Access to develop new drill bit technologies are increasing the capabilities to improve performance in the most challenging directional applications, where the focus is to reduce any type of disfunctions that will be generated due to the interaction between the drill bit, drill string and formation compressive strength. A case study is presented to demonstrate the liability and consistency of this new technology. This paper discusses the sensing at the bit technology that has different capabilities that can be used to improve drilling performance, combining the new cutting structure in the drill bit that keeps in series the shearing and breaking actions generated by the new cutting elements, at the same time those actions are recorded by the drill bit sensor. The generated information is used to compare standard drill bits with modified designs where the advantages can be seen clearly, and at the same time new engineered technologies can be put in place to have further improvements in performance. In Kuwait, the 12 ¼" section is a challenging application in terms of directional requirements, rate of penetration and is mandatory to have the necessary stability to be able to increase the required drilling parameters that will end up with outstanding performances. A compressive engineering analysis of a customized drill bit and the implementation of the sensing at the bit data capture was used to understand the drilling parameters, drilling disfunctions and the interaction between the engineered cutting structure and the formations drilled. The data was correlated with available data from offset wells and helped to confirm the performances achieved. The detection of different disfunctions and the frequency generated for the added device was the key to understand the functionality of the tool. It showed that the new technology drill bit, in which a rolling crush-and-shear cone is incorporated to the center of a PDC bit, increases bit stability and mitigates lateral vibration while achieving outstanding performance.

Deep gas drilling the early Devonian unconformity in Oman is an extremely challenging hard and abrasive application fraught with a diverse set of PDC drill bit challenges and objectives, particularly in the 8 3/8″ vertical section where between 2 to 4 fixed cutter drill bits can be necessary to reach total depth. Each trip can significantly impact well construction cost and delay production on stream dates. Using high frequency digital data collected at the drill bit and detailed forensic analysis of drill bit photographs a new, physics based, drilling equipment and parameter strategy was developed. The section requires drilling approximately 2,000m of hard and abrasive interbedded Sandstone and Shale formations to around 5,000m vertical depth. Drilling performance is typically limited by severe wear to the PDC cutting structure or motor failure from significant torsional and lateral vibrations. High frequency digital data was captured at the bit in conjunction with output data from an automated photometric dull grading system over several wells to identify dysfunction type. The results were then analyzed by vendor and operator SMEs collaboratively to optimize drilling parameter performance and provide insights into optimal cutter shape and grade selection to further reduce drilling dysfunction. Using downhole high frequency digital readings to understand down hole vibrations and the impact of formation interaction on bit dull has led to changes in the cutting structure and the applied drilling strategy. Different drilling approaches were applied to each formation layer to manage interbedded transitions as well as to increase depth of cut for improved drill bit dynamic stability. Insights were derived from an automated dull grading system assisted in optimizing cutter shape and grade selection in the select parts of the drill bit cutting structure. The photometric analysis also helped refine drilling parameters for a more efficient drilling by increasing axial loading on hard formations that then resulted in increased ROP. Additionally, newly developed high abrasion resistant cutters placed optimally in the drill bit at the highest work locations based on automated dull grading feedback resulted in extended cutter life helping to keep the bit sharp and maintain the high rate of penetration through the various layers reaching final section depth with consistently high rate of penetration. The execution of the new physics-based drilling strategy has resulted in improved bit dull grade conditions which helped reaching the section final depth in one run with reduced downhole dysfunctions. that resulted in a section drilled without trips and with reduced well construction costs. The section is 32% faster than the offsets and was drilled 7 days earlier compared to plan.

In the mature fields in Norway's North Sea, extended-reach drilling (ERD) well designs were implemented to reach distant reservoir target zones. Resulting from this change, the 12.25-in. overburden section, which drills through mostly shale with various hard and thin dolomitic limestone sections, had to be modified from a 5,000- to 7,000-ft vertical section to a 10,000- to 12,000-ft section at a tangent inclination anywhere from 35 to 70°. Drill-bit designs that used to drill the vertical overburden section consistently in one run currently require up to three bits to complete the modified tangent sections caused by excessive damage to the diamond cutting structure. An extensive study into the offset ERD wells and corresponding bit dull conditions helped identify that the cutting structure damage originated from high-point load impacts to the shoulder of the bit while transitioning through the thin, hard dolomitic limestone formations; the damaged cutters were being tangentially overloaded. Through further bit modifications, it was determined that this type of damage could not be addressed using typical bit design modifications (e.g., increased cutter density, increased blade count, etc.); therefore, a unique design solution was developed and implemented. This solution involved combining analytical simulations and a dull condition analysis to develop an improved method for using the backup cutting structure to support the high tangential loading on the primary cutting structure during hard, high-inclination transitions. In most dual-row cutting structure designs, the backup cutters are on the same radial position as their parent primary cutters and are underexposed, engaging the formation only at a specific depth of cut or after the primary cutters are worn down a certain amount. When positioned as such, the backup cutters do nothing to support the tangential loading on the primary cutters. By moving the backup cutters actively on profile with the primary cutters and offsetting them to their own radial positions, the backups could now actively support the high tangential loads occurring on the primary cutters when engaging the hard dolomitic limestone. This simple but unique modification enabled the bit to handle the transitions and drill the entire next 11,000-ft+ ERD section in one run while also providing the fastest rate of penetration (ROP) to date, with an increase ranging from 30 to 40% compared to previous runs. The success has been repeated a dozen more times since, each time providing a new record ROP for an ERD section. The improved dull condition could also allow for more efficient designs in the future for further improvements to drilling performance. The successful reduction of tangential impact damage could have implications for various bit designs globally that incur a similar dull condition.

The 9 1/4-in. polycrystalline diamond compact (PDC) bit is a unique size necessary for long-interval deep-drilling casing programs in Kuwait. Drilling the section is a major challenge because the long interval consists of nonuniform lithology with variations in compressive strengths, and it contains an abrasive ultra-hard sandstone, a compact hard shale with a low rate of penetration (ROP) performance, and carbonates with shale, oolite, and sand traces. The interval is commonly drilled using either two or three new PDC bits, and extra trips are expected. Efforts were made to substitute the numerous PDC bit runs with one customized and reliable design that can overcome formation hardness and variations in compressive strength and maintain the same ROP to total depth (TD) with limited success, even though the idea of backup cutters has existed for decades. A new, durable PDC design was implemented with the objective of helping improve the ROPs across all intervals. The innovative backup cutter placement design and minimal critical depth of cut for each primary and backup cutter in the same radial position are the most desirable solutions. The new and innovative PDC cutters’ distribution structure using the new bit design software coupled with an innovative backup cutter placement minimized the calculated bit wear and maintained the cutters’ sharpness along the entire section without needing an extra trip or a new second bit, which produced the best performance achieved in the northwestern Kuwait fields. The new bit design achieved the longest footage drilled in Kuwait for a single bit of 9 1/4-in. size with a competitive ROP compared to previous cases. The used bit came out of the well in excellent condition with minimal normal wear. A case study of an innovative PDC cutting structure layout using the new PDC bit design with efficient backup cutter placement, bit formation interaction modeled to help predict cutting structure wear, and advanced rock mechanics analysis are discussed. The new backup cutters’ layout procedure extended bit life without sacrificing ROP.