Collaboration delivers first Lower Tertiary smart completion system
World Oil / MAY 2014 43
INTELLIGENT WELL COMPLETIONS
All three lower-completion intervals in the well were stimulated
successfully with the MST system, one of the deepest, multi-zone
sand-control completions in the industry.
Petrobras and Baker Hughes collaborated to
accomplish the industry’s first intelligent well
completion in the deepwater Lower Tertiary
Wilcox formation under HPHT (>250°F and
>19,000 psi) conditions at a water depth
exceeding 8,200 ft and a 26,000-ft TVD.
The Lower Tertiary play in the Gulf of Mexico (GOM) is a
proving ground for E&P technologies capable of withstanding
bearing reservoir with 1,200-ft gross sand thickness. At water
depths ranging from 8,200 ft to 8,900 ft, the reservoir depths are
greater than 26,000 ft TVD, with reservoir temperatures greater
than 250°F and pressures exceeding 19,000 psi. The formation
is composed of stacked thin beds of sand and fine-grained silt-
stone intervals that have, effectively, no vertical permeability
and an occasional cap of thick salt/sediment layers. The region
also provides an opportunity to achieve industry firsts by apply-
ing advanced technologies at record depths.
Since the start of production from its Lower-Tertiary Cascade
and Chinook (C&C) fields in 2012, Petrobras has relied con-
sistently on advanced technology applications. Located in the
Walker Ridge area, 180 mi off the Louisiana coast, the fields are
tied to the GOM’s first floating production, storage and offload-
deepwater development, Fig. 1.
in Cascade and two in Chinook), each of them producing from
two separate pay intervals—an upper interval known as Wilcox 1
and a lower interval called Wilcox 2. While these wells have been
Petrobras the opportunity to accurately measure the production
contribution from each individual interval. The operator has re-
lied on the use of tracers to qualitatively measure production from
all of the zones, and on multiphase flowmeters at the wellhead to
monitor the total, commingled production from each well.
This limitation, and the need for more quantitative measure-
ments of each interval’s flow characteristics, prompted Petrobras’
reservoir group to call for the development of an intelligent well
completion. Such a system, the first of its kind in the Lower Ter-
tiary, would allow for a more quantitative understanding of each
pay interval’s contribution to the overall production, while pro-
viding greater zonal control.
Petrobras selected the new Cascade 6 well as its candidate
for the first intelligent well system (IWS), and tapped Baker
Hughes to develop the necessary completion technologies. The
well, a subsea completion with an 8,211-ft water depth and total
well depth of approximately 27,000 ft, required a comprehen-
sive completion package specifically tailored to the challenges
encountered in producing from the two zones. Both companies
had collaborated successfully on the previous completions in the
C&C project, and built on that collaboration to develop the IWS
for Cascade 6.
The collaboration began with upfront planning meetings, in
which representatives from each company discussed the produc-
tion and operational goals for the well. This team then jointly de-
veloped the final completion design that would meet Petrobras’
goals and minimize the need for complex, costly and invasive
interventions. Petrobras carried this collaborative team philoso-
phy throughout the project. Rather than make decisions behind
closed doors and then give Baker Hughes direction, both com-
panies discussed each phase of the well completion development
and design. Similarly, the completion equipment design, manu-
facturing and quality processes were a collaborative effort. This
open process of information sharing and decision-making helped
streamline development and planning, and minimized the risk of
any unforeseen surprises that might delay the project.
Originally appeared in World Oil
MAY 2014 issue, pgs 43-48. Posted with permission.
44 MAY 2014 / WorldOil.com
INTELLIGENT WELL COMPLETIONS
FINAL DESIGN WITH MANY FIRSTS
The final design for the Cascade 6 well consisted of an up-
per and lower completion, which would isolate the upper pay
zones (two hydraulically fractured intervals from the Wilcox 1
interval) from the lower zone (one hydraulically fractured inter-
val from the Wilcox 2) and allow for selective production from
each zone, if required, Fig. 2.
The major components in the upper completion include:
• Seven downhole pressure/temperature gauges, which
besides monitoring the downhole temperature and the
pressure of the production intervals, are used to infer the
water cut (fluid density) and the flowrate from Wilcox 2
with a Venturi flowmeter. The gauges also provide infor-
mation to assist casing pressure (Annulus A) verification
throughout the production life of the well.
• A 4½-in. hydraulic sliding sleeve (DHFC downhole flow
control valve), rated to 12,000 psi differential pressure
and used to control production from Wilcox 1, Fig. 3.
This is the highest pressure-rated system of its kind de-
signed and installed, to date, by Baker Hughes.
• A 3½-in. shrouded hydraulic sliding sleeve (DHFC
valve), also rated to 12,000 psi differential pressure and
used to control production from Wilcox 2.
• Two separate chemical injection systems, one for par-
affin inhibitor and one for scale inhibitor. The paraffin
injection system injects treatment chemicals above the
retrievable production packer, while the scale inhibi-
tor injection system includes a line that carries scale in-
hibitor into the shroud of the 3½-in. DHFC valve. This
unique design allows scale inhibitor treatment into the
tubing for both zones through only one chemical injec-
tion valve, regardless of the position of the hydraulic slid-
• A feed-through packer with six ¼-in. control line feed-
• Three flat packs that contain three ¼-in. hydraulic con-
trol lines for the DHFCs, two ¼-in. hydraulic control
Fig. 1. Petrobras’ Cascade and Chinook fields are at the outer
limits of the current developments in the deepwater Lower
Fig. 2. Completion
the upper and
Fig. 3. The system’s
sleeve valves are
rated to 12,000 psi.
46 MAY 2014 / WorldOil.com
INTELLIGENT WELL COMPLETIONS
lines for the safety valve, two ⅜-in. lines for chemical in-
jection and one ¼-in. TEC line for the gauges.
• A Venturi flowmeter to measure production from the
Wilcox 2 zone. While Venturi meters have been deployed
in other subsea assemblies, this marked the deepest in-
stallation to date. The use of this flowmeter answered
the operator’s need to more accurately estimate the pro-
duction contribution from each zone. With the Wilcox
2 production measured with the Venturi device and the
total commingled output available from the multiphase
flowmeter at the wellhead, the production from Wilcox
1 can be calculated with ease.
• A next-generation Neptune EP safety valve, which in-
cludes design upgrades for improved operational effi-
ciency and reliability. This marked the first Baker Hughes
installation of this upgraded Neptune valve design.
• The TORRENT multi-zone, single-trip (MST) system
to stimulate the three zones (two in Wilcox 1, one in Wil-
cox 2) as an alternative to a conventional stack frac-pack
operation. Petrobras had experience using the MST on
previous C&C wells, but this well represented the first
deployment of the MST system with an intelligent well
system (IWS) completion and also the first time that the
same service tools were used throughout the hydraulic
with a 50-ft tieback receptacle, which is part of the isolation as-
sembly and was used as a mechanical barrier throughout the
upper completion deployment and commissioning operations.
PUTTING CONTINGENCIES IN PLACE
Given the well’s depth and high upfront capital expense,
coupled with the objective to design and construct a completion
to withstand production for 20 years or longer, Petrobras devel-
oped an enhanced well design to minimize the risk of equipment
failure and interventions. To that end, both companies worked
together to include multiple contingencies into the design, that
would keep production flowing from each zone, if the primary
equipment would fail.
Such contingencies include the capability to install one sin-
gle-scale inhibitor injection point, to be able to treat the entire
production string down to the lowest hydraulic sliding sleeve,
even in the event that the valve is shifted closed. Among other
flow assurance concerns, the scale inhibitor is designed to avoid
buildup along the moving parts of the hydraulic sliding sleeves
that might prevent their normal operation. This was considered a
much more cost-effective measure, compared to installing a sec-
ond scale inhibitor injection point (one below each valve), with
implications not only to the well design (additional ⅜-in. control
line), but also to the subsea tree system.
A 4½-in. mechanical sliding sleeve was installed above the
4½-in. DHFC valve (upper) as another contingency. The slid-
ing sleeve is kept in the closed position during normal well op-
erations. If the upper DHFC valve should fail (e.g., in case a plug
in the control line prevents its normal hydraulic operation or any
attempt to mechanically override it), then the mechanical sliding
sleeve can be opened to allow production from Wilcox 1 to reach
the surface. Conversely, if the 4½-in. DHFC valve is stuck open
and production from Wilcox 1 needs to be shut off, a fit-for-pur-
pose separation sleeve could be installed to straddle the DHFC
ports, effectively shutting off production from Wilcox 1, while al-
lowing continued production from Wilcox 2.
Contingencies also exist, in the event that production from
(which controls Wilcox 2 flow) cannot be closed hydraulically or
mechanically, the valve includes a sealbore nipple profile above
its ports. A plug can be installed in this nipple profile to shut off
production from Wilcox 2. In the event that the shrouded valve is
stuck in the closed position, production from Wilcox 2 can be re-
stored by pulling the plug used to divert the flow into the shroud
housing. With the plug removed, Wilcox 2 production flows
straight up the tubing, rather than perforating the sliding sleeve.
PRE-PLANNING PAYS OFF
One of the keys to success on both the upper and lower com-
pletions, and ultimately, the entire installation, was the significant
amount of planning, collaboration and preparation that took
place from the completion design conceptual phase, through the
procedure elaboration and peer review meetings. This involved
not only Petrobras and Baker Hughes, but all the main contrac-
tors, to plan the equipment make-ups prior to going offshore and
final deployment. To minimize rig time, subassemblies were built
on land, function-tested and then shipped offshore.
For example, the MST subassemblies were made up and
spaced out to match the perforation intervals provided by
Petrobras. Once the perforations were finalized, they were laid
out with the MST system to ensure a proper space-out, using
Baker Hughes’ real-time tool position, visualization and design
software. Because the MST system uses multiple shifters, it was
also verified in the design software that shifting one sleeve did
not inadvertently shift another sleeve. Once the space-out was
set, Baker Hughes technicians built the equipment, and loaded
it to go offshore.
The upper completion was planned, and the equipment was
built to minimize rig time. This was accomplished by building
up subassemblies and pre-installing the majority of the hydrau-
lic lines prior to going offshore. The lines were passed through
the feed-through packer, routed and terminated throughout the
subassembly. These were tested onshore and shipped ready to
The onshore testing protocol included numerous pressure
Fig. 4. Make-up of the intelligent well system assembly in
preparation for hydro testing.