Diamond Bit Handling and Operation

Distinguished Author Series articles are general, descriptiverepresentations that summarize the state of the art in an area of technology bydescribing recent developments for readers who are not specialists in thetopics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and presentspecific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleumengineering. Summary. Part 1 (June JPT, Pages 675–84) discussed the characteristics, development, and outlook for polycrystalline diamond compact (PDC) bits. Thissecond part treats applications of PDC bits, including suitable locations, types of hole, and uses. Introduction This paper is intended as a quick reference for operational staff who may beconsidering the application of PDC bits. Unfortunately, these bits cannot yetcope with all formations. Consequently, bit selection is of paramountimportance to avoid misruns, as will be indicated. Suitable Formations PDC bits usually can be used with success only in soft, soft to PDC bitsusually can be used with success only in soft, soft to medium-hard, andmedium-hard, non-abrasive formations. Success, however, is fully dependent on agood match between the bit, the formation to be drilled, and the operatingconditions. (See PDC-Bit Development in Part 1, where performance of thecorrect PDC bits with both oil- and performance of the correct PDC bits withboth oil- and water-based muds is explained.) Experience has shown that, forPDC bits, the type of mud, the bit hydraulics, and bit design PDC bits, thetype of mud, the bit hydraulics, and bit design affect bit performance muchmore than variations in mud properties. Over and over again, it has been foundthat it properties. Over and over again, it has been found that it pays todevelop the best bit design for a particular field rather pays to develop thebest bit design for a particular field rather than to select one from a range.PDC bits can be tailored to the job to provide surprisingly goodperformance. Hard and/or abrasive formations are taboo for PDC bits in that they causeexcessive wear. Streaks of limited extent, lenses, or thin sections of suchrocks within thick sections of a suitable formation can be drilled. It isimperative to consult wireline logs, mud logs, and bit records of neighboringwells. With local expertise at hand, available from bit suppliers and withinthe oil company, it is then decided where to spot the bits, if at all. Refs. 1through 3 and 5 through 15 provide detailed examples of recent case histories. Mudstone and siltstone have been drilled well; sandstones, particularly ifcoarse-grained and cemented, are virtually impossible to drill economically andare highly destructive to the bit. Hard limestone, dolomite, etc., can be cutwith great difficulty. Consult PDC Cutters in Part 1 for an understanding, Sections on TSP Diamond Bits and Hybrid Bits, also in Part 1, provideassistance in seeking alternative bits. Applications PDC bits may play a significant role in a number of drilling PDC bits mayplay a significant role in a number of drilling related applications ashighlighted here. A wealth of referenced literature is available to elaborateon the various aspects. Depleted Reservoirs. Because such reservoirs usually cannot be drilled at areasonable overbalance, the drilling may become extremely slow and costly. Inthe case of roller-cone bits, the common excessive overbalance causes them tocrush the rock to a very thick, dense layer that is hardly removed at all. Diamond bits can often do better because of their plowing action. PDC bitsshave the rock and expose the permeable rock to mud filtration, which can bepromoted by hydraulics to lessen the effective overbalance. Koskie and Appenreport a side benefit of "fishtail" PDC bits in Colombia: their ability todrill depleted sands rapidly at an overbalance of as much as 10 Ibm/gal [1198kg/m3]! Apparently, the sand was not really abrasive and the bit and the mudwere well selected. Others report economically successful runs of TSP diamondbits in depleted sands in south Louisiana. The TSP diamond bit is of limitedversatility; if much shale is encountered, the bit may slow down too much. Deviation Control. PDC bits require only light weight on bit (WOB) to drillrapidly. Because of this feature, the bits have become popular where deviationcontrol is needed, particularly for use in a crooked-hole area. If theformations are suitable for PDC bits, impressive savings can be achieved inthis application. Even less suitable formations, causing accelerated bit wear, can be tolerated to benefit from the PDC bit's favorable characteristic, if thealternative bits performed very poorly. The bit's profile can affect thebuilding or drop of poorly. The bit's profile can affect the building or dropof bottomhole assemblies (BHA, s). Refs. 5 and 17 report local experience. Directional Control. The directional characteristics of PDC bits differpronouncedly, but not unfavorably, from those of roller cone bits. PDC bits, particularly matrix-body bits, have been used to arrest the right-walktendencies experienced with roller-cone bits. JPT P. 817

SPE Members Abstract Historically, the Upper Jurassic Brae conglomerates intrinsic to North Sea Block 16/17 have been drilled with IADC 517 to 617 type roller cone bits. Unfortunately, excessive wear to the cutting structure and gauge area of these bits dramatically limited their useful life and made them uneconomical. Runs shorter than 100 ft with penetration rates as low as 4 ft/hr was not uncommon with these bits. This was true even for roller cone rock bits incorporating enhanced gauge protection. The decision to employ fixed cutter bits in Block 16/17 was initially frustrated with the inability of existing designs to effectively drill the conglomerates. However, a new fixed cutter design concept utilizing impregnated grit-sized diamonds has greatly improved drilling performance with substantially lower cost per foot. Field tests have shown average penetration rates of more than 1 5 ft/hr with bit life averaging 400 ft. Penetration rates have remained steady throughout the target interval. Further, no significant gauge wear has been observed, despite the fact the bits were run on turbines. This paper describes the development of the IADC M841 class fixed cutter bit and its application in these formations. The cost savings achieved with these bits and the future potential of the M841 impregnated diamond drill bit will be analyzed. The laboratory testing leading up to the development of the impregnated diamond bit will be detailed. Introduction Block 1 6/1 7, also known as the T-Block, is located about 120 miles from Aberdeen in the Central North Sea (Fig. 1). Phillips Petroleum made the first discovery in the region in 1976 and since then four distinct fields have been identified: Tiffany, Toni, Thelma, and South East Thelma (Fig. 2). Since assuming operatorship of the block in 1986, Agip UK has thus far decided to develop the Tiffany and Toni fields. To date, 20 exploration and appraisal wells have been drilled on the block. Four development wells have been pre-drilled for the Tiffany platform, which became operational in the summer of 1993, and five wells have been drilled through a subsea template installed for the Toni development. Historically, the Brae conglomerates of the Upper Jurassic sequence of the Central North Sea have proved extremely difficult to drill. The unique combination of a hard and abrasive sandstone matrix with a pebble and occasional breccia conglomerate found in Block 16/17 has made it a particularly difficult area to drill. The formations encountered there have proved impenetrable for both insert roller cone or standard fixed cutter bits. Since 1 988, Agip UK has been involved in an extensive program to develop a fixed cutter bit capable of drilling the difficult Brae conglomerates of Block 16/17. What resulted was a partnership with a bit manufacturer, which led to the successful development of the IADC M841 type impregnated diamond fixed cutter drill bit, P. 205^

The PDC cutter-rock interaction behavior in rock cutting: A review

The existence of hard, interbedded formations often prove to be very damaging to conventional polycrystalline diamond compact (PDC) fixed cutter bit designs, and as a result, may require additional trips to replace the bit for insert roller cone or impregnated diamond. This can represent significant additional drilling costs for the operator, equating to very high costs per foot if the remaining section to be drilled is short. The challenge is to maintain a low cost per foot, through the use of a bit design which is both durable enough to drill the desired interval, at the best possible penetration rate. This paper describes the development of a new innovative drill bit technology that fuses two existing fixed cutter materials using a unique design philosophy that allows for greater versatility in drilling a wider range of interbedded, difficult to drill lithologies that are not typically drilled entirely with PDC bits. This novel design philosophy includes optimized cutter placement allowing engineered exposure of diamond impregnated mix applied in critical areas of the bit for added durability. This development project was initially targeted for the sub-Saharan region in the Congo, where the existence of a conglomeratic interval at the bottom of the section prevented to reach total depth (TD) with fixed cutter bits, having to end with roller cone insert designs. In its first trial, the new design drilled three times the interval of the best offset with a 34% improvement in rate of penetration (ROP). Applications in different regions of China were soon identified, resulting in a challenge to design for a new hole size with various drive types; the results of which are detailed in this paper.

Harder formations in geothermal and deeper oil and gas wells typically see lower rates of penetration (ROPs) and higher bit wear. Recent drilling experience in the Utah FORGE observed higher ROPs and longer runs using lighter drilling muds and new cutter technologies. Questions have arisen regarding reasons for the improved ROP and if the higher ROP is due to increased spurt loss or reduced hydrostatic pressure from lighter drilling fluids. A study was performed on an inhouse rig using two polycrystalline diamond compact (PDC) bits (4-bladed vs 5-bladed) to analyze the effect of confinement on ROP in Sierra White Granite (SWG). Tests were performed at confinements of 0, 1000, and 2000 psi and at constant rotational speeds of 80 and 150 RPM. Results show that when confinement is increased, ROPs are similar in the ineffective cutting Phase I. However, results in Phase II indicate that ROP is largely different between the unconfined and higher confinement testing. No significant effect on ROP is observed between 1000 and 2000 psi. At zero confinement, the 4-bladed bit outperformed the 5-bladed bit while at 1000 and 2000 psi confinement, the performance was similar. This paper presents the laboratory results with potential applications to hard rock geothermal drilling. INTRODUCTION Confining pressure in drilling terms is the hydrostatic pressure at the bottom of the well while drilling in impermeable formations. Many studies have outlined the effects of confining pressure on rock deformation but the effect of confinement on drilling efficiency and ROP is yet to be thoroughly investigated. In recent years, hard rock drilling especially in geothermal reservoirs has faced great challenges such as low penetration rates and high bit wear leading to high drilling costs. Advanced bit technology is required to maneuver the unique physical and mechanical properties of hard and abrasive rocks at high confining pressures. Although roller cone bits were predominantly used to drill hard and abrasive formations, PDC bits with enhanced cutter properties and ‘special’ cutter geometries are at the forefront of drilling research and technology. During the past years, new PDC cutter technology has improved cutter wear resistance and its capability to carry higher loads. Recent drilling experience in the Utah FORGE observed higher ROPs and longer bit runs using lighter drilling muds and new cutter technologies including shaped cutters (Dupriest and Noynaert, 2022). Glowka, (1985) discussed the potential for developing a PDC drill bit for hard rock applications such as geothermal drilling. Different cutter geometrical shapes and designs are currently being designed to address heavy impact damage in hard formations, prevent thermal damage and extend drilling runs while maximizing ROP. Zhu et al. (2022) analyzed the loading performance and rock cutting mechanism of different PDC cutters by using single cutter analysis to study geometry, aggressiveness, and stress distribution in granite. Xiong et al. (2022) studied the performance of a stinger PDC cutter in granite to evaluate cutting force and mechanical specific energy (MSE). Barnett et al. (2022) studied the effects of drillstring torsional vibration on ROP with PDC bits in hard rock. Wang et al. (2020) designed a PDC hybrid drill bit to navigate hard and abrasive formations. Akhtarmanesh et al. (2021) designed an ROP model for drilling hard and abrasive formations for PDC bits. It was seen that distinct phases of drilling exist where Phase I is the inefficient drilling phase due to insufficient WOB and Phase II is the efficient drilling phase due to higher WOB which results in a higher ROP. Figure 1 shows the different phases of drilling as described by Akhtarmanesh et al. (2021). Due to the complexity of drilling in hard formations, more testing is crucial to completely understand the effects of temperature, rock behavior, and confining pressure on ROP and bit cutting mechanism. An understanding of bit cutting action in hard rock is crucial for successful ROP optimization and improving drilling efficiency.

Previous work has suggested that thermal phenomena can greatly accelerate the wear of polycrystalline diamond compact (PDC) drag cutters under certain conditions. In this paper, the implications of that finding for PDC bit design and operation are examined. An abrasive wear model for cutters is developed and applied to rotary drilling applications to demonstrate the significance of thermally-accelerated wear on bit life. Under conditions where thermal effects are not important, it is concluded that in order to maximize bit life, greater bit weights and lower rotary speeds are preferable over shallow cuts and high speeds. It is found that even under normal abrasive wear conditions, a PDC cutter develops a significant wearflat before one-half its useful life is expended, suggesting that PDC bits should be designed to operate effectively in the worn condition. A cutter placement criterion is presented for designing bits for equal cutter wear. Through analysis of new experimental data, a technique is developed for approximating cutter penetrating forces in the presence of cutter interactions on a bit face and for estimating relative cutter wear. A hypothetical bit designed for equal rock removal volume per cutter is examined to determine the relationship between the equal volume and equal wear criteria for cutter placement. The complex role of thermal wear phenomena in this relationship is also examined for the hypothetical bit in three different rock types.

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.

This paper explores the successful application of hybrid bit technology in offshore gas well operations. It details the strategic steps taken to meet the primary objectives, utilizing a 28-Inch hybrid bit technology to tackle the complexities of drilling in challenging offshore intervals. Key aims of the bit design and tool deployment encompassed achieving single-trip completion of the section, enhancing drilling speed and efficiency, and driving cost savings in operations. Offshore gas drilling presents significant costs and challenges, particularly in large hole sizes. In this specific scenario, the interval comprises highly interbedded formations and a demanding drilling environment, including fluid loss zones, boulders, and hard, abrasive intercalations. The challenging 28-Inch section spans over 4,000 ft of medium to hard dolomites with occasional streaks of anhydrite and interbedded limestone with shales. The conventional approach to drilling such sections involves using two or three roller cone tungsten carbide bits, leading to high drilling costs and instability issues due to prolonged hole exposure. To address these challenges, multiple wells in the area were meticulously analyzed, examining both time and depth-based logs along with electrical logs. This comprehensive analysis revealed a drilling trend, indicating that hybrid bit cutting structures were best suited for this demanding application. The hybrid bit solution was chosen for its unique capability to shear and crush formations during drilling, combining the durability of roller cone bits with the efficiency of PDC (Polycrystalline Diamond Compact) drill bits. This distinctive drilling mechanism enables hybrid bit technology to efficiently drill through this challenging application compared to traditional drill bits. In the field-testing phase, the hybrid bit was deployed in two consecutive wells. Although the drilling parameters were controlled to prevent total losses, which impacted the overall average rate of penetration (ROP), the outcomes were remarkable. Both wells successfully completed the section using only the hybrid bit, which was pulled out of the hole in good condition. Furthermore, both wells achieved above-average ROP and saved 3 to 4 days of drilling time compared to the conventional method of using standard roller cone bits. The 28-Inch hybrid bit technology has proven to be the ideal solution for addressing the demanding offshore gas drilling challenges in this application. It stands out as the only drill bit technology capable of completing this section in a single trip, thereby facilitating the achievement of all performance targets set for the test.

The Sognefjord reservoir (Jurassic) in Troll Field, Norwegian North Sea, is drilled horizontally in 9½" hole from 1,800 m to 3,100 m in length. The reservoir consists of loose sands, subdivided into clean and micaceous units and local hard calcareous cemented zones. These sections must be drilled in a tight horizontal plane, approximately one meter above the oil-water contact to maximize oil production. The oil bearing strata is typically between 12 m and 27 m thick. Most steering is done in the vertical plane to keep the well within the narrow target window (∼1 m TVD or less) and in the optimum azimuth to place the well in the desired reservoir sand. Historically this section has been drilled with steerable motor assemblies and tungsten carbide insert roller cone bits. The use of polycrystalline diamond compact (PDC) bits was precluded due to problems associated with toolface control in the loose sands. With the advent of a rotary steerable tool (RSS) came the prospect of long runs with specialized PDC bits. After major area specific problems were encountered a joint task force was assembled, consisting of a drilling operator and an integrated service company, to attempt to improve drilling performance in the reservoir section. Three main areas of potential improvement were identified: Improve reliability of the RSS (including MWD). Increased ROP in hard calcite cemented sandstones. Mapping and prediction of calcite cemented zones. The team concentrated on rock strength analysis, simulator testing of new PDC designs, BHA vibration modeling and analysis of depth based drilling, MWD & vibration data. Modified BHA's and Troll specific antiwhirl PDC bits, along with revised drilling practices, were applied in the field. This allowed step improvements in drilling performance to be achieved. Overall, meters/BHA increased from 264 m to ∼640 m. The new bit designs also increased the overall average R from ∼10 to 20 m/hr and improved instantaneous ROP in the calcareous sandstone sections. Savings in rig time on the Troll development are potentially immense as approximately 60 wells remain to be drilled. This paper will highlight the need for a systematic approach, including problem definition, data collection, solutions implementation and results benchmarking.

To minimize the detrimental effects of cobalt binder on the thermal stability of polycrystalline diamond compact (PDC) under high temperature working conditions and enhance the PDC’s properties. Hot filament chemical vapor deposition diamond coated polycrystalline diamond compact (HFCVD-PDC) was prepared by depositing homogeneous epitaxial diamond film on the polycrystalline diamond layer (PCD layer) treated with cobalt binder removal. The effect of deposition pressure on the microstructure of the diamond film was investigated, and the PDC’s wear resistance was assessed using the abrasion ratio test. The drop hammer impact test was utilized to evaluate the impact toughness of the original PDC, cobalt removal PDC, and HFCVD-PDC. The results showed that a continuous and dense nanodiamond film with a cauliflower-like structure was formed on the PDC surface at the deposition pressure of 3 kPa. The abrasion ratio of the HFCVD-PDC increased by 67.44% compared to the original PDC, and by 33.29% compared to the cobalt removal PDC. Furthermore, filling nanodiamonds into the pores of cobalt removal PDC improved its impact toughness. These findings suggest that the application of homogeneous epitaxial diamond on the PCD layer can significantly improve the PDC’s wear resistance and impact toughness.

A major effort has been made to evaluate the commercial application of bits fitted with STRATAPAX Drill Blanks for drilling oil wells. Over 40 field runs have been made with such Diamond Cutter bits and a significant potential economic application of the new material is indicated. Further development work will be required to improve bit design and manufacture as well as the wear and engineering characteristics of the diamond cutters. Introduction Surface-set diamond bits usually contain natural diamonds. The available, as-manufactured, Synthetic diamonds are too small to be used economically in these bits for oilfield drilling. A technique has, however, been developed by the General Electric Company to bind small synthetic diamonds together with a diamond-to-diamond bond on top of a tungsten-carbide substrate. As a result, a relatively large diamond cutter could be produced. The technique was initiated in the manufacture of diamond compacts for machining and dressing purposes. The product was named "COMPAX Industrial Diamond Blank". product was named "COMPAX Industrial Diamond Blank". With the success of this application, these diamond blanks were introduced into the drilling-bit industry. Recently a similar product, named STRATAPAX Drill Blank, was offered particularly for rock-drilling purposes. Mainly during the past few years several companies began to develop bits suitable for fitting with these diamond blanks for use in oil-well drilling. This paper reviews the results of a major effort obtained from over forty field runs with such bits, fitted with either COMPAX or STRATAPAX blanks. Such bits will be referred to as Diamond Cutter bits. In addition, some general information on STRATAPAX Drill Blanks is discussed and results of a number of laboratory experiments are presented. Though a competitive product - SYNDITE is now also available, it has not been product - SYNDITE is now also available, it has not been included in the field tests reported here. WHAT IS A 'STRATAPAX DRILL BLANK'? Examples of a STRATAPAX Drill Blank are shown in Fig. 1. Each blank is made up of a thin diamond layer (minimum thickness 0.5 mm or 0.020 in), firmly bonded to a tungsten-carbide substrate. This layer is obtained by subjecting a mixture of small high-quality synthetic blocky diamond particles and a small amount of catalyst to very high pressures and temperatures. Because of the catalyst selected the diamond layer has only an effective operating-temperature limit of about 700 degrees C, beyond which level the bond between the individual diamond crystals loses its strength. This temperature limitation has proved to be a significant handicap in the development of the processes for attaching the STRATAPAX Drill Blanks to the processes for attaching the STRATAPAX Drill Blanks to the bit, because conventional diamond bit manufacturing methods use temperatures over 900 degrees C. This temperature limitation could also affect the wear of the cutting edge of the bit in actual operation. The diamond layer features a polycrystalline structure without cleavage planes. This is only matched in nature by carbonado diamonds, which have only been used to a limited extent in drilling bits because of their short supply and high cost. The cost of STRATAPAX Drill Blanks is also high, but unlike the carbonado diamonds, the supply of diamond blanks is virtually unlimited. The diamond blank exhibits the following important advantages over the types of natural diamonds generally used in bits for oilfield application:–a generally sharper cutting edge–higher-quality diamond crystals–a polycrystalline and crack-free structure. These advantages only apply if the temperature limit for the diamond layer is not exceeded. Since this limit may be exceeded during the drilling operations, there is clearly a need for further improvement of the STRATAPAX Drill Blanks. The diamond layer is firmly bonded to a tungsten-carbide substrate, which is about 2.7 mm thick.

There have been papers that analyze the relationship between bit design and a bit’s vibrational characteristics. These papers typically are based on the analysis of three-axis near-bit down-hole vibration sensors. In this paper, the authors take a simpler approach. Using a standard microphone literally pointed at the bit, they record the noise of the bit/rock interaction while drilling and analyze the resulting noise for these bit vibrational characteristics. The data were gathered at the Colorado School of Mines in Golden, CO. The noise of a PDC core, roller cone, and diamond core bits were recorded under various weight and rotary speeds using a microphone and a vertically mounted uniaxial geophone (used for confirming the data recorded on the microphones). Using a Fast Fourier Transform, the frequency spectra were extracted from the recorded data and analyzed. The data were normalized for rotational speed. The results of the frequency analysis of the roller cone, the PDC, and the natural diamond bits are presented in this paper. The major differences in the three bit frequency characteristics could be detected and furthermore, for drag bits, the frequency characteristics could be related to the bit’s design. The frequency spectra of the roller cone bit can best be described with a general high amplitude level that is relatively evenly distributed over the whole frequency spectrum. The drag bit data showed a strong relationship between the number and arrangement of cutting elements and frequency peaks on a plot of amplitude versus cycles per revolution. Frequency peaks were observed at multiples of the number of cutting elements. In general this relationship was strongly visible on the PDC bit data but not as strongly visible on the diamond bit data. The conclusion is that bit characteristics can be determined using only the noise of a bit. Potential applications of this research include detecting and diagnosing bit problems (e.g., broken teeth and bit balling) in real time using simple microphone based acoustic data.

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 102067, "Faster, Longer, and More-Reliable Bit Runs With New-Generation PDC Cutter," by J. Clegg, SPE, ReedHycalog, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September. A new process for manufacturing polycrystalline-diamond compact (PDC) cutters creates a wrapped thermostable region across the face and around the periphery of the PDC cutter. This differs significantly from existing first-generation thermostable product because the treated region has complex geometry in three dimensions. The full-length paper describes the new cutter geometry and shows how the thermostable region supports the cutter as it slowly wears. Introduction Historically, there has been a trade-off between abrasion and impact resistance of PDC cutters. Typically, impact resistance was achievable by use of a larger diamond grain size but at the expense of abrasion resistance. The first attempts to extend the envelope of PDC-bit and -cutter performance occurred in the mid-1990s when multimodal polycrystalline diamond was introduced. This used a mixture of grit sizes from 50 to 2 µm in diameter, allowing the smaller grits to fill the voids left between the larger particles, resulting in a much denser polycrystalline-diamond layer that improved abrasion resistance. Additional improvement was achieved by use of nonplanar interfaces. The move from planar to nonplanar interfaces was driven by a desire to reduce stresses at the interface between the polycrystalline diamond and its tungsten carbide substrate. The introduction of the nonplanar interface combined with the multimodal polycrystalline-diamond mix provided significant improvement in both relative toughness and relative wear life over planar multimodal materials. The thicker diamond edge that resulted improved relative abrasion life. Thermostable PDC Cutters Cobalt normally is present in the creation of polycrystalline diamond in the PDC press. It is introduced in the tungsten carbide support, where it acts as a cement. At the elevated temperature and pressure where diamond-to-diamond bonding occurs, the cobalt migrates into the diamond grit and helps to catalyze the bonding process. It also forms a bond with the tungsten carbide substrate and ensures that the PDC is one integral component. However, cobalt significantly reduces the thermal stability of the PDC because it has a greater coefficient of thermal expansion than the surrounding diamond particles. Between 700 and 760°C, the cobalt expands and forces the diamond-to-diamond bonds apart. This results in the rapid breakdown of the compact. What appears to be abrasive wear when a dull PDC bit is analyzed often can be the result of the breakdown of the diamond-to-diamond bonds because of overheating. Therefore, it is important that the temperature of the PDC cutter is maintained below 700°C to avoid thermal breakdown. Unfortunately, the cutting-tip temperature often exceeds this critical limit.

The Cambro-Ordovician formation in onshore Algeria consists of hard and abrasive sandstones that have proven challenging to drill. Up until now, no bit has completed the section in one run, and these formations have been considered beyond the limit of what is drillable by PDC cutters. Previous sections have used impregnated diamond and roller cone bits that achieved low penetration rates and required multiple bit runs. The impregnated runs require the additional cost of turbo drills or high-speed motors to deliver the rotation speeds necessary to achieve acceptable rates of penetration, while a bearing seal failure of a roller cone bit increases the risk of losing bit pieces in hole.The operator conducted an optimization process based on rock mechanics including an analysis of prior performances to conclude that the formation could be drilled more economically applying the recent advances in PDC bit technology. Collaboration between the bit manufacturer and the operator facilitated the implementation and development of the latest bit technology, including enhanced bit stability, improved cutter layout and more resistant cutters. After an initial, partially successful run, new bit improvements were implemented. The two subsequent runs completed their sections, enabling the operator to drill with one bit through what was previously a multiple-bit section. Rates of penetration were improved significantly over previous impregnated and roller cone runs. Requirements for down hole drive tools and bit trips were eliminated as was the risk of bit junk being left in hole.This paper outlines the process that led to improved understanding of the formation drill ability, the research and development behind this new bit technology, the continuous optimization of the specific bit, its field performance, and the resulting cost saving for the operator.

In recent years, polycrystalline diamond compact (PDC) drill bits have seen significant advancements. They have replaced over 90% of the workload traditionally handled by roller cone bits and have become the predominant choice in energy drilling due to their superior efficiency and durability. However, PDC drill bits are susceptible to adhesion of rock cuttings during drilling in muddy formations, leading to mud accumulation on the bit surface. This phenomenon can cause drill bit failure and may contribute to downhole complications, including tool failure and borehole instability. The adhesion issue between PDC drill bits and mud rock cuttings underground is primarily influenced by the normal adhesion force between the drill bit surface and the mud rock cuttings. Therefore, biological non-smooth surface technology is applied to the prevention and control of drill bit balling. It is an optimal selection of biomimetic non-smooth surface structures with reduced adhesion and detachment properties. A non-smooth surface model for the PDC drill bit body is established through the analysis of the morphological characteristics of natural biological non-smooth surfaces. An experimental platform is designed and manufactured to evaluate the adhesion performance of non-smooth surface specimens. Indoor experiments are conducted to test the normal adhesion force of non-smooth surface specimens under varying morphologies, sizes, and contact times with clay. Finally, the anti-adhesion performance of the non-smooth surface unit structures is then analyzed. The normal adhesion force with a contact time of 12 h is as follows: 340 Pa of big square raised, 250 Pa of middle square raised, 190 Pa of small square raised, 315 Pa of big circular groove, 280 Pa of middle circular groove, 200 Pa of small circular groove, 225 Pa of big dot pit, 205 Pa of middle dot pit, and 130 Pa of small dot pit. Compared with the normal adhesion force of 550 Pa for smooth surface specimens with a contact time of 12 h, the anti-adhesion properties of the three non-smooth surface unit structure specimens designed in this paper were verified. We analyzed the anti-adhesion performance of non-smooth surface unit structures. At the critical contact time when the adhesion force tends to stabilize, the adhesion forces of different specimens are as follows: 330 Pa of big square raised, 237.5 Pa of middle square raised, 175 Pa of small square raised, 290 Pa of big circular groove, 250 Pa of middle circular groove, 160 Pa of small circular groove, 210 Pa of big dot pit, 185 Pa of middle dot pit, and 115 Pa of small dot pit. The results indicate that the anti-adhesion effect of small dot pit structures is the most effective, while the anti-adhesion effect of large square convex structures is the least effective. As the size of the unit structure decreases, it becomes more similar to the surface size of the organism. Additionally, a shorter contact time with clay leads to a better anti-adhesion effect. These findings provide new insights and research directions for the effective prevention and control of mud wrapping on PDC drill bits.