Decades after invention of polycrystalline diamond cutters, PDC bits edge out roller cones with advances in cutters, stability, hydraulics
By Dan Scott, Baker Hughes
Editor’s note: This is an excerpted version of an article that appears in a new Drill Bits e-book that will be available through the IADC bookstore and e-bookstore later this year.
Since the invention of the carbide-supported polycrystalline diamond cutter (PDC) by General Electric in 1971, this technology has impacted nearly all material removal industries. This article will trace the history and significant milestones of PDC technologies in the oil and gas well drilling industry since their introduction. This article will focus on advances in synthetic diamond cutters, bit design and other factors that have significantly increased drill bit performance and drilling efficiency to a point where PDC bits have taken over most applications once dominated by the venerable rolling cone bit, introduced by the Hughes Tool Co (HTC) in 1909.
Over the years, the key bit company customers have insisted on pushing the technology and performance envelope, not allowing the PDC cutter to become a commodity item. As a result, PDC cutters, inserts, wear parts and bearings for oil and gas drilling products are, arguably, the largest segment of the super-abrasives industry. This technology is playing a significant role in changing how and where oil and gas wells are drilled.
Early PDC cutter development
After being introduced into the drilling industry at HTC by GE Carboloy in late 1972, the PDC cutter and bit technology progressed slowly for several years.
The early cutter was available as a carbide disc 0.330-in (8.38-mm) diameter by 0.110-in (2.8-mm) thick, with a 0.020-in (0.5-mm) thick PDC layer that was un-chamfered. A Compax “slug system” that later became known as the stud cutter was also available where the PDC blank was brazed to a carbide stud for easier attachment into steel body bits to allow design freedom (Figure 1).
The braze alloy, BAg-1, was chosen for this attachment to keep the temperature of the cutter below the thermal degradation temperature of the PDC layer. Much of the initial laboratory testing was directed to demonstrate that the PDC cutter could replace the natural diamond “surface set” bits that were then used in the hardest and most abrasive formations. The focus switched in the next couple of years to the soft to moderate formations typically considered “steel tooth roller cone applications” at the time.
A year before the PDC cutter was introduced to the oil exploration industry, there had been the major introduction of the innovative “O” ring sealed journal bearing tungsten carbide insert (TCI) bit by HTC. This bit provided a step-change in performance, with bit life and reliability increasing several fold. Other established roller cone bit companies were focusing their technical staff on introduction of their own versions of the sealed journal bearing TCI bit. It quickly dominated the marketplace. These innovations were both introduced at the time when the oil drilling industry had been in a steady declining market for 15 years.
With the discovery and ongoing development of the large oilfields with high volume production rates in the Gulf of Mexico, Persian Gulf countries, North Africa and other places, the need to drill wells in the heavily explored North American basins was less attractive. It was hard to absorb both drill bit innovations with the same technical and economic resources, and the “O” ring sealed journal bearing TCI bit employed known application and drilling technology and was readily accepted by the drilling industry customers. This slowed the introduction of PDC technology.
Early commercial development
In July 1973, GE had arranged for the first test run of one of its early bit designs to be made on an Exxon well on King Ranch in South Texas. Bit cleaning was thought to be an issue in portions of the run; three cutters failed at their braze joint, and two cutters broke through the carbide studs. Subsequently, a second bit with improved hydraulics to focus on the cleaning of the cutters was run in Hudson, Colo., where it was reported to have drilled fast in a sand-shale sequence, but it deviated significantly from the prescribed well path and again suffered several lost cutters due to suspected braze joint problems.
In April 1974, the third bit was run in San Juan, Utah. It had an improved stud design and improved bit profile. It replaced three mill tooth bits on an offset well but suffered from a lost nozzle and damage to the bit, thought to have occurred at the end of the run from running into a hard formation or from the lost nozzle. A fourth bit, this time a mineral exploration core bit, was run in early 1974 in an iron mine in Upper Michigan, drilling into hematite strata, where the offsets were typically natural surface set diamond bits.
Through 1974-76, cutter improvements were evaluated by established bit companies and entrepreneurs. Many of the issues that had been identified were addressed. The solutions were incorporated into the Stratapax product line of PDC cutters, which was introduced commercially by GE in December 1976. The product line included the original 8-mm and new 13-mm cutters and a longer substrate (LS Bonded) design that facilitated attachment onto bits and provided a more impact-resistant cutter. Several shapes and configurations became commercially available (Figure 2).
While PDC cutter technology was introduced at a low point in the drilling market, the new PDC bit was being introduced against the backdrop of a major boom. The number of active rigs drilling for oil and gas in 1977 was at a 20-year high (3,444 in December 1977).
Many early successes and studies were being reported at industry technical conferences and associated literature from 1977 to 1979.
Many individuals and companies were experimenting with this new PDC cutter and developing bits to utilize them. Diamant Boart reported limited success in drilling salt formations in the Persian Gulf and the North Sea in 1974 and 1975, while the cutters were still in their infancy and developments were ongoing. Entrepreneurs Ken Davis and Dusty Hicks experienced some success in South Texas in the late 1970s. The first widely applied PDC bits were developed by Drilling & Service (D&S), led by John Barr in the UK North Sea, and Stratabit led by Mahlon Dennis and Bill Mauer in the US. Eastman Christensen had some success in prototype bits in the North Sea as early as 1976.
Innovations like chamfered cutters, non-planar interfaces, fishtail bits and rental and repair of the bit versus sale of the bit, were pioneered by Stratabit. Major oil companies like Shell were conducting their own research and working with bit suppliers to develop bits and to understand the best way to apply this new technology. It was a period of much innovation and learning, although the rate of penetration of PDC technology into the drill bit market was still slow.
Expansion and competition of the cutter market
Innovations in drilling practices, bit designs and hydraulics were introduced in the late 1970s and through the late ’80s. These improvements and continued technology developments in the cutters paved the way for the wider commercial success of the PDC cutter. Competition in the cutter field, a growing bit market and demanding customers in the bit companies helped drive the technology forward.
Valdiamant, the PDC department of Valeron, started in 1979 under the leadership of Bob Frushour, and by the early ’80s was supplying prototype cutters to the bit companies. Their entrance to the market was as a supplier of custom-made cutters with input and collaboration from the bit companies. They were instrumental in the development of the first commercially successful non-planar interface (NPI) cutter, the Claw Cutter, which was introduced into the market by Stratabit in 1984. This cutter dealt with the troublesome residual stress problems thought to be responsible for some of the table delamination of cutters and generally detrimental to cutter performance. Valdiamant was also the first to introduce the 19-mm cutter, now an industry standard.
Now know as Element 6, DeBeers Industrial Diamond Division (DEBID) entered the PDC cutter market in 1981 with both stud and cylindrical cutters. Both of the major synthetic diamond suppliers and most bit companies were now well engaged in the pursuit of commercializing the PDC cutter in drilling for oil and gas. The typical PDC cutter from DEBID had a 0.040-in. (1-mm) thick diamond table, which was substantially thicker than what was previously available from GE. The increased diamond volume provided improved toughness and wear resistance and dissipated heat better, which proved to be a benefit in certain applications.
DEBID became a significant supplier to the drilling market in the 1980s. By 1986, it had introduced PDC cutters up to 50 mm (2 in.) in diameter. There was a flurry of activity among some bit companies to develop very aggressive light set bits that could drill soft and sticky formations and could make use of the ultra-large cutters. Some designs resembled the fishtail drag bits, which the Hughes rolling cone bit had made obsolete some 75 years earlier. Later, in conjunction with a major bit manufacturer, DEBID pioneered the development and introduction of a layered diamond table cutter with a wear-resistant fine-grained diamond feed on the face, backed up by a tougher coarse diamond feed on a stress-engineered interface. This cutter feature became the foundation for a market-leading drill bit product line and was one of the highest volume cutters over its lifetime.
US Synthetic entered the PDC cutter market in 1983. Starting by working in collaboration with customer-driven proprietary cutter development programs focused totally on the drilling market from 1991 forward, they became the market share leader in 1997 and still hold that position. They are a leading supplier focused only on the drilling market. They were the first to commercialize a tough durable PDC cutter with what was the thickest and most impact-resistant diamond table in the industry at the time, and the first large company to be predominately customer-driven in their development activities.
The number of active oil and gas rigs hit an all-time high of 6,227 in December 1981, with 4,520 of these in the US. This is more than three times the number of potential drilling customers just 10 years earlier. Bit companies were rapidly introducing the improved bit and cutter technology to drilling customers, and the customers were becoming receptive to the new technology. The bad news for PDC bits was that only a very small portion of the US market was PDC-drillable with the technology available at that time, and the roller cone bit continued to be a dominating force in the market.
Through the early 1980s, the diamond tables delaminated from the substrate too often, and the bits lacked durability in many markets, with spalled, broken and chipped cutters dominating most dulls. The economics still favored roller cone bits in hard or interbedded formations. Bit hydraulic and cleaning improvements were still issues that were getting attention, with significant advancements yet to be made. Thermal stability issues were identified, and many developments were conducted in that technology.
There was a rapid growth in drilling activity in the late 1970s and early ’80s and a subsequent rapid fall driven by surplus supply and low oil prices in the mid-’80s. In this period of substantial contraction in the drilling industry, cutter and bit developments continued, and the amount of hole drilled by PDC bits showed a slow but steady rate of increase to 5% of the market by 1990. Innovations are frequently spurred on in such tough markets as suppliers, bit companies, contractors and operators look for any opportunity to reduce cost and improve efficiency.
The US drilling market reached a historic low in 1989, again in 1992 and nearly collapsed in 1999. Companies in the bit business were consolidating into a smaller but more financially viable number of competitors with more technical resources. These companies continued to develop and introduce new technology and improved drill bits to a very depressed marketplace. The major bit suppliers compete in a highly competitive market, where a technological or market lead can be fleeting. The properties of the cutters were gradually improved, and the long substrate cutter that had been introduced was much more adaptable to the matrix-style bit technology that was adapted from the surface-set bits and became favored for this product line. The ability to predict where these bits would work best was gaining momentum as application expertise was improved.
Most major oil companies were working with bit companies to develop new PDC drill bits and improved application techniques and to identify formations in which they could be successfully applied. Cutter and bit suppliers were also working to help provide this guidance to the customers.
Drilling through shale intervals could be problematic, and many papers dealt with a variety of solutions to this problem. Because most drilling involves significant shale intervals and there was potential to significantly reduce well costs, this problem was being worked on by universities, major oil companies, the US Department of Energy (DOE), bit suppliers and the PDC suppliers themselves. The studies and improvements in this area were continued well into the 1990s. Innovations in drilling fluids to control the bit balling phenomenon encountered in shale played a significant impact on the eventual success. Innovative patented bit designs were also keys to success in some applications.
Today, most bit manufacturers use computational fluid dynamics (CFD) as a part of their bit hydraulics design process. Bits may be optimized for cleaning, erosion or cooling, depending on the demands of a particular application.
Bit stability identification
By the late ’80s, the problem of fractured cutters and their terminal effects on bit life were being researched on a more global scale. Bit vibration and drilling dynamics were being studied by many in the industry.
At Amoco Drilling Research in Tulsa, Okla., a team led by Tommy Warren was researching the issue of cutter damage and bit performance. This team published seminal papers in oilfield literature describing the problems, observations and their patented solutions. Eastman Christensen commercialized these Amoco patents in an Anti-Whirl product line under an innovative license arrangement. Amoco and Eastman Christensen used the royalties to fund a jointly managed PDC bit R&D program to further the introduction of improved technology.
With the introduction of a stable bit frame, the benefit of improved cutter technology could be exploited. The improved bit gave the cutters a chance to drill without suffering high and catastrophic loads leading to massive cutter fracture. A step-change in reported footage was seen in the industry’s bit records, and the PDC bit market saw a step-change in growth with the introduction of this technology and the improved non-planar cutters that shortly followed. Between 1990 and 1992, PDC bits moved from 5% to 9% of the footage drilled.
Further developments continue to this day, with a significant effort on computer modeling of the bit’s expected behavior, cutter work rates, cutter loads, etc, in the drilling environment.
Another contributor to the success of the PDC cutter was the development of computer models, which helped to design and understand the behavior of PDC bits. Many dealt with balance forces on the bit, the rock-cutter interaction, and the drill string behavior and influence on the bit. A wide variety of these models were developed by universities, the US DOE, oil companies and bit companies. The more recent and more complex models developed and used by the major oil service companies combine influences of all of these factors. A significant amount of study was conducted on the thermal behavior and thermal management of the cutters. CFD is used extensively in the bit industry, as is FEA for cutter design, bit body strength and manufacturing processes. More recently, models are used to characterize the bit and applications to improve the process of matching the bit technology to the application requirements.
With the development of the stable bit, efforts could now be concentrated on improving the cutters. Understanding of the role that residual stress played in cutter performance and how to measure and manage it was coming into its own in the early 1990s. Finite element modeling became standard practice for understanding cutter behavior and cutter developments.
Proprietary cutters with non-planar interfaces and better residual stress management have become the norm in the industry, with a plethora of interfaces being patented by the PDC suppliers, bit companies, oil companies and individuals. It took several years, however, to go from the initial NPI cutter in 1984 to where the PDC suppliers were willing to entertain the idea of “designer” or “signature” customized cutters for larger customers and dealing with the inventory and manufacturing complexity it presented to the market. US Synthetic’s success at this custom cutter concept set the tone for the industry.
Another step-change was seen in bit performance with the widespread introduction of the NPI cutters to the stable bit frames in the early 1990s. By 1995, the PDC bits were drilling nearly 15% of the footage.
Many improvements to the diamond table were introduced from the 1990s and up to today. They have raised the durability, wear resistance, thermal stability and consistency of PDC bits and extended their application range. Cutters with diamond tables over 4-mm thick were introduced. These had the durability to extend the life of the bits through interbedded formations. A peripheral ring of diamond with a variety of nuances on the outside of a non-planar interface became a popular and near-standard feature on many cutters.
While most early cutters used a coarse uni-modal or bi-modal diamond feed, multimodal feeds became the norm in the 1990s. A unique layered diamond table cutter was commercially introduced in 1999, where a fine abrasion-resistant layer was backed up by a coarser impact-resistant layer over a stress-engineered interface. This is still a broadly applied cutter technology. These layered cutters offered further potential in abrasive and high-impact applications and were part of the basis for a new product line by a major bit company. One industry source reported it to be the highest volume cutter in the industry’s history.
Highly engineered, application-specific signature cutters were pioneered by Hughes Christensen. Being able to tailor the performance of the cutters through managing the residual stress, load-carrying capacity of the cutter, table thickness, wear resistance, diamond grit mixes, chamfer geometry, etc, allowed for application-specific cutters to be utilized in particular parts of the bit to optimize the performance and was protected by patents.
Improvements in chamfer technology and the use of multiple chamfers patented in 1995 became widespread in the mid-1990s. When properly utilized, the fracture resistance of a cutter during drilling increased by 100%, with a corresponding significant increase in a bit’s durability and length of run. Innovations in edge geometry continue to show further benefits, and Baker Hughes has successfully employed a dual chamfer in recent years. Another innovation was the introduction of a patented polished cutter for drill bits by Baker Hughes in 1995. Research in the laboratory had shown a marked reduction in friction of the cutter in certain formations, and this was proven in full-scale drilling tests and in field trials.
Leaching of the cobalt catalyst from the working surface of a PDC cutter, which had been studied by GE and Sumitomo in the 1980s but not commercialized, was re-discovered and patented for dill bits by Hycalog. The thermal stability of the PDC cutter is substantially better if the metal is removed from the interstices, allowing for the drilling of much harder and more abrasive formations where the heat generated at the rock-cutter interface can exceed the thermal stability limits of the cutter. Improved wear resistance in highly abrasive hard rock led to another step-change in PDC application range and growth, with further encroachment into the roller cone market.
The recent introduction of an innovative PDC-roller cone hybrid bit, patented by Baker Hughes, has blurred product classifications. This bit has enjoyed significant growth by demonstrating longer runs and smoother runs. It also has been well documented to drill with less vibration, leading to better durability and reliability of downhole tool electronics. The innovative hybrid bit combining a roller cone with a PDC bit met with many questions when introduced.
Recent research into rock-cutter interaction, chip formation, chip flow and other cutter behaviors led to the commercial introduction of a patent-pending PDC cutter with a contoured face profile that manages chip formation and behavior in a manner that also reduces the temperature of the cutter in service. Documented improvements have been measured in the laboratory and demonstrated in applications with highly interbedded formations.
Another recent development, introduced by Schlumberger, is the rolling PDC cutter. It is said to better manage wear from high temperatures. This cutter rotates in service, allowing the cutter edge to stay cooler, with success also reported in industry literature. Shaped cutters are another area of activity among several enterprises. It is another evolution with potential yet to be fully understood. How to best apply the ability to make shapes other than a flat round PDC will be an area of activity in the coming years.
With the significant improvement in diamond tables and the widespread growth of the rental and repair market for bits, substrate erosion became the controlling factor in PDC cutter performance through two breakdown mechanisms. One is erosion that is substantial enough to leave a diamond table standing proud and eventually breaking off. This is often misdiagnosed as a PDC cutter durability problem. The other behavior is erosion that is excessive and prevents an otherwise perfectly reusable cutter from being spun and reused because the braze joint is too large. This substantially raises the cost of the bit maintenance in the rental markets. Solutions to this behavior are being implemented by some bit suppliers.
Global PDC bit market
The growth rate for PDC has been relatively slow until the recent few years. Changes in the rate of growth were generally preceded by introductions of new technologies or market forces.
The first commercially successful runs known were by test bits designed by Diamant Boart in the Persian Gulf and North Sea in 1974 and 1975. Developments continued in most market areas but with a concentrated effort in North Sea applications; many of the successes in the late 1970s were in this high-cost market. However, despite the large amount of publicity and hype, in 1980 less than 2% of the footage in the world was drilled by PDC bits.
Through the 1980s, the focus moved to the Gulf of Mexico, which also had a relatively high-cost operating environment. By 1988, the Gulf surpassed the North Sea in terms of units used, but the North Sea still led in terms of market revenue. In 1988, approximately 1,200 PDC bits were run in the North Sea and nearly 1,300 in the Gulf of Mexico. However, revenue was approximately $25 million in the Gulf and $34 million in the North Sea. PDC bits accounted for less than 5% of the total footage drilled that year and just over 5% by 1990. By 2000, PDC bits accounted for 24% of the footage drilled.
Market impact now
Since 2000, PDC bits have rapidly expanded in application. Formations considered un-drillable by PDC bits a few years earlier were being drilled economically and reliably. The bits became able to penetrate formations with hard interbedded streaks. The rule of thumb for identifying the applications of an upper limit of 20 ksi unconfined compressive strength in the rock, if the drilling practices were managed well, was being broken.
Bit companies introduced application-specific bits with improved design and application review processes. Baker Hughes pioneered the process of running new bit designs through its drilling laboratory to confirm that the design objectives for rate of penetration and stability were met before the bit was shipped to the customer. These application-specific, customer-focused bit designs further extended the reliability and life of PDC bits.
Improvements to the modeling of the bottomhole assembly (BHA) was instrumental in the understanding and management of torsional oscillations and other modes of bit vibration that could lead to bit damage. Management of the bit vibrations through better BHA design has helped to extend the application range and reliability of PDC bits. Improvements to rig technology and downhole drive systems have also been a major factor in the rapid growth in PDC applications. Top drives, higher horsepower, better hydraulics and high-tech instrumentation on rigs and in drilling systems have been a major contributor. The introduction and widespread use of new high-torque motors and rotary steerable systems with highly instrumented MWD and LWD systems provide for better data and operating parameters, allowing the contractor to concentrate on making hole as the number of bits per well continues to decrease and the nonproductive time making trips is reduced.
Other design improvements provided a step-change in steerability for bits used in directional wells. Most offshore and many land wells are drilled using steerable assemblies to direct the bits to the target formations. Some of these wells employ a complex well geometry and target multiple oil reservoirs that may be only a few meters thick with a horizontal entry. Roller cones had traditionally been used for much of this as they are easily steered, while the traditional PDC bit with a higher operating torque and more fluctuations in the toolface had limitations in this area. New PDC bits with patented steerable features have been shown to markedly reduce drilling cost and reliably meet operator objectives.
In 2004, PDC bits accounted for approximately 50% of the revenue in the bit industry and nearly 60% of the footage drilled. Growth continued, and today it’s estimated that PDC bits comprise 75-80% of the market and drill more than 90% of the footage. PDC bits are now being used in nearly all of the North American land drilling applications.
After their introduction in the mid-1970s and their initial slow growth, PDC cutters have helped change the oil and gas exploration bit industry. PDC bits are now 75-80% of the bit market and still growing. The impact on the drilling industry has been dramatic, with today’s wells taking a fraction of the time to drill compared with 20-30 years ago. This has come from ROP that may be five to 10 times that of older drill bits.
Diamond elements for use in the bit industry has been one of the fastest-growing segments of the super-abrasive industry in the past 15 years, now accounting for, including captive sources, well in excess of $500 million by some estimates. Competition among the established vendors to make a step-change in PDC cutters, new entrants to the premium and near-premium cutter market and the bit companies continues to lead to innovative materials and processes, which continue to push the performance envelope. It is now one of the largest segments for the super abrasives industry, partially due to the substantial commoditization and price erosion in saw grits and wheel grits in the past few years.
This article is based on an invited paper first presented at the Diamond at Works Conference in Barcelona, Spain, in 2005, and was edited and updated for this article. Element 6 authorized the re-printing of the updated article. The author thanks Baker Hughes for allowing the time to compile and publish this and IADC for requesting it. The author is Dan Scott, Senior Technical Advisor at Baker Hughes and a Distinguished Member of SPE.