American Oil and Gas Reporter - July 2015 - 57

SpecialReport: Horizontal Well Operations

Well Features Impact CT Reach Limits
By Patrick Kelleher,
Ken Newman,
Irma Galvan
and Steve Opel

NEW WAVERLY, TX.-The continued
growth of extended-reach wells and the
expanded use of coiled tubing during
completion operations in these wells has
placed increased reach requirements on
CT units performing fracturing plug millouts, creating demand for increased-capability CT spreads.
CT reach typically is limited by friction
lockup during milling operations and can
reduce effective pay zone penetration.
Several common well features typically
contribute to the majority of the low
force transfer factors, leading to insufficient
set-down force and helical lockup. The
industry has responded by creating larger
CT rigs utilizing significantly larger-diameter tubing that can reach farther into
laterals as a result of reduced radial clearances and higher flow rates for more efficient hole cleaning.
While the entire industry is working
to improve CT reach, it may be possible
in certain circumstances to extend CT
reach using existing equipment by making
minor changes to horizontal well designs.
For this to be possible, several considerations must be made following an appropriate workflow that includes:
* Quantitatively identifying well features and possible variations that significantly impact CT reach;
* Identifying limiting factors for these
features, such as flow requirements during
fracturing or production, well site location,
lease boundaries, true vertical depth of
the pay zone, etc.; and
* Performing an economic analysis
of the impact of adjusting any of these
parameters to justify a completion design
change.
The quantitative impacts that variations
in key well feature have on CT reach
provide parametric references for completion engineers to consider during the
well design process. A case study of several Marcellus Shale horizontal well designs illustrates some of these parameter
variations, and how they impact typical
CT reach capabilities using a tubing
forces model. Features analyzed include
kick-off build rate, vertical sections and
simple deviations down to the heel, tra-

jectory changes in the horizontal section,
well completion geometry, and required
weight on bit (WOB).

Friction Lockup
Friction lockup occurs when a CT
string reaches a point in the wellbore
where any depth increase is prohibited
by insufficient available set-down force
because of frictional forces acting on the
length of the CT string (generally the
result of friction from wall contact forces
between the tubing and the hole through
which it is being conveyed). However,
under most conditions, lockup can be attributed largely to two occurrences that
cause wall contact forces to increase as
compressive axial force increases: the
capstan (belt) effect around the wellbore
curvature, and helical buckling of tubing
sections inside the casing where the compressive axial force exceeds the helical
buckling load.
Analytically, friction lockup can be
defined as the depth at which setting
down additional force at surface results
in only a small force increase at the end
of the bottom-hole assembly. The percentage of additional force applied to
the BHA to the change in surface force
is defined as the force transfer factor
(FTF).
For this analysis, lockup is assumed
at the depth where the total FTF for the
entire well crosses the 1 percent threshold
with the required WOB applied to the
end of the BHA. Since a tubing forces
model must take various boundary conditions into account, the string typically
is broken into numerous elements, with
a wall contact force and associated FTF
for each element.
Force transfer loss is dependent on
the FTF, but it can be calculated for any
continuous section of CT in a well. A
loss factor of 98 percent in the vertical
section suggests that almost all additional
force transferred from the surface to the
tubing string is lost to wall contact forces
in the vertical section, while minimal
force transfer loss in the lateral suggests
that all additional forces from the heel
can be transferred to the end of the CT
string.
Friction caused by buoyant weight in
the lateral does not impact the force transfer loss because the friction force on a
small segment of tubing due to weight is

constant and independent of both input
and output force. This makes it easier to
locate tubing sections where buckling or
curvature creates a rapid force transfer
decrease.
Figure 1A shows the normalized wall
contact forces along the axis of the tubing
in a Marcellus "base case" well before
lockup. Dark sections of the tubing indicate
areas with the most side wall forces and
light areas indicate little or no wall contact.
The majority of wall contact occurs in
the lateral because of the CT's buoyant
weight. Figure 1B shows the force transfer
loss along the tubing axis at lockup, indicating that the majority of additional
set-down force from surface is lost in the
vertical section. Figure 1C shows the

FIGURE 1A
Well Contact Force
Before Lockup
* Side wall force in lateral primarily from
buoyant weight
* Low side wall force in most of the vertical

FIGURE 1B
Force Transfer Loss at Lockup
* High force transfer loss (98% in vertical)
* Low force transfer loss (0% in lateral)

FIGURE 1C
Well Contact Force after lockup
* High side wall force throughout lateral
and much of the vertical
* Low side wall force near surface

JULY 2015 57



American Oil and Gas Reporter - July 2015

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