Improvements in computer aided design and computer aided manufacturing (CAD/CAM), along with improvements in dull bit grading, allowed optimization of bit design for specific applications.

Main body of a tool; the portion of a drill or similar end-held tool that fits into a collet, chuck or similar mounting device.

Each manufacturer has a slightly different design concept, and no one design seems to stop or prevent whirl in all situations.

The typical product life is about 2 years, and the number of variants of a particular design are increasing rapidly.

Sources such as service companies, operators, vendors, and investment bankers use various methods to gauge the success and growth of PDC bits in the drilling industry. Some market analyses include the number of bits sold or purchased, footage drilled per bit, or bit revenue.

General Electric introduced PDC in 1973. Bits with PDC cutters became commercially available the following year.

Much of this focus has been on making the diamond layer more abrasion resistant and reducing the stress behind the diamond layer. The bond between diamond layer and tungsten carbide stud is critical for a PDC bit.

Many formations in the U.S. are not well suited to PDC bits. Extremely hard rock and soft formations with hard stringers can often be drilled more economically with roller cone bits than with PDC bits.

PDC bits historically have found applications in relatively deep or expensive wells and in soft to medium hard formations. In these wells, the longer bit life, compared with roller cone bits, usually offsets the greater bit cost. ROP ultimately determines the economics of the bit run.

About 75% of the PDC bit market lies outside the U.S., say Diamond Products International Inc. and Security DBS. Many non-U.S. areas have relatively soft formations or are expensive to drill because of high rig day rates, remote or offshore locations, or deep wells. Those factors present favorable economics for PDC bit use.

To this end, he and his colleagues are engaging with their counterparts in Europe, where a robust operational excellence program is underway. The two teams recently met in Schaumburg for a workshop to begin baselining current production capabilities and share ideas on ways to further improve shop floor operations, among them future automation initiatives and the standardization of work documentation.

Cutters are no longer limited to a 13-mm round shape. They come in various sizes (8 mm to 19 mm) and shapes. A few companies have had success with dome shaped cutters.

Some of today's PDC bits can drill entire intervals that required two to three PDC bits or five to 10 roller cone bits only a few years ago. The big advantage comes in reducing the number of bit trips and increasing penetration rates, especially for deep wells or those with high rig costs.

Runs endmills and arbor-mounted milling cutters. Features include a head with a spindle that drives the cutters; a column, knee and table that provide motion in the three Cartesian axes; and a base that supports the components and houses the cutting-fluid pump and reservoir. The work is mounted on the table and fed into the rotating cutter or endmill to accomplish the milling steps; vertical milling machines also feed endmills into the work by means of a spindle-mounted quill. Models range from small manual machines to big bed-type and duplex mills. All take one of three basic forms: vertical, horizontal or convertible horizontal/vertical. Vertical machines may be knee-type (the table is mounted on a knee that can be elevated) or bed-type (the table is securely supported and only moves horizontally). In general, horizontal machines are bigger and more powerful, while vertical machines are lighter but more versatile and easier to set up and operate.

The rock strength analysis programs help an operator better determine PDC drillable intervals, make the optimum bit selection, and select appropriate drilling parameters. Such programs have been instrumental in expanding the number of formations drillable by PDC bits.

If peculiar wear is found, that information can be used to alter the design of the next bit. Most manufacturers can then redesign and build the new bit and have it on location almost anywhere in the world within a couple of weeks.

PDC cutters consist of a layer of bonded diamond particles backed up by a thicker layer of tungsten carbide.

Bit whirl patterns can cause the PDC cutters diamond table to chip or spall, accelerating wear and decreasing bit life.

BP ran a 171/ 2-in. Hycalog PDC bit on the BA-X14 well in Colombia's Cusiana field, where offset well BA-X11 on the same drilling pad required two PDC bits, one from Hycalog and one from another manufacturer, for the same interval

Enlarging a hole that already has been drilled or cored. Generally, it is an operation of truing the previously drilled hole with a single-point, lathe-type tool. Boring is essentially internal turning, in that usually a single-point cutting tool forms the internal shape. Some tools are available with two cutting edges to balance cutting forces.

Hughes Christensen has formed many successful alliances with operators. Many of such alliances focus on a technical objective.

Furthermore, operators in the U.S. still drill many shallow wells. So the ability to reduce the number of trips or trip time is not as significant as in deeper wells.

Designing and building a new bit has become very fast, mainly because of advances in CAD/CAM and engineering practices. PDC bits have become a specialty tool, not a commodity that can be bought in large number in advance of need.

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“With 110 tools resident in the magazine, all I have to do on most jobs is pop in the fixture, run a probing routine to pick up work offsets, and push cycle start,” he said. “Setup times have dropped to maybe half an hour, whereas they were taking hours previously. On top of that, I expect that the Integrex and some of the other equipment will be running lights-out fairly soon. Considering Industry 4.0 and all the other technology that’s available today, that's where manufacturing is headed.”

There is no single solution to hydraulics problems at the bit. Each company has a slightly different technical perspective. The goal is to clean the bit effectively but not to erode it with mud flow through nozzles.

“When Ceratizit USA invested in its first mill-turn machines around seven years ago, I volunteered to move over to that department, because up until that time I'd spent my entire career almost entirely in the milling area," he said. "It turns out that was a very good decision that they purchased the Integrex and offered me that position due to my experience with live-tool lathes. That's what I've been doing for the past three years.”

Furthermore, the cost of tungsten carbide, used in the stud that holds the diamond, has increased during the past few years.

The last true revolutionary change in PDC bits occurred in the late 1980s after Amoco Production Co. identified bit whirl, an inefficient mode of drilling. New bit designs and changes in drilling parameters to combat bit whirl have drastically improved bit life and rate of penetration (ROP).

Rick Cahn knows as much about the KUB Trigon drill as anyone. He applied for an entry-level assembly and deburring job at Ceratizit USA’s (formerly Komet of America) Schaumburg, Illinois, facility in 1994—just a few months before the product’s debut—and has been there ever since.

As PDC bit design improves, the bits tend to drill longer intervals, and many can be used in several wells. In such cases, footage drilled per bit is more important than the number of bits used.

Cahn’s also made his fair share of KUB drills. As you’ll see, the manufacturing approach has changed a great deal recently, but it was once a "fairly lengthy process" that required multiple machining operations.

The chances are good that the logo inscribed on that revolutionary cutting tool spelled KUB. First introduced in 1977, Ceratizit’s Komet KUB product category of insert drills paved the way to easier, more productive and accurate holemaking. The century-old German cutting tool manufacturer—now part of the Ceratizit Group—took holemaking even further with the KUB Trigon in 1995, a design that continues to set today's indexable drilling standard.

PDC bits are most effective in very weak, poorly consolidated, brittle, hydratable sediments -- sands and silts, for example.

In one case, Exeter Drilling Corp. and Hughes Christensen formed an alliance to design a PDC bit that would drill wells in the Denver-Julesberg basin of the Rocky Mountain region fast but with reduced pump pressure. They codeveloped a 77/ 8-in. multiport PDC bit that drilled more than 75,000 ft without repair, averaging 103.2 ft/hr.

Economic success of the first PDC bits stemmed from high operating costs for the rig and use in very select geological intervals. In the early 1980s, PDC bits underwent true engineering to suit specific field applications.

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The U.S., by contrast, has many areas in which rig day rates are relatively low, especially onshore. That makes the economics of running PDC bits less favorable.

These bits, most of which use PDC cutters, generally drill the more critical, expensive wells around the world. Diamond bits account for almost one third of the world bit market, and sales exceed $200 million/year, the U.S. Department of Energy reports.

The technology to minimize downhole vibrations has yielded longer bit life, faster penetration rates, and reduced drilling costs.

Improvements in PDC bit stability, hydraulics, and cutter design have contributed to increased footage per bit in recent years. Roller cone bits also have shown improvement in performance.

Hardness is a measure of the resistance of a material to surface indentation or abrasion. There is no absolute scale for hardness. In order to express hardness quantitatively, each type of test has its own scale, which defines hardness. Indentation hardness obtained through static methods is measured by Brinell, Rockwell, Vickers and Knoop tests. Hardness without indentation is measured by a dynamic method, known as the Scleroscope test.

Advances in polycrystalline diamond compact (PDC) bits have sharply increased penetration rates(31588 bytes) in oil and gas wells.

PDC bit design improvements are driven by research, good engineering practices (finite element analysis, accurate analysis of dull bit grading, rock strength analysis, and the like), and fierce competition from other PDC bit manufacturers and the rock bit industry.

Improvements in ROP and bit life allow PDC bits to drill harder formations, previously thought drillable only by rock bits or tungsten carbide insert bits.

Commercial practical limits for PDC bit sizes have been 31/ 2-in. and 171/ 2-in. diameters. These limits are due mainly to economics, not technology.

Microprocessor-based controller dedicated to a machine tool that permits the creation or modification of parts. Programmed numerical control activates the machine’s servos and spindle drives and controls the various machining operations. See DNC, direct numerical control; NC, numerical control.

What's more, design improvements have allowed PDC bits to drill harder formations and soft formations with hard stringers, previously thought to be drillable only by roller cone bits.

For example, Enron Oil & Gas Co. and Diamond Products International have such an agreement in which Enron helped design a new PDC bit for an area in the Gulf of Mexico where PDC bits have been used successfully for years. Although previous PDC bits worked well in the area, changes in hydraulics design, cutter layout, and blade spiraling increased penetration rates 20-30%.

Veteran machinists might remember their first use of an indexable insert drill. Suddenly, the taper shank and Silver and Deming drills they’d been struggling with for years were obsolete, replaced by cutting tools able to drill holes at least four times faster than their high-speed steel, non-coolant fed counterparts. No more pecking, no more spotting drills or pilot holes, no more drill wander or stopping production to sharpen a worn drill bit—simply load up a fresh set of inserts and get drilling.

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At about $10,000-150,000 apiece, PDC bits generally cost five to 15 times more than roller cone bits. But a PDC bit run in the proper application can substantially lower total drilling costs despite the higher initial expense.

Diamond is 10 times harder than steel and twice as hard as tungsten carbide. Diamond also is the most wear resistant material known. It has a wear resistance about 10 times that of tungsten carbide. Diamond, however, is brittle and susceptible to impact damage.

Replaceable tool that clamps into a tool body, drill, mill or other cutter body designed to accommodate inserts. Most inserts are made of cemented carbide. Often they are coated with a hard material. Other insert materials are ceramic, cermet, polycrystalline cubic boron nitride and polycrystalline diamond. The insert is used until dull, then indexed, or turned, to expose a fresh cutting edge. When the entire insert is dull, it is usually discarded. Some inserts can be resharpened.

The bottom hole pattern (left) of a whirling PDC bit has an irregular pattern, whereas the bottom hole pattern (right) of an antiwhirl PDC bit shows smooth drilling.

Some companies use cutter force balancing, bit asymmetry, gauge design, bit profile, cutter configuration, and cutter layout to eliminate whirl. Other manufacturers control whirl through engineered cutter placement designed to create a net imbalance force, pushing against the borehole wall, to create a stable rotating condition.

Some operators and manufacturers prefer not to take part in such formal agreements because of the speed with which PDC bits undergo improvements. Bits often are left out of many drilling alliance agreements between operators and service companies.

Cahn now enjoys the title of lead CNC machinist for 5-axis. He said he enjoys working with the Integrex, and using it finds the manufacturing process for KUB Trigon drills is far shorter than it once was. The blanks are machined in Germany, heat-treated and ground, then delivered to the Integrex for final machining. Here, a RoboJob six-axis robot loads and unloads parts all day from a pair of pallets, freeing Cahn for more important work than machine tending.

This diamond/tungsten carbide interface can be made successfully with various geometrical shapes, instead of conventional flat surfaces, to reduce stress on the diamond face during drilling. As these premium cutters wear, there is more diamond remaining on the stud to continue cutting. This nonplanar geometry has significantly lengthened cutter life downhole.

Fluid that reduces temperature buildup at the tool/workpiece interface during machining. Normally takes the form of a liquid such as soluble or chemical mixtures (semisynthetic, synthetic) but can be pressurized air or other gas. Because of water’s ability to absorb great quantities of heat, it is widely used as a coolant and vehicle for various cutting compounds, with the water-to-compound ratio varying with the machining task. See cutting fluid; semisynthetic cutting fluid; soluble-oil cutting fluid; synthetic cutting fluid.

Cost of the bit may be only about 2-3% of total well cost, yet the bit can affect up to three-fourths of the total cost.

Another relatively recent advance is the use of polished diamond cutters. The polished PDC surface has a significantly lower coefficient of friction, preventing cuttings from building up on the cutter surface.

PDC bits usually have applications when long on-bottom times are important, oil-based muds are used, or water-based muds are used in nonhydrating formations. PDC bits also are advantageous for high rotational speed drilling, such as with a turbine or mud motor, or for drilling deviated hole sections.

The new bit drilled 1,338 ft in 145.8 rotating hr for an average ROP of 9.2 ft/hr. The two bits run in the offset well drilled a total 1,017 ft at an average ROP of 6.3 ft/hr.

One of the people helping to move the company in this direction is Steve Heckard, Manager of US Operations. He notes that Ceratizit USA is pushing further in this direction via numerous continuous improvement initiatives. These include offline presetting of cutting tools, quick-changeover workholding like that used on the Mazak, and greater use of machine probing, all in an effort to reduce setup time wherever possible. “Despite the fact that some standard products may run in the thousands, production jobs of one to five pieces are common, with many specifying custom parts they will never see again,” said Heckard. “We very much have to operate with a job shop mentality here, and that means focusing on our changeovers.”

Even though PDC bits may be considered a specialty tool, their use is still governed in most instances by economics. The decision to run a PDC bit often focuses on cost per foot or total well cost.

They also can be used in low strength, poorly compacted, nonabrasive, shallow sediments, precipitates, and evaporites -- for example, salts, anhydrites, marls, and chalk -- and in moderately strong, somewhat abrasive and ductile formations such as silty claystone, siliceous shales, porous carbonates, and anhydrites.

"After my first year, they let me apply for the apprenticeship program, and four years after that, I graduated to the CNC machining department,” says Cahn. “Since then, I’ve worked on everything from our standard product lines like drills and cartridges to all manner of special tooling—chamfer tools, boring bars, form cutters ... you name it.”

He notes that the best way to address this is for Ceratizit and the manufacturing community overall to begin building partnerships and relationships with community colleges, vocational-technical institutes, and high schools, investing in the next generation of talent now so that shops will not be even more short-handed in the years to come. "There are some great opportunities in manufacturing, and it’s our task to educate young people on these opportunities and attract them to the rewarding, good-paying jobs that we and others are offering," said Heckard.

Exeter received proprietary rights to the bit, and Hughes Christensen developed a new bit it could manufacture for costs similar to that of old style bits.

Operators and bit manufacturers have developed many ways to prevent bit whirl and overcome or minimize it when it shows up.

One of the biggest limitations on high penetration rates is the need to avoid overheating the PDC. The PDC wafer and tungsten carbide base have different coefficients of thermal expansion, which can lead to cracking at high temperatures.

Historically, two factors have been mainly responsible for limiting the operating range and economics of running PDC bits: shortened life because of cutter fracture and slower ROP because of inadequate cutter cleaning.

Larger hole sizes are generally thought uneconomic for PDC bits because large holes are typically shallow and easily drilled by roller cone bits. The high cost to manufacture such large PDC bits usually is not justified. One operator in South America, however, used recently 26-in. PDC bits with success.

Hughes Christensen(27064 bytes) predicts diamond bits will account for almost 25% of world footage drilled by 1997. About 10 years ago, PDC bits had only 10% of the market.

Today's PDC bits drill about 1 1/ 2 times faster than comparable PDC bits in use only 2 years ago. The polycrystalline diamond now used is about twice as abrasion resistant as the diamond used 2 years ago. Many of these types of improvements are considered fine tuning or evolutionary changes in design.

During whirl, the instantaneous center of rotation of the bit changes, instead of staying in line with the borehole center. Cutters can move laterally and even backwards relative to the local rock surface.

The biggest change in the PDC bit industry was identification of bit instability, or bit whirl, by Amoco and the subsequent antiwhirl bit designs. Basically, bit whirl is any deviation of bit rotation from the bit's geometric center.

"Back then, we used a pair of CNC lathes and a rotary table-equipped machining center to rough turn both ends, drill the coolant holes, and mill a pair of straight flutes, after which the partially completed drill would go into an induction heating device,” he said. “There, it was brought up to 1000 degree F or so in less than ten seconds and then twisted to generate the spiral flutes."

Recent advances in metallurgy have allowed use of various PDC cutter geometries. These cutters are less susceptible to breakage and can withstand stress better.

Although most PDC still comes from General Electric and De Beers, several smaller companies have begun making high quality diamond wafers. This increased competition has not reduced cutter cost, mainly because PDC manufacturing is an expensive, capital intensive process.

Machining operation in which material is removed from the workpiece by a powered abrasive wheel, stone, belt, paste, sheet, compound, slurry, etc. Takes various forms: surface grinding (creates flat and/or squared surfaces); cylindrical grinding (for external cylindrical and tapered shapes, fillets, undercuts, etc.); centerless grinding; chamfering; thread and form grinding; tool and cutter grinding; offhand grinding; lapping and polishing (grinding with extremely fine grits to create ultrasmooth surfaces); honing; and disc grinding.

Much of the knowledge on how to run PDC bits properly flowed from Shell International Petroleum Co. Ltd.'s research on torque and vibration problems, Amoco's antiwhirl developments, and work by other major oil companies and service companies.

As PDC bit use has become more widespread, directional drillers and drilling engineers have become more familiar with the proper operational parameters to run a PDC bit successfully in a given formation. Those parameters include weight on bit, mud pressure, flow rate, and rotational speed.

When cool, the drill was sent back to the CNC department for finish turning, milling of the insert pockets, and then heat-treated to the desired hardness. This was followed by cylindrical grinding of the shank and some additional machining operations on the drill's front end to make the insert pockets perfectly true. As Cahn stated, it was a lengthy process, but has since been streamlined somewhat by the addition of some very advanced machining technology—an Integrex multitasking center from Mazak.

Increased use of automation notwithstanding, they’re also searching for solutions to another problem, one that plagues manufacturers across the United States: the shortage of skilled workers. “I think one of the biggest challenges right now—not only for us but for the industry at large—is developing a pipeline of talent to one day fill the shoes of machine shop veterans like Rick [Cahn]. These people have lots of experience that will be difficult to replace.”

Machining operation in which metal or other material is removed by applying power to a rotating cutter. In vertical milling, the cutting tool is mounted vertically on the spindle. In horizontal milling, the cutting tool is mounted horizontally, either directly on the spindle or on an arbor. Horizontal milling is further broken down into conventional milling, where the cutter rotates opposite the direction of feed, or “up” into the workpiece; and climb milling, where the cutter rotates in the direction of feed, or “down” into the workpiece. Milling operations include plane or surface milling, endmilling, facemilling, angle milling, form milling and profiling.

Some of General Electric's original PDC patents expired during the past few years, opening the market to many small PDC manufacturers.

Many operators still prefer to choose the bit themselves, usually with assistance from the manufacturer. Manufacturers agree that the most prudent method is to choose a bit based on the interval to be drilled, not on purchase agreements or inventory on hand.

CNC machine tool capable of drilling, reaming, tapping, milling and boring. Normally comes with an automatic toolchanger. See automatic toolchanger.

PDC bits generally work better in oil based muds than in water based muds. Oil-based muds, however, are not viable options in many areas because of environmental regulations and the high cost of disposal or treatment. As a result, many operators may use water based muds.

For example, BP Exploration Co. (Colombia) Ltd. used only one newly designed PDC bit in place of two other PDC bits to drill an interval in a well in Colombia. It saved $419,000 because of the faster ROP and one less bit trip.

Workpiece is held in a chuck, mounted on a face plate or secured between centers and rotated while a cutting tool, normally a single-point tool, is fed into it along its periphery or across its end or face. Takes the form of straight turning (cutting along the periphery of the workpiece); taper turning (creating a taper); step turning (turning different-size diameters on the same work); chamfering (beveling an edge or shoulder); facing (cutting on an end); turning threads (usually external but can be internal); roughing (high-volume metal removal); and finishing (final light cuts). Performed on lathes, turning centers, chucking machines, automatic screw machines and similar machines.

Several service companies and operators use rock strength analysis computer programs to determine the hardness of formations in a well. These computer models use well log analysis techniques and empirical formulas to determine the confined compressive strength of formations to be drilled.

Grinding operation in which the workpiece is rotated around a fixed axis while the grinding wheel is fed into the outside surface in controlled relation to the axis of rotation. The workpiece is usually cylindrical, but it may be tapered or curvilinear in profile. See centerless grinding; grinding.

Advances in metallurgy, hy- draulics, and cutter geometry have not cut the cost of the bits. Rather, they have allowed PDC bits to drill longer or more effectively in a greater number of formations. Another key advantage of these design improvements is the ability of PDC bits to withstand hard formation stringers.

Some new synthetic muds, based on mineral oils or glycerin, and friction-reducing additives for water base muds have helped improve PDC bit penetration rates compared with that in typical water based muds.

Bit whirl can be caused by cutter/ rock interaction forces and things such as formation characteristics and undesirable bottom hole assembly motions. Conventional PDC bit technology provides little resistance to whirl and may reinforce whirl once it starts.

Bit performance economics are measured in terms of cost per foot drilled. This involves factors such as bit cost, footage drilled, time spent drilling, trip time, and daily rig costs.

The use of dual powerhead motors, basically two positive displacement mud motors in tandem, has helped stabilize downhole torque. Other improvements in bottom hole assembly components have helped minimize torque and whirl problems.

PDC bits are less effective in hard, cemented abrasive sandstones, hard dolomites, chert, and granites.

Round cutters with a buttress or beveled edge have significantly improved PDC bit performance in several areas. These cutters have worked well in applications in which cutting elements are subjected to high impact loads, such as in hard formations, dynamically unstable drilling, or highly interbedded formations.

Grooves and spaces in the body of a tool that permit chip removal from, and cutting-fluid application to, the point of cut.

Some operators and manufacturers work together informally, usually to improve bit design by adding specific features to suit a given formation.

If the price premium for a PDC bit is less than the value of the saved drilling and tripping time, the PDC bit will be the most economic choice.

In general, positive displacement mud motors last longer during drilling. Therefore, bits have to be robust to keep up.