20 Oilfield Review

Coiled Tubing Drilling on the Alaskan North Slope

Lamar L. GanttErin M. ObaARCO Alaska Inc.Anchorage, Alaska, USA

Larry LeisingRosharon, Texas, USA

Ted StaggMark StanleyEric WalkerBP Exploration (Alaska) Inc.Anchorage, Alaska

Rohan WalkerAnchorage, Alaska

For help in preparation of this article, thanks to ArvellBass, ARCO Alaska Inc., Prudhoe Bay, Alaska, USA;David Gallagher and Scott Tinkham, Dowell, SugarLand, Texas, USA; Perry Kline, Dave Smith and RussellA. Wagstaff, Dowell, Prudhoe Bay, Alaska; Dale Meek,Anadrill, Sugar Land, Texas; Andy Rike, Dowell, SugarLand; Jim Todd, Dowell, Rosharon, Texas; Tim Smith,Wireline & Testing, Prudhoe Bay, Alaska; Rick Whitlow,BP Exploration, Prudhoe Bay, Alaska; and BrockWilliams, BP Exploration, Sugar Land, Texas.CTD (Coiled Tubing Drilling) is a mark of Schlumberger.

Drilling with coiled tubing has evolved from an experimental technique to a proven

technology now used for nearly half of all new wells on the North Slope of Alaska,

USA. Specially designed arctic coiled tubing units can move, rig up and begin work

in a matter of hours. By working concentrically through large production tubulars,

wells can be sidetracked at lower cost than with conventional drilling rigs.

Reentering existing wellbores is an efficientand effective way to increase recovery frommature fields.1 Use of coiled tubing avoidsthe significant time and cost incurred by con-ventional drilling units, which requireremoval of the existing tubing, packer andwellhead before drilling can begin. Through-tubing reentry with coiled tubing allows alateral wellbore to be drilled without remov-ing the production tubing, provided the pro-duction tubing has a large enough internaldiameter. This difference promoted theadvancement of CTD Coiled Tubing Drillingtechnology and is the main driver for its pro-liferation on the North Slope of Alaska, USA.

In many areas, CTD techniques are stillviewed as experimental. This is not the caseon the North Slope, where it has taken cen-ter stage as an economic means of tappingnew pools of oil.2 Numerous factors havecome into play to make the CTD processeconomically and technically successful inAlaska. The vast number of wells and uniqueoperating conditions presented many oppor-tunities for remedial well operations. Therepetitive nature of coiled tubing workoversgave engineers and crews extensive experi-ence and fostered efficiency.

ARCO Alaska Inc. (ARCO) and BP Explo-ration (Alaska) Inc. (BPX) have becomeleaders in the development and use of coiledtubing. The majority of their CTD techniqueshave been developed by working togetherand in partnership with Dowell and otherservice companies.

Prudhoe Bay is the largest reservoir in theUSA and accounts for 5% of the total US oilproduction. The field, discovered in 1968, isjointly operated by ARCO and BPX. First pro-duction came on-stream in 1977, and peakproduction reached 1.5 million BOPD[240,000 m3/d] in 1989.

1. Hightower CM and Blount CG: “An Operator’s CoiledTubing Drilling History,” presented at World Oil’s 6thInternational Coiled Tubing & Well InterventionConference & Exhibition, Houston, Texas, USA,February 9-11, 1998.Kunkel B: “Benefits Fuel CT Growth,” PetroleumEngineer International 70, no. 7 (July 1997): 36-41.Sjonberg G: “Coiled Tubing Drilling: SuccessfulDrilling Offshore in the North Sea,” presented atWorld Oil’s 5th International Conference on CoiledTubing and Well Intervention, Houston, Texas, USA,February 4-6, 1997.Hill D, Neme E, Ehlig-Economides C and MollinedoM: “Reentry Drilling Gives New Life to Aging Fields.”Oilfield Review 8, no. 3 (Autumn 1996): 4-17.

2. MacDonald RR and Crombie DL: “Balanced DrillingWith Coiled Tubing,” paper IADC/SPE 27435, pre-sented at the IADC/SPE Drilling Conference, Dallas,Texas, USA, February 15-18, 1994.

Summer 1998 21

new targets continually decreases as the fieldmatures. The cost to drill a CTD well is abouthalf that of a conventionally drilled well. Thecomparison is not exact, because conven-tional rotary rigs can drill longer horizontalstepouts. Nonetheless, CTD units routinelydrill several thousand feet horizontally, keep-ing development cost per barrel low. CTDtechnology currently delivers new produc-tion at an average development cost of 60%of rig costs on a per barrel basis.

This article discusses strategies for drillingwith coiled tubing, drilling techniques andtools developed in Alaska, and the rig designsthat have played a crucial role in the techni-cal and economic success there.

Reservoir StrategiesAs the Prudhoe Bay field matures, new wellsare needed to recover small pockets of oilmissed by previous wells. Targeting newwells in this large, mature field is challenging.It calls for consensus among interdisciplinarygroups of reservoir, drilling, facility and pro-duction engineers as well as geoscientists.4

To help mitigate field decline, an extensiveinfill-drilling program, predominantly hori-zontal reentry wells, was undertaken.

The field is a combination structural andstratigraphic trap, and the producing forma-tions comprise the Sag River, the Shublik andthe Sadlerochit group. The most importantinterval is the Ivishak, part of the Sadlerochitgroup, which accounts for the majority of

22 Oilfield Review

The Prudhoe Bay field, with numerouswells of similar design, was ideal for rapiddevelopment and growth of CTD technol-ogy. In the early 1980s, the development ofcoiled tubing cement-squeeze techniques,inflatable packers and electric line inside thereel increased confidence in expanding therole of coiled tubing beyond intervention.

Prudhoe Bay field has 1338 wells: 1128 pro-ducers and 210 injectors. Of these wells,1062 are conventional vertical wells, 261 hor-izontal, and 15 multilateral. Coiled tubingreentry drilling is currently used on verticalproducer and injection wells that havereached their economic limit. The drillingschedule for rotary and CTD rigs targets about

100 wells per year, with slight increases fromyear to year. On average, 85 of these wells aresidetracks, and 15 are new wells. Each CTDrig can drill about 20 sidetracks a year. In1998, CTD rigs drilled more than 40% of thewells (below). About 60 will be drilled withthree CTD rigs next year, accounting for morethan half of planned Prudhoe Bay drilling. Todate, ARCO has drilled more than 70 wellswith coiled tubing and BPX more than 50. Allwere drilled in the Prudhoe Bay field, exceptfor two in the Kuparuk field.

Economics encourage growth in CTD useon the North Slope. The prize is large—morethan 3 billion bbl [476 million m3] of oilremain to be recovered.3 The reserve size of

1993 1994 1995 1996 1997 19980

20

40

60

80

100

120Prudhoe Bay unit total wells

Prudhoe Bay unit CTD wells

Prudhoe Bay CTD Job Count

■CTD well count. Coiled tubing drilling continues to increase its share of drilling activity inthe Prudhoe Bay field in Alaska. About 40% of the wells are drilled with coiled tubing, andthat number should increase when an additional CTD rig is brought in next year (top). Thistrend follows the global increase in CTD wells as the technology becomes more economi-cal to apply in other fields (bottom).

1991 1992 1993 1994 1995 1996 1997

Nonsteered

Directional

Num

ber

of j

obs

0

100

200

300

400

500

Worldwide CTD Job Count

3. Ramos AB, Fahel RA, Chaffin MG and Pulls KH:“Horizontal Slim-Hole Drilling with Coiled Tubing:An Operator’s Experience,” Journal of PetroleumTechnology 44, no. 10 (October 1992): 1119-1125.Leising LJ and Newman KR: “Coiled Tubing Drilling,”SPE Drilling & Completion 8, no. 4 (December 1993): 227-232. Simon AD and Peterson EJ: “Reservoir Management ofthe Prudhoe Bay Field,” paper SPE 38847, presented atthe SPE Annual Technical Conference and Exhibition,San Antonio, Texas, USA, October 5-8, 1997.

4. Shirzadi SG and Lawal AS: “MultidisciplinaryApproach for Targeting New Wells,” Journal ofPetroleum Technology 45, no. 10 (October 1993): 998-993.

5. Dyke CG and Crockett DA: “Prudhoe Bay RigWorkovers: Best Practices for Minimizing ProductivityImpairment and Formation Damage,” paper SPE26042, presented at the SPE Western RegionalMeeting, Anchorage, Alaska, USA, May 26-28, 1993.

6. Szabo DJ and Meyers KO: “Prudhoe Bay:Development History and Future Potential,” paperSPE 26053, presented at the SPE Western RegionalMeeting, Anchorage, Alaska, USA, May 26-28, 1993.

7. Kay EA, Bodnar DA and Cazier EC: “Faulting: A MajorControl on Fluid Flow and Production Performance,Prudhoe Bay Field, Alaska,” paper SPE 26061, pre-sented at the SPE Western Regional Meeting,Anchorage, Alaska, USA, May 26-28, 1993.

Summer 1998 23

proven and potential reserves. The Ivishakformation is a gradual upward finingsequence of fluvio-deltaic, fine-to-mediumgrained sandstones with thin interbeddedsiltstones and shales. The interbeddedsiltstones and shales play a key part in the accelerated use of CTD techniques inthis field because the streaks isolate smallpools of oil that are currently economicallyaccessible only by coiled tubing. Per-meability of the producing intervals varieswidely throughout the field—from about 10 mD in the peripheral regions to severalhundred millidarcies.5

Horizontal wells in the gravity drainagearea have greater initial production ratesthan vertical wells for a given drawdown, butbecause of a greater standoff from the gas/oilcontact, gas breakthrough is delayed. Theamount of oil produced by these wellsincreases with increased standoff betweenthe perforated section of the wellbore andthe gas-oil contact. Geoscientists evaluatethe untapped pools of oil in relation torecently shut-in wells. Smaller pools close tovertical wellbores are prime candidates forCTD use, which currently has a maximumhorizontal reach of some 3000 ft [900 m].Conventional rotary drilling rigs tap thelarger pools more distant from existingwellbores because they can drill longerhorizontal sections.

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2800

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Shublik

Shublik

Zone 4

Zone 4

Zone 4

Zone 3

Zone 3

Zone 2

Zone 2

Zone 2

Zone 1

Zone 1

Sag River

Heavy oil/tar (HOT)

Aquifer

Gravity drainage Waterflood

0

0

1 2

2

3 4

4

5

6 8

miles

kilometers

Original gas cap

Expanded gas cap

Light oil column

Water influx

Aquifer

Gravity drainage/waterflood interaction

■Prudhoe Bay field cross section. As the Prudhoe Bay field matures, remaining pockets of oil become smaller and smaller. Injection ofproduced gas from above and water influx from below are the main reasons for shutting in wells. Coiled tubing drilling has found aniche market by drilling horizontal sections into small pools of oil missed by these shut-in wells.

The four dominant recovery processes aregas-cap expansion and gravity drainage,waterflood, miscible flood and gas cycling.6

Continuous management of these processesand analysis of field performance have led toidentification of attractive targets for furtherdevelopment (above).7

In the gravity drainage area, which is thepredominant recovery mechanism, oil pro-duction is controlled initially by well pro-ductivity. Once gas breaks through, however,wells become rate-restricted because of thegas-handling capacity of the productionfacilities. As gas/oil ratios increase, wellsbecome uneconomic to keep on-stream.Once an existing well reaches its economiclimit, it is typically shut in and considered acandidate for reentry drilling.

Rig DesignsCoiled tubing services were first developedfor the workover market. Most coiled tubingunits are not capable of running casing orpulling and running completions. As a result,the first applications of CTD techniques werereentry drilling, usually performed in con-junction with a workover rig.8

Currently, three CTD rigs operate in PrudhoeBay. The first unit consists of a conventionalarctic well service unit coupled with a coiledtubing unit. The second unit is a purpose-builthybrid containing a coiled tubing unit perma-nently attached to the end of a mobile arcticworkover unit. Nordic Calista and Dowellbuilt that rig in a joint venture to drill reentrywells specifically for BPX. In mid-1998,ARCO brought in a third CTD rig.

24 Oilfield Review

■Comparing CTD unit 4 with a conven-tional rig. The first arctic CTD setup(above), consisted of Dowell coiled tubingunit no. 4 working in conjunction with anarctic workover unit. This drilling packageoccupies considerably less space than theconventional drilling rig on the right in thephoto. With much less equipment, the CTDrig can mobilize and demobilize muchfaster. The current CTD equipment layout(right) is shown with the coiled tubing unitperpendicular to the well service rig. Thissetup is used by ARCO Alaska Inc. in thePrudhoe Bay Eastern Operating Area andhas drilled more than 70 wells.

Mud pits

Doghouse

Disposal tank

Mud pump

Primemovers

Generators

Cuttings box

Pill pit

Dry-addhopper

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CT Unit 4—The first dedicated CTD rig atPrudhoe Bay combined a conventional arcticwell service unit, Nabors Drilling Rig 3S, with a coiled tubing unit, Dowell CT unit 4(previous page). This setup drills exclusivelyfor ARCO on the North Slope. The standardrig up for the CTD operation requires removalof the protective well house and Christmastree, excluding the master valve. The well ser-vice rig main carrier is then centered over thewell, and the derrick raised. The main carrierprovides a heated, enclosed rig floor and aprotective enclosure for the blowout pre-venter (BOP) stack. The main carrier alsohouses the primary mud pump system, pumpand choke manifolds, and diesel-poweredgenerators. The pit module is located adja-cent to the main carrier and provides steamboilers, 300-bbl [50-m3] fluid-storage capac-ity, fluid mixing and degassing equipment,and limited solids-removal capability.

Once the rig modules are in place, thecoiled tubing unit is positioned adjacent andperpendicular to the main carrier. The injec-tor head is placed inside the rig floor windwalls and moved into position over the well.The injector head is protected from extremeweather and can be continuously monitoredduring operations. Drilling and tripping arecontrolled from the coiled tubing unit opera-tions cab. Hydraulic tongs on the rig floormake up bottomhole assemblies (BHAs),jointed pipe liners and completion strings.The rig pump and BOP equipment can becontrolled in the coiled tubing unit opera-tions cab or from the well service rig floor.

A solids processing unit, in combinationwith the rig pit module, maintains criticaldrilling fluid properties. The unit contains alinear motion mud shaker and a high-speedcentrifuge to remove drilled solids. To mini-mize operational cost, the portable unit isrigged up and operated only during drillingin openhole.

The BOP stack consists of two sets ofdouble rams, one annular preventer and a conventional coiled tubing lubricator and stripper head (right). Other surfaceequipment includes a measurements-while-drilling (MWD) trailer for monitoring andmaintaining directional equipment, a trailerfor the directional driller and geologist, and a trailer for rebuilding drilling tools.Upright tanks are used to store up to 800 bbl[130 m3] of clean auxiliary fluids (methanol-water for freeze protection and seawater)and 800 bbl of used fluids.

Summer 1998 25

Choke line

71/16-in. BOPs

51/8-in. BOPs

Hydraulicallycontrolled

remote valve

Casing valve

Master valve

Kill line

BHA or liner slip rams

BHA or liner pipe rams

71/16-in. annular preventer

CT pipe or slip rams

CT blind or shear rams

■Typical CTD BOP configuration. The lower 71⁄16-in., 5000-psi [3.5-MPa] double ram setand annular preventer are used during BHA makeup and for running liners. The upper51⁄8-in., 10,000-psi [6.9-MPa] double ram set contains combination blind/shear andpipe/slip rams for the coiled tubing workstring. A hydraulic stripper head sits atop the BOP stack and provides an additional level of protection.

8. Leising et al, reference 3.

readings go outside a preset operating win-dow. Explosion-proof video cameras are partof a closed-circuit television system thatmonitors critical areas of the rig and allowsthe operator located in the control cab tovisually check on components. Along withthe watchdog system, they give the operatorextra eyes to compensate for reduced rig per-sonnel and provide earlier problem detec-tion. Another significant upgrade to theelectronics package uses a computer to over-ride the injector in case the operatorattempts to exceed coiled tubing limits.

The electronics package and computer can perform some drilling functions, and an electronic autodriller with downholefeedback has also been developed for thissystem, which advances the coil into thehole at a rate based on the pressure dropacross the downhole motor. As the motor issubjected to additional weight from the coil,more torque is required to rotate the bit as indicated by a pressure increase at sur-face. Generally, the operator sets the pres-sure limit at a value less than the pressure atwhich the motor stalls. The computeradvances the coil into the hole until theupper pressure limit is attained; coil move-ment is stopped until the motor pressuredrops below the preset limit. When thisoccurs, the motor no longer drills ahead,indicating that additional weight can beapplied to the bit. The computer then reengages the injector and begins advancingcoil into the hole.

26 Oilfield Review

Hybrid rig—The Dowell/Nordic Calistahybrid CTD rig began working at PrudhoeBay in November 1996.9 This one-piece, self-propelled unit is capable of running both 23⁄8-in. coiled tubing and jointed pipe(right). The unit is uniquely suited to theharsh arctic environment. It was originallydeveloped as an arctic workover rig byNordic Calista and serviced wells for tenyears on the North Slope. In January 1996,Dowell and Nordic Calista developed a con-ceptual foundation for completely modifyingthe unit to accept coiled tubing components.

The rig package is fully self-contained andcomprises mud pumps, mud pits and fluid-handling equipment, and a pipe-handlingshed. In most cases, the rig can be movedwith pipe standing in the raised derrick. Therig floor cantilevers over the wellhead toallow access to wells in tight clusters and iscapable of leaving the tree and flowlineintact during reentry drilling. This capabilityreduces system cost and maintains tree andtubing integrity.

The hybrid rig provides a fast, efficientmethod of running jointed pipe for liners, aswell as running and pulling the 11⁄4-in. tubingthat is used for perforating and cementingliners. The rig mast and traveling block sim-plify picking up and laying down BHA com-ponents and handling the injector head.Although the rotary table has been removedto facilitate coiled tubing operations, all sup-port components remain in place and therotary table can be replaced quickly to allowuse of jointed pipe and drill collars for spe-cial operations or complex fishing jobs. If themechanical integrity of a well’s productiontubing is questionable, the rig can pull,repair and rerun the tubing prior to side-tracking operations.

Where possible, existing rig componentsthat could satisfy both coiled tubing drillingoperations and jointed pipe operations wereleft intact. The hydraulic system for coiledtubing components remains independent ofthe rig. A hydraulic power pack works incombination with electronic controls devel-oped for the hybrid coiled tubing unit. Thehydraulic pumps are powered by a DC trac-tion motor, the same motor that powers thetwo mud pumps. Although this motor deliv-ers more horsepower than required to oper-ate the coiled tubing components, it waschosen because replacement parts are iden-tical to those for the mud pumps, therebyreducing inventory.

The hydraulic power pack operates theinjector, reel, power tongs and hydraulicrams on the doors that enclose the coiledtubing reel. Other than using the DC traction

motor for power to the hydraulic pumps, thepower pack is nearly identical to other unitscurrently in service. To date, the electricmotor has been failure- and maintenance-free, and maintenance costs and downtimeare expected to be less than for a conven-tional diesel power pack.

The fluid-handling system is rated to 5000-psi [34.5-MPa] working pressure. Thetwo mud pumps can be operated inde-pendently from either the coiled tubingoperator console or the driller console on the rig floor. The triplex pumps had to besized to handle the relatively low rate buthigh-pressure requirements of coiled tubingdrilling. Typical pump pressures are 4000 psi[27.6 MPa] at 2.7 bbl/min [0.4 m3/min]. Alinear motion shaker and high-speed cen-trifuge maintain solids content in the drillingfluid below 1% by volume. BOP equipmentcan be controlled from the rig floor, thecoiled tubing operator console, or the mainaccumulator closing unit.

Coiled tubing electronic monitoring sys-tems, in general, have evolved significantlysince 1990. Most equipment and wellparameters are currently recorded and dis-played on two computer screens and threevideo monitors in the operations cab. Thehybrid CTD rig system records and displaysinformation from more than 40 sensors.

The unit electronics package was upgradedto include a “watchdog” network, whichmonitors all critical rig equipment and alertsthe operator through audible warnings if

■Self-propelled arcticCTD hybrid unit. Dowelland Nordic Calistajointly constructed thishybrid CTD rig specifi-cally for arctic opera-tions at Prudhoe Bay.The coiled tubing unitwas attached to theend of the mobileworkover unit oppositethe derrick. The self-propelled rig can movefrom one well and rigup on another inroughly 4 hr. This rigbegan working for BP Exploration (Alaska)in the Prudhoe BayWestern OperatingArea in late 1996 andhas drilled more than40 wells.

This system allows maximum penetrationrates while limiting the number of motorstalls. An experienced coiled tubing operatorcan drill at least as effectively as the auto-driller, which is measured by rate of penetra-tion and frequency of stalls. For theinexperienced operator, however, the systemcan increase drilling efficiency.

Personnel requirements are minimized byusing specialized equipment to monitorengines, fluid levels, pit levels and hydrauliccomponents. This technology allows theCTD rig to be manned by a toolpusher,driller, motorman, coiled tubing supervisorand service technician; a conventional rotaryrig has a crew twice this size. Because ofoperational differences between CTD opera-

reel into the injector head without having topass through a gooseneck. Bending at thegooseneck causes a great deal of stress onthe coil, so eliminating this point of fatigueshould increase coil life. Transocean Drillingestimates that the coil will last three to fourtimes longer than that for CTD rigs using astandard gooseneck.

Drilling OperationsThe techniques and equipment associatedwith CTD operations have undergone rapiddevelopment since the first operations in1991.10 A principal stimulus for this activitywas the availability of reliable, large-diame-ter coiled tubing to allow sufficient hydraulichorsepower to power the downhole motorand provide sufficient flow rate to ensureadequate hole cleaning. Larger, heavier-walltubing gives the necessary weight for effi-cient drilling and withstands drilling torqueand fatigue.

The CTD process has several advantagesover conventional drilling rig operations.Well-control equipment configuration forcoiled tubing provides a higher degree ofcontrol and safety, which is maintainedthroughout drilling and tripping because tub-ing is pulled continuously through a sealedstripper. The equipment allows underbal-anced drilling to be conducted safely andefficiently, which can reduce reservoir dam-age from invasion of drilling-fluid filtrate.Under many conditions, CTD techniqueshave the potential to cut drilling and wellcosts significantly. The principal areas of costsavings come in reduced hole size, reducedtrip time and lower mobilization and demo-bilization costs.

Coiled tubing drilling has its limitations,however. In formations prone to sloughing orwashing out, coiled tubing is not appropri-ate. If wellbore stability problems develop,coiled tubing cannot be rotated, nor can itwithstand the stress that conventional drillcollars and drillpipe can.

Due to the size, strength and weight ofcoiled tubing, horizontal drilling reach andhole size are generally less than for conven-tional equipment. The longest horizontalsection drilled using coiled tubing has areach of nearly 3000 ft, whereas the longestextended-reach well drilled by rotary meanshas a step-out length ten times farther (above left).

tions and jointed-pipe drilling, the roles ofteam members change with each operation.For example, during drilling operations,responsibilities typically assigned to thedriller become the responsibility of thecoiled tubing supervisor. Cooperation isrequired by all personnel as the reportingstatus changes depending on the operation.

CDR-1—Nabors/Transocean Drilling RigCDR-1 began CTD operations on the NorthSlope in June 1998. It is a purpose-builtcoiled tubing drilling rig and has drilledmore than 20 underbalanced wells inCanada. The design is unique because thereel sits above the injector head, directlyover the well. The injector head is placed atthe rig floor, and tubing feeds directly off the

Summer 1998 27

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Coarse, hard conglomerateswith poorly sorted sand matrix

Massive very fine grain sands

Clean sands with thininterbedded shales

Interbedded clean sands andlenticular conglomerates; localto extensive thin shales

Interbedded sands and shales

Gamma ray

Sag River

Shublik

Zone 4

Zone 3

Zone 2

Zone 1

Ivishak10

0 ft

[30

m]

F-43L1

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D-17A

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0 1000 2000 feet

0 300 600 meters

■Horizontal reach. This figure shows the range of horizontal sidetracks drilled from ahypothetical wellbore. The well paths in the plan view (top) and vertical section are thetrajectories of wells drilled with coiled tubing. These paths (red) are all superimposed onone hypothetical wellbore (bottom) to indicate the extent and variety of horizontal well-bores now being drilled.

9. Larson EB, Huffman A, Williams BA, Parker C andSnisarenko P: “Update on Hybrid Rig Development forCoiled Tubing Drilling,” presented at World Oil’s 5thInternational Conference on Coiled Tubing and Well Intervention, Houston, Texas, USA, February 4-6, 1997.

10. Ramos et al, reference 3.Leising et al, reference 3.

A dual-flapper check-valve system preventsbackflow of wellbore fluids into the coiledtubing drillstring. The checks are positionedjust below the coiled tubing connector. Aball-actuated hydraulic disconnect is locatedbelow the check valves. The hydraulic dis-connect provides the option to release theBHA should it become stuck in the wellbore.

The circulation sub is positioned below thehydraulic disconnect and is activated by cir-culating a ball onto a seat. When the sub isopened, the fluid path is diverted above theMWD tools and mud motor and directedradially through side exit ports. The circula-tion sub allows increased circulation rates byeliminating the pressure loss and flow rateconstraints through the BHA. The sub is nor-mally opened when tripping out of casedhole. The higher flow rate improves cuttingsremoval. Circulation to surface is possiblewithout concern for bit or production tubingdamage because the bit does not rotate withthe circulation sub open.

It is often necessary to deploy tools into thehole in two or more sections due to thelength of the BHA. After the lower BHA isdeployed, it is held in place by the BOPslips. String rotation is no longer possibleand a conventional threaded connectioncannot be made up. A splined nonrotatingjoint is used to make up this connection. Thetwo pieces slide together and lock with inter-nal splines to prevent rotation. A threadedcollar slides over the splined section tosecure the BHA.

An orienting tool rotates or indexes thelower section of the BHA to adjust the tool-face in the desired direction. The tool is actu-ated by cycling the flow rate through thetool. An internal-to-annulus pressure differ-ential drives a piston which, in turn, indexesthe tool. A clutch and cam rotate the toolclockwise by a preset amount, typically 20º.The orienter generates up to 500 ft-lbf

[680 N-m] of torque. A jetted sub is installedbelow the orienter and is used to increasethe pressure drop through the tool string andenhance the torque generated. The jetted subalso has a bleed port that allows approxi-

28 Oilfield Review

BHA DesignA variety of BHAs has been used on theNorth Slope during evolution of the CTDsidetrack program. The typical drilling BHA isapproximately 50 ft [15 m] long and consistsof several standard components (below).11

Bottomhole assemblies are designed accord-ing to their function: casing or liner exit,angle-build section, or horizontal section.Overall angle-build rate is a function of themotor housing bend, the size of the motorwear pad, motor and bit diameters, and thelength of the housing from bit to pad. Otherfactors influence angle-build rates. Small-diameter bent housing motors will flex whensubjected to drilling loads. The amount of flexis a function of weight on bit, type of benthousing (adjustable or fixed), and hole geom-etry. Other factors such as motor bearingtolerances, lithology, bit type and wear alsoaffect performance and contribute to uncer-tainty in predicted build rates.

With experience, refinements to motorhousing angles have been made and a moreprecise motor geometry is now employed.Housing angles as exact as 0.625º are speci-fied for use. Further refinements to motorbearing tolerances have also led to a reduc-tion in the build-rate variances observedwith smaller angle motors.

Most of the CTD projects have been per-formed through 41⁄2-in. production tubingusing 33⁄4-in. [95-mm] bits. The BHAs are 31⁄16 in. [78 mm] in diameter or smaller, witha maximum of 3.42 in. [86.9 mm] at a collaron the MWD flow tube.

The coiled tubing connector is a dimple-style fastener that makes up to the coiled tub-ing with set screws. The dimple-typeconnector was selected for its superior capa-bility to withstand torque, overpull anddrilling shock. The durability of the dimpleconnector has been established throughrepeated field use in high-vibration andhigh-impact applications.

Coil

Connector

Check valves

Disconnect

Circulation sub

Nonrotating joint

Orienter

Flow tube

Gamma ray tool

MWD collar

Direction andinclination package

Bleed sub

Mud motor

Bit

■Drilling BHA. CTD operations on the NorthSlope typically use three different types ofBHA designed according to their function.Separate BHAs are used to sidetrack out ofthe casing, drill the angle-build section anddrill the horizontal section through the reser-voir. Each type of BHA uses a differentmotor configuration and MWD packagedepending on the drilling objectives.

mately 10% of the drilling mud to escape tothe annulus prior to reaching the motor. Thebleed port allows the pressure to equalizebelow the orienter; this pressure might oth-erwise be trapped by the motor when thepumps are shut down. Pressure built up inthe tool string as a result of high-viscositymud can prevent the orienter from cycling.

The MWD system currently in use is a pos-itive-pressure, turbine-powered, mud-pulsesystem. Mud-pulse telemetry allows gammaray, toolface, inclination and azimuth mea-surements to be transmitted to surfacethrough the mud column by pressure pulsesgenerated by the pulser assembly. Nonmag-netic collars house directional and gammaray probes between the mud motor and flowtube. Inclination is typically recorded 12 ft[3.7 m] behind the bit, and the gamma raysensor is approximately 24 ft [7.3 m] behindthe bit. The tool has performed satisfactorilythrough doglegs up to 56º.

A 11⁄2-stage, 27⁄8-in. [73-mm] positive-displacement mud motor with a 7:8 loberatio has been used to drill most wells on theNorth Slope. Larger 31⁄2-in. [89-mm] motorsare sometimes used when production tubingis larger than 41⁄2 in. Nonmagnetic rotor/sta-tor combinations have been developed fordrilling through the formation. The use of thenonmagnetic material reduces magneticinterference sufficiently to allow the steeringtools to be placed within 2 ft [0.6 m] of themotor. Conventional steel motors require theuse of 10 to 15 ft [3.0 to 4.6 m] of nonmag-netic collars below the directional probe toeliminate magnetic interference, resulting inbit-to-sensor spacing up 25 ft [7.6 m].Wellbore trajectory projections are greatlyimproved with shorter bit-to-sensor spacing,resulting in more precise directional control.

force, combined with wall friction, results ina net force that opposes coiled tubing move-ment into the well, and eventually this forceprevents advancement of the coiled tubing.This condition is known as helical lockup.12

Helical lockup is modeled during the wellplanning process (below). Predictions ofmaximum weight on bit before helicallockup occurs help in designing the BHAand coil size to match the desired well path.Available weight on bit falls rapidly once the well begins the horizontal section. Many wells on the North Slope are drilledwith 2-in. diameter coiled tubing, due in partto the operational efficiency realized fromworking inside the 27⁄8-in. liner completionsrun after drilling the sidetrack. However, 23⁄8-in. coiled tubing is used in wells whereavailable weight on bit would not be suffi-cient to attain the desired horizontal reachwith the smaller diameter coiled tubing.

Polycrystalline-diamond-compact (PDC)bits have been used extensively in CTD oper-ations on the North Slope. The typical bit hasa five-bladed design and contains a combi-nation of round and flattened 8-mm cuttersto reduce motor stalling and reactive torque.Rates of penetration typically range 30 to 70 ft/hr [9 to 21 m/hr] in sands and 10 to 20 ft/hr [3 to 6 m/hr] in shale zones. Cutterbreakage typically limits bit life to approxi-mately 1000 ft [300 m] of hole or 60 to 70 hrof rotating time.

Coiled tubing geometry changes and thecoil begins to buckle as compressive force isincreased behind the bit. Initially, the coiledtubing buckles in a two-dimensional, sinu-soidal fashion and then deforms into a heli-cal shape when the compressive forceexceeds a critical level. Additional slackoff at the surface reduces the pitch of the helixand increases the normal force of the coiledtubing against the hole wall. This normal

Summer 1998 29

2000 2500 3000 3500 4000 4500

10,100

10,200

10,300

10,400

10,500

10,600

10,700

10,800

10,900

11,000

Maximum weight on bit before lockup, lbf

Window depth

30°/100 ftbuild section

Horizontalsection

2190-lbf weight on bitat total depth

Mea

sure

d d

epth

(M

D),

ft

Parameters:• 33/4-in. openhole• 2-in. coil• 0.156-in. wall thickness• 80,000-psi yield strength• E=32 x 106 psi• 8.8-ppg fluid• 0-psi wellhead pressure• 3500-psi coil pressure• Slackoff coefficient 0.26 in casing and 0.36 in openhole

■Predicted weight on bit. A model of themaximum weight on bit before helical lockupoccurs helps determine the total measureddepth possible for a given well design with aparticular BHA and coil. Once the wellreaches horizontal, the available weight onbit drops dramatically, limiting the total pos-sible length of the well.

8. Leising and Newman, reference 3. 9. Larson EB, Huffman A, Williams BA, Parker C and

Snisarenko P: “Update on Hybrid Rig Development forCoiled Tubing Drilling,” presented at World Oil’s 5thInternational Conference on Coiled Tubing and WellIntervention, Houston, Texas, USA, February 4-6, 1997.

10. Ramos et al, reference 3.Leising et al, reference 3.

11. Leising LJ, Hearn DD, Rike EA, Doremus DM andPaslay PR: “Sidetracking Technology for CoiledTubing Drilling,” paper SPE 30486, presented at theSPE Annual Technical Conference and Exhibition,Dallas, Texas, USA, October 22-25, 1995.

30 Oilfield Review

Window MillingIn 1991, operators began encouraging sup-pliers to develop a mechanical whipstockthat could be run through 41⁄2-in. tubing andset inside 7-in. casing. Although initialresults were encouraging, tool reliability wasa problem. The capability to mill a windowwas crucial to sustaining the entire CTD pro-ject. An alternative method was needed.Milling off a cement plug was originally con-ceived as a stop-gap measure until mechan-ical whipstocks could be made morereliable, but what was originally thought ofas a risky technique turned into a reliable,economic method of sidetracking.

Cement sidetracking, the most straightfor-ward technique, is generally used in wellswith 41⁄2-in. production tubing set inside 7-in. or 95⁄8-in. casing.13 A specially designedcement plug is placed in the casing anddirectionally drilled with a bent housingmotor to cut the window and lateral well-bore. Time drilling (increasing depth by smallincrements at specified time intervals) isused to start the window.

The cement plug technique has severaladvantages over mechanical whipstocks. Noiron whipstock is left in the well. The cementcan easily be drilled out at a later date.Moreover, if the existing wellbore must beplugged and abandoned with cement, thereis effectively no additional cost for the plug.

The method has several disadvantages,however. The windows tend to be shorterthan those drilled with a mechanical whip-stock. The cement ramp tends to be fragile, socare must be taken when the BHA is runthrough the window. Despite these disadvan-tages, more wells are sidetracked off cementplugs than with mechanical whipstocks onthe North Slope.

In 1994, a coiled tubing BHA cut the firstwindow below production tubing. The win-dow was cut off a fiber-cement plug withoutthe use of a mechanical whipstock. The timerequired to a mill a window off cementdropped to less than one day once the capa-bility to cut a window in a single mill run wasdeveloped. The majority of windows cut offcement plugs use a 3.8-in. [96.5-mm] dia-mond speed mill run on a 27⁄8-in. motor or a4.55-in. [115.6-mm] mill on a 31⁄2-in. motor.

The first step in sidetracking without awhipstock is to spot a cement kickoff plug.The cement provides a foundation forwindow-milling operations, and most impor-tantly, access through the window until thewell reaches total depth. The cement systemis a 17-ppg [2-sg], Class G formulation withnylon fibers added for strength, although

some current cement plugs no longer includethe fibers. The cement placement techniquewas adapted from the successful coiled tubingcement-squeeze program.14

Nylon fibers are often added to the side-track cement because they help bind frag-ments together. The fibers provide impactresistance when the bit mills on top of orthrough a cement plug, reducing the likeli-hood of cracking.15 If the cement doesdevelop cracks during milling, the fiberholds the cement intact, so cement piecesare less likely to fall on top of tools run in thewell during subsequent operations. Thefibers reduce cement compressive strengthsomewhat, but so far that has not been aproblem. The benefits of the fibers cannot bemeasured with standard oilfield test proce-dures; however, examination of cement testcubes after compressive failure has shownthe fiber’s benefits qualitatively.

The next step is the drilling of the pilot holeto just above the kickoff point. The shape ofthe pilot hole sets the stage for the remainderof the milling operation. A conventional, shortparabolic diamond bit has proven the bestchoice in drilling the pilot hole. It is run on asteerable positive displacement motor with a1º bent housing. A downhole orienter andmud pulse MWD steering tool provide direc-tional control for the BHA. This BHA alsomills a 3.725-in. [94.6-mm] no-go nipple inthe tubing string to 3.8 in. Each bit can drillfive to ten pilot holes and nipples.

The typical pilot hole trajectory is curved.The pilot hole is drilled down the oppositeside from the window, and the toolface isrotated 180º to the direction of the window.The pilot BHA builds angle across thecemented liner to the opposite wall. Thismethod provides easy BHA orientation andpredictable build. When the bit contacts thewall, a counterclockwise reaction in toolfaceoccurs. The pilot assembly is pulled, and themilling assembly is then run.

The milling assembly has an aggressivedouble-bend BHA to start cutting the casingwall. The milling BHA is the same as thedrilling BHA used later in the well, except itincludes four to six 31⁄8-in. [79-mm] drill col-lars between the steering tools and tubing.The coiled tubing string is compliant in com-pression due to helical buckling. The collarsprovide weight on bit during milling andkeep the coiled tubing in tension, makingweight and depth control more precise.Milling occurs at 1 ft/hr [0.3 m/hr] using ahesitation procedure; once the mill contactsthe casing wall, it is time drilled by advanc-ing the coil in 0.1 ft [0.03 m] increments. Thetime required to mill a window is primarilydetermined by the metal-cutting process.

■Window-milling test. In a mockup test, amechanical whipstock was set inside 7-in.casing, and a mill run on coiled tubingdrilled a window out of the casing. Thisproof-of-concept test early in the CTD pro-gram helped in refining the design ofthrough-tubing whipstocks and the drillingparameters to cut an optimum window.

13. Leising et al, reference 11.Hightower CM, Blount CG, Ward SL, Martin RF,Cantwell DL and Ackers MJ: “Coiled TubingSidetrack: Slaughter Field Case History,” SPE Drilling& Completion 10, no. 1 (March 1995): 4-9.

14. Harrison TW and Blount CG: “Coiled TubingCement Squeeze Technique at Prudhoe Bay,Alaska,” paper SPE 15104, presented at the SPECalifornia Regional Meeting, Oakland, California,USA, April 2-4, 1986.

15. Loveland KR and Bond AJ: “Recent Applications ofCoiled Tubing in Remedial Well Work at PrudhoeBay,” paper SPE 35587, presented at the SPEWestern Regional Meeting, Anchorage, Alaska,USA, May 22-24, 1996.

Mechanical WhipstockSeveral types of through-tubing mechanicalwhipstocks are available. All consist of ananchor that reacts against torsional and axialloads and are designed to allow the smallthrough-tubing diameter to span from thehigh side to the low side of the much largercasing inside diameter. Through-tubing whip-stocks are run inside the 41⁄2-in. casing andexpand to fit inside a 7-in. or 51⁄2-in. liner.These whipstocks are typically used for anear-high-side exit. Gravity forces the upperwhipstock taper to lie against the low side ofthe casing. The disadvantage to this design isthat it requires significant hole angle.

A through-tubing mechanical whipstock,developed by Baker Hughes, is used on theNorth Slope for sidetracking. The proceduresand BHAs used to mill through the liner withminimum dogleg severity, while providing aclean window area, were developed at a testfacility in Shreveport, Louisiana, USA, andrefined during the subsequent window-milling operations. This whipstock wasdesigned with a maximum diameter of 35⁄8-in. [92 mm] so it could easily run throughthe 41⁄2-in. nipple in the typical 41⁄2-in. com-pletion. The whipstock is run and set on elec-tric line to allow good depth control andwhipstock face orientation.

The windows are milled with filtered, slickproduced water or seawater. Viscous pillshave been pumped to clean the metal debris,but downhole videos have shown that signif-icant amounts of metal cuttings remain in thewellbore. There is significant annular area,however, around the whipstock body toallow the metal cuttings to settle inside theliner, so the cuttings have not caused over-pull problems on any wells to date. The win-dows are usually milled in two runs. The firstmill opens up the nipple, which later servesas a reference point for depth control.

In 7-in. casing, the initial point of contact is3 ft down on the whipstock (previous page).The mill breaks through the casing and con-tacts the cement sheath 2 ft [0.6 m] later. Thelength of window is typically 6 ft [1.8 m]from this point, and the mill enters theformation. The initial BHA is normallypulled, and a second BHA is run with a pilotmill designed to drill formation. This BHAincludes a string reamer to dress off the win-dow and drills a pilot hole just far enough forthe reamer to clear the window (right).

Summer 1998 31

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Motor

Flexjoint

Startingmill

Watermelonmill

Flat facemill

Coil

MotorCoil

■Whipstock window-milling procedure. A 12-ft long through-tubing whipstock is first runand set with electric line in a directional well. The mechanical whipstock is permanentlyanchored in the well and orients toward the high side of the well. A flex-joint BHA opensthe window out of the casing, and a second, stiff BHA with a tungsten carbide mill thenopens a 3.8-in. by 6-ft long window through the casing. A key to developing and refiningthe operational procedure was the use of downhole video technology to inspect the vari-ous steps in the window-milling process.

cient crude is pumped to significantly reducethe hydrostatic pressure, perhaps becausethe crude increases lubricity or breaks adrilled solids filter cake. As weight-transferproblems become significant, the standardpractice is to displace the well with newdrilling fluid.

In addition to weight-transfer techniques,coiled tubing drilling requires special meth-ods or tools for orienting the BHA. Theindexing hydraulic orienter is used to makedirectional changes. The orienter is actuatedby bleeding off and then restoring coiledtubing pressure. Each cycle results in a preset toolface change of 20º. Small toolfacechanges can often be made by alteringweight on bit. The resulting change inreactive motor torque causes variations intoolface. To minimize drilled doglegs, direc-tional changes are made in 20º increments,when feasible, to correspond with orientercapabilities. If a dogleg or tight spot isobserved, the section is back reamed. Threepasses upward, typically at 60 to 120 ft/hr,are made with 120º toolface changesbetween each pass. Reaming while runningin the hole at slow rates is avoided to reducethe possibility of accidentally sidetracking.

Directional drilling with a conventionaldrilling rig is usually accomplished using a combination of rotating and sliding.Rotating results in straight hole, while sliding(not rotating the drillstring) creates a turn.With this technique, the turn rate of a par-ticular bent motor BHA can be controlled by drilling combinations of angle build and straight (tangent) sections. This combina-tion of sliding and rotating results in anaverage directional change over a giveninterval of hole. Directional changes in CTDjobs occur only by sliding because the drill-string cannot rotate.

Motor bend selection is critical for drillingthe build section. If the drilled build rateexceeds the target build rate, a series of S-shaped turns may be used to reduce theeffective build rate. If the resulting doglegsare projected to be severe enough to causeweight-transfer problems while drilling theremainder of the well, the motor is trippedand replaced. Motor selection while drillingthe horizontal section is less critical. Themost common CTD well types have shortbuild sections with longer horizontal sec-tions (left).

32 Oilfield Review

Drilling TechniquesBecause the CTD string is not rotated, holecleaning and weight-transfer benefitsattributed to pipe rotation are not realized.Effective hole cleaning and weight-transfertechniques for both cased and openholeoperations have been established, however.Many of the drilling mechanics and holecleaning problems experienced in earlywells have been reduced or eliminated withthe use of a low-solids polymer drilling fluid.

Satisfactory drill rates with coiled tubing orrotary drilling require adequate transfer ofweight to the bit. Conventional rotary drillingrelies primarily on BHA weight. For rotarydrilling of horizontal wells, weight is oftentransferred to the bit by placing a section ofheavy-weight drillpipe or drill collars in thedrillstring above the build section to push the lower end of the drillstring in the hori-zontal section. Drillstring rotation improvesweight transfer to the bit by reducing drag; it changes the direction of friction from dragto torque.

Weight transfer in CTD operations occursprimarily by pushing on the resilient coiledtubing drillstring in the horizontal section.Due to its smaller diameter, coiled tubing isless rigid than drillpipe, and helical bucklingand eventually lockup will occur as thecoiled tubing is increasingly compressed.Maximum weight on bit with coiled tubing isless than with rotary drilling in horizontalwells. Because of the small hole sizes, how-ever, the weight on bit in pounds per inch ofbit diameter is adequate, and high-speedmotors yield comparable penetration rates tothose of rotary drilling.

Cuttings beds, which accumulate aroundthe coiled tubing in deviated and horizontalhole sections, reduce weight transfer andcan result in differential sticking unlessremoved by frequent short trips. The combi-nation of mechanical agitation by the bit, jet-ting force at the nozzles and continuouscirculation of drilling fluid during short tripsmitigates the problem of cuttings bed accu-mulation. Short trips to the start of the buildsection or the casing window are performedafter 50 to 100 ft of new hole are drilled.Extended short trips to the tubing tail toremove cuttings from the large casing annu-lus above the window are made once per12-hour tour, or as necessary. Short trip ratesof 15 to 20 ft/min [4 to 6 m/min] whilepulling out of the hole are used to allow ade-quate agitation and cuttings sweep. Tripspeeds while returning to bottom are typi-cally 40 to 50 ft/min [12 to 15 m/min] toreduce the possibility of accidentally side-tracking. Drill rates in soft sands are normallylimited to 75 ft/hr [23 m/hr] to prevent rapidbuildup of a cuttings bed and to allow ade-quate hole cleaning.

The drilling fluid influences weight to bittransfer, particularly in the horizontal sec-tion. Weight transfer diminishes as the hori-zontal section is extended and the drillingfluid is spent. The coiled tubing and BHA,which move freely at normal tripping speeds,can become differentially stuck with a spentdrilling fluid at normal drill rates. Deadcrude oil is typically circulated into theopenhole to free the drillstring in stuck pipeconditions involving differential sticking. Thedrillstring is commonly freed before suffi-

������������������

Drilling fluid in coiled tubing

�Cement

Drilling fluid in liner

41/2-in. tubing

95/8-in. casing

Window in 7-in. liner

31/2-in. openhole

27/8-in. liner with spiral centralizers

13/4-in. coiled tubing

Whipstock

Original perforations Dart

Landing collar

Seal assembly

Stinger

Float

■Typical CTD well. A typical CTD well on the North Slope has a short build section and along horizontal section into the reservoir. The liner is made up in the derrick of the rig, runat the end of the coiled tubing string and cemented in place. The wells are then perfo-rated with coiled tubing-conveyed perforating guns.

Accurate depth control is important inhigh-build-rate directional calculations andcritical to successful window-milling opera-tions. Depth control with coiled tubing isaccomplished by first accurately locating aproduction string component of knowndepth, such as the tubing tail or profile nip-ple, and then marking or flagging the coiledtubing at surface. The BHA depth on subse-quent runs can be corrected to the flag point,independent of mechanical depth counterson surface. CTD operations use real-time,MWD gamma ray data for accurate depthcontrol. Gamma ray tie-in is obtained duringeach trip in the hole. Bit depth is correlatedto a baseline log, and a flag is then paintedon the coiled tubing at surface (right).

The use of gamma ray tie-in logs confirmsthe phenomenon of pipe stretch. The elonga-tion of the coiled tubing is determined by thedepth shift of the reference flag painted on thepipe. Up to 4 ft [1.2 m] of coiled tubingstretch is often measured for a 10,000-ft[3000-m] round trip using 2-in. diameter pipewith a 0.156-in. [4-mm] wall thickness. Thestretch probably reflects deformation of thecoiled tubing as it is bent over the coiled tub-ing gooseneck, straightened out by the injec-tor chains and then loaded axially.

Drilling FluidCritical fluid functions are to provide cut-tings transport and suspension in largeannuli, optimize pump pressure and flowrate, minimize stuck pipe, provide lubricitybetween the coil and wellbore, controlleakoff or fluid loss, minimize formationdamage, provide wellbore stability, allowaccurate MWD and logging data acquisition,and enhance cementing operations.

The rheologically engineered, solids-freedrill-in fluid was designed to address theunique challenges of CTD operations on theNorth Slope. Rheologically engineered fluidsexhibit viscoelastic, time-dependent proper-ties and are designed to have elevated lowshear-rate viscosity (LSRV). A high LSRV cor-relates with the drilling fluid’s capability tosuspend drilled solids, especially in the wideannulus between the coil and original casing.LSRV is measured at a shear rate of 0.06 sec-1

on a Brookfield viscometer (right). Thedrilling fluid contains five basic components:base liquid phase, biopolymer, lubricant, bio-cide and potassium hydroxide.

Summer 1998 33

400

800

1200

400 08001200160020002400

Original holeG-3

G-3A plan

8100

8300

8500

8700

8900

9100

200400600800100012001400160018002000 0

G-3

G-3A plan

True

ver

tical

dep

th s

ubse

a, ft

Departure, ft

Target

Distance west of surface location, ft

Dis

tanc

e so

uth

ofsu

rfac

e lo

catio

n, ft

■Complex well trajectory. The G-3A well is one of the longest wells drilled to date withcoiled tubing. The sidetrack was drilled 2725 ft [830 m] directly into a small targetarea. This well indicates the high degree of directional control now possible with coiledtubing drilling.

■Low shear-rate viscosity (LSRV) drilling fluid. High frictional pressure losses inside the coiland BHA limit the flow rate possible during CTD operations. The low flow rate leads to lowannular velocity for the fluid carrying drilled solids in the wide annulus between the coiledtubing and casing. The xanthan biopolymer drilling fluid used in CTD wells providesbetter particle suspension at these low flow rates than hydroxyethyl cellulose (HEC) poly-mer fluid. The measure of this property is low shear-rate viscosity, taken at a shear rate of0.06 sec -1 on a Brookfield viscometer.

0.01 0.1 1 10 100

0

10

20

30

401.5 ppb-xanthan

3.4-ppb HEC

3 6

Low Shear-Rate Viscosity

Visc

osity

, tho

usan

d c

p

Shear rate, sec-1LSRV

Fann viscometer rpm

“Solids free” does not mean the fluid never contains solids; rather, it means nosolids are added during preparation ormaintenance of the fluid. No particulatematter is used for either density or fluid-losscontrol. Obviously, some drilled solids willenter the fluid system, but aggressive solidsremoval minimizes their effect on fluidperformance. The solids-control programuses linear-motion shakers and a high-speedcentrifuge to keep the drilling fluid clean and maintain total solids concentration lessthan 1%. Once the solids content reaches1%, the system is diluted with fresh solids-free fluid.

The fluid relies on viscoelastic propertiesand elevated LSRV, not filter cake, to controlinvasion of filtrate into the formation, creatinga high differential pressure gradient. As fluidleaks off radially into the formation, the shear

34 Oilfield Review

A premium-grade, clarified xanthan gumproduces LSRV in the fluid. Clarified xanthanhas had bacterial residue from the manufac-turing process removed. Conventional rheo-logical properties can be adjusted atrelatively low polymer concentrations, butLSRV does not develop until a critical poly-mer concentration has been exceeded. AsLSRV is the last property to develop, it is alsothe first to degrade.

Conventional drilling experience hasshown that a 60,000 to 80,000 cp LSRV con-trols leakoff to permeable zones up to 5 D.Unfortunately, LSRV alone cannot controllosses to secondary permeability, such asfaults and fractures, which have been aproblem in Prudhoe Bay where wells havecrossed faults. Once a wellbore crosses afault, losses can range from simple seepage

to severe, depending on fault size. Lostreturns contribute to problems with holecleaning, well control, lubricity and stuckpipe. Conventional lost-circulation materialsare routinely pumped to attempt to controllosses. Different crosslinked polymer pillsand other ways of controlling these losses areunder investigation.

The typical brine concentration is 5% potassium chloride and 3% sodiumchloride, for a total chloride concentration of40,000 mg/L. This concentration optimizespolymer performance, provides adequatedensity at 8.8 ppg [1.06 sg] and achievesmore than a two-to-one potassium-to-sodium ion ratio for shale inhibition andformation protection. Potassium hydroxidemaintains pH around 9.0 to 9.5 to optimizepolymer performance and lower corrosionrates from the drilling fluid.

Downtime

Drilling time

Liner

Waiting on cement

Perforating

Rig up and rig down

Other

Hou

rs

0

50

100

150

200

250

Well 1 Well 2 Well 3 Well 4 Well 5 Well 6 Well 7 Well 8

■Total drilling time improvement. Throughout the CTD programs on the North Slope, the percentage of nonproductive time on the rigshas decreased steadily as the CTD learning curve progressed. The greatest improvements in time utilization were seen in the decreasein drilling time. These improvements resulted from a better understanding of the CTD process and improved equipment reliability. Onaverage, on-bottom drilling time accounts for 49% of the total well time, liner operations 9%, downtime 9%, perforating 7%, riggingup/down 7%, waiting on cement 5% and the rest miscellaneous activities.

rate decreases, and the viscosity prevents fur-ther penetration. Temperature, overbalancepressure, formation permeability and poros-ity, and formation fluid viscosity control thedepth of fluid penetration into the formation.

A gradual pressure gradient develops asdrilling fluid enters the formation, reducingthe potential for differentially stuck pipe,which is critical because there is no piperotation to minimize the chance of stuckpipe. The fluid invasion depth has not beenquantified yet, but well productivity has metor exceeded expectations, demonstrating thefluid’s nondamaging characteristics.

Minimal solids provide several benefits.Pump pressures remain low, improving coillife. Stuck-pipe potential drops if the fluidsystem has less than 1% solids. At greatersolids concentrations, a filter cake begins toform along with a greater differential pres-sure gradient. With lower solids content, thecoefficient of friction in the wellboredecreases, and lubricants function betterbecause of less solids surface area to coat.Plastic viscosity increases with increasingsolids content; a higher plastic viscosityresults in higher pump pressures and lowerpenetration rates.

OutlookCTD technology has proven to be a viabledrilling method in Prudhoe Bay, and opera-tors in Alaska are considering its expansioninto the nearby fields of Milne Point,Lisburne, Endicott and Kuparuk. CTD tech-niques are also used, but to a lesser extent,offshore in the Kenai fields of Alaska. BothBPX and ARCO are evaluating their AlaskanCTD experience for use in other fields world-wide. There is some concern that the uniqueoperational and reservoir conditions on theNorth Slope which have fostered CTD devel-opment may not necessarily be the case inother fields. Another issue is the high startupcost of CTD techniques, especially for one-well projects.

The success of through-tubing CTD jobshas spawned development of through-tubingrotary drilling (TTRD). TTRD is in its infancyand is an emerging technology that may pro-vide many of the same benefits as coiled tub-ing drilling. Both types of through-tubingdrilling offer the main economic benefits ofnot having to remove the production string.

CTD technology is maturing, as evidencedby the focus on improving operational effi-ciency (previous page). The current challengeto contractors is to provide incident-freeoperations while delivering 15% year-on-year cost reduction and achieving annualproduction targets (above).

In Alaska, there have been more problemswith downhole drilling tools during CTDoperations than during conventional rotarydrilling. These problems primarily stem fromthe smaller tools used. Service providersworking in Alaska are focusing on strength-ening these tools, while simultaneouslydeveloping the next generation of evensmaller tools for drilling through 31⁄2-in. com-pletion strings, using the same electronics asin larger tools.

The drilling engineer’s wish list is obvious:a desire for every tool and service availablefor conventional rotary drilling, only madesmaller and less expensive. Realistically,these advancements will take some time andthere will be many problems to solve duringdevelopment. Building bigger, stronger toolsis typically easier than building smaller ones.

The number of skeptics is fewer than in the early days of coiled tubing drilling.Although coiled tubing drilling will notreplace rotary drilling, some applicationsare particularly well-suited for CTD tech-niques. Of these, Prudhoe Bay is the biggestsuccess story. —KR

Wells will become increasing complex asPrudhoe Bay production continues todecline. The length of horizontal sectionsdrilled by coiled tubing will need toincrease. Operators expect to drill wells withmultilateral sections to tap even smallerpools of oil from a single surface site.

Several technical areas warrant furtherimprovements. Drilling fluids and hydraulicsare critical to operational efficiency. Thebiopolymer drilling fluid works adequately,yet there is much room for improvement. Thedrilling fluid wears out rapidly, but the exactcause is unknown. The used drilling fluidmust be replaced, as it typically lasts forabout 1000 ft (half a typical well). The nextgeneration of fluids will need to improvehole cleaning, thereby reducing wiper trips,and improve lubricity to allow better weighttransfer to the bit.

Equipment reliability has been a concernand will continue to be a focus for improve-ment. The goal is to decrease failures inMWD tools, injector heads, tubing andpumps. To that end, there has already beensignificant improvement. Downtime com-parisons between rotary rigs and CTD rigsare unfair, however, because rotary rigs typi-cally have built-in redundancy and backupsystems. Coiled tubing units have historicallybeen designed for compactness with onlyone of each critical item.

Summer 1998 35

Mill window18%

Drillbuild section

18%Drill

horizontal section13%

Logging6%

Run liner8%

Perforate10%

After rig down4%

Contingency10%

Beforerig up

6%Plug andabandon

7%

■Typical CTD cost distribution on the North Slope.