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.

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.

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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.

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%.

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.

Lamello users can now avail themselves of fast drilling and insertion on a variety of CNC machines made by Lamello’s partners that have been fitted with special aggregates and suit the needs of small craftsmen right through to flat-pack producers. We took the opportunity at Ligna to talk to several:

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

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.

“It makes the whole process extremely efficient and Lamello’s connectors are the ideal solution for customers who need the flexibility to flat pack their furniture without the quality being affected.”

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.

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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.

“We have been engineering solutions with Lamello for eight years. We were the first CNC producer to work with Lamello and at this year’s Ligna, we were pleased to present our first Centateq N-600 nesting machine, which has been designed to automatically insert the Cabineo.

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.

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

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.

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

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.

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.

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.

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.

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.

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.

“There’s also been great interest from high-production companies who are looking to improve productivity and reduce labour costs. We’ve calculated that this machine can insert one Cabineo every three seconds, making it extremely efficient. It’s this level of flexibility and innovation that makes Lamello an ideal partner for us.”

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.

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.

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.

“We were keen to show visitors just how versatile our products could be when partnered with Lamello’s P-System. Our stand featured several P-System-ready machines, including the NexTex 4.0, which can be modified to suit the needs of the customers. It has been designed to work with the Clamex and Cabineo and offers a completely digitalised production cycle.

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.

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.

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.

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.

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

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

“All of Biesse’s machines are predisposed to work with Lamello’s connectors due to the volume of interest in its product range. We offer complete flexibility across our range and as such, we have the possibility to create solutions that can work with one or more of Lamello’s connectors.

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.

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).

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.

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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.

“We are the first machinery manufacturer to create an aggregate that not only drills and routers the panel but also inserts the fixings, offering an extremely efficient way to use Lamello’s connectors. In this case, one machine really does offer a complete solution and we were excited to show live demonstrations throughout the show.

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

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.

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.

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.

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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.

“This is one of many innovations we’ve designed to work with Lamello which is, in part, due to the growing number of our customers using Lamello fixings. Homag has been a driving force behind automisation in the industry for many years and partnerships such as this add value to our product line and benefit our customers massively.”

“Building a partnership with Lamello is extremely important to us. Our aim is to connect the industry and create an ecosystem especially for the wood industry. Think of it as a digital shop floor that is open 24/7.

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.

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

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.

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

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.

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.

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.

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.

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

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.

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.

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.

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.

“At Ligna, we presented the Brema Vektor 15 CS vertical boring machine. It features a built-in unit for inserting glue and dowels but the beauty of this machine is its flexibility. It has already been customised to insert Lamello’s Cabineo and Clamex connectors automatically, making it the ideal solution for batch one manufacturers.

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

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.

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.

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“We want to work with forward-thinking companies that understand the importance of being part of a community and work with them to create new business models in the market. We think Lamello is a perfect fit for us and its experience in the sector shows commitment to the industry.”

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

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

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.

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.

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

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.

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.

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.

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.

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

“Our software, which can be used remotely, makes it really easy to select or adjust a cabinet’s dimensions – it even calculates how many Lamello connectors you will need to use on each design – simplifying the whole process. Once the data has been transferred to the machine, the CNC will format and drill all vertical holes and grooves and will cut-out the necessary channels for the connectors on the edges or in X and Y directions on the surface.

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.

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.

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.

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.

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.

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.

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.

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.

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

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

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 name Lamello is synonymous with jointing technology. On its Interzum and Ligna stands were solutions for fixing panels swiftly and easily, fixing shelves inside cabinets, jointing solid wood, and a full range of hand-held machines made by Lamello in Switzerland.