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Improved Methods Aid Understanding and Mitigation of Stick/Slip Torsional Vibrations

Topics: Drilling fluids

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Historically, prediction of stick/slip vibrations in advance of drilling has been fraught with challenges. Although the factors influencing stick/slip, and the directional changes required to mitigate it, are known, a need exists for a simple method to determine quantitatively the degree of dysfunction and the effects of redesign parameters. This paper will show how stick/slip vibration distributions can be used to guide drillstring and parameter redesign to mitigate stick/slip in the next well.

Background

Torsional vibrations, also known as stick/slip, occur as the rotational speed of the bit and drillstring vary because of stiffness, inertia, and torsional friction interactions. In some wells, these torsional/rotational fluctuations are not severe and may not reach full stick/slip, which occurs when the bit comes to a full stop in the torsional vibration cycle.

The drilling data obtained in the drilling of a well are displayed typically as time or depth tracks, with different parameters shown on the same or adjacent tracks over the corresponding time or depth interval. Although of interest, this display of data is limited. It does not provide a direct indication of the amount of dysfunction present over the duration of the interval. A histogram is a particularly useful display of the distribution of data values.

In the case of stick/slip vibrations, the torsional-severity estimate (TSE) is a measure of proximity to full stick/slip. A TSE value of 0.0 represents no torsional vibrations, where the entire drillstring is turning at a constant angular velocity. A TSE of 1.0 represents full stick/slip, in which the rotary speed at the surface is constant but the bit speed varies sinusoidally between zero and twice the surface rotary speed. Values of TSE greater than 1.0 indicate time intervals in which the bit comes to a complete stop and then accelerates to more than twice the surface rotational speed. The most severe cases may even involve negative rotation of the bit.

Analytical tools that help assess the degree of torsional vibrations can be useful, especially in those instances where known remediation techniques are not available or may be costly. A variety of methods exists to address torsional vibration problems, and the most-cost-effective method may be the method of choice.

The authors are not aware of simple analytical methods that can provide quantitative evaluation to address the following:

  • How will the stick/slip problem change if the drillstring design is modified?
  • How will stick/slip change if the operating parameters are modified?
  • The bit-design parameters may be varied to increase or decrease bit torque. How will changes to the bit friction factor affect stick/slip vibrations in a certain application?

The methodology discussed here is one approach to address these questions. This empirical method is based on data obtained from two wells, and the data distributions are scaled by changes in the drilling parameters. One then may determine if the modified design satisfies the stick/slip design objective.

Stick/Slip Distribution Modification

A histogram of TSE values indicates vibration severity over an interval. The histogram may be used as a tool in redesign. The distribution of stick/slip may be modified by changing certain parameters. The TSE values are linearly related to the following three factors:

  • Drillstring stiffness
  • Downhole torque
  • Rotary speed

The quantification of stick/slip vibration mitigation using stick/slip distribution modification may be explained best through a simple example. Note that, in the example, the torque swing at full stick/slip increases linearly with rotary speed such that the system may come out of stick/slip if the rotary speed is increased a sufficient amount with all other parameters equal.

Consider a drillstring with ­reference specific torque swing (ΔTQSSRef) of 100 ft-lbf/(rev/min). This is ­primarily a function of the drillpipe torsional stiffness and length. If operated at 100 rev/min, full stick/slip would be expected at a torque swing of 10,000 ft‑lbf, at a corresponding TSE value of 1.0.

When operated at 200 rev/min, the TSE for the same torque swing decreases to 0.5, and the bit will not be in full stick/slip. The peak-to-peak amplitude of the bit-speed variation is proportional to the amplitude of the surface torque variation, so the same bit speed peak-to-peak variation occurs as that seen with 100 rev/min at surface. However, the bit never stops in this case because of the higher rotary speed. The effects on the stick/slip TSE distribution for changes in drillstring stiffness and bit and drillstring torque measurements scale quantitatively in a similar way.

Parameter Redesign To Mitigate Stick/Slip Vibrations

Drilling data from two wells are used to illustrate this methodology in a real-world application. Figs. 1a and 1b provide raw drilling data and calculated values related to torsional vibrations seen in two wells. The torsional vibrations were severe in Well 1 and significantly mitigated in Well 2, and Well 2 drilled this challenging interval much faster than Well 1.

Fig. 1—Drilling data from Well 1 (a) and Well 2 (b).

 

Starting at left, in Fig. 1a, the first parameter is the surface torque (TQ). The next parameter is the torque swing measured from one cycle to the next (ΔTQ). This torque swing is directly related to the stick/slip peak-to-peak values at the bit. Fig. 1 shows that torque swing is more severe for Well 1 than for Well 2.

The next parameter to the right is the surface rotary speed [revolutions per minute (RPM)]. Neither of these assemblies had a downhole motor. Well 1 showed minimal stall, whereas Well 2 had some stalling events because it was operated at a greater weight on bit.

Following the RPM track is specific torque swing per RPM (ΔTQS). This is the measured torque swing divided by the average rotary speed. The next column is the TSE value for bit stick/slip based on the surface torque swing method (TSETQ). The following column is the TSE value based on measured downhole bit RPM data (TSEBRPM). Overall, the TSE trends are relatively constant in depth. Again, stick/slip was not the limiter in Well 2 that it was in Well 1. The last column shows the measured downhole torque (DTOR) value.

The drillstrings were different in the two wells. The surface rotary speed was higher in the second well, and the DTOR was lower in the second well. Thus all three factors from Well 1 were modified for Well 2.

Drillstring Stiffness. The drilling data for both runs have been evaluated to determine the specific torque swing values per RPM, and these values are displayed in Fig. 2. Considerably higher values were present in Well 1 than in Well 2. The calculated reference values at full stick/slip from the torsional vibration model (ΔTQSRef) are also plotted in Fig. 2, shown as red dashed lines. The plot reveals clearly that Well 1 was operated far beyond the torque swing capacity of the drillstring.

Fig. 2—Specific torque swing in Well 1 (a) and Well 2 (b).

 

Mitigation of this condition in Well 1 could be achieved in a number of ways. In Well 2, it was mitigated through an improved drillstring design in addition to operating at a higher rotary speed and reduced torque demand from the bit. Pipe stiffness was not sufficient by itself to mitigate stick/slip fully. The higher rotary speed and reduction in torque also were important factors in achieving full mitigation.

DTOR. The hole size was 17.5 in. in Well 1 and 16.5 in. in Well 2. The reduction in hole size was expected to reduce bit torque. Other bit design features were modified for Well 2 to reduce the bit friction factor, and the DTOR levels indeed were lower.

Surface Rotary Speed. In drilling Well 1, attempts to drill at higher rotary speeds were not successful because of increased shock rates at the tools for higher rotary speeds. The changes to the bottomhole assembly (BHA) from Well 1 to Well 2 were significant, and the changes to the BHA made higher sweet-spot rotary speeds available to the driller. Well 2 was indeed able to be run at a greater rotational speed.

Combined Effects. These factors may now be combined using an equation included in the complete paper to estimate the change to be expected in TSE distribution from Well 1 to Well 2 that is based on the improvement in drillstring design, the increase in rotary speed, and the reduction in DTOR values. The surface rotary speed was increased from an average of 91 to 126 rev/min. The wellbore size was reduced, and the bit was redesigned with a less-aggressive cutting structure; a reduction in DTOR of approximately 30% was expected. The measured values showed nearly this ­degree of torque reduction.

These results were obtained with average values for torque and rotational speed. The method could be refined by including distributions of these values instead of average values, which would essentially provide a pointwise evaluation of the data. The pointwise scaling method would be more complicated but is certainly feasible.

For a limited time, the complete paper SPE 189673 is free to SPE members.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 189673, “Improved Methods To Understand and Mitigate Stick/Slip Torsional Vibrations,” by J.R. Bailey, SPE, G.S. Payette, SPE, and L. Wang, SPE, ExxonMobil, prepared for the 2018 IADC/SPE Drilling Technology Conference and Exhibition, Fort Worth, Texas, USA, 6–8 March. The paper has not been peer reviewed.

Improved Methods Aid Understanding and Mitigation of Stick/Slip Torsional Vibrations

01 December 2018

Volume: 70 | Issue: 12

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