38 Oilfield Review

Coiled Tubing: The Next Generation

Ali Chareuf AfghoulZakum Development Company (ZADCO)Abu Dhabi, United Arab Emirates

Sridhar AmaravadiStavanger, Norway

Abderrahmane BoumaliSonatrachAlgiers, Algeria

João Carlos Neves CalmetoPetrobrasRio de Janeiro, Brazil

Joe LimaJohn LovellScott TinkhamKean ZemlakSugar Land, Texas, USA

Timo StaalInverurie, Scotland

For help in preparation of this article, thanks to Marc Allcorn,Rex Burgos, Luis Cabanzo, Lambert Dilling, Frank Espinosa,Richard Luht, Robin Mallalieu, Mark Oettli, RadovanRolovich, Stuart Wilson and Warren Zemlak, Sugar Land,Texas, USA; Tommy Andreassen, BP, Stavanger, Norway;Alastair Buchanan, Stavanger, Norway; Curtis Blount, ConocoPhillips Alaska, Inc., Anchorage, Alaska, USA; JeremyKinslow, Rock Springs, Wyoming, USA; Ronald Knoppe,Shell Internation Exploration and Production B.V., Rijswijk,The Netherlands; Jerry Murphy, Kellyville, Oklahoma, USA;Randal Pruitt, BP-Sharjah, United Arab Emirates; Iuri Frederico de Oliveira Santos, Macae, Brazil; and Jodi Woodand Jamal Zakaria, Hassi Messaoud, Algeria.Blaster, Bridge Blaster, CoilCADE, CoilCAT, CoilFLATE, CoilFRAC, CoilLIFE, CoilSAFE, CoilTOOLS, CT Sim, CT EXPRESS, CT InSpec, CT SEAS (Coiled Tubing Safer, Efficient Automated Solutions), DepthLOG, Discovery MLT,FIV (Formation Isolation Valve), Friction Deployed, IIC (Intel-ligent Injector Control), InterACT, Jet Blaster, MultiSensor,OptiSTIM MP, OptiSTIM ST, Phoenix, PipeSAVER, PowerCLEAN, REDA, REDACoil, Scale Blaster and Sterling Beads are marks of Schlumberger.

Building on a technological resurgence during the 1990s, this unique well-intervention

technique firmly established a place in mainstream operations. We review advances

in surface equipment and downhole tools that increase operational efficiency and

safety, improve wellbore and reservoir remediation methods, and also facilitate

drilling and completing wells with coiled tubing.

Once considered high-risk and applicable onlyfor niche services, coiled tubing (CT) is now anessential tool for many well-intervention opera-tions. In the late 1980s and throughout the1990s, this technology gained wider acceptanceamong operators because of its ability to reduceoverall costs, greatly improved reliability and anexpanding range of applications, which resultedin significantly increased CT activity (next page).1

Used generically, coiled tubing describes con-tinuous lengths of small-diameter steel pipe,related surface equipment and associatedworkover, drilling and well-completion tech-niques. Since its introduction to oilfieldoperations in the early 1960s, CT utilization hasincreased because of better manufacturing,larger tube diameters and advances in equip-ment that improved operational efficiency (see“A History of Coiled Tubing,” page 42).

Coiled tubing is spooled onto a reel for stor-age and transport. These strings can be 31,000 ft[9,450 m] long or more, depending on reel sizeand tube diameters, which range from 1 to 41⁄2 in.A hydraulic power pack, or prime mover, con-trolled from a console in a central control cabin

drives the injector head to deploy and retrievecoiled tubing. The large storage reel also appliesback-tension on the tubing.

The continuous tubing passes over a goose-neck and through an injector head beforeinsertion into a wellbore through well-controlequipment that typically consists of a stuffingbox, or packoff, riser and blowout preventer(BOP) stack on top of the wellhead. This processis reversed to retrieve and spool coiled tubingback onto the reel. Modern CT equipment andtechniques have several advantages over conven-tional drilling, workover and snubbing units.

These include quick mobilization and lowercost, expedited operations with no need to stopand connect tubing joints, and reasonably highload capacities for deeper vertical and high-anglereach compared with wireline and slickline. Theflexibility of working under pressure in “live”wells without killing a well and the unique capability to pump fluids at any time regardlessof position in a well or direction of travel are also advantages.

Spring 2004 39

These capabilities are especially useful inwellbore cleanouts, jetting with inert gases orlight fluids, perforation acid washes, acid or fracture stimulations and sand-consolidationtreatments, cementing, fishing and milling,underreaming and underbalanced drilling.Adding an electric line, data or power cablesinside coiled tubing strings facilitates well logging, downhole monitoring or control, directional drilling and electrical submersiblepump (ESP) installations.

Deeper high-angle wellbores are increasinglycommon and many are beginning to requireremedial interventions. Going into deeper wells

increases coiled tubing weight, requiringstronger pipe and injector heads plus improvedfluids.2 CT is a viable option for these demandingremedial operations, but detailed planning isrequired to ensure job safety and efficiency.

Better tubular manufacturing and qualitycontrol had a significant positive impact, butequipment optimization and improved opera-tional techniques and procedures have beenequally important in improving CT performanceand reliability. This article reviews the latestdevelopments in CT wellsite efficiency, wellboreand reservoir remediation applications, newdownhole tools, reentry and underbalanceddrilling operations and artificial lift.

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> Coiled tubing activity—1965 to the present. Development of continuous tubulars began in World War II with project PLUTO (Pipe Lines Under The Ocean) in 1944. In the 1960s, coiled tubing (CT) was used to wash out sand, retrieve subsurface safety valves and lift fluids out of wells with nitrogen. Later, CTapplications expanded to include acid and fracturing treatments, tool conveyance, tubing replacement, drilling, artificial lift and well completions. As a result,the number of CT units operating worldwide increased from a few in 1965 to more than 1,000 in 2004.

1. Ackert D, Beardsell M, Corrigan M and Newman K: “The Coiled Tubing Revolution,” Oilfield Review 1, no. 3(October 1989): 4–16.Bigio D, Rike A, Christensen A, Collins J, Hardman D,Doremus D, Tracy P, Glass G, Joergensen NB andStephens D: “Coiled Tubing Takes Center Stage,” Oilfield Review 6, no. 4 (October 1994): 9–23.

2. Hodder M, Michel C, Kelligray D and Bailey L: “Investigation of Polymeric and Mixed Metal Oxide Fluidsfor Use in Well Intervention Operations,” paper SPE 89637,presented at the SPE/ICoTA Coiled Tubing Conference andExhibition, Houston, Texas, USA, March 23–24, 2004.

Wellsite EfficiencyA feasibility study in 2001 and subsequent engineering efforts resulted in a new offshore CT unit, which was launched in 2003. The auto-mated, modular CT SEAS Coiled Tubing Safer,Efficient Automated Solutions system was firstinstalled on a BP Valhall field platform in theNorth Sea Norwegian sector (above).3

A typical Valhall field horizontal well requires5 to 12 separate fracture stimulations. To savetime, BP performs drilling and completion operations simultaneously on the platform. Afterwell-completion equipment is installed, thedrilling rig skids to the next wellhead slot. Alarge CT unit and a stimulation vessel completethe wells.

The first CT run performs wellbore cleanoutand perforating. The stimulation vessel thenpumps a proppant fracturing treatment. The nextCT run cleans out excess proppant, but leaves asand plug to isolate the preceding fracture. Thenext interval is perforated, and this cycle continues until all zones are stimulated.

In the past, conventional CT units operatedwith a 13-member crew. The equipment spreadconsisted of a control unit, reel and power pack,well-control equipment, two high-pressure posi-tive displacement pumps, mud shakers, flowvalves and chokes, and an injector-head stand.

Recent extended-reach wells with 2,000-m[6,562-ft] horizontal sections drilled to tap outerareas of the field are more challenging than previous wells. The ability to use larger, heavier27⁄8-in. coiled tubing would increase operationalefficiency and allow completion of additionalintervals, but required a redesigned CT unit.

An evaluation of platform operations andrequirements, and local regulations helped engi-neers develop the new CT SEAS unit. The newdesign targeted decreases in rig-up and overalloperational cycle times to achieve a 15% effi-ciency increase and a 30% reduction in CTpersonnel. The resulting CT SEAS unit consists ofmodular components that are easy to deliver andassemble, produce zero discharge and optimizespace utilization offshore (next page, top).

Flexibility in equipment layout reduces rig-up time and improves CT operations. Conventional offshore CT units typically involve54 crane lifts during rig-up; the new unit cutsthis number to 36. CT SEAS components travelto the wellsite preassembled and pretested onskids to reduce the number of crane lifts and theamount of manual equipment handling.

The injector head is transported with theconnector installed. A self-folding gooseneck andpartially automated process for stabbing coiledtubing into the injector head limits personnelexposure to hazards.

To simplify hookups and pressure testing, theimproved skid designs have fewer valves andsome piping is connected and tested in advanceas modular components. Distributed electriccontrol of valves in place of centralizedhydraulic control reduces the number ofhydraulic connections. The CT SEAS system has36 hydraulic connections instead of the usual 84of older units.

Control cabin ergonomics allow operators toreact quickly and efficiently to any situation(next page, bottom). Automated process andequipment control reduces crew requirementsfrom 13 to 9 members and allows the unit opera-tor to focus on well-intervention efficiency.Process-control software incorporates automatedsafety features that reduce risk exposure in set-tings prone to human errors.

During CT operations, job parameters aremonitored, recorded and plotted by the CoilCATcoiled tubing computer-aided treatment systemfor real-time data acquisition. The InterACT real-time monitoring and data delivery systemprovides secure Web-based, two-way communica-tion that makes field data available at all stagesof a CT operation.4

Authorized client and Schlumberger personnel have access to data and can monitorjobs remotely. Streaming data transfer facilitatesreal-time evaluation of operations to help fine-tune job procedures and speed up decision-making.

The CT SEAS unit has improved wellborecleanout efficiency and allowed completion ofmore difficult flank wells. The capability of run-ning up to 6,000 m [1,829 ft] of 27⁄8-in. coiled

40 Oilfield Review

> A Valhall platform, North Sea Norwegian sector. The new CT SEAS unitperforms perforating and wellbore cleanout operations before and afterproppant fracturing treatments in the BP Valhall field offshore Norway.

3. Andreassen T, Langeteig B, Amaravadi S, Mallalieu R and Polsky Y: “Field Launch of a Safer, More-EfficientCoiled-Tubing Unit in North Sea for Valhall Stimulations,”paper SPE 89604, presented at the SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, Texas, USA,March 23–24, 2004.

4. Cabanzo LE and Zhou W: “Real-Time Data Delivery inCoiled-Tubing Well Interventions,” paper SPE 89528, presented at the SPE/ICoTA Coiled Tubing Conferenceand Exhibition, Houston, Texas, USA, March 23–24, 2004.

Spring 2004 41

Drop-in-drum tubing reel

BOP-control and choke skid

Hydraulic power unit

Mud shaker and tank system

Injector head and jacking frame

BOP skid

Control cabin and tool shop

< A safer, more efficient off-shore unit. The CT SEAS unitconsists of modular skids containing multiple systems foroptimal utilization of platformspace, efficient rig-up and easy delivery. This designreduces the number of cranelifts required to rig up on a plat-form or move from well to well.The principal components arean injector head and jackingframe, blowout preventer(BOP) skid, stackable controlcabin and tool shop, shakerand tank system, BOP-controland choke skid, hydraulicpower unit and drop-in-drumtubing reel. A self-foldinggooseneck and partially auto-mated process for stabbingcoiled tubing into the injectorhead reduce the risk of accidents and injuries. Unitautomation further improvessafety and efficiency, andreduces unit crews from 13 to 9 members.

> CT unit and system control. A cyber-based system in the CT SEAS cabinoperates the reel, injector head, well-control equipment, flow-controlchokes, mud shakers and pumps.

tubing at faster rates has improved well cleaning,eliminated the need for friction-reducing chemi-cal additives and reduced overall job times.

In the new CT unit design, the current andfuture success of this technology can beattributed to platform designs tailored to CTrequirements. To date, all of the targeted effi-ciency gains have not been realized on theValhall platform, but with each campaign theteam moves closer to those goals.

The need for efficient CT technology is not lim-ited to offshore operations. Schlumbergerdeveloped the CT EXPRESS rapid-deploymentcoiled tubing service for intermediate-depthonshore wells (next page, top). This system com-prises two trucks—a purpose-built CT unit andcombination nitrogen and liquid pump—operatedby three people. It provides the same capabilitiesas conventional units with five-person crews.

The combination pumper includes a liquid-nitrogen tank and liquid-additive systems, andprovides electrical and hydraulic power. This unitis designed for applications involving relativelylow pump rates, moderate pressures and contin-uous operations for long periods.

Tubing remains stabbed in the injector headduring transportation, and the bottomhole assem-bly (BHA) can be assembled and pressure testedprior to arrival on location. A drop-in-drum tubingreel and innovative BOP pressure-test stand facil-itate unit mobilization. For rig-up safety andefficiency, no hydraulic or electric connectionshave to be made on location.

The unit operator controls the reel, injectorhead and BOP stack from a cyber-based controlcabin, which utilizes available personnel more effectively and improves wellsite communi-cation. There are also separate stand-alonecontrol panels for operation of individual equipment components.

Statistics from CT operations show that inac-tion or incorrect actions contribute to at leastone-third of all failures. About 83% of the failureswere triggered by a downhole event, resulting inforces that exceeded safe CT working limits. Toaddress this problem, the Schlumberger IICIntelligent Injector Control, which is compatiblewith both conventional and new CT SEAS units,provides automated control of CT conveyance.

In conjunction with CoilCADE coiled tubingdesign and evaluation software, IIC technologyensures that CT operations remain within specified job parameters. This system performsautomated injector load, or pull, tests and controls speed, applied load, depth and otherparameters while running in or out of a well.

42 Oilfield Review

Early coiled tubing (CT) technology can betraced to project PLUTO (Pipe Lines UnderThe Ocean)—a top-secret effort to installpipelines across the English Channel duringWorld War II.1 In June 1944, Allied engineersdeployed several pipelines to provide fuel forD-day invasion forces. Most of the lines werefabricated from 40-ft [12-m] joints of 3-in.inside diameter (ID), 0.212-in. wall thicknesssteel pipe welded together to form 4,000-ft[1,220-m] sections.

These larger pipe sections were weldedend-to-end, spooled onto 40-ft diameter float-ing drums and towed behind cable-layingvessels. Successful deployment of 23 pipelinesranging in length from 30 to 70 miles [48 to113 km] set the stage for future developmentand use of coiled tubing in oil and gas wells.

Elements of modern CT injector heads canbe found in a device developed by BowenTools during the early 1960s for deployingradio antennae to the ocean surface from sub-marines submerged as deep as 600 ft [183 m].The antennae were stored on a spool beneaththe injector for easy extension and retrieval.These basic concepts aided in the design ofCT units and injector systems.

The first such unit, built by Bowen Tools andthe California Oil Company in 1962, included aninjector rated for surface loads up to 30,000 lbm[13,608 kg] that ran a continuous string of1.315-in. outside diameter (OD) pipe. The unit’s9-ft [2.7-m] diameter storage reel included ahub with a rotating fluid swivel to allow contin-uous pumping down the coiled tubing.

However, low yield-strength steels and thenumerous end-to-end, or butt, welds requiredto fabricate continuous tubing could not with-stand repeated bending cycles and high tensileloads. Weld failures, equipment breakdownsand fishing operations to retrieve lost coiledtubing caused operators to lose confidence inthis technique.

From the 1960s through the 1970s, manu-facturing companies, including Bowen Tools,Brown Oil Tools, Uni-Flex, Inc., Hydra Rig Inc.and Otis Engineering, continued making

improvements in CT equipment and injectorheads. These changes allowed larger coiled tub-ing sizes to be used at greater working depths,improved coiled tubing performance and reliability, and reduced the number of surfaceequipment failures. Unfortunately, an overallpoor success rate and a reputation for limitedreliability continued to plague CT operations.

The late 1970s and early 1980s represented aturning point for coiled tubing, which up to thattime was milled, or formed, in 1,500-ft [457-m]sections. In 1978, improved manufacturingquality and continuous milling allowed fabrica-tion of 11⁄4-in. OD pipe. In 1980, SouthwesternPipe introduced 70,000-psi (70-ksi) [483-MPa]high-strength, low-alloy (HSLA) steel for coiledtubing. The early 1980s saw the introduction of11⁄2-in. and 13⁄4-in. OD coiled tubing.

In 1983, Quality Tubing Inc. began using3,000-ft [914-m] sheets of Japanese steel toreduce the number of required welds by 50%.Later in the 1980s, Quality Tubing introducedbias welding to eliminate butt welds. Thisprocess involved cutting flat steel strips diag-onally to enhance coiled tubing strength andlife by spreading the heat-affected weld zonespirally around the tube. In addition, a betterunderstanding of coiled tubing fatigueenabled improvements in reliability and pipe performance.

In 1990, the first string of 2-in. coiled tubingwas milled for a permanent well completion.Soon after that suppliers began manufactur-ing 23⁄8-, 25⁄8-, 27⁄8-, 31⁄2- and 41⁄2-in. OD sizes forwell-servicing applications. Today, coiled tub-ing is manufactured from steel with high yieldstrengths of 90, 100, 110 and 120 ksi [620, 689, 758 and 827 MPa], as well as corrosion-resistant alloys. Higher strength steel, largerdiameters and the need to reduce costs werekey factors behind the CT revolution of the1990s, and subsequently accounted for theextraordinary increase in concentric, orthrough-tubing, well-intervention work.

1. Wright TR Jr and Sas-Jaworsky II A (eds): World Oil’sCoiled Tubing Handbook. Houston, Texas, USA: Gulf Publishing Co. (1998): 7.

A History of Coiled Tubing

Spring 2004 43

This is particularly important during criticallogging, cementing and high-pressure applica-tions, or weight-sensitive milling or drillingoperations. Predetermined trip schedules andslow-down points protect completion equipment,such as profile nipples. Programmed safety limitsprovide overpull protection and emergency shutdown for downhole obstructions.

The automated IIC control system protectswellbore and completion equipment and helpsprevent downhole failures caused by humanerror. In addition to improvements in CT unitsand surface equipment, a better understandingof stresses and fatigue and more effective pipemanagement have improved service quality andjob safety.

Tube ReliabilityResults from an eight-year Schlumberger analy-sis of tube flaws and failures indicated thatcoiled tubing utilization efficiency is improving.5

A better understanding of tube failures and afocused pipe-management program contributedto increased CT reliability and improved servicequality. As part of an ongoing Coiled Tubing Failure Analysis Program, Schlumberger investi-gated and classified failure causes andmechanisms (left).

These data provide valuable input forresearch, development and engineering efforts,training and competency programs, and quality-assurance plans. Based on identified trends and failure causes, Schlumberger implemented preventive field procedures to mitigate coiledtubing failures.

The result was a steady increase in the num-ber of Schlumberger jobs per 1,000 ft [305 m] ofcoiled tubing purchased from 2 in 1998 to 3.6 in2003. The number of successful jobs between failures also improved from 100 in 1999 to a highof 235 in 2001.

Schlumberger developed the CT Pipe Management Program to track and address tubeflaws and failures. Failures while coiled tubing isin a well or being bent at the surface can have acatastrophic impact on safety, the environmentand intervention economics. Significant improve-ments have been made to reduce the number ofCT failures.

< A fit-for-purpose land-based CT unit. The CTEXPRESS unit includes twotrailers that rig up in less than 30 minutes. The maintrailer includes an injectorrated to pull 40,000-lbf [178-kN] and 10,000-psi[68.9-MPa] pressure-controlequipment on a 42-ft [13-m]mast. This unit can be usedon wellheads up to 20 ft [6.1 m] high, with a 6-ft [1.8-m] or shorter bottom-hole assembly (BHA). Alonger BHA can be accom-modated on shorterwellheads. The secondtrailer carries nitrogen- andliquid-pumping equipmentand liquid-additive systems.

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> Coiled tubing failure analysis. Schlumberger has tracked failure causes (top) and mechanisms(bottom) for eight years. A cause refers to the initial condition that eventually leads to tube failure. Amechanism is the event that ultimately triggers the failure. For example, the mechanism of fatigue canresult in a failure caused by a corrosion pit or a dent. These data resulted in a focused pipe-management program and better quality control in the field that improved coiled tubing utilization,efficiency and operating practices.

5. Van Adrichem WP: “Coiled Tubing Failure Statistics Usedto Develop CT Performance Indicators,” paper SPE 54478,presented at the SPE/ICoTA Coiled Tubing Conferenceand Exhibition, Houston, Texas, USA, May, 25–26, 1999.Larsen HA, Bravenec EV and Coburn GS: “Coiled-TubingPerformance Indicators 3 Years Later: An Update,” paperSPE 81713, presented at the SPE/ICoTA Coiled TubingConference, Houston, Texas, USA, April 8–9, 2003.

Tube materials, manufacturing processes andquality control before coiled tubing goes to thefield have improved through an alliance with CT supplier Precision Tube Technology Inc. TheCoilLIFE coiled tubing life prediction modelhelps assess fatigue damage and remove coiledtubing from service before it reaches the end ofits useful life.

The PipeSAVER coiled tubing storage inhibi-tion system has improved coiled tubing handlingby mitigating mechanical damage and corrosion.Training personnel in the proper use and mainte-nance of the pipe, and planning tools, such asCoilSAFE coiled tubing risk assessment system,help address operational safety. The Schlumbergerglobal tubing inventory has aided in understandingcoiled tubing performance by requiring that fail-ures be recorded, analyzed and categorized.

Fracturing and acid stimulation throughcoiled tubing erode or corrode the steel. Certainwell environments, such as chrome tubulars,cause external coiled tubing abrasion, and CT is

being used at higher pressures, with the defini-tion of “high-pressure” constantly increasing.These increased demands require a better meansof monitoring CT integrity.

Several CT inspection systems have beendeveloped. The universal tubing integrity moni-tor (UTIM) measures tube diameter and ovality.Other systems that detect cracks and pits, andgive an average wall thickness have niche appli-cations, but none are completely satisfactory.These limitations drive ongoing research anddevelopment in CT inspection.

Technology is currently being developed toaddress flaw identification and description, theeffects of flaws on coiled tubing life, and assessment of related risks. The new ultrasonicCT InSpec real-time device, for example, moni-tors both ovality and wall thickness (above).6

Wall thickness is directly related to tubularburst strength, remaining string life, string abrasion and erosion effects and critical load-conveyance effects.

These measurements help users optimizestring life and reduce tube failures in the field.The CT InSpec device does not address all CTinspection issues, but is a significant step forward. Combining this technology with existing magnetic-flux leakage or ultrasonicshear measurements may allow detection oflocalized flaws, such as pitting and corrosion. Inaddition to improved CT string management,new developments are optimizing wellborecleanout operations.

Wellbore RemediationAbout 50% of CT operations involve removing for-mation sand, fracturing proppants or other solidsfrom wells (next page, top). These materialslimit or prevent production, block the passage ofwireline or other downhole tools, and interferewith completion and well-intervention opera-tions. Conventional CT techniques often leavesolids behind, requiring repeated cleanoutattempts over an extended period, whichincrease costs and delay production.

To address this problem, Schlumberger conducted extensive testing directed at under-standing solids transport by cleanout fluids.7 Theresulting PowerCLEAN engineered fill removalservice is an integrated approach that consistsof specialized fluids, improved jetting nozzles,design software and a real-time system thatmonitors returning solids at the surface (nextpage, bottom).

Mixed with fresh water or seawater, PowerCLEAN fluids create a low-friction, high-viscosity stable solution that extends cleanouteffectiveness to 325°F [163°C]. Water, guar,hydroxyethyl cellulose (HEC), xanthan and viscoelastic surfactants (VES) can also be usedwith the PowerCLEAN system up to their temperature limit—about 250°F [121°C].

Previous CT nozzle designs commonly haveforward-only or forward and backward jets thatdo not effectively remove solids from high-anglewells. New PowerCLEAN nozzles have no movingparts, but create a swirling effect that providescontinuous jetting; this utilizes fluid energy moreefficiently and removes solids at greater thantwice the rate of conventional nozzles.

The PowerCLEAN software integratescleanout simulation with job optimization. Jobparameters include circulating rate, CT running

44 Oilfield Review

Drip pan

Elastomerelement

Ultrasonicprobes

> Coiled tubing inspection. Improved pipe inspection helps reduce tubefailures and optimize pipe life. The CT InSpec wellsite system uses 12ultrasonic probes, arranged radially, to monitor wall thickness and pipe ovalityover variable CT interval lengths (top). This new device measures tubing wallthickness as coiled tubing comes off the reel (bottom).

6. Newman KR and Lovell J: “A New Approach to Ultrasonic CT Inspection,” paper SPE 87122, presented atthe SPE/ICoTA Coiled Tubing Conference and Exhibition,Houston, Texas, USA, April 8–9, 2003.

7. Rolovic R, Weng X, Hill S, Robinson G, Zemlak K andNajafov J: “An Intergrated System Approach to WellboreCleanouts with Coiled Tubing,” paper SPE 89333, presentedat the SPE/ICoTA Coiled Tubing Conference and Exhibition,Houston, Texas, USA, March 23–24, 2004.

Spring 2004 45

speed when penetrating fill, particle-bed depth,CT pulling speed for sweeping solids uphole, andnumber and length of sweep before running backin. The software accounts for factors such asmaximum surface pressure and pump rate,acceptable bottomhole pressure (BHP),entrained solids concentration, fluid leakoff orinflow and solids transport.

Additional constraints ensure safe, problem-free cleanouts. The solids bed is not allowed toexceed a specified height that avoids drag on thecoiled tubing, higher friction pressures and stuckpipe. In addition, the volume of solids that canbe lifted above the nozzle is limited. This helpsensure that the coiled tubing can be pulled out

in the event of lost circulation because of pumpfailure or excessive fluid leakoff. These safetyconstraints typically result in multiple sweeps toremove large fill volumes.

The real-time PowerCLEAN solids monitoruses acoustic sensors to detect returning solidsat the surface and help determine whether acleanout is progressing as planned. This non-intrusive monitor mounts on an elbow of theflowback line. The PowerCLEAN system recentlyplayed a key role in wellbore-cleanout operationsin continental Europe and the Gulf of Mexico.

After hydraulically fracturing a gas well com-pleted with a 7-in. liner, the operator needed toclean out the wellbore at balanced pressure con-ditions to avoid damaging the well. A 59-bbl[9.4-m3] volume of bauxite proppant filled thewellbore from about 13,700 to 16,400 ft [4,176 to4,999 m], a length of 2,700 ft [823 m]. The maximum well inclination at this depth was 31°and the bottomhole temperature (BHT) was304°F [151°C].

A 13⁄4-in. coiled tubing string pumping thenew cleanout fluid penetrated fill at about 6 to10 ft/min [1.8 to 3 m/min]. The PowerCLEANsoftware predicted that other fluids would notprovide an effective cleanout because of the high BHT and large casing. It also deter-mined that several sweeps would be required to remove solids that settled in high-angle wellbore sections.

Each CT penetration into the fill was limitedto 80 ft [24 m], which minimized the solids duneheight and prevented coiled tubing from becoming stuck if fluid loss occurred or pumpingstopped. Sweep speed while pulling out of thewell was 10 to 20 ft/min [3 to 6 m/min] to ensurecomplete fill removal.

An optimal flow rate through the 21,000 ft[6,401 m] of coiled tubing was achieved at pres-sures below 4,000 psi [27.6 MPa] because of thelow-friction PowerCLEAN fluid. Solids returnswere monitored at the surface in real time. Thewell was cleaned without problems and 59 bbl ofbauxite proppant were recovered.

In another well, the PowerCLEAN service wasused to remove excess bauxite from a Gulf ofMexico well in order to replace the gravel-packscreen assembly. This wellbore was completedwith a 31⁄2-in. liner and had a complex trajectorywith a maximum deviation of 70°. At a BHT ofless than 200°F [93°C] and a 0.75-bbl/min [0.12 m3/min] pump rate, the PowerCLEAN nozzlewith a xanthan-base fluid resulted in an optimized cleanout.

Friction pressurein coiled tubing

Particle transport

Solids bed heightand dune movement

Jetting and solidsmobilization

> Cleaning high-angle and horizontal wells. During CT wellbore cleanouts,fluid is pumped down coiled tubing through a downhole nozzle with jets, orports. The resulting turbulent flow agitates fill in the wellbore, causing thesolids to be mixed and temporarily suspended in cleanout fluid as a result ofturbulent flow. Pumping rates depend on available horsepower and frictionpressure in the coiled tubing. Over time, solids traveling in the coiled tubing-by-wellbore annulus settle on the low side of a wellbore and form dunesbehind the nozzle. How far solids can be transported depends on fluidproperties, particle sizes and density, flow rate and wellbore geometry,including the coiled tubing.

> Integrated wellbore cleanout services. In addition to enhanced designsoftware, new cleanout fluids and solids monitoring at the surface, thePowerCLEAN system includes a specialized nozzle that creates a fluidvortex, which removes solids at lower flow rates than conventional nozzles.Unlike other nozzles, PowerCLEAN nozzles use optimized jet angles toproduce this swirling effect, and have no moving parts to maintain. The new PowerCLEAN fluid and nozzle effectively remove fill at rates as low as 1 bbl/min [0.15 m3/min] for 7-in. casing and 2 bbl/min [0.3 m3/min] for 95⁄8-in.casing at any inclination.

Based on real-time monitoring, cleanoutoperations removed 16,500 lbm [7,484 kg] ofbauxite in 12 hours. A subsequent CT run taggedthe gravel-pack assembly rope socket, confirmingthat the well was clean. After gravel-packscreens were replaced, well productionincreased from 0.5 to 2.5 MMcf/D [14,320 to70,600 m3/d].

Downhole deposits of inorganic scales inwellbore tubulars are a serious well-interventionproblem (above left).8 Scale buildup changes thesurface roughness of tubulars, increasing frictional pressure and restricting production.Additional scale growth decreases tubular flowarea, prevents access to deeper sections of a welland ultimately may block the tubing completely.Extremely hard, insoluble scales, such as stron-tium or barium sulfate, may form when injectedseawater breaks into a well.

In Brazil, Petrobras used abrasive-jet CTtechnology to clean heavy barium sulfate scalefrom production tubing in an offshore well.9 Thewell was located on a fixed offshore platform andno workover rigs were available, so tubingreplacement was not an option. CT provided ameans of conveying mechanical scale-removaltools and circulating cleanout fluids without aconventional rig.

Methods such as chemical dissolvers, slickline brushes and downhole motors had suc-cessfully removed scale in other area fields. Insome of these cases, however, residual debris fell

to the bottom of wells and blocked the perfora-tions, requiring additional cleanout operations.

Schlumberger Blaster services use high-pres-sure jetting technology to remove downholedeposits (above). This specialized system usessolvents or special abrasive material to removescale without damaging tubulars or com-pletion equipment, such as profile nipples, subsurface safety valves or sliding sleeves. This technology comprises three techniques—JetBlaster, Scale Blaster and Bridge Blaster scale-removal services.

Jet Blaster techniques use conventional fluids or scale-dissolving solvents with a radialjetting tool. The Scale Blaster approach uses theSterling Beads safe hard scale-removal systemdeveloped at Schlumberger Cambridge Researchin England to remove hard, inert scales (left).By properly selecting particle hardness, shape,size, density and fracture toughness, researchersachieved unique properties that remove scalewithout damaging steel surfaces.

The Bridge Blaster technique combines apositive displacement motor (PDM) and a 15⁄8-in.tapered mill with the radial jetting tool and theSterling Beads system modified to prevent PDMclogging. This system drills scale deposits orcement plugs through tubing without damagingwellbore equipment. The small tapered millpartially removes the scale deposit while jettingremoves the rest. Removal rates are higher thanwith conventional milling.

46 Oilfield Review

Tubing wall

Scale

> Scale buildup in wellbore tubulars. Variationsin produced water quality, especially wheninjecting seawater for pressure maintenance,contribute to the formation of hard inorganicscales in perforations and wellbore tubulars.Insoluble scale buildup reduces the flow area,restricting or preventing production, andcontributes to gas-lift problems, and failure ofsubsurface safety valves and other equipment.

Tubing wall

ScaleJet nozzle

Rotating head

Drift ring

>Mechanical scale-removal. The Jet Blaster tool consists of a rotating headwith opposing tangentially offset nozzles and a drift ring. The jet nozzlesremove scale from tubular walls while the drift ring allows the tool to advanceonly after the internal tubular diameter is clean. Blaster services include threemechanical scale-removal techniques: the Jet Blaster method usesnonabrasive fluids for removal of soft scales; the Scale Blaster method addsthe abrasive Sterling Beads system to remove hard scales; and the BridgeBlaster method uses abrasive jetting and a powered milling head whentubulars are completely plugged.

Sand particles Limestone particles

Glass beads Sterling Beads particles

0.75 mm

>Microscopic views of Sterling Beads shapeand various particle abrasion effects. Thespherical Sterling Beads particles have a highfracture toughness, low friability, and are acidsoluble (top). This nontoxic material matches theerosive performance of sand on hard, brittlescales, but does not cause excess damage tosteel during prolonged jetting in one spot.Angular sand and calcite particles gouge steelsurfaces, which can cause ductile tubularfailures (middle left and right). Glass beads andround particles tend to bounce off steel surfaces,creating large, deep craters that eventually mayresult in erosion through tubular walls (bottomleft). Sterling Beads particles shatter on impact,creating only small pits (bottom right).

Spring 2004 47

Blaster design software helps select jettingtool geometry—drift ring, nozzle head, port sizeand configuration—required fluid rates,expected treating pressures, abrasive materialconcentrations and scale-removal rates. The soft-ware also estimates consumables, such as gellingagents, mixing products and abrasive materials.

The coiled tubing BHA encountered scale at2,546 m [8,353 ft] in the Petrobras well. Using axanthan-gelled brine and 3%-by-weight SterlingBeads abrasive particles, the Jet Blaster toolachieved a cleanout rate of 12 to 15 m/hr [39.4 to49.2 ft/hr] from 2,546 to 3,087 m [10,128 ft].Pumping at 0.23 to 0.27 m3/min [1.5 to1.7 bbl/min] with circulating pump pressures of24.1 to 27.6 MPa [3,500 to 4,000 psi], this part ofthe job required 36 hours and three jetting tools.

At 3,087 m, 60 m [197 ft] below the tubingand inside the 7-in. liner, the jetting tool wasreplaced with a PDM and a 21⁄2-in. three-step mill.This final stage took 12 hours to clean out 43 m[141 ft] to 3,130 m [10,269 ft] and completelyconsumed the mill.

The total operation generated about66,000 lbm [29,937 kg] of debris—6,000 lbm[2,722 kg] of scale and 60,000 lbm [27,216 kg] ofabrasive particles—that were captured in theplatform production separator. After the job,other platform wells had to be shut in for a shorttime to clean the production separator. Mostscale-removal jobs now use a temporary separa-tor to capture solids before they reach theproduction separator.

Scale Blaster technology effectively removedbarium sulfate scale from completion tubing andhardware in conditions under which conven-tional methods had failed in the past. As a result,oil production increased 1,025%, which resultedin a 19-day payout.

It is common for wells in mature fields toexperience scale deposition. Blaster serviceshave been applied in several other locations tosave time and money, including Duri field inIndonesia and several North Sea fields. In addi-tion to use in wellbore cleanouts, CT has becomean important tool in formation stimulation.

Reservoir RemediationIn Algeria, Sonatrach stimulates deep high-pressure, high-temperature (HPHT) wells of theHassi Messaoud field using coiled tubing-con-veyed fracturing and new packer technology.10

Reservoir conditions allow low-rate, high-pressure hydraulic fracturing treatments, whichsignificantly increase productivity and prolongthe economic life of these wells. Unfortunately,many wells require remedial cement squeezes ortubing replacement to address tubular-integrityproblems before stimulation operations can begin.

In the past, problems with conventional pack-ers limited fracturing success because ofdifferential pressures in excess of 9,000 psi[62.1 MPa] across the isolation packer. Sometreatments resulted in costly fishing operations.CoilFRAC stimulation through coiled tubingtreatments provided an alternative to conven-tional workover rigs (right).11 The availability ofCT units was an additional advantage.

Coupled with more reliable mechanical pack-ers for downhole isolation, CT-conveyedfracturing protects wellbore tubulars from hightreating pressures and abrasive proppants. CoilFRAC techniques are applicable for initialstimulation treatments in new wells, stimulationof bypassed pay and restimulation of previouslytreated intervals.12

In October 2001, Sonatrach performed thefirst CoilFRAC treatment in Hassi Messaoud WellOMP843. Completed with a 41⁄2-in. cemented andperforated liner and 41⁄2-in. tubing, this well hadpressure between the 7-in. and 95⁄8-in. casing. TheCT packer was set at 10,660 ft [3,249 m] above aprofile nipple in the production tubing. Thetreatment placed a total of 21,464 lbm [9,736 kg]of 20/40 proppant in the formation at a maximumconcentration of 3.1 pounds of proppant added(ppa) per gallon of treatment fluid.

The average surface treating pressure was8,600 psi [59.3 MPa]. A 13,100-ft [3,993-m] 23⁄8-in.coiled tubing string isolated wellbore completiontubulars. The packer withstood a maximum8,800-psi [60.7-MPa] differential pressure at9 bbl/min [1.4 m3/min]. Prefracture productionwas 860 B/D [137 m3/d] of oil; postfracture pro-duction was 2,280 B/D [362 m3/d] of oil. The

treatment, including deferred production, paidout in 39 days.

At that time, this was the deepest well frac-tured through coiled tubing. Excessive hydraulicforces caused the packer to release twice duringprejob injectivity and treatment-calibration tests.Bottomhole pressure gauges verified the model-ing of downhole forces and guided modificationsto the CT packer.

Based on CoilFRAC experience from threeHassi Messaoud field wells, including WellOMP843, stimulated between October 2001 andJanuary 2003, Schlumberger made severalpacker improvements. Development of the OptiSTIM MP mechanical packer for stimulation

Pay zone 1

Pay zone 2

Sand plug 1

Sand plug 2

Packer

Straddle-isolation tool

Fracture

Fracture

Pay zone 3

Pay zone 1

Pay zone 2

Pay zone 3

> Selective isolation and stimulation.Conventional hydraulic fracturing maximizesfracture height, often at the expense of fracturelength and complete stimulation coverage.Coiled tubing-conveyed fracturing overcomesthese limitations and allows engineers to designoptimal fractures for each pay zone. CoilFRACstimulations can be performed with a singlemechanical packer and sand plugs (top) orselective straddle tool assemblies (bottom).

8. Crabtree M, Eslinger D, Fletcher P, Miller M, Johnson Aand King G: “Fighting Scale—Removal and Prevention,”Oilfield Review 11, no. 3 (Autumn 1999): 30–45.

9. Quiroga MHV, Calmeto JCN, Assis CAS, Pinto SL andSantos F: “Hard Scale Mechanical Removal: A Solutionfor Brazilian Offshore Operations,” paper SPE 89627, presented at the SPE/ICoTA Coiled Tubing Conferenceand Exhibition, Houston, Texas, USA, March 23–24, 2004.

10. Allouti A, Ben Amor B, Ferhat A, Oettli M, Ortiz A andWood J: “Coiled-Tubing-Conveyed Fracturing TechniqueProvides Economic Alternative to Workover Rigs in Stimulation Campaign,” paper SPE 89446, presented atthe SPE/ICoTA Coiled Tubing Conference and Exhibition,Houston, Texas, USA, March 23–24, 2004.

11. Degenhardt KF, Stevenson J, Gale B, Gonzalez D, Hall S,Marsh J and Zemlak W: “Isolate and Stimulate IndividualPay Zones,” Oilfield Review 13, no. 3 (Autumn 2001): 60–77.

12. Gutor C, Al-Saleem A, Rieger B and Lemp SP : “New Lifefor Old Wells: A Case Study of Re-Stimulating Gas WellsUsing Fracturing Through Coiled Tubing and SnubbingTechniques,” paper SPE 81730, presented at theSPE/ICoTA Coiled Tubing Conference and Exhibition,Houston, Texas, USA, April 8–9, 2003.

design led to consistently successful treatments(below). Modifications included optimizing theslip area, designing a more robust J-type latchingmechanism, and adding two equalizing ports anda pressure-balance section to the emergency-release mechanism.

Because coiled tubing-conveyed fracturingoften induces difficult-to-predict, variable loadsand stresses greater than those normally encoun-tered by stimulation packers, Schlumbergerdeveloped software to optimize treatmentdesigns and reduce excessive packer loads. Thissoftware can also be used to monitor job progressand make necessary corrections in real time.

The new software and redesigned OptiSTIM MP packer were used on Well OML862,an oil producer completed with 41⁄2-in. cementedproduction tubing and a 5-in. slotted liner. Thiswell had communication between the 41⁄2-in. pro-duction tubing and 7-in. casing, and between the7-in. and 95⁄8-in. casing strings. The cemented pro-duction tubing made a conventional workoverimpossible. Performing a fracture treatmentthrough coiled tubing isolated the wellbore tubulars from high treating pressures and abrasive proppants.

With the packer set at 10,220 ft [3,115 m], a10,000-gal [37.9-m3] calibration treatmentpumped at 6.6 bbl/min [1 m3/min] and surfacetreating pressure of 9,400 psi [64.8 MPa] indi-cated a closure pressure of 10,300 psi [71 MPa],which gives a fracture gradient of 0.92 psi/ft[20.8 kPa/m]. The primary fracture treatmentwas pumped successfully at an average rate of6.4 bbl/min [1 m3/min] with the packer set at10,186 ft [3,105 m].

Sonatrach pumped 23,975 lbm [10,875 kg] of20/40-mesh high-strength proppant at a maxi-mum bottomhole concentration of 4 ppa, placinga total of 21,529 lbm [9,765 kg] in the formation.When a screenout occurred 24 bbl [3.8 m3]before the end of the flush, the pump rate wasreduced to stay below the maximum allowabletreating pressure of 10,000 psi [68.9 MPa].

The packer was then released and anyremaining proppant was circulated out prior toretrieving the packer. The packer was exposed toan average differential pressure of 5,500 psi[37.9 MPa] and a maximum differential pressureof 9,600 psi [66.2 MPa] at screenout. The well isproducing 65 m3/d [409 B/D] while Sonatrachoptimizes the gas-lift system.

Fracturing through coiled tubing in HassiMessaoud field required modified packers andimproved computer software to model downholeforces. These improvements increased the reliability of CoilFRAC treatments, which cannow be performed in wells as deep as 12,000 ft[3,658 m]. Pumping rates can range from 8 to25 bbl/min [1.3 to 4 m3/min] with 5 to 12 ppa.

CoilFRAC technology can tap previouslybypassed gas reserves and optimize well produc-tivity, especially in low-permeability gas

reservoirs. The latest OptiSTIM ST straddlepacker provides added flexibility for selective iso-lation and stimulation of individual zones (nextpage, left). Reservoir applications from perforat-ing to selective zonal isolation and stimulationhave generated several new downhole CT tools.

Advanced Downhole ToolsEffective zonal isolation for CT applicationsrequires inflatable packers that can pass throughtubing, expand and then seal in larger casing. Inthe past, these systems were rarely used in hostile environments because of expansion limi-tations and susceptibility to high temperaturesand pressures, and corrosive fluids or chemicals.Schlumberger developed the 21⁄8-in. single-ele-ment CoilFLATE HPHT high-pressure,high-temperature through-tubing inflatableanchoring packer to address the limitation of con-ventional inflatable packers (next page, right).13

CoilFLATE HPHT packers extend critical con-centric zonal isolation to previously inaccessibledownhole environments. These packers can berun in vertical, high-angle or horizontal well-bores on coiled tubing or on jointed pipe using asnubbing unit. This eliminates the need for aworkover rig and allows remedial operationswithout killing the well.

Tapered slats in the tool body, or carcass,allow narrow sections near the end of a packer toprovide the required load-bearing cross section,while the wider sections provide the necessaryextrusion barrier and coverage for the inflationbladder. A CoilFLATE HPHT carcass restraintsystem (CRS), or internal crush sleeve, imposes aconstant axial load on the slats during inflationthat creates tension on the packer to ensure pro-gressive inflation from the center toward bothends. This center-out inflation prevents end sections of the packer element from inflatingfirst and trapping fluids, resulting in an ineffi-cient seal, or soft set.

The proprietary elastomer and packer ele-ments are resistant to hydrogen sulfide [H2S],carbon dioxide [CO2] and other chemicals. Steelparts in the 21⁄8-in. setting tool are replaced bynickel-based high-strength alloy components tomake the entire BHA fully H2S compatible. Thecomposite elastomer bladder uses carbon fibersto eliminate axial strain and allows the packercircumference to expand freely.

This design provides a reliable seal at final-to-initial expansion ratios of greater than 3 to 1.CoilFLATE HPHT packers do not rely on a ball

48 Oilfield Review

Pressure-balance section

Equalizing port

J-type latch

Drag blocks

High-strength slips withoptimized contact area

Equalizing port

High-pressure elastomerelement and anti-extrusiondevice

Adjustable shear-releasesystem

> Selective stimulation with single-seal packers.The OptiSTIM MP mechanical packer is amultiple-operation, tension-set tool for coiledtubing or jointed pipe. This assembly is used formultizone CoilFRAC treatments when existingperforations or tubulars must be protected fromtreating fluids and pressures.

13. Wilson S, Erkol Z, Faugere A, Eatwell B, Espinosa F andXu R: “Inflatable Packers in Extreme Environments,”paper SPE 89529, presented at the SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, Texas, USA,March 23–24, 2004.

Spring 2004 49

valve to initiate inflation. A large internal diameter allows high-rate fluid treatments. A 21⁄8-in. CoilFLATE ST straddle tool version forstimulation applications uses the same princi-ples as the CoilFLATE HPHT packer.

CoilFLATE HPHT packers can isolate wellboresections for pressure testing, temporary zonal iso-lation and permanent abandonment. Thesechemically resistant systems can also be used for

sand consolidation, acidizing and fracturing, aspermanent and retrievable bridge plugs for waterand gas shutoff, and as a cement retainer orpacker for through-tubing gravel packing.

Bottompressureelement

Flowback-controlelement

Straddlebypass

Multicycledumpvalve

Dump port

Straddlebypass

Top pressureelement

Treatmentsub

Straddlesections

> Selective stimulation with dual-seal straddle isolation tools. The OptiSTIM STstraddle packer for coiled tubing or jointed pipe comprises a straddle bypass,a straddle extension assembly with ported treatment sub and a multicycledump valve. This configuration facilitates effective sequential placement ofchemical, acid or proppant fracture treatments.

> Inflatable packer expansion. Heavy-dutytapered slats, a high-strength carcass restraintsystem (CRS), a composite inflation bladder and achemically resistant elastomer anchor CoilFLATEHPHT packers in place and provide a high-pressure seal even at large expansion ratios—2to 1 at 5,000 psi [34.5 MPa] and 3 to 1 at 2,000 psi[13.7 MPa]. These packers withstand extendedexposure at temperatures up to 375°F [191°C] inalmost any chemical environment.

CoilFLATE HPHT packers were used recentlyfor a deep, high-expansion, high-pressure cementretainer application in the Gulf of Mexico, ascreenless sand-consolidation treatment in NorthAfrica, and a high-pressure, high-temperaturestraddle packer for a stimulation treatment inthe Middle East. In each of these applications,depth correlation was critically important.

The wireless DepthLOG CT depth correlationlog is used for well logging, perforating, settingsand plugs, bridge plugs or mechanical packers,and for positioning straddle-isolation tools dur-ing selective stimulation treatments (right).This new tool combines a traditional casing collar locator (CCL) to detect magnetic variations at casing joints with pulse-telemetrytechnology that sends pressure signals to the surface.

Subsurface depth correlations are deter-mined quickly and accurately by comparisonwith baseline well logs. Wireless technologydecreases the number of trips into a well, savingup to 12 hours per operation on typical coiledtubing-conveyed perforating and stimulationoperations. Flow-through capability providesunobstructed coiled tubing for pumping servicesand stimulation treatments. The ability to dropball-type actuators through the DepthLOG toolallows setting or inflation of CT packers, activa-tion or release of downhole tools, and detonationof perforating guns.

In Algeria, Sonatrach was first to use a CoilFLATE inflatable packer in combination withwireless DepthLOG technology.14 Remedialoperations in Well MD 264 of the Hassi Messaoudfield with two perforated zones required isolationand stimulation of an underperforming lowerinterval. To maximize workover economics, thisacid treatment had to be conducted without a rig.

A separation of only 10 ft [3 m] betweenzones at a depth of about 10,000 ft [3,048 m] pre-sented additional challenges. The packer had tobe accurately positioned to isolate a high-permeability upper interval from the less permeable lower zone. An initial attempt withoutDepthLOG correlation resulted in packer inflation across the lower perforations and ineffective treatment-fluid diversion.

The DepthLOG tool was added to the BHA,which was run in the well to a point below thelower zone. Two upward passes while pumpingfluid and receiving pressure pulses from theDepthLOG tool clearly indicated casing collarlocations. The CoilFLATE packer was positionedat the target depth and inflated to an internalpressure of 4,000 psi [27.6 MPa].

Set-down weight on the coiled tubing verifiedcomplete packer inflation before pumping anacid treatment. This operation created a maxi-mum differential pressure across the packer ofabout 3,500 psi [24.1 MPa], significantly higherthan other inflatable packers can handle.

Immediately after completing the treatment,the packer was deflated, and nitrogen waspumped to flow spent acid back while pulling thecoiled tubing out of the well. The production tub-ing did not have to be pulled and only one tripwas required to achieve a sustained 326%

50 Oilfield Review

Signaler

Processor

Signal booster

Battery power forsignal processor

Casing collarlocator (CCL)

> Depth control. The wireless DepthLOG CT tool uses a traditional casingcollar locator (CCL) to detect magnetic variations at jointed casing collars(left). Hydraulic pressure-pulse telemetry transmits data to the surface,eliminating the need for coiled tubing with an electric line installed. Flow-through capability provides an unobstructed coiled tubing string. A signalbooster can be added for depth correlation inside casing sizes larger than 7 in. (right).

Spring 2004 51

increase in oil production from 238 B/D[37.9 m3/d] to 776 B/D [123.4 m3/d].

Inherent advantages—fast trip times andcontinuous circulation without pipe connections,live well intervention with improved pressurecontrol and a smaller footprint for reduced envi-ronmental impact—that make CT attractive forremedial wellbore and reservoir applications arealso advantages for coiled tubing drilling.

Reentry and Underbalanced DrillingSince 1991, coiled tubing has been used to con-struct thousands of vertical and directional wells.CT drilling applications include deepening, side-tracking and drilling new wells, especially forshallow gas reservoirs and gas-storage projectsand environmentally sensitive locations. After adecade of profitable operations, four CT drillingapplications have proved technically and

commercially viable:• new wells to about 3,000 ft [914 m]• safety-sensitive operations• through-tubing reentry• underbalanced drilling.

CT drilling is ideally suited for underbalanceddrilling. In depleted zones, drilling under-balanced minimizes formation damage anddifferential BHA sticking.15

Schlumberger drills and completes more than100 wells per year with coiled tubing. The majorityof vertical CT drilling activity occurs in Venezuelawhere 30 to 60 surface-hole sections are drilledand cased each year. A self-contained CT drillingbarge, designed specifically to minimize theimpact of encountering shallow gas zones in LakeMaracaibo, was commissioned in 1995.

Typically, this barge drills a 121⁄4-in. hole 1,000to 1,800 ft [300 to 550 m] deep. Specializedequipment runs 95⁄8-in. casing, executes cement-ing operations and conducts wireline logging.Schlumberger has constructed more than275 vertical wells in Lake Maracaibo, eachrequiring an average of four days to complete.

Operations on the North Slope of Alaska,including the Prudhoe Bay field, represent one ofthe most successful CT drilling applications ofthe past decade, clearly demonstrating CT effi-ciencies and economics. Two fit-for-purposehybrid CT drilling units operate continuously onthe North Slope, each capable of drilling andcompleting three wells per month. A typicalNorth Slope CT drilling well involves a direc-tional through-tubing reentry to access bypassedoil (left). To date, more than 400 North Slope wells have been reentered using CTdrilling technology.16

3

6

41

25

7

> Coiled tubing drilling on the Alaskan North Slope. A typical CT drillingreentry at Prudhoe Bay, Alaska, USA, consists of running an expandablewhipstock through existing 41⁄2-in. tubing and setting it at the kickoff depth in 7-in. casing (1), squeezing existing perforations by running CT to the top of thewhipstock and pumping cement (2), milling out profile nipples at the end of thetubing and cutting a 3.8-in. casing-exit window (3), drilling a 33⁄4-in. sidetrackhole (4), deploying a 23⁄8-in. liner on CT without a hanger in the lower tailpipe(5), cementing the liner to 200 ft [60 m] above the casing-exit window (6), andperforating the liner using hydraulically activated guns run on CT (7).

14. Boumali A and Wilson S: “Treating the Tough Ones,”Hart’s E&P 76, no. 12 (December 2003): 57–59.

15. Ackers M, Doremus D and Newman K: “An Early Look at Coiled-Tubing Drilling,” Oilfield Review 4, no. 3 (July 1992): 45–51.Byrom TG: “Coiled-Tubing Drilling in Perspective,” Journal of Petroleum Technology 51, no. 6 (June 1999):57–61.

16. Gantt LL, Oba EM, Leising L, Stagg T, Stanley M, Walker Eand Walker R: “Coiled Tubing Drilling on the AlaskanNorth Slope,” Oilfield Review 10, no. 2 (Summer 1998): 20–35.McCarty TM, Stanley MJ and Gantt LL: “Coiled TubingDrilling: Continued Performance Improvement in Alaska,”paper SPE 67824, presented at the SPE/IADC DrillingConference, Amsterdam, The Netherlands, February 27–March 1, 2001.Luht R and Tinkham S: “Selection Crucial to CT DrillingSuccess,” The American Oil & Gas Reporter 46, no. 3(March 2003): 116–123.

In April 2003, BP-Sharjah embarked on anunderbalanced CT drilling program to performthrough-tubing sidetracks from existing wells inthe Sajaa gas-condensate field, United Arab Emi-rates (UAE). The objective was to improve well productivity and unlock additional reserves withmultilateral wellbores connected to existing primary vertical wellbores.

Since initial production in 1980, reservoirpressure in the Thamama limestone reservoir at12,000 ft [3,658 m] true vertical depth (TVD)declined from 7,900 psi [54.5 MPa] to less than2,000 psi [13.8 MPa]. Considerable gas and con-densate reserves remain, despite a significant20% annual production decline in early 2003.

The operator believed that overbalanceddrilling had caused formation damage, resultingin extensive well cleanup. Recent horizontalrotary drilling programs had suffered massive,incurable lost circulation and severe differentialsticking, which prevented some wells from reach-ing their geologic and drilling-length objectives.17

Underbalanced CT drilling operations weredesigned for wells previously completed withfree-hanging 5-in. tubing inside vertical 7-in. casing.18 Plans called for setting flow-through,through-tubing whipstocks in 7-in. casing aboveexisting perforations.

After milling a 3.8-in. casing-exit window, theCT drilling BHA—a specialized 3-in. wired CTdrilling BHA attached to 23⁄8-in. coiled tubing andwireline heptacable, a PDM designed for com-pressible fluids, and either a 3.75-in.polycrystalline diamond compact (PDC) or a 4.1-in. bicentered bit—would be used to drillunderbalanced with nitrogen [N2] energized fluids.

Three or more openhole laterals were to bedrilled to access up to 10,000 ft [3,048 m] of addi-tional reservoir per well (above). The initialphase of this campaign involved drilling 10 wellsand 29 laterals with more than 66,000 ft[20,117 m] of new open hole. Up to five lateralshave been drilled from a single exit window.Threefold production increases are common.

In several wells, underbalanced CT drillinghas increased production from about 5 MMcf/D[143,200 m3/d] to more than 25 MMcf/D[716,000 m3/d], limited by the flow restriction of5-in. production tubing.19 These successes moti-vated BP-Sharjah to pursue additional CT drillingwell candidates and extend the campaign. Schlumberger was recently awarded a two-yearcontract extension.

Directional hole sizes of 23⁄4-in. and 41⁄8-in. areconsidered optimal for CT load capacities, hole-cleaning fluid velocities and surface equipmentspecifications. However, 6-in. hole sizes and largercan be drilled under some conditions, particularly in vertical wells. Because of BHA limi-tations, directional CT drilling plans should targetbuild rates less than 50° per 100 ft [30.5 m]. Exit-window depths and CT drilling lateral lengthsshould be evaluated on a case-by-case basis.

Schlumberger is advancing CT drilling tech-nology worldwide through ongoing operations inAlaska, the Middle East, Venezuela and Indone-sia.20 Over the past five years, average CT drillinglateral lengths have ranged from 1,500 to 3,000 ft[457 to 1,044 m]. With increasing activity, the CTdrilling operating envelope continues to expandas evidenced by recent Schlumberger records:• a 15,800 ft [4,816 m] whipstock casing exit in

Colombia during 2002• more than 9,000 ft [2,743 m] of open hole

drilled underbalanced in a single reentry wellin the UAE Sajaa gas field during 2003

• the deepest whipstock casing exit at 16,240 ft[4,950 m] and deepest total CT drilling reentrydepth of 17,515 ft [5,339 m] in Alaska during 2004.

52 Oilfield Review

30-in. casing at 70 ft20-in. casing at 600 ft

13 3⁄8-in. casing at 6,100 ft

5-in. tubing

Typical Sajaa main wellbore

9 5⁄8-in. casing at 11,100 ft

7-in. liner at 14,400 ft

Main wellbore

Lateral 1

Shuaiba

Kharaib

Lekhwair

Lateral 2

Lateral 3

> Coiled tubing drilling in the Middle East. BP-Sharjah initiated reentry CT drillingoperations from existing wells of the Sajaa gas field in the United Arab Emirates(left). The drilling configuration consisted of 23⁄8-in. coiled tubing and a 3-in. BHA witha 4.1-in. bit. An inflatable whipstock was set above the perforations to mill a windowin the 7-in. casing of the main wellbore. Plans called for at least three horizontalsidetracks in each well (right).

Spring 2004 53

1. 2. 3. 4.

>Multilateral well interventions. The corrosion-resistant Discovery MLT system includesa controllable orienting device to rotate the tool and an adjustable bent sub. Wellborejunctions are located by moving the tool, which is actuated by fluid flow, up and downacross a target interval (1). When fluid flow exceeds a threshold rate, the lower toolsection changes from straight to bent (2). Each actuation cycle rotates the tool 30°,producing a surface-displayed pressure profile that confirms lateral orientation (3). Thissystem allows coiled tubing to selectively access any type of lateral for well cleanouts,logging, perforating, stimulation and cementing (4).

17. Mathes RA and Jack LJ: “Successful Drilling of anUnderbalanced, Dual-Lateral Horizontal Well in the SajaaField, Sharjah UAE,” paper SPE 57569, presented at theSPE/IADC Middle East Drilling Technology Conference,Abu Dhabi, UAE, November 8–10, 1999.

18. Suryanarayana PV, Smith B, Hasan ABM, Leslie C,Buchanan R and Pruitt R: “Basis of Design for CoiledTubing Underbalanced Through-Tubing Drilling in theSajaa Field,” paper SPE 87146, presented at theIADC/SPE Drilling Conference and Exhibition, Dallas,Texas, USA, March 2–4, 2004.

19. Pruitt R, Leslie C, Smith B, Knight J and Buchanan R:“Sajaa Underbalance Coiled Tubing Drilling ‘Putting It AllTogether’,” paper SPE 89644, prepared for presentationat the SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, Texas, USA, March 23–24, 2004.

20. Wright HJ, Aristianto B, Gan RG, Jenie JR and Kyaw HA:“Coiled-Tubing Drilling Reentry: Case History from East Kalimantan,” paper SPE 89632, presented at theSPE/ICoTA Coiled Tubing Conference and Exhibition,Houston, Texas, USA, March 23–24, 2004.

21. Multilateral wells are classified according to definitionsestablished during the Technical Advancement of Multilaterals (TAML) Forum held in Aberdeen, Scotland,July 26, 1999 and recently updated in a July 2002 proposal that was approved in 2003. These standardscharacterize wellbore junctions as Level 1, 2, 3, 4, 5 or 6based on degree of mechanical complexity, connectivityand hydraulic isolation.

In addition to incremental production andimproved reserve recovery, these worldwide CT drilling campaigns are yielding con-tinual improvements in wellsite safety and operational efficiency.

Accessing Lateral Well BranchesIn the past, reentry access to sidetracks from anopenhole main wellbore (TAML Level 1 junction)or openhole drains and dropoff lateral liners in acased well (TAML Level 2 junction) was not possible.21 This prevented remedial operations onindividual laterals and precluded effective reser-voir management. Schlumberger developed theDiscovery MLT multilateral tool to selectivelyaccess all types of multilateral junctions usingstandard CT equipment.

The Discovery MLT tool provides CT-conveyedcleanout, stimulation, cementing and well-logging options for wells with previously inacces-sible junctions and for multilateral completionswithout specialized diverter equipment. Thisacid-resistant tool operates solely on pressureand flow. Reentry operations are performed in asingle trip into the wellbore.

A flow-activated bent-sub controls tool opera-tion (above). Initially, the tool is indexed through360° to establish the lateral orientation. Afterrepeating this process to confirm the junction location, a pressure-telemetry signal tothe surface confirms lateral access. ZakumDevelopment Company (ZADCO) applied this

tool in the UAE.22 Multilateral completions in theUpper Zakum field tap several reservoir layerswith as many as 12 laterals drilled from a singlemain wellbore (above).

Previously, remedial access to individualbranches was not possible, which preventedeffective stimulation and production logging ofindividual laterals to evaluate treatment resultsand monitor production. Acid had to be bull-headed—pumped from surface—down wellboretubulars or coiled tubing with the end of pipenear a lateral entrance.

The majority of the acid reaction occurred atthe entrance of the openhole section, leaving theremainder of the lateral branch untreated. This

practice also created large voids that could col-lapse and prevent future access to the lateral orrestrict production. ZADCO successfully acidizedopenhole laterals in two offshore wells using Discovery MLT technology.

In the first use of this tool, ZADCO performeda selective treatment in one lateral of a well withfour branches. In a second well, two of the fivelaterals were treated individually. These jobstook seven days—four days of operations andthree days of mobilization, demobilization andweather delays—and cost 65% less than using adrilling rig. Production increased by 11% in thefirst well and 30% in the second well, which paidback the investment in two days.

The Discovery MLT tool has proved to be asimple, cost-effective lateral reentry solution thathelps maximize the productivity and performanceof multilateral wells. In another UAE well for adifferent operating company, the Discovery MLTsystem helped selectively cement a lateral andshut off water production utilizing coiled tubing.

In Oman, Petroleum Development Oman(PDO) successfully performed production loggingin a Saih Rawl field multilateral well.23 PDO selec-tively reentered and logged three lateralbranches to determine the water-injection profileand identify possible fractures in the formation.

54 Oilfield Review

30-in. casing at 310 ft MD

30-in. casing at 288 ft MD

7-in. liner at 7,867 ft MD

8,300 ft MD

10,152 ft MD

7,688 ft MD

9,255 ft MD

9,098 ft MD

9,255 ft MD

13 3⁄8-in. casing at 5,350 ft MD

13 3⁄8-in. casing at 5,185 ft MD

9 5⁄8-in. casing at 8,473 ft MD

9 5⁄8-in. casing at 7,870 ft MD

H-IAH-IA

H-IIA

H-IIB

H-IIC

H-IID

H-IIE

H-IIF

H-IIA

H-IIB

H-IIC

H-IID

H-IIE

> Selective lateral access. In the UAE Upper Zakum field, ZADCO needed to reenter two multilateralwells. The first well, drilled and completed with dual tubing, produced from four openhole laterals (left).The short string produced from a lateral in Reservoir H-IA, and the long string produced separatelaterals in Reservoirs H-IIB, H-IIC and H-IID. ZADCO selectively acidized the H-IIC lateral using aDiscovery MLT tool. The second well also had dual tubing (right). The short string produced a horizontallateral in Reservoir H-IA. The long string produced from horizontal laterals in the H-IIC, H-IID, H-IIE andH-IIF reservoirs. ZADCO selectively acidized the H-IID and H-IIE laterals with a Discovery MLT tool.

Spring 2004 55

The advantages and economics that make CTattractive for drilling and remedial interventionsalso apply for well completions. For example,techniques for running an electrical submersiblepump (ESP) on coiled tubing expand artificial-lift options for remote locations with limited rigavailability, for areas with high workover costsand for offshore wells.

Artificial LiftA CT-deployed ESP lifts fluid through the coiled tubing or up the annulus around a coiledtubing string. Prior to being purchased bySchlumberger, CAMCO company REDA installedthe first submergible pump on coiled tubing in1992 and the first coiled tubing ESP and powercable system in the UK in 1994. Today, REDACoilsubmergible pump technology installs and sup-ports the ESP power cable inside 2-in. or 23⁄8-in.coiled tubing (right).

The self-supporting Friction Deployed sub-mergible pump power cable minimizes CT unitand installation costs. The cable is no longerbanded to the coiled tubing during deploymentat a wellsite, but remains protected in an inhib-ited fluid. The coiled tubing can also be used as ahydraulic conduit for pressure actuation of packers, subsurface safety valves or other down-hole equipment.

Controlling wells with kill-weight fluids priorto an ESP installation is expensive and time-consuming, and often results in lower well pro-ductivity because of formation damage. TheREDACoil system allows for quick, safe coiledtubing deployment into a well under pressure.Placing the power cable inside coiled tubingassures a secure seal within the BOP and stripper head during installation.

Recent advances in REDACoil technology,including internal power, data and fiber-opticcables, have made it possible to produce highflow-rate wells at up to 20,000 B/D [3,180 m3/d]of fluid inside 7-in. casing. For well conditionsthat do not allow flow up the casing, placing aREDACoil system inside 7-in. production pipeisolates produced fluids from both the 95⁄8-in. wellcasing and the ESP power cable.

Friction Deployed powercable

CoilTOOLS connector

REDA lower connector

Motors

Universal motor base (UMB)

Protector

Special discharge head

Pump

Shrouded intake

Protector with UMB

5.5-in. x 15-ft shrouded tube

Fluted centralizer

7-in. retrievable packer

7-in. production tubing

9 5⁄8-in. casing

2 3⁄8-in. coiled tubing

Friction Deployedpower cable

2 3⁄8-in. coiled tubing

> Artificial-lift deployment. REDACoil CT-deployed electrical submersible pump (ESP) systems withinternal power cables reduce installation expenses and production downtime associated with remoteor high-cost wells and offshore platforms where space and rig availability are limited.

22. Dahroug A, Al-Marzooqi A, Al-Ansara F, Chareuf A andHassan M, “Selective Coiled-Tubing Access into Multilateral Wells in Upper Zakum Field: A Two-WellCase Study from Abu-Dhabi,” paper SPE 81716, presented at the SPE/IcoTA Coiled Tubing Conference,Houston, Texas, USA, April 8–9, 2003.

23. Al Farsi N, Ojulari B, Hook P and Staal TW: “A CombinedDiagnosis and Treatment Service for Multilateral InjectorWells,” paper SPE 84403, presented at the SPE AnnualTechnical Conference and Exhibition, Denver, Colorado,USA, October 5–8, 2003.

REDACoil technology has a proven recordwith more than 20 installations worldwide.Anadarko Petroleum has installed 12 REDACoilcompletions in Qatar.24 These systems were bottom-intake configurations with annular production. These wells have 95⁄8-in. casing atabout 4,000 ft [1,219 m] TVD with 4,000 to6,300 ft [1,920 m] MD. The maximum well incli-nation at pump depth is 86°.

The current REDACoil configuration consistsof 23⁄8-in. coiled tubing with internal power cable,a REDA lower connector, motors, universal motorbase, protector, discharge head, pumps, intakeand thrust protector. The 150-ft [46-m] BHA isinstalled inside a 7-in. liner. Fluid productionranges from 8,000 to 12,000 B/D [1,272 to1,907 m3/d] with only about 100 Mcf/D[2,864 m3/d] of gas. The BHT is 155°F [68°C].The lower completion contains a deep-set down-hole safety valve, sliding sleeve, permanentpressure and temperature gauges and chemical-injection mandrels.

On other REDACoil installations a mechani-cally activated FIV Formation Isolation Valvedevice may also be included. This ball-type valveis actuated by a stinger at the bottom of theREDACoil assembly to allow underbalanceddeployment of the ESP. It is also possible to add aPhoenix MultiSensor system for continuousdownhole data-gathering. This sensor monitorspump and well parameters and transmits datathrough the power cable.

Offshore, CT expands ESP applications whenthrough-tubing installation is feasible, eliminat-ing the need for conventional rig workovers andminimizing downtime as well as deferred produc-tion. This unique, flexible technique haspotential in small or marginal offshore fieldswhere no gas-lift infrastructure exists or whereconversion from gas lift to ESP is required.

In the South China Sea Magpie field ofSoutheast Asia, Shell Brunei installed two off-shore REDACoil completions similar to those inQatar except for using 2-in. instead of 23⁄8-in.coiled tubing.25 The well depth is 3,400 to3,800 ft [1,036 to 1,158 m] with well inclinationsof 60 to 65°. REDACoil equipment is the same asthat used in Qatar, but the pumps have lowerfluid-volume output.

Shell selected the REDACoil system to meetworkover cost objectives when converting fromgas lift to ESP as the field matured. Combinedwith technologies like an advanced gas handlerand additional mechanical barriers, the REDACoil system reduced costs and increasedoil production in two wells. Production from thefirst REDACoil installation, Magpie Well 14,increased to 2,201 B/D [350 m3/d], 56% morethan the gas-lift design of 1,415 B/D [225 m3/d].

In the second well, ESP production increasedto 4,560 B/D [725 m3/d], 32% more than the3,459 B/D [550 m3/d] with a gas-lift design. Shellestimates that converting from gas lift to ESPwill recover an incremental 3.4 million bbl

[540,000 m3] of oil from the first well and 2 mil-lion bbl [318,000 m3] from the second. TheREDACoil system in Magpie Well 14 continues tooperate after more than 41⁄2 years.

56 Oilfield Review

> Aerial view of coiled tubing drilling and completion operations in the Sajaa gas field of the UnitedArab Emirates.

24. Penny RC, Patterson JC, Stamey RC and Dwiggins JL:“Coiled Tubing and ESP Technology Improve Field Evaluation Cost,” paper SPE 38332, presented at the SPE Western Regional Meeting, Long Beach, California,USA, June 25–27, 1997.Patterson JC, Pursell JC and McHugh MD: “A CoiledTubing Deployed Electric Submersible Pumping SystemEnhance Field Development Costs,” presented at the SPEESP Workshop, Houston, Texas, USA, April 26–28, 2000.

25. Pastor G, Knoppe R and Shepler R: “South China Sea GasLifted Oil Well Conversion Utilizing Coil Tubing ElectricSubmersible Pumping Systems,” presented at the SPEESP Workshop, Houston, Texas, USA, April 28–30, 1999.

26. Lode JE, Møller RE, Nesvik KT, Buchanan A and Myklebust J: “Further Developments for Coiled TubingFloater Operations,” paper SPE 89623, presented at theSPE/ICoTA Coiled Tubing Conference and Exhibition,Houston, Texas, USA, March 23–24, 2004.Leising LJ, Ali AM, Young JR and Arciniegas OE: “Re-Enterable Through-Tubing Gravel-Pack System,”paper SPE 89524, presented at the SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, Texas, USA,March 23–24, 2004.

27. Barclay C, Pellenbarg J, Tettero F, Pfeiffer J, Slater H,Staal T, Stiles D, Tilling G and Whitney C: “The Beginningof the End: A Review of Abandonment and Decommis-sioning Practices,” Oilfield Review 13, no. 4 (Winter2001/2002): 28–41.

28. Barclay IS, Johnson CR, Staal TW, Choudhary S and Al-Hamandani A: “Utilizing Innovative Flexible SealantTechnology in Rigless Plug and Abandonment,” paperSPE 89622, presented at the SPE/ICoTA Coiled TubingConference and Exhibition, Houston, Texas, USA, March 23–24, 2004.

29. Tettero F, Barclay I and Staal T: “Optimizing Integrated Rigless Plug and Abandonment — A 60 Well Case Study,”paper SPE 89636, presented at the SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, Texas, USA,March 23–24, 2004.

Spring 2004 57

Ongoing Developments and OperationsIn almost every area of oil and gas activity, CT isa firmly established technology for remedial wellinterventions and the drilling and completion ofnew wells (previous page and right). CT allowsselective placement and accurate controlleddelivery of chemical, acid and fracturing treat-ments. It is also used to clean, protect or replaceexisting tubulars. CT versatility is especially valu-able in wellbores with questionable tubularintegrity, or wells requiring flow conformance forwater and gas control, and also for sand control.

CT services can be executed efficiently underalmost any condition, including live wells, whileensuring optimal well control. In addition, CTallows real-time communication with downholetools conveyed to control treatments, manipulatehardware and analyze reservoir properties. Thistechnology has proved effective for developinglow-permeability, low-pressure and mature ordepleted reservoirs in which conventional tech-niques fail to achieve commercial production.

Upgrading existing tools and techniqueswhile developing new technology remains a keyto CT success as does improving our understand-ing of coiled tubing behavior and riskassessment. Combining multiple systems or pro-cesses yields new and unique solutions to oldwell-intervention challenges. For example,Schlumberger has made further advances in sys-tems for operating CT units from anchoredfloating vessels and platforms, and recently fieldtested a new through-tubing gravel-pack systemwith reentry capabilities.26

Deeper, higher pressure, higher temperatureand extended-reach wells increase the complex-ity of CT operations. In 1995, Schlumbergerbegan using simulators in training centers atKellyville, Oklahoma, USA, and Bottesford, England, to familiarize employees with CT equipment, operations and contingency pro-cedures. Capitalizing on extensive simulatorexperience and continual improvement inportable computer capabilities, Schlumbergerfollowed this with development of portable simulation-based training.

The resulting CT Sim computer-based learn-ing resource presents concepts, equipmentfunctionality and operating procedures. Theintent was to provide prerequisite knowledge andpractice in order to optimize training at thelearning centers or in field locations. Scheduledfor release in 2004, the CT Sim program will be akey component for training and recertification ofCT supervisors and engineers.

Schlumberger continues to develop andrefine equipment, procedures and techniques toextend the operating pressure ranges for CT jobs,including high-pressure applications up to13,500 psi [93.1 MPa]. Also in development arespoolable CT connectors and completion equip-ment, including gas-lift valves, which willfacilitate operations in logistically challengingareas, such as mature offshore platforms andremote or environmentally sensitive locations.

However, not all well-intervention applica-tions involve pushing the limits of CT tubularcapabilities, equipment and tools. CT continuesto be a workhorse for many conventional welloperations and services. Petroleum Developmentof Oman (PDO) used CT to optimize plug andabandonment (P&A) practices.27

Rigless methods with new cement andsealant technologies minimize costs while ensur-ing long-term environmental protection in theseonce prolific oil wells.28 CT saved up to 30% com-pared with P&A campaigns using conventionaldrilling and workover rigs. This represented atotal savings of more than US$ 5 million in arecent 60-well program.29

As CT reliability improves, operators arereevaluating candidate wells and targeting morecompletions for through-tubing or concentricremedial interventions, including some wells pre-viously considered too risky for CT operations. Tothat end, CT equipment and string reliability con-tinue to be the focus of efforts to reducedownhole risks and decrease operational failures.

Schlumberger is committed to maintainingtechnical leadership in CT services through cost-effective solutions that address operator needsfrom the most basic to the most complicatedapplications, with skilled personnel to imple-ment them. The goal is to assure optimal welland reservoir performance through safe and effi-cient operations. —MET

> Coiled tubing pilot drilling program in Colombia’s Cusiana field.