whirl-resistance bit development

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Development of a Whirl-Resistant BitThomas M. Warren, SPE, J. Ford Brett, SPE, and L. Allen Sinor, SPE, Amoco Production Company

Copyright © 2012 Society of Petroleum Engineers

This paper (SPE 19572) was accepted for presentation at the SPE Annual TechnicalConference and Exhibition, San Antonio, 8–11 October, and revised for publication. Original

manuscript received for review 9 October 1989. Revised manuscript received for review 17September 1990. Paper peer approved 27 September 1990.

This is a reprint of a paper first published in the December 1990

SPE Drilling Engineering journal.

Summary

Bit whirl is a major cause of early failure and reduced performanceof polycrystalline-diamond-compact (PDC) bits. Attempts to con-trol bit whirl by stabilizing the drillstring have been unsuccessful,but a low-friction bit design has been discovered that substantiallyeliminates whirl. The low-friction design is based on placing thecutters so that the net imbalance force from the cutters is directedtoward a smooth pad that slides along the wellbore wall.

Introduction

The detrimental effects of impact loading on PDC bits have longbeen recognized, but most previous discussions of PDC bit wearhave concentrated primarily on thermal effects (Glowka 1987;Zijsling 1984; Prakesh 1986). Amoco Production Company’s fieldtests have shown that cutter failure, especially early in the life of abit, is more likely to be caused by impact damage than by thermaleffects. Impact damage is sometimes difficult to observe because itoften precedes and is destroyed by the subsequent thermally accel-erated wear that is frequently evident when dull bits are pulled.A reduction in the frequency of broken and chipped cutters, whichaccelerates cutter wear, would allow longer bit runs, faster ratesof penetration (ROPs), and possibly cheaper bits because fewerdiamond cutters would be needed.

Brett et at. (1990) describe bit whirl and show that it is thepredominant cause of impact loading. Whirl is defined as a condi-tion where the instantaneous center of rotation moves about thebit face as the bit rotates. This type of loading chips cutters and

accelerates cutter damage and wear for PDC bits.The objective of the research presented here was to extend use

of PDC bits into rocks that are too “ratty” (i.e., inhomogeneous)for acceptable performance from current PDC designs. Most ofthe field testing was conducted at the Catoosa test facility nearTulsa. Warren and Canson (1987) describe this test rig, and Winterset al. (1987) describe the site’s geology.

Bit Stability

Several papers (Glowka 1987; Warren and Sinor 1989; Sinor andWarren 1989) discuss the desirability of producing a bit with abalanced cutting structure. A balanced design is one in which thecutting forces acting on the cutters can be resolved into an axialforce or weight on bit (WOB), moment about the bit centerline (bittorque), and a near-zero radial force called the bit imbalance force.Because the magnitude of the imbalance force is almost directlyproportional to the WOB, the imbalance force is normally referredto as a percentage of the WOB.

Reasonably good analytical tools are available to evaluatethe balance of a particular bit design (Glowka 1987; Warren andSinor 1989; Sinor and Warren 1989). These tools provide a staticevaluation based on the assumption that the loads on all cuttersare constant for a full revolution of the bit. A general trend in theindustry is to apply these analytical tools to design bits with lowerdegrees of imbalance. Our measurements of numerous bits indicate

that a highly balanced commercial bit might be 2% imbalanced;

however, 10% imbalanced is more typical, and values greater than15% are not unusual. The imbalance of a particular bit designmay vary considerably from bit to bit as a result of manufacturingtolerances.

Although some evidence indicates that improvements in bitbalance will improve performance, low static imbalance alone isnot sufficient to prevent whirl. Figs. 1 and 2 show the bottomholepattern and the spectrum data for a bit with only 2% imbalance.There is no doubt that this bit whirled. Other similar tests confirmthat a low static balance will not prevent whirl.

In the case of bit whirl, the instantaneous center of rotationcontinues to move around the bit face. A dynamically stable bitmust have its center of rotation at a fixed point on the bit that is anode of stability. Any perturbation from this point must be resistedby a restoring force that moves the bit back to its original position.

The static analysis of bit balance can determine the force pushingthe bit away from a constant point of rotation, but it cannot tellwhether the bit will have a tendency to return to or move fartheraway from that point when it is displaced. This limitation of thestatic analysis results from the assumption that the cutter forcesare constant for a full revolution of the bit.

The restoring force necessary for a stable bit design can poten-tially result from forces that act on the drill collar above the bit,from features that are built into the cutting structure of the bit,or from stabilizer pads on the bit. No matter how the restoringforce is created, a relatively large force for a small displacementis required to prevent whirl.

Stabilization Above the Bit Face

In most rotating machinery, the problem of vibration and whirlis minimized by ensuring that the rotating member is properlyaligned, balanced, and adequately confined with tight-fitting, prop-erly spaced, low-friction bearings. A similar solution to bit whirlcould exist for drilling assemblies, where stabilizers are used as thebearings. If the stabilizers fit tightly in the borehole, then the stiff-ness of the drill collar is generally large enough to generate restoringforces. Unfortunately, this often is not the case because the hole isenlarged and/or because slightly undergauge stabilizers are used.

One major difference between most rotating systems and adrillstring is that the drillstring moves axially along a path cut by amember on the rotating system. If for any reason the hole becomesslightly overgauge, the bearings (stabilizers) fit loosely in the hole andthe string is unconstrained for small displacements. Once the bit iseven slightly unconstrained, it begins to whirl and the hole becomesmore overgauge. Once started, the process is self-perpetuating.

Stabilization mechanisms above the bit must fit tightly in thehole to prevent whirl and must not hinder the axial progression ofthe string. These two requirements are somewhat contradictory. Thebottom line is that the conventional bit and stabilizer system cannotreliably prevent whirl. Any perturbation at the bit that causes eventhe slightest overgauge hole will reduce the stabilizing benefit andthe hole may be further enlarged as the bit progresses. The verynature of the system where the bit and stabilizers rotate on a com-mon shaft dictates that the stabilizers cannot prevent bit whirl.

In a vertical hole, little force is required to displace the drill-string laterally if it is not confined by the stabilizers or forces onthe bit. In a directional hole, a force determined by the drill-collarweight, stiffness, and borehole inclination is required to move

the string laterally. This provides a damping that may reduce theeffects of bit whirl at higher inclinations.


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As Brett et al. (1987) discuss, high rotational speeds increasethe tendency for a bit to whirl, resulting in much larger sideforces and displacements. In most situations, these create a greatertendency for a bit to whirl when it is run on a downhole motorthan when it is rotated by the drillstring. There is also a greatertendency for the motor stabilizers to hang up on ledges causedby intermittent bit whirl. In cases where a motor is run and thedrillstring is rotated, an opportunity exists to uncouple the cuttingof the final hole diameter from the bit. This can be accomplishedby use of a slightly undersize bit and by stabilization of the motorwith a radial stabilizer preceded by an axial cutting section to cutthe final borehole wall, as shown in Fig. 3. Because the motor isrotated more slowly than the bit, the tendency to whirl is reduced.Consequently, the stabilizers have a much better chance of mak-ing tight contact with the wellbore wall. Another benefit of thisreamer/stabilizer combination is that, if the bit does whirl andcreate ledges, then the reamer on the motor body will prevent itfrom getting hung up.

A reamer/stabilizer was built and tested at the Catoosa testfacility. An 8½-in. bit was run on a 7-in., 120-stage turbine withan 8¾-in. reamer/stabilizer. The field test was conducted with the

same motor and bit that had exhibited a significant tendency toget hung up during drilling of the same section on previous tests.The reamer/ stabilizer assembly completely eliminated the hang-upproblem on the test well. It also seemed to reduce damage to thebit and allowed more footage to be drilled; however, according todownhole-vibration measurements and cutter chipping, it did noteliminate whirl.

Stabilization on the Bit Face

It does not appear likely that bit whirl during rotary drilling can beeliminated by a stabilizer located on the drillstring above the bit.Consequently, we evaluated several concepts for stabilizing the bitwith features on the bit face.

Brett et al. (1987) discuss what happens when a bit whirlsand show that very high centrifugal forces can exist that maintainthe whirl once it is started. Any technique for preventing whirlby modifying the bit face must be aimed at stopping whirl at thepoint where it starts. To do this, one needs a basic understandingof how whirl is started.

Consider Bit A, the hypothetical four-bladed bit shown inFig. 4, which is well-balanced according to the normal definitionof bit balance. The bit rotates about the point that requires theminimum torque, which in this case is the center of the bit. Whenhomogeneous rock is drilled with constant bit load, there is notendency for the bit to rotate “off center.”

If the bit is perturbed so that it moves slightly off center, theinstantaneous center of rotation can change quite severely. Forexample, if the bit is arbitrarily displaced 0.050 in. in the directionof Blade 1, the forces on the blades are radically altered, as shown

by the face-up schematic in Fig. 5. Figs. 6 and 7 show the cutterloading before and after the bit is offset. The circumferential force

Fig. 1—Bottomhole pattern showing evidence of whirl for a bitwith 2% imbalance.

Fig. 2—Frequency spectrum data for whirling bit.

Fig. 3—Reamer/stabilizer for preventing drillstring hang-up.



on Blade 1 increases from 3,414 to 4,764 lbf, which causes theinstantaneous center of rotation to move from the center of the bitto the point shown in Fig. 5.

When the instantaneous center of rotation is moved away fromthe center of the bit, the bit torque causes the load on Blade 4 toincrease and the loads on Blades 2 and 3 to decrease. The high

loads on Blade 4 cause the center of rotation then to move to apoint on that blade. This process continues and systematicallycauses the bit to “walk” around the hole.

As soon as the bit begins to walk around the hole, a centrifugalforce is generated that increases the side loading on the bit. Witha rotary speed of only 120 rev/min, the centrifugal force can be11,700 lbf for a borehole enlargement of 1 ⁄ 8 in. with an 8½-in. bit.This very high, sustained force associated with whirl can cause thewhirling condition to be much more stable than the nonwhirlingcondition. Thus, any whirl-arresting feature must prevent whirlfrom starting.

Cutter-Edge Geometry. Laboratory testing has shown that thecutter-edge geometry for new cutters is important from the stand-points of initiating whirl and of determining the tendency for thecutters to chip. A sharp, right-angle edge on a new cutter createsa very aggressive cutting surface that increases the tendency for a

Fig. 4—Hypothetical bit profiles.

Fig. 5—Top view of blade positions for Bit A.

Fig. 6—Cutter loading for Bit A before displacement. Fig. 7—Cutter loading for Bit A after displacement.



bit to “grab” and start to whirl. The sharp cutter edge is also muchmore prone to chip. Repeated testing with bits with chamferedcutters demonstrated a very significant reduction in the number of

chipped cutters that occur during laboratory testing.The chamfered cutters initially required about two times asmuch weight to drill at the same rate as the cutters with sharpedges. Quite often in field tests, the cutters with sharp edges chipearly in the bit run and the weights quickly become nearly thesame for bits with both types of cutters. Allowing this uncontrolledchipping to occur often damages long-term performance of thecutter more than chamfering the cutter. After the chamfered cuttersdevelop wear-flats, little difference exists between the chamferedand nonchamfered cutters.

Bit Profile. The center of rotation of a tapered bit is more sensi-tive than that of a flat bit to lateral displacement. Fig. 4 shows theprofile of three bits that range from very tapered to flat. Each bithas cutters laid out on four equally spaced blades. When Bits A,

B, and C are each displaced 0.050 in. toward Blade 1, the centerof rotation shifts by 0.69, 0.40, and 0.30 in., respectively. Thisshifting indicates that a flat-profile bit is less prone to whirl thana more tapered-profile bit.

The reduced tendency for a flat-faced bit to whirl was con-firmed by laboratory tests with various bits. In some cases, theflat-profile bit will drill a gauge, smooth hole at 120 rev/min.At turbine speeds, however, the hole in Indiana limestone can bemore than ½ in. overgauge. Even though the flat-profile bit showsa lower tendency to whirl, it still whirls under certain conditions.Another drawback of the flat-profile bit is that it severely reducesthe space available for cutters, especially when a bladed bit isneeded to control bit balling or when a high cutter density is neededfor wear resistance.

Deep Cone in Center of Bit. Cutters in a deep cone at the center ofa bit are loaded on the opposite side from those cutters outside thecone when the bit is laterally displaced. A bit with this arrangementnot only tends to resist lateral displacement, but the cutters insidethe cone tend to whirl in the opposite direction from the cuttersoutside the cone. Results from tests with commercially availabledeep-cone bits show a tendency for them to whirl less than manyother bits; however, they still whirl, especially at high speeds.

For shallower cones, the cone appears to be drilled away by thelateral movement as the bit whirls. This reduces the contact on theinside of the cone, and the bit impacts the formation primarily onits nose and flanks after whirl starts. The reduced contact of thecutters inside the cone often results in their being less damagedthan the nose and flank cutters.

The results of tests with these three methods of reducing bitwhirl indicate that they all worked to some extent, but within rather

narrow limits. Warren et al. (1989) describe two other techniquesfor stabilizing a bit with cutter placement and orientation (posi-tive siderake and stabilizing grooves) with similar results. All thetechniques rely on interaction between the cutters and the rock togenerate the restoring force necessary to prevent the start of whirl.A perturbation in the cutter loads resulting from formation inho-mogeneity or changes in WOB is often sufficient to cause enoughlateral movement of the bit so that the restoring force nonlinearlydecreases (by cutting away the rock) rather than increases asneeded. After the external perturbations that initiate whirl exceedsome level, the cutters destroy the stabilizing bottomhole geometry.The methods for stabilizing the bit with the cutters apparently have

a rather low limit of stability.

Low-Friction Gauge. Even though it is theoretically possible toeliminate bit whirl by stabilizing the bit with the cutting forces,actually doing so is difficult. The stability achieved by balancingcutting forces is similar to the stability achieved by adjusting therotors on a helicopter. What is really needed is a technique thatprovides a stability similar to that of a freight train rather thanthat of a helicopter.

A technique was discovered that provides much better stabilitythan any of the methods described earlier. The procedure uses alarge, noncutting wear pad to balance the forces created by the cut-ters (see Fig. 8). The vector sum of the cutting forces is directed toa pad that has a much lower frictional contact with the borehole wall

than the gauge cutters. Because the friction in the direction of theimbalance force is low, the bit slides at the borehole wall and doesnot begin to walk around the hole. If the pad is relatively wide, theforce on the cutters can change quite drastically without causing theresultant force to move off the pad. As long as the net radial forceon the bit is directed toward the pad, the bit will not whirl.

The low-friction idea was discovered by investigating why avery highly imbalanced (25%) 4¾-in. bit performed much betterthan any other bit previously tested at the Catoosa test site. [SeeWarren et al. (1989) for the details of this discovery.]

After studying the 4¾-in. bit, we modified an 8½-in. bit thatwhirled at 60 rev/min by removing 12 cutters outside a radius of2 in. to create a low-friction pad. Laboratory testing of the bitdemonstrated that it was stable at rotary speeds > 1,000 rev/min.Fig. 9 shows the bottomhole pattern for the bit at 60 rev/min before

modification and at 120 and l,000 rev/min after modification. Themodifications eliminated all evidence of whirl from the bottomholepattern. This is most amazing considering that the same bit vibratedso violently that it could not even be tested at high speeds beforeit was modified.

Fig. 10 shows vibration data for the bit before and after modi-fication. Roughly one-half of the cutters were chipped during thedrilling of just 2 ft of Carthage limestone in the laboratory beforethe bit was modified. Attempts to test the bit at high speed resultedin the borehole being enlarged to 0.75 in. and a stalled test drive.After the modifications, the borehole was completely gauge.

While discussing the benefits of the bit modifications with amachinist, it was discovered that a technique similar to the low-friction-gauge idea is used with gun drills to bore deep, high-toler-

ance holes. A gun drill typically has one or more cutting bladesthat extend from the center of the bit to the OD of the hole andtwo wear pads that stabilize the bit. This technique allows holesto be drilled with close tolerances, minimizes chatter of the toolthat results in a rough hole wall, increases the machining rate, andminimizes the tool wear. Osman and Latinovic (1976) discuss theprinciples used in gun-drill design.

Operating Procedures

Laboratory tests showed that when a bit first touches the rock, it isvery unstable. As the rotary speed increases, the stability decreases,but as the WOB increases, the bit becomes more stable. Fig. 11 shows an example of bit whirl as a bit first touches the rock at120 rev/min during a laboratory test. These low-weight vibrations

occurred even though a good pilot hole previously had been drilled.In some cases, the WOB must be increased to 3,000 to 5,000 lbf

Fig. 8—Schematlc of low-friction gauge bit.



before severe whirl diminishes. Similar vibrations are seen whenthe WOB is lowered to retrieve the bit off bottom.

Much of the impact damage to a bit apparently occurs fromlateral bit movement; thus, the energy that causes cutter damagecomes from the string rotation, not the WOB. Because the damageis caused by impacts, it can occur over a very short time periodand may occur while the driller is seating the bit on bottom. To

Fig. 9—Comparison of bottomhole pattern before and after bit modification.

Fig. 10—Vibration data for bit before and after modification. Fig. 11—Bit whirl observed as bit first touches rock.

minimize the damage that occurs when the bit contacts the rockwith low weights, the rotary speed can be reduced to less than 50rev/min when the bit is set on bottom and again when it is pickedup. This procedure was field tested and causes no operationalproblems.

Opinions differ about the best operating procedure to minimizedamage to the bit when a PDC bit is used to drill through a hardstringer. Some drillers think that it is best to lower the WOB andincrease the rotary speed (primarily to decrease the cutter tempera-ture), while others think that the opposite is better. Our researchindicates that it is much better to decrease the rotary speed and

possibly increase the WOB. This response should minimize impactdamage, but possibly at the expense of cutter temperature. Unfortu-nately, the transition from soft to hard rock may not be recognizedquickly enough at the rig site to prevent whirl damage.

A PDC-bit run often is terminated because the bit abruptlystops drilling and the torque decreases significantly. Fig. 12 shows a typical example of this from our Catoosa test site. Thebit was pulled 5 minutes after drilling stopped. Most of the cut-ters had slight wear-flats, typical of the one shown in Fig. 13, but



Fig. 12—Example of abrupt stop in penetration.

Fig. 13—Cutter wear on bit that stopped drilling.

Fig. 14—Geology at Catoosa test site.

none had diamond lips protruding above the carbide. This abrupthalt in penetration appears to occur most often when the bit isdrilling shale at a good ROP and then hits a sandstone stringer.

The diamond lips [see Brett and Warren (1990)] are sheared offthe cutters, prohibiting the bit from drilling the harder rock. TheWOB typically is increased until it is decided that the bit shouldbe pulled. This may drastically accelerate the rate of cutter wear.Fig. 13 also shows the same cutters after the bit was rerun at highWOB for an additional 44 minutes. Diamond lips were undetect-able on any of the cutters when the bit was pulled. Evidence suchas this indicates that much more of the cutter damage seen on dullPDC bits from the field may occur near the end of their runs thanpreviously thought.

Field Evaluation of Whirl-Elimination Techniques

Laboratory testing can be used to evaluate the whirl tendencies of abit by examining the vibrations during drilling and the bottomhole

pattern after drilling. In some instances, it can even show that thecutters are chipped during drilling of a very short distance. Butgenerally, the long-term effects of whirl cannot be demonstratedin the laboratory.

The Catoosa test site is a rather uncommon facility for thefield testing of bits to evaluate their wear characteristics. Because

the facility is operated strictly for research purposes, a bit can bepulled and examined at any point during its run. High-quality dataare collected, and the operating parameters for the bit are wellcontrolled. Because the test wells arc closely spaced, the geologyfrom one test to the next is very similar.

Fig. 14 shows the geology at the Catoosa test site. The primarytest section (200 to 1,350 ft) consists of soft shales; hard limestonesections; moderate-strength, thin sandstone stringers; and a shortinterval of abrasive sandstone. Other than being shallow, it is typi-cal of intervals that are difficult to drill economically with PDCbits because of the hard stringers.

Numerous tests were conducted at Catoosa to establish the base-line performance of various drilling techniques. Fig. 15 shows threetypical drilling curves representative of drilling with a roller-conebit, with a PDC bit on rotary, and with a PDC bit on a turbine. Theroller-cone bit can routinely drill the entire section, but the ROP withan 8½-in. bit averages about 55 ft/hr for the interval when run at 90rev/min and 40,000 lbf. The PDC bit on rotary initially drills muchfaster than the roller-cone bit, but rarely is able to drill the entireinterval. A PDC bit on the turbine drills at about the same rate as thePDC bit on rotary, but is damaged much earlier in the section.

To test the low-friction concept, a commercial four-bladed,8½-in. PDC bit was converted into a low-friction bit by removingall the cutters on one blade outside a radius of roughly 3 in. andrun at the Catoosa site. Before modification, the bit whirled readilyin the laboratory, as shown in Figs. 1 and 2. After modification,the bit was retested and all evidence of whirl was eliminated, asshown in Fig. 16.

The bit was run at the Catoosa site from 227 to 1,256 ft and

averaged 155 ft/hr, as shown in Fig. 17. This can be compared withthe performances of typical bits shown in Fig. 15.



Fig. 15—Typical drilling performance at Catoosa test site.

Fig. 16—Vibration data for low-friction bit.

Fig. 17—Drilling performance of low-friction bit at Catoosatest site.

The bit was pulled at 592 and 1,256 ft to inspect the cutters.No damage to any of the cutters was evident at 592 ft, but sixcutters began to show slight wear at 1,256 ft. Fig. 18 shows thelocations of the damaged cutters. Fig. 19 shows the most severelyworn cutter.

This test demonstrated that the elimination of bit vibrationsassociated with bit whirl improves not only laboratory perfor-mance, but also field performance of the bit.

Review

Bit whirl is a significant factor contributing to the early failure andreduced performance of PDC bits. Attempts to control bit whirlby drillstring stabilization alone have not been successful. Severaltechniques for controlling bit whirl by incorporating stabilizingfeatures in the cutting geometry have demonstrated some promise

but have not been completely successful. They reduce whirl ten-dencies and probably could be used to improve typical PDC bitperformance. With improved manufacturing tolerances, they mighteven be completely successful at eliminating bit whirl at rotaryspeeds below 200 rev/min. Research continues on the applicationof these techniques.

Use of a low-friction gauge pad to eliminate bit whirl has beenthe most successful technique tried. It can completely eliminatewhirl at rotary speeds up to l,000 rev/min in the laboratory andis relatively insensitive to slight variations in cutter placementresulting from manufacturing tolerances. The low-friction gaugeidea was successfully demonstrated al the Catoosa test facility. Thetechnology needed to design commercial bits according to the low-friction concept is still being refined, but the concept is proved.

The elimination of whirl is expected to make a significantcontribution toward extending the application of PDC bits into

rocks that are currently difficult to drill with PDC bits. It will notprovide a solution to all PDC bit problems, particularly abrasivewear and thermal degradation.

Acknowledgments

We thank Diamant Boart Stratabit and Smith International for

providing the standard and prototype bits used in this study. Wealso thank Jim Powers for processing the test data and preparingthe figures presented in the paper.



Fig. 18—Cutter layout of low-friction bit showing location ofcutter damage.

Fig. 19—Most severely worn cutter of low-friction bit.

References

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of PDC Bit Failure. SPEDE (Dec. 1990) 275–81.

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mance and Wear of PDC Drill Bits. Report, SAND86-174S.uc-66c,

Sandia Natl. Laboratories, Albuquerque, NM (Sept. 1987).

Osman, M.O.M., and Latinovic. V. 1976. On the Development of Multi-

Edge Cutting Tools for BTA Deep-Hole Machining. J. Engineering for

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Prakesh, V. 1986. Finite Element Method for Temperature Distribution

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Ductility and Cone Offset.” paper SPE 16696 presented at the 1987 SPE

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