American Oil and Gas Reporter - July 2015 - 62

SpecialReport: Horizontal Well Operations
ficients results in extended lateral reach
and a shorter length of buckled tubing.
Conversely, higher friction coefficients
cause reduced lateral reach and typically
result in exacerbated buckling. Friction
coefficients generally are determined by
varying friction coefficients in a CT
forces model to find the values that cause
the calculated surface weight curves to
best fit measured surface weight values.
This can be difficult since many factors
can cause a shift in surface weight other
than downhole friction, including wellhead
pressure (WHP), stripper friction, reelback tension, force on tool, weight gauge
calibration, and dynamic forces down
hole or at surface.
WHP can be accounted for fairly
easily, and stripper friction and reel-back
tension can be calculated based on the
surface weights measured while the tool
is in the vertical section of the well. Data
points acquired during operations should
be excluded from the friction match if
they are suspected of having any significant forces not accounted for in the calculated surface weight plots. These forces
could be caused by set-down or pickup
forces on the end of the tool, effects of a
tractor, fluid hammer, or many other factors that could cause forces on the BHA
and CT.
This study compared friction coeffi-

cients of 0.3, 0.28, 0.25 and 0.20, as
shown in Figure 5. Even small changes
in the friction factor can have significant
effects on CT reach, especially when
there is sufficient compressive force on
the end of the BHA to induce helical
buckling in a portion of the tubing.

Lateral Design Issues
The capstan/belt effect that occurs
during trajectory changes can be summarized for lateral turns if the tubing
forces do not exceed the straight lateral
buckling load. Lateral reach is reduced
as an exponential function of the degrees
turned. However, if the axial force in the
lateral exceeds the helical buckling load,
the tubing forces modeling results are
less easily summarized.
These conditions were largely eliminated by the custom CT string design to
minimize buckling in the lateral. Lateral
turns of 23 and 45 degrees over 1,500
feet were simulated with 166- and 299foot reach reductions, respectively. Although any turn reduces reach, a slight
turn can be planned without greatly impacting maximum operational CT depth.
Since there is zero force transfer loss
in a straight section with no curvature or
buckling, if tortuosity is negligible and
the CT string is designed to avoid buckling
in the horizontal, then all force transfer

FIGURE 6
Lateral Tortuosity versus Lateral Reach
9,000

Lateral Reach (ft)

8,500

8,000

7,500

7,000

6,500
0.0

0.2

0.4

0.6
0.8
1.0
Tortuosity (deg/100 ft)
Lateral Reach (ft)

62 THE AMERICAN OIL & GAS REPORTER

1.2

1.4

1.6

loss will result from the heel (and just
above it) where buckling is likely to
occur. However, wall contact force caused
by buoyant weight in the lateral is still
present, so the force available at the
bottom of the heel must exceed the sum
of the friction force and the weight transferred from the end of the toe to the heel
to reach farther.
In both lateral "toe-up" inclinations
analyzed, buckling was induced in the
lateral even with the custom taper string
and caused increased force transfer loss
in the lateral. While this effect can be
mitigated by reducing friction using a
lubricant or downhole vibration tool, it
will impact only the friction force and
will not reduce weight transfer from the
end of the tubing. As a result, extendedreach wells with toe-up inclinations may
cause helical buckling of the CT near the
heel, even with a custom string design
and friction reduction methods.
Lateral reach was increased in wells
with toe-down laterals. The reach increases
seen with 1.0- and 2.0-degree toe-down
inclinations were 439 and 932 feet, respectively, compared with the reach reductions with the 1.0- to 2.0-degree toeup cases. The disparity between the impact
of toe-up and toe-down laterals on CT
reach can be attributed to the custom
taper string limiting lateral buckling. For
this situation, toe-down laterals cannot
reduce buckling in the lateral. Conversely,
toe-up designs using this custom tapered
CT string induced helical buckling in the
lateral near the heel, causing significant
reductions in lateral reach.
Theoretically, there is a "critical angle"
toe-down inclination at which the CT
weight vector can overcome the frictional
force as a result of buoyant weight. At
this angle, the tubing could be run with
minimal additional set-down weight at
surface. The critical angle depends on
the downhole friction factor, and friction
factors found during typical operations
limit it to inclinations between 75 and 80
degrees for well sections with zero curvature. These angles are far too aggressive
to help extend pay zone penetration in
most horizontal wells, making a critical
toe-down inclination an unrealistic design
consideration for most horizontal wells.
Other Key Factors
Other key factors impacting CT reach
include well pressures, WOB and tortuosity. Although well pressures are not
the result of a specific completion design,



American Oil and Gas Reporter - July 2015

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