The bit-rock interaction has long been studied to assess PDC drill bit performance, which is driven both by cutting and non-cutting parts of the drill bit. While the cutter-rock interaction has been studied by many authors in the literature, only a few studies have focused on the interaction between the rock and non-cutting parts of the drill bit. In this paper, we introduce a new method designed to model the interaction between the whole drill bit and the rock formation within a full three-dimensional framework. This approach is based on a generic computational geometry algorithm which simulates the drilling process considering both the drill bit and the hole being drilled as a set of 3D meshed surfaces. The volume of rock removed by the PDC cutters as well as the area and the volume of contact between the rock and the non-cutting parts of the drill bit can be computed with a high accuracy based on the 3D CAD model of the drill bit. The in-house drill bit simulator implementing this algorithm primarily allows the engineer to estimate how bit-rock interactions distribute between cutting and non-cutting parts of the drill bit and to balance the bit design in the 3D space accordingly over a given range of drilling parameters. This approach has been brought to the field in order to address cutter breakage based on rubbing contacts optimization. Field results associated to some case studies in US shale plays and Canada are described and clearly show that contact points predictions closely match field observations. Moreover, design modifications applied following this process have led to an overall increase in bit performance and bit durability while preventing core-out issues. The bit design methodology presented in this paper is dedicated to design drill bits whose interaction with the rock formation is predicted with a higher accuracy by accounting for the exact 3D shape of the drill bit.

Hydraulics can significantly affect Polycrystalline Diamond Compact (PDC) bit performance in applications where cuttings volume, formation types, and rig pressure limitations lead to poor fluid dynamics that compromise cleaning and cooling, and result in lower ROP and higher bit wear. A key mitigation challenge is improving cleaning efficiency without experiencing a significant pressure drop across the bit. This paper studies hydraulic conditions affecting PDC bit performance, examines modeling and design steps to develop a curved nozzle design, and presents the nozzle's performance in the field. Research including computational fluid dynamics (CFD) modeling was conducted to better understand flow and velocity across the bit face. The resulting curved nozzle geometry was complex and required multiple iterations to achieve the desired effect. The nozzle design was applied in the field and its performance was compared to similar PDC bits with standard nozzles. The curved nozzle design redirects fluid flow and reduces distance from the nozzle outlet to cutting face while retaining the same total flow area (TFA). The change in flow characteristics increases fluid impact on the formation and velocity in the waterways to enhance cleaning efficiency and cooling. The carbide nozzles were manufactured and installed on standard PDC bits used in a series of Permian Basin vertical and lateral wells in the United States. Vertical applications in Canada's Viewfield field were also studied. Bits fitted with the curved nozzles demonstrated significant performance gains compared to bits with conventional nozzles. Field reports show higher ROP and less bit wear in formations where interbedded clays and reactive shales present hydraulic challenges. The insights gained into PDC bit hydraulics and the performance of the resulting curved nozzle design has enhanced the ability to mitigate many common hydraulics-related cleaning and cooling challenges.

A specially designed diamond impregnated bit set new performance records in its initial application in a hard, abrasive Oman formation. Built for turbine drilling in the formation's sandstone-siltstones-shale, the 212.72-mm (8 3/8-in) bit drilled 588 m (1929 ft) in a single run, increasing footage drilled by 14% compared to the previous-best 8 3/8-in. run with a ROP of 2.02 m/hr (6.6 ft/hr). This performance replaced 2.7 bits through increased footage drilled and drill out capabilities. When the bit was pulled due to the BHA it was dull-graded: 3-2-WT-A-X-1-LM-BHA. The bit developed for the Oman run was a matrix body with 16 blades. Maximum durability and performance in the high-compressive strength formation was addressed with diamond-impregnated blocks on each blade and thermo/abrasion resistant PDC cutters in the bit center. Extreme drilling conditions presented by the turbine application and formation led to an optimized impregnated segment block geometry to maximize bit durability without impacting efficiency, and a change in hydraulics to maximize cooling and cleaning of the cutting faces. This paper is the first published examination of the diamond impregnated bit design process and resulting field experience in the Oman application. The study discusses the basis of the bit design and considerations in achieving operator objectives, including drilling as much footage as possible from 4190 m (13,743 ft) measured depth, while maintaining an average ROP of 2 to 2.5 m/hr (6.5 to 8.2 ft/hr). The authors examine the role of modeling and design software in optimizing durability and penetration rate in the hard formation, and they review enabling manufacturing and material advances.

Torsional vibrations are a very common phenomenon affecting drilling operations by limiting efficiency, increasing the risk of downhole equipment failure and generating additional costs, particularly when their most severe form is encountered, the stick-slip. It is less known that torsional vibrations also strongly affect directional drilling operations reducing directional stability and tool face control. In this paper, the highly variable solicitation induced by torsional vibrations is addressed with a statistical approach. This approach, used successfully in Kuwait applications, resulted in an operational savings of 30% of the cost per foot over a panel of more than 15 runs analyzed. Steerability and directional stability is critical on directional wells, especially when using push-the-bit systems with PDC bit due to side force distributed unevenly over one bit revolution. Most of today bit design comparisons are made with an average steerability factor computed over one full revolution of the bit. The method described in this paper is going further in details and looks at the evolution of directional performance indicators within one bit revolution. With the help of a state-of-the-art 3D bit-rock interaction model, which simulates the drilling environment considering the drive system mechanism and both the drill bit and the hole being drilled as a set of 3D meshed surfaces, an accurate picture of the directional stability of the bit design is available. This approach is complemented by a statistical analysis which allows to simulate a multitude of input parameters combinations and to map the directional response of a bit design in a more robust way. Based on the results of the statistical analysis, an optimized design was selected and manufactured for a 12 ¼’-in. rotary steerable system (RSS) directional application known for having torsional vibration limitations. As revealed by the simulation results, this design was expected to exhibit a better directional stability than previous bit design iterations. This optimized design was run on RSS and positive displacement motor (PDM) assemblies and successfully drilled several wells in different fields of Kuwait operations ground. It experienced smooth and stable directional control while reducing the risk for torsional vibrations and resulted in tremendous reduction of the overall cost per foot. PDC bit selection and design process have considerably evolved in the last decade with the use of increasingly accurate simulations models. This paper presents the next step of evolution dedicated to delivering the best adapted solution to any given scenario by examining in greater detail the directional response of a drill bit.

Drilling into harsh environment with heterogeneous formations including chert or conglomerate is usually a boundary that can't be crossed with standard PDC bit technology. This paper will show how an innovative PDC cutter shape combined with a novel 3D approach of cutting structure design have withstood this challenge and successfully replaced 16-in. traditional roller cone application in United Arab Emirates by the latest PDC technology delivering an average 35% improvement on Rate Of Penetration (ROP) while continuously drilling to Total Depth (TD) on each section. When drilling chert or conglomerate type of formation with a PDC drill bit, uneven load per cutters is detrimental to their integrity and results in short runs or brutal stop in the drilling operation triggering a trip for drill bit change. The new technology shown in this paper includes a unique hybrid combination of cutter shapes with a design arrangement of the cutting structure to allow for the pre-fracturing of any hard formation heterogeneity by 3D shaped cutters while standard cutters ensure a high level of cutting efficiency through their shearing action. This innovative concept has been intensively tested in the lab through single cutter and full bit scale drilling testing. In addition, in-house 3D bit simulation software has been used to optimize the cutting structure and assure performance within a wide range of drilling scenarios. Based on these simulations, an optimized design was manufactured for 16-in. directional applications usually tackled by roller cone drill bits and known for having heterogeneous cherty formations to drill throughout the end of the 5,000 ft section. Simulation results helped to validate the unique shaped cutters placement on the cutting structure to maximize the pre-fracturing effect. This design was run on Rotary Steerable System (RSS) and Positive Displacement Motor (PDM) assemblies and successfully drilled 5 wells in a challenging field of the United Arab Emirates offshore operations. 100% successful rate to reach TD in one run was achieved while increasing drastically the average ROP of the section by at least 35%. Moreover, the unique design configuration allowed to better control the directional behavior of the drill string, which resulted in a significant reduction in the overall cost per foot. A new boundary has been breached in several wells of a complex 16-in. chert and conglomerate application in the United Arab Emirates thanks to a years-long effort combining an innovative cutter technology, an optimized bit design process including a state-of-the-art 3D simulation software with lab and field experimental testing campaigns. By looking at the micro level structure of the rock destruction mechanism, a huge improvement has been obtained at the macro level of drilling operation economics.