WELLBORE TUBULARS
Axial-Force Transfer of Buckled Drillpipe in Deviated Wells
Horizontal Well Without Dogleg
5000
Model, rotation
4500
Top Load, N
Axial-force transfer is an issue in deviated wells where friction and buckling
phenomena take place. The general
perception in the industry is that once
drillpipe exceeds conventional buckling
criteria, axial force cannot be transferred
downhole. The full-length paper shows
that, even though buckling criteria are
exceeded, axial-force transfer still could
be good if drillpipe is in rotation.
Tests without rotation
4000
Tests with rotation
3500
Model, loading/unloading
3000
Loading
2500
Unloading
2000
1500
Introduction
Axial-force transfer is an issue in highly
deviated wells, such as horizontal and
extended-reach-drilling (ERD) wells
where drag friction is significant and
buckling may occur. These challenging
wells are characterized by a long horizontal departure (HD) relative to the
true vertical depth (TVD) of the well.
The axial-force-transfer issue comes
from insufficient tubular weight in the
vertical, or low-deviation, section of
the well to run the drillstring in the
long horizontal section. To overcome
this problem, drilling engineers sometimes use drill collars or heavyweight
drillpipe above regular drillpipe to push
the string downhole. The critical angle
for which drillpipe can no longer move
downhole because of its own weight is a
function of the coefficient of friction, μ.
Drilling and completion runningstring designs for these increasingly
complex wells are based on torque-anddrag results, and more specifically on
This article, written by Assistant Technology
Editor Karen Bybee, contains highlights of
paper SPE 119861, “Axial Force Transfer
of Buckled Drill Pipe in Deviated Wells,”
by S. Menand, SPE, H. Sellami, and A.
Bouguecha, Mines Paris Tech.; P.
Isambourg, Total S.A.; and C. Simon,
SPE, Drillscan, originally prepared for the
2009 SPE/IADC Drilling Conference and
Exhibition, Amsterdam, 17–19 March.
The paper has not been peer reviewed.
1000
500
0
0
500
1000
1500
2000
2500
3000
3500
4000
4500
Bottom Load, N
Fig. 1—Axial-force transfer with and without rotation, µ = 0.38.
buckling criteria, to determine if the
string can be run in the hole. However,
some recent papers and some full-scale
experiments have shown that these conventional buckling models should be
revisited. Because these models fail to
predict buckling correctly, they also fail
to predict axial-force transfer. Drillingequipment manufacturers have developed some torque-and-drag-reduction
tools to push the limits of ERD. Even
though these tools are able to reduce
friction in certain situations, accurate
modeling still is needed to predict the
axial-force transfer correctly and the
occurrence of lockup.
Tools, Techniques, and Methods
Many methods and tools can be used
to reduce friction and improve axialforce transfer. Friction reduction can
be obtained with liquid or solid lubricants and mud additives, mechanical
tools such as rollers, and by vibrating
or rotating the drillstring. The goal of
these tools is to reduce friction between
the drillstring and borehole to improve
axial-force transfer downhole. Torqueand-drag- or friction-reduction tools
can be added to drillpipe or completion-
running strings. They consist generally
of nonrotating sleeves (or centralizers)
or low-friction slider pads that reduce
friction in the axial (sliding) or tangential (rotating) direction. Even though
these tools can reduce the friction coefficient as much as 50%, these special
devices require additional rig time for
installation and removal and generally
are used only in the cased-hole section.
Existing Models
Existing theories provide correct results
only for a perfect wellbore geometry,
without considering both friction and
rotation. However, except for these
ideal configurations, the existing theories can predict neither the buckled
state of the drillstring nor the axial-force
transfer from the surface to the bottom.
The mechanical problem of a tapered
drillstring rotating inside a 3D wellbore with tortuosity requires advanced
numerical models to predict the buckling and axial-force transfer correctly.
There is no unique buckling criterion
valid for different operational situations.
A sliding or slackoff situation (i.e., axial
friction, no rotation) is totally different
from a drilling situation (i.e., tangential
For a limited time, the full-length paper is available free to SPE members at www.spe.org/jpt.
80
JPT • MAY 2009
friction, rotation, and torque friction).
Small doglegs can affect the critical
buckling load significantly.
Torque-and-drag models need to be
coupled with a buckling model to compute friction losses all along the drillstring properly. Increasing drag will
increase compression in drillpipes, and
this will lead to even more buckling
and even greater contact forces, leading
again to increased drag. This simultaneous calculation, only possible with
large computation times through finiteelement analysis (FEA), is now possible
with the new model.
Model Description
The numerical model, ABIS, dedicated
to drillstring mechanics from drill bit to
surface, can simulate any drilling tool
for direction analysis such as point-thebit or push-the-bit rotary-steerable systems, steerable mud motor, and adjustable-gauge stabilizers and can perform
torque/drag and buckling analysis for
tubulars from conventional drillstrings
to coiled tubing. Because the drillstring
is divided into very-small-beam elements, the model permits focus on
any critical drillstring component such
as measurement-while-drilling (MWD)
tools or electronic measurement subassemblies. The model considers any
external forces applied on each element
of the drillstring such as hydraulic forces or temperature effects in the case of
high-pressure/high-temperature wells.
Although the 3D mechanical behavior
of drillstring generally is solved by use
of FEA, the current model is based on a
numerical solution of integral equations
that greatly reduces the computational time. Any well-trajectory geometry
can be simulated, with possible borehole enlargement, and the rotation of
a beam element is accounted for with
the μ, making this model very close to
simulated field conditions. The model
includes a contact algorithm based on
an iterative process: At first, no contact
is assumed, and then contact points are
calculated successively.
The software can perform torque,
drag, and buckling calculations simultaneously, enabling the friction analysis to
account for the increased contact force
generated by buckling. These calculations are performed within a short iterative process to check the equilibrium
state of the buckled drillstring (stable or
neutral). Fig. 2 in the full-length paper
shows an example of buckled drillpipe
JPT • MAY 2009
in a tortuous horizontal wellbore and
highlights the 3D contacts between the
wellbore and the drillstring.
Experimental Setup
A testing facility has been built to perform small-scale experimental tests. A
15-m, 0.60-kg/m steel pipe (outside
diameter=13.5 mm) was inserted into
a transparent plastic tube (inside diameter=42.2 mm) representing the wellbore. The pipe and tube sizes were
selected by using a scaling criterion
that considers the ratio of the size of
the hole to the outside diameter of the
pipe. The tube was sufficiently flexible
to produce doglegs along the path to
study the tortuosity effect on buckling.
Both fixed- and free-end support can be
provided to the pipe. A motor is fixed
at one end to make the pipe rotate, and
it enables torque and rotation speed to
be recorded vs. time. The experimental
facility allows axial load to be applied
at one end of the pipe and load to be
measured at both ends of the pipe. The
compressive axial load is applied by a
hand-controlled hydraulic jack, enabling
the experiment to be paused at any position for visual inspection and additional
measurements. The displacement of the
pipe is measured by a linear variabledisplacement transducer at the top end
of the pipe, and the loads and displacements are recorded by a computer dataacquisition system. A typical experiment
consists of loading the pipe to a given
compressive load and then unloading
the pipe back to its original state, with
or without rotation. The μ between the
pipe and the plastic tube has been measured to be from 0.25 to 0.38.
Results
The objective of the full-length paper is
to show and explain how axial force is
transferred downhole in simulated field
conditions. For each situation, compressive top and bottom loads are measured to determine axial-force transfer.
If the top load is equal to the bottom
load, then axial-force transfer is 100%
efficient. The following four cases were
considered for a horizontal well.
• Case 1—without dogleg in sliding
mode.
• Case 2—without dogleg in rotating
mode.
• Case 3—with dogleg in sliding
mode.
• Case 4—with dogleg in rotating
mode.
Each experiment is compared to the
numerical model.
Sliding vs. Rotating. Fig. 1 shows the
axial-force transfer (top load vs. bottom
load) for a nonrotating and rotating
pipe when the pipe is loaded (increasing
compressive load) or unloaded (decreasing compressive load) in a horizontal
well (Cases 1 and 2, respectively). In
the loaded case without rotation (similar to a slackoff or sliding situation), the
bottom load is less than the top load, as
a result of sliding friction. Once the pipe
without rotation is unloaded, the relative motion between the pipe and the
tube becomes opposite, and this is why
the bottom load is greater than the top
load (the pipe is pulled out of the hole).
As observed experimentally by numer-
ous authors, this hysteresis effect is the
result of friction because the relative
motion between the pipe and the tube
is opposite when the pipe is loaded or
unloaded. The current model is able to
reproduce this hysteresis effect.
For the rotating case, the hysteresis
effect has disappeared almost completely
in the experiments; that is, the loading
curve is quite similar to the unloading
curve. This effect depends on the ratio
of the rotation speed of the pipe to
the loading/unloading rate. The current
model is able to reproduce correctly
observations made in the laboratory. For
the axial-force transfer in sliding mode
for the horizontal well without or with
doglegs (Cases 1 and 3, respectively),
the weight transfer is affected by the
dogleg because approximately 70% of
the top load is transferred to the bottom
load (Case 3) when the top load reaches
5000 N. Experimental and numerical
results show that axial-force transfer is
very good, even though conventional
helical-buckling criteria are exceeded. At
a compressive load more than two times
the conventional critical helical load, the
axial-force transfer still is very good.
These laboratory tests and numerical simulations demonstrate that the
axial-force transfer is quite good even
though drillpipe is helically buckled
and that helical buckling decreases
axial-load transfer in sliding mode, but
not in rotating mode. These observations confirm field case studies where it
was possible to drill with compressive
loads significantly higher than standard
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critical-buckling loads.
DOWNHOLE WELL CONNECTIONS . . . (Contd. from page 77)
drilled), a magnetic sensor is run on
wireline and placed inside the nonmagnetic collars. The intersecting well is thus
the receiver for the SWG tool. The direction and distance to the transmitter/target
well are calculated from the sensor data.
RMRS. As opposed to SWG service,
with RMRS the intersecting well is
the transmitter and the target well is
the receiver. Permanent magnets are
mounted in the bit subassembly transverse to the bit-rotation axis. As the bit
turns, the magnetic fields rotate with it.
A three-component AC magnetometer
located in the target well, somewhere
in the general projected path, measures
the local time-varying magnetic field.
The location of the receiver relative
to the rotating magnets is determined
from the AC magnetic data along with
the known rotation-axis orientation
(drilling survey) and the known receiver orientation (target survey or gravity
and Earth-magnetic-field data from the
tool). Data travel up the wireline to
a radio modem that transmits data to
the command center on the drilling
rig. This allows continuous updates
on the target coordinates to the directional driller.
Field Trial
After extensive testing and determining the ranging technology suitable, an
existing offshore well jacket in Southeast
Asia, in 5.1 m of water and 1.3 km from
shore, was identified as a good candidate for field validation of the concept.
In late December 2006, a well was spudded from a nearby onshore location
with the intention of drilling directionally to connect hydraulically to one of
the wells drilled from the well jacket.
Two electromagnetic-ranging systems,
SWG service and RMRS, were tested
from less than 220 m and less than
45 m measured depth from the target.
The electromagnetic-ranging technology facilitated the successful intersection
of the target well according to plan with
a bypass within the specified proximity
(less than 40 cm) and in the correct
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sand (±1.5-m TVD window).
CASING ULTRADEEP, ULTRALONG . . . (Contd. from page 79)
Lamé’s equation. Both plane-stress and
plane-strain solutions were considered
by applying the elastic 2D method.
A numerical solution is required to
model casing failure under more-complicated loading conditions, such as nonuniform salt-to-casing contact at a given
depth, or at different depths. The 3D
FEM model was used for this analysis.
Casing-Failure Diagnosis
and Mitigation
On the basis of the models described
in the full-length paper, casing failure in Well 1 was most likely caused
by nonuniform-salt-contact stress. The
lightweight casing used in this well
had insufficient strength to bear the
nonuniform stress with the given MW.
Therefore, the casing experienced plas82
tic deformation and failed. The FEM
models indicated no significant deformation for heavy-walled pipe under
conditions in which the magnitude of
radial stresses varied axially, smoothly
increasing with depths, distributed over
angles of 18°, and applied diametrically. Therefore, the modeling showed the
heavy-walled pipe proving to be highly
effective in resisting large, less-thanextreme loads. Therefore heavy-walled
pipe (135/8 in., 88.2 lbm/ft) should be
incorporated into the drilling programs
of future wells.
Under any circumstances, the
extreme stress conditions (asymmetrical nonuniform salt contact) described
in Model 3 in the full-length paper
must be avoided. The primary mitigation options include the following.
• Cement the annulus to maintain
uniform salt contact with the casing.
The base of the salt should be cemented
to prevent the nonuniform salt contact.
• Underream suspected slip or shear
load areas.
• Use higher MWs. Increasing MW
reduces the risk of collapse failure.
• Avoid suspected slip areas, inclusions, or sutures in the salt formation
while drilling.
Effective cementing of casing is one
of the most important factors in drilling long sections of salt successfully,
both for zonal isolation and for the
prevention of unequal loads on casing. Effective cementing is particularly
important at the base of the salt, where
the stresses and uniform salt/casing
contact are most critical.
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JPT • MAY 2009