Oil sands applications are well known to be one of the most demanding drilling environments in the industry with regard to durability. The bodies of the cutters and the body of the bit experience severe wear in these applications, leading to inconsistent drilling performance. Extensive efforts in the past decade to solve this issue have been met with limited success. In oil sands applications, the sands are highly abrasive and unconsolidated. The result is that the sand particles quickly become suspended in the drilling fluid and mimic the effect of sandblasting the bit for the duration of the run. In many cases, the bit body wear around the cutters is extensive enough to cause premature bit failure due to cutter loss. The bodies of the PDC cutters themselves also suffer extreme material loss, which leads to cutter breakage and an associated reduction in drilling performance. Finally, in the lateral interval, the sands in cutting beds lying on the low side of the hole cause serious wear to both the gage and backreaming portions of the bit. This paper will discuss new technologies that have proven to eliminate bit wear in the horizontal reservoir interval. Comparisons will be made detailing the severe wear experienced with conventional bits and the absence of wear experienced with identical bit designs using a new body construction technology. A novel PDC cutter will also be presented that has been developed to eliminate cutter body wear. The requirements for improving drilling performance in oil sands applications are as unconventional as the wear experienced in these applications. Unlike traditional applications where improving performance includes an effort to drill faster or further, oil sands applications are typically control drilled and the entire interval is almost always completed in one run. The focus in these applications to augment performance is to improve directional control, enhance backreaming efficiency and hole quality, and increase bit durability. The new technologies detailed in this paper have proven to dramatically enhance each of these key performance indicators, resulting in the ability to drill further and faster, while improving the possibility of success of the well completion.
In heavy oil applications, drill bit body and PDC cutter erosion are frequently encountered challenges that can significantly affect the durability and overall drilling performance of the bit. Abrasive formations such as unconsolidated sands, drilling fluids with high solids content, and high hydraulic flow rates are all factors that limit the life of the drill bit, and consequently, there exists an opportunity to improve the economics of heavy oil wells through the development of more abrasion and erosion resistant body materials and PDC cutter substrates. This paper will discuss the various stages of research and development performed on drill bit hardfacing and PDC cutter substrate materials to improve durability and minimize repair costs in Canadian Oil Sands applications. Hardfacing development was accomplished through microstructural analysis, experimentation with various carbide compositions and particle sizes, and the incorporation of superhard abrasives (hardness values in excess of 5800 ksi) dispersed throughout the hard metal matrix. Moreover, the development of erosion resistant PDC cutter substrates was achieved through novel manufacturing processes and material research. Close cooperation with operators and the ability for rapid field testing of new technologies has enabled the collection of valuable feedback and performance comparisons between close offset wells. To date, a significant improvement in wear resistance has been achieved in hundreds of runs in the Canadian Oil Sands. These runs consisted predominantly of 10.625 in. and 8.750 in. diameter horizontal intervals, in which the operators typically observed a positive impact on drilling economics. For instance, reduced gage pad wear has resulted in fewer bits falling under-gage, thereby preventing the subsequent bit from having to ream the under-gage section to the correct diameter. Enhanced hardfacing life has reduced bit body erosion surrounding PDC cutters and other brazed components, thus decreasing the number of lost components due to the erosion of supporting material. Furthermore, PDC cutter substrate improvements have reduced the amount of observed carbide loss behind the diamond table in order to mitigate cutter breakage and preserve their formation shearing efficiency. Additional efforts are currently underway to further develop wear resistant materials tailored to abrasive and erosive drilling environments. These technologies have potential to enhance drilling efficiency and repairability of drill bits in heavy oil applications including, but not limited to, the Canadian Oil Sands.
The increasing emergence of hybrid drill bit technologies in recent years is pushing drilling performance to new levels that were previously unattainable by conventional designs. One example of a hybrid bit technology uses a combination of gouging inserts and shearing PDC cutters to increase the overall effectiveness of rock removal. In two and a half years of development, this hybrid gouging / shearing cutting structure has consistently demonstrated a superior average ROP over rollercone bits, as well as improved PDC cutter durability and lower reactive torque compared to traditional PDC bits. Until recently, the majority of gouging / shearing hybrid bit applications were in surface intervals drilled by six-bladed, 16mm cutter designs. This configuration is adept in enhancing ROP and durability in challenging formations such as gravel and boulders, which normally cause severe impact damage to PDC cutters. However, to push the benefits of the hybrid technology into new territory, significant design changes were made to optimize its performance in the newly targeted applications. In high ROP intervals, lowering the blade count of the bit has been shown to provide two key benefits: firstly, reduced cutter density increases the depth of cut and work rate for each PDC cutter, thereby increasing the aggressiveness and ROP potential of the design. Secondly, it enables more geometrical freedom for a hydraulic configuration that better suits high ROP and thermal demands. Unlike the six- bladed designs, the hydraulic layout of the reduced blade count designs incorporates separate nozzles dedicated to both the gouging inserts and PDC cutters on each blade. The ability to direct high velocity drilling fluid to both cutting structures promotes more effective cooling and removal of cuttings. The first instance of the updated hybrid technology was realized with a four-bladed, 12.25 in. diameter design used in a series of runs in Western Canada, drilling competent formations consisting primarily of shale with interbedded sandstones. The hybrid runs in these areas have exceeded the ROP typically achieved by six-bladed PDC bits in offset wells, and in certain cases, recorded average ROPs of over 310 ft/hr while still maintaining superior torque management throughout the entire run. Additionally, the dull conditions of the bits have repeatedly demonstrated reduced PDC cutter impact damage and thermal wear compared to conventional PDC designs. More development is currently underway to further expand lighter-set hybrid designs into more diverse applications.
Drill bit performance has a direct connection with the economics of drilling a well. While there have been impressive advances in both PDC and roller-cone drill bits over the previous decades, the rate of improvement has declined in recent years. New drill bit technologies are required in order to regain the pace of performance improvement, especially in large hole sizes. Traditional development cycles for novel drill bit technologies tend to be lengthy, with new products reaching commercialization after close to a decade, or more, of R&D. Critical new technologies are typically only developed by the largest oilfield service companies in the industry, which contributes to the pace of development. In order to deliver enhanced performance to the industry in months instead of years, an entirely new approach is required. As a response to this situation, a unique process has been created and implemented which has allowed a brand new type of oilfield drill bit to be commercialized within one year of the initial concept. This paper will discuss the performance of a new type of oilfield drill bit that has proven to reduce operating costs in large hole diameter intervals. This new type of drill bit has a novel hybrid cutting structure with both rotating, gouging inserts and shearing PDC cutters. This unique cutting mechanism has demonstrated improved performance compared to both PDC and roller-cone drill bits in hundreds of applications. The challenges associated with increasing drilling performance in large hole sizes are significantly different from intermediate and production intervals, and this paper will detail how those challenges are met by the new cutting structure. Worldwide, roller-cone bits have maintained a relatively large market share of sections that are 12-1/4″ diameter and larger due to their toughness, steerability and smooth drilling behavior compared to PDC bits. However, roller-cone bit performance is still limited by the durability of bearings, seals and teeth / inserts. The new hybrid gouging / shearing cutting mechanism provides similar performance benefits to roller-cone bits, such as excellent steerability, while providing durability superior to PDC bits. The introduction of gouging cutting structures into fixed cutter drill bits is an active area of R&D in the industry. For more than a century, drill bits have failed rock via crushing (roller-cone bits), grinding or plowing (diamond impregnated / natural diamond bits), or shearing (PDC bits). The gouging mechanism displays unique characteristics compared to conventional methods, and initially appears to be more suitable to many drilling environments.
One of the biggest ongoing challenges to the successful production of many natural gas reserves is the ability to improve drilling efficiency. In many of these applications, in order to drill the interval safely, it is necessary to drill through gas producing formations using high mud weight. As is well known in the industry, drilling with high mud weight poses significant challenges to drilling efficiency. Generally speaking, high mud weight equates to high solids content in the mud, and slow ROP for the drill bit, which means high hours to drill the section and frequent bit trips. Further to that, high hours and high solids equate to wear and erosion problems with bits and downhole equipment, leading to higher costs. A new line of steel bodied drill bits has recently been introduced that has shown dramatic improvements in drilling efficiency in Western Canadian foothills natural gas applications. The hydraulic configuration (blade shape & height, void volume, junk slot area, nozzle orientation and TFA flexibility) of the drill bit is of paramount importance in applications with high mud weight. Bit balling is very common in these types of applications, and is very detrimental to drilling efficiency. The ability to utilize a steel body, and to protect it from the typical erosion and wear that is seen in high solid environments, is critical to maximizing hydraulic performance. The new technology developed for these drill bits allows higher ROP in high mud weight applications, increased mechanical efficiency during the drilling process, and greatly enhanced wear / erosion resistance. Runs have been recorded in intervals with = 1750 kg/m3 mud weight and > 85 cP viscosity showing dramatic increases in ROP, with absolutely no erosive wear to the body of the bit, even after drilling for ~ 160 hours. This significant increase in ROP is a major breakthrough as less time spent in the hole means less wear and erosion on all downhole components. Introduction In one particular gas play in Western Canada, the Hinton field, drilling performance has been greatly hampered by the necessity to drill with high MW through highly interbedded formations. The Hinton field is located alongside the Canadian Rocky Mountains, approximately 290 kilometers straight west of Edmonton, Alberta, Canada and has a reputation of being a very challenging area for drilling. High bottom hole pressures, steep formation dip angles, hole instability, hard abrasive sandstone and siltstone formations and unpredictable and highly transitional / faulted formation layers are common. The application of study starts off after the 222mm intermediate hole section is completed and cased at an approximate depth of 3000m. The 156mm (6–1/8") main hole section is approximately 600m in length (approximately 3000m to 3600m), and is drilled utilizing an oil based mud system and a bent housing BHA (primarily to maintain verticality). Bottom hole pressures can frequently exceed 60,000 kPa and the interval is very faulted, with inconsistent transition layers of shale, sand, silt and coal seams with compressive strengths varying between 10000psi – 25000psi. The 156mm interval starts off in the Dunvegan, and drills down through the Shaftesbury, Base Fish Scales, Peace Rivier, and finishes in the Mannville.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.