American Oil and Gas Reporter - July 2015 - 58

SpecialReport: Horizontal Well Operations
normalized wall contact forces after applying an additional 50 pounds of WOB.
Note the migration of wall contact force
upward into the heel and vertical section
compared with Figure 1A.

Marcellus Case Study
Eleven extended-reach wells in the
Marcellus Shale play with somewhat similar TVDs were selected for analysis to
identify how well features impact CT
forces. From these wells, average build
rates, lateral turns, toe inclinations, and
lateral tortuosity values were estimated
and assembled as a range of parameter
values. Based on these values, a set of
base parameters was selected to represent
the control well (base case). The specific
parameters of the base case well included
a build rate of 5.0 degrees per 100 feet, a
TVD of 6,145 feet and a 5.5-inch/17
pound-per-foot casing monobore with no
lateral turns or tortuosity.
The CT string design created for the
base case remained constant with each
parameter variation. This reflects many
CT operations, since it is common to design a CT string for one particular well
and then use it throughout a field with
only slight trajectory variations.
Monowall CT is the simplest design
available. It performs sufficiently for most
well interventions and permits simple
pipe management strategies. However,
for many unconventional wells, monowall
designs do not fit required operational
parameters. In the case of the Marcellus
wells, monowall designs could not produce

sufficient WOB in extended lateral sections
to reach total depth while milling out frac
plugs or sliding sleeves. For this reason,
a custom multitaper CT string was designed
to reach 15,000+ feet. The design optimizes
reach by reducing weight in the lateral
and increasing stiffness in the vertical
section, where high wall thickness cannot
prevent helical buckling.
Designing an extended-reach CT taper
normally requires many iterations of tubing
force modeling. Parameters that engineers
may optimize include section length, wall
thickness, outside diameter, and material
yield stress. Unfortunately, even with advanced trip in-hole simulations, this can
require hours of design engineering work.
To reduce this constraint, an automated
extended-reach CT design computer program was created in conjunction with this
study to perform systematic optimizations.
The algorithm in the Cerberus™ v12.0
String Design Wizard software optimizes
available tubing parameters by performing
dozens, or even hundreds, of tubing force
modeling (TFM) simulations in a matter
of seconds.
The automated program resulted in a
23⁄8-inch, 100-ksi yield string design with
aggressive wall tapers to provide enhanced
reach benefits (the design can be safely
achieved using linear tapers available
from CT manufacturers). Wall thickness
was limited to 0.156 inches and higher
to reduce fatigue and diametrical growth

Buildup Rates
Since wells are always planned to
reach a specific TVD, the buildup rate
(BUR) and length of the vertical section
are typically coupled. Increasing the
buildup rate implies increasing the vertical
section length, and vice versa. TVD generally was considered fixed in this manner
throughout the study.
Varying build rates with a fixed TVD
of 6,150 feet reduced lateral reach by
734 feet when BUR was increased by
3.0 degrees/100 feet (to 8.0 degrees). Increasing BUR to 14.0 degrees/100 feet
resulted in even less lateral reach-even
with an increased kickoff depth and an
associated weight increase near the heel-

FIGURE 3
Helical Buckling Load in Heel
0

FIGURE 2
Base Tubing Forces
Model Results at Lockup

-5,000

Helical Buckling Load (lb/f)

0.0

2,000.0

4,000.0

6,000.0
Depth (ft)

issues associated with cycling the tubing
in and out of the well.
TFM simulations of the CT string run
in the base case well resulted in an overall
lockup depth of 15,215 feet with 500
pound/foot WOB. The end of the heel
for the base well was at 6,800 feet,
yielding a lateral reach of 8,415 feet.
The ratio of TD/TVD was 2.47. Figure 2
shows the base case axial force along the
wellbore depth near friction lockup. The
location of the effective force run into
the hole versus the buckling load indicates
that there was no near-lockup helical
buckling in the lateral and heel, but significant buckling from the top of the
build section to surface.

8,000.0

10,000.0

-10,000
-15,000
-20,000
-25,000
-30,000

12,000.0

-35,000
14,000.0

Buckling Load
Effective Force RIH
Effective Force POOH

16,000.0
-20,000.0

0.0

20,000.0
Force (lbf)

40,000.0

58 THE AMERICAN OIL & GAS REPORTER

-40,000

0

2

4

6
8
10
Buildup Rate (deg/100 ft)

Helical Buckling Load in the Heel (lb/f)

12

14

16
American Oil and Gas Reporter - July 2015

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