Downhole Measurement and MonitoringLead to an Enhanced Understanding of

Drilling Vibrations and PolycrystallineDiamond Compact Bit Damage

L.W. Ledgerwood III, SPE, Jayesh R. Jain, SPE, Olivier J. Hoffmann, SPE, and Reed W. Spencer, SPE, Baker Hughes

Summary

Since backward whirl was discovered as a severe cause of poly-crystalline diamond compact (PDC) bit failure, the oil and gasindustry has made great strides toward creating whirl-resistantbits and operating practices. But is whirl still the major cause ofPDC bit damage in conventional rotary applications? This paperreports on a recent field study in which downhole vibrations weremeasured by use of a newly available in-bit vibration-monitoringdevice. The focus of this study was to understand the primarysource of bit damage. In addition, four wells were also drilled byuse of a research drilling rig in Oklahoma. In these tests, the PDCbits, bottomhole assemblies (BHAs), and operating parameterswere varied to document their effect on downhole vibrations. Inthese four wells, vibration measurements from the new in-bitmeasuring device were validated against a commercially availableand industry-proven measurement-while-drilling (MWD) vibra-tion-monitoring service.

The results of this study indicate that the most common fieldvibration in hard-rock vertical conventional rotary drilling isstick/slip, not whirl. In field tests, stick/slip was observed almostexclusively. For typical field applications with a surface rotaryspeed of approximately 70 rpm, the team measured a peak down-hole rpm as high as 500 during the slip phase. Stick/slip was iden-tified as the primary cause of bit damage in these applications.Lateral vibration occurring during the slip phase correlated wellwith the observed damage and is proposed as a new mode of dam-age during stick/slip. The characterization of the lateral vibrationscoupled with stick/slip is presented on the basis of downholemeasurements.

Introduction

Analysts have long recognized that drillstrings vibrate, and thesevibrations damage bits and BHA components. Early studies (Cun-ningham 1967; Daering and Livesay 1968; Deily et al. 1968;Denison 1979) focused on axial and torsional vibrations of thedrillstring. In 1989, researchers at Amoco identified backwardwhirl as a common vibration experienced by PDC bits. Backwardwhirl can catastrophically damage a PDC bit in a matter of sec-onds (Brett 1992; Warren et al. 1990). From that time to today,PDC bit designers have focused on developing strategies forcreating PDC bits that resist backward whirl (Cooley et al.1992; Sinor and Warren 1993; Johnson 2006; Fuselier et al.2010). Meanwhile, cutter-technology improvements have enableddrillers to apply more bit weight to increase drilling efficiency.High bit weight can cause stick/slip, and, therefore, PDC bits arenow more susceptible to stick/slip than when they were firstintroduced.

The research reported in this paper was conducted to deter-mine the predominant vibration mode that damages PDC bits in

vertical conventional-rotary wells. The authors chose to focus onvertical, conventional-rotary wells and partnered with an operatorthat uses packed BHAs and good drilling practices. The team con-ducted tests in two target areas—one west of Oklahoma City,Oklahoma and the other in the vicinity of Fort Worth, Texas—byuse of a new in-bit vibration sensor to quantify the vibrationsexperienced downhole (Pastusek et al. 2007). The team also con-ducted tests in four research wells drilled by a drilling rig dedi-cated to research (Sinor et al. 2001). In these research wells, thein-bit vibration sensor was used in tandem with a commercialMWD vibration-monitoring system (Heisig et al. 1998). The teamchose drilling parameters that caused a variety of downholedynamic dysfunctions in the research wells to create stabilitymaps showing the realms of stick/slip, smooth drilling, and back-ward whirl.

This investigation shows that stick/slip is a common downholevibration in vertical conventional-rotary wells and demonstratesthat stick/slip can cause serious damage to PDC bits. The analysisof the dull condition and the measured vibrations led to the under-standing that lateral vibrations occurring during the slip phasedamage the bits. The nature of these coupled vibrations is dis-cussed in light of measured downhole data. It is suggested that themost effective way to minimize the damage is to mitigate stick/slip. Several stick/slip-mitigation strategies have been reported inthe literature, including some in recent papers (Chesher et al.2010; Dykstra et al. 2011; Jain et al. 2011). One such strategy isto introduce a motor in the BHA. Fortunately, recent develop-ments in the field and the need for more power at the bit have ledto an increasing usage of motor drilling. Nevertheless, motors donot eliminate stick/slip completely, and can still experience highlateral vibrations in the BHA during slip phase, as is evident fromthe examples reported in this paper.

Downhole Vibration Sensors

The in-bit vibration sensor (Pastusek et al. 2007) fits in the shankof the bit, as shown in Fig. 1. The device has a special set ofaccelerometers from which the axial, lateral, and torsional vibra-tions and bit angular velocity are computed. It stores 5-second-long samples of high-frequency data, called “burst files,” at regu-lar intervals. The device also calculates and stores average valuesincluding axial and lateral accelerations and maximal, minimal,and average rotary speeds. The user can control how frequentlythe burst files and average values are stored in the memory. It iseasy to identify the presence of stick/slip from a plot of bit rotaryspeed vs. time, which will become evident in the following sec-tions. The existence of backward whirl is detected from the accel-erometers’ measurements processed in a proprietary manner.

The team validated the in-bit sensor in two different ways.Tests were conducted in a full-scale drilling laboratory that useslaser proximity sensors to measure the lateral motion of the bit.Results of these tests, shown in Fig. 2, indicate that the whirl rates(or whirl frequency) calculated from accelerations measured bythe in-bit device agree very well with the whirl rates calculatedfrom the lasers. The team also compared angular velocities andlateral vibrations, measured by the in-bit device, with the

Copyright VC 2013 Society of Petroleum Engineers

This paper (SPE 134488) was accepted for presentation at the SPE Annual TechnicalConference and Exhibition, Florence, Italy, 19–22 September 2010, and revised forpublication. Original manuscript received for review 1 February 2013. Revised manuscriptreceived for review 9 May 2013. Paper peer approved 16 May 2013.

254 September 2013 SPE Drilling & Completion

commercial MWD vibration monitor in the research wells. This isdiscussed in the following section.

Tests Conducted in the Research Wells

The team conducted several tests in the research wells at the testfacility in Oklahoma (Sinor et al. 2001) to validate the in-bit sen-sor and to study downhole vibrations. The in-bit vibration sensorwas programmed to acquire a high-frequency burst file every 2minutes. The team used the MWD vibration monitor to obtainreal-time feedback while conducting the tests to help chooseappropriate operating parameters for the tests. After completingthe tests each day, the bit was pulled out of the hole and the datain the in-bit sensor were downloaded for detailed analysis.

Stick/Slip

The term “stick/slip” refers to torsional oscillations in which thebit comes to a complete stop. Fig. 3a shows bit angular velocitymeasured during stick/slip by the in-bit sensor and the commer-cial MWD vibration monitor. The measurements show excellentagreement. Fig. 3b shows the downhole rotary speed from a typi-cal stick/slip event measured during the tests. Note that the rotaryspeed reaches a maximum of approximately 210 rpm, and thelength of the “stuck” phase is approximately 1.5 seconds. In thiscase, the surface rotary speed was 70 rpm and the depth was2,900 ft.

The MWD tool uses readings from magnetometers to deter-mine the angular velocity, whereas the in-bit device derives itfrom centripetal acceleration. Each of these methods has advan-tages and limitations. The magnetometers provide very accuratemeasurements even at very low velocities, and have less noise(see Fig. 3). On the other hand, accelerometers do not need non-magnetic subs, and they more accurately capture very-high-fre-quency variations in angular velocity.

To characterize the damage caused by stick/slip, a 121=4-in. bitwas run in the research well under conditions that exposed the bitto stick/slip exclusively. This bit was run on 5 successive days,tripping in and out of the hole each day to quantify vibrations andto document the progress of bit damage. Over a 5-day period, thebit drilled a total of 471 ft in the Wilcox sandstone, McLish shale,Oil Creek sandstone, and Arbuckle dolomite. Fig. 4 shows typicalworn cutters from the bit at the end of the 5-day period. The flatsurfaces in Cutters 77, 79, 81, and 83 are ground surfaces; theyare not bit wear. The cutter damage on this bit began with spallingon the ground flats, such as that evident in Cutter 83. Then, as thedamage evolved, it spread from the ground flat to the cutter face,as is evident in Cutter 81. Damage to the primary cutters, such asis evident on Cutters 20 and 43, began after the damage to theground flats.

Backward Whirl

Fig. 5a shows the lateral accelerations during backward whirlmeasured by the in-bit device, and Fig. 5b shows the same eventmeasured by the MWD tool. Despite being approximately 50 ftapart, the two devices measured very similar lateral vibration. Thebackward whirl probably originated at the bit and propagated intothe BHA. The bending moments measured by the MWD tool, notshown here, support this claim. As expected, these vibrations aredamped in the BHA as is evident from the lower amplitudes inFig. 5b. Bit damage because of backward whirl is well-known andwas also experienced in these tests.

Torsional Resonance of Drill Collars

Another vibration that was frequently observed in the researchwells was torsional drill-collar resonance. As shown in Fig. 6, thebit angular velocities measured by the in-bit sensors and theMWD tool during an episode of torsional resonance are in goodagreement. Warren identified this vibration in 1998 (Warren and

Fig. 1—In-bit dynamics sensor.

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Oster 1998). Warren and Oster used BHA modeling to show thatthe frequencies at which this oscillation occurred were the tor-sional natural frequencies of the BHA. Our data from the 83=4-in.research wells also show that this vibration occurs at discrete fre-quencies of 4, 8, and 9 Hz, which BHA modeling reveals to benatural torsional frequencies of the packed BHA that we used inthe 83=4-in. wells. Warren and Oster thought that short instances ofreverse rotation could occur during torsional drill-collar reso-nance, and these instances of reverse rotation might damage bits.None of our data suggest that the torsional resonance of the drillcollars was damaging PDC bits or that any significant reverserotation was occurring.

Stability Maps

The team conducted several tests in the research well to definestability maps. The testing included two bit sizes, at least two dif-ferent bit designs for each bit size, and multiple formations in twowells. A stability map is plotted in bit weight vs. rotary-speedspace, as shown in Fig. 7. The colored disks in this space repre-sent bit-weight/rotary-speed combinations at which a test wasconducted to acquire a “data point.” The procedure to acquireeach data point involved going to the bottom, establishing thedesired bit weight and rotary speed, and then drilling at those pa-rameters for 5 to 6 minutes to collect data. The in-bit vibrationsensor was programmed to acquire a high-frequency burst file

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every 2 minutes. This process captured vibration information in atleast 2 burst files for each data point. The team chose thick, homo-geneous formations to conduct stability-map tests. All data pointsin any one stability map come from one formation in an intervalof approximately 50 ft of drilling. The team used the MWD vibra-tion monitor to obtain real-time feedback while constructing thestability map to choose optimal coordinates for the data points.After completing all data points in the stability map, the bit waspulled out of the hole, and the data in the in-bit sensor were down-loaded. The stability maps shown in this paper were constructedon the basis of high-frequency data from the in-bit sensor. Datapoints in the stability maps with a blue disk indicate data points atwhich stick/slip occurred. Data points in red indicate data pointsin which backward whirl occurred. Green disks represent datapoints in which neither stick-slip nor backward whirl occurred.The size of the disk is proportional to the severity of lateralvibrations.

We compared the stability maps of two different 121=4-in. bits.One of the bits, called the “stable bit,” is designed to resist back-ward whirl. The other bit, called the “unstable bit,” is not. Theteam conducted laboratory tests to quantify the backward-whirltendency of these two bits. In this test, the depth of cut isincreased in steps at a constant rotary speed. Most bits whirl at thelowest depth of cut, and then stop whirling at some higher depthof cut. The depth of cut at which the bit stops whirling is taken asa measure of its stability. Bits that stabilize at low depths of cuthave fewer tendencies to whirl backward than bits that stabilize athigher depths of cut (Cooley et al. 1992). Laboratory tests of these

two bits showed that the stable bit stabilized at 0.04 in./rev, andthe unstable bit was unstable even at 0.96 in./rev. Fig. 7 shows thestability maps for these two bits drilling in the research well. Bothbits were run on the same packed BHA in the Wilcox sandstone ata depth of approximately 2,700 ft. Note that the backward-whirlregion for the stable bit is much smaller than the backward-whirlregion of the unstable bit. The unstable bit exhibits significantlymore backward whirl, which becomes more severe at lower bitweight and higher rotary speed as is evident from higher lateralvibrations in that zone in Fig. 7b. Stability maps for these two bitswere also created in the Arbuckle Dolomite with the same result.

The team also tested the packed and slick BHAs to confirmtheir effect on downhole vibrations. Figs. 8a and 8b show theMWD whirl diagnostic plotted in the bit-weight/rotary-speedspace of the stability map for packed and slick BHAs, respec-tively. Both tests were conducted with the same 83=4-in. PDC bitat approximately 3,100-ft depth in the Arbuckle dolomite. Thesignificant difference in lateral stability is evident from the plots;the slick BHA experienced much higher whirl instability com-pared with the packed BHA. In-bit measurements, not shownhere, indicated a stable region between the stick/slip and back-ward-whirl regions for the packed BHA. When the stabilizerswere removed, the stable region was almost nonexistent. The slickBHA also exhibited a few episodes of severe lateral vibrations atthe bit. It is interesting to note that the effect of stabilization wasmore significant on the BHA whirl than on the bit whirl.

The stability maps that we measured contradict the claimsmade in Xianping et al. (2010). Several figures in that paper are

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stability maps generated by use of drillstring-dynamics simula-tions. Their simulation-based stability maps indicate that stick/slip occurs in the upper-left portion of the stability map. This is inagreement with the team’s findings. Their simulation-based stabil-ity maps, however, indicate that backward whirl occurs at a highrotary speed and high bit weight. They show a forward-whirlregion in the lower-right portion of the stability-map space, sug-gesting that one way to get out of the backward-whirl region is todrop the bit weight. Contrary to this, the team’s measurementsindicate that backward whirl becomes more intense and morelikely as the operating parameters move to lower bit weight andhigher rotary speed. These measurements agree with the recom-mended industry practices for eliminating backward whirl (Brettet al. 1989; Warren et al. 1990).

Field Evaluation

The team ran field tests in a total of nine field wells. Four of thewells were 83=4 in. and five were 121=4 in. The field wells varied indepth from approximately 6,000 to 11,000 ft. From all these fieldtests together, the team collected 263 high-frequency burst files ofvibrations with in-bit vibration sensors. Table 1 shows the inci-dence of vibrations measured from these 263 cases. Stick/slipwas, by far, the most predominant vibration measured, occurringin 64% of the 83=4-in. burst files and in 78% of the 121=4-in. burstfiles. Incidents of backward whirl were recorded in none of the83=4-in. wells and in only 6% of the burst files in 121=4-in. wells.Torsional drill-collar resonance occurred only in one 83=4-in. fieldwell. In this well, torsional resonance was strong right after thedrilling out of surface casing at 1,024 ft. As the bit drilled deeper,the magnitude of torsional resonance decreased, and the lowerfundamental frequency of the drillstring predominated.

Fig. 9 shows examples of the bit rotary speed measured duringstick/slip in the field. Fig. 9a is for a 6,000-ft well near FortWorth, Texas. The surface rotary speed was 70 rpm. The burst fileshows the bit speed increasing to 200 rpm at the beginning of the5-second window then dropping to zero at approximately 1.6 sec-onds, remaining “stuck” for more than 2 seconds, and then accel-erating to more than 200 rpm. Fig. 9b is for a well in westernOklahoma at 10,400 ft. The surface rotary speed was 60 rpm. Atthis depth, the period of stick/slip is so long that it cannot all becaptured in the 5-second window (models show that the period isapproximately 8 seconds). The bit accelerated to 400 rpm at thebeginning of the run, and then dropped to zero at approximately2.4 seconds and remained “stuck” for the remainder of the burstfile.

The image in Fig. 10 shows the dull condition of a bit that wasdamaged in one of the field wells. Industry analysts have specu-lated why stick/slip damages bits. One theory is that reverse rota-tion, which can occur just after the bit decelerates to zero rpm,might be the cause of the damage to PDC bits during stick/slip.Although it is certainly true that the reverse rotation of the bit cancatastrophically damage PDC bits, the team saw little evidence ofthe reverse rotation in the data. Only one of the 263 burst filesacquired in the field tests showed reverse rotation, indicating it isa rare phenomenon. Nevertheless, bits were damaged by stick/slipin the field. This suggests looking elsewhere for the primary-dam-age mechanism.

Field measurements of stick/slip suggest that lateral vibrationsthat occur during the high-rpm portion of the stick/slip cycle areresponsible for damaging bits. Fig. 11 shows the rotary speed of abit in combination with the lateral accelerations measured at thesame time. Note that the lateral vibrations are highest during thehigh-rpm portion of stick/slip. The form of damage (chipping/breakage) in the dull condition corroborates this hypothesis. Theformation was not particularly abrasive; therefore, wear is notconsidered as the primary-damage mechanism. However, it ispossible that these lateral vibrations started/caused the cutter dam-age and also led to the accelerated wear of the cutters.

In five of the field tests, the bits experienced only stick/slip.That is, there was no indication of drill-collar torsional resonanceor whirl that might have damaged the bit. Comparing the damageon these bits to the peak values of the lateral accelerations thatoccurred during the high-rpm portion of stick/slip indicates thatthere is a relationship between the two. Fig. 12a shows the dam-age to the outer cutting structure, quantified in International Asso-ciation of Drilling Contractors dull grades of 0 to 8, plottedagainst the average over the bit run of the peak lateral accelera-tions experienced during the high-rpm portion of stick/slip. Fig.12b shows the dull condition plotted against the highest of thepeak average accelerations experienced during the bit run. Bothquantifications of vibration indicate that the bit damage is a func-tion of the lateral vibrations experienced during the high-rpm por-tion of stick/slip. Figs. 12c and 12d show the dull conditionplotted against drilling hours and footage, respectively. In the ab-sence of vibrations, one would expect a trend indicating increasedbit wear with increasing footage and drilling hours as shown inthe green arrow superimposed on the graph. However, these datado not follow that trend. The fact that the dull condition is not afunction of drilling hours or footage drilled, but is a function ofthe lateral-vibration level, is strong evidence that lateral vibrationsthat occur during stick/slip are damaging to bits. These resultsagree with recent observations made by another research team(Craig et al. 2010).

Lateral Vibrations Occurring During the SlipPhase

It is important to understand the nature of the lateral vibrationsoccurring during the slip phase. It is well-known that backwardwhirl occurs at higher rotational speeds. Therefore, a possiblemechanism causing higher lateral vibrations is the coupling ofbackward whirl with the slip phase. As an example of such a

TABLE 1—DOWNHOLE VIBRATIONS MEASURED IN FIELD

WELLS AND FREQUENCY OF OCCURRENCE

83=4-in. Wells 121=4-in. Wells

No dynamic dysfunction 14% 16%

Stick/slip 64% 78%

Drill-collar torsional resonance 22% 0%

Backward whirl 0% 6%

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258 September 2013 SPE Drilling & Completion

coupling, Fig. 13a displays the time history of angular velocityand lateral vibrations measured downhole by the in-bit deviceduring stick/slip when the rotational speed at the surface was 60rpm. The corresponding calculated whirl diagnostics are alsoshown. At the end of the stick phase (approximately 3 seconds),the lateral vibrations increased with the rotational speed. The highlateral vibrations were a result of backward whirl, which occurredat a frequency proportional to the rotational speed in this case. Arecent paper (Raap et al. 2011) reported that such coupling wasnot observed in their measurements and that the observation was

consistent with theoretical results reported in Leine et al. (2002).The team would like to clarify that the model of Leine et al.(2002), which concludes that a combination of stick/slip and whirlmotion is rare or nonexisting, assumed the fluid forces to be thecause of the phenomena they observed in the measurements.Although insightful, their model did not include effects such asmass imbalance, interaction with the nonperfect wall, and bit/rockinteraction. Therefore, such a coupling of stick/slip and backwardwhirl cannot be ruled out on the basis of their model. A similarcoupling was recently reported in the literature in which backwardwhirl was seen at a higher angular velocity during the slip phase(Lesso et al. 2011).

If backward whirl were the only phenomenon causing lateralvibrations during stick/slip, then such vibrations could be miti-gated by using antiwhirl bit designs. However, these vibrationsare not necessarily a result of coupled backward whirl. In fact, themajority of downhole measurements of such vibrations showedno indication of backward whirl. For example, Fig. 13b showstime history measured by the in-bit device in which high lateralvibrations were recorded in the field while the system was experi-encing extreme stick/slip. For a surface rpm of 60, the peak rpmmeasured downhole was more than 500. The whirl diagnostics didnot show backward whirl, and instead detected nonsynchronousforward whirl.

Because motors are being increasingly used in the field, anexample of stick/slip with a motor BHA in horizontal drilling ispresented. Fig. 14a shows the time history of rotational speed andlateral vibrations measured below the motor, while the systemwas experiencing stick/slip. The BHA exhibited high lateralvibrations during the slip phase. In this case, there were no

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indications of well-defined motion such as forward or backwardwhirl. Although this example is not intended to show a typicalmotor drilling scenario, it serves as evidence that high lateralvibrations during the slip phase are not limited to bit dynamics orconventional rotary drilling. They can occur with any systemexperiencing stick/slip, and can lead to bit/BHA damage.

Finally, though the team did find that high lateral vibrationswere more likely to occur during more severe stick/slip, severestick/slip does not always cause high lateral vibrations. The teammeasured severe stick/slip with moderate to low lateral vibrationsin the same run in which high lateral vibrations during the slipphase were measured. Fig. 14b plots the time history of bit rpmand lateral vibrations measured downhole. Despite the peak rpmreaching 400, the drilling is remarkably smooth. The teambelieves that lateral vibrations during the slip phase are a result ofthe complex interaction of BHA elements with the borehole. Suchinteraction likely involves impacts because of sudden accelera-

tion/deceleration of the BHA while the strain energy stored duringthe stick phase is being released. It can be envisaged that suchvibrations would depend on the formation, wellbore quality, bitdesign, BHA design, and several other factors that can be difficultto predict and control. These observations have important impli-cations. Although antiwhirl bits and stabilized BHAs may allevi-ate the problem, they would not mitigate lateral vibrations in allstick/slip cases. The most effective strategy would be to mitigatestick/slip through design and operating guidelines, in combinationwith a laterally stable bit/BHA design.

Conclusions

The oil and gas industry has not invested enough effort intounderstanding the synergy between PDC bits and stick/slip of thedrillstring. The effect of stick/slip on PDC bit damage has notbeen thoroughly investigated either. A few papers suggest that

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PDC bit design features affect the genesis of stick/slip, and somediscuss the damage caused to PDC bits by stick/slip (Brett 1992;Fear et al. 1997; Abbassian and Dunayevesky 1998; Richard 2001;Richard et al. 2002). This paper argues that stick/slip is more wide-spread than previously believed, warranting more focus on stick/slip for PDC bit development. A companion paper focuses onthe mitigation of stick/slip through PDC bit design (Jain et al.2011).

In vertical conventional-rotary drilling applications, stick/slipis a common downhole vibration. Stick/slip is a primary cause ofPDC bit damage in these applications. The occurrence of high lat-eral vibrations during the high-rpm portion of stick/slip is identi-fied as a new mechanism for bit damage during stick/slip. It isdemonstrated through measured examples that the lateral vibra-tions in some cases are backward whirl, whereas, in many othercases, they are not. In all cases, stick/slip is the root cause of dam-age—if the stick/slip could be eliminated, the lateral vibrationswould be eliminated.

Acknowledgments

The authors would like to acknowledge Baker Hughes for permis-sion to publish this paper. The authors would also like to recog-nize Eric Sullivan, Tu Trinh, Gabriel Teodorescu, Keith Glasgow,and Jason Habernal for help with in-bit sensing; Kurtis Schmitzand Cara Weinheimer for field support; Hanno Reckmann forhelp with MWD tools; and Erica Tucci for reviewing the manu-script. Special thanks to Sarvesh Tyagi and Lance Endres for theircontributions throughout the project.

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L.W. (Roy) Ledgerwood III is a technical adviser with BakerHughes. He has worked in drill-bit research for more than 37years, beginning his career with Hughes Tool Company. Ledg-erwood earned a BS degree in mechanical engineering fromTexas Tech University and an MS degree in mechanical engi-neering from Rice University, where he studied with JohnCheatham. His research today focuses on the physics ofrock destruction at high pressure and drill-bit vibrations.

September 2013 SPE Drilling & Completion 261

Ledgerwood is the author of 16 engineering publications andholds 10 patents.

Jayesh R. Jain is a research engineer with Baker Hughes. Heearned a master of technology degree in mechanical engi-neering from Indian Institute of Technology, Delhi, where he wasawarded a DAAD Scholarship for conducting research in rotordynamics at Technical University of Darmstadt, Germany. Jain’sdoctoral research at The Ohio State University, Columbus, wasin computational mechanics with a focus on the multiscalemodeling of composites. His current research deals with drillingmechanics and drilling-system dynamics. Jain has coauthored8 research articles and 6 patent applications. He serves as atechnical editor for SPE Drilling & Completion and as a reviewerfor several international journals. Jain was the winner of the 2011SPE Young Professional Paper Contest in the Drilling category.

Olivier J. Hoffmann worked with Baker Hughes as a researchengineer in drilling mechanics for more than 5 years. Heearned an MS degree in applied geology from Universite deFranche-Comte, France, and a PhD degree in civil engineer-ing from the University of Minnesota, USA. Hoffmann’s areas ofexpertise include drilling mechanics, rock characterization,and data processing.

Reed W. Spencer is a research engineer with the DrillingMechanics Group at Baker Hughes. He holds a BS degree inmechanical engineering from the University of Utah, where hegraduated magna cum laude. Spencer leads projects involv-ing the development of drilling-simulation software. Hisresearch includes the directional drilling behavior of bit/BHAdrilling systems and the dynamic behavior of bit/BHA drillingsystems.

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