Integrated Work Flow Mitigates Drilling Vibrations

Fig. 1—Notional drilling-dysfunction domains.

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A work flow that combines optimization of the drillstring and bottomhole-assembly (BHA) design during well planning and then applies advanced surveillance tools to a well-trained drilling crew yields reduced vibrations and higher drilling rates. This methodology is based on the premise that an efficient drilling operation requires optimized tool designs, advanced diagnostics using real-time drilling parameters, and on-site training of efficient drilling practices and the proper use of rig-control systems.


In recent years, as part of a limiter-redesign process and rate-of-penetration (ROP) optimization effort, the operator has sought to develop and validate in the field a suite of tools specifically directed toward drilling-operations support. Vibration-mitigation efforts are a subset of the entirety of this broader program.

BHA redesign involves planning to change the downhole tools. Once a BHA has been selected and its rotary-speed sweet spot is known, there is a real-time component as the driller determines how good the sweet-spot prediction might be or if an alternative operating condition is preferred.

Drillstring modifications on the basis of torsional string modeling typically involve drillpipe-outer-diameter selection and understanding or optimizing the equivalent-circulating-density (ECD) profile, typically resulting in the largest pipe that satisfies the ECD criteria being desired, provided that torque-and-drag modeling do not indicate rig limitations or buckling concerns. Torsional string modeling provides the capability for ­real-time stick/slip detection on the basis of monitoring the surface torque variation.

A drilling advisory system (DAS) is, first and foremost, a real-time dysfunction-recognition and response tool. The DAS provides the driller with diagnostic data and charts illustrating the drilling-performance map in a stoplight format to select the best operating parameters.

Rig-control systems, in particular the autodriller, may generate a certain amount of dysfunction as a result of the way they are implemented and operated. Significant changes in drilling line feed rate result from on/off control systems, high control-system gains, and unstable feedback mechanisms in certain situations. These line-feed-rate perturbations may exacerbate other vibration modes, such as stick/slip, resulting in dysfunction and reduced drilling performance.

Efforts to mitigate these effects contribute to the reduction of nonproductive time. Taken together, they have yielded improved drilling results, increasing the number of single-bit runs to section depth in fewer days.

BHA Modeling for Lateral-Vibration Mitigation

The vibration-mitigation work flow developed by the operator has included for several years lateral-vibration modeling of the BHA to compare different design configurations.

Typically, the design that has the lowest calculated vibration index is selected to drill the hole section, provided that all applicable constraints are observed.

The lateral-vibration-model results are primarily governed by the position of the borehole contact points, or nodal points, determined by the placement of the stabilizer blades. The collar outer and inner diameters are also important. Just as the position of the fingers on a stringed instrument governs the frequency of the note that will be played, the locations of these nodal points determine the frequency response of a BHA.

The lateral-vibration model calculates an in-plane dynamic bending mode called flex that is excited by a side force applied at the bit and a rotary centrifugal mode called twirl excited by mass eccentricity. A significant experience base has been developed comparing drilling performance with model results, and this has shown that the flex mode is the most significant vibration mode to mitigate. Ideally, both flex and twirl indices would decline for a preferred BHA design, but field experience has shown that a significant reduction in flex results will yield improved drilling performance even if twirl results increase to some extent.

Drillstring Modeling for Torsional-Vibration Mitigation

Drillstring-torsional-vibration modeling has improved the ability to select the optimal drillstring in challenging applications. Current practice in the industry is to model extended-reach wells for torque and drag, buckling, and ECD. In narrow-margin drilling applications, ECD, of course, is a real concern. When the ECD approaches the fracture gradient, loss of drilling fluid can occur, often costing significant amounts in terms of replacement fluids and remediation. Buckling and torque/drag predictions can be highly dependent on detailed well profile and parameters. However, industry models are reasonably good at predicting torque, drag, buckling, and ECD.

A relatively simple model of torsional vibrations can be applied to help evaluate the stick/slip tendency of different drillstring options, complementing the existing modeling tools without the overhead of complicated finite-element-analysis codes. Torsional-vibration-model results add value in the decision-making process regarding operational tradeoffs between competing string-design objectives.

A simple torsional-vibration model that estimates the resistance of a string to stick/slip is a helpful tool to shed light on the implications of these choices for the stick/slip vibration problem. Note that this analysis of ECD and torsional-­modeling trends is independent of the well profile and, therefore, is more broadly applicable. A more-complete analysis will look also at individual well profiles as well as torque, drag, and buckling considerations, which vary considerably. In each individual case, the pros and cons of each element of the drilling plan (e.g., drillstring design, hole-size selection, fluid selection, pump rate) have to be evaluated to determine the best and most-economical solution.

Application of a DAS To Mitigate Vibrations

The operator’s DAS is in the late development/precommercialization stage, and it has shown promise as a driller’s guide to help identify drilling dysfunctions. In a perfect drilling environment, there are no limits to applying maximum weight on bit (WOB) and turning with the fastest possible rotary speed, which, in the absence of dysfunction, will yield the highest drilling rate. However, in a great many wells, drilling dysfunctions cause this scenario to be elusive.

Primary causes of dysfunction include lateral vibrations (whirl) and stick/slip torsional vibrations. Coupled modes also exist in which both of these may be present. Axial vibrations are less frequent today but are still a potential problem when using roller-cone bits.

As indicated in Fig. 1 above, as WOB increases, the bit is typically stabilized against lateral vibrations, yet the potential for stick/slip increases. On the other hand, higher rotary speeds often help to resolve stick/slip, with the possibility of generating higher lateral vibrations. In some instances, the driller is able to find a sweet spot between these two vibrational dysfunctions. In those difficult circumstances where there is no middle ground between stick/slip and whirl, and when the driller is unable to go to the maximum-WOB and maximum-­rotary-speed conditions that would provide the highest ROP, it is helpful to have an advisory system that monitors drilling performance continuously in real time and provides parameter recommendations. This system can balance competing objectives to find an optimal set of drilling parameters.

The DAS objective function seeks to find the best balance between competing goals. Field testing has shown several examples where the DAS display in front of the driller has provided an increase in drilling performance. The driller is relieved of complex drilling-performance calculations and can rely on a quick glance at the DAS screen to see the current drilling performance.

Identification and Mitigation of Rig-Control-System Dysfunctions

The response of the autodriller has been found to have a significant effect on drillstring vibrations, in particular on stick/slip. It has been found that it is much easier to find a vibrationally quiet set of operating parameters when the control system is stable, and it is sometimes impossible when it is not stable. This suggests that control-system stability needs to be evaluated and corrected if required as part of the drilling-optimization process.

Many autodrillers can be selected to control in one of four modes: ROP, WOB, torque, and differential pressure. Only one mode is in control at a time.

There are several different types of control systems and several variations on the basic types. However, all autodrillers ultimately control the drum rotation speed and, thus, ROP.


The operator has taken a comprehensive approach to address drilling vibrations. It is commonly known that reducing vibrations yields benefits that include faster ROP, more time spent drilling on bottom, fewer trips and thus reduced pipe handling, less damage to equipment, and reduced nonproductive time. The complete paper has sought to document concrete examples of four paths toward mitigating drilling vibrations.

  • BHA redesign—Comparing two BHA designs in similar intervals, it was shown that the simpler BHA with a low vibration index demonstrated lower vibrations than another design with measurement-while-drilling tools that had higher vibration indices.
  • Torsional modeling—An evaluation of six different drillstring designs included both torsional-vibration modeling and ECD calculations, showing that tapered drillstrings tend to be inefficient relative to single-diameter strings. More torque swing capacity may be achieved with the same ECD using a single-diameter drillstring.
  • Application of a DAS—A real-time system monitoring drilling parameters can strike a balance between drilling dysfunctions adaptively, targeting mitigation of the dysfunction that has the greatest effect on performance.
  • Rig-control systems—At present, autodriller control systems may be tuned improperly and cause stick/slip and other dysfunctions during system oscillations. However, significant improvements can be made with support from system designers and driller training.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 183550, “An Integrated Work Flow To Mitigate Drilling Vibrations and Increase Daily Footage,” by J.R. Bailey, SPE, and P.E. Pastusek, SPE, ExxonMobil Development Company; H. Al Junaibi and M. Al Awadhi, National Drilling Company; Y. Al Katheeri, SPE, M.R. Niznik, and K.S. Akyabi, Zakum Development Company; and C.G. Page, Exxon Neftegas, prepared for the 2016 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 7–10 November. The paper has not been peer reviewed.

Integrated Work Flow Mitigates Drilling Vibrations

01 September 2017

Volume: 69 | Issue: 9


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