Integrated drilling dynamics control - are we there yet?

Drilling system vibration was recognized as a potential cause of elevated drilling costs half a century ago. It has been thoroughly studied in the years since, and sound mitigation practices have been published. Shell's Mark Dykstra discusses the state of the art, and some improvements on the horizon.

Although you could probably find earlier papers if you searched hard enough, I would argue that the study of drillstring dynamics began in earnest with a key observation by two researchers from Shell in 19601: ‘Under certain drilling conditions . . . very noticeable motion of the drill string is produced, and drillstring vibrations do seem to be a possible cause of drill-string failures.'

Hundreds of theoretical and experimental studies have been conducted in the years since. A raft of vibration sources have been identified, including the cutting actions of rolling and fixed cutter bits, dry friction between the drillstring and the borehole, misalignment and imbalance of the rotating drillstring, and pressure pulses associated with pump strokes. These excitations cause axial vibration (extension and compression along the pipe axis), torsional vibration (twisting about the pipe axis) and lateral vibration (flexure and transverse motion). The different modes of vibration are coupled, and certain combinations of operating parameters and system properties can cause vibration amplitudes – and thus dynamic loads and stresses – to become very large. The behavior of the drilling system under these conditions is said to be dysfunctional, and specific dysfunctions have been associated with severe forms of each type of vibration.

Bit bounce
When an axial excitation – for instance, the crushing action of a roller cone bit – occurs at a natural frequency of the system, the bit can lift off the hole bottom and come crashing back down. Downhole measurements from Baker Hughes' CoPilot tool show how a surface weight-on-bit (WOB) of 20klb can generate peak downhole loads of 130klb. The figure also indicates that dynamic loads can be surprising – note the large negative torques that can occur as the bit interacts with the bottom hole pattern.

Bounce is generally considered a forced vibration, and it can often be controlled by changing the frequency of the excitation – in other words, changing rotary speed.

Stick-slip
Some torsional oscillation is always present in the system because the limber drill pipe and stiff, heavy bottom hole assembly (BHA) behave like a torsional pendulum. In some cases, nonlinearity in the system – for example, the declining torque-speed relationship of the cutting action of PDC bits – can cause oscillations to grow until stick-slip conditions are reached. During the stick phase, the bit and BHA come to a complete stop. Torque builds as surface rotation continues until enough is applied to break the bit and BHA free, at which point it rapidly accelerates. Peak speeds during the slip phase can easily be five or more times the average surface speed.

Beyond a threshold rotary speed stickslip will not occur, so the mitigation strategy typically begins by increasing rotary speed. In some cases the threshold speed cannot be reached due to equipment limitations; in other cases the high speeds cause the next type of vibration to be excited.

Whirl and buckling
Whirl is lateral vibration associated with rotation. Forward whirl, where the pipe orbits the hole in the same direction as it rotates about its axis, can cause flat spots to be worn on components. At higher speeds, forward whirl can cause impacts to occur, and the tangential forces that arise from these impacts can cause the pipe to roll along the borehole wall. As it does, it orbits in the opposite direction as its rotation about its axis, and for this reason it is called backward whirl. The onset of backward whirl can be sudden, and the vibration that ensues is intense. Measurements from Sperry Sun's DDS tool show average accelerations of 10G and peaks of 100G. Performance of downhole electronics begins to suffer when averages reach 4G.

Severe whirl is sometimes forced – as when unbalanced components are rotated at a critical speed – and can be avoided if critical rotary speeds are avoided. Backward whirl can also be self-excited, for instance by the cutting action of polycrystalline diamond compact (PDC) bits or when buckled BHAs are rotated. Once backward whirl starts, it tends to persist; the most effective way to stop it is to pick up off bottom, briefly halt rotation, then restart.

Buckling occurs when the compressive load in a beam – in this case, the BHA – exceeds the amount that it can carry without becoming unstable and deflecting laterally. Figure 5 shows the progression of buckling as WOB is increased in a horizontal well. The initially straight BHA first buckles in two dimensions (sinusoidal buckling), then into a 3D helix (helical buckling). Behavior in vertical wells is similar. Once buckled, the rigidity of the BHA diminishes and contact forces between it and the wellbore increase dramatically. Simulations and field experiments have shown that backward whirl is very likely when rotating a buckled BHA.

Integrated control approach
Left unchecked, bit bounce, stickslip, whirl and buckling slow drilling, accelerate the dulling of bits, cause fatigue of the connections and pipe bodies and shock and impact damage to expensive downhole tools. They have also been linked with poor hole quality, which further reduces drilling efficiency and makes casing running, logging and cementing more difficult.²

Jim Nicholson presented an effective approach for managing these dysfunctions in the mid-1990s.³ The following sections describe how his integrated approach for drilling dynamics planning, identification and control has been implemented within Shell's Drilling Efficiency Optimization workflow.

Pre-well planning
The integrated control approach begins in the pre-well planning phase. Drilling data from nearby wells are analyzed for the presence of performance-limiting dysfunctions. In the absence of offset data, the vibrations most likely to occur can be anticipated given the bit type, drive system and subsurface formation properties.

Consider, for example, a vertical 17 1/2in hole section through hard, interbedded formations. A roller cone bit may be selected because of the hole size and formation strength. The cutting action of these bits is known to generate axial vibrations, so bit bounce is a real concern. The WOB required to penetrate the rock will likely be high, so BHA buckling is also a possibility. If a PDC bit is selected instead, the risk of bit bounce fades, but bit whirl becomes a very real concern.

Once the likely dysfunctions have been identified, the next step is to design the BHA and drillstring to avoid triggering the problems. This is done using mathematical models in the form of computer programs. A general procedure is shown in Figure 6.⁴

The models employed range in complexity and capability. Some are designed to provide quick answers, while others simulate complex, nonlinear phenomena in the time domain.⁵ Key outputs from either type of model include estimates of WOB and speed that will (and will not) cause vibration. These are captured in parameter roadmaps that are given to rig personnel prior to drilling each hole section.

Well execution
Drilling begins using the parameters specified in the roadmaps, and personnel on the rig and elsewhere, in the case of Shell's Real Time Operation Centers, monitor performance. Surface measurements (and downhole, if available) are continually scrutinized for signs of dysfunction because parameters that lead to their onset may be somewhat different than expected. An old friend and former colleague once put it this way: ‘In theory, there's no difference between theory and reality, but in reality, there is.' Said differently, models are idealizations of reality, and while they are useful for planning, actual conditions downhole may be quite different than we assumed they would be.

If vibration does become severe, operating parameters need to be adjusted to bring it back under control. Persistent vibration may require a trip for a different bit or BHA. Successful mitigation requires an understanding of the governing physics, so personnel responsible for monitoring and intervening need to be properly trained.

Post-well analysis
An admired professor and mentor once told me: ‘You can work, and you can think, but you can't do both at the same time.' While the well is being drilled, the focus is on the work; the post-well period presents an opportunity to think.

Comparison of actual and expected vibration types, vibration severity and overall drilling performance can point to changes in bit selection, BHA design, drilling fluid or well trajectory that will improve performance in subsequent wells. The inability to mitigate vibration via operating parameters may indicate the need for vibration control equipment, for example, a shock absorber in the BHA to reduce axial vibration, or a soft torque rotary system at the surface to reduce torsional vibration. If observations cannot be explained from available data, the expense of additional measurements may well be justified in subsequent wells. Of course, the ultimate goal is to capture and reuse best practices to accelerate progress along the learning curve.

Are we there yet?
Nicholson concluded his paper by recommending that ‘the service industry adopt an integrated approach towards drilling vibration control'. Fifteen years have passed since, and I believe a lot of progress has been made toward that goal. Pre-run modeling of BHAs to identify dangerous combinations of operating parameters is done routinely. Virtually all modern measurement while drilling tools include sensors for evaluating vibration, either real-time or post-run. Rig equipment has improved, and remote monitoring has allowed more – and often more highly skilled – sets of eyes to monitor drilling operations. A variety of optimization services are available that make use of all of this. Moreover, operators have been working to refine their own optimization processes.^6,7 Despite this progress, however, dysfunctions still occur, and they still cause cost per foot to be higher than operators would like it to be.

The reasons for this are manifold. One is that control of operating parameters is still in the hands of drillers, and the ebb and flow of talent from one rig crew to the next – and in and out of the industry – makes it virtually impossible to keep them all highly skilled in vibration control. Remote monitoring can help, but even experts are at least partially blind to what is happening downhole without real-time downhole measurements, and intense focus on controllable drilling costs prevents many operators from spending the money to acquire the data. Even if expertise and information are available, continuously changing downhole conditions can make it very difficult to find combinations of operating parameters that yield high ROP and directional control with minimal bit bounce, stick-slip, buckling and whirl.

Where to next?
Since downhole conditions change, it stands to reason that system properties must also be able to change to preserve – or provide – a window of efficient operation. Rotary steerable systems are a step in this direction: steering force magnitude and direction change automatically to achieve a preset directional response. Soft torque rotary systems are another step: torsional vibration is actively damped as it is sensed at the surface. There is no doubt in my mind that adaptive BHA components will eventually supplant passive tools like traditional shock absorbers. More advanced surface control systems will also emerge. The technology exists – the automobile you drove to work today is most likely rife with it. Certainly cost presents a very real barrier to development and implementation, but just as RSS use has expanded from expensive offshore environs to lower budget onshore plays, the performance gains offered by smart drilling systems will eventually justify the investment. Will these systems obviate the integrated vibration control approach? I don't think so . . . but they will certainly make it easier to implement. OE

About the Author

Mark Dykstra is a senior staff well engineer on Shell's Drilling Efficiency Optimization team. His 20+ year career has largely focused on developing and applying better performing drill bits and drilling systems. He holds BS, MS, and PhD degrees in petroleum engineering from the University of Tulsa. Industry contributions include 14 patents and 12 publications. He is a member of a number of professional societies, and served as an SPE Distinguished Lecturer in 2008/09.