A polycrystalline diamond compact (PDC) bit was used to drill a northern Kuwait well. The typical casing design for this field calls for the 16-in. section to be the longest section in the well, which extended from 1,230 ft to 6,000 ft for a total of 4,770 ft in this particular well. The formations drilled in this section were mainly comprised of carbonates interbedded with shale. The first 2,000 ft of the section was highly interbedded with hard and soft layers of carbonates with the unconfined compressive strength ranging from 6,000 psi to 30,000 psi. Additionally, the remainder of the section had hard stringers with unconfined compressive strength up to 30,000 psi. Such highly varying and highly interbedded formations tend to damage the PDC cutters because they are more susceptible to impact damage. For this reason, roller cone bits with tungsten carbide inserts (TCI) are preferred and are typically run in this section. However, the rate of penetration (ROP) significantly decreases when the TCI bits drill through the hard formations. For this reason, the operator and service provider established an objective to design a PDC cutting structure that would efficiently drill through the hard interbedded formations and complete the section in one run, achieving higher ROP than was achieved with the TCI bits in the offset wells.
Based on the formation strength information available, the decision was made to initially use a 6-bladed 16-mm cutter. The service provider then recommended using conical diamond elements (CDEs) and placing them behind the primary PDC cutting structure. The conical shape of the CDEs penetrate the high-compressive-strength rock, effectively weakening the formation with a plowing mechanism. Furthermore, the CDEs also protect the PDC cutting element from impact damage. A high-performance motor was also recommended to reduce stick-slip. A finite element analysis (FEA)-based modeling system was used to comprehend the dynamic behavior of the bit and bottomhole assembly (BHA) design. The most efficient bit design was selected, and changes in the BHA were recommended to deliver the most stable and optimized drilling system. A detailed drilling parameters sensitivity analysis was performed, and a driller's parameter plan was prepared to provide enhanced drilling parameters for mitigating downhole vibrations.
As a result, the CDE bit drilled the entire section, achieving an increase in on-bottom ROP by 24%. In the hard formation—where the ROP of TCI bits would typically decrease—the CDE bit drilled at twice the normal ROP.
The CDE bit technology proved to be efficient in what was previously thought to be a roller cone application. By reducing the drilling hours needed to complete the entire 16-in. section, the CDE bit saved the operator 3.5 days of equivalent drilling time.