Abderrahmane BoumaliSonatrachAlgiers, Algeria

Mark E. BradyDoha, Qatar

Erik FerdiansyahSanthana KumarStan van GisbergenPetroleum Development Oman Muscat, Oman

Tom Kavanagh Sharjah, United Arab Emirates

Avel Z. OrtizSugar Land, Texas, USA

Richard A. OrtizBP Sharjah Oil CompanySharjah, United Arab Emirates

Arun PandeyMuscat, Oman

Doug Pipchuk Calgary, Canada

Stuart WilsonMoscow, Russia

Winter 2005/2006 29

Many operating companies are turning tothrough-tubing, or concentric, operations tosolve difficult production problems and to meetdemanding well-intervention or wellbore-recompletion challenges. Steeply decliningproduction output and insufficient replacementof oil and gas reserves have compelled operatorsto reexamine field-development strategies andreservoir-management efforts. Increasingly, assetmanagers need to optimize the performance ofboth new and existing wells to meet globaldemand for petroleum.

Long strings of relatively small-diameter steelpipe, or coiled tubing, can be mobilized quickly todrill new wells or reenter wells through existingwellbore tubulars. This technology also is used toperform initial completions, remedial interven-tions and workovers, or recompletions. Comparedwith conventional rotary drilling, workover andsnubbing units, coiled tubing spooled onto a reelfor transport and the associated surfaceequipment for deployment and well insertion offerseveral advantages.

Increased efficiency comes throughcontinuous pipe deployment and retrieval underpressure, or “live” conditions, without having tocontrol, or kill, a well. In addition, there is noneed to pull production tubulars from thewellbore and perform downhole operations byrerunning individual joints of a conventionalworkstring with threaded connections.

The capability of working under pressure andthe unique ability to pump fluids at any time,regardless of coiled tubing depth or direction oftravel in a wellbore, offer distinct benefits andoperational flexibility. Compared with wireline or

slickline, coiled tubing provides relatively highload capacities for deeper vertical or extendedhigh-angle reach, and for greater tensilecapacity, or overpull, downhole.

These capabilities facilitate wellborecleanouts; jetting or lifting wells with inert gases or lighter fluids; perforation washes; acidand hydraulic fracturing stimulations, sand-consolidation or sand-control treatments;cementing; fishing or milling; and both direc-tional and underbalanced drilling. Installingwireline, data or power cables inside a string ofcoiled tubing allows real-time well logging,downhole monitoring and control, measurementswhile drilling and operation of electricalsubmersible pumps.1

Using application-specific downhole systems,coiled tubing concentric operations are helpingoperators increase well and field productivitythroughout the entire life cycle of producingreservoirs. Even under adverse economicconditions and harsh subsurface operatingenvironments, coiled tubing facilitates cost-effective interventions that can optimizehydrocarbon output from wells, increase reserverecovery from reservoirs and greatly improvefield profitability.

Coiled tubing is a viable alternative in manydemanding applications that must be performedwithout a rotary drilling rig or workover unit tomaximize profitability. New integrated systemsand innovative combinations of tools andtechniques have been keys to recent success usingcoiled tubing in several specialized applications.

Coiled Tubing: Innovative Rigless Interventions

Reentry drilling, reservoir stimulation and wellbore recompletions often need to be performed

without rotary rigs or conventional workover units as a means of maximizing production economics.

Coiled tubing allows remedial operations to be performed under pressure, or “live” conditions,

without pulling well tubulars. Collaboration between operators and providers of this technology

continues to yield tools and techniques that improve productivity in both new and mature fields.

For help in preparation of this article, thanks to Fardin AliNeyaei, Ruwi, Oman; and Allan Lesinszki, Talisman EnergyCompany, Calgary, Alberta, Canada.Blaster MLT, CoilFLATE, DepthLOG, Discovery MLT,Jet Blaster, NODAL and Secure are marks of Schlumberger.Allen-Bradley and FrontView are marks of Allen-BradleyCompany, Inc.

28 Oilfield Review

This article begins with an overview of coiledtubing equipment and practices that are beingused for underbalanced drilling in the MiddleEast. We then present a new downhole systemthat was used to locate and stimulate individuallateral branches of multilateral wells in Canada.That discussion is followed by a case history fromAlgeria demonstrating selective isolation andstimulation of closely spaced intervals. Thearticle concludes by presenting a methodology forperforming multiple through-tubing operationsduring a single rig-up and wellsite operation.

Underbalanced Reentry Drilling The Sajaa field in the United Arab Emirates(UAE) produces from a deep, low-pressurecarbonate reservoir. Amoco, now BP, drilled thefirst wells in this prolific gas field during theearly 1980s. Initial development activity involvedabout 40 vertical wells drilled with overbalancedpressures by conventional rotary rigs. Later,many of these wells were recompleted withcemented 7-in. liners tied back to surface and5-in. production tubing without a downholepacker (right).

During the 1990s, BP Sharjah sidetracked afew of these wells using rotary rigs andunderbalanced drilling techniques. Morerecently, this experience was helpful duringplanning and implementation of a new infilldrilling campaign. As reservoir pressure and wellproductivity declined, BP needed to accessreserves in areas that were not being drainedeffectively by the original wellbores.

A team of BP personnel from North SlopeAlaska operations, Houston EngineeringTechnical Practices (ETP), UK ETP, SunburyResearch and Sharjah engineering and operationsgroups evaluated several methods for reenteringwells and drilling underbalanced. They foundcoiled tubing to be the best option. In March 2003,BP Sharjah began drilling multilateral sidetracksfrom existing wellbores using coiled tubing forunderbalanced operations.2

The BP team chose 2 ⁄3⁄⁄ -in. outside diameter(OD) coiled tubing with an internal wirelinecable as a means of continuously transmittingdownhole data and measurements to surface.Initially, BP used an 80,000-psi [552-MPa] yieldstrength, uniform wall thickness tube that couldbe swapped end for end, or reversed, on the spool

30 Oilfield Review

2. Kavanagh T, Pruitt R, Reynolds M, Ortiz R, Shotenski M,Coe R, Davis P and Bergum R: “Underbalanced CoiledTubing Drilling Practices in a Deep, Low-Pressure GasReservoir,” paper IPTC-10308-PP, presented at theSPE Annual Technical Conference and Exhibition, Dallas,October 10–12, 2005.

> Typical wellbore configuration in the Middle East Sajaa gas field. BP SharjahOil Company initiated coiled tubing underbalanced reentry drilling operationsfrom existing wellbores in the Sajaa gas field of the United Arab Emirates (top).Most of these wells had been recompleted with cemented 7-in. liners tied backtto surface and 5-in. production tubing (bottom left). A few wells were reenteredttin the 1990s to drill lateral sidetracks with conventional rotary rigs andunderbalanced drilling techniques (bottom right).tt

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30-in. casing at 100 ft

13 3⁄3 4⁄⁄ g-in. casing at 6,000 ft

9 5⁄5 8⁄⁄ -in. casing at 11,000 ft

7-in. packer at 12,000 ft

5-in. tubing

7-in. whipstock 6-in. bit

4 3⁄3 4⁄⁄ -in. motor

3 1⁄1 2⁄⁄ -in. drillpipe

7-in. liner at 14,000 ft

20-in. casing at 600 ft

Winter 2005/2006 31

to extend fatigue, or usable, life. This stringdesign evolved to a 90,000-psi [620-MPa] yieldtapered-wall tube with high yield strength andsufficient hydrogen sulfide [H2S] resistance. Thefootage that could be drilled with these taperedstrings was found to be acceptable even thoughthe tapered strings could not be reversed.

Tapered strings minimize loads on thesurface injector head, reduce pickup weightsduring normal operations and increase availableoverpull downhole in stuck-pipe situations. Lessweight on bit (WOB) is available for drillingcompared with the uniform-wall strings, but thishas not been a disadvantage because of therelatively soft formations in this area andsuccessful efforts to optimize bit performance.

Most laterals are limited in length becausethe pickup weight at total depth (TD) becomestoo high, not because of limited WOB. Inaddition, drilling longer laterals may berestricted by increased friction pressures whiledrilling, which cause a higher equivalentcirculating density and a degree of overbalanceat the bit that formations can no longer tolerate.

A coiled tubing drilling tower builtspecifically for Sajaa field operations supportedthe coiled tubing injector; the wellhead andblowout preventer (BOP) stack supported theweight of the coiled tubing string (right).

The tower work decks were positioned foreasy access to BOP systems, which provide dualbarriers while deploying tools under pressureand drilling underbalanced. The BOP system alsoprovides two mechanical barriers duringnonroutine events, such as elastomer-sealfailures or leaking BOP rams, and other minor contingencies.

A hydraulically operated choke manifold onthe fluid-return line controls flow from thewellbore and downhole pressure during drillingoperations. This manifold is fitted withredundant isolation valves for each of the twochokes to maintain constant flow even if one sidebecomes plugged or inoperable. All of thecommon drilling contingencies and well-controlsituations that have occurred have been handledsafely using these surface systems.

If gas went directly to the pipeline, high linepressure might preclude underbalanced opera-tions on many Sajaa field wells. Therefore,produced gas from returning fluids is sent to avertical flare stack or to a compression system.Sending gas to the Sajaa processing plant whiledrilling minimizes lost or deferred production.

> Sajaa field surface equipment for coiled tubing. Schlumberger built a four-piece coiled tubing drilling tower specifically for the Sajaa project (top).This modular structure supports only the injector head. It was designed towithstand maximum sandstorm winds, but is lightweight for easy transportand setup. The blowout preventer (BOP) stack (bottom), which ensuresdouble pressure barriers at all times, and the wellhead support the weightof the coiled tubing string.

-in. shear/seal preventer

7 1⁄1 16⁄⁄ -in. annular preventer

3-in. inverted pipe/slip preventer

3-in. pipe/slip preventer

-in. pipe/slip preventer

-in. pipe/slip preventer

-in. shear/seal preventer

The bottomhole assembly (BHA) forunderbalanced drilling is a 3-in. OD, wiredassembly powered from the surface through awireline cable inside the coiled tubing (left).This BHA includes two upper and two lower ballvalves that can isolate both wellbore pressureand coiled tubing pressure. The upper valveseliminate the need to bleed pressure from thecoiled tubing every time a BHA is assembled ordisassembled.

A downhole data system acquires pressure,temperature, WOB, lateral and stick-slipvibration, gamma ray, casing collar location,azimuth and inclination measurements. BP alsohas used a resistivity logging tool with multipledepths of investigation while drilling some of the wells.

To reduce vibration-related failures, BakerHughes Inteq moved electronic components inthe BHA away from the downhole motor andswitched from bicentered 4 ⁄1⁄⁄ -in. polycrystallinediamond compact (PDC) bits to 33⁄3⁄⁄ -in. gaugePDC bits. The gauge bits provided a higher rateof penetration (ROP) and less vibration withoutadversely impacting borehole size and wellproductivity. Engineers also monitored lateraland axial vibrations closely, and reducedinjection rates to minimize BHA vibrationsduring hole-cleaning, or wiper, trips.

These measures reduced BHA failures causedby excessive vibrations when drilling with two-phase liquid and gas. A BHA can now operate forseveral days to more than a week at a time. BPuses a 2 ⁄7⁄⁄ -in. air-drill motor (ADM) with anexcellent performance history, so motor failuresare rare. BP and Baker Hughes Inteq optimizedthe rotor-stator clearance and materials used inthese motors to extend ADM operating life underharsh wellbore conditions. The longest motor runto date lasted more than 12 days and drilled9,763 ft [2,975 m].

BP drills with underbalanced pressures usingnitrogen [N2] and fresh water with a biodegrad-able friction reducer to reduce pickup weightsand pumping pressures. Typically, BP drills threeor more multilateral sidetracks, each about3,000 ft [914 m] in length, through a singlecasing-exit window (next page).

Milling windows with through-tubing,inflatable whipstock assemblies has been themost challenging part of this project, and the onethat has improved the most. Optimized millingtechniques resulted in better casing-exitwindows to allow easier passage of 33⁄3⁄⁄ -in. gaugePDC bits. BP also developed a molded resin cap,which disintegrates during the first few minutesof drilling, to guide bits through a casing window.

32 Oilfield Review

> Coiled tubing bottomhole assembly (BHA) for underbalanced drilling intthe UAE. The BHA used for underbalanced reentry drilling in the Sajaa fieldincludes dual upper and two lower ball valves to isolate both wellborepressure and coiled tubing pressure. This eliminates the need to bleedinternal pressure from the coiled tubing every time the BHA is assembledor disassembled. It also includes sensors to acquire internal and externalpressure, external temperature, weight-on-bit (WOB), lateral and stick-slipvibration, casing collar locator (CCL), directional azimuth and inclination,and gamma ray measurements. Baker Hughes Inteq positions electroniccomponents in the BHA as far as possible from the 27⁄7⁄⁄ -in. downhole air-drillmotor (ADM). In addition, BP now uses a 33⁄3⁄⁄ -in. gauge polycrystallinediamond compact (PDC) bit instead of a bicentered 4 ⁄1⁄⁄ -in. PDC bit to reducedownhole vibrations and related BHA failures.

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Winter 2005/2006 33

The BHA for this project was designed foropenhole drilling and could not survive for longunder the severe vibrations of milling windowsusing liquid and gas. Therefore, BP initiallyperformed milling operations with single-phaseliquids, but this often resulted in the loss of largevolumes of water to the formation. In some wells,excessive losses made it difficult to reestablishwell flow and underbalanced conditions when itwas time to start drilling a sidetrack because thesurrounding formation was saturated, or loaded,with water.

In wells that will not tolerate excessive fluidlosses, BP mills casing windows using liquid andgas two-phase drilling fluids and PDC bitsspecifically designed for milling with no

electronics in the BHA. BP has successfullymilled five 3.8-in. windows in underbalancedconditions using two-phase fluids withoutdownhole pressure sensors.

BP shuts wells in before mobilizing the coiledtubing unit to allow the near-wellbore pressure tobuild up. Extremely low-pressure intervals requirelonger shut-in periods to achieve and maintainunderbalanced conditions. In this way, availablereservoir pressure is conserved for as long aspossible while drilling. As lateral drilling proceedsand frictional pressures increase, additionalreservoir pressure must be encountered to ensureunderbalanced conditions.

In areas of the reservoir with higherpressures, BP maintains underbalanced drilling

conditions by manipulating the choke manifoldat the surface. At some point, however,bottomhole pressure exceeds reservoir pressureand drilling becomes overbalanced from thatpoint on. If the formation permeability is lowenough to tolerate some degree of overbalance,drilling can continue to extend the lateralbranches as far as possible.

While drilling with slightly overbalancedpressure, engineers limit the ROP, make shorterwiper trips to remove excess cuttings, reducefluid injection rates and minimize or eliminateN2 foam sweeps to avoid additional increases inpressure. BP continues drilling until theoverbalance gets too high, pickup weights get tooclose to the coiled tubing yield strength, or thereis no additional forward penetration.

Using these techniques, BP Sharjah hasreentered 37 wellbores and drilled more than 150lateral sidetracks with a combined footage thatexceeds 300,000 ft [91,440 m]. To date, thelongest single lateral drilled has been 4,350 ft[1,326 m], and the most footage drilled during asingle reentry has been 14,487 ft [4,416 m] witheight laterals. Accessing reserves that were notbeing drained by the original wellbores reducedthe production decline in Sajaa field, signifi-cantly extending the life of this field.

From health, safety, cost and environmentalperspectives, this program also has beenextremely successful. During more than two and ahalf years of drilling, encompassing more than1 million staff-hours of work, there have been nolost workdays.

In the early phases of this project, BPencountered rig-up, equipment and operationsproblems that required 79 days to complete thefirst well. Wells are currently drilled in only 20 to30 days. Rig moves, which initially took almostnine full days, now require only 2.5 days.

BP maintains an extensive database thatfacilitates knowledge sharing and continuousimprovement by capturing operational practicesand experience from each contractor. Thedatabase includes everything from rigging down,rig moves and rigging up, to milling casing-exitwindows and drilling laterals.

Multilateral wells maximize wellbore contactwith a reservoir, increase well productivity andoptimize reserve recovery. However, productionenhancement and maintaining well productivityin these types of completions require cost-effective methods for performing stimulationtreatments. In addition to reentry drilling, coiledtubing also plays a vital role in wellbore remedialoperations and reservoir stimulation treatmentsfor multilateral wellbores.

> Sajaa field reentry multilateral drilling. BP set a whipstock above existingperforations or openhole sections to allow milling of an exit window in the7-in. casing of the main wellbore below the end of the production tubing.Plans called for drilling at least three horizontal lateral sidetracks in eachwell using coiled tubing and underbalanced drilling techniques.

5-in. tubing

2 3⁄3 8⁄⁄ -in. coiled tubing

3-in. BHA

2 7⁄7 8⁄⁄ -in. ADM

3 3⁄3 4⁄⁄ -in. PDC bit

7-in. packer

Through-tubingexpandable whipstock

>Multilateral well interventions and lateral access. The corrosion-resistant Discoveryt MLT multilateralttool includes an adjustable bent subt and a controllable orienting device to rotate the tool. Lateralwellbore branches 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 tool section changesfrom straight to bent (2). Each actuation cycle rotates the tool 30°, producing a surface-displayedpressure profile that confirms lateral orientation (3). This coiled tubing system allows selectiveaccess to any type of lateral junction for cleanouts, logging, perforating, stimulation and cementingoperations (4 and lower right).tt

1 2 3 4

Multilateral Well StimulationsTalisman Energy drillsy wells in the Turner Valleyrfield of Alberta,f Canada, that consist of af mainawellbore and two or morer horizontal openholelaterals targeting porous, upper and lowergeologic units of thef dolomitic Rundle formation.Remedial operations in these wells traditionallywere inefficient, ineffective and expensive.Engineers needed an effective means of conveyingfacid into the individual well branches to optimizeproduction from multilateral completions.3

Previous methods of blindlyf searchingy for andrandomly accessingy laterals often left Talismanand other operating companies in this areauncertain about the effectiveness of cleanoutfoperations and acid treatments. Schlumbergerintegrated two technologies—the Discovery MLTymultilateral tool and the Jet Blaster jetting scaleremoval service—to access and stimulateindividual lateral branches without the need forcomplex, permanent well-completion equipment.

Initially, producers in this area performedstimulation treatments on multilateral wells inseveral steps. They madey separate runs with twodifferent BHA configurations, hoping torandomly accessy each lateral. The Jet Blasterservice was used during the first run to scour theborehole wall with a high-energy fluidy jet andreconnect with the rock-matrix permeabilityx(above left).

A secondA run followed with a flexible BHAthat had different bend angles than the naturalcurvature at the lower end of thef coiled tubing.The disadvantage of thisf “hunt-and-hope”approach was that operators had no control overwhich lateral the BHA wouldA enter, so thesame well branch might get treated twice.

Even when applied repeatedly, this methoddid not significantly improvey well productivity.Subsequently, companies began using a jettingtool only duringy the first run followed by ay secondrun without the jetting tool, using only ayDiscovery MLTy tool to locate and treat individuallaterals (left).

This technique routinely accessedy the secondlateral in one run, but only they first lateral wasoptimally treatedy with the high-energy rotaryyjetting tool. Operators considered the benefit ofmechanically removingy damage with a high-energy fluidy jet in just one branch worth the costand risk ofk makingf multiple runs.

In wells with closely spacedy laterals, therewas still uncertainty abouty which lateral hadbeen accessed, especially ify measuredf depthswere within about 50 ft [15 m] or if helicalf

34 Oilfield Review

>Mechanical scale-removal. The Jet Blastert tool consists of a rotating head,a drift ringt and opposing offset nozzlest that removet formation damage andscale from borehole or tubular walls.

Jet nozzleRotating head Scale

Drift ring

Borehole wall

Winter 2005/2006 35

lockup of the coiled tubing occurred. There alsowere the possibilities of treating a lateral twiceor not at all. To address these problems and tofacilitate effective stimulation of multilateralwells, Schlumberger developed an integratedlateral-locating and rotary jet-wash tool.

This new Blaster MLT multilateral reentrystimulation and scale removal system combinesthe capabilities of a Discovery MLT tool and aJet Blaster tool. This unique system can accessall of the lateral branches in a well to convey acidand scour the borehole with a high-energy fluidjet. Several laterals can be treated in a singletrip, which reduces job time at the wellsite.

Qualification testing and verification ofBlaster MLT system capabilities were performedat the Schlumberger Reservoir Completions(SRC) Center in Rosharon, Texas. Varioustests were conducted to determine operatingparameters, develop treatment procedures andcorrelate a theoretical model that aids inpredicting tool performance at specific flowrates. Engineers ran the system in a 7,000-ft[2,134-m] test well to compare surface-testresults with actual downhole performance dataand were able to predict operating flow rateswith reasonable accuracy.

Schlumberger also performed a series ofrigorous flow-loop tests, ranging from 10 to12 hours, to evaluate the durability of thissystem. During extended operating periods,injection rates were increased and decreasedwhile pumping fresh water, N2 or fluids foamedwith N2. The Blaster MLT system performedwithin the initial design parameters without anytool failures.

Talisman Energy performed stimulationtreatments in two similar wells of the TurnerValley field, one with a Jet Blaster tool followed bya Discovery MLT tool and the other with the newintegrated multilateral jet-wash tool. The BlasterMLT system was run in a multilateral well toperform separate acid treatments in each lateralbranch during a single trip into the wellbore.

This newly drilled openhole completionconsisted of a main borehole and two lateralsidetracks. The true vertical depth (TVD) of thiswell was 8,888 ft [2,709 m]. The longest lateralleg extended to 11,387 ft [3,471 m] measureddepth (MD). The multilateral jet-wash tool wasrun into each openhole lateral.

The lateral-locating mechanism was notrequired to enter the first well branch. However,the Blaster MLT tool was activated to locate andaccess the other two branches. Lateral accessand tool location were verified by correlating theTVD and MD of each branch, which confirmed thefunctionality of the Blaster MLT system (above).

After the bottom of each lateral was reached,the BHA was slowly pulled back to the entrypoint while the high-energy jet-wash componentscoured the borehole wall. Sharp increases incirculating pressure confirmed continuousjetting action throughout each lateral. Injectionpressures and flow rates indicated that the

system performed as expected. Treating fluidswere effectively conveyed to the formation withno downtime.

At the top of each lateral, the fluid injectionrate was reduced to zero to equalize the internaltool pressure with the wellbore pressure. Afterall three laterals were treated, the BHA waspulled into the intermediate casing to purge thetool and tubing, and to lift the well with N2.Schlumberger found no indications of tool failure or wear when the system was inspected atthe surface.3. Lesinszki A, Stewart C, Ortiz A, Heap D, Pipchuk D and

Zemlak K: “Multilateral/High-Pressure Jet Wash ToolSystem Successfully Employed in Multilateral Wells,”paper SPE 94370, presented at the SPE/ICoTA CoiledTubing Conference and Exhibition, The Woodlands,Texas, USA, April 12–13, 2005.

> Multilateral jet-wash system in a well with three lateral branches (top). The integrated Blaster MLTmultilateral tool combines the lateral-access capabilities of the Discovery MLT system and thehigh-energy rotary jetting action of the Jet Blaster tool. This unique single-trip tool conveys a high-energy stream of acid or other stimulation fluid directly onto the borehole wall to scour the formationrock face. Compared with previous combinations of tools and techniques, this method ensuredaccess to every lateral in a well and provided more effective application of treatment fluids torestore the undamaged matrix permeability of the Rundle formation in the Turner Valley field ofAlberta, Canada (bottom).

Discovery MLTassembly

Jet Blasterassembly

The Blaster MLT system ensured lateralaccess and reduced the number of trips into thiswellbore from three to one, which resulted in a50% reduction in time required at a wellsite.Talisman Energy successfully treated four otherwells, and believes that the multilateral jet-washsystem will aid production optimization efforts inthe Turner Valley field and other area fields. Eachof these jobs, including rig-up and rig-down, werecompleted in about 48 hours.

New multilateral wells can be treatedeffectively and existing underperforming wellscan be reentered to enhance production andhydrocarbon recovery. Exploratory wells withopenhole sidetracks and multilateral comple-tions in low-permeability formations now can bestimulated more effectively to better evaluate,characterize and produce a reservoir.

Combining coiled tubing tools and tech-niques also provides novel solutions in otherstimulation and remedial applications, includingselective zonal isolation and diversion ofhydraulic fracturing or acid treatments.

Accurate Zonal IsolationSonatrach needed a reliable, rigless techniquefor isolating and selectively stimulating closely spaced perforated intervals in theHassi-Messaoud field, Algeria.4 This NorthAfrican field produces from a thick sandstone atabout 3,300 m [10,827 ft] with four distinctreservoir intervals and a transition zone. Most ofthe wells have cemented liners with multipleperforated intervals.

Traditionally, Sonatrach circulated oil-basefluids to control these wells prior to any well-

intervention operations, which often resulted innear-wellbore formation damage. This operatorperforms about 50 acid stimulations each year to remove damage and restore or optimizewell productivity.

Well MD 264 was producing from twoperforated intervals: a hydraulically fracturedupper zone and two deeper, low-permeabilityzones that were underperforming (below left).Only 3 m [10 ft] of unperforated casing wasavailable from 3,430 to 3,433 m [11,253 to11,263 ft] between the upper and lowerunderperforming intervals.

This well, which was drilled to 3,503 m[11,493 ft] and completed open hole in the late1970s, initially produced 329 m3/d [2,069 bbl/d].3

36 Oilfield Review

> Concentric zonal isolation and selectivestimulation. Sonatrach wanted to isolate anupper hydraulically fractured zone in Well MD264 of the Hassi-Messaoud field, Algeria, withoutkilling the well. This would allow selectivestimulation of a lower perforated interval withhydrofluoric [HF] organic acid. Through-tubingttreatment success depended on using coiledttubing to set an inflatable packer in a 3-m [10-ft]section of unperforated casing between thettwo intervals.

4 1⁄2-in. liner

InflatedCoilFLATEpacker

10 ft

Organic acidtreatment

> Inflatable coiled tubing packers. Heavy-duty tapered slats, a high-strength carcass restraint system,a composite inflation bladder and a chemically resistant elastomer element anchor CoilFLATE high-pressure, high-temperature (HPHT) packers in place and provide a high-pressure seal even at largeexpansion ratios—a 5,000-psi [34.5-MPa] differential at a 2 to 1 expansion and a 2,000-psi [13.7-MPa]differential at a 3 to 1 expansion. These packers withstand extended exposure at temperatures up to375°F [191°C] in almost any chemical environment. The 2 ⁄1⁄⁄ -in. OD CoilFLATE HPHT packer can expandtto more than three times its initial OD and can set in casing sizes up to 7 ⁄5⁄⁄ -in. OD. After expansion,tthese packers allow injection above and below the packer or both. Following a stimulation treatmentand while still connected to the coiled tubing, the packer can be deflated back to approximately itsoriginal 2 ⁄1⁄⁄ -in. OD for retrieval through wellbore restrictions of about 2.205 in.

Winter 2005/2006 37

In the mid-1990s, Sonatrach installed a cemented4 ⁄1⁄⁄ -in. liner and perforated the upper intervalfrom 3,406 to 3,418 m [11,175 to 11,214 ft].

That zone failed to produce economicallyeven after proppant fracture stimulation.Sonatrach added perforations from 3,421 to3,464 m [11,224 to 11,365 ft], which produced57 m3/d [359 bbl/d] after an acid stimulation. A3

pressure buildup test and a NODAL productionsystem analysis indicated a high positive skin, orformation damage, and a potential undamagedproductivity of 94 m3/d [592 bbl/d]. Sonatrach3

wanted to selectively treat the lower perforatedintervals from 3,433 to 3,464 m [11,263 to11,365 ft] with hydrofluoric [HF] organic acid.

To avoid further damage from killing the well,engineers decided to perform this treatmentthrough the existing production tubing usingcoiled tubing and an inflatable packer to isolatethe upper hydraulically fractured interval.Treatment success depended on accuratelysetting the packer.

If the packer were set too high, treatmentfluid might take the path of least resistance anddivert into the upper previously fracture-stimulated zone; if set too low, a large part of thelower perforated interval might not be treated,increasing risk of damage to the outer packerelements and internal bladder, which mightprevent inflation.

The inflatable packer had to withstand highdifferential pressures across the packer withoutleaking or failing because the deeper, low-permeability intervals might require treatmentinjection pressures as high as 3,500 psi [24 MPa],even at minimal pumping rates. Sonatrach usedthe CoilFLATE coiled tubing through-tubinginflatable packer, which was designed towithstand harsh downhole wellbore conditionsand corrosive treatment chemicals underextended periods of exposure at up to 375°F[191°C] (previous page, right).

An initial attempt to position and inflate thepacker without real-time downhole depthcorrelation failed, reinforcing the need foraccurate depth correlation. Sonatrach could notinject fluid after setting the packer based onsurface measurements of coiled tubing length,which only have an accuracy of about10 ft/10,000 ft [3 m/3,048 m]. Packer damageafter retrieval indicated that the packer hadbeen set across a perforated interval.

Sonatrach considered two methods forcorrelating downhole depths and positioning thepacker. One method was coiled tubing with aninternal wireline cable to transmit data fromdownhole logging tools, and the other was amemory log. Coiled tubing with wireline providesreal-time depth correlations, but addsoperational complexity, risk and cost. Inaddition, acid stimulations cannot be performedunless armored cable with a special plasticcoating is installed.

Memory logging requires an extra trip toretrieve data from the downhole memory anddoes not provide real-time depth correlations. Italso relies on computer modeling to estimatecoiled tubing length because running in and outof the wellbore plastically deforms and stretchesthe coiled tubing. To achieve an increased level ofaccuracy on the second attempt, Sonatrach usedthe DepthLOG CT depth correlation log (above).

This wireless casing collar locator (CCL)system with pump-through capability providesaccurate, real-time depth measurements, allowspumping of corrosive fluids and is compatible withthe CoilFLATE high-pressure, high-temperature(HPHT) packer as an add-on assembly.

4. Boumali A, Wilson S, Amine DM and Kinslow J:“Creative Combination of New Coiled TubingTechnologies for Stimulation Treatments,” paperSPE 92081, presented at the SPE/ICoTA Coiled TubingConference and Exhibition, The Woodlands, Texas,April 12–13, 2005.

> Depth control. The wireless DepthLOG CT tool uses a traditional casing collarlocator to detect magnetic variations at jointed casing collars (left). Hydraulicttpressure-pulse telemetry transmits data to the surface through fluid inside thecoiled tubing, eliminating the need for an internal wireline cable. Flow-throughcapability provides an unobstructed coiled tubing string for pumping cementand stimulation treatments. A signal booster can be added for depth correlationwhen transitioning from smaller production tubing into casing sizes larger tthan 7 in. (right).tt

SignalerSignalerSi l

ProcessorProcessor

Battery power forBattery power forB fsignal processorsignal processori l

Casing collarCasing collarC i lllocatorlocatorl

The tool sends telemetry pulses to the surfacethrough fluid in the coiled tubing and outputs aninstantaneous and continuous CCL log withoutthe need for a wireline cable inside the coiledtubing. A real-time depth correlation log allowedSonatrach to accurately position the packerbetween the two perforated intervals.

Combining these two innovative technologiesin a modular toolstring met all operationalobjectives of this demanding application. Duringa single run into the well with coiled tubing,Sonatrach could acquire a CCL log for accuratedepth correlation and optimal packer placementin the 3-m casing section, set and inflate theCoilFLATE HPHT packer, pump the HF acidtreatment, deflate the packer and initiate wellflow by injecting nitrogen.

The DepthLOG CT system required aminimum fluid rate of 0.5 bbl/min [0.08 m3/min]3

to produce a positive pressure signal at thesurface. An additional 0.5 bbl/min was needed tokeep the coiled tubing continuously full of fluid.Surface testing verified that the pressure pulsesand flow rates required to generate wireless CCLsignals would not cause premature inflation ofthe CoilFLATE packer.

At the well location, an initial coiled tubingrun used the high-pressure Jet Blaster tool topump nitrified fluids and clean the productiontubulars. This operation confirmed clear passageto the packer setting depth, cleaned theperforations to ensure optimal acid penetrationand removed any possible debris and scalebuildup from the casing walls where the packerwas to be set.

Schlumberger performed two DepthLOGcorrelation logs to accurately position theCoilFLATE packer within the 3-m casing section.Sonatrach confirmed packer inflation andanchoring by setting coiled tubing weight downon the packer and performed an injection test toconfirm a positive seal before pumping 120 bbl[19.1 m3] of HF acid foamed with N2. Thestimulation treatment was pumped in two stages,each consisting of a hydrochloric [HCl] acidpreflush, HF acid stage and HCl overflush stage, with a chemical diversion system betweeneach stage.

The inflatable packer was designed towithstand high differential and injectionpressures, so it was possible to pump thistreatment at 3,500 psi [24 MPa] and still

maintain a margin of safety to avoid packerfailure. Formation injectivity increased from0.2 to 1 bbl/min [0.03 to 0.16 m3/min] while3

maintaining a constant wellhead pressure,indicating no packer leakage and confirming thatthe acid was dissolving formation damage,opening the perforations and reducing skin.

After Sonatrach completed this treatment,overpull was applied to the coiled tubing at thesurface to deflate the CoilFLATE packer.Nitrogen was then circulated through the coiledtubing to reinitiate well flow as quickly aspossible. This helped recover the spent acid,which can cause severe damage if it remains inthe formation for an extended period of time.

After the CoilFLATE packer was retrieved, avisual inspection of the outer element revealedno indentations or damage to the metal slats orrubber seal from perforations or casing collars,which verified that the packer had been set incasing between the perforated zones.

The proposed workover required only a singletrip into the well, and the production tubing did nothave to be retrieved. Depth correlation, acidizingand initiating production were performed on thesame run as setting the packer, saving two runs.After the stimulation treatment, oil productionmore than tripled from 38 m3/d [239 bbl/d] to3

120 m3/d [755 bbl/d] 3 (left).For more than one year after the treatment,

production remained at the same improved level.The use of the inflatable-anchoring packer andwireless CCL tool curtailed the conventional rigoperation that pulled the production tubing priorto any selective stimulation treatment. Thisworkover operation was the beginning of aplanned campaign for treating additional wells inthe same field that had similar completions andrequired stimulation.

Field experience using a 2 ⁄1⁄⁄ -in. OD CoilFLATEinflatable-anchoring packer proved that zones inwells with multiple completion intervals can bereliably isolated and stimulated using coiledtubing. Fast turnaround times and accurate fluidplacement allow production enhancement inwells that previously could not be treatedsatisfactorily or economically with otherintervention techniques and methods.

38 Oilfield Review

5. Kumar PS, Van Gisbergen S, Harris J, Al Kaabi K,Ferdiansyah E, Brady M, Al Harthy S and Pandey A:“Eliminating Multiple Interventions Using a Single Rig-UpCoiled-Tubing Solution,” paper SPE 94125, presented atthe SPE/ICoTA Coiled Tubing Conference and Exhibition,The Woodlands, Texas, April 12–13, 2005.

6. Kumar PS, Van Gisbergen S, Harris JM, Al-Naabi AM,Murshidi A, Brady ME, Ferdiansyah E, El-Banbi A andAl Harthy S: “Stimulation Challenges and Solutions inComplex Carbonate Reservoirs,” paper SPE 93413,presented at the SPE Middle East Oil & Gas Show andConference, Bahrain, March 12–15, 2005.

> Coiled tubing stimulation results in the Hassi-Messaoud field, Algeria. Production from Well MD264 increased more than threefold from 38 m3/d [239 bbl/d] to 120 m3 3/d [755 bbl/d] after pumping ahydrofluoric [HF] organic acid stimulation treatment through coiled tubing using an inflatable-anchoring packer to isolate the lower target interval from an upper interval, which had previouslybeen hydraulically fractured.

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Winter 2005/2006 39

Selective zonal isolation and treatment ofindividual intervals under extreme wellconditions provide new options and alternativesfor well construction and reservoir evaluation,including rig-based or rigless operations, such aswell testing of individual zones, pressure andtemperature monitoring, and pressure-declinetesting. Combining tools and multiple concentricoperations also has helped improve the overallefficiency of remedial workovers and wellrecompletions across an entire field in theMiddle East.

Single Rig-Up, Multiple OperationsPetroleum Development Oman (PDO) andSchlumberger collaborated on a novel method-ology to facilitate well recompletions in a maturenorthern Oman field. This new techniquecombined a series of operations into a single intervention, eliminating multiple trips

to a wellsite and the need to mobilize bothcoiled tubing units and conventional workoverrigs (above).5

Most of the wells in this field produce fromthe Shuaiba carbonate formation, and arecompleted with cemented and perforated4 ⁄1⁄⁄ -in. OD horizontal liners. Water productioncurrently exceeds 90% of the total field output, sothese wells are produced by artificial lift—gaslift or electrical submersible pump. Highdrawdown pressures cause scale deposition,which necessitates wellbore cleanouts prior toperforming workover operations.

Well interventions also include acquisition ofa pulsed-neutron log to measure fluid saturationsand prioritize potential completion intervalsaccording to oil content and potentialproductivity. These evaluations are followed byperforation and stimulation of selected intervals.

Initially, PDO performed these interventionsusing two coiled tubing units, one with and one

without an internal wireline. The operator alsoperformed jobs with two coiled tubing units and aworkover rig. Both methods, however, were costly.

Operations without a workover rig required atleast four separate coiled tubing runs. During thefirst run, PDO used conventional coiled tubing toclean out the wellbore liners. On the second run,the company used coiled tubing with an internalwireline to acquire a pulsed-neutron log.

On subsequent runs PDO perforated newintervals using conventional coiled tubing with ahydraulic firing head and stimulated each newcompletion interval during a series of wellboreentries that involved running and retrievingperforating guns under pressure.

From wellbore cleanout and pulsed-neutronlogging through perforating and stimulation,these operations required about 10 days onlocation and at least three months to complete,even when the intervention proceeded withoutsignificant problems.

Compared with these multiple coiled tubinginterventions, operations involving twointerventions with coiled tubing and oneintervention with a workover rig required moretime on location, about 12 days, but less totaltime, about two months. However, costs werehigher. During the first operation, PDO usedconventional coiled tubing to clean out thewellbore. The second operation involved runninga pulsed-neutron log using coiled tubing with aninternal wireline.

Perforating and stimulation were performedduring operations with a workover rig. Cleanoutand logging operations were not performed withthe workover rig because pulsed-neutron logsneeded to be acquired under live-well, orflowing, conditions.

This approach avoided flushing of the near-wellbore region by wellbore fluids under static oroverbalanced pressure conditions, which cancreate false saturation readings in perforatedhigh-permeability and naturally fractured zones.PDO also observed that stimulation results with apolymer-base diverting system were not optimalin this naturally fractured formation, even whencombined with mechanical diversion systems,such as an isolation straddle packer.

PDO evaluated alternative methods ofacquiring pulsed-neutron logs and quickly usingthis information to identify productionoptimization and recompletion opportunities.Various methods were considered to maximizewell productivity and reduce costs, including anondamaging, surfactant-base, self-divertingacid system.6

>Well interventions in northern Oman. PDO has performed workovers usingone coiled tubing unit with an internal wireline for logging and perforatingoperations (top), and one unit without an internal wireline for cleanouts andstimulation treatments (lower right). These operations have also beenttperformed with two coiled tubing units and a workover rig, or pulling unit(lower left). Both methods, however, were expensive and required multiplettoperations and trips to a wellsite.

PDO and Schlumberger proposed aninnovative solution for these gas lift wells: a singlerig-up intervention with coiled tubing. During onecontinuous operation, a single coiled tubing unitwould be used for wellbore cleanouts, logging, perforating and stimulation treatments.Schlumberger developed a specialized string ofcoiled tubing and modular bottomhole assembliesfor performing these operations and productionlog spinner surveys to evaluate if water shutoff isrequired (below right).

This coiled tubing string includes a modifiedwireline cable with an armored outer sheath, orjacket, to provide stability under unstable loadconditions and sudden compressive forces insidethe coiled tubing. A special plastic coatingprotects the wireline from corrosive treatmentfluids that could degrade the mechanical orelectrical performance of the cable.

The system is compatible with the Securedetonator, which requires more than 200 volts toactivate and initiate the firing of perforatingcharges, is safe against stray or static voltage,and does not require radio silence on locations.Underbalanced perforating also can beperformed during these interventions byactivating the gas lift system or by displacing thewellbore with lighter fluids.

PDO first applied this system in Well A toperforate and stimulate in a single operationwith the same coiled tubing unit. This wellproduced 430 m3/d [2,705 bbl/d] of total fluid,3

29 m3/d [182 bbl/d] of oil and about 93% water3

before this remedial intervention, which wasexpected to increase oil production by 30 m3/d3

[189 bbl/d].The operator perforated new intervals in

three runs. After perforating, well productionincreased to 500 m3/d [3,145 bbl/d] with 57 m3 3/d3

[359 bbl/d] of oil and about 89% water. Afterstimulation of two upper perforated intervalswith a surfactant-base, self-diverting acidsystem, the well produced 572 m3/d [3,598 bbl/d]3

of total fluid with 63 m3/d [396 bbl/d] oil, an3

increase in oil production of 34 m3/d [214 bbl/d].3

During the second application, PDOperformed a single rig-up coiled tubing workoveron Well B to shut off the existing perforations andperforate new intervals that had more than 65%oil saturation. PDO made a trial, or dummy, runto tag TD followed by a wellbore cleanoutoperation and a pulsed-neutron logging run.

Based on the pulsed-neutron log evaluation,engineers decided to isolate the existingperforations with a bridge plug and perforate41 m [135 ft] near the end of the horizontalsection. During the same operation, PDO

stimulated these perforations with thesurfactant-base, self-diverting acid system.Engineers expected an additional 24 m3/d[151 bbl/d] of oil output. The well produced523 m3/d [3,290 bbl/d] of total fluid with 25 m3 3/d3

[157 bbl/d] of oil.PDO evaluated objectives, procedures, risks

and results on these first two wells to optimizeoperational efficiency, and to further reduce thetime requirements and costs of these operations.As a result, PDO eliminated the dummy run onsubsequent jobs. This integrated well-intervention method required about six days onlocation over a 15-day period, or less than half a

month. Compared with 10 to 12 total days overtwo to three months for previous multiple-entry methods, this saved PDO US$ 60,000 toUS $100,000 per well (next page, top).

PDO applied this new remedial technique toacquire fluid saturations and quickly identifyrecompletion opportunities on 10 wells, resultingin less deferred production and early returns onworkover investments. Using this approach toperform various combinations of remedialoperations, PDO exceeded production targets forthis field and saved more than US$ 1 million in2004. PDO is currently evaluating the applicationof this technique in other areas.

40 Oilfield Review

> Single rig-up well interventions with coiled tubing. PDO and Schlumbergerdeveloped a specialized string of coiled tubing and modular tool assembliesspecifically to perform wellbore cleanouts, well logging, perforating andstimulation operations. The customized logging and perforating head requiressimultaneous pumping of fluid at a predetermined rate and overpull todisconnect the head. This dual-release mechanism avoids an unintentionaldisconnect from the head.

Stimulation

Coiled tubing

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Wellborecleanout Logging

Loggingtools

Winter 2005/2006 41

Continuous Tubing, Continuous ImprovementThe reliability of coiled tubing equipment andoperational practices continues to improve.From the most basic applications to the mostcomplicated, advances in coiled tubing tools,techniques and concentric operations ensuresafer and more efficient day-to-day operations.As a result, coiled tubing technology has becomefirmly established in many areas of oil and gasactivity that cannot be adequately addressedusing conventional well-intervention operations,techniques and services.

The modular nature of coiled tubing systems,rigless operations, quicker well-turnaroundtimes and accurate selective placement of fluidsor stimulation treatments are helping producingcompanies optimize well performance.Increasingly, operators are reevaluating fieldsand individual wellbores for remedialintervention or recompletion operations usingcoiled tubing, including many wells thatpreviously were considered too risky even forconventional operations (below left).

However, not all concentric well interven-tions require new technology or mandate thatexisting coiled tubing equipment and techniquesbe pushed beyond their current limits. Operatorsand providers of coiled tubing services also arecollaborating to develop innovative tool combina-tions and integrated systems, operational bestpractices and new approaches that can improvewell productivity and increase reserve recoveryin new and mature fields alike. By building onthese cooperative efforts, Schlumberger isimproving and expanding concentric servicesthrough ongoing development and optimizationof coiled tubing equipment, proceduresand techniques.

Improvements in materials and manufac-turing, advances in design software, and real-time monitoring and control have significantlyreduced the frequency of coiled tubing failuresand increased the success of through-tubingoperations. There are still some operatingcompanies that have not forgotten about thelimitations and problems that were associatedwith early coiled tubing strings and equipment.However, through knowledge sharing and bettercommunication, more oilfield companies arecomfortable performing concentric wellinterventions using coiled tubing. —MET

> Improving the profitability of concentric operations. Multiple-entry remedial operations withouta workover rig required that PDO perform at least four separate coiled tubing runs, requiring about10 days on location over three months (red). Well interventions involving two coiled tubing operationsand one operation with a workover rig required less total time, about two months, but 12 totaldays on location with costs that were higher (blue). The integrated single rig-up method using aspecialized string of coiled tubing and one coiled tubing unit required only about six days on locationover a 15-day period (black).

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> Expanding the application of coiled tubing reentry drilling. Producing companies are becoming more confident in conducting remedial interventions or recompletions through existing productionttubulars. During December 2004, BP Sharjah Oil Company reentered a well in the Sajaa field for asecond time and drilled four additional laterals using underbalanced techniques and coiled tubing. BP initially had reentered this well with coiled tubing drilling three laterals in August 2003.