PDC and depth-of-cut control technology set drilling record

The Panna field produces predominantly from two carbonate reservoirs, including the upper A-zone (Oligocene) and lower B-zone (Middle Eocene). Overlying sediments comprise the argillaceous formation of Chinchini, Tapti, Mahim, and Bombay limestone, followed by alternations that lie directly on the A-zone reservoir. The alternations horizon is between 70 m and 100 m (230-328 ft) thick with thin interbedded shale and limestone formations of varying hardness.

The rate of penetration was increased, and the entire 1,264-m (4,147-ft), 8 1/2-in. (21.6-cm) section was completed in a single BHA run.

BGEPIL’s ongoing campaign involves re-entering wells through a window milled in pre-existing 9 5/8-in. (24.4-cm) casing to drill multiple fishbone laterals in the reservoir section utilizing a rotary steerable system (RSS) integrated with a resistivity, density, and neutron porosity formation-evaluation package.

Application challenges

The operator used steerable motors with logging-while-drilling (LWD) tools in the earlier horizontal wells. The BHA experienced sliding difficulties that limited the extent of the horizontal reach. There were repeated incidents of BHA whirl and severe acceleration and deceleration caused by stick-slip and consequent tool damage on several occasions.

While drilling the openhole sidetrack in the 8 1/2-in. (21.6 cm) horizontal section, the directional requirements and formation mineralogy required the bit to deliver optimum dogleg severity (DLS) without an aggressive gauge. This could cause a micro-dogleg, compromising wellbore quality and operational efficiency.

Also, the carbonate reservoir is prone to lost circulation. Severe mud losses were encountered frequently, which necessitated the use of a diluted mud system that increased friction between drillstring components and the formation, further aggravating drilling dynamics and eventually resulting in BHA failure. The lost circulation and the diluted mud system may have reduced cuttings evacuation from the bit face, resulting in bit balling and compromising the ROP.

The relative position of the target with respect to the surface location and strict total vertical depth tolerances meant a demanding wellbore trajectory. This required the bit to deliver the necessary DLS capability with less steering force to minimize wear and general degradation of the RSS.

Over all, the operator required a new approach to overcome issues with BHA dynamics, drilling dynamics, stick-slip, bit stability, lost circulation, difficult trajectory, and bit balling.

Application analysis

The directional drilling service provider and drill bit provider initiated a BHA design and bit review to resolve the damaging dynamic stability issues. A complete analysis of the BHA stress and critical speed was performed using the service company’s proprietary software.

Rock strength analysis of offset wells revealed the average unconfined compressive strength (UCS) values are relatively low, generally less than 5,000 psi (34.7 mPa). However, UCS peaks of approximately 17,000 psi (117.2 mPa) were documented while drilling the curve section in the interbedded alternations formation.

Between the alternations and the lower zone, there were fluctuations in UCS that suggested the bit would have to drill and remain in stable mode through these formations of changing hardness.

The operator worked closely with the service company’s bit division to solve the vibration challenges using of a proprietary design process. This process improves communication, reduces costly and time-consuming iterations, and maximizes the ultimate solution. It focuses on the complex interdisciplinary downhole dynamics critical to increasing directional RSS-PDC drilling efficiency.

With this information, the bit manufacturer’s design engineers created a more stable PDC bit body using a proprietary modeling program to accurately predict stability and dynamic loading.

The new-style PDC bit included:

• Depth-of-cut control technology that reduces aggressiveness by decreasing cutter exposure
• A proprietary gauge that improves bit steerability with less steering force for a given DLS, improving the RSS tool life and run length
• Hydraulics optimization based on computational fluid dynamics to ensure the best balance between fluid flow and cutter cooling while reducing bit body erosion.

Service company engineers also decided to increase the relative stiffness of the BHA gradually for improved transmission of the torsional energy to the bit.

Increased efficiency

On the next well, the operator implemented the recommendations for the 8 1/2-in. (21.6 cm) section, which included the enhanced BHA and the newly designed Genesis 8 1/2-in. HCR605 rotary steerable bit with EZSteer depth-of-cut control technology. In the upper section, the operator encountered torsional drilling dysfunctions that were effectively controlled by managing the drilling parameters. As drilling progressed, there were minimal signs of lateral vibration and stick-slip.

When comparing the dysfunction levels of a previous well with the current well there was a significant decrease in stick-slip. The reduced vibration resulted in zero downhole tool/BHA failures. There was increased ROP, and the entire 1,264-m (4,145-ft), 8 1/2-in. (21.6-cm) section was completed in a single BHA run.

The two wells drilled with the RSS and the newly designed BHA resulted in performance improvement as a result of the new-style PDC bit with depth-of-cut control technology.

Drilling record

Several multilateral wells have been drilled since May 2004. Because of the initial performance improvement, all of the 8 1/2-in. (21.6-cm) sections have been drilled using the PDC bit with depth-of-cut control technology.

Recently, the Genesis PDC bit set a national record in India for the longest 8 1/2-in. section, drilling 3,936 m (12,913 ft) of hole in a single run while placing all three lateral wellbores in the proper position.