Since backward whirl was discovered as a severe cause of PDC bit failure, our industry has made great strides toward creating whirl-resistant bits and operating practices. But is whirl still the major cause of PDC bit damage in today's applications? This paper reports on a recent field study in which downhole vibrations were measured using a newly available in-bit vibration-monitoring device. The focus of this study was to understand today's North American vertical conventional rotary applications. In addition, four wells were also drilled using a research drill rig in Oklahoma. In these tests, PDC bits, BHAs, and operating parameters were varied to document their effect on downhole vibrations. In these four wells, vibration measurements from the new in-bit measuring device were validated against a commercially available and industry-proven MWD vibration monitoring service. Also, a computer model that accounts for the coupled response of bits and BHAs was run for selected tests in field wells and the research drilling rig. The models agreed well with the measured cases in both whirl and stick-slip. The model also allowed the authors to confirm that high-frequency torsional oscillations (4-9 Hz) which we observed were, as a previous industry paper suggests, due to BHA torsional resonance. The results of this study indicate that the most common field vibration today in hard rock PDC drilling is stick-slip, not whirl, in the target test region. In field tests, stick-slip was almost exclusively observed. For typical field applications with a surface rotary speed of about 70, we have measured peak downhole RPM during the slip phase as high as 500. This paper will report on these findings, document damage resulting from stick-slip, and suggest potential solutions to mitigate downhole vibrations.

The response of the drilling system to axial and torsional vibration inputs has a significant impact on drilling performance. Usually the goal is to minimize dynamic response to limit the effects of potentially damaging phenomena in the low frequency range (e.g. bit bounce and torsional stick-slip) and high frequency range (e.g. axial chatter and torsional resonance). However, in some cases the goal is to maximize dynamic response, for example when introducing oscillation tools to overcome wellbore friction while directional drilling or to free stuck pipe. Whether the intention is to maximize or minimize, a suitable mathematical model is required. The model presented in this study uses the transfer matrix approach to predict how a harmonic vibration input propagates through the remainder of the drillstring. Novel features of the model include the ability to place the excitation source anywhere in the drillstring and to estimate damping effects due to Coulomb friction in directional wells.Model inputs include drillstring and bottom hole assembly composition, well survey data, surface equipment and drilling parameters. Drillstring components are modeled as spring or beam elements and the surface equipment is modeled as a mass-spring system. Bit-formation interaction is modeled as a spring, the stiffness of which can be adjusted to provide a boundary condition ranging from fixed to free. Damping due to material hysteresis and interaction with the drilling fluid is modeled using a velocitydependent term. Coulomb friction is modeled as an equivalent viscous damping coefficient. A harmonic excitation is specified at a given location in the drillstring and the responses at other locations in the system are computed via transfer matrices. This approach allows rapid characterization of the axial and torsional response of the drillstring in the frequency domain and may be applied to analyses of induced oscillation, such as from axial oscillation tools (AOTs), or unintended vibration, such as bit bounce.Case studies show that predicted frequency responses in the axial and torsional domain compare favorably with high sampling rate downhole and surface measurements, respectively. Additional case studies demonstrate how the model has been successfully applied to diagnose and resolve severe axial vibrations while drilling with roller cone bits. Finally, model predictions are compared with downhole acceleration measurements to evaluate effectiveness of axial oscillation tools while drilling with steerable motor systems. Recommended practices for device placement and drillstring configuration are provided based on the findings from these studies.

Summary Since backward whirl was discovered as a severe cause of polycrystalline diamond compact (PDC) bit failure, the oil and gas industry has made great strides toward creating whirl-resistant bits and operating practices. But is whirl still the major cause of PDC bit damage in conventional rotary applications? This paper reports on a recent field study in which downhole vibrations were measured by use of a newly available in-bit vibration-monitoring device. The focus of this study was to understand the primary source of bit damage. In addition, four wells were also drilled by use of a research drilling rig in Oklahoma. In these tests, the PDC bits, bottomhole assemblies (BHAs), and operating parameters were varied to document their effect on downhole vibrations. In these four wells, vibration measurements from the new in-bit measuring device were validated against a commercially available and industry-proven measurement-while-drilling (MWD) vibration-monitoring service. The results of this study indicate that the most common field vibration in hard-rock vertical conventional rotary drilling is stick/slip, not whirl. In field tests, stick/slip was observed almost exclusively. For typical field applications with a surface rotary speed of approximately 70 rpm, the team measured a peak downhole rpm as high as 500 during the slip phase. Stick/slip was identified as the primary cause of bit damage in these applications. Lateral vibration occurring during the slip phase correlated well with the observed damage and is proposed as a new mode of damage during stick/slip. The characterization of the lateral vibrations coupled with stick/slip is presented on the basis of downhole measurements.

Stick-slip vibrations of drillstrings have been studied by researchers for several decades. The subject is gaining renewed interest as operating parameters for PDC bits have shifted to the stick-slip regime of higher bit weight and lower rotary speed for enhanced drilling performance. In Ledgerwood et al. (2010), stick-slip was identified as a primary cause of bit damage. The main objective of the current investigation is to answer the longstanding question: Do bit designs influence stick-slip behavior of the drilling system? Five prevailing industry perceptions reported in the literature are that anti-whirl bits, reduced exposure bits, and bits with bit-rock interaction number "β" > 1 are less prone to stick-slip, while highly aggressive bits and worn bits are more prone to stick-slip. Although the phenomenological basis of these theories has been provided, validation in most cases is based on anecdotal evidence from the field. Data with diagnosis based on downhole measurements in a controlled environment are scarce. Consequently, conflicting opinions continue to exist about whether any of these theories work in reality. To assess their validity, the five leading theories were reviewed and pairs of PDC bits were designed and manufactured. Each pair consisted of a bit with a standard design and a bit that embodied one of the theories. The bits were first tested in the laboratory to characterize their response. Full-scale wells were then drilled under controlled conditions using a research drill rig in Oklahoma. In these wells, only the operating parameters were varied while BHA, formation, and other variables were unchanged for a given bit pair. The downhole vibrations were measured with a new in-bit device and an industry-proven MWD vibration monitoring service. The most important conclusion emerging from this study is that PDC bit design has a significant effect on stick-slip vibrations. While some of the theories held true, evidence from this study did not support others. The details of test results are provided and various aspects of bit design are discussed in an attempt to enhance the understanding of stick-slip mitigation.

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