An Early Look at Coiled-Tubing Drilling- Disk 2 · downhole mud motors, wireline steering tools, a mechanical downhole orienting tool and 3 7/8-in. bits. An average buildup rate of

Mick AckersDenis DoremusSugar Land, Texas, USA

Ken NewmanMontrouge, France

nA coiled-tubingunit with diagramsof the injectorhead (left) andblowout preven-ters (center).

An Early Look at Coiled-Tubing Drilling

Interest in drilling slimhole wells with coiled tubing is high. So far, only a few experimental wells have been

drilled and many technological issues remain unresolved. But if these challenges are met, coiled-tubing

drilling could become the medium that finally delivers slimhole wells across the industry.

In this article, FSTS (Formation Selective TreatmentSystem), SideKick and CoilLIFE are marks of DowellSchlumberger. SLIM1 is a mark of Anadrill.For help in preparation of this article, thanks to BruceAdam, Dowell Schlumberger, Rosharon, Texas, USA.

1. For details of coiled-tubing hardware and its applica-tions to workover and logging:Ackert D, Beardsel M, Corrigan M and Newman K:“The Coiled Tubing Revolution,” Oilfield Review 1,no. 3 (October 1989): 4-16.

2. Littleton J: “Coiled Tubing Springs into HorizontalDrilling,” Petroleum Engineer International 2 (Febru-ary 1992): 20-22.

In recent years, workover and logging usingcoiled tubing has become increasinglywidespread (above ).1 During workoveroperations, coiled tubing has been usedsuccessfully to drill out cement plugs andremove scale—in most cases harder to drillthan formation. Now attention is focused oncoiled-tubing drilling as a technique todeliver cost-effective slimhole wells for bothexploration and production.2

Slimhole wells are normally defined ashaving at least 90% of their diameter lessthan 7 in. They are drilled using rotary rigsthat are much smaller than normalrigs—about 20% of their weight, requiringabout a quarter of the drillsite area. Overhalf of drilling costs depend on factorsother than drilling time, such as construct-

45

New wells Re-entry

Disposable exploration wells

Deviated development wells

Well deepening intonew producing zone

Horizontal extensioninto producing zone

Multiple radial drainholes

Straight holes

Lateral holes

Original

New

nPotential applica-tions for coiled-tub-ing drilling.

ing the drill pad and access roads, movingthe rig, and the cost of casing and consum-ables like mud.3 A coiled-tubing unit (CTU)is even smaller than a slimhole rig, is easierto mobilize and requires less equipmentand personnel. Its smaller site requirementleads to lower civil engineering costs. Thesmaller, quieter CTUs have a reduced envi-ronmental impact.

There are also particular benefits offeredby use of continuous tubing. It avoids theneed for connections, speeding up trip timesand increasing safety—many drill floor acci-dents and blowout/stuck-pipe incidentsoccur when drilling is stopped to make aconnection. CTUs have pressure controlequipment designed to allow the tubing tobe safely run in and out of live wells. Thestripper above the blowout preventers(BOPs) seals the annulus during drilling andtripping. This offers increased safety duringdrilling—similar to having a conventionalrig’s annular preventer closed all the time.This safety feature also facilitates underbal-anced drilling, in which drilling is carriedout while the well is flowing.

A range of different uses has been pro-posed for slim holes drilled by a CTU(right). So far, lateral production and verticalre-entry wells have been drilled. Theseexperimental wells were designed to provethat the technique can effectively meetdesign specifications.

Three re-entry horizontal production wellshave been drilled in the Austin chalk, Texas,USA, using 2-in. directionally-controlledcoiled tubing with 37/8-in. bits. In an effortto prove the efficacy of coiled-tubingdrilling for exploration, a vertical well wasdeepened in the Paris basin, France, using11/2-in. coiled tubing with 37/8-in. bits. Thiswas also a re-entry, but a new vertical wellis also planned.

This article reviews one of the Austinchalk wells and the Paris basin well. Then itwill look at the technological challengesarising from these experiences.

46

Lateral Re-Entry for ProductionLast year, Oryx Energy Company re-entereda vertical well in the Pearson field, Texas,USA, completed in Austin chalk. Horizontaldrilling in Austin chalk using mud com-monly encounters almost total lost circula-tion. To reduce mud losses, formation dam-age and costs, water is often used as drillingfluid. This decreases bottomhole hydrostaticpressure to less than formationpressure—underbalanced drilling. To com-bat annular pressure from formation flowduring drilling, conventional rigs use a rotat-ing stripping head or rotating BOPs to sealthe annulus. The wells are killed each timea trip is made.

By using a CTU, which has its annulussealed throughout drilling by the stripper,Oryx was able to run in and out of holewithout killing the well. This improved safety

3. Randolph S, Bosio J and Boyington B: “SlimholeDrilling: The Story So Far...” Oilfield Review 3, no. 3(July 1991): 46-54.

4. Ramos AB, Fahel RA, Chaffin M and Pulis KH: “Hori-zontal Slim-Hole Drilling With Coiled Tubing: AnOperator’s Experience,” paper IADC/SPE 23875, pre-sented at the 1992 IADC/SPE Annual Drilling Confer-ence, New Orleans, Louisiana, USA, February 18-21,1992.Wesson HR: “New Horizontal Drilling TechniquesUsing Coiled Tubing,” paper SPE 23951, presented atthe 1992 Permian Basin Oil and Gas Conference,Midland, Texas, USA, March 18-20, 1992.

and avoided the expense and potential dam-aging effects to the formation of pumpingbrines to kill the well prior to tripping.

To prepare the well, Oryx used a conven-tional service rig to remove the existingcompletion hardware, set a whipstock andsidetrack out of 41/2-in. casing at a true verti-cal depth of 5300 ft [1615 m]. Drilling wasthen continued using 2-in. coiled tubing,downhole mud motors, wireline steeringtools, a mechanical downhole orienting tooland 3 7/8-in. bits. An average buildup rate of15°/100 ft [15°/30 m] was achieved and ahorizontal section drilled for 1458 ft [444m].4 The main bottomhole assembly (BHA)components were:

Drillstring—Oryx employed a reel com-prising 10,050 ft [3060 m] of 2-in. outsidediameter coiled tubing with 5/16-in. mono-conductor cable installed inside the tubing.

Oilfield Review

5. Traonmilin E, Courteille JM, Bergerot JL, Reysset JLand Laffiche J: “First Field Trial of a Coiled Tubing forExploration Drilling,” paper IADC/SPE 23876, pre-sented at the IADC/SPE Annual Drilling Conference,New Orleans, Louisiana, USA, February 18-21,1992.Traonmilin E and Newman K: “Coiled Tubing Used forSlim Hole Re-entry,” Oil & Gas Journal 90 (February17, 1992): 45-51.

6. Ackert et al, reference 1.

Normal drilling60.9%

Waiting/repairs20.5%

Directional7.1%

Fishing11.5%

nFinal analysis of the Oryx well in Austin chalk, Texas, USA. With a steerable bottom-hole assembly, the horizontal section was drilled within its 50-ft vertical window.

5100

5300

5500

5700

5900

61000 400200 600 800 1000 1200 1400 1600 1800

Displacement, ft

True

ver

tical

dep

th, f

t

Coiled tubing and finalwell trajectory

Wireline connector

Downhole orienting sub

WhipstockDirectional survey tool

Check valve

Positive displacementmud motor

Fixed cutter bit

Tubing reel Power supply

Tubing injector

Bent sub

50 ft

Orientation tool—Because coiled tubingcannot be rotated from surface to alterdrilling direction, a downhole method ofchanging tool face orientation is needed. Toachieve this, Oryx deployed a mechanicaltool that converts tubing reciprocation intorotation—compression rotated the tool faceto the right, extension to the left. Onceadjusted, the tool face was locked in placeusing a minimum 250-psi differential pres-sure across the tool.

Directional survey tool—The survey toolinside a nonmagnetic collar relayed direc-tional information to surface via the wireline.

Directional BHA—Two assemblies wereused, depending on the build ratesrequired—a double-bend assembly consist-ing of a conventional 27/8-in. bent housingmud motor coupled to a single bent sub, ora steerable assembly comprising a single-bend motor.

Bit—Thermally stable diamond bits wereused to drill the curve and build sectionsand polycrystalline diamond compact(PDC) bits to drill the lateral section.

Oryx’s motive for drilling this well was toprove that coiled tubing could be used todrill a lateral well in a controlled manner.This was achieved—the final wellbore tra-jectory came within a 50-ft [15-m] verticalwindow along the horizontal section (above).

Because this well was the first of its kind,new techniques had to be developed, andmuch of the drilling equipment had to beadapted from existing conventional hard-

July 1992

ware. Orienting the tool face was not diffi-cult, but maintaining it was hard because ofthe unpredictable reaction of the coiled tub-ing to the torque generated by the drillingmotor’s rotation. Drilling was also slowedby failure of BHA components, particularlythe orienting and directional survey tools.

These difficulties affected the final costanalysis. Total cost was estimated by Oryxat twice that of using a conventionalrig—nondrilling time was responsible fornearly 40% of this (below). However, aspurpose-designed equipment becomesavailable and drilling procedures arerefined, coiled tubing should deliver morecost-effective, slimhole, lateral wells.

nCost breakdown for the first Oryx well.

Vertical Exploration WellLast year, Elf Aquitaine embarked on a seriesof trials to determine whether coiled tubingcould be used to drill slimhole wells, cuttingexploration drilling costs. The goal of thefirst well was to demonstrate that a CTU candrill a vertical well sufficiently fast, cut coresand test formations. Elf envisions initiallydrilling these slimhole wells with a singleopenhole section—avoiding the need forcasing—with the surface casings set usinglow-cost, water well rigs.

This first trial involved the re-entry of wellSaint Firmin 13 in the Paris basin.5 The planwas to use the CTU to set cement plugsacross the existing perforations at 2120 ft[646 m] and then drill a 2105-ft [642-m]vertical section of 37/8-in. diameter. Direc-tional measurements using a coiled-tubing-conveyed survey were to be taken every500 ft [150 m]. Then a 50-ft interval was tobe cored and logged. Finally, a zone was tobe flow tested by measuring pressurebetween two straddle packers.6

The trial was carried out by DowellSchlumberger using a trailer-mounted CTUwith a reel of about 6000 ft [1830 m] of11/2-in. tubing. To avoid the need for costlymodifications, standard surface hardware,like injector head with stripper and BOPstack, were used. A workover rig substruc-ture was installed over the existing wellheadto act as a work platform.

The operation encountered difficulties atthe outset—not with the drilling but with theintegrity of the well’s 30-year-old casing.After cement plugs were set, the well wouldnot hold the 360 psi above hydrostatic pres-sure required to withstand the anticipatedformation pressures. Because of this, drillingdepth was limited to 2955 ft [901 m] whichallowed limestone coring but did not extendto a high-pressure aquifer.

The drilling BHAs employed a high-speed, low-torque motor with PDC bits. Forcoring, a high-torque motor was used. Thedrilling and coring assemblies were made tohang vertically by incorporating heavy drillcollars into the BHA, creating a pendulumassembly. At the start, the deviation at thecasing shoe was 2° and, as expected, theBHA did not build angle—at 2362 ft and2795 ft [720 m and 852 m], the deviationangles were 23/4° and 21/4° respectively.During drilling, the rates were comparableto those drilled by conventional rigs at workin the area. This showed that a CTU candrill vertical wells at commercial rates. Twocores were cut and retrieved with goodrecovery—meeting the second objective ofthe trial.

47

Packer

Formation tobe tested

Packer

FSTS setting tool

nThe FSTS Formation Selective TreatmentSystem. The coiled-tubing conveyed FSTSstraddle packers were set across the for-mation to allow reservoir fluids to flow,proving that drillstem tests can be carriedout using coiled tubing.

Blind rams

Shear rams

Slip rams

Pipe rams

Kill line Choke line

Wellhead, casing or christmas tree

Annular preventer

Injector head

Stripper

Drill floor

Mud returns

BOP stack 41/16 in. 10,000 psi

nBlowout preven-ter configurationfor a well drilledwith a hole sizeless than 4-in.diameter.

Because the program had to be revised toavoid high-pressure zones, no oil-bearingformation could be tested. To prove the test-ing technology and meet the third objective,a drawdown test was carried out on a zonebetween 2221 ft and 2231 ft [677 m and680 m]. The FSTS Formation Selective Treat-ment System was deployed with its twopackers straddling this zone. The formationwas successfully isolated and, if it had beena reservoir, would have produced into thecoiled tubing (above).

48

Looking to the FutureIn addition to proving that coiled tubing canbe used to drill wells, the trial pointed outhow procedures could be changed andwhere future hardware development isrequired. For example, rate of drilling couldbe increased by incorporation of measure-ment-while-drilling tools to make direc-tional surveys, improving surface handlingand weight-on-bit (WOB) control tech-niques and better optimization of the BHA.

To address these issues, Dowell Schlum-berger has assembled a multidisciplinarytask force with Sedco Forex and Anadrill. Itswide-ranging agenda covers equipmentneeds, operational and safety procedures,tubing limits and personnel requirements.

Equipment needs—The Elf job utilized aworkover rig substructure. In the future, apurpose-built substructure will be employed.Standing 10 ft [3 m] off the ground and overthe wellhead, this substructure will act asthe drill floor to make or break the BHA andalso to support the injector head.

The BOPs will be mounted below theinjector head directly on top of the well-head, casing or christmas tree. If the holediameter is less than 4 in. [10 cm], 4 1/16-in.,10,000 psi coiled-tubing BOPs will be used.If the hole is larger, a standard set of 71/16-in., 5000 psi drilling BOPs will be usedinstead. In both cases an annular preventerwill also be incorporated into the stack(below and next page, left).

In the directional wells drilled so far usingcoiled tubing, BHA direction has beenaltered using reciprocation of an orientingtool. This technique has the dual disadvan-tages of interrupting drilling and requiringmanipulation with pressure in the tubing,which has a severe fatiguing effect. The taskforce has therefore designed BHAs thatincorporate an orienting tool controlled byusing mud flow rate.

Directional information can be sent tosurface either using wireline or mud-pulsetelemetry. Wireline offers real-time transmis-sion of high volumes of information. How-

Oilfield Review

Ground

BHA straight hole

BHA for buildup and

horizontal sections

Connector

Check valve assembly

Pressuredisconnect

Orienting tool

Coiled tubing

SLIM1 MWDin nonmagnetic

drill collar

Mud motor

Adjustablebent housing

Mud motor

Drill collars

ever, having wireline in the tubing requiresa high level of maintenance and cuts downpumping options—like acidization treat-ments. To avoid the need for a cable link,the task force has adapted Anadrill’s SLIM1measurement-while-drilling system—whichuses mud pulse telemetry—so that it fitsinside a 31/16-in. diameter nonmagnetic drillcollar (right).

The chemistry of muds used when drillingwith a CTU is not expected to be signifi-cantly different from muds used in conven-tional wells. However, the technique doeshave some special rheological require-ments. In a re-entry well, the coiled tub-ing /casing annulus may be relativelylarge—perhaps 2 in. inside 7 in.—slowingthe annular velocity of the fluid and possi-bly compromising the cuttings-carryingcapacity of the mud. Further, because thefluid is pumped through small-diameter tub-ing, friction must be kept to a minimum byusing low solids muds with low viscositiesand yield points. To mix and treat drilling

nBlowout preven-ter configurationfor a well drilledwith a hole sizegreater than 4-in.diameter.

nStraight hole and buildup/horizontalbottomhole assemblies (BHAs). In both,fullbore check valves prevent backflow tosurface. The pressure disconnect suballows recovery of the coiled-tubing stringif the BHA gets stuck. A ball is droppedand pumped through the tubing until itseats in the disconnect sub. Internal tub-ing pressure is then applied that shearspins in the sub and releases the string.

The straight hole BHA includes drill col-lars, so that the string acts as a pendulumand tends to the vertical. Buildup andhorizontal BHAs include an adjustablebent housing to facilitate deviateddrilling. The housing angle is fixed at sur-face before the BHA is run, and its effecton the drilling angle is controlled byusing the orienting tool to rotate the toolface. Progress is monitored by the SLIM1MWD tool, which relays the information tosurface via mud pulses.

A CTU employs a low WOB, 2000 lb[900 kg] compared to 4000 to 6000 lb[1800 to 2700 kg] for conventional slim-hole drilling. So high-speed—700 rpm—low-torque drilling motors are expected tobe most effective. Polycrystalline diamondcompact or thermally stable bits are used.

Injector head

Stripper

Drill floor

Ground

ChokeKill

Mud returns

Annular preventer

Blind rams

Shear rams

BOP Stack 71/16 in. 5000 psi

Wellhead, casingor christmas tree

49July 1992

fluid, a trailer-mounted pumping and treat-ment unit has been constructed.

In a vertical hole, the setdown weightread at surface is equivalent to the WOB.However at high angles, the tubing com-presses inside the wellbore. If too muchweight is set down, the tubing may lockagainst the walls of the well, failing to trans-fer any further weight to the bit.7

Experience from the Paris basin wellshowed that while manual control of set-down weight was possible, it was tediousand required absolute concentration fromthe operator. To improve drilling efficiency,the CTU has been fitted with a system thatautomatically maintains a setdown weight.With this autodrilling system, the operatorcan monitor progress without having tomake continual minute weight changes.

The task force is reviewing three otherareas of equipment development underreview. All involve handling tubulars:removing the existing production tubing inre-entry wells, deploying the BHA into alive well, and running casing.

Operational and safety procedures—Procedures for controlling a slimhole wellwhen drilling with a CTU differ from thoseneeded when drilling with a conventionalslimhole rig. At the heart of this is the differ-ence in annuli. Conventional slimholewells have a narrow annulus and the mudtraveling up it creates a back pressure,called the equivalent circulating density(ECD). The ECD increases with pump rateand raises bottomhole hydrostatic pressure.This provides the option of dynamickill—increasing the rate to increase thepressure—but also a potential disadvantageof losing mud due to ECD exceeding theformation fracture gradient.

nComparison of gas kicks in 5000-ft wellsdrilled using coiled-tubing and conven-tional methods with 3 1/8-in. and 61/2-in.BHAs, respectively. SideKick software wasused to compare the effects of influxesthat gave similar annular heights. In bothcases, the driller’s method was used to cir-culate out the kick, during which casingshoe pressures were about the same.Because of its smaller annular volume,the well being drilled by CTU experi-enced much smaller pit gains.

wells (left). But in modeling an influx of 7.5barrels in the slim and conventional annuli,the SICP and CSP in the coiled-tubing wellwere much higher—double or more.

Therefore, early detection of gas influxesduring coiled-tubing drilling is vital. TheCTU’s stripper seals the annulus and ensuresthat the mud return line is full, improvingthe reliability of delta flow measurements—the difference between mud flow rate in andout of the well. Delta flow is measurabledown to 10 gal/min [0.8 liter/sec], permit-ting rapid detection of kicks after allowingfor the volume increase due to cuttings. Inthe mud pits, resolution of conventionallevel sensors is improved by having mudtanks with a smaller base area than is normal.

All drilling operations are subject to safetyregulations limiting operational equipmentto zones—in Europe, Zone I allows only themost stringent explosion-proof equipment,Zone II the next most, and so on. Ironically,the compactness of a CTU complicatescompliance with these regulations.

In the Paris basin well, the Zone II classifi-cation was specially reduced by the authori-ties from a 100-ft to a 50-ft radius from thewellhead. If the radius had been any larger,it would have extended the zone’s require-ments to the cars on the edge of the lease(next page). Changes in local regulationsand in equipment classification may berequired in the future.

Tubing limits—Coiled tubing had a slowstart as a workover service because of unre-liability and propensity for unpredicted fail-ure. To combat this, Dowell Schlumbergerhas developed a better understanding of thefactors governing tubing fatigue; this is nowbeing applied to drilling operations.9Repeated use of coiled tubing has threetypes of limitation:

50 Oilfield Review

7. Ackert et al, reference 1.8. White D and Lowe C: “Advances in Well Control

Training and Practice,” paper, presented at the ThirdAnnual IADC European Well Control Conference,Noordwijkerhout, The Netherlands, June 2-4, 1992.

9. Newman KR: “Coiled-Tubing Pressure and TensionLimits,” paper SPE 23131, presented at the OffshoreEurope Conference, Aberdeen, Scotland, September3-6, 1991.

10. Newman KR and Newburn DA: “Coiled-Tubing-LifeModeling,” paper SPE 22820, presented at the 66thSPE Annual Technical Conference and Exhibition,Dallas, Texas, USA, October 6-9, 1991.Newman K: “Determining the Working Life of aCoiled Tubing String,” Offshore 51 (December1991): 31-32, 34-36.

25

40 80

15

Pit

gain

, bbl

Time, min

Coiled tubingConventional drilling

5

110 130

600

800

1000

Cas

ing

shoe

pre

ssur

e, p

si0

When drilled with a CTU, the annulus islarger—particularly in re-entry wells—ECDis not a factor and dynamic kill cannot beapplied. To evaluate other well-kill strate-gies, the task force used SideKick softwareto model gas influxes in a full size wellbeing drilled conventionally and a slimholewell being drilled by a CTU.8

The SideKick model was used to assessthe significance of the volume of influx.First, it modeled influxes that gave compara-ble heights of gas in conventional andcoiled-tubing annuli (about 7.5 and 3 bar-rels, respectively). The shut-in casing pres-sure (SICP) at surface and the casing shoepressure (CSP) were broadly similar in both

• Pressure and tension limits—the burst andcollapse pressures and the maximum ten-sion and compression at various pres-sures. These are analogous to the limitsexperienced by drillpipe and can be cal-culated through tests and carefullyavoided during operations.

• Diameter and ovality limits—the degreeto which the pipe is collapsed, balloonedor mechanically damaged. This also hasan analogy in drillpipe where damagedpipe and couplings have to be detected.With coiled tubing, the physical shape ofthe tubing can be continuously monitoredduring the job to detect damage.

• Life limits—primarily due to bending inthe pipe at the gooseneck and on the reelas it is spooled on and off, often with thetubing pressured. Anticipating life limits oftubing has proved difficult, but is vital toavoid catastrophic failure. At its crudest,the fatigue of a reel of tubing can beequated to the number of times it is runinto and out of the well—termed cycles.

After extensive research, Dowell Schlumber-ger has developed a way of assessing coiled-

tubing fatigue that is more sophisticated thansimply counting cycles—the CoilLIFEmodel.10 During jobs, all tubing movementand pressures are monitored and recorded.The CoilLIFE software then calculates theamount of life remaining in the string. Ittakes into account the relative severity ofeach cycle, the nature of the fluids that havebeen pumped and the sequence in whichthe cycle occurred—which affects the accu-mulated damage.

Personnel requirements—The number ofpersonnel required for coiled-tubing drillingis likely to be about 50% of that needed forconventional operations. Not only are day-to-day operational requirements lower, butthe number of service personnel can also bereduced. For example, when running cas-ing, the mud system could be employed tomix and pump cement—eliminating theneed for a cementing engineer. All thedrilling information, along with basic mudlogging data and general surface data, willbe centralized in a computerized informa-tion system, eliminating the need for a full-time mud logger. —CF

nLayout of Elf’scoiled-tubingdrilling site in theParis basin,France.

51July 1992

Portakabin Portakabin

Access road

CT unitGen

erat

or

Cat

frac

unit

back

up p

ump

Bin Bin Bin

Substructure

Crane truck

Mud productsstorage area

Tool rack

50 ft safety perimeter

Water tank

Mud treatment/pumping unit

Fuel tank

Chokemanifold