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Copyright 2000, IADC/SPE Drilling Conference
This paper was prepared for presentation at the 2000 IADC/SPE Drilling Conference held inNew Orleans, Louisiana, 2325 February 2000.
This paper was selected for presentation by an IADC/SPE Program Committee followingreview of information contained in an abstract submitted by the author(s). Contents of thepaper, as presented, have not been reviewed by the International Association of DrillingContractors or the Society of Petroleum Engineers and are subject to correction by theauthor(s). The material, as presented, does not necessarily reflect any position of the IADC orSPE, their officers, or members. Papers presented at the IADC/SPE meetings are subject topublication review by Editorial Committees of the IADC and SPE. Electronic reproduction,distribution, or storage of any part of this paper for commercial purposes without the writtenconsent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is
restricted to an abstract of not more than 300 words; illustrations may not be copied. Theabstract must contain conspicuous acknowledgment of where and by whom the paper waspresented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax
01-972-952-9435.
AbstractThe wells in the Gullfaks field, operated by Statoil in offshore
Norway, produce from several reservoirs, with the largest
reserves being found in the Brent, Cook and Statfjord sands.Only one well in the field, Well C-29, produced from the
Lunde formation.
Although Well C-29 intersected the Statfjord formation,commingled production could not be considered since
differing pressure regimes, the productivity index, and
expected watercuts ruled out this possibility. When the well
economics from Lunde formation production became
unfeasible, the original plan had been to plug and recomplete
the well in another zone. Rather than follow the originallyplanned well scenario, an innovative technology that
introduced a surface-controlled downhole choke system was
suggested and subsequently used. This paper will discuss the
recompletion of this well.
The new system had the capability to provide two
important benefits. It would not only allow commingled
production, not possible before, but would save a dedicated
Statfjord well slot. The system, incorporating a number of
zonal isolation packers and adjustable downhole chokes, eachindependently controlled from surface, would provide this
well with the means of selective or simultaneous production.The recompletion operations were to be divided into two
major parts with the first using hydraulic workover (HWO) to
accomplish the through-tubing zonal isolation and tubing-
conveyed perforating (TCP) operations. The second
operational phase was to be performed with a drilling rig,which would pull the existing completion and run the newcompletion, employing the zonal-isolation control system.
The completion was successfully installed, and the well is
currently a commingled producer with all downhole systems
functioning and communicating as planned. The installation
proved to be economically favorable, and production plans for
the area have been revised to take full advantage of the
enhanced reservoir data that has been generated from the wel
due to the new intelligent well completion technology. O
particular significance is the fact that this is the worlds firsrecompletion in which intelligent well technology has been
used.
IntroductionThe Gullfaks field is located offshore Norway and is one of
the largest producing oil fields in the North Sea. The field is
operated by Statoil and has produced since 1986 . It isdeveloped with three concrete integrated production anddrilling platforms, namely the Gullfaks A, B and C. The total
production rate from the Gullfaks field is currently some
50,000 Sm3/d with estimated total recoverable reserves of 319
million Sm3.
The field produces mainly from the Statfjord, Brent and
Cook formations; however, some small additional reserves arealso present in the deeper Lunde reservoir. Fig. 1 shows the
location of the Gullfaks field.Well C-29 is currently the only location on the Gullfaks
field producing from the Lunde formation. Although the
reserve base in Lunde is small compared to Statfjord and
Brent, it represents a net reserve that adds to the othereserves on which the fields economy is based. Lunde
reservoir properties are generally poorer than the other
formations at Gullfaks, and since no pressure maintenance
scheme has been designed for Lunde, pressure development in
a Lunde well differs from traditional pressure-maintained
wells.Well C-29 was originally drilled and completed in 1995
initially as a Lunde producer. The well also penetrated the
Statfjord formation reserves at a higher point in the wellborePlans for the well called for plugging of the Lunde
perforations when economic production was no longe
possible, and then, reperforation in the high productivity
Statfjord (SF) sands. This plan also included a separate SF
producer well approximately 500 m away to help acceleratethe SF production in the area. Fig 2is a section and location
map of Well C-29.
Early in 1998, plans were underway to complete the
IADC/SPE 59210
Intelligent Recompletion Eliminates the Need for Additional WellOle Henrik Lie, SPE, Statoil, and Wayne Wallace, SPE, Halliburton Energy Services, Inc.
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2 OLE HENRIK LIE AND WAYNE WALLACE IADC/SPE 59210
Statfjord formation producer in the second stage of the
original C-29 plan when the idea was presented that new
technological advances might be available to allow C-29 to berecompleted for commingled production hence eliminating
the need for an additional well. Commingled production from
the SF and Lunde formations had not been considered earlierbecause of the greatly varying reservoir parameters of these
two formations. It was also an issue that production fromdifferent zones could not take place without some
measurement for the location from where the off take wouldbe generated.
Considering the significant expense of completing a new
producer, the decision was made to initiate a project to
investigate recompletion of Well C-29 for commingled,
surface-controlled and measurable production using the newlyavailable intelligent-well technology.
Control System Principles for Intelligent WellsThe intelligent system uses permanently installed electric
cables (I-Wire) to provide power and communicate with each
downhole sensor and well tool. Permanently installed
hydraulic lines are used in conjunction with solenoids, under
electronic control, to selectively manipulate each downholetool. Combining each into a single re-enforced flat pack
clamped to the completion string protects the I-Wire and
hydraulic line. Additionally, a redundant pair of hydraulic
lines and I-Wire is run. This redundancy is configured such
that multiple failures in these lines can be tolerated without
any loss in functionality. The electronics located in each zone
can detect and bypass the failed hydraulic cable or I-Wire.
Stringent attention must be paid to the elimination of
potential leak paths and sub-system redundancy. The majorityof mechanical interfaces that require a seal medium are
welded or include redundant metal-to-metal sealing. Each
downhole device contains two sets of redundant, electronicsystems.
Surface-controlled computer software monitors the
communication system and downhole tools for current status
and operates, for example, the opening and closing of intervalcontrol valves (ICV) that are normally positioned between HFfeed-through production packers. Sending electrical power and
digital communications down the instrument wire (I-Wire)
initiates operation of actuator electronic modules (AEMs)
located at the upper end of the ICV. The selected AEM turns
on the selected solenoid valve, which directs hydraulic
pressure to drive the ICV into open, closed, or intermediatepositions. The surface PC has a graphical interface that
displays the current position of ICVs, communication systemstatus, reservoir data, and fault diagnostics. Chronologicalrecords of all information and communicated instructions are
recorded and transmitted to the desired storage media. Fig 3
illustrates the operational principle of the intelligentcompletion.
Intelligent System BenefitsAn intelligent well system provides an increased range of
benefits over standard conventional completion designs. For
example, well intervention is not required and production can
be commingled from all zones or selectively produced. The
specific advantages include capability to:
1. Selectively reconfigure any ICV choke settings fromsurface.
2. Identify at surface the choke setting position for any ICV.3. Transmit downhole pressures and temperatures for each
zone independently.4. Calculate gross single-phase flow contribution from eachzone.
5. Communicate with a range of system diagnostic sensors.
Selection and Design RequirementsSelection Process. The requirements that would enable C-29
to be capable of providing commingled production weredetermined to be:
Capability to control production rates from 4 individuazones
Capability to allow production from zones at reservoirpressures as far apart as 100 bar
Capability to feed production parameters for all individuazones back to surface
Capability to reconfigure the system from surface withouthe need for intervention.
As the candidate well had experienced some sand
production and new perforations would be needed in weakezones, some tolerance for sand production would also be
required.
Fig. 4illustrates the potential reservoir zones in the wel
with the relevant reservoir parameters. Most of the reservoir
data were prognostic values based on log data only. Thisuncertainty in data values meant that the system would have to
be robust enough to maintain integrity with actual reservoiperformance that might differ to some degree from the
prognostic parameters.
The existing well configuration also added limitations
The well was originally completed as a 7 monobore
producer. Fig. 5 shows the completion schematic of the
original C-29. Dimension of any new equipment in the
wellbore would be limited to the available clearances in C-29Bottlenecks would particularly be expected through the parts
of the old completion that could not be pulled as well as the
entire 7-in. liner.
It was also an absolute prerequisite that the new
completion would have to be installed without imposing any
compromise on well control issues.
Intelligent Well System for Well C-29System Overview. To enable improved productionmanagement, a fully integrated adaptive intelligent completion
system was selected for the C-29 Well. In this new C-29
system, four downhole interval control valves, each being
completely isolated by hydraulic feed through production
packers, would be incorporated.1,2,3
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IADC/SPE 59210 INTELLIGENT RECOMPLETION ELIMINATES THE NEED FOR ADDITIONAL WELL 3
Well Constraints and ChallengesSince this was a first-time installation of an intelligent
completion system as well as a workover, extreme care inplanning was needed to ensure that a safe, successful system
would result.
While there were no major problems or bottlenecksidentified in the upper casing strings, there were restrictions in
the areas of the 9-5/8-in. x 7-in. tie-back liner and theproduction liner itself.
The 9-5/8-in. x 7-in. tie-back liner design incorporated aproduction packer and polished bore receptacle (PBR) to
accommodate tubing movement in the upper 7-in. completion
string. The minimum ID through the PBR was 6.050-in, and
the minimum ID through the packer was 6.00-in. The 7-in.
production liner was 7-in. 32 ppf, having an ID of 6.094-in.and drift of 5.969-in.
The maximum OD of the ICV is 5.965-in, which would
allow only 0.004-in. clearance through the production liner.
Well Control IssuesWell control was a highly important consideration for the
project. Not only was the system being deployed into a
perforated live well with overbalanced fluid being the primarydefense medium, but the system involved a technology that
was completely new to the operator and the majority of the
drilling personnel. Frequent client and third-party
presentations, including platform visits, hardware inspections,
and system demonstrations were conducted in order to
improve the overall familiarization with the system and
technology.
Typically, customer and drilling contractor experience is
fairly high in running conventional completions where onemight have a number of control lines being deployed from
surface. The intelligent completion deployed in C-29 involved
running a quantity of two (one primary, plus one redundant)36mm x 12mm encapsulated umbilical flat packs through the
drilling blowout preventer (BOP). In addition to the hydraulic
and I-wire lines, each umbilical houses two, 7/16-in.
galvanized mild-steel braided-line bumper bars. These bars areincorporated into the design to offer protection to thehydraulic and I-wire lines during deployment.
One of the drawbacks to this design is that a typical
drilling BOP configuration has difficulty in effectively cutting
and sealing small braided bumper bar lines. In addition, the
annular preventer (Hydril) has difficulty in achieving a 100%
effective seal when closed around the umbilical and tubingbecause of the latters geometric irregularity.
Several tests were conducted to verify the capability andeffectiveness of the drilling BOP to cut and seal through 7-in.tubing with the umbilical clamped to the outside. The test
results varied, but were never acceptable. The main problem
concerned the fact that standard drilling BOPs are notdesigned to cut such relatively small cross-sectional braided
lines.
The wellhead configuration in Gullfaks incorporates what
is defined as a tubing shear ram assembly (TSR), which is an
integral part of the wellhead design, and is located below the
tubing hanger spool on the Xmas Tree. The primary purpose
of this device is to cut and seal hydrocarbons from both the
production tubing and any subsurface control lines in the even
there is a catastrophic failure to the Xmas Tree. The actuator
and cutting mechanism for closing the TSR is extremelypowerful and effective, having been specifically designed andtested for this application. When testing was successfully
conducted to verify the effectiveness of the TSR, the devicewas chosen as the primary method for shearing the umbilica
and tubing at surface, if the well control condition warranted
such action. The drilling BOP was then only required to be thesecondary support method.
Well control contingencies such as stripping in on drillpipe
were turned down due to the small tolerances and possibilities
of stuck pipe in an emergency situation. The clamps installedon the tubing would also make this difficult.
During the deployment of the C-29 completion, the tai
pipe was sealed by means of a retrievable plugging deviceThis sealing operation was required to test the integrity of the
tubing at different stages of the deployment.
Surface control and communication are maintained for
each ICV during the deployment. This feature allows a
technician to open or close any of the ICVs duringdeployment or collect data from any of the sensorsFurthermore, the production packers are also selectively se
from surface by means of communicating through the
umbilical. This capability offers real benefits if a well contro
situation should arise.
The lowermost ICV was always in the full-open position
while running tubing. This offered a circulating path within
5m from the end of the tail pipe. In addition the open ICV
allowed the tubing string to fill automatically while runningthe completion.
In a worst case scenario, the upper 9 5/8-in. production
packer could be set by surface control through the umbilica(effectively isolating the upper annulus), and then, the lower
most ICV could be closed, rendering the well safe from any
blowout potential.
Depth Control and PositioningThe spacing out and landing of the completion could be
accomplished either by using pipe tally figures or through
tagging up from a known reference point in the casing. During
the design stage, it was felt that it was important to be allowed
the opportunity to select either option.
Calculating pipe tally is normally relatively
straightforward, but in the C-29 situation, the distances
between the perforated intervals were relatively short. It wasdecided, therefore, to tag up on a lower sump packer, whichwas only 5m below where the end of the completion tail pipe
had to be positioned and set, for reference.
Accurate placement of the packer/ICV assembly was
critical in C-29 as there was the possibility that sand
production could occur. Therefore, it was agreed that eachpacker/ICV assembly should be placed as far as possible
above the top perforation in each zone. There was risk that if
the assembly was placed either adjacent to or below the
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IADC/SPE 59210 INTELLIGENT RECOMPLETION ELIMINATES THE NEED FOR ADDITIONAL WELL 5
Kill the WellAs the perforated interval was only 1m and no cross-flow
existed, the killing operation was to be performed bycirculating in a kill pill from bottom. No difficulties had been
anticipated; however, this was not the case, and after several
unsuccessful attempts, a new strategy was needed.Several scenarios were constructed to explain why the kill
process did not work. Possible reasons for the failure were: A blown pump-out plug against the Lower Lundeformation
A poor cement job allowing channelling to weakerformations at the shoe
Fig. 7illustrates the possible leakage locations.
As communication against the Lower Lunde did not seem
likely due to the observed wellhead pressure, it was assumedthat a thief zone existed. A drillable cement retainer was run,
and a cement squeeze performed above this. After cleaning
out the cement across the perforated interval, it was clear that
the interval now held pressure. Further drilling of the cement
did, however, reveal that the plug against Lower Lunde was
blown as the well could not be pressured up. To resolve this
problem, another pump-out plug was installed on top of theblown packer /plug assembly.
Perforate Remaining Intervals and Prepare for RigActivitiesDue to the questions that appeared during the failed killing
sequence, uncertainty ranges for the pore pressure in the
Upper Lunde formation were extended. This established theneed for a separate check of this pressure also. Therefore,
before the well was killed, another perforating run had to be
performed in under-balanced conditions to confirm thepressure. This time, the operation was performed as planned
without any difficulties. To avoid any possible pressure pulses
from the detonation stressing the pump-out sub, a stinger wasadded to the perforation assembly to sting into and
hydraulically isolate the pump-out sub. Fig. 8 illustrates this
set-up.
Remaining intervals were then perforated overbalanced in
one run using the same stinger concept. The well was securedwith isolation plugs and displaced to sea water before the
HWU was rigged down. Fig. 9illustrates the well at this stage.
Results From the HWOThe job was technically brought to a successful completion
although the costs were somewhat higher than anticipated in
the original budget.
This was not surprising since entering an older well cansometimes lead to the discovery of unexpected well conditionsthat must be addressed, and there will always be added
uncertainties compared to completing in a new wellbore. In
this case, a poor primary-liner cement job was potentially
responsible for the challenges experienced when attempting to
kill the well after the first test perforation. Geometry variances
as well as the debris that inherently is found in an old well
could have caused the premature setting of the first packer.
The mysteriously blown pump-out plug cannot be
explained, but as the later stinger-assisted perforations did not
experience any problems; this was considered an indication
that the same protection should have been added for the firstperforation also.
If one lesson were to be drawn from this part of the job, itwould be that even though a very complex completion is being
planned, equally as close attention must be paid to the moretraditional parts of the sequence such as the packer setting and
perforation scenarios. In this case, all the challenge
experienced were related to pure mechanical difficulties thawere not related to the complexity of the intelligent wel
system.
Rig Work SequenceThe objectives of the rig work were to:
1. Pull out the old completion2. Remove additional bottlenecks3. Cleanout wellbore4. Verify clearances5. Run intelligent completion string
The very small tolerances available made the cleanout ofthe well critical. Handling of various fluids, removal of debris
left after milling, and well control with brine only in the wel
were key elements to be addressed.
Pull old completion and remove bottlenecks. The oldcompletion was pulled without difficulty and the wellbore
displaced to heavy brine,however, the female member of the
PBR still remained downhole. This item was identified as
being a potential bottleneck to the succesful running of theintelligent completion. Subsequently, a run on drill pipe was
made to retirieve the remaining part of the PBR prior to
opening up the bore of the permanent packer with a 6.05-in
tandem mill. To maintain a clean wellbore, the mill cuttings
were cleaned out with a venturi junk basket before furtheroperations were commenced. The deepset plug that was stil
in place facilitated this operation. Fig. 10 illustrates the
wellbore after this cleanout operation.
Clean out perforated interval and gauge wellbore. During
the planning stages, this part of the operation had been
identified as critical. The well was to be cleaned out by
circulating heavy brine, maintaining fluid loss control with
filtercake and overbalance.
The deepset plug was pulled after having conditioned the
brine and verified consistent weight. The well was once againcirculated to check for any hydrocarbon migration. At this
stage, the perforated interval was still covered with a killpill.A cleanout assembly consisting of a 5-7/8-in. bit with two
6.05-in. string mills in tandem were run next. Using this
assembly, the entire perforated interval was cleaned out by
circulating brine at high rates. Killpill material could not be
used as ECD considerations demanded non-viscous fluid. Thecleanout progressed to total depth without losses of any kind.
To once again secure the well, a new killpill was placed
across the perforated interval, and the cleanout assembly waspulled out of the hole.
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6 OLE HENRIK LIE AND WAYNE WALLACE IADC/SPE 59210
Finally, a specially designed drift was run to total depth.
This drift was specifically designed and manufactured to
simulate the critical components of the completion string interms of diameter, length and stiffness. No restrictions were
noted.
Installing the intelligent completion string. In preparationfor the installation, a location plan outlining the positioning
for all surface equipment had been prepared.The 'intelligent' parts of the completion are fairly modular,
and the actual running of the string only differs from a normal
completion in that a considerable amount of surface work is
required each time an 'intelligent' component is made up. For
each separate zone to be controlled, one full assembly must be
made up. Typical make-up times were 24 hours per assembly.
After installation of the first assembly, a bolt from a dog
collar handle was lost in the hole. Due to the optimized
equipment placement, it was possible to rack the entireassembly back, control lines and all, while the bolt wassuccessfully recovered with a venturi junk basket.
The remaining assemblies were run as planned and the
hanger landed after depths had been verified by tagging thedeep isolation packer. The string was tested, and the annulus
displaced to packer fluid through the upper choke before all
downhole packers were set. Additional tests were performedbefore plugs could be set. The BOP was nippled down, and the
rig procedures were completed. Fig. 11 illustrates thedisplacement process with the intelligent completion string on
position.
Finalizing the Installation. After the rig was removed, theXMT was installed. All control lines were pulled through the
wellhead barriers and the intelligent control system hooked up.
All downhole functions could now be controlled from the
platform control room.
Prior to handing the well over for production testing, theplug against the Lower Lunde formation was blown by
pressuring up the wellbore, keeping only the lowermost choke
in the open position.
Fig. 12shows the well schematic of the completed well.
Summary of Operational ResultsNo major difficulties were experienced, and this sequence of
operations was performed according to plan for the most part.
One notable experience was that maintaining a clean and
weighted brine system while performing a cleanout withpossible debris and HC-traces is difficult and costly. The brine
returns were often found to be insufficient in quality and could
not be circulated back down.No problems were experienced with the tight clearances
that were initially considered as one of the major challenges to
address. The detailed cleanout process is considered the main
reason this phase of the operation was comparatively problemfree and this justifies the costs incurred.
CostsThe final bill for the job came in above forecast budget.However, some of this over run can be attributed to last
minute changes in data and demands resulting from
experiences gathered during the job. All these changes were
however, approved along the way, and therefore, are not
considered as traditional cost over runs.Major additional over runs were nevertheless caused by
the lost circulation problems experienced, which caused a lossof several days, in addition to a severe cost escalation for the
additional fluid needed. The fluid bill was, in fact, one of thebudget items that showed the greatest variation from estimate
The challenge of performing so many operations in a clean
brine system was underestimated. Some time was also lost dueto other difficulties, primarily related to the HWU operation.
Production ResultsThe well today is capable of producing simultaneously fromfour different zones. One zone, however, is presently shut in
because of pressure that is too low to allow introduction intothe well stream even with full chokes on the other zones.
Production results are favorable, and the data available
from the continuous downhole production logs for each zone
has provided the reservoir-planning group with valuable
information.
Data gathered in C-29 as well as the introduction of thenew zonal control possibilities have, in fact, led to a reviseddevelopment plan for the area. A new injector/producer is
planned to assist the recovery of all zones. This well will be
run according to data gathered real time in C-29 and will resul
in an increased recovery for the area. Fig. 13 illustrates this
planned well and the drainage concept.
Financially, the well can more than sustain the additiona
installation costs that were incurred. Even with the stringent
net present value (NPV) demands prevailing in todaysclimate, the well is an economic success. Additionally, the
experience that has been gained from this project is
invaluable. Similar projects are already underway using thistechnology, which is now considered as proven from the
operators viewpoint.
Fig. 14 is a graph showing the current production profile
estimates compared to the expected production had an
intelligent completion not been installed.
ConclusionsThe installation of the first intelligent well on the Gullfaks
field has been completed and is considered as a success. This
was the worlds first case history in which a well was
recompleted with an intelligent completion system.
Although some challenges were encountered during the
installation process, very few problems encountered could berelated to the intelligent well technology. The bottom line forthe well is positive, both from a technical and an economic
viewpoint.
The increased reservoir knowledge has attributed to a
revised development plan for the area. The technology is nowconsidered field proven, and several other installations are
already underway. Many lessons were learned from this firs
installation that will undoubtedly facilitate the operationa
procedures planned for subsequent wells.
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8 OLE HENRIK LIE AND WAYNE WALLACE IADC/SPE 59210
Fig. 2 Section and location map of Well C-29
SCSSV
7 HF Zonal Isolation
IICV with Sensors
7 HF Zonal Isolation Packer
IICV with Sensors
7 HF Zonal Isolation
IICV with Sensors
9 5/8 HF Zonal Isolation Packer
SCSSV Control Line
Dual Flat Packs each containing a Single Hydraulic and Single Electrical Line
Fig. 3 Operational principle of the Intelligent Well system.
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IADC/SPE 59210 INTELLIGENT RECOMPLETION ELIMINATES THE NEED FOR ADDITIONAL WELL 9
Fig. 4 Potential reservoir zones in the well with relevant reservoir parameters
LITHOLOGY PERM,mD RFT,bar
200
0,2
360
270
300mTVD
"UPPER"
STATFJORD
GOOD CONTINUITYHIGH PERMEABILITYLOW WATER SATURATION
"LOWER"
STATFJORD
MODERATE CONTINUITYHIGH PERMEABILITYLOW WATER SATURATION
"UPPER"LUNDE
MODERATE CONTINUITY
MODERATE-HIGH PERMEABILITYMODERATE WATER SATURATION
"LOWER"
LUNDE
LOW CONTINUITYLOW PERMEABILITY
HIGH WATER SATURATION (>50 %)
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10 OLE HENRIK LIE AND WAYNE WALLACE IADC/SPE 59210
Fig. 5 Completion schematic of original C-29 well.
MD(m)
WELL SCHEMATIC DESCRIPTION
41.05 7Upper Tubing Hanger
729# Pup Joint
7Lower Tubing hanger
729# Pup Joint
729# Tubing
729# Pup Joint
729# TRCF-5-RH Safety Valve
729# Pup Joint
729# Tubing
729# Pup Joint
7Gauge Carrier
729# Pup Joint
732# Tubing
732# Pup Joint
7PBR 32# W/20ft Stroke
732# Pup Joint
732# Tubing
732# Pup Joint
732# SABAnchor7 x 9 5/8-53.5 THB Packer
732# Pup Joint
732# Tubing
732# Pup Joint
732# Pup Joint
729# Tie-Back Seal Stem
41.80
42.46
47.30
554.00
555.88
558.92
560.76
2657.96
2659.82
2661.90
2663.78
2675.88
2678.07
2686.14
2688.17
2700.28
2702.35
2704.57
2707.09
2731.29
2733.78
2735.66
2740.19
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IADC/SPE 59210 INTELLIGENT RECOMPLETION ELIMINATES THE NEED FOR ADDITIONAL WELL 11
Fig. 7 Possible Leakage locations
Fig. 6 Packer in place and In-flow testing
7liner
Pump Open Plug
Weak Formation at shoe
Possible Poor Cement
I
II
Lower LundeFormation(depleted pressure)
Upper Statfjord fm.
I : Channeling to shoeII: Blown Pump-Out plug
Leakage Option
b991139
XMT
LundePressure
SW
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12 OLE HENRIK LIE AND WAYNE WALLACE IADC/SPE 59210
Orienting Guns
Solid XO Tandem w/swivel sub
2-7/8Tubing
Pinned Circulating Valve
Seal Stinger w/landing collar
Permanent Production Packerw/pump out ball
Trapped Fluid VolumeDischarged Through
Circulating Ports WhenStinging Into Packer
Orienting Guns
2- 7/8Tubing
Solid XO Tandemw/swivel sub
Pinned Circulating Valve
Seal Stinger w/landing collar
Permanent Production Packerw/pump out ball
Tubing Volume Isolated
Sheared Pins and ClosedCirculating Ports
Fig. 8 Perforating Stinger Arrangement
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IADC/SPE 59210 INTELLIGENT RECOMPLETION ELIMINATES THE NEED FOR ADDITIONAL WELL 13
Fig. 10Old completion string removed and cleanoutperformed above plug.
Lunde
Pressure
Killpill
DRILLINGBOP
RKB
Heavybrine
Removedtubing
RemovedPBR ext.
Milledpackerbore
XMT
Lunde
Pressure
Statfjord
Statfjord
U. Lunde
L. Lunde
SW
Killpill
Fig. 9After Hydraulic Workover operation.
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HeavyBrine
DRILLINGBOP
RKB
Opened upper 9 5/8" ICV
Pumped packer fluid downannulus and into tubing through9 5/8" ICV
Took returns of brine on tubingside. Choked back to maintain
overbalance
Closed 9 5/8" ICV
Note that well is nowunderbalanced. Well pressureheld on choke.
Runningstring
c-line
Hydrocarbons
Killpill
DHSV
Pack
erfluid
Brine
Packerfluid
Fig. 11 Displacing to light completion fluid.
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IADC/SPE 59210 INTELLIGENT RECOMPLETION ELIMINATES THE NEED FOR ADDITIONAL WELL 15
Fig. 12 Schematic of the Final C-29 Well configuration.
MD(m)
DEV(deg)
WELL SCHEMATIC DESCRIPTION
577
2636
2641
2665
2702
3032
3147
3297
3311
3312
3316
33183320
3322
68 deg
73 deg
74 deg
70 deg
7Upper Tubig Hanger729# Pup Joint
7Lower Tubing hanger729# Pup Joint729# Tubing729# Pup Joint729# TRCF-5-RO Safety Valve729# Pup Joint
729# Tubing
Crossover 5 1/2x 7.00
5 1/220# Tubing
5 1/2Crossover Pup Joint
9 5/8x 5 1/2HFPacker
5 1/2Crossover Pup Joint9 5/8x 5 1/2ICV5 1/220# Pup JointTop of PBRFluted Centralizer3 1/29.2# Tubing9 5/8TBHPacker C/W Tie-Back Seal Stem
7x 3 1/2HFPacker
3 1/2Crossover Pup Joint7x 3 1/2ICV3 1/2Crossover3 1/29.2# Pup Joint3 1/29.2# Tubing3 1/29.2# Pup Joint7x 3 1/2HFPacker
3 1/2Crossover Pup Joint7x 3 1/2ICVCrossover3 1/29.2# Pup Joint
3 1/29.2# Pup Joint
7x 3 1/2HFPackerCrossover Pup Joint7x 3 1/2ICVCrossover Pup Joint3 1/29.2# Pup Joint3 1/2Landing Nipple4 1/2x 3 1/2CrossoverSelf Aligning Muleshoe
732# Permanent PackerCrossover
Pump-Out PlugMuleshoe732# Permanent PackerPump-Out PlugMuleshoe
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16 OLE HENRIK LIE AND WAYNE WALLACE IADC/SPE 59210
Fig.11 Displacement Procedure
Fig. 13 illustrates the planned well and drainage concept.
REVISED DRAINAGE STRATEGY
C-29
ca 650 m
"LOWER" STATFJORD
BCU
"UPPER" LUNDE
"UPPER" STATFJORD
REVISED C-39
"LOWER" LUNDE
L1 L2
1750
2000
2250
PROPOSEDC-39
NS
As a consequence of installing Scrams, the drilling of a new well,C-39, was postponed until gaining production experienceA revised C-39 will be positioned further south (producer and injector)
TEST
TEST
Fig. 14 Graph showing Current production profile estimates compared to expected.