A novel idea to control the rotary speed incorporates the torque signal, in addition to the speed signal, to produce a more uniform motion of the drillstring. This produce a more uniform motion of the drillstring. This method is easily incorporated into existing equipment used to control the rotary speed. We have tested this control system on a full-scale research drilling rig and have demonstrated that such a system can stop slip-stick motion and prevent it from starting. As an additional benefit, such a control system leads to smoother rotation of the bit which can lead to a reduction in axial and lateral vibrations of the drillstring. In this paper we present the theoretical basis behind such a system and give an example of the experimental results. Introduction Torsional drillstring vibrations, in particular slip-stick oscillations, have been studied intensively in the last few years. Frequency analysis of the driving torque has shown that a large number of peaks in the torque spectrum can be identified as torsional drillstring resonances. The sharpness of the resonance features indicates that there is little damping of such vibrations. Slip-stick motion of the bottom hole assembly can be regarded as extreme, self-sustained oscillations of the lowest torsional mode, called the pendulum mode. Such a motion is characterized by finite time intervals during which the bit is non-rotating and the drillpipe section is twisted by the rotary table. When the drillstring torque reaches a certain level (determined by the static friction resistance of the bottom hole assembly), the bottom hole assembly breaks free and speeds up to more than twice the nominal speed before it slows down and again comes to a complete stop. It is obvious that such motion represents a large cyclic stress in the drillpipe that can lead to fatigue problems. In addition, the high bit speed level in the problems. In addition, the high bit speed level in the slip phase can induce severe axial and lateral vibrations in the bottom hole assembly which can be damaging to the connections. Finally, it is likely that drilling with slip-stick motion leads to excessive bit wear and also a reduction in the penetration rate. It is therefore desirable to cure, or at least to reduce, the torsional vibrations in the drillstring. P. 277

An improved formula for critical buckling forces has been derived. This formula, which takes the well curvature into account, has been verified in small scale laboratory tests. The theory has been applied to survey data from a real horizontal well and it predicts that the well curvature substantially affects the critical force for helical buckling, and thereby also the maximum run-in length of coiled tubing. Criteria for operational limits, such as lock-up and tubing failure, are also discussed in the paper. Introduction Coiled tubing has numerous applications in well technology. Coiled tubing has been found useful for logging, well clean outs, well stimulation, gas lift and cementing. Encouraging attempts at drilling with coiled tubing have recently been carried out. Coiled tubing is also used as a stiff wireline for a number of tool operations in highly deviated wells. One of the main limitations associated with coiled tubing is assumed to be helical buckling and the additional wall friction force generated by buckling. When axial compression forces over a critical value are applied on coiled tubing, the coiled tubing will buckle. The coiled tubing will first buckle into a sinusoidal wave shape. As the compression force increases further, it will ultimately deform into a helix. Confined to the wellbore, the helically buckled coiled tubing will be forced against the wall of wellbore and additional contacting forces developed. The force needed to push coiled tubing into a well increases dramatically once the coiled tubing is forced into a helix. The frictional drag developed as coiled tubing is forced against the hole or casing wall will ultimately overcome the pushing forces. This phenomena is called lock-up. The critical buckling force in inclined well sections is currently determined by the Dawson formula for sinusoidal buckling and the Chen et al formula for helical buckling. These formula are currently used as the operational criteria for coiled tubing. In practice, it is often found that the operational force can be significantly larger than the theoretical buckling force, and the operations still be successful. There is considerable field evidence that using the critical buckling force as operational limit is too conservative. Two major shortcomings exist for these formulas and the way buckling analysis is performed:–The well curvature effects on the critical buckling force are not considered in these formulas.–The previously published analysis method is restricted to subcritical forces and no post-buckling is considered. It is incorrectly assumed that operations are not feasible if the axial compression force anywhere exceeds the critical buckling force. The above two points have been addressed in a recent publication, but no detailed information is given.

Stick-slip is a dysfunction of rotary drilling, characterized by large cyclic variations of the drive torque and the rotational bit speed. It is recognized as a major source of problems, such as excessive bit wear, premature tool failures and poor drilling rate. This paper presents a new system for curing and preventing stick-slip motion. Like other competitive systems it fights the stick-slip oscillations by smart control of the drive. But in contrast to other active systems it does not use any kind of torque feed-back, not even the motor current. Fundamentally, the system is a PI-type speed controller that is tuned to effectively dampen torsional vibrations at the observed stick-slip frequency. In addition to automatic tuning of the speed controller the system includes a suite of support functions, such as automatic determination of the stick-slip frequency, estimation of the instantaneous bit rotation speed and calculation of the stick-slip severity, defined as the normalized downhole speed amplitude. All software is implemented in a standard programmable logic controller (PLC). The paper also includes results from a field test and from Hardware-In-the-Loop (HIL) simulation tests. In the latter tests utilizing the HIL, the software runs on a PLC communicating with an advanced real-time computer model for the drive and the drill string. HIL testing has proved to be cost efficient because the PLC software can easily be tested over a wide range of different downhole conditions that rarely occur in the field. Introduction The stick-slip phenomenon has been studied for more than two decades and it is recognized as a major source of problems, such as excessive bit wear, premature tool failures and poor drilling rate. The problems are closely related to the high peak speeds occurring during in the slip phase. The high rotation speeds in turn lead to extreme accelerations and forces, both in axial and lateral directions. A large number of papers and articles have addressed the stick-slip problem and a selection is included in the reference list. Many authors (Kyllingstad and Halsey 1988; Dufeyte and Henneuse 1991; Brett 1992, Pavove and Deplans 1994; Fear et al. 1997; Shuttleworth et al. 1998, Robnet 1999) focus on detecting stick-slip motion and on controlling the oscillations by operational means, such as adding friction reducers to the mud, increasing the rotation speed or reducing the weight on bit. Even though these remedies sometimes help, they are either insufficient or they represent a significant increase cost. Some papers also recommend applying smart control of the drive to dampen and prevent stick-slip oscillations. Halsey et al. (1988) demonstrated that torque feed-back from a dedicated string torque sensor could effectively cure stick-slip oscillations by adjusting the drive speed in response to the measured torque variations. As pointed out by Jansen and Steen (1995) the drawback of this approach is the need for a new and direct measurement of the string torque. They show that an alternative feedback based on available motor current and speed can be used. Their method has been patented (Warrall et al 1992) and the system, which is called Soft Torque Rotary System, has been commercially available for many years. Sananikone et al. (1992) and Pavone and Desplans (1994) also mention the use of a feed-back system for controlling torsional vibrations, but they give little or no details on how to do it.

This paper deals with torsional oscillations caused by slip/stick motion of the drill-collar section. This phenomenon is associated with a large-amplitude, saw-tooth-like variation in the applied torque. "Slip/stick motion" refers to the belief that the amplitude of the torsional oscillations becomes so large that the drill-collar section periodically comes to a complete stop and does not come free until enough torque is built up in the drillstring to overcome the static friction.A mathematical model of slip/stick motion is presented. This model includes parameters describing downhole friction effects and a simplified description of the drillstring. The effects of damping, finite rotary-table inertia, and the rotary-speed control system are discussed. Theoretical predictions are compared with measured torque signals recorded during field drilling.This kind of drilling performance is likely to be less effective than normal drilling and may also lead to fatigue problems. This paper discusses ways to avoid severe torsional oscillations by using a more sophisticated feedback system to control the rotary speed.

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