The IADC Roller Bit Classification System

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.

There is a problem of increasing the durability of the roller cone bit of the drilling rigs used in the quarries of Ukraine. One of the effective ways to solve it is to apply the control method of maintaining a constant flow of mechanical power in the bottom hole zone. The implementation of such a control method leads to the necessity of controlling and limiting the resistance torque on the roller cone bit. To solve the problem of determining the resistance torque, we used methods of parameter identification: the Luenberger observation device with adaptation to external influences; estimation of the resistance torque using an extended observation object; the theory of regulators adapting to perturbations. It has been established that the most rational method of identifying the resistance torque on a roller cone bit is an astatic monitoring device, which allows to implement a method of controlling the rotation of the drill rod by a drive mechanism that maintains a constant flow of mechanical energy through the roller cone bit and increases the durability of the roller cone bit.

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 predominant experience throughout the drilling industry is with roller cone rock bits. However, diamond bit use has increased substantially in the past five years and continued increases are likely. Diamond bits are different enough in their design and function that they require distinctly different handling and operating procedures. This paper describes such procedures from the point the bit is unboxed, through make-up in the rotary table, tripping into the hole, washing and reaming to bottom (with attention to downhole motors), establishing a new bottomhole pattern, identifying pumpoff effects if present, establishing a satisfactory penetration rate, responding to formation changes, and recognizing and diagnosing indications that may lead to the decision to trip out of the hole. This paper bridges the gap between two other related papers which describe how new diamond bits are classified before they go in the hole23 and how worn diamond bits are graded once they are out of the hole24.

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.

This paper describes the field experience of a new hybrid bit based on proven polycrystalline diamond compact (PDC) bit designs with rolling cutters on the bit periphery. A hybrid bit can drill shale and other plastically behaving formations up to three or four times faster than a roller-cone bit by being more aggressive and efficient. The penetration rate of a hybrid bit responds linearly to revolutions per minute (RPM) unlike roller-cone bits, which have an exponential response with an exponent of less than one. In other words, the hybrid bit drills significantly faster than a comparable roller-cone bit in motor applications. Another benefit is the effect of the rolling cutters on the bit dynamics. Compared to conventional polycrystalline diamond cutter bits, torsional oscillations are as much as 50% lower; stick/slip is reduced at low RPM, and whirl at high RPM. This gives the hybrid bit a wider operating window and greatly improves toolface control in directional drilling. The hybrid drill bit technology combines roller-cone and PDC bits into a single patented design, employing the best attributes of each bit type to improve reliability and efficiency, while ensuring performance consistency in the most problematic applications. This revolutionary technology has a large spectrum of applications, excelling in typically troublesome formations for PDC and roller-cone bits, such as interbedded hard and soft stringers or hard nodular inclusions. The results of a field test in an inland application will be presented, comparing the performance of hybrid bits with conventional PDC and roller-cone bits used on offset wells. A planning and engineering process was applied, ensuring high-quality support to the operator in the office and at the rigsite. The client saved multiple conventional tungsten carbide insert bit runs and drilled 100% farther, ultimately achieving a rate of penetration (ROP) two times faster than the best tungsten carbide insert (TCI) bit run in the same well.

Cemented tungsten carbide and polycrystalline diamond are the most critical materials used for roller cone bit cutting structure. Chipping and catastrophic breakage are the primary failure modes for the materials and hence the limiting factor of service life of a drill bit. Chipping and fracture resistance can be improved at the expense of hardness and wear resistance of the materials. This trade-off between wear resistance and chipping resistance hinders the development of super hard materials for demanding drilling applications. Functionally designed composite materials of polycrystalline diamond (PCD) and cemented tungsten carbide (WC-CO) that offer enhanced chipping resistance without significantly sacrificing wear resistance are studied and reported in this presentation. Specifically, one example of the functionally designed composite materials is a honeycomb structured composite of polycrystalline diamond (PCD) and WC-Co and its application for diamond enhanced inserts for roller cone bits. The PCD/WC-Co composite takes advantages of high modulus and superior wear resistance of diamond, while it mitigates chipping and cracking using the tougher WC-Co as cell boundaries. The overall engineering properties and performance are superior to that of pure PCD. Another example of functionally engineered hard materials is double cemented (DC) tungsten carbide. Double cemented tungsten carbide has 50% or higher fracture toughness than conventional cemented tungsten carbide at equivalent wear resistance. When compared to tool steels, DC carbide has equivalent fracture toughness but much higher wear resistance. Field tests of honeycomb structured diamond enhanced inserts (CDEI) demonstrated the controlled chipping characteristics and longer durability of components as compared to conventional homogeneous PCD materials with comparable wear resistance. DC carbide also exhibited excellent damage tolerance during field tests in demanding applications where excessive heat checking and fracturing of inserts are common failure modes.

Recent developments in polycrystalline diamond (PCD) technology have led to breakthroughs in PCD bearing designs and PCD insert cutting structures. The authors suggest that the next major step in bit technology will be to combine these two innovations in a new generation roller cone bit, capable of sustained operation with a PDM or turbine. Other potential areas of innovation are now made possible with this new technology. One of the first areas will be an integrated high-speed downhole drilling system consisting of the next generation roller cone bit, turbine, and MWD. Another area for development will be a downhole mudhammer for percussion drilling of petroleum wells. A more distant potential development is called the Robotic Advanced Drilling System (RAD), which uses a flexible drillstem and a downhole thrusting mechanism to give WOB and real-time drilling control.

The in-situ mechanical strengths of rocks are very difficult properties to determine or measure because of variation in stress states and rock anisotropics. On the other hand, drilling penetration rates in rocks which are related to some rock strengths can be measured with a higher degree of reliability in the field. From penetration rate and other drilling data, a rock's drilling strength may be determined and related to its mechanical properties. Wireline electrical log data have been extensively used in reservoir characterization and sometimes give direct measurements of some elastic properties of the rocks. However, there is still the need to evolve some universally acceptable rock strength determination method from wireline electric log data. This approach has the advantage of not requiring extensive drilling and laboratory data and also provides a realistic estimate of in-situ rock strength. This paper discusses relationships between rock drilling strength and some wireline log properties and shows how a formation's drilling strength can be estimated from log data.

Performance prediction and multi-objective optimization of metal seals in roller cone bits

Rotary drilling with roller cone bit is often accompanied by wide fluctuations of the weight on bit (WOB). In certain cases, the WOB periodically reduces to null. It has been postulated that in these cases the drill bit lifts off from the formation surface. The present study models the interaction among the lift-off of the drill bit, the WOB variation, and the modulation of the amplitude of the lobes on the formation surface. The analytical model is used to obtain numerical results for a specific drillstring. From these results it is inferred that the rotary speeds corresponding to the axial resonant frequencies of the system, determined from the functions of the driving point mobility and impedance at the drill bit, are critical regarding the wide fluctuations of the WOB; they may be associated with the sustenance of the lobes with large amplitude.

This paper describes the development of processing techniques to extract roller cone bit wear information from near-bit force and acceleration measurements. Laboratory data have been col-lected for bits in a variety of wear states operating in a small atmospheric drilling machine and under the simulated downhole conditions provided by a fullscale drilling test station. This has given information on how bit cone speed increases as the wear process progressively reduces the cone radius. Recent studies are reported and the detailed dynamic features of force mea-surements made on laboratory drilling machines are described. The improved understanding of the nature of the bit signature has led to the development of novel processing techniques for the detection of bit wear from near-bit measurements. A com-parison with results obtained from bit modelling work is also presented.

One of the key aspects, which are designed to ensure the quality’s production of cones for roller cone bits drill bits with carbide insert cutter are presented. The influence of technological parameters on the formation of holes for planting carbide insert cutter and the assembling operation of the connection tungsten carbide insert cutter-cone. The analysis showed that at the stages of holes reaming operations there are the most problems in quality assurance. Based on numerous experiments on different sizes of carbide insert cutter, it is established that the speed of the pressing process is extremely important. Analysis of cut and disassembled such joints revealed that the walls of the hole have a significant plastic deformation, micro cracks, and in some places chips formed at the bottom of the hole. The parameters of deviation in the roughness of such surfaces were also investigated. If we use the recommendations, then we found that wetting the carbide insert cutter in oxidized paraffin reduces the plastic deformation of the hole’s wall in half. This allows you to increase the tension in the connection. In order to increase the accuracy of the pressing operation, a special device was developed, which allowed accurately orienting the carbide insert cutter before pressing, as well as significantly reducing the shortage. Analysis of the hole’s walls on the steel AISI 9315H revealed that at tensions up to 0.068 mm there was an elastic deformation, then up to 0.148 mm, and then with increasing tension was obtained significant plastic deformation. Theoretically and experimentally substantiated developed methods to improve the technology of drilling bits, which minimizes the deformation of cones and carbide, insert cutters. The main purpose was to determine the empirical dependence, which allows establishing the relationship between the roughness parameters and the amount of tension in the connection cone- carbide insert cutter .

The penetration rates of dispersed and non-dispersed water-base muds were studied using Mancos Shale. The full-scale wellbore simulator at Drilling Research Laboratory was utilized. Previous studies1 have indicated that in invert oil muds higher penetration rates can be achieved when the weighting agent is ilmenite rather than barite. This study compares barite and ilmenite in water-base systems. Two grind sizes of ilmenite (fine and standard) were used in order to determine the effects of particle size on penetration rate. In addition to these tests, hematite, fine-grind ilmenite and barite were tested in a low colloid invert oil mud system as a supplement to the original study. An additional test was conducted with a conventional diamond bit and the low colloid oil mud for comparison. Highest penetration rates were observed with the standard particle size distribution ilmenite for the water-base muds. For the invert oil mud, similar penetration rates were observed for the fine-grind ilmenite and the hematite; the barite weighted mud resulted in relatively lower rates of penetration. The fine grind ilmenite/low colloid oil mud/diamond bit combination provided penetration rates equal to or greater than the barite/low colloid oil mud/roller cone bit combination.

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