The Destruction of PDC Bits by Severe Slip-Stick Vibration

Abstract

Surface mud logging systems have detected a severe form of torsional vibration that causes rapid destruction of polycrystalline diamond compact (PDC) drill bits. These failures can occur when combining a limber bottomhole assembly (BHA) with a PDC bit lacking some form of anti-whirl stabilization. On the basis of experience to date, these vibration-induced failures occur only in larger hole sizes. This paper describes the nature of these bit failures, their dependence on operating conditions, and practical recommendations for avoiding failure. Experience from one operation, in which revised drilling practices and bit selection criteria eradicated the failures, will be presented. Introduction The nature of various vibration modes, their damaging effects on downhole equipment, and the measurement and suppression technology developed to combat vibration, is well-documented in the literature.1,2,3,4,5 In drilling operations, one of the more common modes is torsional vibration, which is recognized by surface torque fluctuations with a frequency close to the fundamental torsional mode of the drillstring. The frequency of torque oscillations under such conditions is given by: f=12πkJb(1) Fig. 1, which was taken from an actual drilling operation, is an example of this frequency. These data, and all other vibration data described here, were acquired with a previously described detection system.5 In its extreme, torsional vibration can advance to the point that the bit and bottomhole assembly come to a complete stop-start (stick-slip) motion.6 Various characteristics in surface torque behavior can detect this extreme condition. First, the frequency of surface torque oscillations will decrease below the fundamental frequency, thereby reflecting the sticking time downhole. Second, peak surface torque will increase to a value approximately equal to the static torque required to break the bit/BHA free, plus the torque required to rotate the drillstring. In fact, if a drop in surface rotary speed accompanies this rise in torque, which is typical for topside rig equipment, the speed minima concurring with the torque maxima creates an inertial force opposite to string rotation. This adds another component to peak surface torque. Finally, the effect of inertia will also reduce surface torque below the level that is required to rotate the drillstring as the bit and BHA break free downhole. Fig. 2 is an example of this fully developed ‘slip-stick’ behavior. Of particular significance is the frequency of the torque oscillations compared to the calculated fundamental frequency. The rise in torque is linear to the observed maxima, reflecting the deceleration of the BHA during the stick phase. The subsequent torque drop suggests a rapid acceleration of the BHA during the slip phase. The purpose of this paper is to report the operator's experience with this form of slip-stick vibration in one major drilling program. The circumstances under which it occured, its effect on drilling performance/economics, and measures that have been developed to control it, will be described. In addition, the authors will use detailed analyses of surface drilling parameter and other operational data, and simulations using a finite element model of the drillstring to interpret the downhole behavior that provokes slip-stick.

Laboratory investigation of drillstring vibrations

“…Figure 12(b) shows a comparison between the computed and measured torque, which manifests excellent agreement. This behaviour is consistent with field measurements, as well as computerized simulations reported by Fear et al [30]. In their field investigation, it was observed that the behaviour of surface torque during intervals of pronounced fluctuation, as recorded by the highfrequency mud logging data, gives some illustration of downhole behaviour, and helps confirm that the fluctuations are indeed due to slip-stick.…”

Exploration of the Interaction Between Drill Bit Gauge Profile and Point-The-Bit Rotary Steerable Systems

“…Whilst investigating the damage to PDC bits under severe stick-slip vibration, Fear et al (1997) concluded that; "nose damage is actually related to the freedom of the bit to move laterally, rather than merely being due to the variation in bit speed. In the absence of near-bit stabilization, bit lateral motion probably occurs with sufficient freedom to rapidly and terminally damage the bit".…”

Characterization of a Pulsating Drill Bit Blaster

“…(Gefei, 2015) Once collapsed the contact area of the drill string along he wellbore is increase leading to more overall frictional force which can damaged the wellbore and limits the WOB that can be applied to drill. Excessive friction during rotational drilling in which the drillstring is rotated while drilling can cause a condition known as "stick slippage" in which there is micro-stickage between the bottom hole assembly (BHA) and wellbore while rotating followed by a sudden lurch as the rotation unsticks when the friction exceeds a critical value (Fear, et al, 1997). This process can occur several times a second and can lead to premature wear and total failure of large diameter PDC bits.…”

“…Even if the bit is not damaged by this stick slipping it still makes controlling the tool face much more difficult and can lead to lower ROP. Weight stacking can also occur when the cumulative friction along the entire drill string exceeds the applied WOB and results in little or no ROP during drilling (Fear, et al, 1997). In order to combat these problems a friction reducer called "AG-itator" that was operated by using a rotor-stator configuration to periodically open and closed a path for the drilling fluid flow was installed and tested along a drill string to cause vibrations (Fear, et al, 1997).…”

“…In order to combat these problems a friction reducer called "AG-itator" that was operated by using a rotor-stator configuration to periodically open and closed a path for the drilling fluid flow was installed and tested along a drill string to cause vibrations (Fear, et al, 1997). During testing in Texas, a 30% decrease in the WOB needed to optimize the ROP and a 12.5% increase in the ROP on average along the section drilled compared to historical data from offset wells was recorded (Fear, et al, 1997).…”