SPE 121461 Applying Well-Remediation Techniques To Subsea Flowlines in Deepwater Gulf of Mexico
SPE 121461 Applying Well-Remediation Techniques To Subsea Flowlines in Deepwater Gulf of Mexico
SPE 121461 Applying Well-Remediation Techniques To Subsea Flowlines in Deepwater Gulf of Mexico
Abstract
Flow assurance in subsea production flow lines is becoming more prevalent as deepwater well developments continue to
grow. Coiled tubing (CT), though traditionally used in wellbore environments, can be utilized to address flow assurance.
Complications are possible when applying CT technology in a nonconventional environment. Connection tie-ins and
available deck area are typically incompatible with intervention-type activities, and challenging issues such as weight
limitations, nature of blockage, and weather sensitive environments lead to the need for elaborate planning with multiple
contingencies to address the uncertainties. Our study investigated the operational planning and logistical requirements
associated with the radiation of the flow assurance for the Serrano flowline.
The Serrano flowline is located in the Gulf of Mexico (GOM), in 3,500 ft of water and is tied back 6 miles to the Auger
TLP. Three subsea wells have produced through the electrically heated Serrano flowline since 2001. In November 2006, there
was an unplanned shutdown of the flowline and despite numerous attempts to restart, the wells had failed to flow.
In December 2007, after 6 months of intensive and complex planning, a standalone CT operation was successfully
performed while drilling operations continued on the main rig. The operations consisted of utilizing a unique small footprint
compensation frame to allow access to the flowline from a confined area. Then a 1-1/2-in CT string was deployed into the
flowline to retrieve a sample of the blockage for diagnostic purposes. The analysis of the sample dictated the optimal cleanout
strategy which was to combine a specialized rotary nozzle with pumping diesel and solvents to successfully clean out the
flowline. The blockage was breached at a depth of 3,700 ft after cleaning almost 1,000 ft in less than 24 hours. The flowline
was reinstated and gas production restored to >2,000 bbl/d and 8 MMcf, thus preventing the client from losing the lease.
Introduction
The Serrano flowline is tied back six miles to the Auger TLP platform and consists of 3 wells. The flowline is a single 6 in
by 10 in pipe-in-pipe insulated flowline. The flowline and its counter part the Oregano are not only the first pipe-in-pipe
single flowline systems but also the first use of an electrical heating flowline system. This heated system was used to aid in the
reduction/elimination of potential hydrate formation due to subsea temperatures.
In August 2005, the hurricane Katrina evacuation caused a shut-in of the flowlines for 17 days. The flowlines were brought
back online without incident. Shortly after the August shut-in, hurricane Rita, November 2005, caused another shut-in for a
total of 78 days. The comparison of the well tests completed before each shut-in showed that production values were
comparable and little to no loss was seen. The third shut-in was done in July 2006 for 2 days after which a small but noticeable
reduction in productivity was seen. The flowline was shut in for 1 week in November 2006. Generator power to the EH
(electrical heating) system was lost. Once the flowline was opened back up for restart, it would not flow. It was suspected that
a hydrate formed in the flowline during the shut-in period, but other possibilities were sand and paraffin buildup. Pressure
(2,800 psi) was applied from the riser side of the blockage; however, it failed to dislodge the plug. Methanol was then pumped
down the riser to further prevent hydrate formation since it was possible that the EH system was not functioning properly. The
top of the plug has been estimated to begin at approximately 2,200 ft to 3,500 ft, based on the fluid volumes pumped into the
flowline from the TLP. There were some variations during the November 2006 shutdown compared to the previous shutdown
operations, which include a blowdown of the flowline, a Chilly Choke back pressurization upon restart, and the injection of
approximately 24 bbl of MeOH injected into the riser section.
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Once it was clear that the available methods to restart the flowline were not working, CT was determined to be the best
option for intervention. CT would be used to determine the composition of the plug and to remove the obstruction from the
flowline.
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Since the well had no survey data like a drilled well, the tubing forces calculated for the operation had to be extrapolated
from the data available (x, y, and z coordinates). Calculated tubing forces analysis allowed the CT support team to anticipate
the total depth achievable by the CT alone and with tractor assistance. The total anticipated depth that the CT could reach
without assistance was 6,000 ft. The total length of the flowline is approximately 34,320 ft. The additional distance that could
be achieved with the aid of a CT tractor BHA was 3,000 ft. A yard test was done at the onshore facility to determine the
required pump rate to activate the tractor as well as to determine that the BHA could pass through the 4.5-in ID as per the job
design with an 18-degree deviation. In the event that the tractor had to be used, the proper pressures and rates had been
confirmed on surface to ensure better accuracy when the intervention was underway.
The first run to be completed would be a bailer run to obtain a sample of the obstruction and to best select the go forward
plan for the intervention. Once on location, the bailer run proved to be successful and provided a significant amount of fill
sample to use for onsite testing. If the blockage was paraffin/wax substance, diesel would be used in conjunction with an
aromatic solvent. This solvent has been successful in cleaning out paraffin and wax debris world wide, is also coded as a green
chemical with a health coding of 2, and is partially biodegradable. Due to the potential for hydrate formation, it was critical not
to put water-based fluids in the flowline. In the event that sand was the primary blockage, diesel would still be utilized to
prevent a hydrate formation. This diesel would be a specialized gelled system to carry the sand particles back to surface. In
both methods the separation system would be used to reduce the amount of diesel in the operation.
To ensure the plug had been removed and full communication had been established throughout the flowline, the downhole
pressure gauge would be monitored at all times to determine when breakthrough would occur. Throughout the operation, full
communication with the control team would be in place with radios to get constant updates on the changes in the bottomhole
pressure gauge.
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It was then decided to pressure test the flowline and ensure good communication at the downhole pressure gauge. The
pressure test was done to 500 psi and the increase was seen downhole. It was a slow process most likely due to the
compression of gas in the flowline. After the pressure testing was confirmed, the equipment was rigged down and backloaded.
Conclusions
The planning of this operation was extremely thorough. The extensive planning enabled the operation to run smoothly and
safely. The following are the lessons learned from the planning process:
X, Y, Z coordinate system can be converted and utilized to simulate anticipated tubing forces for CT operations.
Compensation for flowline movement must be considered and applied when intervening on a deepwater vessel.
Small footprint equipment and spotting must be considered and prejob rig evaluations need to be conducted well in
advance to ensure that modifications to the rig can be made before the planned intervention.
Later lab results proved that the aromatic solvent used would have completely dissolved the paraffin solution over
time and, therefore, was a positive choice to be left in the flowline while waiting on the startup of production. This
fluid, in combination with diesel, is not likely to form hydrates and would help dissolve any residual paraffin left
in the flowline.
During the project, an approximate total of 35 bbl of paraffin wax was removed from the flowline during the cleanout
process. The paraffin had been dehydrated as a result of the methanol pumped into the flowline during earlier tests, but the
combination of diesel and the specialized rotary wash nozzle BHA were sufficient to remove the debris. The flowline was
brought back online and began producing at > 2,000 bbl/d and 8 MMcf, which prevented the client from losing the lease
This study proved that, with enough planning, such intervention operations can be performed from a TLP platform. The
flowline was brought back online at a better production rate that initially anticipated and the overall intervention was a great
success.
Acknowledgment
The authors would like to thank the management teams of Shell and Schlumberger for allowing this useful information to
be published. Finally we would like to acknowledge the crews of all the involved parties for the hard work and their
commitment to putting safety first.
Reference
Alsyed S., Larsen H., Johnston P., Schaider F., Lounsbury J., Smith J.; 2000. Pipeline Intervention From a Dynamically
Positioned Mono-Hull Vessel via a Flexible Riser. SPE 60728.
Patton, B., Escobar J.C., Schuurman R., Mallalieu R., Polsky Y; 2005. Taking Coiled-Tubing Heave Compensation to the
Next Level. SPE 94350.
Symon, W., Hudson, L.; 2007. Welltec Well Tractor Yard Testing. Schlumberger Internall Document.
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C lie n t:
W e ll:
In sta lla tio n:
D a te :
D ra w n:
R e visio n:
C o ile d T u b in g S e rv ic e s
M IS w aco
S kip
#19
M IS w aco
S kip
# 19
M IS w aco
MGS
#18
M I-S w a co
P F M S S y ste m
#17
T o ta l W e ig h t D R Y = 3 5 1 K lb s
T o ta l W e ig h t W E T = 4 5 9 K lb s
105bbl Tank
#23
2 4 ft
Treating Iron
Basket
#13
C o ile d T u b in g M e zz D e c k L a y o u t
CPump
#14
Walkway
3 9 ft
N o te :
T h is as su m e s a ll ta nk s a re
1 0 0 % flu id fu ll, n o rm a lly
o p e ra tin g w ill b e o n ly b e 5 0 7 5 % fu ll
U n u sa b le
S p a ce
#8
8 2 ft
S h e ll
S e rra n o F lo w lin e
Auger TLP
3 rd D e c 2 0 0 7
L is a W e b e r
Rev 7
C o n ce n tric
1 0 0 b b l D ie se l
Tank #20
#8
#8
M o o n P o ol
A
F ra m e
F lu id
Pum p
#5
500 H H P
F lu id
P um p
#6
C ra ne
In je cto rh e a d -JM C F ra m e -B O P S ta ck
3 0 ft
2 4 ft
9 0K N 2
Pum p #15
CT Reel
#4
In je cto r
T ra n sp o rt
S kid # 9
N 2 Tank
#16
4 5 ft
# 21
Tool box
S ta irs
CT
C ab
#1
#8
PFM S
C h o ke
M fo ld
#20
CT
PPack
2 4 ft
BOP
T ra n sp
o rt S kid
#10
N 2 Tank
#16
N 2 Tank
#16
C ra n e B e a m P a cka g e
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Figure 3: TFM (Tubing Force Module) Plot for Sample Bailer Run1 (Auger Serrano)
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Figure 8: View of Decking and West Mez Deck Rig Up (Reel and Console).
10
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Figure 11: Boarding Valves Tie-In Point for Riser System (38 ft Below Mez Deck).