OPTIMIZING WELL INTERVENTION
Real-time force monitoring
improves CT drillout efficiency
Interactive tubing force analysis models,
real-time data overlays reduce stuck pipe, NPT
BY JESSICA STUMP, TRAVIS THOMAS AND COLT ABLES, NOV
Considerable progress has been made in
advancing methods and procedures for
well intervention operations with coiled
tubing (CT). However, stuck-tubing events
are still common in post-fracturing drill-
outs. Most analysis happens after these
incidents have occurred, despite technol-
ogy allowing for real-time viewing and
engineering analysis of these operations.

Between 2005 and 2010, horizontal
drillouts became common in the Barnett
and Haynesville shale plays. The indus-
try rapidly standardized the operational
procedures for horizontal plug-and-perf
operations. The main standard operating
procedures (SOPs) transferred over were
weight checks to determine that CT was
safe and free. However, CT technology
used to analyze the operations in real time
did not follow suit at the same pace.

CT modeling software and data acquisi-
tion systems (DAS) were used specifically
to track string fatigue and record data for
post-job analysis. Most field operations
directly transferred vertical well SOPs to
horizontal well applications. As horizon-
tal well interventions became common,
each operation was pre-modeled with a
tubing force analysis (TFA). However, the
TFA was used to determine if the CT could
reach total depth (TD) but was not shared
with field operations.

Engineering tools like force monitors
have been available since 2014. However,
their use in North American operations
have been limited because multiple short-
cycle downturns removed engineering
resources from the field. The online migra-
tion capabilities of these engineering tools
have improved as the well site trans-
formed from largely remote to a data-
connected environment. The connection
of the subject matter expertise, which has
moved out of the field and into the office,
has allowed the most informed resources
to access critical operational data and
provide real-time engineering feedback
without ever having to be at the well site.

NOV’s CTES Cerberus intervention mod-
eling software for planning and perform-
ing CT operations now features cloud con-
nectivity to provide field operators, man-
agement and engineers with real-time
access to the same data. This enables
quick and inclusive operational decisions
to be made before potential issues occur.

Interactive TFA models in the software,
combined with real-time data overlays,
improve the efficiency of post-fracturing
intervention of horizontal wells with CT
and prevent problems currently analyzed
only after operations have been negative-
ly affected. Operational efficiencies can
be achieved with the following proactive
real-time engineering approaches:
• Use Cerberus to:
• Create a digital twin of the CT string
for calculating fatigue;
• Create a digital twin of a wellbore so
expected variables, such as dynamic
friction, pressures and temperature,
can be considered when applying cal-
culations in the TFA; and
• Create an Orpheus Force project (TFA)
to generate the expected weight ver-
sus depth;
• Run the Orpheus project to determine
the coefficient of friction (CoF) reduction
needed to reach plug back TD;
• Using historic basin data, determine the
acceptable deviations from the modeled
run in hole (RIH) and pull out of hole
(POOH) weights to ensure there is an
agreed-upon stopping point;
• Upload the Orpheus TFA into the CTES
Figure 1 (left): The TFA shows that during RIH (blue), the model
and weight indicators are good, but the friction increases
before the 0.30 lockup depth, indicating an underperforming
ERT. Figure 2 (above): The post-job TFA shows that after POOH
(green) began, the CT pulled heavy and became stuck. After
five days of circulating, the CT was freed and returned to the
surface. 42
M AY/J U N E 202 2 • D R I L L I N G C O N T R AC T O R



OPTIMIZING WELL INTERVENTION
Live Real-Time Force Monitor so the live
data can be overlaid on the model and
deviations can be seen before opera-
tional issues arise; and
• During the live job, adjust the model to
account for current well conditions.

RIH deviations
If the RIH values are less than the
planned values by the predetermined off-
sets, there is either debris in the wellbore,
an underperforming extended-reach tool
(ERT), weight indicator calibration issues,
or the model needs to be updated for actual
well variables, such as pressure and ERT
friction reduction value.

Before moving farther in hole, determine
the cause of the deviation. If the modeled
data’s inputs have not deviated from the
actual well conditions and the actual data
previously matched the modeled data, the
model did not cause the deviation.

If the measured depth is less than the
0.30 CoF lockup depth, an ERT perfor-
mance issue did not cause the deviation.

Bottomhole assembly (BHA) performance
issues are indicated when there is an
apparent friction increase prior to the 0.30
CoF lockup depth and the CT can still prog-
ress in the hole with clean weight checks,
indicating no debris in the well.

If debris is causing the deviation, a
torque differential may be noticeable
on the BHA, divergent pressures indi-
cate bridging behind the BHA, or the CT
continues to move in hole but only with
increased set-down force and overpulls on
weight checks.

For instance, during a job, a service com-
pany believed the CT was reaching friction
lockup or a hard tag. The CT was pulled
out of the hole to the surface, and the BHA
was function tested. The CT tripped back
in at normal speed and experienced the
same issue at the same depth. The CT was
pulled out of the hole again, and the BHA
was changed. On the third run, the CT
progressed to the bottom and completed
the job with the replaced BHA. If the com-
pany used the TFA as shown in Figure 1,
the underperforming BHA, specifically the
ERT, causing the deviation would have
been apparent. If the tools were changed
on the first run, multiple trips could have
been eliminated, reducing nonproductive
time (NPT) and costs.

Figure 3: The CTES Live Real-Time Force
Monitor enables the live data to be
overlaid on the TFA so deviations can
be seen before operational issues arise.

POOH deviations
If POOH values are greater than the
planned values by more than the predeter-
mined offsets, there is debris in the well-
bore or weight indicator calibration issues.

To determine the deviation cause, ver-
ify the weight indicator readings versus
the hydraulic calculations. If the weight
indicator varies from the hydraulic cal-
culations, calibrate the weight indica-
tor and reevaluate the operation. If the
weight indicator does not deviate from the
hydraulic calculation, debris is in the well-
bore. Pulling heavy can result in debris
bridging and stuck pipe. Stop and circulate
the well clean. If possible, RIH to assist in
static friction reduction of the debris to
increase removal.

For example, a 7,000-ft horizontal well
with 5.5-in. 20-lb/ft casing and a 2.635-
in. CT string was modeled before arriv-
ing on location. Data suggested that the
approximately 17,000-ft TD could easily be
reached with an ERT and a 0.30 CoF while
pumping 5 bpm through the CT and taking
6 bpm returns.

As shown in Figure 2, this well began
with the weight data being offset from
the TFA RIH line. The operator should
have checked the TFA to ensure the input
parameters matched the actual job condi-
tions. A weight indicator issue could have
also caused this offset. However, the weight
was consistent compared with the TFA
RIH line until they entered the horizon-
tal. As the CT continued in the wellbore,
the weight data deviated from the expect-
ed weight from the TFA, even though it
was making excellent progress to TD. The
weight crosses over the expected TFA line
and remains on the “light” side of the line,
which indicates more weight is required to
RIH than expected. The most likely cause
of this is excess sand in the wellbore. The
CT made it to TD in 12 hours without issues.

After circulating for 20 minutes on bot-
tom, the service company began to POOH
at 35 ft/min. The circulation was too short,
and the POOH speed was too fast. When
looking at the force monitor, sand was
most likely present. After 1,800 ft, the CT
began to pull heavy and became stuck.

After five days of circulating and pulling
up to 140,000 lb, the CT was freed and
removed from the wellbore.

The wellbore was cleaned during the five
days, so little or no sand remained in the
horizontal section. After the CT was freed,
the POOH weight matched the expected
POOH TFA line, although the offset from
the beginning of the job remained. In a
clean wellbore, the POOH weight data runs
parallel to the expected POOH TFA plot.

The future of automation
Analyzing the data in real time to make
operational decisions is a foundation for
the future of CT, but not the goal. As real-
time force monitoring becomes common,
NOV is applying the same real-time force
data to develop automated CT operations
in the future. The TFA will be the roadmap
to keep the operation on path and ensure it
does not deviate from the plan. Automated
CT will be able to streamline well inter-
ventions, capture lessons learned, apply
improved processes, reduce the potential
for human error in operations, and enhance
efficiency and safety for all personnel.

Conclusion While CT operations in horizontal shale
plays have become standardized, the
increased use of interactive TFA models
and real-time data overlays will reduce
stuck-tubing events, NPT and costs. Today,
the tools to analyze and act on TFA devia-
tions are available in most CT units. Real-
time force monitoring improves drillout
efficiency. DC
This article is adapted from SPE 208999,
“Optimizing Drillouts Using Live TFA,” presented
at the SPE/ICoTA Well Intervention Conference,
22-23, March 2022.

CTES, Cerberus, Orpheus and CTES Live are
NOV trademarks.

D R I L L I N G C O N T R AC T O R • M AY/J U N E 202 2
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