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SPE 30364

HPHT Drilling and Completion Design for the Erskine FieldSociety of Petroleum Engineers

G.S.Elliott SPE, R.A.Brockman, Texaco North Sea UK Co, R.M.Shivers III, SPE, Texaco Limited.Cop'yright 1995, society of Petroleum Engineers , Inc.Thi s p ap er was p re pa re d f o r presenta t ion a t Offshore Europe 95 heldin Aberdeen 5- 8 September 1995.This paper was selected fo r presentation by an SPE Program C o m m ~ t t e efo l lowing rev iew of t he i n fo rmat ion con ta ine d in an abs t rac t submlt tedby th e author(s). Contents of the paper, presented, have ,not beenreviewed by th e S oc iet y of petroleum Englne er s and ar e subJected tocorrect ion by t he a u th o r( s} . The material , as presented, does notnecessarily r e f lec t any posi t ion of the soc ie ty of PetroleumEngineers i t s o ff ic er s, o r members. Papers presented a t SPE meetingsare subje'ct t o p u bl ic at io n review by Editorial conunittees of thesociety of petroleum Engineers. Permiss ion to copy i s r es tr ic te d toan abst ract of not more than 300 words. I l lust ra t ions may no t becopied The abst ract should contain conspicuous acknowledgement ofwhere by whom t h e paper was p res en ted . wr i te L ibra ri a n, SPE, P.O.Box 833836, Richardson, Tx 75083-3836, U.S.A., fax 01-214-952"9435 .

AbstractThis paper summarises the factors influencing the welldesign for a high pressure high temperature (HPHT)* fielddevelopment using a Not Normally Manned Installation(NNMI) in the UK sector of the Central North Sea (CNS).IntroductionThe Erskine gas condensate field is a 50% Texaco / 50% BPventure and will be the first HPHT field developed in theNorth Sea with frrst gas scheduled for 1997 (Fig. 1). Thefield development concept is to install a not normallymanned installation (NNMI) with multiphase export ofproduced fluids to the Lomond platform from six platformwells. Drilling and completion operations will be carried outusing a harsh environment jack-up rig in cantilever mode.Primary functional requirements for the wells include highreliability, high productivity and the ability to performthrough tubing plug-backs. Reserves in the core area arefound in three separate but generally overlying Jurassicsandstone producing horizons, the Kimmeridge, Erskine, andPentland sands.A multi-discipline project team consisting of reservoir,production, drilling and facilities engineers was set up toprogress the development concept. Specific well designprinciples were adopted and an iterative approach was usedto produce a robust and reliable drilling and completiondesign that is compatible with the overall developmentconcept and provides reliability on a NNMI in HPHT serviceconditions.Jackup drilling will commence over the platform jacketwhich will be installed over an existing sub-sea appraisal 103

well in the spring of 1996 (Fig.2). Two wells will bepredrilled through the jacket structure and suspended prior tothe platform topsides deck being lifted into place in 1997.The appraisal well will be tied back and wells will then becompleted ready for commercial gas export in late 1997.Further wells will then be drilled and completed as required.*Defined by United Kingdom Continental ShelfOperations Notice as anywell where the undisturbed bottom hole temperature is 300F or greater andeither the pore pressure exceedr 0.8 psilft or pressure control equipmentgreater than 10, 000 psi rated working pressure is required.PlatfOl'm Concept OutlineBy North Sea standards Erskine is a marginal field (335MMSCF gas, 66.5 MMBBL oil). The resultant developmenthas revolved around this in order to make developmenteconomic. The following lists the main features of thedevelopment.1) Simple NNMI 12 slot wellhead platform providingunprocessed multiphase fluids export to host platformwith a projected field life of 15-20 years.

2) Platform design and slot layout which enables access toall slots for cantilevered jack-up drilling in the 300 ftwater depth.Well Design ConsiderationsPrimary considerations for the well design are:1) Reservoir fluids containing H2S and CO 2, Reservoirpressure +/-14.,000 psi, temperature 350Op, initial surfaceshut-in pressure 10,600 psi (Table 1).

2) Design flow rates required from each well will be up to60 mmscf/day of gas.

3) The wells that are initially completed as Pentland sandproducers will water out and require to be plugged backand re-completed as Erskine sand producers. Due toavailability and cost of large jack-up rigs, this requires tobe a rig-less operation.

4) Possible future production enhancement with fracturing /

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2 HPHT DRILLING AND COMPLETION DESIGN FOR THE ERSKINE FffiLD .SPE 303M

laterals.5) Wells must be reliable because of:

a) limited rig availability and high rig cost.b) NNMI concept allowing very limited personnel accesswithout support vessels.c) platform maintenance, inspection andwell interventiononly being planned for once yearly.

6) Well and drilling programme features to minimise wellcosts.

Well Design Primary FeaturesPrimary well design features to meet these requirements are:1) Monobore completion for reliable through tubing plug.backs..

2) Polished Bore Receptacles (PBR) instead of packers.3) Corrosion Resistant Alloys (CRA) for all flow wettedsurfaces.

5) Standard, field provenmaterials and technology wheneverpossible.6) Use of API bit sizes which are common in the North Sea

if necessary at the expense of non-standard casing sizes.Completion DesignThe requirement for through tubing plug backs, highproduction rates, and wellbore reliability drove the proposedcompletion design. The completion design (Fig.3) is basedon a PBR. It consists of a seal mandrel run on 4.112" CRAtubing with a full bore tubing retrievable surface controlledsubsurface safety valve (TRSCSSSV). Landing nipple ID'shave been selected to allow through tubing plug backs usingcast iron bridge plugs (CIBP). The production string will berun in a non killweight packer fluid prior to perforation ofthe wells on wireline.Tubing Design. A 4.112" tubing string satisfies both theproduction requirements and provides a workable overallwell design. Nodal analysis indicated that 3.1/2" tubingwould not achieve the required production rates of 60mmscf/d. 5.112" tubing would provide a modest increase inflow capacity, but would greatly increase the cost andcomplexity of the casing programme. It would cause thePentland wells to water out prematurely due to the effect ofhigh liquid loadings in the tubing. Even with high flow ratesthe number of wells could not be reduced due to reservoirrecovery considerations.The production string will consist of 4.112" x 0.320" WT, 104

130 ksi tubing below the safety valve with 5" x 0.400" WT,130 ksi tubing above to accommodate wireline insert safetyvalve installation.The tubing has been designed for burst loads based on initialshutin wellhead pressures of 10,600 psi and flowingwellhead temperatures of 325 deg F. The collapse load hasbeen based on minimum bottom hole pressure with a 18.0ppg packer fluid. Triaxial analysis has been performed toconfirm the tubing design together with tubing movementcalculations for various operational load cases.Metallurgy. The combination of high temperatures, CO 2 andH2S partial pressures, formation water salinity, andmultiphase flow requires the use of CRA materials for thetubing and production liner to ensure reliable corrosioncontrol (Table.l). A 28%Cr-31%Ni CRA has been selectedas the base case material with a yield strength of 130 ksiwhich has been derated for use at elevated temperatures(0.85) and for material anisotropy (0.9)1 (Fig 4).Environmental testing of 13%Cr, "Super" 13%Cr and duplexstainless steels has been conducted in an effort to qualifylower cost materials for the tubing string. Preliminary resultsindicate that 13%Cr and "Super" 13%Cr materials are notsuitable, whereas 25%Cr can be used, but with limitations onthe ability to acidize wells.PBRvs Packer. Isolation of the reservoir from theproduction casing annulus is achieved by use of a PBRsystem. The PBR is installed as an integral part of theproduction liner, directly below the liner hanger with theseal mandrel and stack run with the completion string. APBR style completion was selected over a packer stylecompletion because it provides:1) Simpler workovers (no deep milling operations requiredthat could lead to loss of a platform well).2) Lower tubing stresses.3) Simpler completion design.4) Successful experience in US HPHT wells and recently onthe Strathspey field in the North Sea.

To maximise completion reliability and reduce the chancesof a workover, the seal stack will be maintained in a staticposition during all production operations. Sufficient weightwill be set down together with annulus pressure to preventseal movement during hotproducing and cold shutin periods.The stack is positioned in the PBR to accommodate upwardmovement during well kill operations or stimulationtreatment. Seal stack testing at simulated bottom holeconditions is ongoing to determine the best availableconfiguration.TRSCSSSV. The running of tandem tubing retrievable

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SPE 30364 G.S.ELLIOTI, R.A.BROCKMAN, R.M.SHIVERS III 3

surface controlled subsurface safety valve's was considered.However the increase in the overall completion reliabilityand workover cost benefit was not significant whencompared to the added complexity and increased cost of thecompletion design. Hence a single safety valve with acommunication nipple was selected as the base case. Meantime to failure of the safety valve have been estimated as 20years based on available North Sea data.A single piston non-equalising flapper type valve with allmetal to metal seals will be used. To maintain the throughtubing workover ability a 4.112" full bore safety valve willbe run. The valve is rated to 15,000 psi at an operatingtemperature of 350 deg F. It will be manufactured fromInconel 718 material with a 7.875" aD and a 3.813" bore.Skimming the valve aD to 7.750" at the expense of areduction in working pressure to 14,000 psi is beingconsidered. Fluid velocities across the valve are well below100 ftlsec which should ensure no erosion for sand freeproduction2A separate communication nipple will be run above the valveto allow wireline retrievable subsurface safety valves(WRSSV) to be run should the primary valve faiL Separatecontrol lines will be run for the primary valve and thecommunication nipple. In the event of control line failure tothe primary valve a full tubing workover would not berequired as a WRSSV will be run to maintain production.Packer Fluid Selection. Packer fluid selection has beendriven by:1) Improving tubing workover ability.2) Minimising tubing movement.3) Passive to production tubing and tieback materials.4) Cost effectiveness.On unperforated wells the completion string will be run in11.3 ppg calcium chloride brine giving an initial pressuredifferential across the seal stack of 5,500 psi. Seawater hasbeen disregarded as a suitable fluid due to the highdifferential pressure and excessive tubing movementoccurring during production operations for a small reductionin cost. low solubility of oxygen in a saturated calciumchloride brine will ensure that only low general corrosionoccurs.Work is ongoing to try to establish safe, efficient, reliablemeans of completing perforated wells with underbalancedclean packer fluids. If necessary perforated wells will becompleted using kill weight fluids with weights up to 18.0ppg. Pseudo oil based muds will be used for the heavierweight fluids as opposed to zinc bromide and formatebrines.

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Annulus HeatupThis has been analyzed on a global systems basis withvarious well designs. In all cases, pressure build-up in asealed annulus due to thermal expansion from productionconditions results in unacceptable loads on casings. Thiswill be prevented by the following measures.1) Pressure will be bled off from all annuli at the surface

wellhead on initial production start-up.2) For drilling casings below 20" conductor, cement tops

may be left below the previous casing shoe, thusproviding a natural relief valve to the formation.

3) For the tubing to production tieback annulus, pressurewill initially be bled off. In addition, remote pressuremonitoring will be provided on the host platform for thisannulus. In addition application of a pressurised nitrogencushion is being considered for this annulus.

Workover/Intervention PhilosophyWorkovers and well interventions will be minimised by highwell reliability and only carrying out data gathering requiredto maximise hydrocarbon recovery. Major workover andwell interventions will be carried out where possible duringthe summer months. Typical through tubing operations areexpected to be:1) Plug back and re-perforation of 2 Pentland wells asErskine producers.2) Production logging on all wells on a yearly basis.3) Installation of wireline retrievable safety valves.Full tubing workovers are likely to be caused by PBR seal,tubing hanger, tubing or TRSCSSSV failure. It is estimatedthat at least 2 full tubing workovers will be required over thelife of field based on the overall reliability of the completion.Shutin wellhead pressures decline sharply (Fig.5) to allowthrough tubing plug backs to be carried out usingconventional wireline and coiled tubing techniques withthrough tubing CIBP's. The platform has been designed toallow wireline, coiled tubing, and snubbing / hydraulicworkover unit operations. However, logistical support mustbe provided by a bridge linked Mobile Support Vessel. Fulltubing workovers can be conducted at any time by a harshenvironment jackup or a medium size (CEFM 2005-C)jackup in summer. Modular workover rigs can also beutilised by the addition of capping beams to the platformthus enabling full tubing workovers to be accomplishedwithout using a jackup rig.Enhanced RecoveryThe deliverability of the wells completed in the Erskine sanddecline with the sharp drop in reservoir pressure which is acharacteristic of this low permeability reservoir. A number

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4 RPHT DRILLING AND COMPLETION DESIGN FOR THE ERSKINE FIELD SPE 30364

of enhanced recovery techniques have been considered andtheir impact on well design identified.The technical feasibility and design of fracturing theErskineSand to improve recovery has been investigated. Bothtechnology andequipmentexist to enable fracture stimulationto be carried out. However, erosion of production equipmentcaused by proppant flowback over time is a major problemespecially when associated with high flow rates andwellheadpressures. This stimulation technique will not be usedinitially due to the increased risk of equipment failure whichwill impact on the platform reliability and safety.High angle wells have also been considered as a means ofimproving well deliverability. There are however a numberof technical problems that have yet to be solved:1) Limitations of current down hole tools (especiallyslim-hole Measurement While Drilling tools at hightemperatures).2) Bore hole stability in depleted reservoirs limits themaximum hole angle that can be successfully drilled.3) At initial reservoir conditions, fracture gradient decreaseswith increasing hole angle, thus narrowing further themargin between fracture gradient and pore pressure.Studies are ongoing and it is possible that the productionliner design on the two later Erskine sand producers may bemodified to allow a future short radius horizontal sidetrackto be performed within the Erskine sand.Drilling DesignPlatform I Rig Interfaces. The field development planprovides for cantilever Jack-up drilling over the NNMIplatform. Advantages of this are simplified platform designand elimination of skidoff equipment requirements. Thedisadvantage is relative motion of the platform and jacketstructures and possible limits on operability in severeweather. Field data suggests that actual movements will notbe as large as the theoretical movements predicted bystructural analyses. It is estimated that down time due toexcessive relative motion will be limited to 1 year stormconditions or similar. Following selection of the Santa Fe'Monitor' for the development drilling campaign, anoperability study is underway to identify means ofminimising downtime. For example a flex-connect systemis planned to be installed in the riser between the rig andBOP.Other platform rig interfaces include provision and tie-in ofESD, alarms, fire and gas, firewater, kill manifold,navigation lights, power, telecomms / PA, air, water, andaccess bridges. Early selection of the jack-up rig hasallowed the platform design to suit the jack-up to reduce rigmodification cost wherever possible. 106

Lithology / Pressure Regime. Erskine lies in the CentralGraben area of the CNS. The lithology / pore pressure /mud weight diagram is shown in Figure 6. Tertiaryformations extend to approximately 11,500 ftss. Theseformations are primarily normally pressured, but reactiveunstable / overpressured shales of the Eocene age haverequired oilbased mud of 12.5 ppg to maintain good holeconditions.Upper Cretaceous chalk and calcareous limestone thencontinue to around 14,500 ftss. In most of the CNS, LowerCretaceous shales and marls then continue to the LateJurassic Kimmeridge formation which is often overpressureddue to compaction. The pressure transition zone is usuallyover this Lower Cretaceous interval. Most CNS wellstargeted for the Jurassic formation set intermediate casing inthe Lower Cretaceous pressure transition zone. In the corearea of the Erskine field however, the Lower Cretaceous isvirtually absent. This results in a rapid pressure transitiontowards the base of the Upper Cretaceous calcareouslimestone. Intermediate casing has to be set in the base ofthe Upper Cretaceous formation. Although there are usefulformation markers such as the 'Black Limestone Marker',picking this casing point has always been a problematic partof the Erskine appraisal wells. Correct placement of theintermediate casing shoe is essential to ensure sufficientfracture stren,gth to weight up the mud and drill theoverpressured reservoir3The Jurassic, reservoir. sequence consists of Late JurassicKimmeridge formation containing limited Kimmeridgianhydrocarbonbearing sandstones, then MidJurassic sequencesthat contain the Erskine and underlying Pentland sandsequence. Pentland sands are anticipated to exhibit a strongwater drive, whereas the Erskine and Kimmeridgian sandsare depletion drive. Jurassic pore pressure at Erskine rangesfrom ca. 17.8 ppg EMW in the Kimmeridge sands to 17.2ppg EMW in the Pentland sands. Fracture pressure is in therange 18.5 to 20 ppg EMW. Thus there is a very limitedwindow in which to operate allowing for mud ECD's etc.In addition, overbalance of mudweight over pore pressureincreases through the sequence, and mud losses particularlyto the more permeable Pentland sands have caused a drillingliner to be required to reach TD on several appraisal wells.Significant time has been spent controlling influxes andlosses to these formations during appraisal drilling, and thedifferentiation of influxes from kicks and formationballooning has been difficult.Casing Setting Depths. The generic development welldesign is shown in figure 7.

30" Structural Casing provides sufficient formationintegrity to support loads and drill 26" hole for the 20"conductor.20" Conductor is set at 2,500 fiss in order to case offinitial build section and obtain a formation strength in the

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SPE 30364' G.S.ELLIOIT, R.A.BROCKMAN, R.M.smVERS III 5

15-16 ppg EMW range.Suiface Casing is set in the top of the Upper Cretaceous

chalk to case off the unstable shales of the Eocene age andthe penneable Palaeocene sands.Intennediate Casing is set in the pressure transition zone

towards the base of the Upper Cretaceous fonnation asdescribed above.Drilling Liner is contingent to be set during the drilling

of the reservoir sequence if required.Production Liner is set at TD and cases off the reservoir

sands and drilling liner if run.Production Tieback String is cemented in place in thetieback PBR on top of the production liner, and ties back to

surface as the production string.Directional Drilling. Wells will be'S' shaped. This ispossible with quite low tangent angles due to the relativelysmall areal extent of the field. The furthest stepout wellrequires a tangent angle in the region of 35. 'S ' shapedwells enable the well to be vertical from intermediate casingpoint to TD thus eliminating the need for MWD tools in thehighest temperature part of the well. The drillstring will alsobe kept simple in the reservoir section, simplifying wellcontrol and minimising circulating pressure losses.Build rates will be limited to a planned rate of 1.5/l00ftinthe 26" hole and Arnco 200XT or Armacor M drillpipehardbanding will be used in order to minimise casing wear.Well Design Philosophy. The following lists the generalprinciples used in the development of the Erskine welldesign in addition to the considerations for completiondesign previously discussed.1) Use of API bit sizes common in the North Sea hole sizes,

if necessary at the expense of non-standard casing sizes.2) Tapered casing strings to accommodate the TRSCSSSV.3) Allowances made for casing wear, casing yield strengthreduction with temperature (Fig.4) and tri-axial stressanalysis.

4) Specification of 'extreme' and 'expected' load caseswhere appropriate, with differing safety factors for thetwo cases. Lame's casing burst strength equation wasused for uniaxial design calculations rather than APIBarlow equation.

5) Optimisation of running clearances on completion, casingin casing, and casing in open hole. Consideration offishing capabilities of well cleanout strings and tubing.

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6) Provision of one contingency drilling liner for thereservoir interval and acceptance of reaching TD in a6.1/4" equivalent hole size.7) Isolation of the liner lap to remove the risk of liner topleakage from completion with an underbalanced packerfluid.The design considerations specific to each casing string arediscussed in more detail below. This has been laid out inthe order of ascending casing size as well design is primarilydriven by completion design and TD hole size. Table 2shows a summary drilling and production string load criteriaused in the well design.Metallurgy. Due to the casing clearance requirements, it wasdesirable to use high strength sour service casing forintermediate and production string applications. Aqualification testing programme commenced in 1991 andNACE TM0177 method A coupons and full scale casingjoint testing have both taken place. Notable differences wereseen in results from coupons and full scale casing. Fullscale casing qualification testing is preferred because 1) afull scale test sample has an area equal to approximately200,000 coupons thus increasing statistical confidence, 2) theinternal surface of the full scale sample is that which mustprevent initiation of SSC and contains imperfectionsremaining from the manufacturing process. Thesepresumably account for the differences seen in coupon andfull scale results.NACE TM 0175 method A high-end ClOO coupons werefound to have 90% threshold of SMYS in standard NACEsolution, but full scale joints failed this environment at 80%.Low end C90 was used as a control and passed full scaletesting at 90% of SMYS in this environment.Further full scale joint testing took place using a 1.5 psi HzSpartial pressure modified NACEenvironment (conservativeErskine environment). This qualified high end yield strengthClOO at 90% SMYS, a dramatic rise from the testing atNACE environment conditions. Confirmatory ClOO testingis underway, and ClIO sample testing is planned.Selection of surface and drilling casing grades follow NACEMR 0175 temperature and service exposure criterion, usingthe production casing test full scalequalification as the initialreference at surface conditions (Table.3).Thus, for production applications on Erskine ClOO has beenqualified, and ClIO is planned to be used for intermediatecasing in pseudo oil based mud drilling environments.Further testing may also qualify C110 for productionapplications on Erskine4PrOduction Liner. A 4.1/2", 28%Cr-31%Ni production linerwill be used. The corrosive nature of the fluids requires theuse of CRA's and the selection of this material for the

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6 HPIIT DRILLING AND COMPLETION DESIGN FOR THE ERSKINE FIELD sl:>E 30364"

production liner is based on the absolute requirement forlongevity from the liner. This size provides monoborefeatures to the well for ease of plugback with cast ironbridge plugs and simplified workover operations. 3.118"wireline perforating guns can be run for sufficientperforating performance and 2.7/8" cleanout strings can beused.The driving load considered is collapse load of fullundepleted formation pressure externally with depletedproduction pressure at the end of field life internally.Reservoir compaction was calculated, and connections willbe selected to maximise resistance to compression.Zonal isolation is critical when plugging back the Pentlandproducers to Erskine producers after watering out. Thuscementation quality including anti migration properties willbe important.

With the tubingPBR below the liner hanger, hanger andtieback equipment can be of 140 ksi carbon steel at thesetemperatures (+300Op). The hydraulically actuated hangerwill be above the tieback receptacle and hence isolated fromthe production wellbore fluids and pressure. therefore it isdesigned only for hanging loads. The liner lap will be behindthe tieback casing, and thus overbalanced by kill weightmud.Production Tieback String. The production tieback stringis run to provide protection against possible productionloads. Primarily a surface tubing leak at initial shut-inpressure on top of the brine packer fluid with degraded mudbackup was taken as the expected load case. In the extremecase a tubing leak on top of kill weightmud packer fluid hasalso been considered. The intermediate casing provides adegree of redundancy in the event of a breach of theproduction tieback string. This is considered of benefit forthe first HPHT field in the North Sea environment. Otherbenefits provided by the production tieback include isolationof the liner top behind the production casing and eliminationof casing wear concerns on the production string.The tieback's internal size is driven by the completioncomponents. The 15M 4.112" TRCSSSV's available haveOD's in the region of 7.7/8", although it is expected thatErskine valves will be skimmed to 7.3/4" at the expense ofa slight drop in pressure rating. Thus 9.5/8" ClOO sourservice casing provides the required strength capabilities witha 7.95" drift. This provides a minimum running clearance inthe completion brine of 0.2". Increasing this clearance maybe possible ifC110 casing is qualified for Erskine productionconditions.In order to be able to meet the requirement to washover andfish 4.112" tubing with 5" T&C couplings, a 6.3/8" minimumdrift diameter is required below the TRCSSSV. The tiebackcasing selected is therefore 8" ClOO from the TRCSSSV to200F and 7.5/8" Q125 below this to the production liner

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top. Running clearances for the tieback string inside theintermediate string are a minimum of 0.5" on couplings andare around I" on pipe.The tieback string will be tacked in place with cement inorder to prevent tieback seal movement. Followingcementation, it is necessary to pull tension in the productiontieback string to prevent high axial compressive loads fromtemperature deep in the string which could exceed triaxialstress safety factors in the event of a tubing leak duringproduction.Drilling Liner. This will serve the function of a drillingliner only, as the production liner top will straddle andisolate this liner. Thus loads will be limited to losses to theformation for collapse and pressure testing and gasevacuation for extreme burst loads. The liner selected forthis application in 8.112" hole is 7", 23 ppf which providesgood clearance for cementing and allows drilling to TD in6.1/4" hole for the production liner.It is anticipated that this liner will be required on between 2and 4 of the 5 new wells.Intermediate Casing. The setting depth for the intermediatecasing in 12.114" hole is in the pressure transition zone asalready described. This hole section will continue the use ofthe pseudo oilbased mud system to be used for the 17.112"hole. I t is planned that Gamma Ray-Resistivity LWDandVSP's will be used to assist in picking the intermediatecasing point, as there are some identifiable features for.reference in this interval. Following running and cementingof the intermediate casing, the reservoir is drilled in 8.112"/ 6.114" hole to TD of the well through this casing string.Design criteria for this casing string are an 'extreme' burstload defined as gas evacuation to surface from the reservoir.'Expected' load is that of partial gas evacuation. In anyevent sour service casing is required. Collapse loadsconsidered are that of mud level dropping to minimumformation pressure. In addition, the lowermost section of theintermediate casing is designed for production loads as acontingency against failure to land or seal the productiontieback in the liner tieback PBR.In order to accommodate the 9.5/8" casing at the top of thetieback string, and be compatible with a 13.5/8" wellhead /BOP, a 12.1/8", 90 ppf, ClIO, casing with Marubeni ULTconnections was selected for the top of the intermediatecasingS. The remainder ofthe intermediate casing is 10.3/4",73ppf, ClIO down to 200F inside the surface casing, and10", 72ppf, Q125 in 12.114" open hole. The 10" casing hasan 8.112" drift. Clearances for running and cementing thisstring inside the surface casing are a minimum of around I"diameter on the 10.3/4" couplings. This provides acceptablerunning surge pressures and cementing ECD's.Surface Casing. The surface casing string is required to 1)

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SPE 30364 G.S.ELLIOTI, R.A.BROCKMAN, R.M.SHIVERS III 7

case off the Tertiary and Palaeocene sequence, 2)accommodate the 12.118" casing at the top of theintermediate casing, 3) provide a 12.114" drift for drilling tointermediate casing point. Design criteria is based on alimited kick due to knowledge of the area from 8 previousexploration and appraisal wells. Sour service is not requiredfor this string. Losses considered are mudweight dropping tobalance pore pressure. It is planned that 17.112" or 16" openhole will be drilled with a pseudo oil based mud system toinhibit the reactive and unstable Tertiary formation. Surfacecasing will be set in 12.5 ppg mud. The mudweight maythen be reduced for the 12.1/4" hole section to drill theUpper Cretaceous chalk in order to increase penetration rateand assist in detection of the pressure transition zone.A 16" x 13.3/8" tapered casing string has been selected asthe surface casing. 16" will be run inside the 20" conductorand 13.3/8" run below the TRSCSSSV depth and across theopen hole. A modified buttress thread has been selected forthis application on both casing sizes.Conductor . The conductor will be set at 2,500 ftss toprovide a 15+ppg EMW formation strength, and to case offthe build section of the well. 26" hole will be drilled withseawater and viscous sweeps, with returns to the platformdeck elevation. 20", 133 ppf, X56 casing will then be runand cemented. Design criteria are based on kick loadslimited to the 20" shoe formation strength. Due to siting ofthe platform over an existing well and site survey results,shallow gas is considered to be extremely unlikely.Structural Casing. Structural casing is 30" diameter. Preinstalling the jacket allowed omission of a mudlinesuspension system. Full hanging weight of all casings will besupported by the 30"/20" casings. Structural analysisshowed 30" x l" wall, X52 material is suitable for wellsdrilled through the platform jacket. A proviso on this is thatin severe storms it will be necessary to release the jackupfrom the conductorlBOP if relative motion of the twostructures approaches 3 ft. Operations analysis is underwayto determine maximum relative movements that will beallowed for continuing operations. The 30" casing fromseabed to wellhead will be coated with flame sprayedaluminium for corrosion protection.Analysis early in the project planning showed that if wellswere to be drilled from a jackup without the jacket in place,30" structural casing would have required significantredesign from the above sizes.36" hole will be drilled vertically with seawater and viscoussweeps and the 30" casing will be run and cemented.Driving the 30" was discounted due to firm shallowformations and the need to eliminate doglegs and maximisedirectional control.Casing Connections. 30" and 20" use established threadedconnectors. The surface casing uses the Dalmine ATS

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modified buttress thread. Intermediate and smaller casingswill all utilise premium connections.Due to the small annular clearance between some casingstrings, there are requirements for slimline couplings onrelevant casing sizes. For example the 12.118" casing at thetop of the intermediate string has a coupling OD restrictiondue to 13.5/8" wellhead design constraints, however this isalso an area of high tensile loads. The Marubeni ULTconnection was selected due to it's high tensile efficiency,full drift and restricted connection OD features. Connectiondesign also lends itself to this application, being customisedfor specific pipe sizes. Qualification testing is also planned.The remainder of the intermediate string utilisesMannesmann HPC connections.Tieback and production liner connections have not yet beenselected, but similar criteria exist.

WeUheadslXmas TreesThe heavy dutyjack-ups considered for Erskine are generallyequipped with 21.1/4" I 13.5/8" BOP systems. Use of asingle 18.314" 15M BOP was considered to reduce BOPhandling and possibly simplify casing hanger configurationfor the Erskine casing programme. However, the savings donot justify the considerable expense of supply and fitting ofsuch a BOP and handling system for a 6 well development.The wellhead system is designed for the 21.114 5M x 13.5/8"15M BOP configuration and consists of stacked casingspools. Drilling casings will normally be suspended bymandrel hangers with contingency hanger systems will beprovided for all casing strings. Metal to metal seals will beprovided for intermediate and tieback casing strings.Because it is necessary to pull tension in the productiontieback string to prevent high compressive loads deep in thestring during production, a slip and seal is required.As jackup drilling will take place through the platformjacketcasings can be hung at surface and a mudline suspensionsystem is not required.To facilitate safe and efficient BOP I wellhead handling,'quick connect' type connections will be utilised on allwellhead and riser connections that are routinely made upand broken.The tubing hanger will be 11" nominal to facilitate thepossible use of 11" BOP's during future workover or wellintervention that requires only manipulation of the tubing.The x-mas tree will be nominal 4.1116"API 15M to becompatible with the tubing bore, and will be a stacked valveconfiguration to facilitate ease of component valvereplacement. The tree is of split design consisting of a tubingbonnet and upper valve assembly. The upper valve assemblyconsists of a solid block cross containing an actuated mastervalve and manual swab valve. An actuated flow wing valve

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8 HPHT DRILLING AND COMPLETION DESIGN FOR THE ERSKINE FIELD SPE 30364

and a manual service wing are bolted to thier respective 90outlets. A connection for methanol injection is providedbetween the service wing and upper master valve. Thisconfiguration has been adopted to facilitate ease of changeout of component parts of the tree assembly. Trees will befire resistant to maximise well security in the event of fireon the platform. Production bore valves are not required tocut wireline, as this feature will be provided by the blockvalve assembly that will be utilised during the wirelineoperations. This will minimise the chance of removing atree valve that may have been used to cut wire.ConclusionsI. HPHTdevelopment wells can be designed to be safe, cost

effective. and reliable using current field proventechnology.

2. Well design requirements and considerations should bethoroghly evaluated. The design process should start withthe completion str ing and work outwards. An iterativeapproach allows optimisation of well design.

3. An integrated team approach enables dril ling and welldesign issues to be considered in the overall fielddevelopment concept.

AcknowledgementsThe authors wish to thank Texaco and BP for their supportand permission to publish this paper, and all parties whocontributed to the well design and project progression.References1. J.B.Greer, Greer Engineering Co. " Yield Strength Reduction atElevated Temperatures and Anisotropy of Yield Strength inPerformance Design for OCTO" unpublished proprietary report.2. S.J.Svedeman, K.E.Arnold. " Criteria for Sizing MultiphaseFlowlines for Erosive/Corrosive Service" SPE Production &Facilities journal, February 1994.3. S.D.Cassidy, Texaco E&PTechnology. "Solutions to ProblemsDrilling a High Pressure, High Temperature Well" SPE 24603presented at 67th Annual Technical Conference and Exhibition

of the SPE in Washington, DC, 4-7 October 1992.4. J.B.Greer, Greer Engineering Co." TestProgramme for 110 ksiSour Service Casing" unpublished proprietary report.5. E.F.Klementich, S.C.Morey, M.L.Payne, W.T.Asbill,E.O.Banker, J.K.Bouche. "Development and AcceptanceTestingof a Flush Joint Casing Connection with Improved PerformanceProperties" SPE 26320 presented at the 68th Annual TechnicalConference and Exhibition of the SPE in Houston 3-6thOctober 1993.6. The Institute of Petroleum. "Well Control During the Drilling

and Testing ofHigh Pressure Offshore Wells".110

7. S.A.Cruser, Texaco E&P Technology. "HPHT ProductionExperience in the United States" unpublished proprietary report.8. R.M.Shivers,J.P.Brubaker,Texaco Ltd. "DevelopmentPlanning

for the HPHT Erskine Field" SPE 30370 presented atOffshore Europe Conference in Aberdeen, Scotland,September 1995.

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SPE 30364 G.S.ELLIOIT, R.A.BROCKMAN, R.M.SmVERS III

Table 1 - Reservoir Characteristics

9

Reservoir Pressure (psia)Reservoir Temperature (OF)Reservoir Depth (tvd,ft)CITHP (psia)FWHT (OF)Well FluidH2S (ppmv)CO2 (mol %)Formation Water Ct- (ppm)

14,00034515,00010,600325Gas/condensate18 - 333.5 - 5.5up to 160,000

Table 2 - Drilling/Production String Load Criteria

LOAD CRITERIA BURST COLLAPSE TENSIONDrilling 1. 20" casing. Gas evacuation not to exceed fracture Limited losses while drilling:- Pressure test on bumpingCasings gradient at shoe. plug.

Fluid level drops to balance or2. Surface casing. Limited kick. formation pressure. Mud weight String weight plus(16" /13 3/8") behind casing string. 100,000 Ibs over pull.

or3. Intermediate casing. Full gas evacuation from pore pressure Dynamic slip loading.(12 1/8"/10 3/4"/10") at TD of next hole section.

Mud weight behind casing string asbackup (All strings)

Production 1. Tieback string. Tubing leak at surface acting on 11.3 Below PBR:- Pore pressure outside Pressure test on bumpingCasings (9 S/8"/8"n 5/8") ppg packer fluid. with minimum bottom hole plug.

pressure. orDegraded mud outside casing string as String weight plusbackup. Above PBR:- Mud weight outside. 100,000 Ibs over pull.

Seawater inside drops to equalise orpore pressure of deple ted reservoir. Dynamic sl ip loading.

Production 1. Tubing string. Maximum shutin tubing pressure plus Kill weight fluid outside with Seals seize in PBRTubing (5"/4 1/2") excess pressure required to start minimum pressure inside string due preventing movement of

bullhead kill. to depleted reservoir. the string during well killoperations.

Seawater as backup. orString weight plus100,000 Ibs overpull.

Table 3 - OCTG Grade Selection vs Temperature and HzS Exposure

Vertical Depth Minimum Drilling Casing Production(ft) Temperature (deg F) Casing Liner Tubing0-9,000 50 ClIO CIOO - CRA7,500 175 Q125 Q125 - CRA13,500 300 140 140 CRA CRA

111

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10 HPHT DRILLING AND COMPLETION DESIGN FOR THE ERSKINE FIELD SPE 303

II1II I

\ 1 I1 II

Erskine

,,,,,,,,

LomondI,,,,, ETA

,,\ NORWAYUK\

-_.L.-_.L.-_..a. . ;; . . . . . . .BIU---

,.---y----.._-.., ,,,,,

Fig.l -Erskine Field Location Map. Fig.2-JackuplPlatform Interface During Operations

Fig.3.Erskine CompletionString Schematic.9 5/8" / 8" /7 5(8"Production T 1 e b a " ' c k ~ " " " ' ~String

-;::;U....

.....

~r -

.... ,,-

E = ~lU (Ij1ii'iO:ll....... ..t n1M ..

'"...

I ...I

5" TubingFlow Coupling4 1/2" TR-SCSSSV c/YW1m1lne Insert NippleFlow Coupling

4 1/2" Tubing

Locator SubSeal StackI PBRWIr8Ilne NipplePerforated ):Sup JointWlrellne Nipple clwgUide shoe41(r Production liner

112

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SPE30364 G.S.ELLIOTI, R.A.BROCKMAN, R.M.SIUVERS 1lI 11

...'. ".....ow Alloy Steels

28 Cr (NI-Cr-Mo)22/25 Cr Cold Worked

" " .. ~ ," ' - ~ ~ +(,lIlo . . . .

...... lo.Io . . . . . . . . + . . . . . . . . . .0.9 - t - - - - - I - - - - + ~ , , - - - - - + - - ~ 4 - . : . : - . + - . - , - . , - .. : : . . . . ~ ! " " " ' ~ " ".--+---- j-----+-----1

'. . : . ~ . ~ : - - : : . r - - . . . j - - . . . J13 Cr ISuper 13 Cr (Q & T) I - ' - ' . r : - - - - j - - - - - + - - - + . : - . : - - . " ' - : . " " ~ . " " .""'+"""'=:::-:-+_ _ - -1".. -... " . , . : . . , . ~ " ' : : : ...jc:B-Ill 0.8ifl .... , ...0.7 +----t----I----1-----t----+---- '+;-:.,- .. . - - + - - - - + - - - ~....

.. .. ". '.0.6 +----t---- i I ----1----- t----- l ----- l ----- t---- i ---- lo 100 200Temperature (dog F) 300 400

Fig.4-Yield Strength Degradation Factors with Temperature

12,000

10,000

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12 RPHT DRILLING AND COMPLETION DESIGN FOR THE ERSKINE FffiLD SPE 30364

9518" /8" /7 5/1t'Production -----............TlebeckString

- Frl!dlJre Grlldlflll1- - Mud WOight......, Pore PressL18

& 8 10 11 12 13 14 16 18 17 1& 18 :lO 21EMW(ppQ)

Fig.6.Generalised LithologylPore PressurelMudWeight Plot

SHlevei 140 ftSeabed at 436 ft

30" Csg 600 ft

20" Csg . . 2,150ft

16" /13 3/8" SurfaCeCsgat +/-11,!iOOft tvd

TieBackStem S leeve

12 1/8" /10 3/1f' /10"IntermediateCsg +/- 14,850 ft tvd7" Drilling Liner- contingency forErskine Sand wells. Expectedfor Pentland sand wells.41/2" Liner to +/-15,500 ft tvd

L

114

Fig.7-Generic Erskine Well Design