Stephen Rassenfoss, JPT Emerging Technology Senior Editor
Competition among drill-bit makers can be measured by the performance of a thin layer of industrial diamond. It is both the cutting edge of the tools, as well as the technology race among competitors seeking a competitive edge. The thumb-size cylinders made of tungsten carbide topped with a thin layer of industrial diamond are mounted in pockets in the heavy metal heads of fixed cutter bits, which have become a key product line.
The ability of these fixed cutters to efficiently grind through rock has quickly made diamond drill bits the dominant bit design, representing 80% of the footage drilled worldwide last year. That represents a rapid shift in buyer preferences in a market where bits using roller cones were once as dominant. That allowed Schlumberger’s Smith Bits to grab the largest share of a dynamic market where rivals such as Baker Hughes, National Oilwell Varco (NOV), and Halliburton see opportunities to move ahead if they can find new ways to significantly increase cutter performance.
There are many factors in determining drill-bit success, but the one that gets the most attention is narrowing the performance gap between man-made and natural diamonds. Diamond bit demand growth has tracked the marked improvement in cutters. “Compared to the cutter of 10 years ago, a cutter today is 30 times more abrasion-resistant than they were. It wears 30 times slower,” said Rob Arfele, technology discipline manager for fixed cutter drill bits at Halliburton.
Given the marketing value of better cutters, companies are working on projects to continue this rapid pace of improvement. Achieving those gains will be a tall order. But there is plenty of room for performance improvement through better monitoring and control to prevent conditions that damage drill bits, he said.
Customer focus on the longevity of industrial diamond on the tip of the cutter will ensure that drill-bit makers, and their diamond suppliers, continue to aggressively seek ways to make tougher industrial diamonds. “Drill bit and PDC cutter problems and challenges are well known to the industry. The first company to market with solutions is likely to capture and maintain a market advantage,” Arfele said.
Unconventional onshore development has demanded mass production drilling, with efficiency measured by an ever declining number of days per well drilled. It puts a premium on longer drilling runs for cutters at a time when the force exerted by powerful new drilling rigs can generate extreme heat while grinding through rock. High temperatures can cause a polycrystalline diamond compact (PDC) to crack, oxidize, or turn into graphite, a soft form of carbon used in pencils.
“The critical edge is the cutter tip. The edge experiences extremely high localized temperatures,” said David Zhan, research and development manager at National Oilwell Varco Materials Technology. He has been using scanning electron microscope imaging under reservoir conditions to study the causes of failure as it happens.
NOV and Baker Hughes offered a detailed look at how they are using advances in materials science to build tougher polycrystalline diamond-tipped cutters. Baker Hughes is working on using nanotechnology to re-engineer the molecular structure of the PDC to make it tougher.
“There is work being done around using nanomaterials to improve PDC performance,” said Aaron Dick, PDC Cutter team lead of the Baker Hughes Drill Bits product line.
A common target of the work is cobalt, a critical ingredient during manufacturing and a costly problem thereafter. “The PDC depends on a distributed network of crystal strongly bonded together. The trick is to get them bonded together using a metal catalyst, which is generally cobalt. It is also what bonds the table to substrate material (tungsten carbide),” said Anthony DiGiovanni, a diamond research scientist at Baker Hughes. “Without cobalt catalyst, you would need to apply more pressure and heat than are commercially viable today. The problem is the cobalt remains, and when it heats up due to the intense abrasion common during drilling, that metal expands far more than the diamond and it starts breaking it apart.”
The expansion of cobalt causes cracks to develop, leading to failure. Using a scanning electron microscope, Zhan created movies showing what happens when PDC samples are heated under reservoir conditions. Ultimately the result is thermal failure, with irregular cracks appearing as the material darkens, turning the once uniform surface into something resembling the cracked mud at the bottom of a dried pond.
There is a treatment for the problem: leaching out much of the cobalt by soaking the PDC in acid. But that has its limits—some of the metal is sealed in spaces the liquid cannot reach and is left behind—and it comes at a cost. Leaching was invented by NOV, which collects royalties on the process.
“The whole industry is working on (improved) leaching” methods or some other way to further reduce the effect of cobalt, DiGiovanni said. “One of the emerging technologies that will help improve cutter technology is nanotechnology.”
Throughout the industry, the goal is a PDC cutter able to stand up longer to the high heat generated while grinding through hard, variable formations. The rule of thumb in the industry is that heat causes damage in PDC above 750°C and leaching can push that limit to around 1,200°C. A company finding a cost-effective way to push those limits higher could gain a valuable edge.
Baker Hughes has invested in nanotechnology development to create diamonds with an internal structure that minimizes the “mechanical binder” (cobalt) left behind, according to an SPE paper. That paper and patent applications filed by the company describe how it could use a mixture of particle sizes—incredibly fine bits of nanomaterial, and grains of diamond that are hundreds of times larger. When bonded by heat and pressure the smaller grains will fill the space around the big ones, crowding out the cobalt.
Researchers at Baker Hughes have been working to find ways to turn advanced materials science research into an industrial process in partnership with Element Six, the industrial diamond-making arm of DeBeers, whose name is a reference to carbon’s place as the sixth element listed on the periodic table.
One milestone for the partners has been developing a way to handle the minute particles, whose size gives them unique properties that are useful in the final product and trouble while making it. They are extremely small, with particles less than 500 nm and possibly far smaller, which is one reason they are in the realm of nanotechnology. Things that tiny have a powerful attraction to each other relative to mass. To put it simply, they tend to clump and require treatment to keep them apart in solution.
To overcome that obstacle, Baker Hughes had to find a way to “functionalize” them using a chemical coating that keeps them apart by balancing the natural attraction among the particles. In a jar full of water, the functionalized particles remain in solution for days. This is critical for diamond making because it allows the manufacturer to control the distribution of the nanoparticles in the finished product. Another option is the nanoparticles may also be functionalized in a way that attaches them to the larger particles, according to the patent application.
An experiment described in an SPE paper in 2012 used detonation nanodiamonds—carbon particles created by a controlled explosion and then processed to remove impurities. It allowed Baker Hughes to create a PDC cutter that has abrasion properties nearly as good as a leached diamond, according to the SPE paper. The paper predicted that as the cost of nanodiamonds goes down and production methods improve, this could be a way to improve drill bit performance.
Baker Hughes is working on a method that incorporates nanomaterials that will be predominantly diamond, but declines to offer details. The patent, filed in 2010, avoids offering a specific recipe for the process, leaving many options open. For example, the nanoparticles are said to “comprise at least one of a metal, a metal alloy, an intermetallic compound, a carbide, a nitride, and an oxide.”
While the company has made progress on nano-engineered diamond materials, it is a long-term effort. “It is extremely difficult,” DiGiovanni said. “There are a lot of challenges to overcome.”
While NOV is profiting from leaching and seeking ways to improve it, the company is also seeking other methods to reduce the problems caused by cobalt. In the past year, the company has been working to squeeze out more of the cobalt during manufacturing, Zhan said, adding the method is a trade secret.
Diamond properties can be managed by paying close attention to the quality of the raw materials, because “the diamond-diamond bond is very sensitive to any impurities,” Zhan said. How pressure is applied can affect the distribution of the cobalt, as does the size of the bits of diamond used to make it.
He has been comparing the particle size and a numerical ranking of strength, abrasion resistance, and thermal capacity, and has found there are trade-offs. He is always looking for ways to use less catalyst, perhaps ultrafine coatings on the diamond bits. “We can do better to minimize cobalt in the diamond table,” he said.
The path to better cutters will depend on improved failure analysis, Zhan said. Competitors in this business already spend a lot of energy examining used cutters to investigate what caused them to dull, which includes applying extreme magnification. Based on images made while heating PDC samples, he came to some conclusions that differed from the common wisdom.
Samples, which had not been leached, failed at significantly higher temperatures than commonly thought—around 1,000°C—and leached PDC began to come apart at 1,250°C. Both tests were done in a low vacuum and Zhan said the presence of oxygen would likely cause failure at a lower temperature. For that reason, he suspects that attaching cutters to drill bit heads using “vacuum cutter brazing” could reduce the risk of microcracks that could cause early failure.
When he examined the failure of cutters that had been leached, microcracks appeared within the diamond grains. According to Zhan, that is an indication that the diamond is being turned into graphite, indicating that graphitization may be more common than widely assumed.
Zhan said all of those may reveal problems offering avenues for making better cutters. “Cutter material characterization is the key to the next generation of cutter development,” he said.
A Broad Approach to Drill Bit Performance
The variables defining drill-bit performance cover a lot of ground. There is a lot of attention given to cutters studding diamond drill bits, but just as important are what is in the rest of the drillstring and the decisions made by the driller.
Companies looking for an edge in drilling performance are working on building tougher drill bits and better ways to control them to avoid destructive moments.
“To make a bit last longer, we have to look at the larger picture and take a systems approach to everything,” said Chris Charles, director of technology at Baker Hughes Drill Bits product line.
Below is a sampling of ideas, many of them presented at the recent IADC/SPE Drilling Conference and Exhibition in Fort Worth, Texas. It shows the range of possibilities from work performed by companies in the field.
When a drill bit is running, a relatively small part of the circular diamond edge on top of the tungsten carbide base is coming in contact with the rock as the bit rotates.
Schlumberger’s Smith Bits changed that fact of life with a new design that allows a cutter to rotate while drilling by placing it within a specially designed housing. The Onyx Roll Cutter 360 design is supposed to allow drill bits to stay sharp longer by constantly changing the cutting surface.
In a test by Chesapeake Energy in the Granite Wash reservoir, where the abrasive rock is hard on drill bits, the median life span for the rolling cutter was 1,152 ft, compared with 819 ft for the fixed ones, according to an SPE paper. This compared the results for 45 runs by the rolling cutter and 232 for the fixed ones in a formation with highly variable rock. While the rate of penetration was slightly lower—the median rate of penetration was about 9% less for the rolling cutters—the efficiency was improved by the reduction in the time lost changing drill bits.
A second study cited in the paper compared the performance on 4,500 ft laterals in the unconventional play straddling the border between Oklahoma and the Texas Panhandle. It said the new design lasted about 30% longer and penetrated slightly faster. In one well, only five of the rolling cutter bits were needed, down from seven to nine PDC bits in comparable wells.
The rolling cutters were located at key locations on the drill bit, which otherwise used fixed cutters. The rolling cutters were as reliable as fixed cutters, and the added cost of the new design is “not excessive when compared to the benefit,” said Robin Ford, a production planner at Schlumberger who presented the paper at the drilling conference.
The drive to speed drilling by modernizing is leading drillers to add new, more powerful rigs that are leaving their mark on the bodies of drill bits.
“We are getting a lot more energy to the drill bit than in the past and that is having an impact on the drill bit itself,” said Rob Arfele, the manager for fixed cutter drill bits at Halliburton. The large volume and pressure of the drilling fluid used to cool the cutters and clean away cuttings from faster-penetrating bits are also eroding the bodies of fixed cutter bits, shortening their life span.
“We are having to come up with more erosion-resistant body materials,” Arfele said. The starting point is the makeup of the metal used, seeking to increase the strength of composites made up of carbides held together by copper-based binders, which represent about 70% of the heads used. The rest is made of steel, which performs better in certain sticky well environments.
There is also more attention on managing fluid flows to ensure the velocity is sufficient to cool cutters and clear away debris, without eroding the metal around them, which can lead to them falling out. Halliburton is doing computer simulations using computational fluid dynamics, which is also used for tracking flow of air over aircraft wings or water over boat hulls, to visualize how a bit will perform.
Designs based on these insights have had a domino effect of putting a premium on improvements in foundry techniques to allow flexible production of more complex shapes to meet a wide range of customer requests.
Durability matters because the value of fixed cutter heads depends on how many drilling runs it can handle. While the cutters are usually replaced after a single run—the distance varies based on the toughness of the rock, with a 1,000 ft run being a good run in one and a bad performance in another—the heads can last for 100,000 ft of drilling.
A lot of formulas have been written to determine how weight, torque, and revolutions per minute maximize drilling performance.
Achieving optimum levels is another thing. What is known is the measures observed on a drilling rig, such as weight on the bit, revolutions per minute, and torque, are significantly different than what is seen by the bit. As the drillstring gets longer, the power at the face of the bit goes down. Another variable is that the drillbit is moving through rocks whose properties vary unpredictably. Instruments are being developed to measure what goes on the drill bit, and wired drillpipe is available, but real-time downhole monitoring has a way to go.
“Without that (real-time drill bit data), there will always be some level of speculation about what is happening downhole,” Arfele said. But the service companies are working to reduce that level of uncertainty by developing sensors that can be placed as near the drill bit as possible for an electronic device to gather better data.
Baker Hughes has recently upgraded a device that fits inside the shank of the drill bit—the threaded tube used to attach the drill bit—adding the ability to measure the torque and weight on bit to its original function, vibration monitoring. It tracks torque and the weight on the bit by measuring the various strains on the shank, said Jason Habernal, product development engineer at Baker Hughes Drill Bits.
Data recorded in the device, which records data that is analyzed after the bit is pulled, is used to see how decisions above affect performance below. Work by Baker Hughes found that the force applied by powerful drives on a drilling rig can be reduced to the horsepower found in a Smart Car in a long horizontal wellbore.
This matters because a failure to apply enough weight on a bit can lead to periods of vibration, and too much can cause it to stick and slip, either of which can quickly cause damage. Better measures of how a driller’s decisions affect bit performance can be used to learn how to drill later wells more efficiently.
While a good driller will adjust for power losses downhole, the force added to make up for losses requires judgment calls. Some of the same data is gathered by logging tools, which can send data back in real time, but moving the point of measurement back 100 ft results in significantly different results, Habernal said.
There is a mind-boggling number of drill bit designs. When Baker Hughes set out to create a new bit selection software program, it found more than 6,000 unique possibilities in its product lines.
In the past, it tried, and failed, to create advisory programs to make it easier to match the physical characteristics of the bits with a customer’s needs with results that led it to try a different approach.
The problem is that the number of variables is too long. It could start with the shape of the head, number of cutters, their location, their depth, the angle of the cutters, the metal used to make the head, the hard facing to protect it, and continue from there.
“There are hundreds of features on a bit you can name. It is so complex trying to figure out” how it will perform, said Charles of Baker Hughes. Instead, the company has created a database ranking its offerings based on “how bits perform, not on their features.”
Adding to the difficulties is the many possible interactions when features are altered. Change two things and there is a chance they will cancel each other out, said Chaitanya Vempati, product development engineer at Baker Hughes Drill Bits.
The new system is an answer to customers seeking technical justification for bit choices. Baker Hughes’ rankings mix expert opinions with 10 years’ worth of company data on laboratory tests, field performance, and computer simulations.
Criteria rated include aggressiveness, which determines how fast a bit can drill in favorable conditions, but that trait can be a negative in some rocks; how efficiently it can clean out cuttings; its lateral stability; and durability. Rankings have been based on comments by expert users, past performance-based lab testing, simulations, and field experience. This will be updated as new data comes in.
Coming this summer, the system will be available as an app for mobile devices.
The cutters on a PDC bit can be compared with teeth, and Baker Hughes has introduced a design that appears to build on the analogy. It recently introduced a cutter with a depression in the middle of the normally flat table of polycrystalline diamond compact, making the “nonplanar cutter” design rather like a molar.
The goal is to lessen the friction by narrowing the contact area of the rock it is cutting, reducing the heat that can cause the cutter surface to self-destruct. Laboratory testing showed that reducing the surface area of the contact area lowers the temperature by an average of 40% while reducing the force applied by 10%, according to an SPE paper. Temperature matters because a major cause of diamond cutter failure is high heat.
“It is a better cutting edge that lasts longer because we are keeping it cooler longer,” said Anthony DiGiovanni, the scientist doing diamond research at Baker Hughes, who presented a paper on the new design at the conference.
Based on testing in two formations with highly variable rock, the nonplanar cutters were able to drill from 12% to 37% farther, and could also drill faster, with a 10% to 15% increase in the rate of penetration.
For Further Reading
- SPE 157039 The Trick Is The Surface—Functionalized Nanodiamond PDC Technology by Soma Chakraborty, Anthony DiGiovanni, Baker Hughes, et al.
- SPE 168004 In-Situ Analysis of the Microscopic Thermal Fracture Behavior of PDC Cutters Using Environmental Scanning Electron Microscope by Guodong (David) Zhan, National Oilwell Varco, et al.
- SPE 167956 Constructing Difficult Colony Wash Lateral With Innovative Rolling Cutter Technology Improves Drilling Performance by Greg Bruton, Chesapeake Energy, Mark Smith, Smith Bits/Schlumberger, et al.
- SPE 16800 Innovative Non-Planar Face PDC Cutters Demonstrate 21% Drilling Efficiency Improvement in Interbedded Shales and Sand by David Stockey, Anthony DiGiovanni, Baker Hughes, et al.
- SPE 167917 Characterizing Drilling Applications and Bit Designs Using Common Responses Improves Bit Selection Outcomes by S. Craig Russell, Chaitanya Vempati, Baker Hughes.