Saudi Aramco is developing gas fields in various areas utilizing vertical and horizontal wells with rotary as well as motor BHAs. This application requires Saudi Aramco to drill laterals through an extremely tight sandstone formation with inclination varying anywhere from 72° to 90°. The highly abrasive formation is causing inconsistent PDC bit performance while drilling the 5 7/8-in. horizontal section resulting in exceeding the authorization for expenditure (AFE) of the wells. Saudi Aramco, in collaboration with the bit company, analyzed the field data, which showed extensive cutter damage, with abrasive wear being the most common dull characteristic. The cutter wear was causing short runs and frequent trips to change out the bit. A step change in bit design was required to extend bit life and increase rate of penetration (ROP) in areas where poor drilling performance is expected. The fixed PDC design creates an inherent limitation because only a small portion of the cutter contacts the formation, and drilling efficiency declines as the cutter wears. The resulting wear flat generates a high degree of frictional heat, which can break the diamond-to-diamond bonds in the cutter diamond table and lead to accelerated cutter degradation. An R&D initiative was launched to investigate different methods to enable a PDC shearing element to fully rotate while drilling to increase overall cutting efficiency and bit life. Several different retention methods were investigated, and a specialized fixed housing that is brazed into the bit blade was developed. The rolling cutter assembly has essentially the same outside diameter (OD) as a standard PDC cutter, which helps maintain design flexibility and cutter placement options. The newly designed 5 7/8-in. PDC was manufactured with strategically positioned rolling cutters and was run in a gas well. The objective was to achieve an average ROP of 4.7 ft/hr and drill a minimum of 240 ft of lateral hole section to achieve proposed 5% reduction in cost-per-foot. The bit achieved a record ROP of 14.85 ft/hr while drilling 527 ft of the abrasive sandstone formation. After achieving positive results from tests in lateral sections, the new bit design was also tested in a two vertical sections through the same tight sandstone formation on rotary assemblies. In these applications, the new bit design performed better than those in offset wells, with one of the two drilling from shoe to shoe for the first time in that field. This paper will discuss the application and evolution of rolling cutter bits, along with the results achieved by bits fitted with these cutters in Saudi Arabia.

Because of high formation pressure in certain formations, there are three different casing designs available, including slim-bore wells and big-bore wells. The slim-bore wells are 12-in hole section applications, and big-bore wells drilled as 16-in hole sections. In 12-in slim-bore wells, a major challenge is to drill through different carbonate formations with unconfined compressive strength (UCS) between 10,000 and 30,000 psi with hard streaks peaking at 40,000 psi toward section end. Another challenge in the lower section is high formation abrasiveness, which increases PDC cutter wear rate and slows ROP to an unacceptable rate of less than 10 ft/h before reaching TD. The challenges of this extensively drilled application are well known, and the most efficient bit design to date is a seven-bladed PDC with 16-mm cutters. The existing PDC delivers an acceptable ROP, but its dull condition suggests that a more efficient cutting structure would improve project economics in areas of slim-bore wells where the operator expected poor performance. An R&D project to improve PDC bit performance produced a Conical Diamond Element (CDE) with twice the diamond thickness of a conventional PDC cutter. The CDE provides superior resistance to abrasive wear and impact load damage. To extract the maximum benefit from the CDE's enhanced durability, design engineers used a finite element analysis- based modeling system to position the element at bit center on the baseline design by reducing cutter volume. The new design would increase drilling efficiency at the center of the borehole, leading to higher ROP. This new type of PDC has also proven to reduce damage from torsional vibration for improved stability and borehole quality. The modeling system was also used to identify rpm and WOB combinations most likely to improve ROP and dynamic stability drilling through the difficult carbonate formations. Two new 12-in bits were run in the satellite field wells and set new back-to-back benchmarks for the fastest ROP on their first run. In the X field, this bit achieved an 18% improvement in ROP (73.1 ft/h) compared with four offsets drilled with conventional PDC, resulting in a 10% reduction in cost per foot. In the Y field, the central CDE-type bit achieved a 9% improvement in ROP (72.8 ft/h) compared with a direct offset resulting in an 8% reduction in cost per foot. The authors will discuss operational challenges and the technical justification for running the CDE equipped PDC bit. The paper concludes with a discussion of economic benefits for the operator by utilizing this new technology.

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