advances in coiled tubing technology e&p supplement 2006

A custom publication to

1616 S.Voss, Ste. 1000Houston,Texas 77057Tel: (713) 993-9320Fax: (713) 840-0923

Editor in ChiefBILL PIKE

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Group PublisherRUSSELL LAAS

Hart Energy Publishing, LP

Sr. Vice President andChief Financial Officer

KEVIN F. HIGGINS

Executive Vice PresidentFREDERICK L. POTTER

President andChief Executive Officer

RICHARD A. EICHLER

Longer, Stronger Stringsand Deployment Tools

In addition to new tools, a better understandingand greater acceptance of the potential of coiledtubing have accelerated its recent growth.

Cutting Costs, Providing Access to New Reserves

There are two key elements of value in any drillingtechnique – cost-effective drilling performance andthe ability to accurately place the wellbore to max-imize production.

Versatility and Box of Tools makeCT Ideal for Thru-tubing Work

Well maintenance and repair using a work stringand tools that can be deployed through productiontubing has long been the most common applica-tion of coiled tubing technology. With new fit-for-purpose tools as well as sophisticated softwareand telemetry, coiled tubing can perform anincreasing variety of re-entry operations moreeffectively.

Solutions take Shape for Subsea Intervention

If there is one market segment that poses thebiggest challenge to coiled tubing technology, it issubsea intervention. Currently, it is a commercialchallenge, too, although that eventually will change.

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Cover photo courtesy of Rental & Fishing Tools Inc.

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About the cover:The Tubing Intervention Manipulator is a newinvention that enables coiled tubing (CT) rota-tion in both directions. It overcomes CT’s biggestlimitation and promises a dramatic increase incapabilities and applications. This workingmodel, with three-quarters-in. CT on the spool,is currently rigged up on a well in Louisiana.Testing and development are under way, withparticipation by the inventor, John Van Way ofRental & Fishing Tools Inc., Lafayette, La., andthe Mechanical Engineering Department atTexas A&M University.

www.eandpnet.com • November 2006

Longer, Stronger Strings and Deployment ToolsIn addition to new tools, a better understanding and greater acceptance of the potential of coiled tubing have accelerated its recent growth.

As technology expandedcapability during thepast half dozen years,

the number and types of coiledtubing (CT) operations havegrown rapidly. Nearly 1,200 CTunits were active around theworld last year, up about 12%from 2004 and up from 850units in 2001, according to theIntervention & Coiled TubingAssociation (ICoTA). Canadaand the United States each hasabout 250 units, togetheraccounting for half the world-wide total, according to theassociation. In March, 292 CTunits were active in the UnitedStates, an increase of 33 from ayear earlier. By way of compari-son, in late February, activerotary rigs in North Americatotaled about 2,250, accordingto Baker Hughes.

Coiled tubing service revenue jumped 27% last year to$1.684 billion, according to Oilfield Market Report 2005, preparedby Spears & Associates Inc.The report forecast an 18% increasein revenues this year.

Much of the CT potential stems from a unique characteristicof the technology – it can have an important role in a variety ofoperations throughout the life of a well or field.

“You can use coiled tubing to drill, to deploy productiontubulars, to service the well, even to [plug and abandon] the wellat the end of its life,” said Dennis Dunlap, president, CT businessunit for Precision Tube Technology. “Today, wherever in theworld there are oil or gas operations, coiled tubing is there tosupport it.”

CLOSING A GAPA continuous tubular manufactured in various lengths andspooled onto a reel, CT was first used mainly as an inexpensive

well cleanout technique that did not require the well to be shutin. Now, it performs a lengthening list of workover and stimula-tion operations. Drilling with CT promises to be one of itsfastest-growing applications.

No longer a niche technology, CT is steadily closing the gapbetween its capability and that of traditional jointed pipe.Amongthe operational benefits of CT are a relatively fast speed into andout of the hole, as well as the ability to perform live well opera-tions. It can eliminate the need for a more costly workover rig.

The ability of CT to be pushed through highly deviated holesand long horizontal sections is being extended by higher-strength coils and new deployment techniques.Temperature lim-its on tools are also being raised, and government and industryare involved in a sizable list of research and development effortsto further expand CT capability.

Cost pressures, improved tools and equipment as well asindustry’s efforts to shrink the surface footprint of operations are

EXPANDING COILED TUBING PROMISE

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A coiled tubing operation is under way. (Photo courtesy of Schlumberger)

Advances In Coiled Tubing Technology • www.eandpnet.com

fueling the growth of CT activity.As well interven-tion requirements continue to increase, CT canoffer advantages for a range of well types, from shal-low low-productivity wells in mature fields to sub-sea completions in deep water.

Well service/workover applications still accountfor more than 75% of CT operations, according toICoTA, but technical advancements have increaseddrilling and completion capability. Strong growth isexpected in the use of CT for drilling, fracturing,subsea intervention, deeper wells and pipeline/flow-line installation.

Traditional applications will also continue to grow,including well unloading, cleanout, acidizing/stimula-tion, permanent velocity strings, fishing, tool con-veyance, well logging, and setting and retrieving plugs.ICoTA cites these benefits of CT:

• safe and efficient live well intervention;• rapid mobilization and rig-up;• ability to circulate while running in or pulling

out of the hole;• reduced trip time, resulting in less production

downtime;• reduced personnel requirements; and• potential for significantly reduced cost.A CT unit includes the reel for storage and transport of the CT;

an injector head that provides the force to run and retrieve the CT;a control cabin; and a power unit to generate hydraulic and pneu-matic power.Well control equipment is a critical element, since mostCT operations are performed under wellhead pressure.

Coiled tubing technology is a key part of a range of compati-ble and related wellbore intervention technologies that are growingsteadily, including electric wireline tractors and slickline systems,said Gordon Mackenzie, product line manager for thru-tubingintervention with Baker Oil Tools and ICoTA co-chairman.

Coiled tubing intervention is likely to use more than just CT.In CT drilling, for example, electric wireline installed inside thetubing is a compatible technology. Formerly the InternationalCoiled Tubing Association, ICoTA’s new name “reflects a natu-ral diversification to involve these related intervention technolo-gies,” Mackenzie said.

LONGER AND HEAVIER“Coiled tubing is being used in deeper wells and more difficult con-ditions, as the applications continue to expand,” Dunlap said.

That has driven an increase in the size and weight of a typicalstring. Today’s average CT string is an estimated 5,000ft (1,525m)longer than the average a decade ago, and average weight hasincreased by 30,000 lb.

Tube size has been getting larger, too. Precision TubeTechnology, a wholly owned subsidiary of Maverick TubeCorp., manufactures 2-in., 2 3/8-in. and 2 7/8-in. CT for well

workover applications. Larger sizes are available for otherapplications.Today’s injector heads can apply a greater force topush or pull the string, and well control equipment can han-dle the 10,000-psi to 15,000-psi environments now becomingmore frequent.

During the past 5 years, manufacturers have also introducedhigher-strength materials to meet the demands of deep well andhigh-pressure applications.Two decades ago, CT was used onlyon relatively simple wells where pressures above 5,000psi wererare. Now, 10,000psi is encountered routinely, and some jobs arebeing performed in a 15,000-psi environment.

“Longer, bigger and stronger is the trend,” Dunlap said.Early this year, there was a different materials challenge

brought on by CT’s recent growth. Demand for CT was con-siderably ahead of supply, creating a backlog that was nearing6 months.

“Getting pipe is difficult, so planning is critical,” said PerryCourville, manager for CT and hydraulic workover withHalliburton Energy Services. “Projects that require a specialstring are especially hard to get.”

With demand for CT services strong, supply constrained,and growth of unconventional and new CT applications, CTservice providers are forced to get more life out of a CT string,said Warren Zemlak, Schlumberger business development man-ager for CT services.That is driving Schlumberger’s interest innew coil metallurgy, including compositions for sour service,and a focus on advanced fatigue modeling and monitoringtechnology. Monitoring damage – as well as fatigue – is alsoincreasingly important.

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This downhole tractor system includes a turbine and wheels. (Image courtesy of Welltec Inc.)


Advances in real-time pipe management and inspection willhelp extend CT life under increasingly severe conditions,Zemlak said.

NEW MATERIALS MEET NEW DEMANDS“Today’s coiled tubing is far superior to anything we have runas recently as 5 years ago,” said Dan Bohannon, vice presidentfor CT and nitrogen services with Cudd Energy Services.“Manufacturers have done a much better job with manufactur-ing and quality control.”

Coiled tubing is made in diameters ranging from three-quartersin. to 5 in., typically from steels with yield strengths from 55,000psito 120,000psi. Since the tubing is repeatedly plastically deformed innormal use, fatigue is an important design consideration.The tube isstraightened as it comes off the reel, bent again as it moves into theguide arch, then straightened again as it is injected into the wellbore.The deformations are repeated as the string comes out of the hole.

Most CT strings are carbon steel. Recently, higher strengthsteels have been used for coils to be used in deeper wells.Yieldstrengths of 110,000psi and 120,000psi are increasingly importantin applications that require greater depth and pressure capability,Courville said. Because some of these products are new, they are“non-standard” and still pose some operational issues.

FIGHTING CORROSIONSteels for severe corrosive environments have also been developed.Introduced in 2003, QT-16Cr was developed for direct exposureto wet carbon dioxide (CO2) environments.Within a year, morethan 30 strings were in service for depths greater than 18,000ft(5,490m), according to ICoTA, Early applications were as per-manent velocity string installations.

In addition to corrosion resistance, the alloy has greater abra-sion resistance and better fatigue life than carbon steel.

Hydrogen sulfide (H2S) service capability is an area ofincreasing focus on the part of operators and service companies.The basic metallurgy of steel CT is relatively well known and itsfatigue life, as higher H2S conditions are encountered, fairly wellunderstood. Because CT is repeatedly plastically deformed, thereis a need to further quantify the effect of H2S on coiled tubing.

For applications involving H2S, there is still some uncer-tainty about the acceptable upper limit on yield strength. An80,000-psi yield is considered the nominal limit, butHalliburton has successfully run a 90,000-psi yield-strengthsteel with an inhibitor, Courville said.

“That combination extends the depth and pressure capabilityin an H2S environment,” he said. “It mitigates the losses thatwould otherwise occur.”

A chrome material can provide a longer life for the coilbecause it does not rust like carbon steel. However, it is more sen-sitive to acid,Courville said, and in a service application, care mustbe taken when pumping chemicals through a chrome alloy string.

Both 16-chrome and 19-chrome materials introduced for wellswith wet CO2 production are suited for permanent velocity stringsin gas wells, for example, a significant application in North America.

In Canada, 16-chrome is being used for CT fracturingbecause a smoother inner diameter allows higher flow rates at thesame pressure. It also appears that 16-chrome has greater resist-ance to abrasion when fracturing slurries are pumped.

However, 16-chrome has not been adopted as a standard CTintervention string for several reasons, including maintenance andrepair difficulties as well as incompatibility with certain fluids.

A number of different CT metallurgies have been proposed andexamined, including titanium and beryllium copper. It has alwaysbeen an economic balance, said Alex Crabtree, product line technol-ogy manager for CT with BJ Services Co.

Exotic metallurgy can extend the life of CT, but while titanium,for example,might multiply fatigue life by six to eight, it will cost six

to eight times more than steel. Inspection and repair alsobecome more difficult with exotic alloys.

Cost becomes a bigger factor as the base cost of materialrises and strings are larger and longer.

“If it costs six times more to make the string out of anexotic alloy, that becomes a massive capital outlay,” Crabtreesaid.“On balance, for both technical and commercial reasons,steel is pretty tough to beat.”

The reliability of CT pipe has improved during thepast 20 years. Now, corrosion and sour attack are more importantin CT management. Internal corrosion by brines, especially sea-water, is the cause of a large share of corrosion incidents.

“BJ has not seen a ‘pure’ fatigue failure – a failure caused onlyby cycling the pipe – in almost 9 years,” he said.

The No. 1 issue in CT operations is corrosion, Crabtree said.

COMPOSITES? MAYBE…SOMETIMETubing made of fibers embedded in a resin matrix – a composite –has been the focus of research and experiment.Changing the mix offibers, orientation of windings and the resin properties can changethe performance characteristics of the composite material.

First used for velocity strings in the late 1990s, operators andservice companies have been interested in composite CT for adecade, but CT made from composite materials has not yetproved commercially viable and most of the work has been dis-continued. Composite tube is still being made, but primarily forspecialty pipeline applications, not downhole use.

The lighter weight of a composite string would be an advantage,especially in deep wells, but higher temperatures pose a challenge.


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“YOU CAN USE COILED TUBING TO DRILL,TO DEPLOYPRODUCTION TUBULARS, TO SERVICE THE WELL,EVEN TO [PLUG AND ABANDON] THE WELL AT THEEND OF ITS LIFE.”

Dennis Dunlap, President, Coiled Tubing Business Unit, Precision Tube Technology


Dunlap added that most CT strings are retired because of dam-age in the field, not because they have reached the end of theirfatigue life. It is more difficult to repair damage to a compositetube than to a steel tube.

Composite tubing also has a higher initial cost.The result isthat the primary selling point of composite tube – a longerfatigue life – is not as significant an advantage, Dunlap said.

Cudd has run composite CT, but Bohannon expects the mar-ket to take some time to develop, if it does.

DEPLOYMENT, OTHER OPERATING CHALLENGESAs well completions become more complex and horizontal intervalsget ever longer, deploying anything into these holes, including CT,requires increasing capability, downhole and at the surface.

In its pursuit of “surface efficiency,” Schlumberger recentlytook a fresh look at CT systems using its in-house database of60,000 jobs.The goal was to pinpoint recurring equipment prob-lems and safety issues as well as analyze non-productive time.

“We used that information to help design, develop and setspecifications for the next generation of coiled tubing equip-ment,” Zemlak said. “We’re now launching the first seven off-shore base units for field testing.”

A key goal – cutting non-productive time attributed to equip-ment design by 75% – will be met, he said. Crew size requirementsare also being addressed by incorporating ways to work smarter, asfinding enough experienced people continues to be a challenge.

With offshore operations in mind, all elements of the designare aimed at reducing lift weight and space requirement. Thenumber of moving components, pumps and systems is mini-mized and electric systems have replaced hydraulic componentsin the control system and the control cab.Well control has alsobeen reconfigured and a new reel design incorporated.

“An advanced condition monitoring capability will allow theCT specialist to focus on the intervention operation, not solelyon running the equipment,” Zemlak said.

HELPING PUSH AND PULL“Tractor technology helps extend the limits of what coiled tub-ing can do,” said Brian Schwanitz, vice president and generalmanager of Welltec Inc.Welltec is a Danish company founded bythe inventor of the Well Tractor, Jorgen Hallundback, who beganoperations in the North Sea in 1996.

“It’s an enabler that will make it possible to do things in extendedreach wells that are not possible without the technology,” he said.

Typical applications of the tractor in CT operations havebeen in treatments, cleanouts, extended reach drilling and help-ing to convey long strings of perforating guns. Tractors areincreasingly being used for long horizontal intervals where pipepreviously was relied on to convey services.As the lateral extentand the number of extended reach wells continue to grow, trac-tors will see more use, Schwanitz said.

A 3 1/8-in. CT tractor powered by a turbine has been avail-able since 2000. Drive fluid is pumped through the CT, turningthe turbine, which generates power to run the self-containedhydraulic system that drives the tractor’s arms and wheels.

Though use of Welltec’s tractors for CT operations is growing,it still represents only a small share of the company’s total tractorjobs; the rest are for electric wireline applications.With 16 bases in23 countries,Welltec averaged about two CT tractor jobs per monthearly this year. Its wireline tractors have been in service for 10 years.

“We need to get the word out that coiled tubing tractors area good option for the growing number of extended reach appli-cations,” Schwanitz said.

For drilling, the Welltec tractor goes in the hole completelyflush.When the pump rate reaches a preset level, say 2 bbl/min,the tractor is activated and deploys its arms and wheels. If thepump rate drops back below that level, the tool will deactivateand close up flush again.The closed hydraulic system powers anindividual hydraulic motor on each wheel.

The hydraulic system is a constant-capacity system. Varyingthe number of operating wheels can change its operation. Formaximum force, for example, all the tractor wheels – up to 20 inone tractor – can be operating; for maximum speed, only eightwheels might be operated.

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The DeepWave tool on coiled tubing forces trapped liquids out, or treat-ment fluids in. (Graphic courtesy of Halliburton)

Paid Sponsorship


BJ Advances Coiled TubingMethods and TechnologiesBJ Services coiled tubing (CT) experts develop new CT equipment and techniques to solve specificproblems for oil and gas operators. Along the way, they often create new technologies that gobeyond mere enhancements to conventional tools.

BJ’s CT tradition stresses continuousimprovement. The company cre-ates new tools and systems to

improve traditional CT applications,enhance safety in all CT uses and makeCT an enabling technology for addressingwell problems that once went unsolved orenable applications in wells that wouldotherwise be impracticable.

NEW LIFE FOR CT CLASSICSBJ provides state-of-the-art tools for allthe classic CT application areas:

• well cleanouts;• spotting/squeezing fluids;• stimulation;

• nitrogen jetting or fluid lifting; and• perforating.

The backbone of CT applications is wellcleaning: removing sand, scale depositsand other debris from producing oil andgas wells. Early technology often accom-plished the job, but BJ professionals haveimproved treatment efficiency by design-ing and building advanced tools such asdownhole phase separators and specializedjetting nozzles.

Within BJ, well cleanouts have evolvedinto very specialized systems and techniquesthat greatly improve efficiency for specificwell cleaning tasks. Compared with CTtools that merely spray fluids, for example,

BJ rotary jetting technologies use less fluidand cover the wellbore more efficiently:• The Roto-Jet® tool and nozzles pro-

vide the most effective high-energypressure jetting for tough wellboreproblems like barium sulfate scale.

• The patented Roto-PulseSM methodoffers controlled-energy fluid place-ment for cleaning plugged gravel packswithout appreciably altering pre-packedmedia.

• The BJ Vortex nozzle simply and eco-nomically places treatment fluids viaCT. In the Niger delta, BJ has used thisnozzle to clean and acidize wells in asingle trip.

BJ SERVICES

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BJ crews routinely provide coiled tubing drilling services throughout western Canada.


• BJ’s patented TornadoSM cleanoutprocess efficiently sweeps virtually allobstructing solids from the wellbore,evenfrom extended-reach horizontal wells.In a recent Arabian Gulf application, the

BJ Tornado process removed 15 bbl of fillfrom about 400ft (120m) of perforations inone pass. The Tornado tool’s forward- andreverse-jetting nozzles reduced cleaningcosts and job time by nearly 70% comparedwith a conventional CT cleanout.

TAKING CT PERFORMANCE TO NEW LEVELSNew field problems challenge BJ to per-form under economic and operationalconditions other technologies have beenunable to solve.

The BJ DuraLinkTM CT connectorprovides an effective mechanical means forquickly coupling two CT strings offshore.Where platform crane lift capacities limitthe size of CT reels, the DuraLink con-nector offers an economical and reliablesolution for entering deep or extended-reach offshore wells.

For multi-zone reservoirs, BJ’sOptiFracSM service saves operators timeand money on fracture stimulation, withand without proppant or nitrogen gas assist.

In a complex variation on CT fractur-ing, an operator in Norway asked BJ toprovide CT acid fracturing for a newoffshore well. Ineffective fluid diversionduring bullheading treatments bypassedimportant perforated zones. BJ-developedCT tools selectively and accurately stimu-lated 15 zones in one trip using between50% and 80% less acid.The well producedenough oil for operational payback afterjust 11 days. Production stabilized about11,200 b/d of oil, more than twice whatthe operator expected from bullheading.

Back on land, BJ developed CT toolsand technologies for the Pohokura gas fieldin New Zealand. Operational challengesculminated in accurate CT perforatingruns under pressure in three onshore wellsreaching (nearly horizontally) as far as24,400ft (7400m) offshore.

Most recently, a Latin Americanoperator gained significant productionincreases with BJ’s new StimTunnelSM

technology, which uses CT acid jettingto create multiple productive laterals incarbonate formations. The techniqueuses far less acid to provide greater reser-voir access than acid fracturing or matrixacidizing. Its initial field applicationtripled the well’s original production and

enabled natural flow – a first among thatfield’s wells. Additional wells have seensimilarly successful treatments.

EVOLUTIONARY CHANGE,REVOLUTIONARY RESULTSBJ’s proprietary CIRCATM modelingsoftware evolves with each new tool ortechnique. Roughly 20 years of incre-mental improvements make the CIRCAprogram one of the most robust tools inBJ’s kit. BJ personnel routinely useCIRCA analysis to precisely plan andexecute CT operations.

In the hands of BJ experts, CT tech-nology routinely improves productionand extends the useful life of wells undervirtually any conditions. As operatorspush the envelope, BJ makes sure its CTcapabilities keep the pace.

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BJ SERVICES

BJ Services Company11211 West FM 2920 • Tomball,TX 77375Tel: (832) 559-1303 • Fax: (832) 559-1319

www.bjservices.comBJ rotary jetting technologies use less fluid andcover the wellbore more efficiently.

This BJ self-erecting mast unit in south Texas epitomizes rig-up efficiency.


Maximum force from one tractor is about 3,500 lb, but twotractors in tandem with a total of 40 wheels has provided 7,200lb of force, Schwanitz said. A tandem arrangement can also helpnegotiate sections with extensive washout.

Each wheel has an “anti-spin” valve to prevent it from robbingpower from the other wheels by spinning freely, for example in awashed out section of the hole.

“It’s much like a car’s posi-traction system,” Schwanitz said.The tractor can negotiate restrictions without losing traction.

The individually suspended wheels will follow the internal innerdiameter (ID) and maintain the drive through the restriction. Ifcommunication with the tractor is lost, it will collapse back intothe same outer diameter (OD) as when entering the well.

Coiled tubing can also provide flow assurance in pipelinesplugged by paraffin or hydrates, sand or scale, Schwanitz said.Thetractor can provide the force needed, for example, to push a millbit through to eliminate a blockage.

OTHER OPTIONSAnother tool in use to extend reach is an “agitator.” Andergauge’sAG-itator, for example,provides axial excitement by converting pres-sure pulses within the tool.The pulses vibrate the string to break thestatic friction that inhibits movement.According to Andergauge, ini-tial testing on 2-in. coiled tubing reduced friction by 95% and pre-vented the onset of helical lock up.

An externally tapered OD string is another approach to increas-ing deployment capability.A tapered string can extend the depth towhich CT could be used.The ID remains the same throughout atapered string,preserving flow capacity,but a smaller OD on the bot-tom of the string reduces weight.

The ability of a conventional CT string to perform ultra-deepwork depends primarily on its total hanging weight and the yieldstrength of the parent metal. If the hanging weight exceeds thepipe’s yield strength, the string can separate.A tapered string pro-vides greater strength at the upper end of string, but a lighter coil.

During the past 5 years, the number of wells drilled to depthsbelow 25,000ft (7,625m) has increased dramatically, according toHalliburton. Its DeepReach service can extend the current depth ofhigh-pressure CT operations in deepwater deep wells to 32,000ft(9,760m) total vertical depth and is compatible with 15,000psi well-head pressure control equipment.

DeepReach,using multiple sections of CT with different ODs ina single string, can extend reach in deep and ultra-deep wells by 30%compared with conventional CT strings.The service is designed tohelp recover hard-to-access reserves in deep water and perform treat-ments on ultra-deep wells that were virtually impossible previously,according to Halliburton.

Development of the service was a joint project between BP andHalliburton. Quality Tubing,Texas Oil Tools and CTES also wereinvolved in the development team.


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The Emergency Stop System helps avoid failure. (Image courtesy of CTES)

Advances In Coiled Tubing Technology • www.hartenergy.com

Field trials for the system were conducted in South Texas in late2004 using a 13,000-ft (3,965-m) string with a 2-in. OD upper sec-tion and a 1 3/4-in.OD lower section. Later tests used a 2-in.OD by2 3/8-in. OD string.

Several key technologies were developed to make the designwork for deep wells, according to Halliburton: transition joints;V-shaped gripper blocks used in the injector head; modifications tothe injector head; and variable diameter well control equipment.

Aside from deepwater and deep wells, externally tapered ODstrings can be an option for weight-sensitive offshore platforms.Weight can be especially critical on older platforms where cranesmay have been de-rated.

There is another deployment option available to cope withlarger reel weights and sizes. Coils can be taken to location intwo sections and joined together on location by welding or witha mechanical connector.

Welding CT is not simple and a welded joint reduces thenumber of allowable string cycles. Welding equipment, inspec-tion equipment and skilled people must all be taken to the wellsite if welding is to be done.

To eliminate the need for welding on location, BJ Serviceshas developed a mechanical connector, Spoolable DuraLink, forjoining two coil lengths mechanically on location. At the wellsite, the two lengths are joined and the entire lengthspooled on to one working reel.After the job, it is separatedinto two lengths for the return trip.

The option is most applicable for offshore work wheredividing a 40-ton reel into two 20-ton lifts that can be liftedonto most platforms makes it possible to operate theworking reel on the platform. Spooling from the boatonto the platform is also an option, but that operation isweather-dependent.

REAL-TIME CONTROLAt its heart, CT technology application is all about cuttingcosts. To do that requires a constant knowledge of operatingconditions and the ability to adapt the operation to the latestinformation.

Electric line is a proven technology for communicatingbetween the surface and the bottom of the hole, but reliabilityand cost often restrict its use in routine applications.To expandtelemetry capability for intervention operations, Schlumbergerhas applied the knowledge gained in developing fiber optic tech-nology for its completion services.

“We put a lot of effort into modeling and design based on reser-voir and other parameters,”Zemlak said.“The goal is to use real-timeinformation to optimize the job as it is executed.And over the longterm, it is important to take some basic downhole measurements inevery operation to help optimize results.”

Schlumberger’s fiber-optic-based iCoil platform will include anumber of services, the first of which will be commercialized “in thevery near future,” Zemlak said.

OPERATING SAFELYAs CT activity grew rapidly last year and early this year, a chal-lenge for CT service companies – as it seemed to be for allindustry segments – was finding enough skilled CT unit opera-tors to operate new units being deployed in the field.

Limited experience always makes safety more important.With multiple events requiring their immediate attention in thecontrol cabin during a field operation, even highly seasonedoperators may be momentarily distracted, said Ed Smalley, seniorvice president of CTES LP.

CTES developed its Emergency Stop System (ESS) to helpavoid sudden operational failures that can result from these tem-porary distractions. A user-definable injector stop system, it isdesigned to avoid catastrophic buckling or parting of the CTstring and can be retrofitted to any CT unit.

“Experience is important in avoiding these problems, ofcourse,” Smalley said.“But the attention of even the best opera-tor can also be diverted at the worst possible moment.”

If that happens while going in the hole near a restriction orwhile nearing the bottom of the hole and tubing continues to beinserted, it can buckle at the surface below the injector. Whencoming out of the hole, if the tubing becomes stuck, it can partif too much pull is exerted.

The ESS continuously monitors four parameters to provideproper injector control. Minimum weight can be used to stopthe injector when going in the hole and the bottom end of thecoil encounters an obstruction. Maximum weight settings can beused to activate the system when coming out of the hole and thestring becomes stuck downhole.

The operator can continuously adjust the maximum andminimum weight settings as more tubing weight is run into orout of the hole. However, if the operator fails to update thesettings during the operation, failure could still occur unlessanother parameter is monitored.

To mitigate this risk, the ESS also monitors the rate of weightchange.

“Even if the operator fails to update the weight settings duringthe job, the system is ‘idling’ in the background to provide protec-tion. If it sees a significant change in the rate of weight change, thesystem will activate, the injector will stop, and the brake will beset,” Smalley said.“Then the operator can review the situation anddecide how to proceed.”

Along with the rate of weight change, the system monitors CT

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“COILED TUBING TECHNOLOGY IS A KEY PART OF ABROAD RANGE OF COMPATIBLE AND RELATED WELL-BORE INTERVENTION TECHNOLOGIES THAT AREGROWING STEADILY…”

Gordon Mackenzie, Product Line Manager,Thru-tubing Intervention, Baker Oil Tools;Intervention & Coiled Tubing Association Co-chairman


speed to help avoid unnecessary shutdowns. If the speed is very slow,for example, it might indicate the coil is being picked up off the bot-tom or the operator is carefully watching weight. So the systemwould not inadvertently shutdown the injector under the slow speedcondition just because weight has increased.

“Because of the rapid expansion of coiled tubing work, and foreconomic reasons, we are getting a lot of interest in this system,”Smalley said.“It makes sense to add this feature to a standard coiledtubing data acquisition package.”

Cudd uses a CT monitoring system and a conservative 80% ofthe pipe’s fatigue rating as a baseline.The result has been a significantreduction in the number of failures.The fatigue monitoring systemprovides better data on the presence and location of worn spots.Because it indicates when the string is close to the limit, it serves as awarning that a coil might not be suited for an application thatinvolves high pressure or other severe service.

“We use the more conservative baseline because the applicationswe are asked to look at typically involve higher pressure or othermore difficult conditions,” Bohannon said.

HIGH TEMPERATURE/HIGH PRESSURE (HP/HT)“We’re seeing more and more HP/HT work,” Bohannon said.“It’snot unusual for us to work in 12,000psi surface pressure, and pres-sures above 7,500psi are common.”

At high pressures, it can be difficult to pump enough fluid tomaintain annular velocity in larger casing sizes.

“Today, we are entering wells that have a surface wellhead pres-sure of 8,000psi to 9,000psi, so internal pressure in the coiled tubingis in the same range,” Crabtree said.“That would have been unheardof a decade ago.”

The number of wells BJ Services is working in at pressuresapproaching 10,000psi or higher is increasing as well. Coiledtubing blowout preventer systems rated for 10,000psi are notuncommon, and 15,000psi stacks are available.

The continuing increase in temperatures faced by most tools,especially telemetry and electronic equipment, is a challenge forCT, which must be cooled when extracted from the well before itis wound on the reel. If it is coiled onto the drum without cool-ing, the tubing will contract and could collapse the drum or break.

BJ has worked in wells with bottomhole temperatures to450°F (232°C). Coiled tubing drilling operations have encoun-tered temperatures between 256°F and 301°F (125°C and 150°C).

Cooling can be done by circulating through the CT or with acooling loop in the riser. A cooling loop has had to be included,for example, when working in geothermal wells.

Baker Hughes’ acquisition of the independent U.K. companyZeroth Technology Ltd. (Zertech) has added an important capa-bility to the Baker Oil Tools CT toolbox, Mackenzie said.

“Zertech’s metal-to-metal Z-Seal technology provides a sig-nificant advantage for sealing systems on well intervention prod-ucts like bridge plugs and straddles in an HP/HT environment,”he said.

Coiled tubing is one of the main deployment methods for theZertech product line.

Z-Seal (patent pending) is a high-integrity, low-profile, hig-expansion seal that may be entirely non-elastomeric. The sealingconcept relies on the controlled application of load to expand theseal to achieve a fully formed pressure barrier, may be fullyretractable and does not rely on memory.The controlled mechanismcan allow for expansion ratios of up to 160%.

By eliminating elastomeric materials from thewellbore seal and internal seals, operating temper-ature limits can be raised to 700ºF (371ºC) andpressure differential, depending on expansion char-acteristics, to more than 10,000psi.

A metal-to-metal seal also eliminates much ofthe risk associated with chemical incompatibility, asignificant advantage as more HP/HT develop-ments around the world use expensive brines,including cesium formates.

Schlumberger’s CoilFLATE service is designedto provide reliable zonal isolation in harsh environ-ments.The HP/HT thru-tubing inflatable anchor-ing packer, designed for extreme conditions, elimi-nates the need for a workover rig because the pack-er is run on CT or jointed pipe into vertical, devi-ated or horizontal wellbores. Remedial operationscan be performed without killing the well. Theservice also features an advanced multi-set straddleand an effective multi-set packer.

CoilFLATE is available in multiple sizes forwork in up to 9 5/8-in. casing.


10

Fracturing is a key growth area for coiled tubing. (Photo courtesy of BJ Services)

Technology, High-pressureIntervention Come Together Improving the performance of each well safely and efficiently is our business.

In today’s market, coiled tubing (CT)technology is critical to the success ofprofitable oilfield operations. Cudd

Energy Services’ field professionals provide arange of engineered well intervention serv-ices with CT, from a simple sand wash to anintricate high-pressure well recovery opera-tion. Cudd aggressively pioneers newadvancements in the use of CT, equipmentdesign and technology for its customers inonshore and offshore environments.

Cudd Energy Services’ technical supportteam and engineering staff use the mostadvanced software to calculate the optimumCT methods and techniques to maximizeand enhance string performance. Theintegrity of the CT work string is carefullymonitored during its operative life using theOrion® data acquisition system andCerberus® real-time modeling and fatiguemonitoring software.These systems are usedin conjunction with a new transflective near-field imaging touch screen display thatincreases brightness on the screen making iteasier for the operator to quickly see criticaldata.Cudd also has an in-house comprehen-sive CT string database and proprietarystring specification program to ensure eachCT application is conducted within the spe-cific string’s operational limits.

HIGH-PRESSURE INTERVENTIONRecently, Cudd Energy Services’ experi-enced personnel and bundled servicesconcept developed a way to utilize CT ina critical service application under extremepressures. A well bridged off at a shallow143ft (44m) with potential wellhead pres-sure in excess of 10,900psi. The bridgeneeded to be removed prior to completingthe next phase of well completion.

The remediation plan called for a 15,000-psi high-pressure CT unit, a short string of

1 3/4 in.QT-900 CT, a thru-tubing solutionsmotor head assembly, Bronco Serviceswellhead equipment and a StimulationServices high-pressure pump along withother necessary surface equipment tomaintain well control.

The situation required careful pre-jobplanning to provide the best solution byminimizing exposure and providing a highprobability for success.Typically, CT oper-ations do not involve such an extremepressure-while-drilling or milling near thesurface, which made the situation unique.Hydrogen sulfide gas was also present,addingto the complexity. This gas along with thehigh pressures placed the CT and downholeequipment in the corrosion stress-crackingregion limiting the type of CT that could besafely placed in the well during the interven-tion. If the stresses exceeded the yield stressof the CT, then failure could occur.

After initial material selection, Cudd’stechnical services group performed tri-axial

stress modeling to predict the best fit. Tri-axial stresses are based on the widelyaccepted Von Mises Distortion EnergyTheory for ductile materials. The theoryuses a combination of the principal stress-es of axial, hoop and radial in comparisonwith the material’s yield stress to predictthe onset of failure.

Although the CT manufacturing industryis held to high standards, Cudd EnergyServices required verification of the actualgeometric properties of the actual tubing tobe used for this critical situation. Even afterthe tubing properties and geometries wereverified, Cudd’s Corpus Christi, Texas, dis-trict and technical services group performedan additional test on samples of the CT. Thetest objective was to simulate the conditionsthat would exist during the job.By perform-ing the test in a controlled environment, theoperations personnel had empirical proof tosupport the stress model, show the equip-ment was mechanically sound and ensurethe operation could be safely performed.

Using proper material selection, soundengineering practices and verification test-ing, a solution was found and the operationsuccessfully completed. The remediationwas a success, and the objective for the cus-tomer was met. This example of using aunique application combined with pre-jobevaluation, communication, cooperation,bundled services and field-testing createvalue for the customer.

CUDD ENERGY SERVICES

Cudd Energy Services15015 Vickery Drive • Houston, TX 77032

(832) 295-4629 • www.cudd.com

Paid Sponsorship

Advances In Coiled Tubing Technology • www.eandpnet.com 11

Cudd pioneers new advancements in coiled tubingtechnology and equipment design.

Cutting Costs, ProvidingAccess to New Reserves There are two key elements of value in any drilling technique – cost-effective drilling performance andthe ability to accurately place the wellbore to maximize production.

W ith a growing choice of more reliable and capa-ble tools, today’s coiled tubing (CT) drillingtechnology is increasingly competitive with

jointed-pipe drilling in both these areas.There is another situation driving the growth in the use of

CT for drilling.“Rig availability,” said Perry Courville, manager for CT

and hydraulic workover with Halliburton Energy Services.“There is more interest now because it is sometimes hard toget a conventional rig.”

A high utilization rate also has pushed conventional rigrates higher, adding to the interest in CT for a variety ofdrilling operations.

“A number of jointed-pipe rig operators have migrated tothe coiled tubing market,” Courville said, but CT drillingcontractors have not moved into the traditional rig market.

Historically, there has been the perception that CTdrilling was cheaper than traditional drilling. However, bythe time all the requited tools are added to the end of thecoil – a motor, special bits, other tools – the rate couldapproach that of traditional rigs.

The most consistent CT drilling activity still is in Canadaand Alaska. In Canada, under-balanced drilling with CT iscommon. Pressure controlled drilling – drilling at close tooverbalance – and thru-tubing drilling are being done in Alaska.

Elsewhere, CT drilling has been sporadic, though somewells have been drilled in Europe, the Far East and theMiddle East.

Weatherford International Ltd. is running a new system inits CT drilling project in Algeria where formations are hardand abrasive.

“It’s a tough area, but we’ve learned a lot and the projectis going well,” said Michael Stulberg, globalproduct line manager for thru-tubing.

Coiled tubing was the choice for the multi-well project for a major operator in Algeria, inpart because it is well suited to drilling in anunder-balanced pressure condition. Rig avail-ability and cost were also considerations.

Weatherford is also active in CT drilling inAlaska and Canada, where short laterals aredrilled for coalbed methane development.

FULFILLING ITS POTENTIALThere has been a dramatic increase in CTdrilling during the past 3 years, said Jimmy Gray,Baker Hughes Inteq product line manager forslimhole re-entry systems.“There have been sig-nificant advances in the reliability and the valueof CT drilling and completion programs.”

Coiled tubing is not yet a mature drillingtechnology, but neither is it in its infancy.Though no longer a niche, high-cost option, itneeds to gain momentum, and cross over intoapplications where it has not previously beenconsidered, to fulfill its full potential.

Increasingly, CT drilling is being used inThis diamond speed mill is on a whipstock ramp. (Image courtesy of Baker Oil Tools)


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CUTTING COSTS

remote locations where “spread” costs are high and logisticsare a challenge. Significant growth also is occurring in themature fields of North America, where there has been agrowing acceptance of the technology, Gray said.

Coiled Tubing is also used to “finish” wells where a con-ventional rig is used to drill to the top of the pay and runcasing. Then CT is used to drill the pay zone in an under-balanced condition. There also is renewed interest in usingCT for exploration.

“Many of the promises that coiled tubing offered in thepast are now being fulfilled,” Gray said.

Industry is more familiar with the technology and increas-ingly willing to consider it for more applications.

“Fundamentally, CTD is reservoir driven,” said AlexCrabtree, product line technology manager for CT with BJServices Co. “There are two key criteria in selecting candi-dates for coiled tubing drilling (CTD): can the well be drilledunderbalanced – is the borehole stable, in other words – andwill it be a better well if drilled underbalanced?”

SIMILAR BUT DIFFERENTFrom a manufacturing standpoint, the main differencebetween tube for drilling and tube for workover is diameterand wall thickness. Precision Tube Technology has focused onthe ability to manufacture heavier wall tube and larger, heav-ier reels of pipe during the past couple of years. A typicaldrilling string of CT is now in the mid-range of Precision’smanufacturing capability, said Dennis Dunlap, president, CTbusiness unit for Precision Tube Technology.

Coiled tubing drilling can be used to drill many of thesame types of wells as conventional rotary drilling, and ele-ments of CTD systems are similar to those of rotary systemsusing jointed drillpipe.

For vertical wells, CT uses a drilling assembly with adownhole motor similar to the bottomhole assembly (BHA)for conventional drilling. For directional drilling, CT issteered much the same as conventional rotary drilling.Parameters are also similar for bit design and selection,whether for CT or conventional drillpipe.

The benefits of CTD tend to reduce cost compared withconventional rotary drilling, according to the Intervention &Coiled Tubing Association (ICoTA), including:

• safe and efficient pressure control;• faster tripping time (150+ ft/min);

• smaller footprint and weight;• faster rig up and rig down;• reduced environmental impact;• fewer personnel; and• availability of high-speed telemetry.Much of the CTD done to date has been in non-direc-

tional shallow gas development and shallow injection wells,and in holes smaller than 7 in., according to the ICoTA.Holes up to 13 3/4 in. have been drilled successfully, accord-ing to the association.

Directional wells can now be drilled with CT, includingnew wells, extensions, sidetracks from existing completionsand horizontal drain holes. Drilling with CT can also bedone in an underbalanced or overbalanced pressure condi-tion. In an overbalanced condition, the operation is similar todrilling with drillpipe. However, the CTD fluid system istypically smaller than that of a conventional rig and thesmaller tubing diameter can limit flow rates.

OPENING THE CTD APPLICATION WINDOWSafety is a key advantage of CTD, especially in underbalancedoperations. Eliminating jointed pipe reduces well control andpressure management risk, and personnel are not required ona rig floor to make connections. Baker Hughes, for example,recently completed a 3-year project with no reportable losttime accidents.

Advances in technology fueling the growth of CTD willopen the window of applications even farther, Gray said.

Closed loop, automated systems will extend the laterallength capability of CT drilling. This “game changer”will bring more opportunities for CTD, he said, includ-ing mature basins, where underbalanced drilling opera-tions may be needed. Bypassed production and com-partmentalized reservoirs are growing targets of pro-duction enhancement efforts, and CTD offers advan-tages in accessing these zones.

Especially in North America where large fields arenot being discovered, a return to mature basins to

develop new zones or stem decline curves is increasinglyattractive.

A closed-loop drilling system enables that search as doadvances in high-performance downhole motor technology.For example, Baker Hughes’ X-treme motor line features acontoured stator technology that can increase at-the-bithorsepower dramatically, compared with conventional posi-tive displacement motors.

Historically, whether in a 2 3/8-in. or 3-in. BHA, powerthat could be delivered to the bit was limited. New motordesigns have made a step-change increase in this capability,Gray said.

“Projects that might not have been drilled with coiled tub-ing in the past are now candidates for the technology,” he said.

To cope with deeper wells, Baker Hughes has focused on

“THERE IS MORE INTEREST NOW (IN COILED TUBINGDRILLING) BECAUSE IT IS SOMETIMES HARD TO GET ACONVENTIONAL RIG.”

Perry Courville,Manager, Coiled Tubing and Hydraulic Workover,

Halliburton Energy Services

reducing overall wellbore tortuosity through the use of auto-mated systems. “Using what we’ve learned from rotary steer-able systems and vertical drilling systems like VertiTrak, wehave been able to package that in a smaller configuration forCT drilling,” Gray said.

During the next 3 to 5 years, there will be additionalapplications including multilateral completions and the abil-ity to place liners to improve wellbore stability, he said.

In multilateral completions, eliminating pipe connectionsmitigates hole-cleaning and hydraulics issues that would arisein drilling through depleted or nearly depleted reservoirs.Differential sticking that can occur in an overbalanced situa-tion can also be minimized when downhole pressure is accu-rately controlled.

Baker Hughes’ CoilTrak system includes a drilling per-formance sub that provides real-time weight-on-bit, down-hole torque and vibration analysis so operating parameterscan be modified in real time to drill a smoother wellbore.

“The system is fully interactive,” Gray said. “We can now‘joy-stick drill’ routinely, something that was considered sci-ence fiction a few years ago.”

Combined with formation evaluation sensors, it is possibleto navigate more precisely in the reservoir. Full resistivity andgamma measurements in real time – not in a memory or log-ging mode – make it possible to steer into production.

This technology has removed a significant disadvantage ofCTD compared with conventional drilling. Formation eval-uation and sensor packages were previously not available inthe tool size needed for CTD.

“It is a big step change, and it will continue to open thewindow of applications, especially in areas of geologicaluncertainty,” Gray said.

THE BUSINESS ENDAn expanding choice of fit-for-purpose bits is also availablefor CTD and other CT operations. Hughes Christensen isdesigning optimized polycrystalline diamond compact bitsspecifically for CT applications.

In Alaska, where CTD continues to gain momentum, a 3 3/4-in.Hughes Christensen STX404 drilled the Ivishak Z1Asand/shale build and lateral sections with one bit.The initialobjective was to construct the build section then verify thebit’s condition.The four-bladed PDC bit was pulled in goodcondition and tripped back in the hole to finish the well.Job details include:

• Build section—419ft (128m) in 10 hours, average devia-tion of 20.13º/100ft (31m);

• Lateral section—1,867ft (570m) in 27 hours, an averageof 69.15 ft/hour (21m);

• Total—2,286ft (697m) in 34 hours, for an average of61.78 ft/hour (19m).

WATCHING FATIGUE, AVOIDING LOCKUPBecause it is repeatedly plastically deformed, coil fatigue is aconcern in any CT operation. Drilling with CT typicallyincreases fatigue compared with other CT operations.

Under “normal” CT use, a string might last between 30and 100 jobs, said Ed Smalley, senior vice president of CTES LP.When used for drilling, depending on the operation, themaximum number of jobs might be less than half that. Tokeep a closer watch on fatigue, the monitoring softwarepackage CTES developed for standard CT operations alsoworks well for drilling, he said.

“When fewer jobs can be done with the string, it becomesimportant, especially when drilling extended reach laterals, tomonitor fatigue in real time,” Smalley said.

The CTES system monitors the percentage of fatigue life used;most coils are retired after about 80% of the fatigue life has been used.The calculation is specific for each CT size, wall thickness and yieldstrength and includes the field-operating environment – gooseneckand CT reel size, internal pressure – to provide accurate results.


CUTTING COSTS

14

Three and three-quarter-in. PDC bit is optimized for coiled tubingoperations. (Image courtesy of Hughes Christensen)


The software can also predict whether a tractor will beneeded to pull a string through an extended reach interval,and how much force the tractor needs to provide.The tractoris used to help avoid CT “lockup,” which occurs when thecoil continues to be pushed from the surface but it has heli-cally buckled at the section of highest compression because ofthe wall contact friction force. At the point of lockup, lessthan 1% of the force applied at the surface is transferred to thebottom end of tubing and forward movement stops.

“Lockup can be a significant challenge when using coiledtubing to drill long horizontal wellbore sections,”Smalley said.

GETTING A LATERAL STARTEDCoiled tubing is increasingly used as a technique fordrilling laterals out of existing wellbores.The first step inthat process is to mill a window in casing so drilling canbegin.

Coiled tubing sidetracking did not begin to gain realacceptance until the mid-1990s. Since then, Baker OilTools has gained extensive experience in using CT for casingexits. Since 1996, the company has performed more than 350casing exit jobs globally and has developed casing exit tech-niques and tools for monobore and thru-tubing environments.

“The proving ground and early adopters of coiled tubing

drilling have been in Alaska,” saidGordon Mackenzie, product linemanager for thru-tubing inter-vention with Baker Oil Tools andIntervention & Coiled TubingAssociation co-chairman.

Typically, a CT casing exit isdone in two trips; on the firstelectric wireline trip, the whip-stock is set and positioned, onthe second trip, the window ismilled. Most windows are milledwith a diamond speed mill.

Introduction of BakerHughes’ Navi-Drill X-tremeworkover motor has helpedexpand casing exit capability. Itsshorter-than-average length andgreater-than-average torquecapabilities are important fea-tures when working with CT.

Another recent advance hasbeen the ability to cut exit win-dows in exotic materials. SinceBaker Oil Tools performed thefirst 25%-chrome exit in theU.K. North Sea in 2002, inter-

est in making exits through high chrome materials and nick-el alloys has grown steadily.

“That’s where thru-tubing casing exit research and designare headed,” Mackenzie said.

Research and development (R&D) is also focused onextremely underbalanced environments.

When a major operator drilled a series of laterals in a gasfield in Sharjah, for example, gas production was not shutdown during milling of the exit window and the subsequentdrilling of the openhole zones.

For such applications, Baker Oil Tools has developed systemsfor almost-pure nitrogen operations. Cooling and controllingvibration present challenges in a nitrogen environment. On theSharjah job, a small amount of injected liquid was permitted tohelp cool the bearing section in the workover motor.

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16

Two coiled tubing units perform simultaneous jobs on two wells. (Photo courtesy of Halliburton)

“THERE HAVE BEEN SIGNIFICANT ADVANCES IN THERELIABILITY AND THE VALUE OF COILED TUBINGDRILLING AND COMPLETION PROGRAMS.”

Jimmy Gray,Product Line Manager, Slimhole Re-entry Systems, Baker Hughes Inteq


CBM AND SHALLOW FIELDSCoalbed methane (CBM) and shallow well drilling are primeapplications of CTD.Wells are typically not complex and thelogistics of getting pipe to the location is seldom a challenge.In these applications, a large number of wells are usually con-tained in a limited geographical area, another characteristicthat plays to the strengths of CTD.

Much shallow drilling is done with CT rigs in Canada, forexample, in areas with dense well populations. Coiled tubingdrilling is often not an economical option for a few wells, butdrilling between 300 and 400 wells with several rigs canbring significant cost savings.

Coiled tubing occupies a smaller footprint, too, often aconsideration in the areas where CBM and more maturefields seem to be located, especially in North America. Anysmaller hole makes fewer cuttings, and requires less fluid andequipment.

Canada is expected to stay active as shallow gas fields andCBM fields are developed in Alberta. Some Canadian opera-tors are entering the U.S. Rocky Mountain region, too,where CBM is also being developed and more CTD isexpected. The wells are deeper than those in Alberta,however, so coils used in Canada often do not holdenough pipe for the Rocky Mountain drilling.

“We’re doing some technologically extreme CToperations. But at the same time, we are focused onbrownfield applications,” said Warren Zemlak,Schlumberger business development manager for CTservices.

As more fields decline, CT is uniquely suited to complet-ing wells and maintaining production. In the past, CTD andmulti-zone fracturing, for example, were niche applications;today those are “mainstream.”

Coalbed methane and alternative gas development will seeincreasing use of unique CT technologies such as multilateralcompletions, to improve reservoir drainage and reduce thesurface impact of drilling operations.

“Re-entry into existing wellbores will be a real opportu-nity for CT drilling,” Zemlak said.

EXTENDING EXTENDED REACH Horizontal drilling continues to set new records for reach.There is growing interest in “ultra extended reach” holes thatcould extend 12 1/2 miles to 18 3/4 miles (20 km to 30 km)from the surface drilling location.

Coiled tubing drilling is setting records in this arena, too.Schlumberger set three new records when it successfullycompleted a directionally drilled well in Alaska using itsDynamically Overbalanced Coiled Tubing Drilling tech-nique with an electric line inside 2-in. CT.

A window was cut at about 15,800ft (4,819m) in the exist-ing 3 1/2-in. tubing and hole drilled to a measured depth of

about 18,200ft (5,551m). Then a low-side openhole sidetrackwas drilled at 17,950ft (5,475m) measured depth, and direc-tionally drilling continued to about 18,350ft (5,597m). A2,600-ft (793-m), 2 3/8-in. slotted liner was set in the open hole.

In long horizontal or high-angle holes, tractors can dra-matically extend the reach of CT operations. A downholetractor can push the string to the target depth and apply thedownhole force needed to operate tools.

Without a tractor, the reach of CT varies with severalparameters, including the size of the coil and hole. Small-diameter CT in a large hole will not go far in a horizontal orhigh-angle well, perhaps 1,000ft (305m). Larger CT – 2 in.or more – inside a smaller hole can be pushed farther.

“The practical limit without using a tractor, even with alarger tubing in a small hole, seems to be somewherebetween 3,500ft and 4,000ft [1,068m and 1,220m],” saidBrian Schwanitz, vice president and general manager ofWelltec Inc.

That limit applies, in general, to holes deviated more than70º, where gravity is providing little or no help.

In addition to extending the reach of CTD, the tractor pro-vides a constant weight-on-bit while drilling, helping to avoidthe “stick/slip” problem, which can wreak havoc with drillingefficiency. In a stick/slip situation, bit weight can change dra-matically as the string shifts from the stick condition to the slipcondition, possibly stalling the bit and motor. Drilling with atractor also controls reactive torque, Schwanitz said.

Welltec has been able to pump as much as 3 bbl/min ofdrilling fluid through its tractor with a mud motor on theend of the tractor and the bit at the bottom. Surface readoutof weight-on-bit has shown the tractor was providing up to2,300 lb of additional weight-on-bit during drilling.

Welltec has performed five CT drilling jobs in PrudhoeBay where the goal was to prove the concept of getting extrareach, Schwanitz said. Many of the targets are right at thelimit of what CT can do without the help of a tractor.

“So far, we have been able to reach bottom in most of thewells we’ve worked in by tailoring the tubing string to thewell,” Crabtree said.

But as horizontal intervals get longer, tractor systems willbe more important.Tractors typically cannot pull the tubingalone, but they reduce the push that must be supplied, delay-ing the onset of buckling.

17

CUTTING COSTS

“FUNDAMENTALLY, COILED TUBING DRILLING ISRESERVOIR DRIVEN.”

Alex Crabtree,Product Line Technology Manager, Coiled Tubing, BJ Services Co.


Vibrating tools help, too. And larger tubing, either diame-ter and/or wall thickness, also extends the reach of CT.

“There is a point of diminishing return, however,” Crabtreesaid. “As size increases, the weight that must be pushed alsoincreases.”

MORE MICROHOLE R&DAccessing bypassed production in mature fields is a key opportu-nity for microhole drilling technology. But so is exploration,Gray said. In exploration, microholes offer the benefits of a smallfootprint that lowers location cost – roads and infrastructure.Casing, cement, mud, waste control and other costs are reduced,and impact on the environment can be minimized.

Microhole drilling can be done where it might not bepossible to move in conventional drilling equipment.

“Microhole drilling can drill, access and define newreserves in a very cost-efficient and environmentally-sensitivemanner,” Gray said.

Baker Hughes has developed thru-tubing drilling (TTD)technology with jointed pipe and CT. With its smart wellintervention technology, it can put tools in the hole that

monitor downhole conditions in a live well. Tools can passthrough production nipples without having to pull a comple-tion string and do remedial work without mobilizing a con-ventional rig, and do it safely without shutting in production.

Baker Hughes has used the technology extensively inRussia where infrastructure is limited to exit casing under-balanced – milling a window – then drilling underbalanced.

Considerable R&D effort is being applied to developingmicrohole technologies and CT drilling is an important partof this potential.

THE DOE’S ONGOING EFFORTMicrohole drilling could be cost effective for shallow and mod-erate-depth holes for exploration, field development, long-termsubsurface monitoring, and to a limited degree, oil and gas pro-duction, according to the U.S. Department of Energy (DOE).

Late last year, the Gas Technology Institute (GTI) and theDOE announced the successful field-testing of a microholedrilling technology. The GTI and partners RosewoodResources Inc. and Advanced Drilling Technologies haveused microhole technology to successfully drill wells in the

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Niobrara Chalk reservoirs in Kansas and Colorado.“The benefits in cost savings (of microhole drilling) to the

natural gas industry alone could be $8.4 billion during a 15-year period,” said Rhonda Lindsey Jacobs, project managerfor the National Energy Technology Laboratory (NETL).“The volume of drilling waste could be reduced by 103 mil-lion bbl or to one-fifth the amount of waste volumes gener-ated while drilling conventional wells. These targets areworth the government’s investment.”

Early last year, the DOE announce R&D funding for 10new microhole technology projects aimed at pushing the tech-nology toward commerciality and widespread application.Theinitiative involves developing technologies associated withdrilling wells smaller than 4 3/4-in. in diameter and relateddownhole micro-instrumentation.

The projects will be managed by the DOE Office ofFossil Energy’s NETL.Total value of the projects is nearly$14.5 million, with the DOE contributing $7.7 millionand industry partners providing $6.8 million. An earlierround of solicitations under the DOE’s microhole technol-ogy initiative, announced in June 2004, involved six proj-ects valued at nearly $5.2 million.

In making the latest announcement, the DOEreported it expects widespread adoption of microholetechnology to boost infill drilling and substantially cutexploration cost and risk.The department recently estimatedthe remaining shallow (less than 5,000ft – 1,525m – subsur-face) oil resource in the United States at 218 billion bbl.

The focus of the DOE’s work is on adapting conventionalCTD techniques to ultra-small-diameter holes. A complete,cost-effective microhole drilling system must include a fullspectrum of subsurface sensors, motors, logging tools andother borehole instruments small enough to fit into themicro-wellbores, yet rugged enough to survive the harshdownhole environment.The 10 new projects announced last year are:

• Geoprober Drilling Inc. (Houston)—This project calls fordrilling three wells with a composite CTD system toconfirm the capability to drill low-cost, shallowslim/microhole exploration wells in water depths to10,000ft (3,050m). Cost savings are projected at 59%compared with conventional wells.

• Technology Institute (Des Plaines, Ill.)—A next-generationmicrohole CT rig fabricated by Coiled TubingSolutions for drilling to 5,000ft will be field-tested. In aKansas gas field last year, the rig was able to drillbetween 280ft and 400ft/hour (85m and 122m). Itcould lower drilling cost/well by 28% to 38%, accord-ing to the DOE.

• Confluent Filtration Systems LLC (Houston)—Researchers will seek to develop an elastic-phase, self-expanding tubular technology.The company’s goal is to

develop self-expanding well casings to any diameter,leading to improved methods and feasibility of mono-bore drilling and well construction.

• Confluent Filtration Systems LLC (Houston)—Sand thatinfiltrates the drillstring during microhole drilling canbe a problem, especially in small-diameter wellbores.This project is designed to develop a concept for a self-expanding, high-flow sand screen that could be madefrom a wide range of materials.

• Tempress Technologies (Kent,Wa.)—The goal is to developa small, mechanically assisted, high-pressure water-jetdrilling tool. A downhole intensifier would boost thepressure.The tool would overcome the limited reliabil-ity, power and torque of small-diameter drill motors, amajor hurdle for microhole drilling reliability.

• CTES LP (Conroe, Texas)—Researchers will focus onimproving the performance and reliability of microholeCTD bottomhole assemblies while reducing the costand complexity of drilling inclined/horizontal well sec-tions greater than 2,000ft (610m). Inducing vibrationalong the CT drillstring would eliminate the need for adownhole tractor.

• Technology International Inc. (Kingwood, Texas)—Thisproject will develop and test an effective downholedrive mechanism and a novel drillbit for drilling withCT. The high-power turbodrill will deliver efficientpower at relatively high revolutions per minute and lowbit weight and use high-temperature cutters that candrill hard and abrasive rock in 3 1/2-in. boreholes.

• Ultima Labs Inc. (Houston)—The goal is to combine exist-ing technologies for measurement-while-drilling andlogging-while-drilling into an integrated, inexpensivemeasurement system to facilitate CTD of small-diameter(3 1/2-in.) wells at depths shallower than 5,000ft.

• Baker Hughes Oilfield Operations Inc. (Houston)—Researchers aim to provide a wireless system to helpsteer drilling in a microbore. Plans call for developing adownhole bi-directional communication and powermodule and a surface CT communication link.

• Gas Technology Institute (Des Plaines, Ill.)—The institute willdesign, develop and evaluate a counter-rotating motordrilling system ideally suited for reducing costs associatedwith drilling wells targeting unconventional gas.

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CUTTING COSTS

“LOCKUP CAN BE A SIGNIFICANT CHALLENGE WHENUSING COILED TUBING TO DRILL LONG HORIZONTALWELLBORE SECTIONS.”

Ed Smalley,Senior Vice President, CTES LP


Versatility and Box of Toolsmake CT Ideal for Thru-tubing WorkWell maintenance and repair using a workstring and tools that can be deployed through productiontubing has long been the most common application of coiled tubing technology. With new fit-for-pur-pose tools as well as sophisticated software and telemetry, coiled tubing can perform an increasingvariety of re-entry operations more effectively.

Much of today’s productioncomes from mature fieldswhere operators have

refocused on how to increase assetvalue by boosting production andrecovery. Some of this gain will bemade “with the drillbit,” but agrowing share of the increase willresult from intervention operations,said Alex Crabtree, product linetechnology manager for coiled tub-ing (CT) with BJ Services Co.

Coiled tubing offers severaladvantages. The ability to circulatewhile treating a live well minimizesformation damage that can occurwhen a well is killed. Circulationalso makes possible the use of flow-activated tools.

Coiled tubing allows faster trip times than conventionaldrillpipe but still has the rigidity needed to access intervals inhighly deviated and horizontal wells, and apply tension or com-pression forces downhole.

In thru-tubing applications, CT can deploy a variety oftools that may not necessarily be CT products. Much of theadvance in CT technology in recent years has been in reduc-ing the size – at the same time maintaining the reliability andincreasing the capability – of tools used for conventional jointedpipe operations.

The Intervention & Coiled Tubing Association (ICoTA) citesthe following pumping applications of CT systems in existingwells:

• removing sand or fill;• fracturing and acidizing;• unloading a well with nitrogen;• gravel packing;

• cutting tubulars with fluid;• pumping slurry plugs;• zone isolation;• scale removal (hydraulic); and• wax, hydrocarbon or hydrate removal.There also is a variety of mechanical well service operations

for which CT is well suited, including setting a plug or packer,fishing, perforating, logging and mechanical scale removal.Tubulars can also be cut mechanically, sliding sleeves operatedand completion equipment installed.

A steadily growing global fleet of CT units is routinely per-forming most of these operations daily.

CUSTOM DESIGNAs the application window opens wider, CT as large as 2 7/8-in.is being used, for example, in the North Sea. It means bottom-hole assemblies (BHA) must be designed with increasing tensile

MAINTENANCE AND REPAIR

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Roto-Pulse screen cleanout process uses Roto-Jet tool. (courtesy of BJ Services)

load capacity, said Gordon Mackenzie, product line manager forthru-tubing intervention with Baker Oil Tools and ICoTA co-chairman. The ability to handle increased loads and increasingtorque has generated a new approach to tool design.

More tools are being designed specifically for CT operations.Until the late 1980s, for example, thru-tubing fishing was doneprimarily with tools adapted from those used for slickline oper-ations, Mackenzie said. To overcome the limits of these tools,Baker Oil Tools has custom-designed CT fishing tools, forexample, with an external and internal catch for a slick or fish-ing neck profile. Once on the fish, the tool can be disengagedhydraulically for further cleanup, to come back out of the holeor to be re-engaged.

In addition to scale removal and cement milling, CT is beingused increasingly for cutting operations. One part of Baker OilTools’ research and development effort is focused on severingexotic materials in monobore and thru-tubing applications.

Thru-tubing operations, including stimulation, also make useof tractors.Almost any fluid, even that which is pure nitrogen ornitrogen-charged, will drive Welltec’s tractor turbines very well,said Brian Schwanitz, vice president and general manager ofWelltec Inc.

“A very promising application of tractors is on offshore plat-forms where it is not possible because of weight orcrane limits to deliver a coil of large diameter tubingthat normally would be needed for a job,” he said.

Smaller-diameter tubing – a lighter-weight coil –combined with a tractor can provide the same abilityto reach the target as larger diameter tubing.

CLEANOUT: CT’S ENDURING STRENGTHWell cleanout – removing sand, proppant flow back,frac job screen-out and other solids that inhibit fluidflow – is one of the most common CT operations.

Coiled tubing capability is keeping pace withthe need to clean out deeper wells and longer hor-izontal intervals. Schlumberger set a depth recordon Russia’s Sakhalin Island, for example, when itcompleted about 32,150ft (9,806m) true measureddepth cleanout operations with 2 3/8-in. outerdiameter CT using a downhole tractor to helpreach the target depth.

Roughly half of CT work is still well cleanout,according to one estimate. In many cases, the materi-al can be circulated out up the CT/tubing annulus asa jetting nozzle on the end of the string penetrates thefill. If the material is more consolidated, it may benecessary to run a downhole motor and bit on theCT to remove the fill.

Reverse circulation can also be used to removelarge amounts of material or when well geometrydoes not permit a high enough flow velocity in the

annulus to lift the sand to surface. The well, however, must bekilled before reverse circulating.

Weatherford’s CT focus is on intervention services.“We are doing more rigless operations, including both coiled

tubing and wireline deployed tools,” said Michael Stulberg, globalproduct line manager for thru-tubing with Weatherford.

The company has made about 25 acquisitions to acquire itsthru-tubing capability.

“Not to minimize the role that each component or tool playsin applying a solution, but there are hundreds of tools availablefor intervention operations,” Stulberg said. “What each of thesetools does independently of the others is irrelevant. It’s about theproblems we can solve by screwing them together in variousways and creating the system that solves our client’s problems.”

Well cleanout is still the largest component of Weatherford’sthru-tubing business. Remedial cementing, zonal isolation andstimulation activities are growing, however.Weatherford dividesits thru-tubing intervention work into three solution categories:wellbore obstruction; wellbore departure; and wellbore isolation.

NEW CAPABILITIESImproved techniques, fluids and tools have boosted the efficiencyof CT well cleanout operations. Because many wells now being

In-tubing completion interventions use non-inflatable packer systems to perform variousintervention completions services, such as velocity string, tubing patch, safety valve, gas liftvalve and jet pump installations. (Image courtesy of Weatherford)




re-entered with CT have much more complex trajectories andgeometries, understanding transport phenomena throughout thewellbore has become more critical – and the subject of currentresearch, Crabtree said.

Selective placement of treatment fluid to remediate gravelpacks is a growing CT application. CT techniques can spot flu-ids in specific areas to “excite” the gravel pack, for example, toallow fluids to enter and fines to be washed out without damag-ing the gravel pack or screen. BJ’s Roto-Pulse, for example, usesthe Roto-Jet tool with optimized operational parameters andnozzles to place fluid uniformly behind the screen across theentire interval and fully remove it.

New indexing tools that allow orienting into multilateralshave improved the “dexterity” of CT, said Dan Bohannon, vicepresident for CT and nitrogen services with Cudd EnergyServices. Motors used for cleanout can now withstand higherpressures and temperatures. Gas motors are available to work onformations that are fluid sensitive, avoiding the need to circulatea full column of fluid.

Cudd has used gas motors with nitrogen and air. For economicreasons and because nitrogen equipment was not readily avail-able, an air mist was used in the U.S. Four Corners area. Air ismore corrosive than nitrogen, and in some situations, it can posewell control risks.

To avoid frequent sand wash operations, it is possible to locksand or proppant in place. An initial wash can be followed witha sand control treatment, for example, that treats the problemrather than the symptoms, said Perry Courville, manager for CTand hydraulic workover with Halliburton Energy Services.

Halliburton’s SandTrap service uses resin technology to con-solidate the near-wellbore area to help prevent sand production.The consolidated area maintains almost 100% of initial perme-ability.The system incorporates a solvent/resin mixture depositedas a thin film on the formation and clay surfaces. The solventpackage provides a low-viscosity treating fluid and a way to getthe resin in contact with the formation.

A SandTrap treatment can be applied to new or existing sandcompletions and placed down production tubing with jointedpipe and a service packer, or with CT. Coiled tubing andSandTrap service can put existing zones back on productionwithout the expense of a conventional workover rig.

Relatively low-tech well cleanout operations using a nozzleand circulation are still one of the most frequent CT operations.More difficult cleanouts typically require rotation to removescale, mill cement or remove bridge plugs.

One of Weatherford’s recent developments is a new motortechnology designed for more power, longer life and highertemperatures.The eCTD motor comes in sizes from 1 11/16 in.to 2 7/8 in.

PLUG REMOVAL“One of the biggest uses for coiled tubing in North America isthe removal of composite bridge plugs and frac plugs followingfracturing operations,” Mackenzie said.

These operations typically require a downhole workovermotor and an appropriate BHA.

Multiple frac jobs are being done more frequently and morequickly, and are being done throughout the United States, pre-dominantly in new gas field developments, Mackenzie said.

In a typical multiple-zone fracturing application, the first zoneis perforated, a proppant or sand frac is performed then a com-posite bridge or frac plug is run.The next step is to perforate thenext zone and frac it above the composite frac plug, and thesequence is repeated. In many cases, the bridge plug and perfo-ration operation have been combined to allow for even greatereconomies of scale.

As many as 20 plugs have been deployed in a single well,Mackenzie said, and Baker Oil Tools has milled 20 plugs in a sin-gle CT run. Average mill-out time for the plugs is between 15minutes and 30 minutes.

Since it provides plugs and milling assemblies, Baker Oil Toolshas designed both to be compatible and able to be milled quickly.Its composite plugs have a clutching mechanism on the top andbottom to lock the clutches together when the center body andlower clutch guide of the plug being milled is pushed onto theplug below. The design allows milling to continue in the mosteconomic manner.

AN EXTREME CASEScale can be a significant problem. In the BMB field in north-west Poland, Polish Oil & Gas Co. has been successful in

22

This coiled tubing tractor unit has treating nozzles. (Photo courtesy of Welltec Inc.)


mechanically removing the scale deposits and restoring produc-tion using under-reaming technology conveyed on heavy-wallCT. BJ Services International BV used the system to clean threewells in the field using positive-displacement motors, mills andunder reamers.The field is estimated to have recoverable reservesof 9.3 million tons of oil in the predominantly dolomiteZechstein formation, and 9.3 billion cu m of gas.

The goal was to boost production by milling the iron sulfidescale from the 2 7/8-in. production tubing, then under-ream scalefrom the 7-in. perforated casing below the tubing shoe.

The candidate wells selected for CT cleanouts were charac-terized by the hardness of the scale, high formation pressures anda hydrogen sulfide (H2S) environment.Wellhead pressures duringoperations were expected to exceed 300 bar, making the collapsepressure rating of the CT a key design criterion.With sour gascontent in excess of 15% in some areas of the field, safety was atop priority.

The special 1 3/4-in. tapered string for the job was manufac-tured with 80,000psi yield material, rather than 90,000psi orhigher, to reduce the risk of H2S embrittlement. An H2Sinhibitor was also used in the base oil circulating fluid to helpprotect the string.

The cleanout operations required an average of 4 1/2 days per well.Onsite CT monitoring and modeling software aided the

clean-out operations. In one instance, CT weight during trip-ping did not match predicted weights; onsite modeling helpedidentify corkscrewed production tubing as the probable cause.

REMEDIAL CEMENTING, ZONAL ISOLATIONFor Baker Oil Tools, zonal isolation means bridge plugs for tem-porary or permanent zone isolation. Permanent applications typ-ically are to shut off gas or water in a lower zone, or for fieldabandonment.Temporary applications include installing a bridgeplug as a workover barrier, for wellhead maintenance or to eval-uate upper zones.

“Coiled tubing can be used to set a retrievable bridge plug forany application,” Mackenzie said.“All the toolscan operate without set-down weight or rota-tion for either removal or setting.”

Coiled tubing can also be used to place waterconformance chemicals to shut off upper or inter-mediate zones with a fluid rather than cement.

With the acquisition of Zertech, Baker OilTools added to its range of zonal isolation solu-tions.The company’s technologies span from amonobore environment where there are nextto no expansion requirements, through themetal-to-metal seal capability with expansionto 160%, to the industry’s highest expansioncapabilities with nitrile elastomeric inflatabletools. Inflatable operations thru-tubing canachieve up to 350% expansion.

Though not developed specifically for CT, BJ’s “liquid stone”cementing technology has a synergy with CT operations,Crabtree said. For example, if squeezing off perforations or set-ting abandonment plugs, volumes tend to be relatively small.Cement can be taken to offshore or remote sites pre-mixed andready to be pumped through CT. Quality control can be per-formed at the base before the cement is sent to location.

STIMULATION: MULTI-FRACS AND CTThe CT stimulation market is large; one estimate puts it at about$100 million per year.

Coiled tubing fracturing has seen significant growth in recentyears, fueled by improvements in fracturing technology and flu-ids. Much of the work is in shallow gas development in Canada.Multiple frac jobs are also a typical treatment in the Barnett shalein the United States; some are done with CT, some are not.

Most CT frac jobs are performed on recently drilled wellsthat require multiple small fracs rather than a massive frac.Theneed to expose the zone to be stimulated while isolating thezone that has just been stimulated can be met by CT’s speedand versatility.

The ability of CT to move in and out of the hole quicklymakes it an attractive tool for fracturing and acidizing, especiallywhen treating multiple zones in a single well. Coiled tubing canaccurately spot treatment fluid and provide uniform treatment oflong horizontal intervals.

BJ Services’ OptiFrac, for example, can perform a typicalmulti-zone frac in less than a day.The service features adjustablestraddle lengths, increased depth, lower cost and other benefits. Itcan be configured for 4 1/2 -in. and 5 1/2 -in. casing and can bemade available for 7 in.

An earlier concern that proppant might erode the CT stringand shorten its life has been mitigated by monitoring wallthickness during the job, according to ICoTA.The measurementscan be used to adjust the CT fatigue models and accurately determine remaining CT string life.

With coiled tubing, CobraMax service and Hydra-Jet create perforations and initiate fractures.(Graphic courtesy of Halliburton)

www.eandpnet.com • November 2006 24


Growing emphasis on the benefits of “pinpoint stimulation,”an objective facilitated by CT’s ability to move up and downthe hole quickly and easily, is driving growth in fracturing withCT, Courville said. More new units are equipped with largertubing for this application.

Ten years ago, 1 1/2 -in. CT was typically used to clean out3 1/2 -in. tubing, for example. Now 1 3/4 -in. or 2-in. tubing isused to achieve the flow rates needed for fracturing. Larger tub-ing then requires larger reels and redesigned injector heads.

Being able to perform multiple fracs in one day is attractive.“It’s common to do eight fracs in a day in one well, then

move on to the next well,” Courville said.Its CobraMax fracturing service combines the performance

of conventional thru-tubing fracturing and the speed and ver-satility of CT operations, according to Halliburton. It requiresfewer trips in the hole and to the well site, and occupies asmaller operating footprint. The service can cost-effectivelystimulate multiple zones that require larger, higher-rate treat-ments than are possible with conventional CT fracturing.Cobra Max’s high performance in multi-interval vertical wells

comes from optimizing injection rate, proppant volume andproppant concentration.

The process involves pumping through conventional CT tocreate perforations and initiate fractures.The main fracture treat-ment is pumped concurrently through the CT/casing annulus.

STIMULATING A GAS STORAGE WELLLate last year, BJ Services completed a CT stimulation operationon an underground gas storage well in Grijpskerk nearGroningen, The Netherlands, that is owned by NederlandseAardolie Maatschappij (NAM), a 50-50 Shell-ExxonMobil jointventure, and operated by Shell Exploration and Production.

The goal was to increase the production and injection rate ofthe 7 5/8-in. gas storage well using acid stimulation to restore thewell’s capacity to 6 million scm/d. Declining performance dur-ing several years indicated scale, fines or drilling damage in thewell. The well was partially completed with 7-in. and 7 5/8-in.tubing, a 7-in. blank liner and 7-in. pre-packed screens from10,735ft (3,272m) to 11,293ft (3,442m).

A pre-packed screen, an acid screen-wash and mud-acid

Sophisticated electronic monitoring ensures exact location and load calculations for placement-critical operations. (Photo courtesy of Schlumberger)



squeeze was proposed, but there wereseveral concerns about the operation:

• the acid resistance of the pre-packedscreen, mesh wire and pre-packedBakerbond sand;

• potential damage to the meshwire by the jetting impact duringthe screen wash; and

• potential damage to surfaceequipment from oxygen andchlorides in the treatment fluids.

BJ tested samples of the screenusing the proposed treatment recipesto determine the required corrosioninhibitor loading. A microscopicexamination of the mesh wire follow-ing a 12-hour soak in the acid at bot-tomhole temperature showed no damageto the screen.

To reduce the impact pressure onthe screen while retaining optimumscreen coverage, BJ considered using itsRoto-Pulse tool. Because the treat-ment would be pumped using nitrified fluids to remain withincollapse limits of the CT, the Phase Separator was introducedto further reduce the impact pressure by separating the nitro-gen from the fluid just above the Roto-Pulse tool. No damagewas sustained by the mesh wire or to the pre-packed sand dur-ing the tests using the Roto-Pulse and jet nozzles.

To prevent oxygen from appearing in the produced fluids,acid was mixed with nitrogen instead of air and an oxygenscavenger was added to the recipe.To lower the chloride con-tent of the fluids before they entered the production system, BJpumped oxygen-free water into the flow lines, a process thatrequired considerable preparation.

The CT intervention was completed in 6 days and boostedproduction from 4.5 million scm/d to 6.5 million scm/d, a ratehigher than the well’s initial performance.

PERFORATING AND RE-COMPLETIONPerforating with CT is an expanding application, especially inhorizontal or high-angle wells. BJ has used various deploymentsystems to run sections of perforating guns as long as 3,000ft(915m) into a well and out of a live well in one run.

Cudd’s work in horizontal intervals includes a growingnumber of “tunnel” perforating applications, Bohannon said.This older concept has been revived as CT technology hasdeveloped.

In tunnel perforating, a plug is set when the CT reachesdepth, then a gelled sand is mixed and pumped to jet cut a tun-nel out into the formation. Operators report the operation pro-vides greater reach into the formation and a more predictable

frac job, Bohannon said. It can be accurately oriented to thefracture or any direction the geologist feels will result in thebest fracture growth.

GOING ‘ROUND THE BENDIn the age of routine high-angle wells, some angles build quicklyand can pose a challenge when attempting to run a long per-forating gun or other long BHA. It is important to know beforegoing in the hole whether the tool can be moved past a signif-icant change in hole direction or dogleg, and if so, how large abending force will be subjected to the tool.

CTES has developed “tool-fit analysis” software based onfinite element analysis to answer these questions. Input to theprogram includes material yield strength, tube outer diameterand inner diameter, and the wellbore trajectory either proposedor actual.

The software will also analyze the effect of adding centralizersor rollers on the BHA, and help determine optimum placement.

“The results from these modeling efforts are not alwaysobvious,” said Ed Smalley, senior vice president of CTES LP.“For example, the addition of knuckle joints may actually makeit more difficult for the BHA to navigate through a dogleg.

“It’s a big help in ‘designer wells’ for determining whatdownhole tool configurations can successfully negotiatedoglegs and herring-bone drainage patterns. If done in theplanning stage, a minor change in wellbore trajectory that isacceptable from a reservoir development standpoint, forexample, could make future well intervention operationsmuch easier and much less costly.”

Z-Seal is a metal-to-metal sealing technology. (Image courtesy of Baker Oil Tools)



Solutions take Shape for Subsea Intervention If there is one market segment that poses the biggest challenge to coiled tubing technology, it is sub-sea intervention. Currently, it is a commercial challenge, too, although that eventually will change.

Subsea intervention with coiled tubing (CT) requires aboat, a coil and a riser, making it a process that necessarilyinvolves several companies. It has been difficult to put all

these elements together in one place, in part because the marketis not yet large enough.

Studies are under way, including some joint industry projects,aimed at developing the best way to exploit CT’s potential forsubsea well intervention.

“The challenge is to get enough players in the market – andto expand the market – so it becomes profitable,” said PerryCourville, manager for CT and hydraulic workover withHalliburton Energy Services.

A recent forecast projected there would be 4,000 subsea wells by2008. It is inevitable that the frequency of workover needed for thesewells will increase, and even though many of these wells wereplanned and drilled to minimize the need for intervention, there isevidence that workover frequency will be higher than expected.

The result is a growing industry-wide interest in how to cost-effectively intervene in subsea wells, said Warren Zemlak,Schlumberger business development manager for CT services,and Schlumberger has several efforts “in the design phase.”

There is a need for a rigless subsea intervention technique, hesaid, but the challenges are significant and there is a lot to be done.

“Today, the solution is to bring back the rig, but currentdemand for rigs and the cost of rig time both challenge an oper-ator’s ability to fix an existing subsea well,” he said.

DIFFERENT PATHS, SAME GOALWhen operators initially forecast reserves discovered by landwells and dry trees on offshore platforms, they might expectvarious interventions for stimulation or sidetrack drillingduring the well’s life to increase that reserve by 50% to 80%

“Why should subsea wells be different?” goes the thinking,said Alex Crabtree, product line technology manager for CTwith BJ Services Co.“How can we apply the intervention tech-niques we’ve been using on traditional wells to subsea wells tobring those same reserves increases?”

Most subsea wells are still young, and the need for interven-tion has been limited, but that will change. How quickly it willchange is difficult to forecast, Crabtree said, making it hard todetermine the right time to spend capital to be prepared.

During the past few years, a number of solutions have been

proposed and projects started that would make subsea interven-tion practical and cost effective, including conversion of jackuprigs, or new fit-for-purpose semisubmersibles or monohull ships.The range of these approaches is broad because of a variety ofsubsea well types, depths and production systems.

“Though subsea intervention faces both technical and com-mercial challenges, it will be a growth area for all facets of theindustry, coiled tubing included,” Crabtree said.

BIG SAVINGS POSSIBLEEarlier, ExxonMobil Corp. announced the development ofthe Subsea Intervention Module (SIM) to significantlyreduce the cost and time of downhole logging, acidizing and

Coiled tubing skid equipment is on an offshore platform.(Photo courtesy of Halliburton)


SUBSEA INTERVENTION

other interventions in deepwater wells. According toExxonMobil, the system could perform these activities up tothree times faster than a mobile offshore drilling unit andsave as much as 50%.

The SIM design consists of a 380-ft (116-m) long vessel witha specially designed intervention tool that is lowered to theseafloor and latched onto the subsea well.The SIM tool will befunctional in up to 6,500ft (1,983m) of water and be able toaccommodate well depths to 13,000ft (3,965m) below theseafloor. The system is designed for use in wells employing hor-izontal subsea trees with 36-in. structural casings.

As planned, the SIM vessel would be a dynamically posi-tioned ship, about 1 1/2 times the size of a standard offshore stim-ulation vessel. It would feature a large moonpool for deploymentof the intervention tool, a mission control center and accommo-dations for a crew of more than 100.

SIM is a very interesting and exciting opportunity for CT,said Dennis Dunlap, president of the CT business unit with

Precision Tube Technology. “It’s a game changer technology forservicing deepwater wells.”

Statoil has made considerable progress with thru-tubing rota-tional drilling operations in subsea wells, operating from mobiledrilling units. Last summer, it successfully completed the firstsubsea thru-tubing rotary drilling and completion operation.

Statoil is exploring the possibility of deploying thru-tubingdrilling from smaller and more cost-efficient vessels. Coiled tub-ing is of interest in this context, according to Statoil, since itcould allow drilling from lighter ships without a drilling derrick.

Statoil has said the development of a fit-for-purpose dynam-ically positioned vessel for subsea thru-tubing drilling could save$20 million per sidetrack compared with a conventional semi-submersible.Vessel size would depend on requirements for mudhandling and production testing.

Such a unit would need high capacity data transmission capa-bility, superior steering capabilities and might make use of com-posite CT, according to Statoil.

Specially designed coiled tubing units have found increasing applications offshore. (Photo courtesy of Cudd Energy Services)


SUBSEA INTERVENTION

PLATFORM STACK STRESSESIn addition to growing interest in CT intervention in subseawells, use of longer and more complex intervention stacks onfloating structures has posed new questions about equipmentselection and safety.

When a CT intervention unit is operated from a tension-legplatform or spar, for example, the wellhead on the platformmoves independent of the platform.The intervention riser mustbe connected to the wellhead so the well can be entered underpressure, but the other end is anchored to the independentlymoving platform.Tall intervention stacks are more susceptible tobending forces from crane, production riser and platform move-ments.

Proper equipment selection, how to best support the riser on theplatform and minimize stress in the riser, are important questions tobe answered when designing the intervention stack.

In the past, the allowable movement, when to add supports andwhen to halt operations were judgment calls. CTES’ Zeta system isdesigned to eliminate guesswork and optimize stack configuration.

“The Zeta-Model enables users to make informed decisionsregarding the need for a gimbaled table or titanium lubricator sec-tions,” said Ed Smalley, senior vice president of CTES LP.

For pre-job modeling, Zeta will determine:• probability of exceeding pre-set safety limits during operation;• need for additional intervention stack supports and

their location;• stress changes as a result of stack loading changes;• maximum stress location;• weight required to buckle the stack; and• an optimized rig-up configuration.For monitoring during the job, CTES has developed a 2-

ft (0.6-m) long lubricator section instrumented with fiberoptic strain gauges installed as part of the intervention stack.Fiber optic strain gauges are required to provide the necessarymeasurement resolution. An added benefit of these straingauges is that no electricity is required at the wellhead. TheZeta-Gauge is at or near the point of maximum stress in thestack to determine the impact of changing surface, downholeor offshore conditions.

“Real-time Zeta monitoring during an operation allows theoperator to decide when to suspend operations based on real data,rather than guesswork,” Smalley said.

WHERE COILED TUBING IS HEADEDCoiled tubing drilling has had a cyclical history. Often, anoperator would use CT drilling on one job, and if results werequestionable, the technology would not be used again untilrecommended by a new department or manager.

Like any emerging technology, that’s not the optimum approach,said Gordon Mackenzie, product line manager for thru-tubingintervention with Baker Oil Tools and Intervention & CoiledTubing Association (ICoTA) co-chairman. A better test is to apply

the technology to a group of wells or campaign to extend thelearning curve, realizing there may well be problems to over-come.

“That’s been the approach in some of our operations inOklahoma, in Alaska and in Sharjah,” Mackenzie said.

Coiled tubing’s history is rooted in its use as a cost-effectivewell cleanout tool. In recent years, these conventional wellborecleanouts and acid stimulation jobs accounted for more thanthree-quarters of total CT revenue.

However, CT fracturing and drilling applications haveemerged as two of the fastest growth areas. Revenue from thesetwo CT applications has grown from almost zero 10 years ago,to about 15%, according to ICoTA.

The CT market is dominated by the three large service com-panies, which control about 60% of the CT market. On a regionalbasis, according to ICoTA, there are typically more than 30providers of CT in the international market; Canada is served bymore than 35 CT service providers, and the United States bymore than 25 companies.

The Zeta screen capture shows stack stress in blue. (Image courtesy of CTES)


SUBSEA INTERVENTION


FAST GROWTH CONTINUESLast year, roughly 100 new CT units were added to the fleet,Courville said, and he expects a similar number of units to beadded this year, though manufacturing capability is currentlyrestricting growth.

“We don’t see any slowdown in activity in the near term,”he said.“The fastest growth will be in stimulation and fracturing.”

In the near future, growth in applications for CT will outstripthe conventional drilling market, said Jimmy Gray, Baker HughesInteq product line manager for slim hole re-entry systems.Though there will be additionsto the conventional rig fleet, there will contin-ue to be limited availability of conventional rigsfor some time.

The ability of CT operations to boostproduction will be the main driver of thatgrowth, Gray said.

“The goal is to more effectively drain thereservoir. Accessing reserves that are known toexist but to date have not been able to be pro-duced will be the biggest market for CTdrilling,” he said.

Cudd currently is focused mainly onintervention – for cleanout, multi-fracbridge plug removal, for example – but ismoving to larger pipe sizes to expand its CTdrilling and stimulation capability. Cudd alsoexpects CT drilling to be the applicationwith the fastest growth.

As opportunities for CT expand, fluidtechnology will become more important.“Expertise we’ve brought to the company hasincreased our coil life through a betterunderstanding of what is needed to inhibitfluid being pumped,” said Dan Bohannon,vice president for CT and nitrogen serviceswith Cudd Energy Services.

Cudd is also building larger pumps to beable to pump higher rates at high pressures.

“But the volume of work we have nowdoes not give us much opportunity toexplore new applications,” Bohannon said.“We could not do much more work thanwe are doing now and still keep our unitsmaintained.”

This high utilization rate is despite therecent addition of new units in the RockyMountain region and the Permian Basin, andmore units are scheduled for delivery. ByDecember, Cudd expects to put three moreunits to work; next year, it plans to add six orseven more units.

Once Gulf of Mexico activity returns to pre-hurricane lev-els, there will be more gravel pack work, Bohannon said.A lot ofthe wells shut in by Katrina may have sanded up and will haveto be worked over.

“There’s going to be a lot of work in that area,” he said.Cudd was in the process early this year of training people and

had three new CT units ready when work resumed in the Gulf.This will be another “solid” year for CT growth, said Dunlap,

much like last year. To meet that expected demand, Precision

31

SUBSEA INTERVENTION

An Inteq engineer inspects the CoilTrak advanced coiled tubing directional drilling bottomhole assem-bly after completion of a successful multilateral drilling run in Alaska. (Photo courtesy of Baker Hughes Inteq)

executed a major expansion of its plant this year, boosting manufac-turing capacity by 50%.

MORE LONG, LARGE STRINGSDunlap expects part of the growth in CT work will be in deep-water wells, an application for which Precision is furnishing anincreasing number of long strings. For example, measured depthcould be 25,000ft (7,625m), water depth 5,000ft (1,525m) andthe service company will want a little backup length.

“All of a sudden, that turns into a 32,000-ft (9,760-m) stringof coiled tubing,” Dunlap said. “We’re seeing more of thesestrings – we’re counting them on two hands now – and morediscussion of this application.”

Precision has manufactured these strings, and it made a27,000-ft (8,235-m) coil of 2 7/8 in. that is the company’s heaviestat about 70 tons.

Precision also supplies CT for small diameter subseapipelines.A number of operators have recognized the advantageof supplying pipelines in long continuous lengths with continu-ous external coating, Dunlap said.

A typical pipeline application might be a 24-in. pipelinewhere a 2-in. methanol line is also needed.To piggyback the 2-in. CT on the 24-in. line is easier than putting a separate weld-ing line and handling system on a lay barge.

“We’re seeing a number of these applications,” Dunlap said.Coiled tubing is being increasingly used for methanol injec-

tion service. Precision supplied the monoethanolamine injectionsystem for Statoil’s Snøhvit project offshore Norway, for exam-ple. Compared with jointed pipe, CT is usually cleaner on theinside, an advantage in a methanol system where needle valvesand filter systems can easily become clogged.

“Expected growth in coiled tubing activity is 15% to 20%,and that will put a strain on the industry. That growth also posesa bottleneck in industry’s ability to absorb new coiled tubingtechnologies,” Zemlak said.

It also is an opportunity to invest more in game-changingtechnology.The CT drilling and intervention envelopes continueto be pushed, for example, as horizontal displacements get longer.Schlumberger recently reached new depth records in CT drillingwith a total measured depth (TMD) of 18,200ft (5,551m), and inintervention applications, which included a TMD of about32,150ft (9,806m) with 2 3/8 in. outer diameter CT.

In expanding its capability, BJ Services will create synergiesbetween other product lines and its CT services to deliver valuein its intervention work, Crabtree said. It also will continue todevelop new technology tailored specifically to CT operations.

Fluids will be one focus, since most work is still done withsmall tubing sizes – 1 1/2 in. and 1 3/4 in. – in which friction pres-sure during pumping operations can be high.The challenge is todevelop fluids that can perform well not only during stimulationor cleaning operations, but also will have a lower friction thatallows higher pumping rates.

“Ensuring pipe performance in sour wells is also a growingissue,” Crabtree said.

BJ is part of an ongoing project with ExxonMobil and ShellCanada to investigate performance of CT in well interventionoperations in hydrogen sulfide environments.

An indication of the maturity of CT operations is theincrease in “regulatory” work in relation to CT, Crabtree said.The American Petroleum Institute, where working groups arefocused on well control and tubing itself, is developing recom-mended practices and standards.Working groups in Canada arealso developing recommended practices.

CHALLENGES TO GROWTHExpected growth in CT activity poses a significant people chal-lenge, Zemlak said.

“Personnel development has become an essential priority for us.Competency and proper training are increasingly important,”he said.

Maintaining commitment to internal training, Schlumbergercontinues to invest in its training centers. Advanced methods oftraining in the field, such as computer-based field simulators avail-able in virtually every Schlumberger CT operation, are also beingincorporated. Schlumberger also offers CT training to customers,and the company has seen a significant increase in requests foradvanced level training, said Zemlak, and has seen a significantincrease in requests for advanced level training.

One of the largest restrictions to growth in the current cycle ofhigh oil/gas prices and demand is limited resources of personnel andequipment, Mackenzie said.

A threat to the further growth of CT as an intervention tech-nique is a shift to positioning downhole equipment in highlydeviated and horizontal wellbores with electric wireline and atractoring system.

“This technology removes the effective monopoly that CTonce held in live well conveyance in deviated and horizontalwellbores,” Mackenzie said.

As the trend to high-pressure, high-temperature (HP/HT)environments continues, intervention tools and systems will beneeded with capability beyond what is available, especially inservice life. Baker Hughes’ high-expansion metal-to-metalZ-Seal technology is an example of what will be needed formore extreme pressures and temperatures, and for chemical compat-ibility. Exotic materials being used to complete HP/HT wells willspur research and development on downhole cutting structures.

“Smart” intervention technology using coiled tubing is alsolikely to become a differentiating technology, Mackenzie said.Asoperators require more and more real-time, two-way communi-cation, the development of smart technology that does notrequire running electric wireline within the CT string will likelyaccelerate. HP/HT, low bottomhole pressures and exoticpower fluid requirements are all trends that will lead to thecontinued evolution of non-elastomeric CT workover motorswith increasing capability.


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advances in coiled tubing technology e&p supplement 2006

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