Impregnated Bit Technology Improves Drilling Efficiency in North Sea Conglomerates

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.

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.

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.

This paper will discuss the deployment of the concentric dual diameter fixed cutter bit technology which was introduced in January 2015. The bit was deployed and tested four times in a vertical application and S-shape wells in Burgan Field, South of Kuwait and achieved the fastest penetration rate in the application. The concentric dual diameter bit is composed of a smaller pilot and a larger reamer section, where the reamer section dictates the final drill size. Conventional fixed cutter bits take very little advantage of stress relieving the rock, as it only affects the borehole wall. Concentric dual diameter technology bits are able to initially drill with a leading smaller pilot section efficiently to relieve the stress of the rocks. Subsequently, the reamer section removes the stress relieved rock with lower mechanical specific energy compared to regular fixed cutter bits, giving it the advantage to generate higher penetration rates. Another advantage of the concentric dual diameter technology bits is the stability of the bit, since two gauge sections are available to be in constant contact with the borehole while drilling. The first 12 ¼ in. concentric dual diameter technology bit in conjunction with a packed rotary BHA was tested in a vertical application in the Burgan Field, South of Kuwait. The bit was able to deliver improved performance by drilling two wells from shoe-to-shoe to section TD of 1372 ft with an ROP of 152.4 ft/hr where the lithology consisted of shale and sandstone. The performance capability was confirmed when the second bit drilled two wells shoe-to-shoe to sections to a TD of 2263 ft with ROP of 161.6 ft/hr. and achieved top record runs in south Kuwait for vertical applications and S-shape wells and consisted of similar lithology of shale and sandstone. The 12 ¼ in. concentric dual diameter was able to surpass the average rate of penetration for the same application in the Burgan Field by 100% saving the operator drilling time and making the concentric dual diameter bit design the top performing drill bit in the field.

This paper will discuss the deployment of the concentric dual diameter fixed cutter bit technology which was introduced in January 2015. The bit was deployed and tested several times in a tangent, directional application and J-shap wells in Burgan Field, South of Kuwait and achieved the fastest penetration rate in the application. The concentric dual diameter bit is composed of a smaller pilot and a larger reamer section, where the reamer section dictates the final drill size. Conventional fixed cutter bits take very little advantage of stress relieving the rock, as it only affects the borehole wall. Concentric dual diameter technology bits are able to initially drill with a leading smaller pilot section efficiently to relieve the stress of the rocks. Subsequently, the reamer section removes the stress-relieved rock with lower mechanical specific energy compared to regular fixed cutter bits, giving it the advantage to generate higher penetration rates. Another advantage of the concentric dual diameter technology bits is the stability of the bit, since two gauge sections are available to be in constant contact with the borehole while drilling. The first 12 ¼ in. concentric dual diameter technology bit in conjunction with directional 8¼ in. PDM (0.16 R/G, 7/8 lobes, 4 stages, 1.5 BH) BHA was tested in a directional application J-Shape well in Burgan Field, South of Kuwait. The bit was able to deliver improved performance by drilling the tangent section from 4345 ft to 6019 ft from Ahmadi to Burgan formation, total 1674 ft in 17 hrs with 98.4 ft/hr. The bit showed excellent steerability, building from 39 deg to 43 deg with 3 deg/100 ft max DLG severity. The section lithology consists mainly of Shale, Limestone & Sandstone. The performance capability was confirmed when the second bit run in conjunction with directional 8¼ in. PDM (0.16 R/G, 7/8 lobes, 4 stages, 1.5 BH) BHA was tested in a directional application S-Shape well in Burgan Field, South of Kuwait. The bit was able to deliver improved performance by drilling the dropping section total 940 ft from Ahmadi to Burgan formation. The bit showed excellent steerability, dropping from 15 deg to 0 deg with 3 deg/100 ft max DLG severity. The section lithology consists mainly of Shale, Limestone & Sandstone. The 12 ¼ in. concentric dual diameter was able to surpass the average rate of penetration for the same application in the Burgan Field by 56% saving the operator drilling time and making the concentric dual diameter bit design the top performing drill bit in the field.

There are two commonly methods to manufacture impregnated diamond bits at present: hot-pressing and the non-pressure immersion method. In order to test the performance of China impregnated diamond bit by hot pressing method and Ukraine bit with AKTM embedding in the lip surface by non-pressure immersion method, two types of drill bits were tested by the indoor bench drilling experiment and in geological core drilling located Jibaomiao mining area, using the same drilling parameters and the same granite formation which drillability was up to level 9.Test results showed that, the average mechanical penetration rate of China bit was 4.76 m/h when Ukrainian was 1.66 m/h; the average life time of China bit was 56.31m when Ukrainian was 25.38m. This paper analyzes the failure reasons of the two types of bits from the manufacturing technique and structure design. The research of this paper contributed to the design and manufacture of small-bore impregnated diamond bits.

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.

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.

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.

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

The LADC (International Association of Drilling Contractors) roller bit classification system provides a convenient method for categorizing rock bits according to their design features and intended applications. The system has been used worldwide since 1972. The 1992 version includes improvements which reflect the latest design trends in roller cone bits. This paper explains the IADC roller bit classification code. Current classification charts are shown for major bit manufacturers. The relationship between the LADC code, bit design factors, and operating guidelines is discussed. Examples depict the major design features included in the code. Since this version contains only minor changes from the 1987 Roller Bit Classification System,1 these changes will be listed at the beginning of the paper. Those experienced with the code need only read the changes. Subsequent paragraphs present a complete discussion of the classification system for the benefit of the readers who may not be familiar with the system or who wish more detail. IADC bit topics also updated in 1992 include Fixed Cutter Classification2 and Dull Bit Grading.3,4

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.

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.

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.