Packer Operating Envelope – – 5 1/2” x ... Production Tubing – HF1 – Prod Superior (Packer 16387.8 ft MD)
-12000 -9000 -6000 -3000 0 3000 6000 9000 12000
Annular Differential Pressure (psi) (+ from Below)
38 Offshore December 2017 • www.offshore-mag.com
DRILLING & COMPLETION
Load analysis of packer envelope.
modes associated with the valve must be considered and mitigated
where possible. To simplify them, two main categories were established—design related risks and external factors. To mitigate the design
related risks, proper design and a robust qualification process should
be implemented to help ensure the tool is going to perform predictably
in a given operational envelope.
Additionally, care should be taken when deploying those systems to
ensure that they are going to reach planned depths without damage to
the tools or control lines. A second mitigation plan is to evaluate the
loads and wearing mechanisms the valve is going to be subjected to.
One of those wearing mechanisms is erosion, an operational plan is
necessary to help ensure flow velocity thresholds are not surpassed
when the valves are subjected to production or injection of fluids.
Inorganic deposition (scale) was identified as a potential risk for valve
failure, so a dedicated chemical injection system associated with the
ICVs deploying scaling inhibitors was established for producer wells.
Also, as part of the flow control system, multifeed-through packers
were selected as production packers to isolate the upper and lower
intervals. Both packers were permanent 9 5/8-in., 53. 5 lb/ft packers
with 4½-in. tubing size, and hydraulic set by tubing pressure application with no body movement. Because of the nature of the different
projects, two packer designs were used with success. The main
difference between the two packers was the retrieval method. The
MFT packer uses a cut-to-release system, using either a chemical or
mechanical cutter. The second model, the HF1, has a shift-and-pump
to release design, requiring a special shifting tool to be run to the
packer depth for the releasing mechanism to be activated.
Data and results
Each interval is made up into a single assembly comprising all of
the pieces of equipment necessary for that specific zone in an onshore
facility. The two main reasons for this approach is the reduction of work
performed on the rig by offshore personnel and the reduction of risk
associated with protecting the lines over the equipment on the rig floor.
The process requires the lines to be run along the packers, ICV, gauge
mandrels, and routing the control lines can be time-consuming and
risky when performed on the rig floor. All connections are centralized
in splice subs, allowing for multiple connections between the assem-
bly lines and the flatpacks to be performed simultaneously, reducing
the online time at the rig floor. Each line has its
designated function—open upper ICV, open lower
ICV, or close ICVs, for example, the individual lines
in the flat pack were color coded to facilitate the
identification process and minimize swapping lines
when splicing the capillary tubing to the assemblies
and the tubing hanger. The position of each line
must be planned to match the planned sequence of
line functions in the flatpacks. The standardization
of well design and material allowed the onshore
preparation process to be optimized for time and
quality. Initially, an average of 25 days to prepare
a full equipment set was considered necessary.
Recently, the preparation time has been reduced
to seven days in some instances without any com-
promise to the quality of the activities performed.
The production packer under went tubing load
modeling because no tubing movement compensa-
tion system that allows control lines to bypass was
available. The packer must withstand the loads
transferred from the tubing over the planned
operations and well production, such as buckling,
ballooning, thermal expansion, and piston effects.
The simulations were necessary to confirm the
fitness of the packer for the well design.
Additionally, to predict the behavior of the system when running in
hole (RIH), torque and drag analysis were performed as part of the
planning phase. When running a deviated well, the job preparation
requirements are reviewed and the simulation is used to compare
with actual values measured during each operation.
The expertise of the offshore personnel is crucial to success. When
the campaign began back in 2013, very few specialists were available in
country. Local talent was selected to be trained overseas. Operational
leaders were sent to a variety of countries, such as Nor way, USA, Qatar,
Kuwait, Brunei, and Russia to acquire hands-on knowledge to ensure
proper procedures were understood and followed to ensure smooth
deployment and fasttrack operational experience. The expertise acquired
was then replicated to new hires and additional personnel locally.
An important performance measure of the intelligent completions
offshore crew was the online rig floor time necessary to prepare the
BHA for the RIH. The time evaluated measures the moment the intel-
ligent completion is rigged up until all connections have been made
on the BHA and it is ready to be deployed with the tubing. This is an
important measure because it removes most third-party activities from
the evaluation and it is the most crucial phase of rig floor preparation.
However, performing faster on the rig floor is not necessarily a good
measurement unless it is attached to an overall quality control KPI. In
2013, a major incident occurred in the second well being installed; a
control line was damaged close to reaching final depth. The comple-
tion was pulled out and the backup equipment had to be deployed.
The main cause was poor protection of one control line, which was
damaged during deployment. Several measures were implemented
which have proven successful since there has been no recurrence.
After almost two years (2014 and 2015) without any nonproductive
time (NPT), NPT was incurred resulting from service equipment
failures, primarily related to a spooling unit that broke down in ser vice.
Additionally, one of the flatpacks deployed was discovered to have a
manufacturing defect detected during the RIH procedure. The damage
was inspected and evaluated and, after consideration of the impacts,
the damaged section was removed and the operation continued.
Considering the complexity and extent of work necessary to deploy
each system and the amount of NPT attributed to the technology
related services, it can be concluded that, overall, the technology is
very reliable for deployment, even in an ultra-deepwater scenario.