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SPE 30364 SeebtyOfPotrebumEndnws

HPHT Drilling and Completion Design for the Erskine Field

G.S.Elliott SPE, R.A.Brockrnan, Texaco North Sea UK Co, R.M.ShiveIS III, SPE, Texaco Ltited.

Cwyright 1995, Society of Petroleum PSIPineers, Inc.

tin paper was prapar.d for premntition at Offmhore -opa 95 heldin Aberdeen 5-a September 1995.

l’his papr was selected for pre8aatation by an SPE Proprm C_tteefollowingreview of tha infomtion contained in an abstract NhOittedby the author(s) . Contents of the paper, as presented, have not henreviewed by the Society of Petroleum Eupimers &@ are mbjectad tocorrect ion by the author [s) . The material, as prasentad, does notnecessarily refhct any position of the society of POtrolaumSnginears, its officers, or mmbers. Paprs present.d at SPE metixsare subject to *licatiOn rwiaw by Mitorial Camitt-a of the

society of Petroloum zineers. permission to copy is r*9trictad toan abstract of not more than 300 W*. Illustration may not be

COPi~. me abtract should contain cmspicuous aclmmledg-t ofwfmre and by wham the -r was presmtsd. WriteLibrarian, SPE, P.O.BOX 833836, RiCtiOn, 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)* field&velopment 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 iirst HPHT field developed in theNorth Sea with first gas sciwduied for 1997 (Fig. 1). Tbbfield 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 perfoH13through tubing plug-backs. Reserves in the COE 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 wem 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 instaIled over an existing sub-sea appraisal

103

well in the spring of 19% (Fig.2). Two wells will be

xti through the jacket structure and suspended prior tothe platform topsides chxk being lifted into place in 1997.The appraisal well will be tied back and wells will then becompleted ready for commerc ial gas export in late 1997.Further wells will then be drilled and completed as required.

* ~~~ @ un~~ K~gdOMCOM&LGnrdShelf @erations Ntike ~ MY

well where the undisturbedbottom hole temperosureis 3(X7For greeter andeither the POWpnmsum exceeds 0.8 psVji or pressure control equipmentgreater then IO,(W)psi roted working pressure is required

Platform Concept OutlineBy North Sea standards Erskine is a marginal field (335MMSCF gas, 66.5 MMBBL oil). The resultant developmenthas mwolved around this in order to make developmenteconomic. The following lists the main fetures of thedevelopment.

1)

2)

Simple W 12 slot wellhead platform providingunprocessed multiphase fluids expxl to host platform

-- ...”with a projeeted tielcl hre of i5-20 years.

Platform design and slot layout which enables access toall slots for cantdevered jack-up drilling in the 300 ftwater depth.

~e~ ~~~ Cc.-...- -nAlcm3&n_*

Primary considerations for the well design are:

1)

2)

3)

4)

Reservoir fluids containing H# and COP Reservoirpressure +/-14.,000 psi, temperate 3500’F,initird surfaceshut-in pressure 10,600 psi (Table 1).

Design flow rates required horn each well will be up to60 mmscfklay of gas.

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

Possible future production enhancement with fracturing /

2 HPHT DRILLING AND COMFLETION DESIGN FOR THE ERSKINEFIEUl SFE 30364

laterals.

5) Wells must be reliable because ofl

. ..a) lnnited rig avaiidiiity and ‘high rig cost.

b) NNMI concept allowing very limited personnel accesswithout support vessels.

c) platform maintenance, inspection and well interventiononly being planned for once yearly.

6) Well and drillhg progranune features to minimke wellCQsts.

Well Desii Primary Features

Primary well design features to meet these requirements SIW

1 \ mz.- L-— ---1 L,... c . -l:. Al= 4-.. *I.I h.h;”e nlmm1] NIUU~WIG cUU#UUU LO1 lG-IW uuuup W.IU6 y..~

backs..—A.

2) Polihed Bom Receptacles (PBR) instead of packers.

~) Comsioa Resis’m’ Allnv= ~f’nA) fhr ~ flow we@. . -.”>. \w..’ ., .-.surfaces.

5) Standard, field proven materials and technology wheneverpossible.

6) Use of API bit sizes which are common in the North Seaif necessary at the expense of non-standard casing sizes.

Completion DesignThe requimrnemt for through tubing plug backs, highproduction rates, and wellbme reliability drove the proposedcompletion design. The completion design (Fig.3) is basedon a PBR. It consists of a seal mandrel mn on 4.1/2” CRAtubing with a full bore tubing retrievable surface controlledsubsurface safety valve (TRSCSSSV). Landing nipple III’shave been selected to allow through tubing plug backs usingcast iron bridge plugs (CIBP). The production string will benm in a non kill weight packer fluid prior to perforation ofthe wells on wireIine.

‘Ihbing Design. A 4. lR” 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 60mmscfld 5.1/2” tubing would provide a modest increase inflOW Ciiptity, but would fJlldy illCIK%W the Cost andcomplexity of the casing programme. It would cause thePentland wells to water out pmnaturely 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.

TIE production string will consist of 4.1/2” x 0.320 WT,

104

130 ksi tubing below the safety valve with 5“ x 0.400” WT,130 ksi tubing alxwe to accommodate wireline insert safetyvalve installation.

~k @&@ ~w *U ~:p~ f~~~~.rs~]Qac b&don initial

shutin weilhead pressures of 10,600 psi and flowingwellhead temperatures of 325 deg F. The collapse load hasbeen baaed on minimum bottom hole pressure with a 18.0ppg packer fluid. Triaxird analysis has been performed toconfirm the tubing design together with tubing movementcalculations for various operational load cases.

Metallurgy. The combiion of high temperatures, COZandH# partial pressures, formation water salinity, andmultiphase flow requires the use of CM materials for thetubing and production liner to ename reliable corrosioncontrol (’hble.1). A 28%Cr-31 %Ni CRA has been selectedas the base case material with a yield strength of 130 ksiwhich has been &rated for use at elevated temperaturesm m .d f~ IW32M imkotropy [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 ab~lty to acidize wells.

PBR vs Packer. Isolation of the reservoir km 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 mandd and stack run with the completion string. APBR style completion was selected over a packer stylecompletion because it provides:

1) Simpler workovem (no deep milling oprations requiredthat could lead to loss of a platform well).

2) Lower tubing stresses.

3) Simpler completion design.

4) SuccessfiIl 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 hot producing and cold shutin periods.The stack is positioned in the PBR to accommodate upwardmovement during well kill operations or stimulationtreatment Seal stack testing at shmdated bottom holeconditions is ongoing to determine the best availableconfiguration.

TRSCSSSV. The running of tandem tubing retrievable

SPE 30364 G.S.ELUG’IT, R.A.BRGCKMAN,R.M.SHIVERS III 3

surface controlled subsurface safety valve’s was considered.However the increase in the overall completion reliabilityand Workwer cow benefit W* not significant when

compared to the added complexity and increased cost of thecompletion ales@. Hence a single safety valve with acommunication nipple was =i=ti asthebasecase.‘Meantimetofailure of the safety valve have been dmated as 20years based on available North Sea data.

A single piston non-equalizing flapper type valve with allmetal to metal seals will be used. To maintain the throughtubing workover abtity a 4.1/2” full bore safety valve willbe run. The vrdve is rated to 15,000 psi at ao opemtingtempemtum of 350 deg F. It will be manufktured fromInconel 718 material with a 7.875” OD and a 3.813” bcue.Skimming the valve OD to 7.750 at the expense of areduction in wmkkg preemtt $0 14,000 pd is beingconsidered. Fluid velocities across the valve am well below100 ft/sec which should ensure no erosion for sand &eProductionz.

A separate communication nipple will be run above the valveto allow wimliie retrievable subsurface safety valves(WRSSV) to be run should the primary va.he fail. Separatecontrol lines wiU be run for the primary valve and thecommunication nipple. In the event of control line failme tothe primary valve a full tubing workover would not berequired as a WRSSV will be run to maintain production.

I%cker Fii Seiin. Packer fiuici seketton has ‘beendriven by

1)

2)

3)

4)

Improving tubing workover abfity.

Minimizing tubing movement.

Passive to production tubing and tieback materials.

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 5300 psi. Seawater hasbeen disregarded as a suitable fluid due to the highdifferential pressure and excessive tubing movementoccurring during production operations for a smalI reductionin cost. low volubility of oxygen in a satumted calciumchloride brine will ensure that only low geaerai corrosionoccurs.

Work is ongoing to try to establish safe, efficient reliablemeans of completing perforated wells with underbalancedclean packer fluids. If necessary perforated wells will becompleled using kill weight fluids with weights up to 18.0ppg. Pseudo oil based muds will b used for the heavierweight fluids as opposed to zinc bromide and formatebrines.

105

~~L- =-wThis has been analyzed on a global systems basis withvarious well ales@. In all cases, pressure build-up in asealed annulus due to thermal expansion from productionconditions results in unacceptable loads on casings. Thiswill be preven’d by tbe fo!!mving measures.

1) pressure will be bled off from all annuli at the surfacewellhead on initial production start-up.

2) For dcilling casings below 20 conductor, cement topsmay be left below the previous casing shoe, thusproviding a natural relief valve to the formation.

3) For the tubing to production tieback anmdus, pmssmeWill illitiy be bled Off. h addition, _Ote ~SStUe

monitoring will be provided on the host platform for thisanmdus. In addition application of a pressmised nitrogencushion is Ixing eonsidemd for this annulus.

Workover/Mervention PhilosophyWorkovers and well interventions will be minimki 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 lxx

1) Plug back and re-perforation of 2 Pentland wells asEr#dnn. p... .rOdUr~~S+

2) Production logging on all wells on a yearly basis.

3) Installation of wireline retrievable safbty 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 thefife ~f fi~d bac~ .m thmfiwemllrdiah~ty Of &t? COI@etiOIJ.— “U . . -. .- ..-—

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 / hydraulicwodcover unit operations. However, logistical support mustbe provided by a bridge linked Mobile Support Vessel. Fulltubimg ‘wCitkOV~rS can be CO”dC*d at any *ti- !))’ a hbsh

environment jackup or a medium size (CEFM 2005-C)jackup in summer. Modular WOI’kOV= I@ Cm dSO be

utilised by the addition of capping beams to the piatformthus enabling full tubing workovem to be accomplishedwithout using a jackup rig.

Enhanced RecoveryThe deliverability of the welk completed in the Erskine sanddeciine with the sharp drop iti m—wii presmre which is a‘-h--’”=~”~” “f ‘hi’ I“w ~ ilitvmaxvoir. A numberb aww.1.uw “. -. .-.. ~———.—.,

4 HPEIT DRILLINGAND COMPLEXIONDESIGN FOR THE ERSIUNE FIELD SPE 30344

of enhanced recovery techniques have been considered andtheir impact on well ddgn identified.

The technical feasibdity and design of fracturing the EdcineSand to improve recovery has been investigated. Bothtechnology and equipment exist to enable Ihcture stimulationto be carried out. However, erosion of production equipmentcaused by proppant flowback over time is a major problemespecially when associated with high flow rates and wellheadpressmes. This stimulation tectilque will not be usedinitially due to the increased risk of equipment failure whichwill impact on the platform ndiability and safety.

High angle wells have also been considered as a means ofimproving well &liverability. There am 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) Boxe hole stability in depleted reservoirs limits themaximum hole angle that can be successfully drilled.

3) At initial memoir conditions, tiacture gradient decreaseswith increasing hole angle, thus narrowing further themargin between tkacture gradient and pore pressme.

Studies are ongoing and it is possible that the productionliner design on the two later Erskine sand producers maybemodified to allow a future short radius horizontal sidetrackto be performed within the Erskine sand.

- *4W

Platform / Rig Interfaces. The field development planprovides for cantilever Jack-up drilling over the NNMIplatform. Advantagea of this are simplified platform des@nand elimirlatictl of skidoff eq@xnent reqttiremerlts. Thedisadvantage is relative motion of the platform and jacketstructwes and possible limits on operability in severeweather. Field data suggests that actual movements will notbe as large as the theoretical movements predicted bystructuml 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, anoperabii~ty study is underway to identify means ofminimizing downtime. For example a flex-connect systemis planned to be installed in the riser between the rig andBOP.

Other platform rig interfaces inclu& 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 des@n to suit the jack-up to reduce rigmodification cost wherever possible.

106

L]thology / pressure Regime. Erskine lies in the CentralGraben area of the CNS. ‘Ile Iithology / pore pressure /mud weight diagram is shown in Figure 6. Tertiaryformations extend to approximately 11500 ftss. Theseformations are primarily normally pressured, but reactiveunstable / overpressured shaks 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 ftas. 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 Cretacaus 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. Intcmnediate casing has to be set in the base ofthe Upper Cretaceous formation. Although there am usefulformation markem such as the ‘Black Limestone Marker’,picking this casing point has always been a problematic partof the Erskine appraisal wells. Conect placement of theintermediate casing shoe is essential to ensure sufficientfracture strength to weight up the mud and drill theoverpressured reservoir’.

The Jurassic. reservoir sequence consists of Late JurassicKimmeridge formation containing Iiited Kimmeridgianhydrocarbon bearing sandstones, then Mid Jurassic sequencesthat contain the Ed&e 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 !8:5 to 20 ppg EMW. Thus there is a very liitedwindow 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 appraisai driiiing, and thedifferentiation of influxes from kicks and formationballooning has been difficult.

Casing Setting Depths The generic development welldesign is shown in figure 7.

30” Structurof Ciasing provides sufficient formationintegrity to support loads and drill 26” hole for the 20”conductor.

20” COn&CtOr is set at 2,500 ftss in order to case off

hitial build section and obtain a formation strength in the

SPE30364 G.SEUKYtT, R.A.BRGCKMAN,R.M.SHIVERS III 5

15-16 ppg EMW range.

S@rce CWng is set in the top of the Upper Cretaceouschalk to case off the unstable shaIes of the Eocene age andthe permeable Pakocene sands.

htermedkte C3rsingis set in the pressure transition zonetowads the base of the Upper Cretaceous formation asdescribed above.

Drilling Liner is contingent to be set during the drillingof the reservoir sequence if required.

PmAction Liner is set at TD and cases off the reservoirsands and dtilling liner if run.

Pmductbn Tieback Sbing is cemented in place in thetieback PBR on top of the production liner, and ties back tosurfkce as the production string.

Directional Drill@. Wells will be ‘S’ shaped. This ispossible with quite low tangent anglca due to the relativelysmall areal extent of the field. The furthest stepout wellrequires a tangent angle in the region of 35°. ‘S’ shapedweiis etde the weii to be verticai fiwrn intt casing~intm~tiuse~gti~for~tikktihighest temperature part of the well. The drillstring will alsobe kept simple in the reservoir sectiom simplifying wellcontrol and minimizing circulating pressure losses.

Build rates will be limited to a plarmed rate of 1.5°/100ft inthe 26 hole and Arnco 200XT or Armacor M drillpipehamlbanding will beusedin order tominimiae casing wear.

Well DesigII Pldlosophy. The following lists the generalptiiples used in the development of the Erskine welldesign in addition to the considerations for completiondesign previously discussed.

1) Use of AiiI bit sires common iu the North Sea hole sizes,if wceamry at the expense of non-standard casing sizes.

2) Tapered casing strings to accommodate the TRSCSSSV.

3) Allowances made for casing wear, casing yield strength

4)

5)

reduction with tempemtum (Fig.4) and td-axial stressanalysis.

Specification of ‘extreme’ and ‘expected load caseswhere appropriate, with differing safety thctors for thetwo cases. Lame’s casing burst strength equation wasused for uniaxial design calculations rather than APIBariow equation.

Opdmisation of running cleamnces on completion, casingin casing, and casing in open hole. Consideration offishing capabilitica of well cleanout strings and tubing.

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 mom detail below. This has been laid out inthe order of ascending casing size as well design is primadyc-hiven by completion design and TD hole size. Table 2shows a summary drilling and production string lotxl criteriaused in the well design.

MetaUargy. Due to the casing clearance requirements, it wasdesirable to use high strength sour service casing forintermediate and production string applications. Aqualification testing prograrnnm Commenced in 1991 andNACE TM0177 method A coupons and full scale casingjoint testing have both taken place. Notable differences wereseen in results horn coupons and full scale casing. Fullscale casing qualiikation testing is preferred because 1) afull scale test sample has an area equal to approximately200,000 cou~.s thus incree=inu statistical confidence, 2) the- -—-internal surface of the full scale sample is that which mustprevent initiation of SSC and contains imperfectionsmnaining from the manufactming process. Thesepresumably account for the differences seen in coupon andfull scale results.

NAC13 TM 0175 method A high-end C1OOCOUpOnS WC= .

found to have 90% thm%old of SMYS in s%ndarr NKE

solution, but full scale joints failed this environmmt at 80%.Low end C90 was used as a control and passed full scaletesting at 90% of SMYSinthiscalvironment

Further W scale joint testing took place using a 1.5 psi H.#partial pressure modified NACE environment (conservativeErskine environmentt). ‘fhiS qudifkd high end yield Stf4?Z@h

C1OO at 90% SMYS, a dramatic rise from the testing atNACE environment conditions. Confirmatory CiOO ‘@stingis underway, and Cl 10 sample testing is planned.

Selection of surface and drilling casing grades foIlow NACEMR 0175 tempczature and service exposure criterion, usingthe production casing test fuii scaic quai@aticm as “b initiaireference at surface c4mditions (Table.3).

Thus, for production applications on Erskine C1OOhas beenqualifid and CIIO is planned to be used for intermediatecasing in pseudo oil based mud drilling environnumts.~~rkW~ t~@ ~~ ~m q~~ify C 1iO for production

applications on Erskine4.

Pmhwtkm Liner. A 4.1/2”, 2896Cr-31%Ni production linerwill be used. The corrosive nature of the fluids requites theuse of CRA’S and the selection of this materkd for the

107

6 HPHTDRILLINGAND COMPLETIONDESIGN FOR THE ERSKINEFIELD SPE 30364

production liner is based on the absolute requirement for!Gfigey~~yfi~~ ~~ !~~~~. ~J~ ~i~ p~Qvi&.s monQbore

features to the well for ease of plugback with cast ironbridge plugs and simplified workover operations. 3.1/8”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 depleted

.-.. — a-~ ,..C G-1A IX- :“*a-mIl.,production peSSLIK at ‘&e ~- U1 LIGIUILLQUw,uau, .Reservoir compaction was calculated, and connections willbe Selected to mmimise resistance to compression.

ZOnai isolation is critical when piugging back the Fentiandproducers to Erskine producers after watering out. Thuscementation quality including anti migration properties wiIlbe important.

With the tubing PBR below the liner hanger, hanger andtieback equipment can be of 140 ksi carbon steel at thesetemperatures (+30@Fj. 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. Prima@ 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 weight mud packer fluid hasalso been considered. The intermediate casing provides adegree of redundancy in the event of a breach of theproduction tieback sting. 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 4.1/2” TRCSSSV’S available haveODs in the region of 7.7/8”, although it is expected thatEd&e valves will be skimmed to 7.3/4” at the expense ofa slight drop in pressure rating. Thus 9.5/8” C1OO sour

—.-.. —___

service casing provides the requhed strength capabilities witha 7.95” drift. This provides a minimum running clearance inthe completion brine of 0.2. Increasing this clearance maybe possible if Cl 10 casing is qualified for Emkine productionconditions.

In order to be able to meet the requirement to washover andfish 4.1/2” tubing with 5“ T&C couplings, a 6.3/8” minimumdrift diameter is required below the TRCSSSV. The tiebackcasing selected is therefore 8 CIOO from the TRCSSSV to200”F and 7.5/8” Q125 below this to tk production liner

top. Running clearances for the tieback string inside theintermediate string are a minimum of 0.5” on couplings andare around 1” 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 sting which could exceed triaxialstress safety factors in the event of a tubing leak duringnmrhlrtinny.-”. . . .

DriUing Liner. This will serve the function of a drillingliner only, as the production liner top will straddle and.. . . . . . AL:-1:-- m.. - l_..A” . ...11 h 1: . I .“’s- *- ●bIsolate w liner. I IIUSMUS WU1 w dm*Wi to ~V=- ●v -formation for collapse and pressure testing and gasevacuation for extreme burst loads. The liner selected forthis application in 8.1/’2”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 12.1/4” hole is in the pressure transition zone asaheady described. This hole section will continue the use ofthe pseudo oilbased mud system to be used for the 17.1/2”hole. It is planned that Gamma Ray-Resistivity LWD andVSP’S will be used to assist in picking the intermediatecasing point, as them are some identifiable features forreference in this interval. Following mnning and cementingof the intermediate casing, the reservoir is drilled in 8.1/2”/ 6.1/4 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 pmssum. 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 compatiiiie with a i 3.5/%”wc’W5ari /BOP, a 12.1/8”, 90 ppf, Cl 10, casing with Marubeni ULTconnections was selected for the top of the intermediatecasin~. The nmainder of the intermediate casing is 10.3/4”,73ppf, Cl 10 down to 2(WF inside the surface casing, and10, 72ppf, Q125 in 12.1/4” open hole. The 10 casing has~~ g.~,~ &d@.. 17rw4m~Ce-~ f~~ nmnin..— ..—.g d CemdDg this

string inside the surface casing are a minimum of around 1”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)108

SPE 30364 G.mLim’iT, R.A.BRGC”*” “ v “--e mx, A.1 l.oru v-. Ill 7

case off the Tertiary and Palaencene sequence, 2)accommodate the 12.1/8” casing at the top of theintermediate casing, 3) provide a 12.1/4 drift for drilling tointermediate casing point. Design criteria is baaed 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 pom pressure. It is planned that 17.1/2” 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 may

‘=a ‘~ ~~~ f~i ●*e ~~.~/# A●I.. AS ma+:fi” tfi ~till thmUuav - .“. w Salu u.

Upper CmtaceOus chalk in order to increase penetration rateand assist in detection of the pressure transition zone.

A 16” x 13.3/8 taped casing string has been selected asthe surface casing. 16 will be run inside the 20 conductorand 13.3/8” mn 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 stnmgth, and to case offthe build section of the well. 26 hole will be chilled 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 weIl and site survey results,shallow gas is considered to be extremely unlikely.

Structural (hai~ Structural casing is 30 diameter. Pre-installing the jacket allowed omission of a mudline

—.. .suspension system. Full hanging weight of til casings WKI‘besupported by the 30/20 casings. Structural analysisshowed 30 x 1” wall, X52 material is suitable for weUs

ddled through the platform jacket, A proviso on this is thatin severe storms it will be necessary to release the jackup!lom the ccmductor/BOP if dative motion of the twostructures approaches 3 ft. Operations analysis is underwayto determine maximum Aative 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 horn a jackup without the jacket in place,30 structural casing would have required significantredesign tlom 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 fm shallowffi-mt:n.e .“#’l*b d ●m.1im;mata Anmlamc9“A m!lw;mica.Wa—””. — - — . “.u— .“~.~. . . —directional control.

Casing Connections. 30 and 20 use established thradedconnectors. The surface casing uses the Dalrnine ATS

109

modified buttress thread. Intermediate and smaller casingswill all utilise premium comections.

Due to the small annular clearance between some casingstrings, there are requirements for slimline couplings onrelevant casing sizes. For example the 12.1/8” casing at thetop of the intermediate string has a coupling OD restrictiondue to 13.5/8” wellhead design constraints, however this isalso an am of high tensile loads. The Marubeni ULTcomection was selected due to it’s high tensile efficiency,full drift and restricted comection OD features. Connection~~;m al~fi l~mdaitw.lf tn thi~ mmlication. hf@ CUStOmkXI—.*.. . ...” .. ..— .-. . -- —- --J--.—.—----, --- _

for specific pipe sizes. Qualification testing is also planned.The remainder of the intermediate string utilisesMannesmann ~ COtMl(@iOt3S.

Tieback and production lier connections have not yet beenselecte4 but similar criteria exist.

WellheadaJXmas Treesn. t.... A..*, :..lr *R. “nm.;rl.mri fnr 17?.clrirma- Umlr=mllvL- II= VT UUby JCSWk+- W.StW.W s“. u“--- -“ ~“--..a..-=

equipped with 21.1/4” / 13.5/8” BOP systems. Use of asingle 18.3/4 15M BOP was considered to reduce BOPhandling and possibly simplify casing hanger configurationfor the Erskine casing programrne 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 21.1/45M x 13.5/8”15M BOP ccdguration and consists of stacked casingspools. DriUing 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 platform jacketcasings can be hung at surface and a mudline suspensionsystem is not required.

To facilitate safe and efficient BOP / 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 woxkover or wellintervention that requires only manipulation of the tubing.

The x-mas tree will be nominal 4.1/16API 15M to becompatible with the tubing bore, and will be a stacked valvePrmfimmnti fin @ facfl&@--..~ . . . . . *A* Qf Compomnt Valve

replacement. 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

8 . HPHT DRILLINGAND COMPLETIONDESIGN FOR THE ERSKINEFIELD SPE 30364

and a manual service wing am bolted to thier respective 90° 7.

outlets. A connection for methanol injection is providedbetween the service wing and upper master valve. Thisconfimration has been adopted to facilhte ease of change 8.~—-.out 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 am not required tocut wireline, as this feature will be provided by the blockvalve assembly that will IE utilised during the wirelineoperations. This will minimise the chance of removing atree valve that may have been used to cut wire.

Concluaiona

1.

2.

3.

HPHT development wells can be designed to be safe, costeffective and reliable using current fieid proventechnology.

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

AU intemated team ammach enables tiling ~d welldesign ;asuea to be- ;onsidered 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.

References

1.

2.

3.

4.

5.

6.

J.B.Greer,Greer Engineering Co. ” Yield StrengthReduction atElevated Temperatmes and Anisotropy of Yield Strength inPerformanceDesign for OC’IKi”unpublishedproprietaryqort.

S.J.Svedeman, K.E.Arnold. “ Criteria for Siziig MukiphaaeFlowlines for Erosivt#Corrosive Service” SPE Production &Facilities jouti Febmary 1994.

S.D.Csssidy, Texaco E&P Technology. “Solutions to ProblemsDrilling a High Pmssure, High TemperatureWell” SPE 24603pnxented at 67th Annual Technical Conference and Exhibitionof the SPE in Washington, DC, 4-7 October 1992.

J.B.Gmer, Gmer EngineeringCo. “Test Progmmmc for 110 tilSour Service Casing” unpublished propriety report-

E.F.Klementich, S.C.Morey, M.L.Payne, W.T.AabiU,E.O.Banker,J.KBouche. “Development andAcceptance Testingof a Flush Joint Casiig Connection with Improved PerformanceProperties”SPE 26320 presented at the 68th Annual TechnicalConference and Exhibition of the SPE in Houston 3-6thOctober 1993.

The Institute of Petroleum. “WeU Control During the DriUingand Testing of High Pressure QIMore Wells”.

110

S.A.Cruaer, Texaco E&P Technology. “HPHT ProductionExperience in the United States”unpublishedproprietaryreport.

RM.Shivers, J.P.Brubaker,Texaco Ltd. “Development Planning.- —-— —..

for the HPHT ErsIune ~kid’ ~FE 30376 P-nAA aOffshore Europe Conference in Aberdeen, Scotland, 5-8September 1995.

SPE 30364 G.S.BLLWIT, R.A.BRGCKMAN,R.M.SHIVBRSIII 9

Table 1- Reservoir Cbaracteristica

Reservoir Pressure (psia)Reservoir Temperature (“F)Reservoir De@ (tvd@)CITHP (@t)mmWeIl FluidH2S (pplllV)

C02 (mol %)Formation Water Cl (ppm)

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

Table 2- DrW@l%d uction String Load Criteria

LOADCRITERIA BURST COLLAPSE TENSION

Drilling 1.20” @rig. Gas evacuatkmnot to exceed fracture Limited 10SSCSwhile drilli~- Pmsslu’etest on bumpingCasings gradientat shoe. P@.

Fluid bd drops to baiancc a

2. Surftwccasing. Limited kick. formationpmssurc. Mud weight String weight plus(16” /13 3/S”) behind casing string. 100,OOOlbs over pull.

3. Intwndi* casing. Full gas evacuationfrom pm pmssurc Dynamic siig%ndmg.(12 1/s”/103/4”/10”) at 111 of next hok section.

Mud weight behind casing string asbackup(All strings)

Producdon 1. Tw&k S@@. Tubing kakatsurfacc acting on 11.3 BcIow PBR- pore pressureoutside Pressuretest on bmnpingCasings (9 Slrlrn 5/s”) ppg packerfluid. with mrnlmumbottomhole plug.

~. orDcgrdcd mud outside casing string as String weight plus

-. Above PBR- Mud weight outside. 100,OOOlbs over pull.seawater inside drops to cqudkc

r IXWSWof depktcd mscrvoir. DylUmic sl&Mding.

Production 1. Tubing string. Maximum shotin tubing pmssum plus Kill weight fluid outside with Seals seh m PBRTubing (5”/4 In”) exass pmasurcrcquked to start minimum pressureinside stringdue preventingmovement of

bunhcadkill. to depleted leservoir. the stringduring well killopwations.

seawater 55 backup. aString weight plusIoo,ooo lb? Ovcspldl.

Table 3- OCTG Grade Selection va Temperature and H# Exposure

Vertical Depth Minimum Drilling casing Production

(h) Temperature (deg F)Caaing Liner Tubing

0-9.000 50 Cllo Cloo CRA

27,500 175 Q125 Q125 CRA

213,500 300 140 140 CRA CM

111

: manmter_

*

‘-4F’mnldirlg

I

I

Fig.1 -Ed&e Field Location Map.

F~S-Erskine Completion 95/6’/6’/7w

String Schematic. Flolh@&TiatlU_

Fig2-JdKu@-ti=m InterfaceDuringOperations

<— 41/2 Pmduuimlhar

2

SPE 30364 G.SELLI~. R.~BR~ , RMS-~ 11

s.

..●..

13 Cr/Sqrer13Cr(Q6m ““*. -%-&.:.....9

. . -.

LowAlloyBte912 * .;--- ●

28 Cr(Ni-Cr-Mo) ... . . . . . -..

22/25 CrColdVWted*..

---- -..●. .

=.O“.s.. -..

- ..~..-.

. .

0 2 4 8 10 u

C2xmAM8

Fig.5-WeUhead l%ewure Over Life of Field

113

12 . HPHTDRILLINGAND COMPHON DESIGN FOR THE ERSIUNE _SPE 30364

Fig.6-Generalised Lithology/Pore PressureMudWeight Plot

9sm’’ls’’l75lr-’PniddM— —Thbadlstlm

ltr/132/rsurmco* ,8t+/-ll,5aattvd

121 PJ’I102WIW

hltoMdMcsga+Flm*ti

YorlllhgLlnu-contm-Y*Eddlmsaldwda.~W~!3andw@18.

41/2” Llnuto +/- 15,=itti

Fig.7-Generic Erskine Well Design

114