Gulf of Mexico mid-year report: - Weatherford International

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World Trends and Technology for Offshore Oil and Gas Operations
June 2011
Gulf of Mexico
mid-year report:
• Permitting update
• OTC roundup
• Mexican GoM
• Lower Tertiary
development
INSIDE:
Stimulation vessels
survey

D R I L L I N G & C O M P L E T I O N
Liner drilling technology
reduces non-productive time
Complex drilling challenges often require unconventional solutions
such as liner drilling to reach a successful outcome
Steven M. Rosenberg
Deepak M. Gala
Weatherford International Ltd.
Hydraulic liner hanger
system components.
It is a well-established reality that the world’s growing appetite
for oil and gas is increasingly being fed from remote, deepwater
fields and technically complex reservoirs. To mitigate the significant
drilling challenges and operational risks that inevitably
come with these locales, drilling engineers have to look beyond
their conventional drilling techniques and consider novel well construction
technologies.
In a relatively short time, liner drilling (LD) has proven itself as
a reliable technology for addressing a host of drilling hazards in
harsh environments, including lost circulation, depletion, wellbore
stability, getting liner to bottom, and wellbore ballooning issues. LD
offers several important benefits that help ensure the liner is set to
its target depth:
• The technology creates a so-called “smear effect” in which the
close proximity of the liner wall to the borehole smears cuttings
against the formation, creating an impermeable wall cake and
minimizing lost circulation
• This close proximity also results in considerably higher annular
velocities for a given circulation rate compared to conventional
drilling, which leads to better hole cleaning while drilling
• LD can require little or no hole preparation. The liner can be
landed and cemented almost immediately upon reaching target
depth with minimal delay for cementing operations
• LD helps reduce the rate of fluid loss in the annulus compared
to conventional drilling operations, enabling annular fluid loss
to be managed with a rig’s trip tank pump
• The rigidity of the liner being used acts as a stiff BHA, enabling
maintenance of existing hole inclination and azimuth within the
constraints of the well’s directional requirements
• Trip margin is eliminated, as there is no need for the liner to be
pulled out of the hole
• No rig modifications are required; the same surface equipment
used for conventional liner running operations is used for LD
• LD is used when required to mitigate a particular well challenge,
allowing well construction to continue and minimizing
NPT in the process.
These benefits have helped several Gulf of Mexico (GoM) operators
achieve their drilling objectives, as the case histories below
demonstrate.
Drilling through depleted sand
A deepwater GoM operator selected LD to drill through and isolate
a pressured shale and depleted sand in a single-hole section.
Conventional methods would require two strings of casing, which
was unacceptable due to severe slimming of the wellbore.
Equipment Selection. A review of existing bit records and lithology
information indicated that a three-bladed, 7 5 ⁄8-in. × 8 1 ⁄2-in. CWD
bit with a thermally stable polycrystalline (TSP) diamond cutting
Reprinted with revisions to format, from the June 2011 edition of OFFSHORE
Copyright 2011 by PennWell Corporation

D R I L L I N G & C O M P L E T I O N
structure would be best for this application. The CWD bit had 6-mmround
TSP diamond cutters pressed into aluminum blades containing
high-velocity oxy fuel (HVOF) hardfacing, and a tungsten carbide
gauge section to enable back-reaming. The bit was fitted with
drillable and interchangeable copper nozzles to minimize damage to
the subsequent shoe-track drill-out bit. The aluminum nose and cutting
structure were fully drillable with conventional PDC or rollercone
bits, eliminating a costly drill-out trip.
A 4,260-ft, 7 5 ⁄8-in., 39-lb/ft Q-125 HYD-523 hydraulically set liner
system was selected, which was designed for extended rotation periods
in deep, high-angle applications and to allow for maximum workability
during deployment.
The key for success with hydraulic liner systems is safe management
of the circulating pressures. The premium liner is equipped
with special mechanical locking devices, which are deactivated
when the hydraulic setting pressure is reached. These devices prevent
premature setting while running in the hole (RIH) and allow for
the highest flow rates and pressures to be used, further aiding the
workability of the system.
The hanger is set by applying hydraulic pressure to shear the
pins in the cylinder, which forces the connector ring and slips up the
cone and into the host casing; the liner’s weight is then transferred
to the slips by lowering the running string.
The setting tool is used to rotate the liner when running in the
well and during the LD operation. Hydraulic pressure, coupled with
a ball-dropping event, shears the sleeve of the hydraulic cylinder on
the setting tool so that it can be mechanically released. Drill pipe
weight is slacked off to de-clutch the tool, which is then turned
to the right to release the float nut. Hydraulic pressure is then reapplied
to shear the ball from its seat in the liner wiper plug tool,
thereby restoring circulation. The running string is then picked up
to check that the setting tool is free, which is confirmed by the loss
of the liner weight.
The packing element is designed to trap atmospheric pressure
underneath it. Thus, as the liner system is lowered into the wellbore,
hydrostatic pressure acts to vacuum it to the liner-top packer
mandrel. This capability helps improve packer performance by preventing
swabbing, premature setting and cuttings accumulation underneath
the packing element.
The packer is set by raising the running string to expose the
packer actuator, forming a no-go which is set down on the polishedbore
receptacle (PBR). The no-go transfers weight through the
PBR, shearing the pins in the packer and allowing the element and
slips to be set in the host casing and the ratchet rings to lock in
the compressive forces. A tieback completion PBR using a patented
locking mechanism helps prevent the PBR from backing off when
tight dogleg sections or high-debris environments are encountered.
LD operation. For the first section, the CWD bit and hydraulic
liner hanger system were used to ream and drill the 7 5 ⁄8-in. liner a
distance of 107 ft through the pressured shale and depleted sand.
Existing 9 7 ⁄8-in. casing was set at 16,156 ft (4,924 m) MD with 60
degrees of inclination. The existing 8 1 ⁄2-in. × 9 7 ⁄8-in. hole was 20,419
ft measured depth (MD). The 4,260 ft (1,299 m) liner was washed
and reamed from 20,320 ft (6,194 m) to 20,419 ft (6,223.7 m) MD and
drilled in an additional 8 ft to 20,427 ft (6,226 m) MD.
The next hole section in the same well contained a 13.5-ppge pressured
shale overlying the 7.7-ppge depleted pay sand. After drilling a
6 1 ⁄2-in. × 7 1 ⁄2-in. bi-center hole through the depleted pay sand, a 5 1 ⁄2-in.,
23-lb/ft, Q-125, HYD-513 liner was reamed in using a 5 1 ⁄2-in. × 6 1 ⁄2-in.
CWD bit. No mud losses were recorded while the 328-ft liner was
reamed from 20,427 ft (6,226 m) to 20,519 ft (6,254 m) MD in the
existing 6 1 ⁄2-in. × 7 1 ⁄2-in. hole. The LD system allowed the operator to
successfully case off the depleted 92-ft (28 m) pay sand interval with
no fluid losses, saving time and cost over conventional methods that
had a low chance of success.
Casing challenges
A GoM shelf operator decided to case off an unstable shale section
and a severely depleted 2-ppge sand with a 480-ft (146.3 m), 5½ -in.
23-lb/ft Q-125, HYD-513 liner at a wellbore inclination of 38°. A threebladed,
PDC drillable 5½-in. x 6½-in. CWD bit with TSP diamond
cutting structure was selected for the LD operation. The operator required
a 3½ -in. production tubing to ensure economic success, which
necessitated a minimum 4½ -in. hole size to total depth after drilling
out the 5½ -in. liner.
As part of the rotary string, the liner string would be subjected to
typical borehole drilling forces and dynamics. Therefore, the 5½ -in.
liner running/drilling tool system was specifically engineered with
up to 38,000 pound force/feet (lbf/ft) of drilling torque capability.
The tool’s release was controlled by hydraulic differential pressure
across an internal ball seat in the setting tool, rather than between
the inside diameter (ID) and outside diameter (OD) of the tool,
which is the setting method common to conventional liner hangers
and running/setting tools.
Liner reaming and drilling. During reaming, shale pack-off was
experienced in the previously drilled shale intervals, requiring operator
and service company teamwork to work the pipe through the
shale intervals. In the second shale section from 13,759 ft (4,193.7
m) to 13,779 ft (4,199.8 m), as much as 55,000 lb of over pull was required
to work the liner free. Pump pressure had increased to 1,686
psi, with surface torque measured as high as18,000 lbf/ft; however,
no fluid was lost to the formation during the reaming operation.
The drilling operation required 10 hours to drill 19 ft of new hole
(from 13,779 (4,199.8 m) to 13,798 ft (4,205.6 m) MD). Rotary speed
ranged from 26 to 50 rpm, weight on bit (WOB) from 0 to 13,000
lb, and drilling torque from 8,000 to 9,000 lbf/ft. A 12.1 ppg WBM
was used. After cementing the liner in place, an 18.3-ppge formation
integrity test (FIT) verified that the 4½-in. hole required for the
completion could be achieved. As in the reaming phase, no fluid was
lost to the formation. No comparison how much fluid was lost on
offset wells is available as this was one-off well.
Catastrophic thief zone
A GoM operator selected LD to case off a catastrophic thief zone,
which was not possible using conventional drilling methods. Planning
for the LD operation had to be completed within a 48-hr window
to avoid rig downtime.
A three-bladed 9 5 ⁄8-in. x 12 1/4-in. CWD bit with TSP diamond cutting
structure was selected, as was the premium 9 5 ⁄8-in., 53.5-lb/ft,
HCP-110, SLIJ-II hydraulic liner hanger system highlighted in the
first case study. A 13.4-ppg water-based mud (WBM) was used for
the LD operation.
After the liner was successfully run to 7,069 ft (2,154 m) MD, the
existing 12¼-in. hole was washed and reamed from 7,069 ft to 7,164
ft (2,183.5 m), at a rotary speed of 40 rpm, torque between 2,500 and
3,500 lbf/ft, surface pump pressure of 1,100 psi and a circulation rate
of 500 gpm. Hook load readings verified that the open hole was in
good condition. Liner washing and reaming continued to the bottom
of the 12¼-in. section, at 7,367 ft (2,245 m) MD.
The liner was then drilled into a sand and shale sequence from
7,367 ft to 7,636 ft at an average rate of penetration (ROP) of 7.7 ft/
hr and an on-bottom rotating time of 35 hr. There were no reported
mud losses to the formation while LD and cementing the 9 5 ⁄8-in. casing.
The liner hanger set without incident and the liner-setting tool
was released and retrieved without problem.
Eliminate contingency liner
A GoM operator producing in the Carpa field offshore Mexico im-

D R I L L I N G & C O M P L E T I O N
9 5 ⁄8-in. x 12 1 ⁄4-in.
Defyer DPC 516
drillable casing bit.
Liner setting tool.
plemented LD after
experiencing 39.65
days of NPT in an
offset well. The NPT,
with a total economic
impact of $4.78 million,
resulted from
massive fluid losses
of more than 2,500
bbl in a fractured
limestone overlying
the production interval.
This caused
stuck pipe and costly
fishing operations,
and raised the eventuality
of running a
contingency liner.
LD was implemented
to case off
the problematic
limestone formation
and land the 9 5 ⁄8-in., 53.5-lb/ft, L-80, Hyd-513 liner in the top of the
producing formation, with no reported fluid losses. A five-bladed
PDC bit that could be converted to a drillable drill shoe was used
in this operation.
The CWD bit was designed to function as a PDC bit until total
depth was reached, after which a ball-dropping event blocks the
drilling nozzles from fluid flow. Pressurizing the casing string then
shears the bit’s pins, displacing the steel blades and PDC cutting
structure into the casing-hole open annulus and exposing the cement
ports. The entire cutting structure is eventually displaced into
the annulus and cemented into place.
Passive directional control was maintained in the 75° hole, using
strategically positioned under- and near-gauge stabilizers in the LD
bottomhole assembly (BHA). The CWD bit blades were displaced
and the liner hanger and liner-top packer were each set with success.
The operator saved $5 million and 40 days rig time by eliminating
lost circulation and the need to run a contingency liner.
Complex thief interval
A GoM shelf operator drilling offshore Texas selected LD to deploy
a 7-in. liner and case off a thief interval exhibiting varying degrees
of lost-circulation through several adjacent blocks. Planning
meetings between the service provider and operator resulted in the
decision to drill a 7-in., 23-lb/ft HCP-110, GB CDE (casing drilling
enhanced) liner through the catastrophic loss zone and set it in a
competent shale below.
A 7-in. × 8 1 ⁄2-in. CWD bit with a displaceable 13-mm PDC cutting
structure was deemed the most suitable for the application. Its design
features enabled the bit to be converted to a drillable casing
shoe at total depth, allowing for shoe-track drill-out with conventional
PDC or roller-cone bits.
As part of the planned LD procedure, a 9 5 ⁄8-in. production casing
was set and cemented in place at 4,150 ft (1,265 m) MD, approximately
50 ft (15.24 m) above the known loss zone. This was followed
by retrieval of the 8 ½-in. BHA, rig-up of the 7-in. liner-handling
equipment and deployment of the liner. Approximately 30 hours
were required to drill the 496-ft of new hole through the catastrophic
loss interval and cement the liner in place. The liner was successfully
pressure tested and the liner shoe was successfully tested to
the required 11.5 ppge.
Conclusions
The case histories presented provide a clear indication of the benefits
of LD technology in difficult drilling environments, including
efficient and accurate liner setting in unstable lost-circulation zones,
a reduced rate of fluid loss in the annulus compared to conventional
drilling operations, and a favorable impact on NPT and overall cost
reduction.
Importantly, the use of LD was identified as the only viable means
for some of these operators to achieve their drilling objectives and
avoid abandoning the well altogether. Complex drilling challenges
often require unconventional solutions such as liner drilling to play
a key role in a successful outcome. •
Acknowledgment
This article is an abbreviated form of “Liner Drilling Technology as a Tool to Reduce
Non-Productive Time: An Update on Field Experiences in the Gulf of Mexico,”
presented at the 2011 AADE National Technical Conference and Exhibition in
Houston.