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1/9124 March 2011 SPE Drilling & Completion

Magnus: Utilization of ConductorSharing Wellhead Technology To Access

Additional Hydrocarbons With aSlot-Constrained Platform

S.E. Hicks, A. Moore,and M. Honey,SPE, BP Exploration; I.R. Farmer, Schlumberger;

B. Smart,SPE, and R. Ekseth,SPE, Gyrodata; and D. Brown,Cameron

Copyright 2011 Society of Petroleum Engineers

This paper (SPE 124233) was accepted for presentation at the SPE Offshore Europe Oil andGas Conference, Aberdeen, UK, 811 September 2009, and revised for publication. Original

manuscript received for review 19 August 2009. Revised manuscript received for review 18July 2010. Paper peer approved 20 July 2010.

Summary

The Magnus platform, UK northern North Sea, has been producingsince 1983 with all 20 original slots now occupied. Additional infilland extend-reach-drilling (ERD) production targets were identi-fied and a means of access was required while maintaining basefield production. Platform modification was selected because ofsignificant commercial advantage over alternative developments.The Magnus jacket was modified to permit running of four addi-tional large conductors into which two smaller casings could be

installed respectively.A tapered jacket profile necessitated preinstalled conductorguide frames to build to 4inclination at seabed, requiring initialuse of the large conductor as a conduit for drilling assemblies.Custom-manufactured and specialist equipment was designed andprocured to enable successful underreaming to 54 in. and installa-tion of 46-in. conductor. Drilling-assembly design and initial pilot-hole profile were deemed critical to subsequent success in runningrigid open-ended 46-in. conductor. Well-critical structural cementwas pumped to seabed by use of a 16-in. inflatable packer and innerstring. Unguided installation of two 185/8-in. casing strings inside46-in. conductor was then achieved. The 185/8-in. casing stringswere cemented in place using light cement to preserve (shallow)casing-shoe integrity. High-resolution multishot gyro surveys anda newly developed gamma-wipe survey technique were used to

obtain critical 185/8-in. relative-shoe-orientation information beforesubsequent kickoff.

Two wells were batch set successfully to the 133/8-in. casingshoe by means of one conductor. Modification of existing well-head technology for close proximity has proved successful. Accessto additional Magnus resources by means of an otherwise fulltemplate has been delivered by this conductor-sharing-wellhead(CSW) technology.

Introduction

Magnus is the most northerly currently operated field on the UKContinental Shelf (Fig. 1). Discovered in 1974, Magnuss firstproduction was established in 1983. Continual field developmenthas resulted in more than 90 penetrations including exploration,

appraisal, and development wells.In 1995, production from a now full well template plateauedand a program of well-intervention work was commenced to offsetrapid decline of 60% per annum (Day et al. 1998). An enhanced-oil-recovery (EOR) program was later adopted, using water-alter-nating-gas injection to maintain field output. Extensive subsurfacework focused on EOR mechanisms across discrete reservoir panelsand identified multiple new injection and off-take points that wouldbe required to optimize field production from each respective area

(Moulds et al. 2005). By the late 1990s, it became apparent thatsidetrack options from existing wells alone would not permit fulloptimization of the Magnus EOR program.

Conventional means of accessing newly required targets, suchas limited multilateral drilling (as wells become available), wouldnot deliver full EOR potential. Conversely, a subsea satellite devel-opment was found to be uncompetitive in early studies, given theincremental nature of the EOR program. The most commerciallyviable solution was found to be modification of the existing Magnusplatform jacket to permit new wells to be drilled from surface.

The complexity and tapered profile of the Magnus platformjacket prevented the introduction of more than seven new drill-ing slots. To use newly constructed slots fully, conductors wouldeffectively have to be split, permitting two wells from surfaceto be installed per conductor. This paper outlines the major chal-lenges posed by conductor-sharing well design and outlines somesolutions found to aid successful well delivery.

Magnus Extension Project (MEP)

The Magnus platform design, providing an original 20 slots,incorporates a double-battered, four-legged jacket, suitable to itslocation 165 km north of Shetland in 186-m water depth. Criti-cally, because of the remote situation and exposure of the platform,Magnus has a 57-m air gap, designed with its own drilling derrick

from the outset. As such, the Magnus platform does not featurea vertical face that jacket designs in shallower water depths mayhave. Presence of such a vertical face or a lesser air gap simplifiesany post-construction jacket modification by permitting additionalconductors to be installed vertically at seabed (Matheson et al.2008). This benefit was not available to the MEP.

Platform Modification. The optimum location of new Magnuswell slots had been decided in 1990. The MEP was sanctionedin 2004, and the most suitable location for new well slots was onthe east side of the platform, the same side as the drilling pack-age. Only the east face of the platform allowed new conductorsto be installed without clashes with existing infrastructure. Earlyfeasibility studies included appraisal of new vertical conductorsexternal to the platform jacket; however, the necessary overhangof the drilling derrick was found to lead to excessive structuralloading. Additional conductors installed on the Magnus platformwere, therefore, required to build to 4 inclination from verticalat seabed.

With the east face selected for the new slot locations, optionsof seven 30-in. slots or four 46-in. slots were identified. MEPfinancial criteria necessitated provision of eight new wells; hence,construction work for four new 46-in. splitter slots commencedin 2005.

To enable additional well slots to be drilled through the Magnusjacket, the modifications described in Table 1were carried out.

Conductor Guide Frames. Installation of six conductor guideframes per new well slot was carried out external to the platform

jacket (Fig. 2). These guide frames incorporated an asymmetricfunnel design to guide rigid conductor pipe, incrementally building

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vertical deviation to 4at seabed. Five of these preinstalled guideframes were installed subsea, and one was installed above sealevel (Fig. 3).

CSW DesignThe CSW concept has been proved elsewhere (Hashim et al. 1998;Dharaphop et al. 1999). Recent developments in wellhead designhave led to reductions in required stack-up height, minimizing plat-form deck requirement (Santos and Floch 2006), and up to three wellshave been installed in a single conductor (Matheson et al. 2008).However, use of 46-in. full-length conductor required the manufac-ture of new wellhead equipment based on existing designs.

Magnus field well design retains the option of a 16-in. liner inthe case of problematic drilling of cuttings-reinjection domains.Such a well design necessitated that 185/8-in. (or larger) conductorconduits be run inside the main 46-in. conductor. Standard 133/8-in. 10K wellhead equipment could be used provided that adapterequipment could be modified for 46-in. conductors. The key chal-lenge in this respect was found to be the close proximity of adjacentwells when drilling, requiring development of an API recognizedD-shaped flange permitting riser installation on adjacent slot-shar-ing wells. Existing 36-in. adapter equipment was scaled up to 46in., and a complete conductor-sharing system was manufacturedthat permits dual 185/8-in. installation from surface (Fig. 4).Thissystem was specified to material class DD/HH, temperature classU (0250F), and product specification level 3 plus gas test, andwas fire safe in accordance with API 6FA/6FB as per Magnusreservoir requirements.

Wellhead Arrangement.While the wellhead and tree equipmentwere manufactured to satisfy a 5.8-m vertical allowance aboveconductor cut height, arrangement of individual wellheads withinthe well bay had to be optimized to permit installation of all eight

planned trees within a 10.5-m-long deck space. The mean 46-in.conductor center-to-center distance at surface was 2.36 m. A tech-nically simple method of achieving this requirement would be themanufacture of four custom-made compact housings, providingunique side-outlet-valve and tree orientations for each well. Thiswould, however, have been prohibitively costly and would haveincurred risk during wellhead installation unless unique back-upequipment was also procured for each well.

To overcome this problem, a 3D model of the well-bay spaceand wellheads was created and final compact-housing wellheadrequirement was refined to three unique designs (Fig. 5).Thesethree variants of compact wellhead housing will permit installationof eight adjacent wells by means of four 46-in. conductors.

The installation of large starter head equipment close to theconductor deck of the platform, compounded with restricted height

availability, made conductor squat and growth analysis critical. Astudy was commissioned to encompass all scenarios of well pairing(e.g., two injectors, two producers, and an injector/producer pair)to verify that any movement of the wellhead would not interferewith platform infrastructure (Fig. 6).

The 46-in. Conductor Installation

The unique challenge of the MEP CSW application stems fromthe 4deviation from vertical imparted by the 46-in. conductor at

Fig. 1Magnus field location within the northern North Sea.Fig. 2Location of new conductor guide frames on the eastface of the Magnus platform jacket; asymmetrically funneledguides were external to the jacket and built vertical deviationto approximately 4at seabed.

TABLE 1MEP PLATFORM MODIFICATIONS AND RATIONALE

Modification elanoitaR

Installation of six conductor guideframes per conductor

Needed to support and guide the curvatureof new well conductors to seabed

Extension of the drilling derrickskid beams

To allow the drilling derrick to skid an additional 8.5 mto the east, thereby accessing the new slots

Strengthening and extension ofplatform steelwork

Impact deck level above wellhead deck requiredextension over new slots; main cantilever primarysteelwork was strengthened to permit safe transfer

of new loads whilst skidded over new slots

Rerouting of existing pipe work Pipe work on the eastern side of the platform wasrerouted to permit new conductors to be run adjacent

to the well bay; new perimeter escape route was required

Control and safety system upgrade Systems modified to include the additionalwells and flow lines

dnastolsllewwenehtmorfgnillirdetatilicafoTedargpugirgnillirD

provide access to new ERD targets

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and promote build-over-drop tendency for conductor running.This pilot hole was opened to 42 in. by use of a hole opener andbullnose assembly, and the 42-in. hole was in turn underreamedto 54 in. These drilling assemblies needed to be guided to seabedthrough the conductor guide frames. To this end, an initial sectionof 46-in. conductor was run open ended to seabed to act as a drill-ing assembly conduit before spud. Use of an inclined open-endedconductor in turn obviated simple use of internal conductor guides,landing rings, or stab-in plates (Hashim et al. 1998; Tuah et al.2000; Anchaboh et al. 2001; Faget et al. 2005) into which subse-quent 185/8-in. strings could be run. Dual 185/8-in. conduit stringswere run unguided into an open-ended 46-in. conductor.

Conductor Handling.A 46-in. conductor joint weighs 11 tonnes,and conventional 46-in. elevators could not be operated easily inthe rig floor space available. Custom-manufactured 46-in. elevatorswere procured that could be used in conjunction with conductorend caps that incorporated a lifting shoulder (Fig. 7).

Use of a custom-manufactured weight-spreader frame toeffectively strengthen the blowout-preventer (BOP) deck directlybeneath the rotary table in the drilling derrick permitted the sus-pension of the initial 46-in.-conductor section before spud, at theBOP deck. The BOP deck weight-spreader frame was designed toincorporate 46-in. remotely operated autoslips (Fig. 8).

An internal lifting tool was used to raise and lower the 46-in.conductor string vertically to the BOP deck, affording a clearrotary table for subsequent top-hole drilling. (Use of 42-in. hole-opening and 54-in. underreaming tools required the removal of the

rotary-table adapter rings that would have complicated operationof a false rotary table.)

Fig. 3MEP conductor guide frames installed external to theplatform jacket, 7 m above LAT; five more guide-frame struc-tures were installed external to the tapered jacket subsea.

Fig. 4Complete 46-in. starter head dual 135/8-in. 10K CSWstack-up illustration.

B-annulus outlets

A-annulus outlets

C-annulus outlets

B-annulus outlets

A-annulus outlets

C-annulus outlets

Fig. 5CSW alignment simulation illustrating relative orienta-tions of wellhead housings at the A, B, and C annuli outlet-

valve levels; note staggered outlet-valve orientations by levelto permit access to and operation of all valves.

seabed. To aid running of 46-in. conductor, 54-in. hole size wasselected. This large hole size required manufacture of new under-reaming arms that could be used on an existing tool. A 26-in. pilothole was first drilled by use of a motor to maintain inclination

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Open-Ended Conductor Running. The seabed at the Magnusplatform location is too hard to permit driving of the conductors.

Historical attempts to run stiff 46-in. conductor through moderate(>1/30 m) doglegs have proved to be problematic. While drill-string design was carried out to minimize top-hole tortuosity andmaintain a hold-to-build profile out of the final conductor guideframes, a contingency was required in the event of undesirabledoglegs being introduced by means of the initial pilot hole. To

this end a 42-in. retro-fit conductor shoe was designed and manu-factured (Fig. 9).This shoe would be run if dogleg severity wassurveyed to exceed 1/30 m at any point in the initial pilot hole.Suspension of the shoe inside an open-ended 46-in. conductor jointwould be achieved by means of a 133/8-in. inflatable packer madeup to a 133/8-in. shear-out sub, and the complete assembly couldbe run and retrieved on drillpipe. The 42-in. retro-fit shoe was notdeployed on the first MEP well because of a surveyed pilot-holeprofile of dogleg severity less than 1/30 m.

46-in.-Conductor Cementing. Cementation of the first MEP46-in. conductor was achieved by means of an inner string witha 16-in. inflatable packer set below sea level. This 16-in. packerprevented backflow of large volumes of cement by removing thecompressible air column within the conductor volume. A cus-tom-manufactured 46-in. cementing/running tool acted as a triplebushing by which the conductor could be sealed at surface and apassing packer could be monitored. Use of a control-line-operated

Fig. 6The 46-in. CSW installed; picture shows intermedi-ate housing lowermost (complete with C-annulus side outletvalves) and dual compact housings uppermost (complete withA- and B-annulus side outlet valves); note close proximity ofconductor deck steel.

Fig. 7Use of 46-in. conductor end caps that incorporated a1-in. lifting shoulder permitted use of custom-manufactured46-in. elevators to aid conductor running.

Fig. 846-in. remotely operated autoslips used in conjunctionwith a custom-manufactured weight-spreading frame allowedthe entire weight of the 46-in. conductor to be supported from

the BOP deck beneath the drilling-rig floor, simplifying initialdrilling operations.

Fig. 942-in. retro-fit conductor-shoe representation; whilethis contingency conductor shoe was not required to be run,given the quality of 54-in. hole drilled, it was designed to maxi-

mize chances of 46-in.-conductor running success in the eventof tortuous top hole.

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pressure seal was required between touching 185/8-in. strings insidethe 46-in. conductor. Given the likely length of metal-on-metalcontact inside the 46-in. conductor, the cementing-fluid velocityprofiles and resulting cement sheath about the unguided conduitswere likely to be poor. Maximum annular coverage was therefore

deemed critical, and 1.50-SG cement slurry was used for the wholecement job to permit a cement column back to surface withoutfracturing the conductor shoe.

The first MEP 185/8-in.-conduit pair was cemented successfullyin this fashion using a stab-in/latch-in cement stinger by means ofthe deepest (E8) 185/8-in. string.

Conductor-Sharing Well Planning

The 4inclination at seabed was imposed by structural constraintsof the upper jacket but is desirable for ERD wells, provided thatthe well heading is aligned similarly. Well target and slot alloca-tion was, therefore, conducted in such a way that non-ERD wellscould turn back beneath the platform from their initial eastwardheading (e.g., to satisfy infill requirements). New ERD injection

and production targets could be accessed to the north and south ofthe platform without the introduction of excessive tortuosity.

New-Well Trajectories.Given the rigidity of the 1-in. wall thicknessof the 46-in. conductor, the constant southeastward heading initiatedby the conductor guide frames was maintained to the conductor set-ting depth. The slight vertical deviation necessarily imparted by the46-in. conductor at seabed was, therefore, held constant in plannedtangents to the 46-in.-shoe depth. Planned MEP wells then adoptedshallow S-shaped profiles to attain target step-out and drop to 45inclination through the reservoir. Maintaining lateral deviation fromadjacent wells at surface would, however, be critical, given the closeproximity to what may be a completed well (Fig. 11).Comprehensiveanticollision schedules and survey programs were required at each

stage of top-hole- and intermediate-hole-section drilling to maintainsafe separation from both existing and planned MEP wells.

Fig.10

E8: PMEP1 E7: NWMP Depth reference datum: rotary table (RT).All depths MDBRT (TVDBRT)Wellhead: 27 m MDBRT

MSL: 57 m

Mud line: 243 m

Upper Nordland: 712 m

(707 m)

Lower Nordland: 958 m

(937 m)

Hordland: 1017 m

(989 m)

185/8?TOC: 77 m (77 m)

46?TOC: Mud line

133/8?TOC: 340 m (340 m)

46?1?WT X52/X56 XLC-S-RB: 380 m (380 m)

3 deg inc / 137 deg azi

185/8?87.5 ppf K55 Hydril 521: 390 m (390 m)

NWMP: 385 m (385 m)

133/8? 72 ppf L80 Dino Vam: 1150 m (1100 m)36 deg inc / 220 deg azi

NWMP: 1131 m (1100 m) 21deg inc / 59 deg azi

Fig. 10CSW well-design illustration showing batch-set 133/8-in.-casing strings cemented back inside conductor-sharing 185/8-in.conduit strings.

inflatable packer also afforded the capability to maintain inflat-able-element pressure if a leaking packer was observed. A 46-in.conductor was suspended by the blocks to mitigate the risk ofbecoming locked in the slips as the cement set.

Unguided Conductor Conduits. To reduce drilling complex-ity, dual 185/8-in. conduits were planned to protrude 5 and 10 mfrom the 46-in.-conductor shoe only, vertically staggered to aidsubsequent kickoff from each well. Placement of 185/8-in.-casingshoes deeper by means of continued drilling was not required bythe Magnus casing design (Fig. 10).To this end, a single 42-in.cleanout run was carried out through the 46-in.-conductor shoe,into which both 185/8-in.-conduit strings could be run.

To reduce the tendency of the second unguided 185/8-in.-conduitstring to hang up on the initial 185/8-in.-conduit string, semiflushconnections were used on non-centralized pipe. The initial conduitstring was run to protrude 5 m outside the 46-in. conductor shoe,a minimum of 8 m off hole bottom to negate any chance of thefirst 185/8-in. string hanging up on hole fill, leading to bucklingand ensuing occupation of greater space inside the 46-in. con-ductor. The second 185/8-in.-conduit string was then run to 10 moutside the 46-in.-conductor-shoe depth with an eccentric shoe toaid running against the initial conduit. A stab-in circulating cas-ing-running tool was also used throughout dual 185/8-in. runningoperations to maintain the capability to wash and rotate casing atany stage in the operation.

Dual Unguided 185/8-in.-Conduit Cementing. Both 185/8-in.-conduit strings needed to be cemented uncentralized (to reducerunning risk) and by means of a 57-m air gap with a low formation-fracture strength. Extensive Magnus offset drilling has resulted in awell-constrained fracture gradient of 1.26 SG at the conductor-shoedepth of 380 m measured depth below rotary table (MDBRT). The185/8-in.-conduit cement did not carry structural loads. All well

and tree loads were transferred to the 46-in. conductor (Fig. 10).Subsequent hole sections were drilled using a diverter, so a 60-psi

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Batch Setting Strategy. Planned well profiles were optimizedas far as possible to satisfy operator anticollision criteria; how-ever, close proximity of conductor-sharing wells down to 600-m

MDBRT would have necessitated the shutting in of an active wellwhen drilling the adjacent conductor-sharing slot. To mitigate thisrisk and simplify operations, batch setting of subsequent (typically133/8-in.) casing strings was adopted (Fig. 10).

Similarly, downhole and annular safety valves have been deep-ened to approximately 650-m MDBRT, which is sufficient to allowsafe exit of future MEP wells from remaining 46-in.-conductorslots. Subsurface safety valves are not recognized as valid pres-sure-containment barriers; however, their planned closing (e.g.,when drilling nearby) does reduce the severity of consequences inthe event of a collision above the closed subsurface safety valve.In this way, a tolerable collision risk-assessment exercise can beconducted and executable separation factors can be derived topermit drilling of close top holes. In this way, boundary conditionswere placed around both existing and planned wells, with lesserseparation permitted above deepened subsurface safety valves. Acollision above a closed and tested subsurface safety valve wouldhave no environmental impact or health, safety, and environmentimplications, provided the appropriate wells have been shut inand gas inventory has been evacuated. A typical traveling-cylinder(anticollision) plot illustrating the close proximity of offset wellsat 600-m MDBRT is presented in Fig. 12.

The 185/8-in. Survey Method. Installation of two unguided casingstrings inside a 46-in. conductor would lead to unknown relativepositioning of respective 185/8-in. strings. Simulation work pre-dicted that the second unguided string would not have sufficientweight to nudge the first string out of position on the low side of the46-in. conductor. The probability of the 185/8-in. strings becoming

twisted could not be eliminated, complicating well target allocationto 185/8-in. slots at surface (Fig. 13).

The two unguided 185/8-in.-casing strings were expected tobe touching at the 46-in.-conductor shoe and to be only 1.33 mfrom planned tolerance lines of adjacent MEP slots. This unusu-ally tight well spacing required the use of some novel surveyingtechniques.

Gamma-Wipe Survey Technique. A newly developed gamma-wipe technique used a directional gamma tool and wireline con-veyed gamma ray source to confirm the relative orientation ofadjacent 185/8-in.-casing strings.

A focused gamma ray logging-while-drilling (LWD) tool wasrun to the shoe of the first 185/8-in. casing, while two centralizedgamma sources were lowered on wireline into the adjacent 185/8-

in.-casing string (Fig. 14).Rotating the LWD tool on drillpipe byincrements of approximately 30provided azimuthally dependentgamma-ray signal strength, providing relative orientation of adja-cent casings.

A peak reading in gamma counts above background indicatedwhen the sensor package was directed toward the center of theadjacent 185/8-in.-casing string (Fig. 15).

High-Density Gyro Surveys. While the gamma-wipe techniquewas planned to provide relative 185/8-in.-string orientation infor-mation before well allocation and drill out, use of high-densitymultishot gyro surveys in both 185/8-in. casings was predicted tobe capable of distinguishing the two well paths in space.

At surface, the position of both 185/8-in.-casing strings wasfixed because of a 46-in. landing plate that was mounted atop the

46-in. starter head. Into this landing plate, the two 185

/8-in. mandrelhangers were run and landed (Fig. 16).Close proximity of adjacent unguided 185/8-in. strings led to the

conventional ellipses of uncertainty for respective gyro runs notproviding unique well paths for individual conduits (Fig. 13, A).To overcome this issue, two gyro-survey runs were carried out ineach casing string with a high-resolution survey interval of 3 m onthe in run and 12 m on the out run. Two complete sets of runninggear and downhole electronics were mobilized to minimize the riskof gross errors being repeated between surveys in the same slot.Multiple survey stations were acquired at each depth to analyzerepeatability of data in real time. High-accuracy centralizationwas achieved through use of precision roller equipment above andbelow survey tools.

Gyro-Survey-Data Analyses. The first step in the analysis

procedure was to verify that there were no misalignments or grosserrors between surveys in the same slot. To achieve this, a coor-dinate-difference test (Ekseth et al. 2007) between the two sets ofsurvey data was compared against an ellipse of uncertainty, setat three standard deviations from center to center of the 185/8-in.strings at total depth (touching each other). This method wouldensure that the data were performing within the ellipse boundariesthroughout the whole run and not only at total depth. A chi-squaredanalysis was then carried out to establish the level of confidencein the comparison between the data sets.

Slot One (E07).The two high-resolution surveys (run in at 3-mintervals) in Slot E07 were compared at 15 different points. Com-parisons of the coordinate differences at these points were then testedagainst error parameters. A chi-squared test was run, and test limitswere set at one, two, and three standard deviations. If all parametersfell within the 2 standard-deviation boundary, analysis could proceedwith confidence. Uncertainty terms in the band between two andthree standard deviations would mean that we could proceed withcaution. Confidence levels above three standard deviations betweentwo surveys in the same slot would mean that repeatability had notbeen achieved because of gross errors. Results from the comparisonwere close to the one-standard deviation limit, allowing combinationof data from both runs to create a definitive survey.

Slot Two (E08). The same process was repeated for the datain Slot E08. Results from the chi-squared test were again favor-able. Run data were again combined, and a definitive survey wascreated. Comparison of the two definitive well paths could thenbe carried out.

Well-Path Comparison. The separation between the two sur-

veyed well paths was plotted against the known minimum (center-to-center distance if 185/8-in. strings were touching) and maximum

Fig. 11Example plan view showing CSW profiles in the vi-cinity of the 46-in. conductors; for planning purposes, both46-in. conductor and internal unguided 185/8-in. conduits wereassigned well paths. Green dots represent conductor locationsat surface (46-in. conductor in center and 185/8-in. conduits oneither side).

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(center-to-center distance if casing strings were sitting againstopposite sides of the 46-in. conductor). Change in relative orien-tation of one string to another was then plotted, and trends wereanalyzed. Separation between the surveys from each casing stringwas then plotted against the known physical boundaries (Fig. 17).

It was expected that the most likely outcome would be that thecasing strings would be touching for the majority of the sectionand hence the actual center-to-center distance would be close tothe minimum separation. This was generally found to be the case,as illustrated in Fig. 17. Little change in relative orientation of

Fig. 12Typical traveling-cylinder, or anticollision, plot illustrating allowable deviations from plan of less than 1 m at 600-m MDBRT.

(a)Image illustrating

overlapping EOUs

(b)

Planned exit from 185/8?(c)

Image of twisted 185/8?(d)

Possible collision if 185/8?

relative orientation unknown

EOUsOUs

Twisted 1wisted 858

Fig. 13Illustration of unknown 185/8-in.-conduit paths inside 46-in. conductor when installed unguided; conventional gyro-survey

accuracies would lead to significantly overlapping ellipses of uncertainty (EOUs) (A) preventing derivation of two distinct paths.Incorrect allocation of well target in the event of an unknown twist (C) could lead to a collision (D).

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the conduit strings was surveyed. The difference in orientationderived from the in-run data processed at 3-m intervals, in-run dataprocessed at 12-m intervals, and out-run data processed at 12-mintervals was between 29.65 and 45.93. Use of the higher-reso-

lution 3-m-spaced data suggested maximum offset of the secondconduit string to be rotated 29.65counterclockwise about the firstconduit string at total depth (Fig. 18).

Attempts to fully describe the two 185/8-in.-conduit paths insidethe 46-in. conductor by gyro surveys alone proved to be success-ful, and relative-orientation information derived from definitive185/8-in. gyro surveys corroborated previous gamma-wipe results.No change to well-slot allocation was required because no twistingof unguided conduits was found to have occurred.

Extensive gyro work carried out on the first MEP well pairoccupied 24 hours of rig time, while the gamma-wipe run occupiedapproximately 4 hours. Gyro-survey findings did, however, suggestthat reduced survey resolution could be afforded in the future anda second tool may be run in memory mode. Reducing the survey

program to one more rapid run per conduit string is, therefore,considered desirable, given the benefit of establishing accuratebottomhole locations. Data quality has shown that if any twistinghad occurred, then the gyro could be used to determine where thisoccurred and how it affected the casing strings. To this end, futureMEP programs will not incorporate the gamma-wipe technique butwill rely on an optimized gyro-survey program, estimated to takeless than 4 hours.

Fig. 1646-in. starter head with dual 185/8-in. landing plate and

18-in. mandrel hanger installed; center-to-center separationof conductor-sharing 185/8-in. strings is 23 in.

.2

.4

.6

.8

Metres

Measured Depth

Centre-Centre Distance Distance

Min 1s

Max 1s

Min 2s

Max 2s

Min 3s

Max 3s

Min physical

Max physical

0 50 100 150 200 250 300 350 400

Fig. 17Plot showing variation in gyro-surveyed center-to-center separation between 185/8-in. conduits inside 46-in. con-ductor with depth; physical limits of conductor inside diameter

and minimum 185

/8-in. center-to-center separation when touch-ing are included.

Conclusion

MEP conductor installation necessitated the use of 46-in. conduc-tor deviated from vertical, which in turn led to the installationof open-ended conductor and running of dual unguided 185/8-in.conduits. The nonstandard operation incorporated use of mul-tiple items of custom-manufactured equipment and required useof novel cementing and surveying techniques. Use of unguidedconduits has been demonstrated to be feasible, provided that newcementing and surveying methods are developed.

Acknowledgments

The authors thank BP EOC and partners Nippon Oil Exploration& Production UK Limited, ENI UK Limited, and Energy NorthSea Limited for permission to print this paper. Thanks are alsoconveyed to all team members of the MEP for helping to deliverthe first slot-sharing well pair ahead of schedule despite inherent

challenges.

References

Anchaboh, L., de Lange, F.P.A., van Beelen, C.J., and Tan, R.K.W. 2001.

Conductor Sharing WellheadsMore For Less. Paper SPE 68699 pre-

sented at the SPE Asia Pacific Oil and Gas Conference and Exhibition,

Jakarta, 1719 April. doi: 10.2118/68699-MS.

Day, S., Griffin, T., and Martins, P. 1998. Redevelopment and Management

of the Magnus Field for Post-Plateau Production. Paper SPE 49130

46Cut-Away

46Cut-Away

18-5/8conduit 1: run inhole with directionalgamma LWD tool to

depth D; rotate for peakgamma signal

18-5/8 conduit 2: run inhole with gamma sourceon slick-line to depth D

Fig. 14Gamma-wipe relative-survey-technique summary.

Gravity Toolface(GT F_RT)

Ray Gamma Ray(GR_RAB_RT)

190 (DEG) 190 0 300(GAP 1)

Fig. 15Image illustrating a typical response from a directionalgamma LWD tool: Gamma ray signature is shown in the right-hand track and gravity tool face in the left-hand track. In thisexample, the peak gamma response corresponds to a tool faceof 90right of high side.

7/25/2019 SPE-124233-PA (1)


Fig. 18Plot showing variation in relative orientation of gyro-surveyed 185/8-in. well paths with depth.

-180

-90

0

90

Degrees

Measured Depth

Centre-Centre Direction Direction

Min 1s

Max 1s

Min 2s

Max 2s

Min 3s

Max 3s

0 50 100 150 200 250 300 350 400

presented at the SPE Annual Technical Conference and Exhibition,

New Orleans, 2730 September. doi: 10.2118/49130-MS.

Dharaphop, J., Borisutsawat, C., Chaisangkha, V., Boyne, K., and Thouvenin,

E. 1999. Conductor Sharing A Viable Alternative to Multilaterals and

Slot Recoveries. Paper SPE 52876 presented at the SPE/IADC Drilling

Conference, Amsterdam, 911 March. doi: 10.2118/52876-MS.

Ekseth, R., Torkildsen, T., Brooks, A., Weston, J., Nyrnes, E., Wilson, H.,

and Kovalenko, K. 2007. High-Integrity Wellbore Surveys: Methods

for Eliminating Gross Errors. Paper SPE 105558 presented at theSPE/IADC Drilling Conference, Amsterdam, 2022 February. doi:

10.2118/105558-MS.

Faget, J.B., Monneyron, J.C., Bourgeois, A., Payer, N., and Cherng, L.H.

2005. 10K Dual Splitter Wellheads: First Worldwide Application on the

Development of an Offshore Gas Field. Paper SPE 96154 presented at

the SPE Annual Technical Conference and Exhibition, Dallas, 912

October. doi: 10.2118/96154-MS.

Hashim, S., Runggai, T., Khalid, M.Z., Kruit, W., Short, D., Duncan, B.,

Pauzi, N., Haron, J., and Low, F.N. 1998. Implementation of Twin

Well Technology Offshore Sarawak. Paper SPE 50082 presented at

the SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth,

Australia, 1214 October. doi: 10.2118/50082-MS.

Matheson, A.E., Tayler, P., Nash, R.S., and McAuley, J. 2008. Development

and Installation of a Triple Wellhead on the Britannia Platform. Paper

SPE 115698 presented at the SPE Annual Technical Conference and

Exhibition, Denver, 2124 September. doi: 10.2118/115698-MS.

Moulds, T.P., Trussell, P., Haseldonckx, S.A., and Carruthers, R.A. 2005. Mag-

nus Field: Reservoir Management in a Mature Field combining Water-

flood, EOR and New Area Developments. Paper SPE 96292 presented at

Offshore Europe, Aberdeen, 69 September. doi: 10.2118/96292-MS.

Santos, A. and Floch, A. 2006. 5K Dual Splitter Wellhead System: 1st

Middle East Deployment on an Offshore Oilfield, Combining Simul-

taneous Production and Drilling on Adjacent Wells Within the Same

Conductor. Paper SPE 101736 presented at the Abu Dhabi International

Petroleum Exhibition and Conference, Abu Dhabi, UAE, 58 Novem-

ber. doi: 10.2118/101736-MS.

Tuah, J.B., Rujhan, M., Mat, B., and Nam, L.F. 2000. Triple Wellhead

Technology in Sarawak Operations. Paper SPE 64277 presented at the

SPE Asia Pacific Oil and Gas Conference and Exhibition, Brisbane,Australia, 1618 October. doi: 10.2118/64277-MS.

SI Metric Conversion Factors

ft 3.048* E01 =min. 2.540* E00 =cmpsi 6.894 745 E00 =kPa

*Conversion factor is exact.

Simon Hicksis a BP drilling engineer, now based in Tripoli, Libya,working for BP Exploration Libya. He joined BP in 2004 havingcompleted a physics Masters degree at Imperial College, UKand a further research Masters degree in marine geophysics

at the National Oceanography Center, UK. Hicks has plannedand overseen numerous drilling programs across the North SeaUK, including subsea appraisal wells west of Shetland, centralNorth Sea subsea tiebacks, and high performance platformdrilling. He is now planning deepwater exploration wells off-shore Libya. Angela Moore is a senior drilling engineer withBP Exploration in Aberdeen, UK. She joined BP in 2000 with aBS degree from the Open University, UK. She worked offshorefor several years in the southern North Sea, UK and west ofShetland, UK on operations including multilaterals, workovers,and subsea wells. Moore worked as senior drilling engineer forMagnus, planning subsea, extended-reach, and conductor-sharing wells. She is currently leading a team that managessupplier performance for UK well operations. Mark Honey is atechnology research and development manager for BP basedin Sunbury-on-Thames, UK. He joined BP in 1998 and has workedmainly in the North Sea, UK in a variety of engineering andoperational roles both onshore and offshore, latterly as wellsteam leader for the Magnus platform. Honey has over 25 yearsexperience in the drilling and completions business and hasa BS degree from Birmingham University, UK. His current role isresearch and development manager for one of BPs flagshiptechnology projects. Honey is an SPE member. Ian Farmer isa drilling engineer at Schlumberger Drilling and Measurementcurrently located in Copenhagen, Denmark. He joinedSchlumberger Wireline Services in 1995 after graduating fromHeriot-Watt University, Edinburgh, UK with a BE in mechanicaland offshore engineering. Farmer is a wellbore surveying andwell positioning subject matter expert within Schlumbergerstechnical community. He has enjoyed a variety of Europeanand international assignments including deepwater projects,west of Shetland, UK as well as mature platform and new fielddevelopments in Denmark.Barry Smartis the Gyrodata techni-

cal services coordinator for the Europe, Africa, and Caspianregion. He joined Gyrodata in 1998 and moved to the tech-nical group in 2007 following five years as a survey engineerand four years as an account manager in the operationsdepartment. Smarts current role within the Gyrodata techni-cal group involves analysis of survey data and the testing andimplementation of new developments. He is an SPE member.Roger Eksethis a development manager at Gyrodata Inc. Hehas research interest in directional surveying. Ekseth holds anMS in geodesy and a PhD in directional surveying, both com-pleted at the Norwegian University of Science and Technology,Trondheim, Norway. He is an SPE member. Dave Brown is thesurface products account manager at Cameron, UK. He hasworked for Cameron for eight years in a range of technicaland managerial roles. Before his move to Cameron, Brownworked for seven years at Wood Group and ten years at Vetco.

He has more than 25 years experience as a design engineerand technical manager with surface wellhead systems.

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SPE-124233-PA (1)