the most challenging reservoirs in the fields of North Oman. The target formations are often very deep with elevated static bottomhole temperatures exceeding 157degC, and with severe potential risks associated with geo mechanical and drilling perspectives. Tectonic stresses, where principal horizontal stress greatly exceeds vertical and minimum horizontal stresses, are coupled with rock compressive strengths varying between 45,000 and 50,000 psi with medium abrasiveness. These factors, together with borehole instability, borehole break-out phenomena, problems with conventional steerable systems due to weight transfer using turbines as well as drill bit sticking, present particular challenges in these wells and require significant up-front engineering resources to be deployed. Drilling in this reservoir is difficult and in the past several issues have occurred while using turbines & rotary bottom hole assemblies. Due to the nature of the formation, a mechanical sticking mechanism (probably caused by plastic deformation of the bore hole wall resulting in the formation clamping bits along the gauge section) commonly occurs during connections and also while performing toolface orientation operations. This sticking could also be caused by breakout cavings, when an attempt is made to pick up off bottom. The time taken for the formation deformation would appear to be very short and probably occurs within seconds of new bore hole being cut i.e. fresh hole is made and the stresses caused by removal of rock by the bit are redistributed around the bore hole wall and increases the probability of sticking with the turbine assemblies. Typically drilling proceeds as normal and when a connection is made or tool face orientation is being attempted, the first sign of a problem occurs when picking up off bottom. The driller will notice a slight over pull, before the bit actually moves off bottom. Further over pull confirms that the bit is stuck on bottom and that bit rotation can not be resumed. If the bit is coupled to a down hole drive then the ability to work torque into the bit is lost as the drill string can normally still be rotated around the drive shaft. Recovery from this situation has a low probability of success ratio. A significant factor is mud weight, including the impact of losing equivalent circulating density. Mud weights required to keep the hole open can be quite high, resulting in very high overbalance. Lowering bottom hole pressure below hydrostatic pressure may cause bore hole instability. Hence, when circulating sweeps and pills or conducting operations where swabbing occurs, the amount of lost pressure on bottom must be known by the drilling team. In this case loss of primary well control is not likely to be the major risk, rather that of bore hole instability, especially with a turbine bottom hole assemblies.

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