Project Management of Offshore Well Completions

4 Oilfield Review

Project Management of Offshore Well Completions

Iain CaulfieldStephen DyerY. Gil HilsmanRosharon, Texas, USA

Kerby J. DufreneJose F. GarciaPort of Spain, Trinidad and Tobago

John C. Healy, Jr.ConsultantHouston, Texas

Matthew MaharajJohn PowersBPPort of Spain, Trinidad and Tobago

Denis StaderoliLuanda, Angola

Mark StrackeKuala Lumpur, Malaysia

Tammy WebbMurphy Oil CorporationKuala Lumpur, Malaysia

For help in preparation of this article, thanks to Mary JoCaliandro, Sugar Land, Texas; and Mark Teel and JeremyWalker, Rosharon, Texas.e-Fire, FIV (Formation Isolation Valve), GeoMarket, PURE,QUANTUM maX, RST (Reservoir Saturation Tool), SenTREE,Trip Saver and WellWatcher are marks of Schlumberger. Alternate Path is a mark of ExxonMobil; this technology islicensed exclusively to Schlumberger.

The global share of oil and gas production from offshore wells is increasing rapidly.

As offshore projects move into deeper waters, economic viability requires efficient

design, testing and installation of well completions. Two case histories from Trinidad

and Malaysia demonstrate the value of close cooperation between operators, service

companies and equipment manufacturers.

Global annual energy consumption has morethan tripled during the last 50 years, mainlybecause of demand growth in developingcountries. These countries will use more energyas their populations grow and their standards ofliving improve. The lack of onshore opportunitiesto meet the growing demand has driven E&Pcompanies to increase the development ofoffshore oil and gas fields. As a result, offshoreproduction is increasing rapidly, and output isexpected to double over the next five years

(below). Most of the reserves are located in deepand ultradeep water. At present, the principaldeepwater fields are located in the Gulf ofMexico, offshore Brazil, West Africa, SoutheastAsia and the North Atlantic margin.1

From drilling to abandonment, and even on todecommissioning, offshore wells present a myriadof technical challenges—particularly in deepwater. The high productivity and inaccessibility ofthese wells require robust completion design,flow assurance, equipment reliability and

1. According to the US Minerals Management Service(MMS), deepwater wells are located in water depths of1,000 ft [305 m] or greater. Ultradeepwater begins at waterdepths of 5,000 ft [1,520 m] or more. For more ondeepwater production projects: Robertson S, Westwood Rand Smith M: “Deep Water Enjoys Growth Surge,” Hart’sE&P 79, no. 5 (May 2006): 50–52.Carré G, Pradié E, Christie A, Delabroy L, Greeson B,Watson G, Fett D, Piedras J, Jenkins R, Schmidt D,Kolstad E, Stimatz G and Taylor G: “High Expectationsfrom Deepwater Wells,” Oilfield Review 14, no. 4 (Winter 2002/2003): 36–51.

> Historical and projected oil production from onshore, shallow-water anddeepwater fields. Experts estimate the proportion of offshore oil producedfrom deepwater fields will grow to 25% by 2015. The United States GeologicalSurvey publication, World Petroleum Assessment, estimates that more than300 billion bbl [48 billion m3] of oil remain to be discovered offshore. [Adaptedfrom Robertson S: The World Offshore Oil and Gas Forecast. Canterbury,England: Douglas-Westwood Ltd. (2006).]

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longevity. Economic viability requires maximizingproduction rates and ultimate recovery in a safeand environmentally sound manner. Deepwaterdrilling vessels currently command rates fromUS $250,000 to $750,000 per day; therefore, wellcompletions must be installed efficiently tominimize rig time. Completion design andequipment reliability are especially criticalbecause the cost to reenter an offshore well forworkover or repair can exceed US $6 million.

In this article, we examine advanced offshorecompletions, from the initial planning stagethrough equipment manufacturing, testing andinstallation. First, we discuss basic completiontechniques and the collaborative project-management process. Then, case histories fromTrinidad and Malaysia will demonstrate thebenefits of collaboration.

Introduction to CompletionsA well completion is composed of tubulars, toolsand equipment placed in a wellbore to convey,pump or control the production or injection offluids.2 There are several ways to classify wellcompletions. The most common criteria includethe following:• wellbore-reservoir interface (openhole or

cased-hole)• producing zones (single or multiple)• production method (naturally flowing or artifi-

cially induced).Openhole completions are feasible only in

reservoirs with sufficient formation strength toprevent caving or sloughing. The absence of casingmaximizes formation contact with the wellbore.To prevent formation solids from entering theproduction stream, slotted screens or perforatedliners may be placed across openhole sections(above). Openhole completions minimize well-completion expenses and allow flexible treatmentoptions if the well is deepened later.

In a cased-hole completion, casing is setthrough the producing reservoir and cementedinto place. Fluid flow is established byperforating the casing and cement sheath,thereby opening and connecting the reservoir tothe wellbore. The perforation tunnel usuallyextends past near-wellbore formation damagecaused by drilling, exposing undamaged rock andallowing unhindered reservoir production (see“Optimal Fluid Systems for Perforating,” page 14).

In a typical single-zone completion, only oneconduit or tubing string is involved, and a packerestablishes hydraulic separation between thetubing string and casing or liner (next page). Thepacker is often considered to be the mostimportant tool in a production string because itmust provide a long-term hydraulic barrier thatis compatible with reservoir fluids and thewellbore annular fluid.

6 Oilfield Review

> Examples of openhole and cased-hole completions across a single zone. In openhole completions, the productioncasing or liner is set and cemented in the reservoir caprock, leaving the wellbore open across the reservoir (left andcenter). The well at the center includes a slotted-liner across the reservoir that excludes formation solids from theproduction stream. In cased-hole completions (right), the perforations provide a selective conduit from the reservoir tothe wellbore, and serve as a portal for injection of stimulation fluids during acidizing or hydraulic fracturing operations.

Productioncasing

Perforations


Spring 2007 7

Several accessories are frequently installedabove and below the packer. A safety valve,typically situated toward the top of theproduction tubing but below the mudline, is anemergency well-flow-control device to protectpersonnel, the reserves and the environmentagainst wellhead or equipment failure. Justabove the packer, a sliding sleeve on theproduction tubing allows completion-fluidcirculation through the tubing-casing annulus.Annular-fluid maintenance is necessary topreserve proper hydrostatic pressure above thepacker and prevent corrosion. Landing nipplesare profiled receptacles in which plugs or chokesmay be landed to control fluid flow, or recordingdevices installed to monitor production. Slottedor ported production tubing allows hydrocarbonsto enter the tubing string. A wireline entry guideensures smooth retrieval of wireline tools backinto the tubing string.

Multiple-zone completions are designed toallow production from more than one interval.There are many possible configurations that allowsimultaneous production from all of the zones orselective production from certain zones. Multipleproducing zones are separated for three principalreasons: government regulations often requireoperators to monitor production from each zone;high- and low-pressure zones are isolated toprevent crossflow; and crude oils from differentzones may be chemically incompatible, formingsludges or precipitates if allowed to commingle.

Wells completed in reservoirs that canproduce without assistance are typically moreeconomical. However, in high-pressure, high-temperature (HPHT) applications, specializedengineering and equipment design are requiredto achieve production in a safe manner. In manycases, wells may flow naturally at first, withsubsequent assistance provided by artificiallifting methods as the reservoir is depleted.These considerations are typically included aspart of the initial planning process to avoidunnecessary expense and production inter -ruption. Artificial lift completions involve gas lifttechniques, or specialized electrically- ormechanically-driven submersible pumps.3

2. For more on well-completion technology: Allen TO andRoberts AP: Production Operations, 4th ed. Tulsa: Oil &Gas Consultants International, Inc. (1997).Economides MJ, Watters LT and Dunn-Norman S:Petroleum Well Construction. New York City: Wiley (1998).

3. Gas lift is an artificial lift method in which gas is injectedinto the production tubing to reduce the hydrostaticpressure of the fluid column, allowing the well toproduce normally with its own formation pressure. Formore on gas lift: Bin Jadid M, Lyngholm A, Opsal M,Vasper A and White TM: “The Pressure's On:Innovations in Gas Lift,” Oilfield Review 18, no. 4 (Winter 2006/2007): 44–53.

> Single-zone and multizone well completions. In the single-zone completion (left), a packer forms aseal inside the production casing that hydraulically isolates the tubing string from the region abovethe packer, called the “backside.” The backside contains a completion fluid with corrosion inhibitorsto prevent casing corrosion. Below the packer are various devices for controlling fluid flow andallowing easy retrieval of wireline tools. The multizone completion at the center employs two packersthat separate the producing zones, but the fluids from both zones are allowed to commingle duringproduction. The multizone completion on the right employs a special dual-string packer that maintainsfluid separation from each producing zone. The single-string packer isolates the lower zone and allowscommunication to the surface through the long tubing string. The dual-string packer isolates the upperzone from the annulus while allowing communication to the surface up the short tubing string.

Surface casing

Annulus pressure

Production casing

Packer Packer

Dual-stringpacker

Packer

Landing nipple

Formation pressure

Perforations

Wireline entryguide

Perforatedproduction tubing

Single-stringpacker


At the top of all well completions is anassembly of valves, spools, pressure gauges andchokes commonly known as a tree (above). Thetree prevents the release of oil and gas from thewell into the environment, and directs andcontrols fluid flow from the well. In addition, thetree contains components that allow insertion ofequipment such as wireline tools into the well.Another vital device at the wellhead during wellcompletions is the blowout preventer (BOP)—avalve that may be closed to prevent loss of well

control. Many BOPs can be actuated remotely,and are critically important to the safety of thecrew, rig and wellbore.

Offshore, the tree location and design are afunction of water depth and platform availability.In water depths less than about 6,000 ft[1,830 m], trees can be located atop an offshoreplatform or spar.4 These “dry trees” areadvantageous because they allow wireline accessto the well during production. When the seafloordepth exceeds 6,000 ft, current technology does not allow platform-based offshore installations.

Therefore, a “wet tree” must be placed on theseafloor. Wet trees are typically more complexthan conventional platform completions, andnormally include provisions for pressure andtemperature monitoring, and sophisticatedhardware for automatic fluid-flow control.Because wireline access on subsea trees is costly,engineers install permanent downhole pressure,temperature and flow-monitoring equipment toanticipate or avoid problems.5

Subsea trees may be either vertical orhorizontal (above). Generally, vertical trees areinstalled after the production tubing has beenplaced in the well. Therefore, if repair is needed,the tree can be retrieved without removing thecompletion. Their main limitation is the dif ficultyof well intervention after installation. Horizontaltrees, on the other hand, are designed to allowengineers to finish a completion after the tree hasbeen installed. As a result, production tubing andother devices can be run into the well after thetree is in place. Workovers can be performedwithout removing the tree, reducing time andexpense while improving safety. In addition,horizontal trees are more compact.

8 Oilfield Review

>Wellhead tree and blowout preventer (BOP). The tree controls fluid flow out of the wellbore andallows controlled insertion of equipment such as wireline tools into the wellbore (left). The BOPprevents loss of well control during drilling and completion operations (right).

Kill wingconnection

Kill wingvalve

Mud returns

Blind rams

Shear rams

Kill Choke

Stripper

Drill floor

BOP stack

Tree cap and gauge

Injector head

Tree adapterSwab valve

Upper master valve

Lower master valve

Tubing head adapterProduction string

Production wing valve

Surface choke

To production facilities

Annularpreventer

> Subsea trees. Vertical trees (top) are loweredonto the well after the production tubing is inplace. Horizontal trees (bottom) are more compact,and can be installed before the well completionis finished. The trees are built to withstand highhydrostatic water pressure at the seafloor andthe corrosive effects of seawater. (Photographscourtesy of FMC Technologies Inc.)

> Integrated offshore-well completion-team organization. Close cooperationbetween Schlumberger and client personnel is essential to ensure a timely flowof information, establish project-management procedures and define the projectobjectives for all parties. Among the issues to consider are rig scheduling tomeet first-oil requirements, detailed component and completion engineeringdesign, geographic locations of team members, and client participation inengineering design and manufacturing.

Engineering

Manufacturing

Telemetry projectteam

GeoMarketsupport

Schlumberger project team Operator project team

Project manager Project leader

Project engineer,lower completion

Technical support,lower completion

System integration testing(SIT) project engineer SIT coordinator

Telemetry projectmanager

Senior petroleumengineer

Field servicemanager

Engineeringcoordinator

Delivery coordinator

Operationalcoordinator

Offshore supervisors Operational engineers

Quality engineer Quality engineer

Project engineer,upper completion

Technical support,upper completion


Spring 2007 9

Planning and Execution of Offshore CompletionsAchieving a successful offshore completionrequires a closely integrated, multidisciplinaryproject-management team comprising personnelfrom the operating company, drilling and service

companies and equipment manu facturers(previous page, bottom). After the contracts aresigned, at least two years are usually required for the team to analyze technical parameters and obstacles, determine the completion strat-egy, design and manufacture the completion

equip ment, perform thorough testing and finallyinstall the completion in the well (above).

4. Carré et al, reference 1.5. Christie A, Kishino A, Cromb J, Hensley R, Kent E,

McBeath B, Stewart H, Vidal A and Koot L: “SubseaSolutions,” Oilfield Review 11, no. 4 (Winter 1999/2000):2–19.

> Typical offshore-completion project organization. After contracts are signed, at least two years are usuallyrequired to complete all the tasks and begin production (top). The projects are divided into nine discrete stepsfrom initial planning to production and maintenance (bottom). Reviews are conducted after the completion ofeach stage, and full agreement between Schlumberger and the client is required before proceeding to the nextone. Acronym definitions: BOD–basis of design; CWOP–complete well on paper; EOWR–end-of-well report;FMEA–failure modes effect analysis; HAZOP–hazard and operability study; ITT–invitation to tender; PO–purchaseorder; PP–project plan; Sub-Assys–subassemblies; TPS–third-party suppliers; SIT–system integration testing.

Planning Engineering &procurement

Installation andprecommission

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in placeEngineering

approval

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acceptanceFile

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Screening,ranking andprioritization

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Transitionand planning

Processstartup

Project planpreparation

Project planreview andapproval

Processstartup

SIT

Installation, pre-commission and

client acceptance

Transportationand receipt of

equipment

Manufacturing

Processstartup

Qualitycontrol

Scopeverification andfinal acceptance

Transportationand receipt of

equipment

Engineering andprocurement

Installation andprecommission

Processstartup

Preoperationalplanning

Startup andcommissioning

Projectcompletion

Contractcloseout

Postprojectreview

File archive

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Preliminaryengineering and

solicitation

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Final designreview andapproval

Operation andmaintenance

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Prototypeproduct

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3 to 9 months 3 to 6 months6 to 24 months

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InstallProcedures

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Offshore completion design and installationinvolve several stages. Before proceeding from onestage to the next, all team members must approvethe work that has been performed to date. Froman economic standpoint, the efficiency of thisprocess is as important as the technology.

During the planning stage, engineers evaluatethe envelope of conditions within which thecompletion must operate. Principal parametersinclude geology, pressure, temperature, produced-fluid properties, anticipated production rates,flow-assurance issues and predicted well life.After completing the analysis, the team generatesa robust and reliable completion design that canbe installed efficiently. After design approval,procurement and manufacture of the completioncomponents begin.

Before the equipment is shipped to thewellsite for installation, thorough systemintegration testing (SIT) should be performed toverify that the completion performance will meetor exceed the agreed-upon specifications, andthat any unforeseen interface-compatibilityissues are identified. SIT also provides a “dryrun” for potential completion designs, allowingengineers to develop more efficient installationprocedures, test contingency options andultimately reduce nonproductive time.

SIT is conducted under simulated conditionsequivalent to those in the actual well. To meetthis testing requirement, Schlumberger openedthe Cameron (Texas) Test Facility (CTF) in2004.6 The ISO-9001 certified facility allowsengineers to assemble the completion exactly asplanned for a specific well, install the completionin an equivalent borehole and verify propersystem-component performance (above right).7

Completion design, manufacturing and SITare guided by failure modes effect analysis(FMEA)—a method to identify potential failuremodes for a product, process or system, assessthe risks associated with the failure modes, rankthe issues in terms of importance, and identifyand perform corrective actions to address themost serious concerns. Widely practiced in manyindustries, notably the automotive and aerospacesectors, FMEA enables engineers to assemble acritical items list (CIL) comprising failure modesthat would have a catastrophic effect. In thecontext of well completions, the CIL identifieshigh-priority items requiring evaluation duringthe SIT process.8

Key well-completion stakeholders witnessSIT in person or remotely, and everyone must besatisfied with the total system performance.After all approvals have been secured, the well-completion hardware is shipped to the wellsite

for preparation, installation and commission.The following case histories illustrate how thisclosely integrated project-management approachhas led to success in offshore well completions.

Completing High-Rate Gas Wells in TrinidadBP Trinidad and Tobago (BP) developed theCannonball field in offshore Trinidad as asource for liquefied natural gas (LNG) plants.Located 22 miles [35 km] from Galeota Point, ata water depth of 231 ft [70 m], the producingsandstone known as the 33 sand is about 280 ft[85 m] thick with 185-mD permeability and 19%porosity. The reservoir temperature is 220°F[104°C] at 12,350 ft [3,764 m] total verticaldepth (TVD). To meet increasing LNG demand,BP and Schlumberger collaborated on theconstruction and completion of three wells with21° to 34° deviations.9

Under normal circumstances, the rockstrength of the producing formation, greaterthan 2,000 psi [13.8 MPa], would be high enoughto allow a sandface completion without sandcontrol. However, this formation was expected to

be prolific and, at an anticipated production rateof 300 MMcf/d [8.5 million m3/d] per well, FMEAshowed that even a small amount of sandproduction would cause catastrophic damage tothe completion hardware and the surfaceequipment. Therefore, to prevent sandproduction, the team chose Alternate Pathtechnology, a system of screens and shunt tubes,to place a complete and homogeneous gravelpack.10 They also chose high-rate water packingas the gravel-placement method.

In similar gas fields in Trinidad, BP achievedsuccess with openhole-gravel-pack (OHGP)sandface completions with no additionalproduction packer. This simple approach ensuredminimal skin values and high flow efficiencies;therefore, the completion team chose the samestrategy for three new wells.11 However, in light ofthe high production rates, BP decided that theopenhole packers must be rated V0, the highestpossible leak-resistance rating for a packer in ISOStandard 14310. At the time of equipmentselection in 2004, Schlumberger had just released

10 Oilfield Review

> System integration testing (SIT) at the Cameron Test Facility (CTF) in Texas.The CTF, which encompasses several hundred acres, became operational in2004. The site is equipped with a full-capability drilling rig that can produceboreholes with more than 6,000 ft of horizontal reach. The rig is mounted on railsfor convenient access to well slots equipped for openhole and cased-hole tests.Cameron is an ideal testing location because the formations penetrated by CTFwells exhibit diverse porosities, permeabilities and mineralogies, allowingrealistic testing over a wide range of conditions.


Spring 2007 11

a 103⁄4-in. by 6-in. QUANTUM maX gravel-packsystem for HPHT conditions, a hydraulically setpacker that met the V0 standard. Therefore, theteam decided to incorporate it in the primarycompletion design (below).

In addition, the new packer had to bequalified for use with the gravel-pack system.Consequently, a successful SIT was a necessitybefore the OHGP system could be approved foruse at the Cannonball field. Two SITs wereperformed between the end of 2005 and early2006. Some problems were encountered duringthe first test that resulted in the use of a newwellbore-cleanout string during the second test.In addition, a FIV Formation Isolation Valve toolwas included below the packer to protect thesand-control assembly from completion-fluid

damage. The second test was successful, and thecompletion design was approved for installationin Trinidad.

On the first well, CAN-01, problems occurredwhen attempting to set the packer, so it was pulledout of the hole and inspected. Within 48 hours, theinvestigation team determined that a carbonateplug in the wash pipe prevented the packer fromsetting. Engineers ran a backup assembly andcompleted the job successfully as designed afterthe hole had been thoroughly cleaned.

The completion program was modified toinclude a more thorough cleaning of theopenhole interval to prevent recurrence of theplugging problem. The team also decided to rungravel-pack logging tools, such as the RSTReservoir Saturation Tool device, to provide

valuable troubleshooting data on all future gravelpacks. In addition, they observed shunt-tubeactivation at the conclusion of the gravel-packoperation in the first well, confirming theimportance of Alternate Path technology in thecompletion design.

On the second well, CAN-02, Alternate Pathtechnology paid dividends with almost 50% of thegravel-pumping job completed through the shunttubes. During drilling, a large rathole was leftbelow the casing. During the gravel-packoperation, a premature screenout occurred whena sand dune formed in the rathole and collapsedafter reaching critical mass. Fortunately, theshunt tubes performed as designed and the wellwas completed five days ahead of schedule.

The third well, CAN-03, had both problemsobserved in the first two wells—wash-pipeplugging and early screenout. However, with thelessons learned, best practices and a robustoverall project design, CAN-03 was completedeight days ahead of schedule.

The Cannonball completion project endedbelow budget, with only 16.2% nonproductivetime. The efficient completion of CAN-02 and CAN-03 resulted in a cost savings ofUS $1.25 million and US $2 million, respectively.In addition, because the V0-certified packersallowed the three wells to produce at their fullpotential, BP saved an additional US $800,000 by eliminating the production packer andassociated joints, assembly, testing and rig time.The Cannonball gas platform began production in March 2006, and is currently producing800 MMcf/d [22.7 million m3/d] from the three wells—the most productive in BP’s offshore portfolio.

> Final completion design for the Cannonball field (left). The well is completed open hole across theproducing zone with Alternate Path gravel-pack screens providing sand control. Uphole, a V0-ratedQUANTUM maX hydraulically-set packer (top right) provides isolation that can withstand high gas-production rates. The packer is deployed on a gravel-pack service tool, set with tubing-to-annulusdifferential pressure. It can be retrieved on drillpipe. In addition, a FIV Formation Isolation Valve(bottom right) protects the sand-control assembly from completion-fluid damage. The FIV tool is a fullopening mechanical ball valve that is mechanically opened and closed as needed using a shiftingtool. The compressed-nitrogen-activated Trip Saver one-trip operation feature allows the operator to open the valve without conventional intervention techniques.

Shifting toolengaged

QUANTUMmaX packer

Shifting toolFIV tool

Trip Savertool opened

FIV closed

Crossover-flow coupling

Nipple

Safety valve

Sand-controlscreens

6. For more on the CTF: Arena M, Dyer S, Bernard LJ,Harrison A, Luckett W, Rebler T, Srinivasan S, Borland B,Watts R, Lesso B and Warren TM: “Testing OilfieldTechnologies for Wellsite Operations,” OilfieldReview 17, no. 4 (Winter 2005/2006): 58–67.

7. ISO standards are developed by the InternationalOrganization for Standardization. See http://www.iso.org(accessed March 19, 2007).

8. For more on FMEA: Stamatis DH: Failure Mode andEffect Analysis: FMEA from Theory to Execution.Milwaukee, Wisconsin, USA: American Society forQuality (1995).

9. Powers J, Maharaj M, Garcia JF and Dufrene K: “Win, Place, Flow Works in Trinidad,” Hart’s E&P 79,no. 11 (November 2006): 49–50.

10. For more on Alternate Path technology: Ali S, Norman D,Wagner D, Ayoub J, Descroches, J, Morales, H, Price P,Shepherd D, Toffanin E, Troncoso J and White S:“Combined Stimulation and Sand Control,” OilfieldReview 14, no. 2 (Summer 2002): 30–47

11. Skin factor is dimensionless and indicates theproduction efficiency of a well by comparing actualconditions with theoretical or ideal conditions. A positiveskin value indicates formation damage or influences thatare impairing well productivity. A negative skin valueindicates enhanced productivity, typically resulting from stimulation.


Developing Resources in Offshore MalaysiaMalaysia has some of the most abundanthydrocarbon reserves in Asia. With total provenreserves of 4 billion bbl [640 million m3] of oiland 87 Tcf [2.5 trillion m3] of natural gas, thecountry has long been a net exporter of bothcommodities. However, at the present rate ofconsumption, Malaysia will have to beginimporting oil by 2015 unless new production isbrought on line. PETRONAS, the nationalMalaysian oil company, is responding with anambitious program to increase production by 3% per year over the next 10 years to at least720,000 bbl/d [114,400 m3/d] by 2010. With this goal in mind, PETRONAS acceleratedexploration and discovered that most of the newoil lies in deep water.

In 2002, Murphy Oil Corporation, aPETRONAS franchisee, discovered the Kikehfield in the deepwater area of Sabah in EastMalaysia. Kikeh lies 4,300 ft [1,311 m] beneaththe South China Sea, and the producingsandstones are estimated to contain severalmillion bbl of recoverable oil. The formations areslightly overpressured, with bottomholetemperatures less than 200°F [93°C], andpermeabilities between 300 mD and 1,000 mD.

To develop the field, plans include drilling upto 19 subsea wells and another 20 dry-tree wellsfrom a spar supported by a drilling-tender unit—a more efficient method that will enable MurphyOil to begin producing oil only five years afterdiscovery. Due to start production in 2007, Kikehwill eventually produce more than 100,000 bbl[15,900 m3] of oil per day, accounting for almost17% of Malaysia’s 2010 production goal.

Both the subsea and spar wells include oilproducers, water injectors and a gas injector. Tomaintain production, the water injectors willoperate at a field rate of approximately200,000 bbl [31,800 m3] per day, and the gasinjector is capable of more than 100 MMcf[2.8 million m3] per day.

After more than a year of well design anddevelopment planning, PETRONAS awarded themajor contracts for the Kikeh completions. Thedevelopment strategy involved applying provencompletion technologies whenever possible.However, several new tools and techniques werenecessary to achieve Murphy’s goals:safeguarding the reservoirs during completionoperations, protecting the environment,maximizing well productivity and using the mostefficient and cost-effective procedures.Achieving the last goal required devising ways tominimize the number of equipment trips anddays required to perform the completions.

Murphy’s Completion and SubsurfaceReservoir Engineering departments performedextensive rock-strength studies before selectingthe basic sandface-completion designs. Testresults indicated that sand control was required across the upper two of the threeprincipal producing sections. Murphy engineersspecified expandable sand screens in cased holes

for the injectors and in open holes for theproducers (below).

Schlumberger and Murphy engineers alsoselected the PURE perforating system for cleanperforations to achieve skin factors less than2.0.12 Combining a QUANTUM maX packer, a FIVtool and tubing-conveyed eFire electronic firinghead systems makes it possible to perforate the

12 Oilfield Review

> Schematic diagram of a Kikeh oil producer (left). The QUANTUM maXpackers, FIV tool and tubing-conveyed eFire electronic firing head systemsallow engineers to perforate the wells, perform reservoir analysis and isolatethe perforations from completion fluids during a single trip. The completion is also equipped with WellWatcher real-time reservoir and productionmonitoring technology including permanent quartz gauges that are designedto operate for 10 years without maintenance (bottom right). To accommodateperiodic chemical injections to prevent scaling, hydrate or wax deposition,Dual-Check Chemical Injection Mandrels (DCIN) are installed at strategiclocations (top right). The mandrels are one-piece devices fabricated from acorrosion-resistant alloy. Dual-check valves provide a reliable leak-proofseal for both liquids and gases.

Tubing hanger

QUANTUMmaX packer

Permanent quartzgauge mandrel

Tubing isolationvalve (TIV)

QUANTUM packer

DCIN Dual-CheckChemical Injection

Mandrels

QUANTUM packer

FIV FormationIsolation Valve


Spring 2007 13

wells, perform reservoir analyses with injection-test programs and isolate the perforations fromcompletion fluids—all on a single trip. Formaximum reliability, the perforating system issupported by an independent pressure-activatedfiring system. This technique saves valuable timewhile offering maximum reservoir protection and exploitation.

In addition to the latest perforating and FIVtechnologies, the Kikeh completions includemultiple-control-line ported packers set with anonintervention tubing isolation valve (TIV)system, again offering rig-time savings whilepermitting full completion-integrity testing andconfirmation. The TIV and FIV combinationallows engineers to fully test subsea-tubing-hanger integrity and the deepwater completion-installation workstring without intervention ortime-consuming surface testing.

To prevent expensive interventions, or atleast minimize their magnitude, Murphy Oil mustnot only manage well production and injection,but also detect potential problems at an earlystage. Therefore, the Kikeh completions includeWellWatcher real-time reservoir and productionmonitoring technology involving permanentquartz gauges, and subsea and surface-tree dataacquisition and transmission systems. Thesecomponents are designed to operate 10 yearswithout maintenance.

To protect the environment and Murphy Oil’sfield infrastructure during completion andproduction operations, engineers chose TRC-IIsubsurface safety valves. The valves feature twoseparate and complete piston systems connectedby individual control lines, offering redundancyand long-term reliability.13 Fouling will beprevented because the valves can be placed atdepths greater than 12,000 ft [3,858 m], wellbelow hydrate- or paraffin-deposition zones. AtKikeh, engineers installed the TRC-II valves at5,790 ft [1,765 m] below sea level. Nevertheless,the Kikeh completions will still require chemicalinjections to inhibit potential scale, wax andhydrate deposition. The Dual-Check ChemicalInjection Mandrel (DCIN) provides this capability.

All of the completion technologies described inthis article depend on reliable equipment to installthe completion hardware far below the ocean’s

surface. For maximum security during theseoperations, Murphy decided to install a modifiedSenTREE 7 subsea well control system for theinjectors. Subsea producers use the fully capableSenTREE 7 system with test-tree valve modules for well access and control. If difficulties areencountered during installation of subseaproducer wells, the control system provides a 15-sresponse time to shut in the well and disconnectthe landing string. As the various completioncomponents are run into the well, the operator hasdirect hydraulic control of down hole valves and thecompletion system even before installation iscomplete. This flexibility not only reducesoperating costs, but also offers contingency optionsshould unforeseen situations arise.

Before the completion components wereshipped to Malaysia, a thorough SIT program wasconducted. The results were successful, givingSchlumberger and Murphy confidence in thecompletion plan. Less than one year later thefirst equipment began to arrive. Within sixmonths, the first completions were installed, amajor accomplishment made possible by closecooperation between the Murphy Oil drilling andcompletions groups and Schlumberger comple -tions, perforating, subsea and testing personnel.

During 2006, initial well performancevalidated the completion architecture selected byMurphy and Schlumberger, and no major designchanges have been necessary to achieve thecompletion objectives. Nevertheless, furthercollaboration and optimization have taken placeto shorten field-development time and improveoperations. For example, the presence of severalpressure-operated TIV and FIV units requiresclose monitoring of all pressures applied to thewell, regardless of actual pressure, to predict andprevent unexpected tool activations. This permitscompletion personnel to make necessaryadjustments before beginning a service operation.

Kikeh’s combined spar and subsea-wellapproach is unique. The subsea wells allow asmall spar size, reducing infrastructure costs andinstallation time. The dual approach also allowssimultaneous spar and subsea drilling, pipelineinstallation and construction of other facilities.This latter development philosophy hasdramatically decreased the time to market ofMurphy’s product, while maximizing theefficiency of the development through sharedresources and fit-for-purpose techniques. In fact,the Kikeh development will be one of the raredeepwater fields to proceed from discovery to oilproduction in five years.

Continued Development of Integrated Offshore CompletionsThe case histories presented in this articleillustrate the complexity and technicalchallenges of today’s offshore completions,especially in deep water. Close integrationbetween the service company and operator iscritical to achieve success in a timely andeconomic manner. In addition, Schlumbergerengineers have responded to developmentalchallenges by introducing a comprehensive andversatile array of completion technologies thatallow operators to produce oil and gas safely andefficiently. As deepwater development continuesto accelerate, lessons learned developing thefields discussed in this article will be applied tofuture ones, and close cooperation between all ofthe players will become commonplace. —EBN

12. For more on the PURE perforating system: Bruyere F,Clark D, Stirton G, Kusumadjaja A, Manalu D, Sobirin M,Martin A, Robertson DI and Stenhouse A: “NewPractices to Enhance Perforating Results,” OilfieldReview 18, no. 3 (Autumn 2006): 18–35.

13. Garner J, Martin K, McCalvin D and McDaniel D: “At theReady: Subsurface Safety Valves,” Oilfield Review 14,no. 4 (Winter 2002/2003): 52–64.


Project Management of Offshore Well Completions

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