This paper will discuss the deployment of the concentric dual diameter fixed cutter bit technology which was introduced in January 2015. The bit was deployed and tested several times in a tangent, directional application and J-shap wells in Burgan Field, South of Kuwait and achieved the fastest penetration rate in the application. The concentric dual diameter bit is composed of a smaller pilot and a larger reamer section, where the reamer section dictates the final drill size. Conventional fixed cutter bits take very little advantage of stress relieving the rock, as it only affects the borehole wall. Concentric dual diameter technology bits are able to initially drill with a leading smaller pilot section efficiently to relieve the stress of the rocks. Subsequently, the reamer section removes the stress-relieved rock with lower mechanical specific energy compared to regular fixed cutter bits, giving it the advantage to generate higher penetration rates. Another advantage of the concentric dual diameter technology bits is the stability of the bit, since two gauge sections are available to be in constant contact with the borehole while drilling. The first 12 ¼ in. concentric dual diameter technology bit in conjunction with directional 8¼ in. PDM (0.16 R/G, 7/8 lobes, 4 stages, 1.5 BH) BHA was tested in a directional application J-Shape well in Burgan Field, South of Kuwait. The bit was able to deliver improved performance by drilling the tangent section from 4345 ft to 6019 ft from Ahmadi to Burgan formation, total 1674 ft in 17 hrs with 98.4 ft/hr. The bit showed excellent steerability, building from 39 deg to 43 deg with 3 deg/100 ft max DLG severity. The section lithology consists mainly of Shale, Limestone & Sandstone. The performance capability was confirmed when the second bit run in conjunction with directional 8¼ in. PDM (0.16 R/G, 7/8 lobes, 4 stages, 1.5 BH) BHA was tested in a directional application S-Shape well in Burgan Field, South of Kuwait. The bit was able to deliver improved performance by drilling the dropping section total 940 ft from Ahmadi to Burgan formation. The bit showed excellent steerability, dropping from 15 deg to 0 deg with 3 deg/100 ft max DLG severity. The section lithology consists mainly of Shale, Limestone & Sandstone. The 12 ¼ in. concentric dual diameter was able to surpass the average rate of penetration for the same application in the Burgan Field by 56% saving the operator drilling time and making the concentric dual diameter bit design the top performing drill bit in the field.

Wellbore instability while drilling mechanically weak, unstable or vugular formations has been a problem for decades. The cost of wellbore instability is a major challenge in achieving safe and economical drilling operations. As drilling operations moved into challenging formations in Kuwait, the operator sought to drill the Burgan shale and Shuaiba limestone formations in one section as opposed to the traditional two sections required to isolate each formation separately. This paper focuses on a class of technology additives used to mitigate the challenges of drilling weak and unstable formations. One approach for drilling micro-fractured shale and weak sands with vugular limestone is to mitigate the invasion of drilling fluids into the formation. Other approaches include: stabilizing the reactive shale by preventing hydration and swelling, improving the filtercake texture and strength, and sealing natural micro-fractures. Drilling fluid invasion can change the pore pressure, which may trigger wellbore instability problems. Thus, using ultra-low invasion drilling fluids, sealing micro-fractures and maximizing shale inhibition are key components for mitigating wellbore instability. Field data for the wells using the ultra-low invasion additives and shale stabilizers is presented and compared with previous wells drilled across Burgan and Shuaiba formations in Kuwait. The field data demonstrates the successful application of these additives to meet challenging key performance indicators (KPI) when drilling the Burgan shale and the vugular Shuaiba limestone in the same hole section. Using the ultra-low invasion additives along with shale inhibitors and borehole stabilizers, resulted in successful drilling operations with no differential sticking, torque-and-drag issues, sloughing, or tight hole problems as compared with usual incidences of differential sticking, pack-offs, and tight hole in other wells within the area. Using those additives also eliminated the need for a higher density fluid to control micro-fractured and tectonically stressed shales. The addition of the additive combination did not affect the rheological profile of the drilling fluid. Meeting these goals through the use of chemical additives in the drilling fluid reduced both non-productive time and formation damage in a cost-effective manner. Data from this paper specifically addresses a chemical solution for drilling the Burgan shale formation together with vugular Shuaiba limestone in a major Middle East producing field. However, the technique of mitigating wellbore instability by using this combination of chemical additives is fundamental to safe and economical drilling operations for any depleted, weak or micro-fractured formations globally.

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.

The Automated Drilling Director, a software application for drilling automation, integrates a physics-based model of the drilling system with machine learning and optimization algorithms to project the well path, monitor collision risk, manage vibrations, and control steering in real time automatically. With "intelligent" rotary steerable systems (RSSs), these steering decisions can be downlinked directly to the tool, thus, fully closing the loop around steering decision-making. Implementation of the Automated Drilling Director within a remote drilling center (RDC) enables the drilling operations to be conducted remotely and effectively with less rig site personnel. The resulting decisions are consistent and reliable, while a team of subject matter experts (SMEs) monitor the operations to optimize well assets, ensuring that the pre-job design of service (DoS) is executed properly. The validation of this innovative technology and approach in Kuwait, amongst others, opens the door to a new way of doing business, where resources, experience, and data are combined in the most efficient manner to improve consistency, as well as to maximize the value of the operators’ assets.

A 16-in. section of a well, located in the Great Burgan field of southeastern Kuwait, presents multiple drilling challenges. The section is approximately 4,000 to 5,000 ft long and is drilled through a highly interbedded formation that consists of carbonate, shale, and anhydrite. The carbonate typically generates impact damage, causing high levels of thermal degradation that affect the gauge inserts. In addition, lost circulation is a hazard commonly encountered during this application. The drilling of this section requires control of drilling parameters, specifically the flow rate. Failure to maintain sufficient flow rate results in poor cuttings transmission and insufficient cutting structure cooling that can create further performance complications. The challenge in this application is to drill the entire section with one bit run at a maximum rate of penetration (ROP). This paper describes a new tungsten carbide insert (TCI) drill bit design that helped to improve the drilling performance in this challenging section in different well profiles. This paper provides a detailed study of the challenging 16-in. section in Kuwait and discusses potential issues, problems, and solutions associated with the use of the new advanced roller cone design.