With an objective to shorten directional intervals, operators place greater demand on higher Build Up Rates (BURs). The section just before the pay zone involves the most intensive directional work, pushing rotary steerable systems to their capability limits. This paper focuses on a particular interval of hard and soft interbedded carbonates that provides a significant challenge for conventional Polycrystalline Diamond Compact (PDC) bits to provide consistent build up rate and good borehole quality on rotary steerable systems. Throughout this paper we demonstrate the engineering process of designing a bit to increase buildup rate capabilities of rotary steerable systems and improving drilling efficiency through interbedded carbonate formations. The engineering process involved reviewing the critical issues of this application to assure a sound solution. This included: Current build up rates versus Rotary Steerable Systems (RSS) steering capability. Vibrations generated by conventional PDC bits being deployed in the field. Specific cutting structure, depth of cut limiters and gauge requirements for different RSS drive types. Formation strength analysis. Parameters used in drilling the section. Roller cone insert and PDC interaction of the hybrid bit with the formation and how formation deformation generated by one interacts with the other. Roller cone insert design aimed specifically at carbonate formation drilling Various hybrid drill bit and Bottom Hole Assembly (BHA) combinations were evaluated with state-of-the-art drilling response simulator to review the buildup rate capabilities combines with the bit and BHA interaction. The best combination was then successfully trialed on several wells, proving significant improvement compared to current performance with conventional PDC bits. The optimized hybrid bit and BHA combination eliminated drilling vibrations in intervals where extreme vibrations were witnessed with conventional PDC bits, significantly increasing drilling efficiency. Improved torsional stability reduced the load on the directional tools improving the ability to achieve the required doglegs. In softer shale where RSS with conventional PDC's had to control parameters while using maximum steer force to achieve target dog legs of 7°/100ft, the hybrid drill bit achieved 10°/100ft while utilizing only 70% of the steer force. The hybrid drill bit has been proven to be successful with both push-the-bit and point-the-bit RSS systems. Hybrid drill bits have proven to be a solution to problems and limitations of both conventional PDC and roller cone bits in directional drilling. Based on recent refinements in the drilling mechanics of hybrid drill bits to further improve their interaction with directional drilling systems, engineering selected this emerging technology to overcome the challenges in this particular application.

In the prolific Burgan field, South East Kuwait, new well profiles are being employed which require the 16 inch hole section to be drilled deeper. This new well profile requires drilling through interbedded abrasive sandstones and sticky shale which were previously drilled in 12 ¼ inch hole size. Drilling becomes increasingly challenging using larger diameter bits where torque fluctuations, down-hole conditions and durability limit performance. As the casing profiles changed, each section's drilling solution was revisited as drilling dynamics and performance diminished drastically when drilled in the larger hole size. What was once a viable solution to drill the section in 12 ¼ inch becomes no longer suitable when drilled in 16 inch. The purpose of this paper is to demonstrate the engineering analysis for large diameter hole application and the selection of an optimized hybrid drill bit design, roller cone combined with Polycrystalline Diamond Compact (PDC), to maximize drilling performance where standard PDC or roller cone bits alone fail to provide an optimal solution. The 12 ¼ inch section was typically drilled using a rotary bottom hole assembly with a roller cone bit or using a performance mud motor with a PDC bit. Drilling parameters were reduced in the upper layers especially with PDC bits as they involve sticky shale which can induce bit balling. While in the lower layers the abrasive formations tend to wear down roller cone bits. Combining the benefits of both bit types, a 16 inch hybrid bit was proposed to answer the challenge of drilling the section as fast as a PDC bit while providing the stability, torque control and smooth hole condition generated by a roller cone. Selecting an appropriate hybrid design to match the application resulted in an initial trial of a durable hybrid bit that finished the interval with virtually no wear on the bit and significantly improved borehole quality. The second trial of the hybrid bit with a modified, more aggressive design approximately doubled the ROP of a PDC bit while maintaining a smooth hole profile and minimizing torque. PDC bits generally provide faster rate of penetration than roller cone bits while generating higher torque fluctuations as they drill by shearing bottom hole formation. Due to their high torque demands, PDC bits require an additional mud motor to drive them efficiently in larger hole sizes. Roller cones crush and gouge the bottom hole formation and due to their mechanical rollers result in reduced reactive torque and a smoother hole profile. Hybrid drill bit technology proven the capability of achieving the benefits of both designs in specific selected applications.

In Kuwait's largest reservoir, the Burgan Field, exploration wells have large potential for drilling optimization and savings; specifically a 22 inch hole, that is drilled conventionally using multiple roller cone bits in multiple trips through challenging inter-bedded formations. Hybrid drill bit technology, roller cone combined with Polycrystalline Diamond Compact, was introduced in search for an economically viable solution to deliver wells faster and achieve yearly operator targets. This paper analyzes the breakthrough drilling performance achieved by a 22 inch hybrid bit in comparison to conventional roller cones offsets and provides conclusions on economic viability. The main challenges drilling the 22 inch section are drill bit durability and drilling vibrations through inter-bedded formation layers of limestone, shale and sandstone. In addition to curing fluid losses in certain porous formations that negatively affect Rate Of Penetration (ROP). Typically two roller cone bits are used on rotary drive to drill this section at 15 feet per hour, consuming seven drilling days. Using Polycrystalline Diamond Compact (PDC) bit with a performance motor to increase ROP performance is not an economically viable solution. Using hybrid drill bit on rotary drive combines the benefits of PDC blades' durability and higher cutting efficiency with the cones' stability by grinding and gouging into the formation. The deployment of the hybrid technology was a collaboration project between a national oil company and a major oil services company. The teams focused on optimizing the complete drilling system including the bottom hole assembly, hydraulics, drilling parameters and geological factors to match the hybrid drill bit mechanism. The hybrid design selection and drilling optimization resulted in a 142-percent ROP improvement from offsets average performance. The hybrid designs consistently drilled the 22 inch hole after casing shoe to section total depth at 31 feet per hour, using one bit, in three drilling days in comparison to seven days average performance. The total operator savings from e section was approximately USD 175,000 in the first deployment. The second and third deployments established performance consistency. Such remarkable economical savings and technical optimization proved that the hybrid technology is the viable solution for two prolific exploration applications.

In the prolific North Kuwait field, the 16 inch intermediate vertical section is typically drilled with Tungesten Carbide Insert (TCI) drill bit [445 IADC] and rotary assembly. The TCI average Rate of Penetration (ROP), through approximately 4,800 feet of limestone, sandstone and shale, is 38.7 feet per hour. Given the operator's target to reduce drilling time and minimize the North Kuwait well cycles; the hybrid drill bit was proposed to raise ROP performance and save drilling days per well. The main challenge was to significantly reduce drilling time and enhance the cost-per-foot of the application with the new hybrid drill bit. In addition to providing smooth torque fluctuations, similar to that of the roller cones drill bit. A specialized Drilling Application Review Team (DART) from the service provider implemented an optimization process to achieve the aforementioned targets. The hybrid bit design has been revised and upgraded to best-fit the interbedded carbonates application. Bottom Hole Assembly has been modeled and optimized by the cross-functional engineering team and the client to ensure best torque response while drilling. Moreover, a detailed formation drilling analysis has been conducted to accurately anticipate hybrid bit ideal case. The optimized hybrid drill bit set the highest ROP record, at 80 feet per hour in North Kuwait achieving 107 percent improvement from offsets’ average performance. Moreover, the optimized design delivered 2 and a half days savings when compared to field offsets by conventional technology. The selected system generated smooth torque response and hence high energy efficiency. This success has been repeated over multiple wells in North Kuwait project; proving consistency in technology value.

In the current challenging global oil and gas market, operators strive to minimize cost-per-foot (CPF) through drilling optimization and the introduction of next-generation tools to maximize return-on-investment. In response, service companies seek game-changing solutions to enhance operators' drilling operations. A cross-functional optimization team was chartered to enhance rate of penetration (ROP) in development drilling Kuwait's prolific Burgan field. The team developed a polycrystalline diamond compact (PDC) drill bit design with 25mm (1 in.) PDC cutters –presently the largest diameter commercial cutter in the industry. This paper presents the outstanding field results that were achieved with the 25mm cutter bit design. The analytical and experimental processes used in the development of the bit design will be described, and the operational results and resulting savings will be presented and compared to the established field benchmark. The geology of the 12¼ in. intermediate sections of Burgan wells is comprised of layered carbonates, shales and sandstones. The section is known to induce moderate-to-severe torsional vibrations with conventional rotary bottomhole assemblies through the heterogeneous formations. Operational practices to mitigate these vibrations effectively limit the section ROP. To address this challenge, an optimization process was initiated to manage the problematic vibrations and maximize drilling efficiency through bit design and cutter technology. In an application that was long dominated by conventional PDC bit designs with 19mm cutters, an upgraded 25mm cutter with the latest HP/HT pressing technologies incorporated in a tailored bit design to strike a balance between drilling aggressiveness and vibration control. The large cutter's unique depth-of-cut potential and increased cutter exposure were combined with reduced bit imbalance and degree of rubbing via numerous computerized simulations as part of the analysis for the Burgan application. The 25mm cutters were lab-tested and video-recorded on a dedicated laboratory rock mill to evaluate the ROP potential and apply these concepts to the 25mm cutter bit design. After the experimental bit was manufactured and performance tested in a controlled laboratory environment, the engineering team focused closely on the successful execution of the preliminary field trials, and then evaluated the results. Deployment of the engineered 25mm cutter bit design led to multiple breakthrough performances in consecutive bit runs, achieving 300%+ increased ROP on each deployment compared to the established 12¼ in. field average. Analysis of the drilling logs indicates the engineered bit design provided the highest drilling efficiency to date in comparison to all conventional PDC bits previously run in this application. Torsional variations were limited through the interbedded formations, which allowed drilling parameters to be optimized throughout the runs. As a result, the operator reduced rotating hours by 70% vs. the field benchmark, with a corresponding 30%+ reduction in CPF.