CREATIVE APPROACH TO OPTIMIZING DRILLING TOOL DESIGNS FOR GEOTHERMAL WELLS

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

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 performance model for Polycrystallíne Diamond Compact (PDC) bits has been modified to include the wear prediction of individual cutters. Wear predictions are based on the geometry of each cutter, the rock, type, the forces acting on the cutter, cutter velocity, and cutter temperature. The results of predicted and actual cutter wear for different 8-1/2 in. field worn PDC bit designs are shown. The worn geometry of each cutter was measured and compared to the model's prediction. Laboratory performance tests were also conducted with similar bit designs to quantify the effect of bit imbalance. Reduced ROP, drilling an overgage hole, and increased cutter wear and breakage can be the result of bit imbalance.

Experimental study on motion and mechanical characteristics of the vertical wheel in the rock-breaking process

U.S. Bureau of Mines field test results show that polycrystalline diamond compact bits used for coal-mine roof bolting, can last 200 to 600 times longer than tungsten carbide bits. During these tests it was also noted that the cutting edges of polycrystalline diamond compact bits remained sharp, they did not show any decrease in penetration rate, and it appeared that they generated less airborne dust. During these tests, however, it was not possible to measure the amount of respirable dust generated under controlled conditions. Laboratory tests were subsequently conducted to compare the respirable dust generated by new tungsten carbide and polycrystalline diamond compact bits. These tests were performed using a rotary drill test facility at the Rock Mechanics and Explosives Research Center, University of Missouri at Rolla. Respirable dust, as defined by a lognormal particle penetration curve with 50 percent penetration of 3.5-μm aerodynamic diameter, and a geometric standard deviation of [sgrave]...

Ultra-large diameter Polycrystalline Diamond Compact (PDC) bit drilling is a fast growing cost-effective solution in high-tier deepwater drilling operations in the U.S. Gulf of Mexico (GOM) where salt is encountered in the shallow part of the wellbore. Conventional design called for roller cone (RC) (IADC Code 111-115) drill bits on positive displacement motors (PDM) in these ultra-large diameter intervals. Cost savings on drilling fluid alone, in the form of Rate of Penetration (ROP) gains through the salt interval, has the industry trending to drill these riserless sections with the use of PDC drill bits on Rotary Steerable System (RSS) drilling assemblies. New robust high torque capacity top drives, stronger drillpipe connections, larger diameter RSS tools and improved mud programs have all largely contributed to this step change in drilling performance. Additionally, evolved bit and BHA design, efficient operating parameters, improved hydraulics and vibration prediction modeling have all aided in the success of these runs. Although this emerging new trend reduces drilling times and associated cost, experience has shown there are multiple challenges that must be overcome to complete a successful run in a single trip. These challenges vary from well to well and include, but are not limited to: BHA steerability, rig equipment limitations, efficient operating parameters, identification of both sediment and salt formations, hole cleaning and hydraulics, salt creep, drilling fluid displacement, drillpipe torque limitations, stabilization placement, lateral/ torsional BHA vibrations, and others. This paper will concentrate on the multiple aspects of ultra-large diameter riserless PDC bit drilling applications and the considerations that have been used to optimize them. Prior SPE papers and data from previous deepwater GOM case histories were heavily researched and scrutinized to support the conclusions provided within the body of this paper. Together with industry experience available, these findings have resulted in a set of defined recommendations, providing operators with a guide to justify a lower cost per foot approach through the potential reduction of drilling time in these challenging applications.

With the introduction of a new, wear-resistant polycrystalline diamond compact (PDC) bit cutter technology in recent years, the demand for increased torque output from the positive displacement motor (PDM) has dramatically increased. The commercial introduction of pre-contoured (i.e., equidistant rubber thickness) stators in 2000, solved the theoretical technical challenge of developing very high torque output in a PDM. Yet, in cost-sensitive land-based drilling markets where conventional power sections are still a major factor, the requirement for traditional motor power section construction restricted the rate of penetration improvements. Recent developments in the chemistry of the standard stator elastomer have enabled a step-change improvement in the performance and durability of the power sections in PDMs. This premium elastomer, manufactured in conventional stator cans, can generate higher differential pressure and subsequently more torque, while achieving increased durability, even in some of today's oil-based drilling environments. This higher level of torque and increased downhole durability is ideally suited for the increasing toughness and aggressiveness of today's premium PDC bit. This paper will review in detail this innovative motor technology, describe how it enables higher performance levels, and present several case histories illustrating this performance enhancement.

Stick/slip vibrations are known to cause damage to drill bits and other drilling system components. Recent investigations reported by the authors determined that the design of polycrystalline diamond compact (PDC) bits has a significant influence on stick/slip behaviour of the drilling systems. Among various bit design methodologies, a depth-of-cut (DOC) control technique has emerged as an effective way of mitigating bit-induced stick/slip. The research reported in this paper aims at enhancing this technique to accurately identify the optimal application of DOC control for maximum reliability and performance. A comprehensive testing program on a full-scale research rig was undertaken to characterize the optimal type, positioning, and extent of DOC control required for mitigating stick/slip. Several PDC bits incorporating strategically configured DOC control elements were designed and tested. The stick/slip tendencies of bits were determined based on diagnostics from downhole drilling dynamics monitoring devices while the surface operating parameters were varied in a controlled manner. Test results indicated that certain DOC control characteristics were the most effective in mitigating stick/slip. While under-application of DOC control did not mitigate stick/slip, over-application reduced performance without mitigating stick/slip. Formation type played a major role in instigating stick/slip, and was a significant factor in designing DOC control. The paper presents analysis details and proposes design guidelines based on testing in multiple formations within three research wells. These design guidelines are also supported by field evidence from the North Sea, where statistics on many bit runs indicate superior performance with properly tuned DOC control.

When drilling wells for hydrocarbon extraction, completing a specific interval of the well in the fastest time possible is a key requirement. One of the main contributing factors for improved performance is the drill bit. It is well known in the drilling industry that the stress state of the formation around the bit and drilled well is significantly lowered once penetrated by the bit. Conventional single diameter polycrystalline diamond compact (PDC) drill bits are not capable of taking advantage of this reduced effective rock strength. Dual-diameter bits address the identified challenges through the use of elegant physical principles and offer an efficient, reliable means of drilling. The concentric, dual-diameter design lowers the effective rock strength encountered by the critical shoulder-to-gauge area of the bit's cutting structure. The smaller pilot section of the bit design drills a pilot hole, which reduces the confinement and thus strength of the rock drilled by the larger reamer section. The reamer section of the bit is able to utilize the bedded pilot bit for stabilization to offset the greater forces associated with larger diameter drilling. The offset blade configuration of the bits also offers 360-degree contact the borehole and helps deliver a gun barrel hole quality. This paper introduces the development of a unique, two-stage, dual-diameter profile, and polycrystalline diamond compact drill bit for an application in Indonesia. Typically, multiple drill bits are required to finish the section, which consists of abrasive sandstone with some layers of coal. The objective was to improve the drilling performance while also minimizing non-productive time (NPT) for a bit trip. The paper provides and in-depth evaluation of the bit performance over several field trials. The first bit was run in a motor assembly and improved 14% rate of penetration (ROP) with exceptional dull condition. The drilling parameters indicated that the bit generated higher ROP with lower weight on bit (WOB) compared to other bit types. This performance convinced the operator to run the dual-diameter PDC bit in a more challenging field where its remarkable performance achieved field records. In comparison to the closest offset well, dual-diameter drill bits replaced three-bit runs with 56% longer intervals drilled and improved overall ROP by 41%. In addition, rig time was reduced by 5.3 days. The operator was extremely pleased with the bit performance and decided to use a dual-diameter PDC bit as the primary option to drill this section in every field.

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.

Summary Since backward whirl was discovered as a severe cause of polycrystalline diamond compact (PDC) bit failure, the oil and gas industry has made great strides toward creating whirl-resistant bits and operating practices. But is whirl still the major cause of PDC bit damage in conventional rotary applications? This paper reports on a recent field study in which downhole vibrations were measured by use of a newly available in-bit vibration-monitoring device. The focus of this study was to understand the primary source of bit damage. In addition, four wells were also drilled by use of a research drilling rig in Oklahoma. In these tests, the PDC bits, bottomhole assemblies (BHAs), and operating parameters were varied to document their effect on downhole vibrations. In these four wells, vibration measurements from the new in-bit measuring device were validated against a commercially available and industry-proven measurement-while-drilling (MWD) vibration-monitoring service. The results of this study indicate that the most common field vibration in hard-rock vertical conventional rotary drilling is stick/slip, not whirl. In field tests, stick/slip was observed almost exclusively. For typical field applications with a surface rotary speed of approximately 70 rpm, the team measured a peak downhole rpm as high as 500 during the slip phase. Stick/slip was identified as the primary cause of bit damage in these applications. Lateral vibration occurring during the slip phase correlated well with the observed damage and is proposed as a new mode of damage during stick/slip. The characterization of the lateral vibrations coupled with stick/slip is presented on the basis of downhole measurements.

Stick-slip vibration analysis of a coupling drilling-rock system with two delays and one delay-dependent coefficient

This paper details the step by step process undertaken by a dedicated focus group established to provide a solution to inconsistent drilling performance with the 16" section in a deep gas field on the Arabian Peninusular. The paper reviews the analysis undertaken as well as focusing on new design concepts and improved technology introduced. Drilling in these deep gas fields, especially the 16" sections has always been a challenge for Polycrystalline Diamond Compact (PDC) drill bits due to the complex lithology that consists of a variety of carbonates with high interfacial severity, followed by a highly abrasive sandstone and dense dolomite formations. Despite improving the ability to consistently drill the 16" sections in a single run over the past few years, the new challenge is to make further improvements to the consistency while at the same time providing further improvements in rate of penetration. Having experienced inconsistent performance and a series of premature PDC bit failures in these applications over the last few years the vendor assembled an integrated project team to investigate the issue. This team carried out an in depth analysis of all the available field data and identified several factors that were responsible for PDC bit damage, such as bit/BHA whirl, poor operating parameters with their associated vibrations and the limited ability of existing PDC cutters to drill such formations. The findings led to the development of a new PDC bit design solution with high lateral and torsional stability capable of drilling with high drilling efficiency, the introduction of new cutter technology; along with optimised operating parameters. The successful implementation of the new drill bit and recommended drilling parameters has enabled the operator to more consistently drill these challenging 16" sections in a single run at higher ROPs than previously achieved. This has resulted in significant cost saving for the operator.

This paper describes the step performance improvement of a 16’’ section in a UAE offshore application. Through close collaboration between directional drilling services, drill bits and operator, a 44% improvement in the section ROP from the field average was achieved. The novel solutions of bit and drive system and drilling practices which allowed for this improvement will be detailed in this paper. A key contributor to this achievement was utilizing a new hybrid bit technology platform which incorporates the dual cutting mechanisms of both polycrystalline Diamond Compact (PDC) and tricone bits. This allows for more efficient drilling through bringing together the improved ROP performance of a PDC bit and the reduced torque fluctuations of a tricone bit. Where initially drilled by tricone bits, the application posed potential for performance improvement, which was to be explored with this bit and BHA solution. Continuous optimization of drilling parameters was essential to minimizing the vibrations and improving the overall drilling efficiency. As a result of the proposed bit and drive system solution and the considerations in execution, the 4900ft long section was drilled in a shoe to shoe run, from surface to Fiqa formation. The unique compatibility between the bit design and the drilling motor allowed for exceeding the intended performance KPI set by the operator. The directional objectives were met as the well was precisely steered between offset wells with critical proximity, where the minimum ellipse separation expected was as low as 1.2ft. The new bit design was seen to not compromise the directional steerability as may be of concern with a PDC bit with a motor. The ROP achieved on the section was a 44% improvement from the field average. Given this being the first run from this new hybrid bit platform, this application still holds potential for further improvements upon design changes based on learnings from the first run. The outcome ultimately would be to take the conventional tricone drilling of this 16’’ section to a complete other performance level.