Estimating Tooth Wear From Roller Cone Bit Vibration

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.

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 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.

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.

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.

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.

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 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.

This paper details the lessons learned in late 2007 and early 2008 whilst air drilling vertical gas wells in the Travis Peak formation of the western East Texas deep Bossier play in Amoroso Field and applying the lessons learned in the US to a deep appraisal well drilled in Northern China. The deep Bossier represents one of the most active onshore plays in the United States. Deep Bossier wells are 14,000 ft (4,267m) to 16,000 ft (4,876m) deep and intersect shale and sandstone formations ranging between 2,000 ft (610m) and 3,000 ft (914m) thick. The Travis Peak is also known as ‘tragic peak’ during conventional drilling operations because the sandstone is hard and abrasive in nature, leading to extreme low rate of penetration (ROP). Air Drilling technology was utilized to increase the ROP through the formation at depths of 10,000 ft (3,047m) and greater. The deep exploration wells in the Daqing area of Northern China are drilled to depths of 20,000ft (6,095m) and greater in an attempt to explore the deep volcanic reservoir potential in the area. In the US the 8-1/2-in hole size was drilled using air hammers and roller cone bits using straight air or nitrogen. Temperatures in the Travis Peal formation were reported to be above 300°F (148°C). Temperatures in Northern China were reported to be as high as 400°F (204°C) in the 12-1/4-in hole size. The fit-for-purpose equipment needed for the air drilling sections of these wells comprised of air hammers capable of drilling in high temperatures, hammer bits with full diamond inserts, high-temperature float valves, air compressors, nitrogen production units, mist injection systems, and rotating control diverters. The lessons learned in the US were applied to the well in China where similar results were encountered. The drive to enhance air drilling to extreme depths and high temperatures previously believed to be off limits proved to be successful in both parts of the world.

High-temperature geothermal resources away from tectonic boundaries or geologic hotspots can be accessed by the drilling of deep wells through significant sections of basement rock. This paper evaluates the impact of rapid cooling on rock cutting process, and incorporates this effect as a part of potential drilling performance optimization. Using data from a series of experiments conducted in a high pressure and high temperature (HPHT) drilling laboratory, we demonstrated that rapid cooling enhanced rates of penetration over 60% in the 300+ °C hot dry rock utilizing a PDC bit or a roller cone bit. Drilling was performed in hard igneous rock samples, with the unconfined compressive strength over 200 MPa. Each sample was heated and confined to predetermined conditions, then drilled with controlled parameters. The drilling performance data was acquired for each experiment, complemented with dynamic in-situ temperature measurements, and visual assessment of rock samples before and after drilling. The rapid cooling effect on the rate of penetration was found to be a function of the temperature difference between the drilling fluid at the bit face and the rock sample temperatures. Unlike previous studies on the Drilling Performance, which overlooked thermal effects, our research focuses on the synergy between rapid cooling and mechanical rock cutting process. This study provides a framework to understand and improve drilling performance for HPHT wells, including deep and hot geothermal wells.

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

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.

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 .

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.