Putting a Damper on
Drilling’s Bad Vibrations
Stuart Jardine
Montrouge, France
Dave Malone
Sugar Land, Texas, USA
Mike Sheppard
Cambridge, England
Drillstring vibrations are increasingly acknowledged to be costing the industry dearly. Although most of the
causes are understood and many remedies are already available, the vital step is to effectively implement
this knowledge and technology to cut drilling costs.
Symptoms of drillstring vibrations vary.
Sometimes, when the crew sees the drillstring bouncing or rotating irregularly, they
are only too aware that something is wrong.
In other cases, the first the driller may know
is when downhole equipment fails because
it has been shaken to pieces by vibrations
that went undetected at surface.
Whether evident or invisible, these bad
vibrations significantly increase the cost of
drilling a well. Although the exact figure is
still being assessed, large costs—an estimated 2% to 10% of well costs—can arise
from vibration-related problems, such as lost
time while pulling out of hole and fishing,
reduced rate of penetration, poor quality
wellbore and increased service cost because
of the need for ruggedized equipment.
It is important to dispel the notion that
potentially damaging vibrations may also
benefit the drilling process. There is little evidence to support this. Although some types of
vibrations may be useful—such as bit noise
used as a signal for seismic while drilling—
these are usually of a different frequency and
amplitude from the destructive vibrations.1
January 1994
Transverse
Axial
Torsional
nThe three modes of drillstring vibration.
Shake, Rattle and Roll
Drillstring vibration can be divided into
three types, or modes: axial, torsional and
transverse (above ). Axial vibrations cause
bit bounce and rough drilling, behavior that
destroys bits, damages bottomhole assemblies (BHA), increases total drilling time and
may be detected at surface.
Torsional vibrations cause irregular downhole rotation that fatigues drill collar connections, damages the bit and slows drilling.
The vibrations are recognized at the
drillfloor by fluctuations in the power
For help in preparation of this article, thanks to JeanMichel Hache, Anadrill, Sugar Land, Texas, USA; David
White, Sedco Forex, Montrouge, France.
1. Vibrations used for seismic while drilling are 10 to
100 Hz; vibrations causing bit bounce are typically
about 3 Hz.
Meehan R, Miller D, Haldorsen J, Kamata M and
Underhill B: “Rekindling Interest in Seismic While
Drilling,” Oilfield Review 5, no. 1 (January 1993):
4-13.
15
nDownhole equipment destroyed by
vibration. An alloy steel threaded connection (top) from inside a bottomhole assembly has been sheared. The insulating
cover of a resistivity measurement-whiledrilling sensor has been chewed up by
banging against the formation (bottom).
16
needed to maintain a constant rate of surface rotation—this will be dealt with in
more detail later.
The more destructive transverse vibrations
may be unleashed with no sign at surface.
Deep in the hole, the rotating BHA interacts
with the borehole wall generating shocks
from transverse vibrations as high as 250g.2
The collisions with the borehole wall produce out-of-gauge hole and the shocks can
damage components of the BHA (left ). Engineering to help equipment such as bits,
measurement while drilling (MWD) tools
and jars survive the tough downhole environment significantly increases the hardware costs.
Vibrations of all three types may occur
during rotary drilling and are more violent in
vertical or low-angle wells, where the drillstring may move more freely than in highangle wells. Many studies of drillstring
vibrations employ one-dimensional, linear
harmonic analysis that largely ignores the
dynamics of wall contact. This approach has
proved relatively successful for axial and torsional vibration. For example, a major study
of torsional vibration using 3500 hours of
surface and downhole vibration data concludes that there are two types of torsional
vibrations: transient and stationary.3
Transient vibrations correlate with variations in drilling conditions—like heterogeneity in the rock. Stationary vibrations are
caused by the natural resonance of the drillstring and are most likely to cause problems.
The most recognizable manifestation of
stationary torsional vibration is stick-slip
during rotary drilling, in which, because of
friction between the bit or BHA and the
wellbore and the spring-like nature of the
drillstring, the bit actually stops rotating
even though the drillpipe is still being
turned at a constant rate on surface—the
stick phase.
After a short period of stasis, sufficient
torque is stored up in the system to overcome friction and the bit starts turning,
speeding up to several times the speed of
rotation being imparted by the rotary table
or topdrive—the slip phase. This accelerated rotation may last for several seconds,
depending on the length of the drillstring.
Then downhole rotation begins to slow
again for another stick phase.
Stick-slip motion results in harmonic, torsional oscillations along the entire length of
the drillstring with a period governed largely
by the length of the drillstring, and to a
lesser extent, the rotational speed at the top.
These vibrations exert high cyclic stresses
on the drillpipe and slow drilling.
The high speeds achieved during the slip
phase are also one of the causes of the third
mode, transverse vibrations. However,
analysis of transverse vibrations cannot rely
on a harmonic model. This is important
because in the past it was believed that by
“fine-tuning” the drillstring—varying its rate
of rotation (revolutions per minute or rpm)
and weight on bit (WOB)—to avoid a resonant frequency, transverse vibrations that
have been initiated downhole may be
stopped. Studies by Anadrill reveal that
once such vibrations start, fine-tuning does
not always work.4
Other field evidence has been assembled.
Transverse vibration problems frequently
occur in hard or abrasive formations. And
shocks are often seen as the MWD or adjacent stabilizer passes from a soft to a hard
formation, without changes in rpm.
These facts, together with laboratory
observations, led Anadrill to conclude that
the interaction between the drillstring and
the borehole wall must be included in any
Frictional
(tangential)
reaction force
Normal
(radial)
reaction
Resultant
motion
Drillstring
element
Borehole
wall
nCreation of transverse vibrations.
When a rotating drillstring collides with
the borehole, its resultant motion is a
response to rapid acceleration due to the
inelastic collision, and tangential acceleration due to the frictional forces opposing
its rotation.
On wall contact, if the energy transferred from rotation to transverse motion is
greater than that absorbed by the rock
during the impact, drillstring transverse
vibrations will increase. Consequently,
subsequent interactions with the borehole
will be increasingly energetic until the
mean energy gained at each impact is
balanced by the absorption of energy
throughout the cycle.
Oilfield Review
Surface
WOB klb
0
100 0
rpm
Lithology
BHA
Shocks
counts/ft
0
200
Resistivity
ohm-m
250 0
2
X300
Depth, m
analysis. Therefore, it is not sufficient to simply identify resonant conditions using linear
harmonic analysis.
At the heart of the generation of transverse
vibrations is a self-sustaining interaction
between the rotating drillstring and the wellbore (previous page ). Once initiated, this
interaction is hard to stop. This coincides
with field observations showing that once
shocks are observed downhole, varying the
rpm will often affect only the number and
severity of the shocks. Shocks are not eliminated until the rpm is reduced to a much
lower value than the rate at which they
commenced. Thus, significant shocks may
be sustained at all but the lowest rpm.
Variation in transverse vibration with
lithology is due to changes in the rock’s
coefficients of friction and restitution. As
friction between the drillstring and rock
increases, more energy per impact is transformed from rotary to transverse motion. In
some cases, “friction” may be exaggerated
through the digging action of stabilizers
clashing with the borehole.
The coefficient of restitution determines
what proportion of the kinetic energy at
impact is absorbed by the formation; low
restitution results in significant energy
absorption. Because limestones and sandstones have high coefficients of friction and
restitution, they are more likely to generate
high shocks than soft shales, which have
lower coefficients of friction and restitution
—again confirming field observations (right ).
X350
X400
Safe 20 klb WOB
Sandstone
Silty shale
nEffects of lithology
on vibration. In this
example, torsional
and transverse
vibrations are measured as downhole
shocks above a certain threshold. The
first shocks are
observed at 358 m,
which is where
the midpoint of
the span between
the bit and stabilizer enters the
sandstone, a rock
type that often promotes vibration. In
this BHA, the midpoint is the most
likely point to
impact the formation. The shocks
disappear when
the midpoint of the
span exits the sandstone and passes
into the claystone
at 386 m.
Span midpoint
Shale
121/4-in.
stabilizer
MWD
Shock Treatment
Once the general principles are understood,
the next step is to find practical ways of
reducing vibration-related drilling costs. To
do this, the driller must be able to measure
the downhole shocks caused by vibration
and then apply appropriate remedies. The
capability to fulfill both these objectives
already exists. First comes measurement.
When there is a complex combination of
events, as is the case with the creation and
propagation of downhole vibrations, one
approach is to try to construct a sophisticated model that may be employed to predict safe operating ranges for critical parameters. However, such a complex model must
include parameters like rock hardness and
hole gauge that are not available for realtime use during drilling.
So, at least in the case of transverse vibrations, modeling is not a field solution. A
more pragmatic approach is to use a simple
downhole sensor to answer the key ques-
2. 250g is approximately equivalent to the force felt by a
driver when stopping a car travelling 150 miles/hr
over a distance of 3 ft (or 240 km/hr over 1 m).
3. Dufeyte M-P and Henneuse H: “Detection and Monitoring of the Slip-Stick Motion: Field Experiments,”
paper SPE/IADC 21945, presented at the 1991
SPE/IADC Drilling Conference, Amsterdam, The
Netherlands, March 11-14, 1991.
4. Aldred WD and Sheppard MC: “Drillstring Vibrations:
A New Generation Mechanism and Control Strategies,” paper SPE 24582, presented at the 67th SPE
Annual Technical Conference and Exhibition, Washington DC, USA, October 4-7, 1992.
5. Rewcastle SC and Burgess TM: “Real-Time Downhole
Shock Measurements Increase Drilling Efficiency and
Improve MWD Reliability,” paper SPE/IADC 23890,
presented at the 1992 SPE/IADC Drilling Conference,
New Orleans, Louisiana, USA, February 18-21, 1992.
Alley SD and Sutherland GB: “The Use of Real-Time
Downhole Shock Measurements to Improve BHA
Component Reliability,” paper SPE 22537, presented
at the 66th SPE Annual Technical Conference and
Exhibition, Dallas, Texas, USA, October 6-9, 1991.
Cook RL, Nicholson JW, Sheppard MC and Westlake
W: “First Real Time Measurements of Downhole
Vibrations, Forces, and Pressures Used to Monitor
Directional Drilling Operations,” paper SPE/IADC
18651, presented at the 1989 SPE/IADC Drilling Conference, New Orleans, Louisiana, USA, February 28March 3, 1989.
January 1994
tion: Is the drillstring experiencing damaging vibrations? The answer may then be
used without recourse to a model.
To supply this information, Anadrill uses a
single downhole accelerometer mounted
eccentrically—so that it measures both
transverse and torsional vibrations—in the
MWD electronics housing. It is programmed to count downhole shocks, sending the information in real time to surface.5
Such downhole shock measurements have
17
100
0
ROP m/hr
GR
rpm
200
Surface
150 0 WOB 1000 kg 25
0 0
121/4-in.
hole
0
Surface torque
kNm
50
2250
M i n Max
81/2-in.
hole
Change the BHA
Downhole
shock sec-1
Downhole
shocks
MWD Tool
enters 81/2-in.
hole
2300
Stabilizer enters
81/2-in. hole
Topdrive
stalling
2350
Driller tests a
different rotary
speed
nUsing real-time information to manage downhole shocks. This example from the
North Sea, with an 8 1/2-in. polycrystalline diamond compact (PDC) bit, shows why
vibrations cannot be easily predicted using a model. More than 100 shocks per second
were experienced in the first 15 m of drilling (2260 to 2275 m) with cyclical surface
torque. This corresponded to the 1/2-in. BHA being unstabilized in the 12 1/4-in. rathole
and precessing around the wellbore. Once the MWD fully entered the 8 1/2-in. hole, the
measured shocks dropped significantly. At 2285-m bit depth, the stabilizer entered the
8 1/2-in. hole and downhole shocks were further reduced to an acceptable value. Coincidentally, the gamma ray log shows a formation change at 2285-m bit depth, the
point at which the rate of penetration increases.
Shocks between 2307 and 2311 m coincided with the topdrive stalling. At 2325 m the
rotary speed was increased from 140 rpm to 175 rpm with no increase in downhole
shocks. At 2344 m, the rotary speed was decreased and this resulted in shocks. The
speed was then increased to avoid bit damage. A later reduction in rpm did not
increase shocks.
been used successfully to monitor the vibration effects of the BHA (above ).
Once significant shocks are detected, the
next step is to reduce them. To do this, the
driller has three options depending on circumstances: modify drilling parameters during drilling until shock measurement shows
that harmful vibrations cease, pull the BHA
out of hole and run one less likely to
vibrate, or employ special systems, such as
torque feedback to reduce stick-slip.
18
Monitor Shocks and Modify Drilling
Parameters
Ideally, monitoring and modification may
be employed without stopping drilling.
Based on feedback from real-time shock
measurement, drilling parameters—usually
rpm and WOB—may be adjusted to minimize vibrations. However, in some severe
cases it may be necessary to stop drilling
altogether and let the vibrations dissipate.
Then, when drilling restarts, the rpm and
WOB may be modified to minimize highenergy wall contact.
In hard, abrasive formations, finding a
rotary speed that completely eliminates
shock is sometimes difficult, if not impossible. In this case, rpm may be reduced to its
lowest acceptable level to reduce shocks as
much as possible. The rate of drilling will
clearly suffer and although WOB may be
increased to limit the reduction in penetration, there is a trade-off. But if the number of
trips is reduced or a fishing job eliminated
by drilling more slowly, the trade-off will
have been worth it.
If drilling parameter control proves unsuccessful, the drilling engineer may opt to
change the BHA, usually at the next scheduled trip. There are several different strategies
to BHA design: pay extra attention to minimize the potential for wall contact; eliminate
surface rotation almost completely by using
downhole motors; or counteract vibration
using special downhole equipment.
•Minimizing wall contact—An important
design parameter for minimizing transverse vibrations is the span between two
stabilizers. Long unstabilized spans—such
as those found in pendulum assemblies
used in vertical drilling—encourage bending and help induce transverse vibrations.
Another likely source of excitation is
wellbore contact by undergauge stabilizers, which can make contact with the
borehole wall following only a small displacement from the center of the hole
axis (next page, top ). Whenever possible,
the number of undergauge stabilizers in
the BHA should be minimized.
Care should be taken when drilling
with the BHA in the casing, since the
BHA is effectively unstabilized in the
higher-diameter cased hole. Furthermore,
vibrations in the casing tend to be more
severe as the casing has a high coefficient
of restitution and provides an ideal environment for vibrations to develop.
•Reducing vibrations by reducing surface
rotation—Since drillstring rotation is a
primary cause of torsional and transverse
vibrations, significantly reducing rpm can
be helpful. Downhole drilling motors may
be used so that the rpm imparted at surface may be eliminated or greatly
reduced, ensuring that most of the string
has low rotational energy and substantially reducing the energy of interactions
between the rotating BHA and wellbore.
•Counteracting vibrations using special
downhole hardware—We will look at the
two of the most popular classes of equipment used to limit drillstring vibrations:
shock guards and antiwhirl bits.
Shock guards—Sometimes downhole
subs are employed to absorb particularly
bad axial vibrations. Most common are
Oilfield Review
MWD
MWD
shock guards that contain an arrangement
of springs and act like car shock absorbers
to limit bit bounce. Typically, these modify the resonant axial response of the drillstring to avoid excitation of axial vibration
in the range of rpm being used.
Antiwhirl bits—Bit whirl is an integral
part of the transverse vibration phenomenon. It is characterized by the bit’s
instantaneous center of rotation moving
erratically around the work face during
drilling—so that the center of the bit does
not coincide with the center of the hole. It
is particularly prevalent with polycrystalline diamond compact (PDC) bits and
accelerates cutter damage and bit wear.
Theoretically, the best way to prevent
the onset of bit whirl is to perfectly centralize the BHA at all times. However, in
many cases the hole becomes enlarged or
there are undergauge stabilizers and, once
the bit is slightly unconstrained, it can
begin to whirl. When this starts, the hole
becomes even more out of gauge and the
process becomes self-perpetuating.6
PDC bits usually have aggressive side
cutters that dig into the borehole, accentuating transverse vibration and bit whirl.
Antiwhirl PDC bits have been developed
with all the cutter faces placed to create a
radial force that is focused in one direction, driving one side of the bit against the
borehole (above, right ). However, on this
side of the bit, the cutters are replaced by
a noncutting wear plate that has much
lower frictional contact with the borehole
than the cutters. Because friction in the
direction of the bit’s deliberate imbalance
is low, the bit slides at the borehole wall
and does not whirl.
nEffect of an
undergauge stabilizer. With little lateral movement,
the undergauge
stabilizer moves
from the center of
the borehole when
at rest (top) to
impact the borehole wall (bottom).
With the rotating
undergauge stabilizer hitting the formation, transverse
vibrations will be
established, sending shocks through
the MWD collar.
nAntiwhirl bit. All the forces on the cutters of an antiwhirl PDC
bit force the smooth wear plate against the borehole wall preventing bit whirl.
6. Warren TM, Brett JF and Sinor LA: “Development of a
Whirl-Resistant Bit,” SPE Drilling Engineering 5
(December 1990): 267-274.
January 1994
19
Employ a Torque Feedback System
7. Halsey GW, Kyllingstad A and Kylling A: “Torque
Feedback Used to Cure Slip-Stick Motion,” paper SPE
18049, presented at the 63rd SPE Annual Technical
Conference and Exhibition, Houston, Texas, USA,
October 2-5, 1988.
Dufeyte and Henneuse, reference 3.
8. Sananikone P, Kamoshima O and White DB: “A Field
Method for Controlling Drillstring Torsional Vibrations,” paper SPE/IADC 23891, presented at the 1992
SPE/IADC Drilling Conference, New Orleans,
Louisiana, USA, February 18-21, 1992.
20
Voltage
feedback
Current
sensor
Desired
+
rpm
-
Voltage and
current
regulator
Power
converter
Shaft
encoder
Motor
Current
feedback
Drillstring
Microprocessor
On/off switch
nTorque feedback system. A combined motor current and acceleration feedback system is used to minimize the reflection of torsional
waves. Monitoring the motor current and the angular acceleration of
the drillstring provides a better estimate of the true drillstring torque
than is obtained by measuring the motor current alone. By combining the two measurements in the feedback loop of the control system, the reflection of torsional waves is significantly reduced over a
wide range of frequencies. It is not necessary to adjust the system for
different drillpipe sizes or for depth changes.
nTorque feedback in
action. In this example, the feedback
control was turned
on for just over 30
minutes. During this
time the feedback
system controlled
the rotary drive
direct current motor
to reduce torsional
vibrations. Less than
3 minutes after the
feedback system
was turned off, the
drillstring vibrations
grew into sustained,
high-amplitude
oscillation.
10
Drillstring torque, kNm
The third major option is the elimination of
stick-slip. When people catch a hard ball,
they draw their hands back as the ball
enters. If they don’t absorb energy in this
way, the ball may bounce out. Torque feedback—or soft torque as it is sometimes
called—uses a similar approach to eliminate
torsional vibrations.
Conventionally, rotary speed is maintained at a constant rate, independent of
torque load. The ideal rpm is usually specified by the drilling engineer depending on
the formation and the bit type. The driller
then attempts to maintain the prescribed
rpm without fluctuation.
When a torsional vibration wave travels
up the drillstring, it increases strain in the
drillpipe at surface. To oppose this strain
and maintain constant rpm, the rotary table
or topdrive has to work harder. In modern
rigs, this is usually achieved by an automatic increase in the current driving the
electric motors that turn the drillstring. In
these circumstances the torque waves are
effectively reflected back, amplifying stickslip downhole. Left alone, these vibrations
are essentially self-sustaining and torsional
vibrations build to a maximum amplitude
limited by interactions along the drillstring.
Like successful catchers, a torque feedback system finds a way of absorbing this
torsional energy.7 By sensing the increase in
torsional strain in the drillpipe at surface,
the system reduces input rotation to create a
sort of “antitorsional wave” that dampens
rather than amplifies the vibration, effectively eradicating the self-sustaining torsional vibrations.
Perhaps the most direct way of achieving
this is through direct measurement of drillstring torque using surface strain gauges. But
in practice, delicate instruments required for
this are unlikely to withstand the harsh
drillfloor environment. Sedco Forex has
devised a system that produces results similar to those using strain gauges but employs
drive motor current and acceleration measurements that may be equated to surface
torque (top ).8
The aim is to dampen the torsional wave
at surface to a minimum across a wide
Off
8
6
4
12
18
24
30
36
Time, min
range of vibration frequencies. A control
system continuously monitors the current
and acceleration of the motor turning the
drillstring. Part of the control system consists
of a feedback loop set up so that the system
automatically adjusts the instantaneous rpm
to dampen torsional waves (above ). The system is now fitted in a dozen or so rigs and
may be employed whenever stick-slip is
expected to be problematic.
The Future for Drilling Vibrations
Some sectors of the industry have recognized the potential for reducing drillstring
vibrations and know that much of the
required technology is already available.
The challenge is to build effective teams of
drilling engineers, drillers and service company personnel dedicated to raising aware-
ness and using the available tools and
know-how. These teams can then effectively
plan vibration-reducing strategies and operational guidelines based on reliable monitoring and application of suitable hardware.
If these efforts are successful, rates of penetration will be increased, numbers of fishing jobs reduced, hole quality improved and
downhole equipment will be spared damaging and expensive shocks. At a time when
almost all eyes are focused on costs, the
elimination of drilling’s bad vibrations represents a significant potential for savings without the need for massive technology development programs.
—CF
Oilfield Review