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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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5/16


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.


6/16


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.


7/16


8/16


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.


9/16


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 %)


10/16


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


11/16


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


12/16


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


13/16


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.


14/16


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.


15/16


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


16/16


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.

articulo terminacion 3

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