Society of Petroleum Engineers

SPE 25384

Bigbore Well Completions: A New Completions Technique for Arun FieldW.L. Cannan, Mobil Oil Indonesia Inc.; D.L. McKenna, RA. Sukup, and D.G. Calvert,Mobil E&P Technical Services Inc.; and R Quitzau, S. Sardjono, and P.C. Ellison,Mobil Oil Indonesia Inc.

SPE Members

Copyright 1993, Society of Petroleum Engineers, Inc.

This paper was prepared lor presentation at the SPE Asia Pacific Oil & Gas Conference & Exhibition held in Singapore, 8-10 February 1993.

This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper,as presented, have not been reviewed by the Society 01 Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflectany position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Societyof Petroleum Engineers. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledg­ment of where and by whom the paper is presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A. Telex, 163245 SPEUT.

ABSTRACT

The prolific Arun Field in North

Sumatra, Indonesia continues to

produce substantial amounts of

natural gas and condensate. However,the massive carbonate reef reservoir

is beginning to require special

measures for more complete

exploitation and recovery of the

large quantities of hydrocarbon

remaining in the formation.

Optimization of production requires­

combined efforts from Arun

geologists, reservoir, production,

drilling, and operations personnel as

well as technical advisors.

Although the Arun Field wells

typically produce 30 to 100 MMSCFD

per well, increased production rates

are being achieved by utilizing

larger bore wells and modifying the

drilling and completion techniques

accordingly. Substantial increases in

gas and condensate production rates are

being reali:zed with a savings in

investment over previous Arun Field

drilling and completion methods

utilizing con.ventional 7" completions.

Previous completion techniques utilized

7" production tubing with either cased

or open holle completions. The "Big

Bore" completion technique has 9-5/8"production t.ubing with an open hole

completion to maximize deliverabili ty.

The primary purpose of the technique is

to boost field productivity in order to

meet gas dE~mand, enhance condensate

optimization, and allow flexibility in

operations. This new completion

technique required extensive equipment

design and testing to meet anticipated

production and stimulation conditions.

This is the first time a completion ofthis type has been utilized in

Indonesia, and as far as we know, these

2 "Big Bore" Well CompletionsA New Completion Technique for the Arun Field

Paper #25384

Operational Overview

The Arun Field was developed using acluster concept where a group of wellsare located with common surfaceproduction facilities. There are fourclusters in the Arun field withlocations for a total of 21 wells percluster. Production wells are

As the reservoir pressure drops, sodoes the average production rate of theindividual wells. The averageproduction rate has fallen from 150MMSCFD at an average wellhead pressureof 4800 psi in 1977 to 50 MMSCFD at1750 psi wellhead pressure in September1992.

The Arun formation consists mainly oflimestone with some sections of thereservoir containing some dolomite.The initial reservoir pressure was 7100psi when production began in 1977.Since the Arun is a depletion drivereservoir, pressures have been steadilydeclining throughout the productionhistory of the field.

butane, and condensatefrom the produced gas at the

gas plant. (Fig. 1).

propane,obtainedPT. Arun

The current reservoir pressure isapproximately 3000 psi and is decliningat about 1 psi/day at the currentproduction rate. The reservoirtemperature is 3500 F and the gascontains 15% CO2 , approximately 50 ppmH2S and produces wi th a condensed watervapor yield of about 10 BBLS/MMSCFD.These are harsh conditions from acompletion design standpoint. (Table 1)

History of Arun Field

are the largest bore, gas producingwell completions in the world. Thispaper discusses the performance ofthe wells and the various componentsutilized in this new "Big Bore"completion technique.

The field was discovered in 1971 andhas been developed by drilling wellsin four clusters located in strategicparts of the reservoir. Currently 73wells produce a total of 3.4 BSCFDand 115, 000 BBLS of condensate perday. Approximately 1 BSCFD of thisgas is processed through a NaturalGas Liquids plant (NGL) to extractadditional liquids (LPG andcondensate) and the dry gas is re­injected into the Arun reservoir toassist in sweeping the condensate tothe producing wells. The remaining2.4 BSCFD is transferred by pipelineto the PT. Arun Liquid Natural Gasplant for liquifaction, andapproximately 150 MMSCFD is sold tovarious national projects for use asfuel. Pertamina sells LNG, liquid

The Arun Field is one of the mostunique gas reservoirs in the world.The field is located in the northernpart of the island of SumatraIndonesia in the Aceh Province andproduces from a Middle Miocene Agelimestone reef that is approximately3 miles wide and 12 miles long,trending in a north/south direction.The average pay thickness is 1000feet and the top of the Arunformation is approximately 10,000feet sub-sea.

Paper #25384 W.L. CANNAN, et al 3

directionally drilled from theclusters in order to minimize thesurface area required for drillingand facilities and to reduce theenvironmental impact on the local

communi ty. Currently there are 73producing wells, 10 gas injectionwells, and 3 observation wells in theArun Field. (Fig. 1 & 2).

Development drilling is in its finalstages and only 4 wells remain to bedrilled and completed. This willbring the total "Big Bore" wells to10 when drilling is completed in

1993.

fractured to reduce skin effect andincrease individual well productivi ty.This stimulation project will continueon selected candidate wells. The "BigBore" Project was designed to complete

a total of ten new production wellswi th 9-5/8" tubing instead of thestandard 7" size. By changing to thelarger tubing size individual wellproduction is increased and productionrequirements can be achieved whilereducing the total drilling cost by $9MM and reduc:ing the total wells to bedrilled. By utilizing "Big Bore"completions as opposed to the standard7" wells, four fewer wells arerequired. (Table 2).

Two proj ects to increase individualwell performance by downholeimprovements were implemented. Theywere acid fracturing [1] and "BigBore" completions. Many of the Arunwells were successfully acid

Individual well performance has beendeclining over the life of the fielddue to declining reservoir pressure.Since the required LNG plant inletpressure is fixed at 850 psi, thisheader pressure to approximately 1750psi in the field with the currentproduction facilities. This allowsfor pressure drops to sufficientlycool the gas and allow efficientseparation of the gas prior totransporting it down the pipeline tothe PT. Arun plant. This fixedheader pressure doesn't leave muchroom for productivity improvementsexcept by reducing the pressure dropsin the wellbore and formation.

DeliverabilityProjects

EnhancementOther proj ec:ts are being designed tolower the wellhead pressures [2] .These proj ects address al ternate meansof cooling the gas with minimalpressure drop (Dehydration Project) andthe installation of compressors(Booster Compression Project) in orderto further lower the wellhead pressure.The Dehydration Project lowers the

wellhead pressure from 1750 psi to 1300psi. The Jroules-Thompson· valves werereplaced with a propane refrigerationsystem. This project was completed in1992. The Booster Compression Projectwill further reduce the wellheadpressure to eventually 300 psi. Thisproject is scheduled for completion in1995. Both projects are designed tomaximize deliverabili ty and meetproduction demands. This paper willfocus on only the "Big Bore" completion

project.

4 "Big Bore" Well CompletionsA New Completion Technique for the Arun Field

Paper #25384

The initial design of the "Big Bore"wells called for a simple approach tothe use of the larger bore tubing.Plans called for a similar wellheadsystem to the current 7" completionexcept with a larger bore, a permanentpacker system, and premium seals on thetubing string.

The Arun· Field operates with a "twobarrier" system i.e., there must be atleast two barriers in place for wellcontainment. So the 9-5/8" tubingwould be the first barrier and the 13­3/8" casing would be the second.However upon closer inspection andfurther discussions it was determinedthat the wellhead system needed somerevisions due to the larger size,resulting loads, and type of service tobe encountered in the "Big Bore"application.

"Big Bore" Concept

The original concept of a "Big Bore"completion was developed in early1990. The idea was to complete onewell in each cluster with 9-5/8"

tubing in order to provide additionalgas deliverability on demand to meetoperational needs such as shutting ina well for diagnostic work or aworkover. This would provide onewell in each cluster capable of beingadjusted to meet productionrequirements and the other wellsallowed to produce at full throttle,making operations much simpler.

However, as the concept developed, itwas soon realized that in addition toproviding extra capacity per well,fewer total wells would be requiredto fully develop the Arun field, at asubstantial cost savings. The "BigBore" wells were estimated to produceapproximately 120 MMCFD as comparedto an average of 70 MMCFD for aconventional 7" Arun well.

review ofutilizationavailable.

past experiences, butof the latest technologies

Large bore tubing wells were not newto the Arun Field. The originalcompletions in 1977 were designed for7" tubing, a rather large tubing sizeat that time by any standard. Manytechnological advances were madeduring the initial stages of the ArunField 7" development to solveproblems associated with wellheadseals, tubing connections and packerfluids used in the harsh Arunenvironment and operating conditions[3 & 4]. The increase in productiontubing size from 7" to 9-5/8"

resulted in not only a thorough

It was also determined that thepermanent packer design that wasoriginally evaluated would cause thecasing to fail under the extreme loadconditions and the 13-3/8" casingrequired a premium connection since itwould serve as the second barrier toArun gas.

The other item that developed fromdiscussions was that of making theentire well full bore with minimuminternal upsets or restrictions toflow. This was based on concerns overpressure drops, potential corrosion anderosion, and also in maximizing the

Paper #25384 W.L. CANNAN, et al 5

,

options for future workovers. Inorder to achieve a full bore well,this eliminated conventional wellheadback-pressure valve preparations anddownhole profiles for wireline

retrievable plugs. This presented anew issue of securing the well. A

new system for Arun well containment

was developed to secure the well in

order to nipple down the blow-out

preventers and install the christmastree, or just to secure the well ifrequired. (Fig. 3).

After a complete review of the

original proposed "Big Bore" concept,several issues needed revision from

the typical 7" Arun well completion.

These will be discussed in detail in

the following discussions of thevarious key "Big Bore" system

components.

The "Big Bore" project was approvedin January 1991 and only 14 months

later the first well was drilled andtested. This represents a tremendouseffort by Mobil and many equipmentmanufacturers. Nearly every

component of the "Big Bore" wells was

a first in the industry since they

were newly designed and manufacturedfor the Arun application. Premium

connections were qualified for the

13-3/8" casing and 10" liner as well

as the 9-518" tubing. A new wellhead

was designed and rated for 5000 psiat 350 degrees F, API 6A Appendix F,PR-2 and a liner hanger/PBR and

isolation packer system was designed

and tested to over one million pounds

compressional load. A retrievablebridge plug was also developed forsecuring the wellbore as required.

Advantages

Full bore 1N'ell design with 9-5/8"

tubing and a PBR provide several

distinct advantages over conventional

7" completions. These advantages are:

* Eliminates the gas turbulence

areas commonly found in conventional

packer completions.

* Eliminates the open liner lapassociated with the 9-5/8" linercompletion.

* Allows for tubing retrieval to5,500 feet if required by corrosion

problems near the surface.* Allows for monitoring the annular

space between the 13-3/8" production

casing and 9-518" tubing string.

* Eliminates some of the completionequipment and accessories commonly

found in the 7" completion.* Require!s fewer wells and less

investment than with 7" completions.

Disadvantages

Although the advantages far outweighthe disadvan"tages, it should be noted

that the 9-5/8" wells require higher

minimum stable flow rates than the 7"

wells. As tubing diameter increases,minimum bottom hole flowing pressure to

maintain stable production rises.

Therefore "Bi.g Bore" wells will load up

at higher pressures than a 7"completion. However this is not

predicted to occur until late in thelife of the field for both 7" or 9-5/8"wells. "Bi.g Bore" completions will

load up approximately one year sooner

than the 7" "'ells.

6 "Big Bore" Well CompletionsA New Completion Technique for the Arun Field

Paper 125384

•

Comparison to Standard Arun Well

The "Big Bore" wells were designedfor maximum gas deliverability and tohave the entire Arun section open toflow. Therefore they reduced thenumber of wells to be drilled to meetthe LNG sales contracts. Fourteenconventional 7" wells totalling $ 84MM, were proposed to complete theArun Field development drillingprogram. Only ten "Big Bore" wellstotalling $ 75 MM are required.

On a standard 7" Arun productionwell, 30" conductor pipe is driven to200 feet with 20" casing set at 2000feet and cemented to surface. A 17­1/2" hole is then drilled toapproximately 7300 feet where 13-3/8"intermediate casing is set andcemented to surface. From this shoea 12-1/4" hole is drilled into thetop of the Arun limestone and a fullstring of 9-5/8" is cemented tosurface. At this point, either a 7"liner is run and cemented across theArun or the well is completed openhole. Some of the 7" wells have theupper, leaner condensate zone, casedoff to allow only the richercondensate zones to contribute. Thisdepends on the relativepermeabilities of the exposed zonesand the objectives of the well.

A permanent, hydraulically set packeris run on 7" tubing and set justabove the 9-5/8" casing shoe or 7"liner top to isolate well fluids fromthe production casing. A non­corrosive, oil based packer fluid isused in the tubing/casing annulus.

(Fig. 3).

ftBig Bore ft Design and QualificationTesting

Prototype equipment design, testing,and manufacture represents a major rolein the success of the "Big Bore"project. This most critical step inthe development of the project wasrequired to safely complete the wellsand ensure proj ect success. Followingis a discussion of the key components.

Wellhead

The 410 stainless steel wellheadassembly is supported by 20" surfacepipe and can suspend and seal on boththe 13-3/8" production casing and the9-5/8" tubing. Mandrel hangers wereused on both the 13-3/8" c"asing and 9­5/8" tubing to ensure a fullS, 000 psirating both internally and externally.Emergency equipment is also availableto suspend on 7" or smaller productiontubing if needed. This capabilityallows smaller tubing to be run in thefuture to optimize well deliverabili tyas formation pressure decreases. Allcomponents in the system were APImonogrammed to 5,000 psi service ratingfor the Arun application.

Christmas Tree Assembly

The christmas tree received the samelevel of QA and QC scrutiny as thewellhead and all component parts areAPI monogrammed. The 9" bore tree andwellhead are over 20 feet tall whenfully assembled. Due to thermalexpansion of the flowline and the risk

Paper #25384 W.L. CANNAN, et al 7

of failure near the surface, thebending moment of the wellhead wascarefully studied. This studyresulted in utilizing an integralflange on the lower block mastervalve to increase strength in thisarea.

All of the 9" bore valves on the treeare hydraulically actuated and fail­closed to provide quick reliableaction. "Big Bore" trees used thefirst 9" gate valves qualified to API6A Appendix F PR-2 requirements andare produced to PSL-3 specifications.The 2-1/16" and 4-1/16" wing valvesare PSL-2.

A two piece, single flowloop designwas chosen to handle the high flowrates and allow for installation ofan emergency tUbing spool ifrequired. The emergency spool raisesthe assembly two feet over itsstandard height, so additionalflowloop spacers are required toadjust the flow-loop elevation. (Fig.8) . Again, all flow-loop, spacers,and connections received particularattention in their manufactureprocess. All components were fullbody stress relieved to ensuremetallurgical uniformity. (Fig.4).

13-3/8 ft X 9-5/8 ft Liner TopIsolation Packer and 10 ft LinerHanger

To accommodate the "Big Bore" design,a liner hanger that could support thetremendous incremental load producedby the thermal growth of the tubingstring and the weight of the 10"liner below was required. These

loads are calculated to be in excess of750,000 lbs.

"Big Bore" completions also required apermanent liner top isolationpacker/hanger assembly for two reasons.First the liner lap· must bemechanically secured and secondly theuse of the packer system ensures theintegrity of the annular space betweenthe production casing and the tubing.The design of the compression-set linertop isolation packer allows for thetransfer of the incremental thermalload through the packer mandrel andload sub in1to the top of the linerhanger. The packer accomplishes thiswi thout incrementally setting thepacker slips or the packing element.This eliminc3.ted the potential forfailure of the 13-3/8" productioncasing due to an incremental increasein induced load.

After the packer is set, the lowerseals stung into the liner hanger PBRremain static. Only the tUbing sealsstung into the packer PBR are dynamic.They only move during a coldstimulation or well kill operation.Space-outs and set down weights werecalculated to prevent movement duringnormal production or shut in cycles.This complete system was designed forinstallation in the vertical sectionand would require additional design andtesting for setting in deviatedwellbores.

Special mills and scrapers wereincluded in the design of the liner topisolation packer and liner hanger/PBRsystems to a.llow for proper clean outand dressing of the PBR's prior to the

8 "Big Bore" Well Completions Paper #25384A New Well Completion Technique for the Arun Field

installation of seal assemblies.

10" Float Equipment

L-80 grade steel was used due to thecorrosive Arun environment and anewly developed heavy wall connectionwas utilized to provide positivepressure integrity during hightemperature production and coolerstimulation cycles.

The float equipment for the projectwas designed to meet project demandsand was certified to meet API RP10Fclass III-C specifications (5,000psi, 400 0 F). The equipment wasmanufactured to Mobil specificationsus ing 2-1 I 4 Chrome tubes. Forcontingency purposes, the equipmentwas designed and tested to withstandfull liner weight on bottom. Theliner could then be set on bottom and

Mobil had previously tested andapproved two 9-5/8" 53.5 :fIft casingconnections. However, Mobil had neverdeveloped a connection for this size astubing. Mobil's first attempt toqualify this connection for use astubing failed, but after switching to a

9-5/a" Tubing String

Cementing Procedures

cemented in place if required. Thispresented two potential problemsduring design. It required the use ofa ported float shoe that had to supportthe full 350,000# liner weight withoutcracking. A shoe was designed andtested to meet and exceed thesecriteria. One key point on the floatequipment was that it maintained thesame degree of integrity and highstandards as all other components ofthe production tubulars.

In a standard 7" Arun completion, the9-5/8" string is single-stage cementedback to surface. This was not possiblein a "Big Bore" well. However, Mal hadperfected the single stage cementingprogram and wanted to simulate thatprocedure on a "Big Bore" liner job.This required a test program on twostandard 7" wells to collect thenecessary circulating temperature datato model and develop cementingprocedures for the 10" liner job. Dueto the wall thickness of the 10" 72tift liner conventional cementevaluation tools are not reliable.Instead, Mal relied on negative andposi tive pressure testing on the linerlap for cement evaluation.

Liner

isolation packer andsystems were closelyprovide a reliable,

10", 72# L-aO

The liner topliner hangerintegrated tosecure system.

Since the 10" liner is part of theproduction tubing string in a "BigBore" completion, it must withstandthe 7,500 psi pore pressure in theBaong shale above the Arun combinedwith the low bottom hole flowingpressure during future production.(Fig. 5). To prevent the liner fromcollapsing required the use of 10" aD72# pipe as the liner material wherethe pressure of the Baong shale ispresent.

Paper #25384 W.L. CANNAN, et al 9

anthe

dayas

whoTo

Anytime a ne1N concept is developed andimplemented training becomesextremely important factor tosuccess of the project. This wasrecognized early on and plans weredeveloped to include a threetraining session with key company,well as service company personnelwould be involved in the proj ect.achieve the maximum effectiveness in

Due to the corrosive Arun environment aplug that met all of MOl's requirementscould not be found. This required aspecial plug be designed, built, andprototype te,sted to ensure it would

satisfy all of the requirements. Theresul ting plug was designed towi thstand differential pressures of4,000 psi from above and below andtemperature extremes from 3500 to 90 0 Fas well as meeting NACE specificationsfor sour service.

Planning

Training

Due to the timing, scope and magnitudeof the proj ect and impact on the ArunField del i verabili ty, technicalspecialists from corporate headquartersprovided consultation and assistancewi th the entire project from theinitial design to final manufacturingand equipment delivery. Brainstormingsessions wer,e initiated early in theproj ect to discuss all phases andidentify critical path items.Contingency plans were developed forvirtually every aspect to provideal ternatives when required. Thishelped to expedite the project andensure that target dates were met.

9-5/8" Retrievable Bridge Plugs

different seal taper and performingextensive testing, it was deemedsuitable for the "Big Bore"application.

The 9-5/8" tubing is landed in theliner top packer/PBR system by use of

a seal assembly. This seal assemblywas designed and tested to maintainsealing integrity under adifferential pressure of 7,500 psiwi th a temperature range of 90 0 to3500 F. The seal assembly consistsof a combination of packing ringsmolded from premium seal material.The seals remain static during normalproduction/shut-in cycles and aredynamic only during a well kill orstimulation.

MOl requires a well to be securedwith two barriers below the surface,resulting in the development of a 9­

5/8" bridge plug. Since the conceptof the "Big Bore" wells includedbeing full bore with minimalrestrictions, back pressure valvepreparations and downhole nippleprofiles were not included in thewell design. This resulted in thechoice of setting a bridge plug thatcould be set on wireline and easilyretrieved with coiled tubing. Due tothe mechanics of setting andretrieval, the decision was made to

set one plug at +/- 3000' and theother plug at +/- 5500'. This wouldpermi t both plugs to be set in thestraight portion of the well,alleviating any problems associatedwi th setting or retrieval in highlydeviated wellbores.

10 "Big Bore" Well Completions Paper 125384A New Well Completion Technique for the Arun Field

the training sessions an overview ofthe entire "Big Bore" well concept,various equipment requirements, thedesign, testing, field running andhandling procedures, and field safetywere discussed.

A detailed field operations manualwas also assembled to fully documentthe special running and handlingrequirements for each component aswell as provide detail drawings for abetter understanding of the designand manufacture of the components.

On-Site Surveillance

Since many of the well componentswere new to Arun personnel keyexperts in each major area of theproject were brought in for on-sitesurveillance and assistance asrequired. The major areas being thewellhead installation, liner hangersetting and cementing, isolationpacker installation, tubular runningand handling, tubing make-up, andsecuring the wellbore to install thechristmas tree. This proved to beextremely beneficial to the successof drilling and completing the firstwell and provided a vehicle forfurther support as needed for theremaining wells.

Results

The first well was spud in January1992 and was completed and on line inMarch 1992. To date six wells havebeen drilled and five of them havebeen completed. Four wells will bedrilled in early 1993 to complete the

"Big Bore" program. The average testresults from the first five "Big Bore"completions were 126 MMSCFD versus anaverage of 70 MMSCFD for recent 7"completions. One well, C-II-21,tested at a rate of over 217 MMSCFD.(Fig. 6). The higher production ratesare attributed not only to largertubing size with less friction, butalso longer open hole sections. "BigBore" wells were designed with highangle, extended reach open holesections to maximize deliverability.

The original estimates predicted thatthe "Big Bore" wells would produce anaverage of 70 % more than a standard 7"completion. However, this predictionwas based on standard Arun open holelengths and the existing reservoirpressure in 1990. Figure 7 shows theactual composi te IPR for wellscompleted with 9-5/8" tubing versus thesimulated results with 7" tubing. Thisclearly demonstrates the substantialproduction increases these wells arecapable of.

We have had tremendous success with the"Big Bore" completions in increasingwell deliverability and meetingproduction requirements. These highrate completions along with otherproduction improvement projects haveprovided more than sufficientdeliverability to achieve ourproduction targets at reduced wellcount and costs.

There have been no mechanical failures,and the results have closely matchedpredictions. This is quite an

Paper 125384 W.L. CANNAN, et al 11

accomplishment considering all of thenew equipment and technologyinvolved. To our knowledge, the "BigBore" completions are the largestbore, gas production wells in theworld [5].

Excellent teamwork and cooperationled to the successful completion ofthe first "Big Bore" well in the ArunField.

2) M.U. Alaydrus and T.P. Bordelon :"Boosting Deliverabili ty in the GiantArun Gas Field", SPE Asia PacificConference, Perth, Western Australia,4-7 November 1991.

3) S.A. Cassinis: Workover Review forHot, High-Pressure Gas Wells", SPEJournal of Petroleum Techn·ology, pages1491-1496, August 1985.

4) H. Husein and D. Steel: "HighTemperature High Rate Gas WellCompletions: A Learning Experience",Offshore South East Asia conference,Singapore, February 2-5, 1988.

Acknowledgments

The authors thank the management ofPertamina and Mobil Oil IndonesiaInc. for the permission to publishthis paper. The work described hasbeen a true team effort between MobilOil Indonesia and Mobil Explorationand Producing Technical Services,involving Arun engineers, geologists,and operations personnel, as well asextensive support from severalContractors and Service Companies.

The benefits gained by the teamworkinvolving extensive design, testing,quali ty control procedures, and newtechnology developed and applied onthis project will be utilized forsimilar proj ects of this scope andmagnitude in the future.

References

1) W.L. Cannan, A.R. Jennings, T.P.Bordelon, and S.Sardjono: "IncreasingArun Well Deliverability ThroughEffective Acid Fracturing", SPEInternational Meeting on PetroleumEngineering, Beijing, China, 24-27March 1992.

5) Management SummaryReport, Mobil Exploration andTechnical Services, Inc., "9Completions: The Big BoreOctober 1992.

TechnicalProducing5/8" ArunProject",

SPE253 84

No

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FIGURE 1 - Arun Field Location

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FIGURE 3 - 7- VI Big Bore ~ompletlon

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FIGURE 4 - BI; Bore X-Mal TrH A••embly-------_---1

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'...-Fracture\ Gradient,,\"\,\

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~ , p_re_s_s_u_re_'_E_q_U_iV_'_P_P_9_______________ I_ FIGURE 5 - Pore Pressure &: Mud Weight Curves ~

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200010 30 50 70 90 110 130 150

MMSCF/0

FIGURE 7 - Typical Big Bore Well Performance

DIIIWIIO MIl ClllI'U:'IlOII r COII'i£lIClII ...1/1" COlIPU:1lClM VAlIIAHCI

Productiv. Area I Acres 23,240 (-I (_I J..!!..LMaximum Gas Pay , Feet 1,050 E.UCAIl + 1C-tIIAS 'l'IlU 311 1.110 lIZ

1 IIQH 11-.0 !'I'\ on)Average Initial Water Saturation , Percent 10.7 I'ACICP + ./Ous 13 410 477

P\.OW CCU'IJNO 14 (14)

Av.rage Poroelty Percent 16 ... + Il-I.NOIIO ..."u;s 1O (1O)

7100 n. 1:'-3/1", cso. 540 In 135

Initial Re.ervoir Pr•••ure , Psig 7,'00 (72f L-IO, IIIT'Il (721 L-IO. III:W v~)

1110 " ....1/1·,l3.1f,I.-1Cl,IUlT 122 (122)

Current Re.ervoir Pr...ure Psi 3000 4100 ". 10". lJl, L-IO. VNA 415 4Ill

lIIOO " ...../1•.•3.110 L-IO,v~ ,)41 ,)41

Re.er/oir Temperature • Deg. F 350 ...."... CDOlllNO 10 H (II)

NO 1M 171 1,007 IttRe.ervolr Datum , Feet Subsea 10,050 ( ,)4 ClAVI I (. DAVI)

15OlHlJlS US4 1.tJ4

CO2 Concentration ." -...TOTAL &,000 1,100 ""t."dOOH2S Concentr\2tlon , PPM 50 I'UMJN[ + ACCIEDllMS 1.000 1,000

)~TAI. 1,000 7,500 1,100

TABLE 1 - Basic Reservoir Data-Arun Field TABLE 2 - 7" vs Big Bore Tubing CompletionCost Comparison