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OTC 6992Downhole and Subsea Completion Design for a High-PressureNorth Sea Gas Condensate FieldS.D. Gomersall, Khalid Sardar, and G,R. Rae, Marathon Oil U.K.Copyright 1992, Offshore Technology ConferenceThis psp er wee p re sent ed at t he 24t h Annual OTC In Houst on, Texa s, May 4-7, 1992,This paper was selec ted for p reeentet ion by the OTC Prcgrsm Commi ttee fol lowing rev iew o f Informa tion con ta ined in an ebs trac t submi tted by the autho r e . Conten ts o f the peper ,se p resented , have not been rev iewed by the Offshore Technology Con fe rence and s re sub jeot to cor rect ion by the autho r s . The mater ia l, se p resented , dces not necessa ri ly ref lectarty poelt lon of the Offehore Technology Conference or I ts off icers. Permlse lon to copy ISreetrlcted toan abstrac t o f not more then 300 words. I llus tret lons mey not be copied. The ebetrec tehould con ta in conep lcuoue acknowledgmen t o f whe re and by whom the peper Is p resented .

@S TRACTThis paper details the overall system design for aJ.5,000 psi subsea, gas condensate well in the NorthSea. Currently, signifkant industry interest exists inthe technology required to complete wells of thistype, which would enable substantial hydrocarbonreserves to be developed. Subsea wells such as thishave not yet been completed.

INTRODUCTIONA significant number of high pressure discoverieswith surface pressures in excess of 10,000 psi havebeen made in the Central Graben of the North Seawhich await attractive project economics to allowtheir development. A reduction in cost and riskassociated with such a development may provide theincentive required. The technology needed to developthese discoveries economically is likely to includesubsea production systems as these are now a provenmeans of providing a low cost development. Subseatechnology has not previously been applied to thesehigh pressure wells and the downhole technology hasonly previously been applied from platform or landbased developments. This paper presents the issuesconcerned with the completion of such a well andwhere possible makes recommendations for a specitlcdesign. In areas where it has not been possible tospecify a ales@ comments are made regarding the

References and illustrations at end of paper

101

issues to be considered or resolved and su~estionsare made for additional industry development.

The work is based upon in-house desi~s ~dexternal studies performed for Marathon Oil UK inorder to allow the future development of its highpressure prospects and d~coveries. This design isbased upon the known and anticipated data from onesuch North Sea reservoir, Figure 1 shows theformation pressure of this reservoir in relation toexisting fields in the North Sea and elsewhere and toother as yet uncompleted prospects. Table 1 lists theoperating conditions. The pressures and temperaturesencountered in this design are not as severe as someother discoveries and do not meet some deftitions ofhostile (reference 1) or high pressure / hightemperature (HP/HT) (reference 2). However, boththese deftitions are somewhat arbritary, and since15,000 psi drilling and production equipment isrequired for the field, it is a significant departurefrom previous subsea completion experience.

The issues raised in this paper are relevant to thecompletion of wells with greater pressures andtemperatures than those in this well and as such thisdesign can be seen as a stepping stone to overcomingthe problems likely to be encountered in these wells.The wide ranging nature of the subject prevents anin depth analysis of each issue but is intended tostimulate and encourage further work in spetilcareas. Certain aspects and recommendations melikely to be controversial but it is hoped that bypublishing the work and sharing ideas, the

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2 DH & SUBSEA COMPLETION DESIGN FOR A HIGH PRESSURQ NORTH SEA GAS CONDENSATE FIELD OTC 6992development of M,000one step closer.

DESIGN PHILOSOPHYThis section outlinesintentions for the well.subsequent sections,

psi subsea wells may become

the general philosophy andSpecific details are given inalong with discussions onequipment selection. The ~perating conditions meshown in table 1.

The general design philosophy is an attempt to utiliseexisting industry experience in the area of downholecompletions, especially that for HP/HT wells whereavailable. Existing subsea technology has beenincorporated into the subsea equipment design wherepossible. The overall design seeks to maintainsimplicity and increase reliability in an effort toavoid workovers due to mechanical reasons. Weilintervention should be minimized through designwherever possible in order to reduce future. maintenance costs (reference 3). AU equipmentshould be designed with an adequate margin ofsafety included, to ensure failures do not occurwhich would compromise safety as well as financialobjectives.

This philosophy involves the use of corrosionresistant alloys (CRAS) for tubing ad dotiolecompletion equipment to prevent tubing leaks due tocorrosion. The requirement for heavy WZIU t hic~esspipe to cope with the high pressures, as well as thepractical limitations of the number of casing stringsrequired, means that the tubing size is determined asmuch by the ID of the casing and subsea productionequipment as by the reservoirs potential. This meansthat erosional velocities in the tubing are a concernespecially in the vicinity of ID changes such as thesurface controlled subsurface safety - valveand tubing hanger.

~The downhole completion design for highwells is not a new subject. Experienceseveral parts of the world, notablv onshore

saw)

pressureexists inUSA andoffshore - in the Guif of Mexico. This experience hasbeen utilised where possible and appropriate(references 1,4,9,12J3). similarly, completionsUtilising corrosion resistant alloys and producing gascondensates are not new to the North Sea andexperience here has also been incorporated(reference 5).

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Materiai SeieetionThe material selection for this weii, as for any other,is divided into two section% that for the flow wettedparts, including the liner and tubin~ and that forsecondary pressure containment components such asthe production casing. Only limited produced fluiddata is currently available and therefore anymaterial selected for the flow wetted parts isconsidered provisional.For long term production, as required for the tubingand liner in this design, H2S and C02 resistance isrequired and necessitates the use of a corrosionresistant alloy. A yield of 120,000 psi has been usedin ail relevant design calculations as the materialstrength available at the elevated temperatures inservice. For most materials this will necessitate adownrating from yield strength at ambienttemperature. For some materials the effect ofanisotropy must also be taken into account whencalculating yield strength under combmed loads. Thefinal material choice is field speciflq and may evenbe well spetilc depending on the chemicalproperties of the produced fluids. This highlights theneed to obtain good exploration drill stem test data,in particular the chemical analysis of ail producedfluids including water. Until such time as moredetailed produced fluid data is available for thiswell, it is assumed that duplex stainless steel will besuitable for the tubing and liner material. Theambient temperature yield strength required toobtain 120 MI at 280 deg F for duplex stainless steelwill be at least 140 ksi. Completion componentsshould be manufactured from a CRA with similar orsuperior corrosion properties and yield strength. Thisgenerally requires the use of nickel based aiioys suchas Incoloy 925 or Inconel 718. These materials alsoshow improved resist~ce to erosion.For secondary pressure containment components ofthis well design, such as the production casing theuse of low alloy steel is recommended. Sour servicegrade lTJ5 is considered preferable for any low aiioymaterial near surface, whilst P11O is consideredsuitable at the higher temperatures found deeper inthe weii. Any P11O selected will be specitled with amaximum tensile strength restriction to exclude thehardest material most susceptible to suiphide stresscracking. Alternatively, the use of 110 WI yieldproprietary sour service grades of low alloy steelmay be preferred in place of either.

Annuius FiuidsThe choice ofconsiderationthis depth and

annuius fluid is normaliv a secondarvin completion desi~ but for wells ofpressure it has a significant influence

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OTC 6992 GOMERSAL~ SARDAR AND RAE 3on the overall design and needs to be consideredfrom the outset.

Conventionally the completion would be designed forkill weight fluid in the annulus under worst caseconditions, and a MI weight fluid would be left inthe anm,dus during completion and subsequentworkovers. The present case requires a kill weight inexcess of 16.9 ppg. In addh.ion to requiriig heavyweight production casing and tubing for this weightof fluid there are a number of problems anduncertainties

Solids basedpotential for

High density

associated with the avail~ble fluids.

muds are discounted becausesolids settling over a period of

zinc bromide based clear brines,

of thetime.

thoughavailable, are unattractive for the following reasons* High cost for supply, handling and dfiposal.*Concern over the long term corrosion effects on thelow alloy steel production casing and the duplexstainless steel tubing. Duplex stainless steel hasshown a tendency to pit and suffer hydrogenembrittlement in lower weight brines (reference 5).These corrosion mechanisms are expected to beaccelerated at the low fluid PH and relatively hightemperatures of this design.* Incompatibtity with certain polymeric materials,notably those used as iiig on some flexible hosesand some elastomeric seals on surface equipment.* Concern over the safety and environmental aspectsrelated to brine handling and disposal.

Proprietary high density brominated hydrocarbonsare discounted on the basis of cost, concerns overcompatibility with H2S and high viscosity at ambienttemperatures.

Once a well is on production there appears to be nobenefit of having kill weight in the anmdus. Itcannot be regarded as a reliable pressure barrier as,in the event of a tubing leak, it is expected to U-tube from the ammlus until pressures are equalised.Undoubtedly, clean ~ weight fluids are required inthe well during certain completion and workoveroperations but there is a practical option to leavenon-kill weight fluid in the anmdus at the end ofsuch operations. This is our preferred approach. Theuse of filtered seawater in this design has theadvantage of being a known fluid avoiding theconcerns which exist with higher density fluids.

Tubular DesignThe tubular design contained in this section is basedon standard design principles utilised for most casingand tubing strings. Ratings for tubular componentshave been calculated using API recommendedformulae. Design requirements have been calculatedbased on the worst case for each string at anyparticular depth. Safety factors have been applied toeach design criteri~ unless indicated otherwise, theseare ; burst 1.25; collapse 1.15 and tension 1.6. Becauseof the nature of these design methods the stresslevels in the casing or tubiig during periods ofhydrocarbon production will be low. This isbeneficial in that low tensile stresses reduce the riskof stress related corrosion failures. Figure 3 showsthe proposed well completion schematic.

a) Production CasingThe critical condition for the production casing isburst when the annulus is exposed to maximum shut-in tubing head pressure on top of a full column ofkill weight fluid. In this well the 7-5/8 casing hasbeen designed to withstand this pressure although itis recommended that at completion a non kill weightfluid is left in the anmdus. Furthermore, the casingburst design has been based on a back-up fluidgradient outside the casing of 8.6 ppg seawater. Sincethe casing will be cemented or will have kill weightdrilling mud externally this represents a significantoverdesign. Because of these two factors it should begenerally considered acceptable to reduce the Safetyfactor on this string. Figure 2 shows the burstrequirement with a safety factor of 1.0 whilst thetubulars selected for this well actually have a safetyfactor of 1.25.

The other considerations which affect the design ofthis production casing string are the internaldiameter required and the material grade chosen. Amaximum internal diameter is required to allowaccess for the downhole safety valve and to interfacewith the subsea tree and tubing hanger. Since thereservoir is to drilled with another hole sectionbelow the 7-5/8 production liner the throughboreshould allow passage of a 6 bit. The grade ofmaterial chosen is a compromise betweenrequirements. The use of 95,OOO psi yield T95 ispreferred where possible as a low cost, low alloymaterial suitable for sour service conditions. The useof proprietary 110 l& yield low alloy sour servicegrade or corrosion resistant alloy may be acceptablein order to increase ID in critical areas, and the useof other low alloy material, such as P11O, is suitabledeep in the well where hydrogen embrittlement isreduced because the temperatures exceed 175 deg F.

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4 DH & SUBSEA COMPLETION DESIGN FOR A HIGH PRESSU~ NORTH SEA GAS CONDENSATE FIELD OTC 6992The design calculated for this well uses acombination string of 7-5/8 casing selected to meetthe above criteria and is detailed in table 2 andshown in figure 3. Figure 2 shows the casing designgraph for the 7-5/8 casing.

b) LinerThe 5 liner design is based on a worst case burstwhen the well is being bullheaded with kill fluidand, 2@MJ psi tubing head pressure giving a burstrequirement of 8,904 psi. The worst case collapseconsiders formation pressure acting on the outside ofthe liner and dry gas internally with zero tubinghead pressure giving a collapse requirement of 11,764psi. Both criteria are satisfied with a string of 5 18lb/ft duplex stainless steel with a design yield of120,000 psi at 280 deg F.

c) TubingThe tubing design is based around a 4-1/2 stringselected as being the maximum size possibleconsidering the constraint of casing ID and the borethrough any dual bore subsea tubing hanger. A stringof 4-1/2 15.1 lb/ft, 120,000 psi duplex stainless steelis required to meet the maximum burst of 12,600 psiat surface and the maximum collapse of 11,113 psi atthe packer. It is calculated, using the Salemacorrelation, that gas rates of 100 mmscfd could beproduced through the tubing before erosionalvelocity becomes a concern. Operational experienceusing similar materials has shown no problems at thesame flow velocities.

Downhole Completion Components

a) Liner Top Completion EquipmentThe reservoir section in this well is to be cased with5 liner. It was decided not to complete the wellinside the 5 liner (4.276 ID) due to the restrictedthroughbore in the completion equipment. A 7-5/8packer has been selected to isolate the 5 x 7-5/8liner lap. This packer includes a locator sealassembly which stabs into the Y liner top and a sealbore extension into which the completion tubing issealed. The packer is set in the 7-5/8 liner and ismade from Inconel 718, because it is exposed toproduced fluids. The burst and collapse requirementsare the same as those of the tubing at that depth andequipment should be specified having comparableparameters (15,700 psi burst, 15,300 psi collapse). Theelastomers selected for use on the dynamic seal

104

assembly should be suitable for the high pressuresand temperatures expected and should be compatiblewith the produced fluids and annulus fluids.Perflouro elastomers containing glass fibrereinforcement have been found to be suitable inSimiiar environments. The fibres help preventexplosive decompression which can be a problem inthese materials.

b) Surface Controlled Subsurface Safety ValveScssvPrevious operating experience indkates thatstatistically, the most reliable SCSSV type is a tubingretrievable valve with flapper closure. It isrecommended that this type of valve be fittedincorporating a lock open and wireliie insert valvefacility for use in the event of failure. The materialwill be Inconel 718 or equivalent with burst andcollapse ratings of at least 15,000 psi. The flapperdifferential pressure rating must be in excess of10,tXXlpsi and should preferably be rated to 1.5,000psi. The valve is required to fit inside 7-5/8 casingwith an ID of 6.435 and to maintain a maximumthroughbore which should ideally be close to that ofthe 4-1/2 tubing (3.826). Sinceno 4-1/2 SCSSVS availablerequirements, a 3-1/2 valve has2.81 ID.

there are currentlywhich meet thesebeen spetiled with

The equalkation of pressure across the flapper ismore problematic than in lower pressure wells.Through flapper equalisation devices are likely topresent problems in high pressure wells because ofthe length of time taken to equahse and the potentialfor hydrate formation. Equalizing the valve bysupplying pressure from above will be dfllcultbecause of the high pressures required and thecompressibtity of gas. Further consideration shouldbe given to equalizing mechanisms and larger SiZEvalves should be developed to suit the aboverequirements

c) Landing Nipples and PlugsLanding nipples, in wells such as this, are likely to besubject to scale build up over a period of time. Forthis reason, only two nipples have been included. Alanding nipple in a sub just above the SCSSV, andone landing nipple above the packer locator. If adeep isolation plug could not be set due to scale, anelectric line bridge plug could be set in the tubiiwhich would be recovered along with the completionduring the subsequentprofdes should be topsequence, to provide

workover. The two nippleno-go and bottom no-go inminimum restriction with

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OTC 6992 GOMEW SARDAR AND RAE 5different seal bore sizes. The material will be ofInconel 718 or equivalent, with burst and collapseratings equivalent to the tubing. The sizes selectedare 2.81 and 2.75 to suit the downhole safety valveavailable.

d) Downhoie GaugesPrevious experience of downhole gauges indicatesthat the information which can be gained isextremely valuable and the cost of wirelineintervention in a subsea well to obtain the data isprohibitive. The use of downhole gauges is thereforerecommended. The technology required for the highpressure gauge itself is under development and theprimary problem expected is with the signaltransmission to surface. Using a traditional signalcable presents problems in the physical clearanceavailable between tub~ and casing especially at thedownhole safety valve.

QPERATIONAL ASPECTS

a) Tubing MovementTwo options were considered to compensate forchanges in tubing length during various operations.A static arrangement with the tubing latched to thepacker was rejected due to high stress levels nearsurface, and the operationrd ~lculties installingand retrieving such an installation, A dynamicarrangement allowing tubing movement was selectedin preference. This includes a downward facing sealbore hung from a packer with seais stabbed inside, inwhat is a standard well configuration. Tub~movement due to changes in pressure andtemperature were evaluated for various operationalconditions. The results indicate that the maximumtubing movement occurs during kill operations andis due to the differential pressure between tubingand anmdus, and to temperature changes. The designmust allow for a maximum travel of 33 ft so a sealbore extension of 40 ft should be suft.icient for thisdesign.

b) PerforatingThree options were considered for perforating thewell.

a) Tubing conveyed guns set on a packer anddropped into the rat-hole after perforatingunderbakmce.

105

b) Wireline retrievable guns.c) Drillpipe conveyed TCPS run prior tocompleting the well and perforatedoverbalance.

The chosen method is a compromise between theoPtimm perforation performance and operation~practicrdities. wiie~e retrievable guns are limitedin size and therefore penetration and would requireseveral runs using 15,000 psi pressure controlequipment. Operational disadvantages exist with theuse of tubing conveyed guns hung in the well priorto ~nning the completion. Concerns exist over thereliabfity of fuing mechanisms and automaticrelease systems, the failure of which may necessitatethe removal of the completion to recover the guns. Ifguns are to be dropped in the well then extra rat-holeis required and if guns remain in place they presenta flow restriction and prevent production logging.Perforating with minimal overbalance using TCPSconveyed on drillpipe prior to running thecompletion presents several operational advantages.* The gUUS are run, fired and re~vered ~ oneoperation allowing confirmation that ail shots havefwed. If any problems occur it is relativelystraightforward to recover and re-run the guns.* Large charges can be used to increase penetration.* Pressure control is by means of a provenoverbalance hydrostatic (with surface BOPs in placefor use if necessary) and not by means of wirelinepressure control equipment,* No restriction remains in place in the well and noextra rat-hole is required.

Research indicates that almost all formation damagecaused by overbalance perforating on high pressurewells can be cleaned up by subsequent flow(reference 8). Operational experience using thetechnique on gas condensate wells supports this workand is therefore recommended for this design.

Subsequent completion operations r quirconsideration of the open perforations, which is thesame as in the workover condition. Since non-killweight fluid is to be left in the annulus a means ofisolating the perforations is required. This designproposes the use of a plug run with the packer andtailpipe, which is sheared out with pressure afterseawater has been circulated into the annulus andpressure testing completed. The plug which is shearpinned to the tailpipe, provides a presswe bmrierwhilst the tubing is installed.

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6 DH & SUBSEA COMPLETION DESIGN FOR A HIGH PRESSUI@ NORTH SEA GAS CONDENSATE FIELD OTC 6992c) Pressure TestingAil tubuiars and completion equipment sho~d bepressure tested prior to production. Testing shouldtake place in sequence to ensure that a minimumamount of equipment retrieval is required in theevent of failure. Care should be taken that, in testingany one section, no other area is subjected to apressure in excess of its test pressure. In generai, anypressure test should be performed such that theexposed area is tested to the worst case pressure thatmay be seen in service.

The design of subsea production systems hastypically been with a pressure rating of 5,000 psi or10,04)0psi. No previous experience exists with the useof 15,000 psi subsea production equipment or relatedinfrastructure. However signMcant experience canbe drawn from other areas of industry activity, mostespecially 15,000 psi rated subsea drilling equipmentand 15,000 psi rated surface production equipment.These related areas will allow the development of15,000 psi subsea completion equipment suitable forthis development with only minimal equipmentredesign. The philosophy and equipment required todevelop a high pressure, subsea infrastructureremains less certain and areas requiriig signifkantattention are highlighted in this paper.

Subsea Completion

a) Design Studies

Equipment

Of the equipment required for the subsea completionof this well only the wellhead is available. Severalequipment manufacturers have developed, tested andinstalled subsea wellhead systems with a pressurerating of 15,000 psi. In order to aiiow production offields of this type it was identified that signifkantdevelopment of the remaining subsea completionequipment was required. As a result, separate studieswere initiated with two subsea equipment suppliersto assess the feasibfity of such a system and to makeproposals as to the design, bore sizes, bore offsets andoverall layout, The results of these two studies arepresented in this section. Both manufacturers wereasked to consider all necessary equipment required tocomplete a weii subsea. This was to include wellhead,tubing hanger, subsea tree, lower riser package,emergency disconnect package, riser system andsurface tree. The design basis was as detailed earlierin this paper utilisiig a 7-5/8 production casingstring. Wherever possible full use was to be made ofproven components and the completion was to be

designed with the maximum possible throughbore. Adual bore system was specified utilisii a 2 rnmuiusbore with access into the tubing hanger, but notbelow. The equipment was to be clad or constructedfrom solid corrosion resistant alloys suitable for theproduced fluid expected. Both manufacturers hadpreviously built 10,000 psi subsea completions andthis study was seen as a logical extension to thatwork. The wellhead tubing hanger and tree stack upsfrom both studies are shown in figures 5 and 6.b) Weiihead / Tubing HangerThe critical areas for the design were bore spacingand size especially in the vicinity of the tubinghanger. The constraint of the ID tilde the 7-5/8casing limited the production bore offset andprevented a 4 throughbore. Further investigationand discussion resulted in the use of a special casingcrossover at the top of the 7-5/8 casing string withlocally increased internal diameter (figure 4) . l%iscrossover is compatible in OD with a 7-5/8 coupling(8.235) and has an ID of 6.935 whilst maintainingthe necessmy burst and collapse ratings by utiiisiiga 120,000 psi yield material. The use of this crossoverin both studies enabled the production bore to beoffset by a further 1/4 ailowing the use of a 4nominal bore. The resulting bore sizes, spacings andoffsets are shown in table 3.

Both companies proposed the use of their own 15,000psi subsea wellhead systems for drilling andcompleting the well. Tubing hangers were developedwhich seal inside the 7-5/8 casing hanger and lockdown into the 18-3/4 wellhead housing. Significantdevelopment is required in the area of the tubinghanger, most spec~lcaiiy in the sealing technolo~-for the tubing hanger nose seals and the tubinghanger to tree stab seals.For this well the downhole safety valve operatingpressure will be less than 15,000 psi. Should the shut-in tubing head pressure, on other wells, approach15,000 psi then it may be necessary to uprate thetubing hanger to 17,500 psi to take the necessarycontrol line pressure in the event of a control lineleak. This has implications on the pressure rating ofthe weiihead system and is discussed further in thesection on the control system.

Since the 7-5/8 casing anmdus is a closed volumefrom the 7-5/8 liner tieback to surface,consideration must be given to a means for bleedingoff pressure which will build up due to thermaleffects (reference 11). On lower pressure subsea wellsprovision is normally made by allowing the pressure

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OTC 6992 GOME- SARDAR AND RAE 7to leak off to the formation at the casing shoe. Thisis not possible in this well as the 7-5/8 productioncasing is tied into the 7-5/8 liner top. Possibleoptions include cementing the 7-5/8 tieback tosurface, perforating the 9-5/8 casing orincorporating a monitoring and bleed facility intothe subsea wellhead and tree. This issue requiresfurther evaluation and discussion.

c) 15,000 psi Subsea TreeTree connectors are either existing 18-3/4 15,000 psiddhg connectors or such connectors rno~led totake into account the reduced loading of theproduction system. Similarly, connectors on the lowerriser package (LRP) and emergency disconnectpackage (EDP) are 13-5/8 L5,W psi connectorssimilar to existing field proven utits.

Both vendors have valve designs for the 4-I/1615,000 psi and 2-1/16 15,000 psi valves butoperational experience is extremely limited. Inparticular, it is liiely that the larger valve will haveto be built in the subsea production configurationwith an actuator, and prototype tested, to suitablepressures and temperatures, prior to it being used ~any application. Actuators were specitied to operatewith 3,000 rather than the more typical 15,OOOpsi.

d) Workover and Riser SystemThe workover and riser system components are verysimilar to existing equipment, the primary differencebeing those issues already &cusse@ 13-5/8 15,000psi connectors and 15,000 psi rated valving.Development of an integral riser joint is required inorder to allow the use of a completion riser system inplace of dual tubing strings. Preliminary risertdysk has been performed in order to identib therequired top tension and stress j obt de~. oneinteresting point to emerge from the studies is thatthe bending stresses associated with a 4 x 2 L5 0 0 0psi system are not si@lcantly greater than thoseassociated with existing 5 x 2 10,000 psi systems,

e) Study ConclusionsThe feasibfity of a 4 x 2 J5,000 psi system tointerface With 7-5/8 casing has been proven. Thishas been done using conservative analysis of criticalareas and in most instances the equipment is verysimilar to existing field proven units. The componentsizes and weights are not significantly different toexisting units at 10,000 psi working pressure. Furtherdevelopment work is now required in only a few

107

specitic areas tubing hanger nose seal and stab seal,4-1/16 15,000 psi valve and actuator prototypetesting and the development of an integralcompletion riser joint.

Chokes

A detailed study of the choke requirements for useon this high pressure, subsea development has notbeen undertaken. If the development were a singlewell unit with a dedicated flowline then possibly nochoke would be required. However some of the issueswhich would require attention, should a de~lon bemade to use subsea chokes, and the status of existingequipment are presented here.Because of the large pressure drop the choke will berequired to take, it may be preferable to design thesystem with two chokes in series in place of one. Thecontrol aspects of this arrangement could be complexespecially if the chokes are close together. Onealternative is a high pressure multistage choke whichcould be designed to accept large pressure drops. hydesign will probably have to cater for signilkantdifferences in flow rate and pressure over the fieldlife.

The subsea choke is best located as close as possibleto the wing valve on the tree so as to minimise theuse of the wing valve as a flow control device. Thismay force the use of subsea chokes on all highpressure subsea wells. The use of a single subseachoke on each well to control commingled wells intoa high pressure flowline with a single surface chokecould be a way of compromising on the number ofchokesfactorchokessection

subsea. The flowline pr&sure rating is a keyin the selection and placement of subseaand this issue is discussed further in theon flowlines.

The design and operation of subsea chokes for use onhigh pressure wells, places the choke in the mostcomplex of design areas. High reliability is requiredto avoid the need for repair or change out, maximumflexibility is required to allow change out (should itbe necessary) and high integrity is required toperform at high pressures and rates with largepressure drops over a wide temperature range.Chokes suitable for all these conditions do not exist,as yet, although development work is being pursuedon various aspects, including high rate, high press~edrop equipment. 15,000 psi surface chokes have beenbuilt previously for several projects with typicaldesign conditions of around 50 mmscfd gas flow ratewith 8,000 psi pressure drop. Other developmentshave required the use of chokes at higher gas flow

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8 DH & SUBSEA COMlW13TION DESIGN FOR A HIGH PRESSUREj NORTH SEA GAS CONDENSATE FIELD OTC 6992rates (up to 150 mmscfd) but with much lowerpressure drops (~500 psi). The current use of chokeson subsea developments is limited to low pressuredevelopments close to 5,000 psi.

The temperature rating of all equipment must besuitable for the wide range of temperatures whichmay be encountered. High temperatures may occurwith high flow rates and fully open choke conditionswhilst very low temperatures (as low as -123 deg C)have been calculated with choked flow conditions(references 6,10). If these temperatures proverealistic then they will present problems withmaterial selection since low alloy steels will beunsuitable. It is expected that facilities will berequired for injection of hydrate inhibitors bothupstream and downstream of the choke.

Control SystemThe control system arrangement for a high pressuredevelopment need not be significantly different tothat for other subsea projects, It is likely that subseatree valves would be actuated with an operatingpressure of 3,000 psi. The use of standard downholesafety valve technology would require a very highpressure (VHP) control supply, usually about 2,000psi above the shut-in tubing head pressure, a total of12@0 psi in this case. It is this supply which willcause the major dtierences, and therefore problemsin a VHP control system. The generation, storage andtransmission of these very high pressures from aremote control centre or their generation subseausing pressure intensifiers represents a significantdeparture from existing experience.

One alternative to these VHP systems does, howeverexist. That is the use of downhole safety valvesoperating on lower control line pressures (iepressures below the shut-in tubing head pressure)utilidng dome charge or balance line technology.These valves, which are under development, are themost likely way forward for high pressureapplications since their use eliminates the entireneed for a VHP control system.

Selection and specification of the control fluidpresents problems for the proposed duty. Water basedcontrol fluids currently in use lose their lubricatingproperties and stabtity at high temperatures andpressures. For the temperatures anticipated in thisdevelopment this ishigher temperaturesbased control fluidsnot considered a problem but atthe development of new wateris required..

FlowlinesThe detailed flowline design for this developmenthas not yet been performed but several design issuesare presented here. Due to the nature of theproduced fluids, the flowliue will probably need tobe a low alloy carbon steel outer pipe lined with acorrosion resistant alloy. The outer pipe will bedesigned to withstand all imposed stresses due tointernal pressure, thermal length changes and endeffects whilst the tiner would act as a corrosionbarrier (reference 7). The alternatives, which arelikely to be less attractive are the use of solid CRAflowlines (high cost) or flexible flowlines (tiltedpressure and temperature rating).Subsea flowlines are normally rated in excess of themaximum shut-in tubing head pressure in order to becapable of taking full well pressure should theflowline be shut in at the production facility but notshut-in subsea. It is likely that this will continue tobe the case for high pressure developments where theflowline would have to be rated to 15,000 psi. Thealternative, which is to utilise a low pressureflowline, is more problematic due to the dit%cultieswhich would be encountered designing a reliableflowline overpressure protection system subsea. Oneinteresting point is that in designing non flexibleflowlines the major design stress is usually axialloading associated with thermal effects, while radial/ tangential stresses will be much closer inmagnitude. In a high pressure flowline it is likelythat the axial stresses and the radial / tangentialstresses will be much closer in magnitude, resultingin a more efticient design. Although flowiines arelikely to be reasonably small in diameter (possibly 6or 8) the increased wall thickness and internallining will make reeling more dfilcult. However,because of the internal lining and the increased costsassociated with offshore make-up it is preferable tohave the flowline made-up onshore. The use of themid-depth tow method of installation may be oneway around such problems. An analysis of highpressure condensate flow through pipelines,including flow regimes, flow correlations, thermaleffects and the formation of hydrates is, of course,the basis of any flowline design.

1. The technology and equipment required for thedownhole completion of a high pressure subsea wellis available and reasonably well proven. Detailedoperational procedures require to be developed.

2. A single liner top and completion packer set in the7-5/8 casing and stabbed into the 5 liner top should

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OTC 6992 GOMEW SARDARANDRAE 9be used to isolate the annulus from produced fluidsand accept any tubing movement.

3. In service stress levels in all tubulars are low as aresult of the design methodology. This serves tominimise concerns over stress related corrosionmechanisms.

4. The reservoir should be perforated using drill pipeconveyed TCPS with overbalance prior to runningthe completion.

5. The well should beinhibited seawater as the completed with falteredannulus packer fluid.

6. The way in which pressure trapped in the 7-5/8by 9-5/8 amu,dus is monitored or bled down requiresfurther consideration.7. Significant development of 15,000 psi actuatedchokes for subsea application is required prior to anypossible installation.

8. The use of a downhole safety valve operated atpressures lower than the maximum shut-in tub~head pressure avoids the need for a very highpressure control system. Such valves are currentlyunder development,

9. The feasibility of a 4 x 2 15,000 psi subseacompletion has been proven, however equipmentdevelopment is required in various areas prior to anypossible installations. These are: development andtesting of tubing hanger nose and stab seals,prototype testing of 4-1/16 15,0410 psi valve andactuator, and development of 15,000 psi completionriser connectors.ACKNOWLEDGEMENTSThe views expressed in this paper are solely those ofthe authors and do not necessarily reflect the viewsof Marathon Oil UKfields.

The authors wish totheir partners; BritoilBow Valley Petroleum

or their partners in the Brae

thank Marathon Oil UK andplq Kerr-McGee Oil (UK) plq(UK) Lt~ L.L.& E. (UK) InqBritish Gas Exploration and Production Ltd,Sovereign Od & Gas plc and British-BorneoPetroleum Syndicate plc for permission to publishthis paper.

109

REFERENCES1. A Review of Completion Technology forOffshore Deep HP/HT Hostile Gas CondensateWells. Prepared by Heriott Watt Petroleum Eng.Dept. on a brief from the Petroleum Science andTechnology Institute and sponsored by Ranger Oil(UK) Ltd and Ultramar Exploration Ltd.2. CSON 59. Applications for Consent to Drill or re-enter high pressure, High bottom hole temperatureexploration and appraisal wells : Supplementaryinformation to be supplied in addition to thatrequired by CSON II. Dept of Energy. May 19903. S.Gomersall. Production Technology for SubseaDevelopment Wells. SUBTECH 91, Aberdeen, 12th -14th November 19914. R.R.Schulq D.E.Stelde, J.Murall.Completion of aDeep, Hot, Corrosive East Texas Gas Well, SPEProduction Engineering. May 19885. S.Gomersall, E.Wade. Operational Experiencewith Corrosion Resistant Alloys in BraeCompletions SPE Seminar, Aberdeen. 18th April19916. A.C. Baker, M.Price , Modelling the Performanceof High Pressure, High Temperature Wells. SPE20903, The Hague, 22nd - 24th October 1990.7. R.Kane, S.M.Wilhetrn, T.Yoshida, S Matsui, T.Iwase Analysis of Bimetallic Pipe for Sour Service.SPE Production Engineerin~ August 19918.T.E.Bundy, M.J.Elmer Perforating a High PressureGas Well Overbalanced in Mud : Is it Really ThatBad? SPE Production Engineering February 19909. M.Celant, T.Cheldi, D.Condanni. ControllingCorrosion in Deep, Hot, Sour Wells for OilProduction NACE - Corrosion Europe 89, Milan,14th - 17th November 198910. J.M.Prieur Control Aspects of Drilling HighPressure Wells. SPE 19245, Offshore Europe 89,Aberdeen, 5th - 8th September 198911. AAdams. How to Design for Anmdus FluidHeat Up. SPE 22871, Dallas, 6th - 9th October, 199112 G.G.Huntoon. Completion Practices in Deep SourTuscaloosa Wells. Journal of Petroleum Technology,January 198413. W.H.Stone. A Completion MethodPressure, Corrosive, Offshore Gas WellsYHouston, 4th - 7th May, 1981

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1 DH & SUBSEA COMPLETION DESIGN FOR A HIGH PRESSU~ NORTH SEA GAS CONDENSATE FIELD OTC 6992Table 1 : Desicm ConditionsReservoir Pressure (psi)Reservoir Temperature (deg 1?)Reservoir Depth (ft;tvdss)Kill Weight Fiuid (ppg)Maximum Shut-in THP (psi)Maximum THPwith bullhead allowance (psi)Maximum Surface Temperature (deg F)Maximum H28 (mol ppm)H2S Partial Pressure (psi)Maximum C02 (mol %)C02 PartiaI Pressure (psi)

13 30028415,70016.910,60012 5002451001.33101,330

~Depth intervai Grade Weightft) iblft) in:

1,000 110 ksi 45,3 6.435l@O - 8JO0 T95 55.3 6S258,500 -1.5,000 Pllo 55+3 6.125

* Either 110 ksi yield propriet~ grade low doysteel or 110 Ml corrosion resistant alloy such asduplex stainless steel. The higher yield material isrequired in order to i n re se t he ID for the downholesafety valve and subsea production equipment.

Tabie 3:15.000 Dsi Subsea ComRietion Bore S~acingVendor A Vendor BAnmdus Bore Size 2-1/16 2-1/16Production Bore Size 4-1/16 4-1/16Bore Centres 5.250 5.000Production Bore Offset 0.960 0.938

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