Coiled Oil

Coiled for oil

In recent years technologicaldevelopments, improved service reliabilityand increasing tubing diameters havecombined to make coiled tubing apreferred technique for many oilfieldapplications in the Middle East. Coiledtubing offers numerous new possibilitiesfor oilfield management. It can, forexample, be used to drill slimhole wells,deploy reeled completions, log high-angleboreholes and deliver treatment fluids.

Coiled tubing has a wide range of potentialapplications, but it is in drilling that thistechnology offers the greatest scope forefficient field management. CTD* coiledtubing drilling operations provide cost-effective placement of a wellbore in areservoir with minimal formation damage,using continuous pipe technology.

David Stein explores the range of CTDtasks and provides examples of successfuloperations conducted in the Middle East.

Num

ber

ofw

ells

dril

led

with

CT

Year

0

70

50

40

30

20

10

1991

1992

1993

1994

1995

1996

1997

60

��

��

��

��yyyyyyyyyyyyyyy

zzzzzzzzzzzzzzz

{{{{{{{{{{{{{{{

|||||||||||||||

Steered

Nonsteered

Num

ber

ofw

ells

dril

led

with

CT

Year

0

500

600

400

300

200

100

1991

1992

1993

1994

1995

1996

1997

��

��

��

��

yyyyyyyyyyyyyyy

zzzzzzzzzzzzzzz

{{{{{{{{{{{{{{{

|||||||||||||||Steered

Nonsteered

Figure 4.1 Around the world, the number of wells

drilled with coiled tubing has risen steadily throughout

the 1990s (top). The growth in Schlumberger CTD

operations (bottom) has mirrored the global trend

36

Nu

mb

er 2

1, 1

99

8

M i d d l e E a s t We l l E v a l u a t i o n R e v i e w

Most people think of coiled tubing(CT) as a tool for well workoveroperations, for example, for

cleaning, removing sand, acidizing orlogging. However, recent improvements inCT technology and the industry’s continu-ing drive towards cost-effective operationshave opened up new areas of CT oper-ation. CTD coiled tubing drilling has foundan important niche in the world drillingmarket and new technology is continuallyhelping to extend the range of applications.

The first steps in CTD techniques weretaken in the 1970s. These experimentaldrilling operations had mixed results andseveral technological advances wererequired to make the technique effectiveand commercial. Advances in metallurgymade it possible to spool and unspool thetubing repeatedly without causing excess-ive metal fatigue. The development oflarger diameter tubing with greaterstrength and improved reliability, and theintroduction of smaller diameter, positivedisplacement downhole motors, orientingtools and survey systems, all contributed tothe success of coiled tubing drilling.

Reliable commercial CTD operationsstarted in the early 1990s. By the mid-1990s several hundred CTD jobs, con-ducted with (steered) or without(nonsteered) geosteering techniques,were being carried out around the globeand the jobs performed by Schlumbergerreflect that trend (Figure 4.1). Initially,most of the jobs performed with CT wererelatively straightforward injection orshallow gas-relief wells. In recent yearsCT jobs have become more complex: thetechnique can be used to drill entire wellsor multilaterals to several targets.

New software can predict a range ofparameters that affect CT operations.These include available weight on the bit,expected pump pressure, wel lborehydraulics and lock-up conditions, whichare vital for determining the feasibility ofthe project.

Applications of coiled tubingdrilling

New shallow wells

CT units can be used to drill shallow wells(typically 5000–6000 ft) with diameters ofup to 8 1⁄2 inches. In some soft formationsthe hole size may reach 13 inches, but thecasing will be restricted by the small size ofthe surface hole.

Coiled tubing is often used to dri l lslimhole wells with diameters of 5 inchesor less. These wells offer good economicand environmental performance, requireless consumable materials for completionand produce less waste. Compared to con-ventional rigs, slimhole drilling setups candeliver wells with fewer people on muchsmaller sites. This cuts site preparationcosts, reduces the environmental impact ofonshore drilling operations and reduces thevessel size and space requirements for off-shore applications.

Conventional reentry

Deepening and sidetracking existing wellsaccount for most of the jobs conducted inthe conventional reentry sector, and CTdrilling is suitable for some of these oper-ations. Conventional reentry involves pullingthe production string and drilling the welloverbalanced or underbalanced. For under-balanced drilling a lightweight or aeratedfluid is needed, because any gas-lift man-drels were removed with the completion.These wells are very sensitive to the well-bore configurations with respect to tubingforces and underbalance parameters. Whenpassing through large diameter casing, theweight transfer downhole is severelyreduced and, when an aerated fluid is used,slugging effects make it difficult to obtain asteady downhole pressure.

37

Nu

mb

er 2

1, 1

99

8


For sidetrack wells a whipstock is set atthe kickoff depth and a window is milled inthe casing. Coiled tubing can provide wellsup to 6 1⁄2 inches in diameter with build ratesup to 30°/100 ft. For horizontal sidetracksthe drainhole length, which is usuallylimited by the required weight on the bit,may reach 4000 ft.

CTD units compete for these jobsagainst conventional rotary drilling rigs. Lowmobilization costs and shorter mobilizationperiods make CTD jobs economicallyattractive for reentry work compared withconventional drilling units. Benefits such asunderbalance drilling, lower productioncost, reduced stimulation costs, and manyothers, make coiled tubing dril l ing anattractive alternative to conventional drilling.

Through-tubing reentry

The greatest technical and economicsuccesses for coiled tubing drilling havebeen in through-tubing reentry operations.The popularity of CT for this applicationreflects the improved safety and efficiencythat it provides. Through-tubing reentriesare typically drilled to deepen or sidetrack awell and are performed without removingproduction tubing (see box: Through themill). These projects suit CTD methodsbecause no additional surface equipment isneeded to pull the tubing. A CT unit canmove in to the wellsite, rig up and begindrilling within a few hours. This rapid rig-upcapability is especially attractive in offshoreand inaccessible locations where drilling andworkover rigs have higher day rates.

When combined with the benefits ofunderbalanced drilling methods, through-tubing reentry drilling projects can provideenormous cost-efficiencies for an operator.

Technical evaluationThe first step in technical evaluation for aCTD operation is to determine how big ahole is required. In through-tubing re-entries, the hole size is limited by the inter-nal diameter of the current completion. Innew wells and conventional reentries thedetermination depends on the reservoirparameters and the minimum restriction ofthe wellbore. For example, it would not besensible to drill a 10,000-ft lateral sectionusing a 2 3⁄4- inch bit, nor would it bebeneficial to drill a 2000-ft lateral sectionusing a 8 1⁄2-inch bit when there is 3 1⁄2-inchtubing in the well.

The hole size will dictate the requiredweight on the bit, the size of motor to turnthe bit, the flow rate to clean the hole andthe size of the coiled tubing. There aremany inter-related variables that affectCTD performance (Figure 4.2). Typicallythe technical evaluation will be determinedin the following order:• determine the reservoir targets• determine the hole size based on the

reservoir and flow rates• determine the trajectories and the point

and method of kicking off• based on the hole size and wellbore

configuration, determine if thecompletion can remain in place

• determine the drilling method—overbalanced or underbalanced

• determine the type of drilling fluid—oil-base mud, water-base mud, crudes,nitrogen

• outline the equipment requirements—motor size, type of directional tools, etc

• determine the flow rates required forgood hole cleaning within the limitationsof the downhole equipment

• determine the CT size based on thecirculation pressures, reach and pullingcapacities

• refine the process• outline the surface equipment needed

The technical feasibility is the deter-mination of the cause and effect relationshipbetween the independent and dependentvariables which must be considered, par-t icularly when mult iphase f luids areinvolved. Topics such as hole cleaning,weight on-bit and wellbore geometry arestudied for their effects on drilling perform-ance. Computer modeling and simulationsare powerful tools to complete the study.

Coiled tubing drillingtechniqueCoiled tubing does not rotate, so holecleaning and weight transfer benefitsattributed to pipe rotation are not real-ized when dril l ing with coiled tubing.Conventional drilling practices have beenrefined to provide effective hole cleaningand weight transfer techniques for casedand openhole operations. Many of thedri l l ing mechanics and hole c leaningproblems encountered in early wells canbe eliminated with the use of low-solidsmuds or underbalanced drilling.

Figure 4.2 CTD variables (motor performance, rate of penetration, etc) are

influenced by independent variables (liquid flow rate, hole size, etc) as shown

��yyyyyzzzzzz{{{{{||||||

��

��


zzzzzzzzzzzzzzzzzz

{{{{{{{{{{||||||||||||��yyyyyzzzzzz{{{{{||||||

��

��


zzzzzzzzzzzzzzzzzz

{{{{{{{{{{||||||||||||

Motor performance

Rate of penetration

Hole cleaning

Bottomhole pressure

Wellbore stability

Cost

Formation damage

Pump pressure

Weight on the bit

X

X

X

X

X

X

X

X

X

1CTD variables

1 Liquid flow rate

2 Gas flow rate

3 Foamed versus nonfoamed fluid

4 Liquid phase type/additives

5 Hole size

6 Casing geometry (size weight)

7 Motor configuration

8 Bit type

9 String weight (hook load)

10 Build rates/doglegs

11 CT size/weight/grade

2 3 4 5 6

Independent variables

7 8 9 10 11

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

��yyyyyzzzzzz{{{{{||||||

��

��

��


zzzzzzzzzzzzzzzzzz

{{{{{{{{{{{{{{{

||||||||||||||||||

Conventional drilling rig

• Disruption of flow when making connections and during tripping

• Downhole pressure fluctuations

• Surface pressures limited to 1500 psi

• Long connection and trip times

Coiled tubing drilling

• Safe option: no personnel required at wellhead during drilling or tripping

• Reduced downhole pressure fluctuations

• Reduced trip times

• Bottomhole assembly can be deployed in a live well

• Internal wireline can be installed for real-time measurement

Underbalanced drilling

Figure 4.3 For underbalanced drilling operations the CTD method is a safer and less

expensive option than conventional rotary drilling methods

Through the millOne of the most attractive markets forCTD jobs is through-tubing reentry wells.One reason for this is that the CTD tech-nique provides a very successful methodfor exit ing the wellbore. Most of thegrowth in reentry drilling was made poss-ible by the rapid developments in whip-stock and cement milling techniques. Theseinnovations are the results of extensivetesting to select the proper equipment andrefine the technique.

Whipstock, or window, milling involvescutting a hole or ‘window’ in the casingand/or tubing with a downhole motor andmill. The mills are nonaggressive to reducemotor stalling and create a smooth exitpath through the tubulars. As the windowmilling progresses, the metal cuttings areweighed at surface. Typically 50–80% ofthe theoretical weight of metal is recoveredat surface (Figure 4A.1). This will give anindication when problems occur. Also,traces of cement and formation solids willstart appearing in the returns as theassembly moves out of the tubular.

In Alaska, Arco completed more than 65reentry sidetracks at 50–75% of the cost ofdrilling a new well. The company docu-mented its drilling program and analyzed per-formance in detail. This careful analysis led toa 25% reduction in total sidetracking time.

Wells included in the program weretypically constructed with 13 3⁄8-inch surfacecasing, 9 5⁄8-inch intermediate (production)casing, 7-inch production liner and 4 1⁄2- or5 1⁄2-inch tubing. A 9 5⁄8-inch permanentpacker was typically set just above the7-inch liner with an optional isolation packerin the liner.

The kickoff method used in Alaska con-sisted of setting a fiber-reinforced cementplug below the tailpipe and inside the 7- or9 5⁄8-inch casing. A pilot hole was drilled intothe cement plug. Initially the hole wasoriented to the low side for approximately15 ft. After drilling with the low-side setting,the tool was oriented to the high side inorder to build up angle before contactingthe opposite casing wall. The hole path givesthe highest contact angle between thebottomhole assembly and casing wall, whichincreases the success of milling through thecasing. If the angle is not high enough themilling assembly will slide down the casingwall without exiting. Once the mill contactsthe casing wall a time drilling process starts.The time drilling process allows the mill togradually cut into the casing without rollingoff the path (Figure 4A.2).

38

Nu

mb

er 2

1, 1

99

8


Satisfactory drilling rates with coiledtubing or rotary drilling require adequatetransfer of weight to the bit. Conventionalrotary drilling relies primarily on the use ofdrill collars, sometimes located in the ver-tical sections for horizontal wells, to supplyweight to the bit. Rotation of the drillstringimproves weight to the bit by reducing theeffective wall contact friction. This followsthe classical friction theory; the friction forcevector opposes the direction of theresulting velocity vector. Weight transfer forcoiled tubing dri l l ing is accomplishedprimarily by pushing on the resilient coiledtubing string in the horizontal sections.Coiled tubing is less rigid than drillpipe andhelical buckling and eventually ‘lock-up’ willoccur as the coiled tubing compressiveforce is increased. Only a small percentageof string weight can be transferred to thebit, because of the high coefficient offriction associated with slide drilling: frictionfactors can be in the range 0.40–0.65,compared with factors of less than 0.10 inrotary drilling.

Cutting beds reduce weight transfer andcan result in differential sticking. Frequentshort trips are used to remove cuttingbeds which accumulate around the coiledtubing in deviated and horizontal sections.Short trips to the start of the build sectionor the casing window are performed aftereach 50–100 ft of new hole. Extendedshort trips to the tubing tail to removecuttings from the large casing are some-times needed for through-tubing appli-cations where the hole size increases inthe casing. The maximum flow rate avail-able for hole cleaning with CT is limited bythe pressure at the surface and the flowrate l imitat ion of the downholemotor/bottomhole assembly (BHA).

Perfectly underbalanced

In underbalanced drilling wellbore pressureis lower than the pressure of the formationbeing drilled. This induces a continuousflow of formation fluids into the hole asdri l l ing progresses and minimizes oreliminates formation damage. Reduceddamage can increase production, provideearlier payout and lower well stimulationcosts, compared with overbalanced wells.

The most important part of an underbal-anced CTD campaign is candidaterecognit ion. The selection process istypically performed by the client in con-junction with specialist teams. Once thecandidate wells have been chosen, a rangeof Schlumberger service providers can bebrought together to pool their expertiseand execute the integrated project. Onlycomputer modeling can handle all of thevariables that the driller will encounter inunderbalanced coiled tubing drilling.

Underbalanced drilling can also help toimprove drilling performance by increasingrate of penetration, eliminating severe lostcirculation and preventing dif ferentialst icking. It is part icularly suitable forhorizontal wells where the pay zone isexposed to drilling operations for longperiods of time.

Although underbalanced drilling jobs canbe conducted with jointed pipe systems,such as snubbing units, they are safer andmore efficient when CT methods areemployed (Figure 4.3). CT is a continuousconduit with no external connections andthis offers a safer underbalanced packagethan conventional drill ing rigs. Under-balanced coiled tubing dril l ing allowsgeoscientists to assess the productivity ofeach section as it is drilled.

��yyzzz{{|||

��

��

��

��yyyyyy

zzzzzzzzz

{{{{{{

|||||||||WL

BD

Tcsg

Ttbg

Ø

Figure 4A.1 The first step in drilling lateral boreholes from existing vertical wells is

to mill a hole or ‘window’ through the casing in the vertical well before a whipstock

is run into the hole to guide the drill bit out of the vertical well. Precision milling can

be a complex and time-consuming process but it is essential for many CTD

operations. The quantity of metal milled can be estimated using a simple formula

(below). This estimate is compared with the total weight of metal returned to

surface by mud circulation

Figure 4A.2 Whipstock (window) drilling��

��

��

��

yyyyyyyyyyyyyyyyyyyyyyyy

zzzzzzzzzzzzzzzzzzzzzzzz

{{{{{{{{{{{{{{{{{{{{{

|||||||||||||||||||||��yyyzzz{{{|||

��

��

��

��

yyyyyyyy

zzzz

{{{{{{{{

|||| Exit production

tubing

Fiber cementplug

Casing

Formation

Kickoff depth(start time drilling)

Squeezed off perforations

��

��

��

��

yyyyyyyyyyyyyyy

zzzzzzzzzzzzzzz

{{{{{{{{{{{{{{{{{{

||||||||||||||||||��yyyzzz

ø : angle of whipstock

WL : window length

Tcsg : casing thickness

Ttbg : tubing thickess

BD : bit diameter

Den : steel density

Values

ø = 2.5¡

WL = 2a

Tcsg = 0.937 inches

Ttbg = 0.542 inches

BD = 3.75 inches

Den = 0.284 lb/inch3

a = (BD/2)/sinø = 42.99 inches

b = BD/2 = 1.875 inches

Area of hole(parabolic) = (4/3)ab

= 107.46 inches2

Volume of metal:

Wt = (Tcsg + Ttbg ) x (2 x area) x Den

= 90 lb

39

Nu

mb

er 2

1, 1

99

8


Over and under in Oman

A recent CTD campaign in Oman involveddrilling 15 onshore wells for PetroleumDevelopment Oman (PDO) (Figures 4.4and 4.5). The campaign was divided intotwo parts:• overbalanced reentries where the

completion had been removed• underbalanced through-tubing drilling

40

Nu

mb

er 2

1, 1

99

8


Figure 4.5 General view

of a CTD drilling site,

Oman

Figure 4.4 Separation

equipment for an

underbalanced drilling

operation, Oman

In the 11 wells that comprised the over-balanced reentry operation, the completionwas pulled out of the well before settingthe whipstock. Once the whipstock hadbeen set, a window was milled through the7-inch or 9 5⁄8-inch casing where a 6 1⁄8-inchbuildup section was drilled. After landingthe buildup section, a 4 1⁄2-inch liner was runwith coiled tubing and cemented in place.The lateral was then drilled with a 3 3⁄4-inchbit and completed barefoot.

After completing 11 overbalanced wells,the remaining four in the campaign werecompleted underbalanced. These wellstook advantage of the through-tubingapplication, passing through 4 1⁄4-inch tubingcontaining gas-lift mandrels. The gas-liftmandrels were used to achieve the under-balanced condit ions. The wells wereallowed to flow throughout the entireoperation, including installation and removalof the BHA from the live well. This was

Figure 4.6 Pressure-deploying the drilling assembly. The crane is

holding the lubricator containing the bottomhole assembly

41

Nu

mb

er 2

1, 1

99

8


accomplished by the use of a deploymentlubricator. The deployment lubricator wasapproximately 70 ft in length, sufficient tocover all of the BHAs (Figure 4.6).

The drilling performance in the underbal-anced wells substantially improved com-pared to the previous overbalanced wells.Overall, the benefits from the underbal-anced drilling campaign included:• a rate of penetration (300 ft/hour) that

was 10 times faster than in wells drilledwith overbalance

• improved hole cleaning; fewer andshorter wiper trips

• more weight transferred to the bit• continuous well flow during the

operations• low circulation pressure• improved coiled tubing life (lower

circulation pressure, fewer short trips)

Fateh laterals

This well was originally completed to pro-duce oil from a lower formation. When thewell had to be permanently shut in as a resultof high water cut, the managers decided tosidetrack it. This involved drilling a 3 3⁄4-inchopenhole horizontal well in the overlyingformation (Figure 4.7). The producing targetsin this formation, the upper and lowerporosity intervals, are separated by about30 ft of dense, low-permeability limestone,so two separate laterals were required.

��

��

��

��

yyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyy

zzzzzzzzzzzzzzzzzzzzzzzzzzzzzzzzzzz

{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{

||||||||||||||||||||||||||||||||||||||||||

Gas-lift mandrels

Cement plug

Whipstock

Whipstock anchor

RetainerTubing perforations

Tubing plugs

Packer

Buildup section

Lateral

95/8-inch casing

41/2-inch tubing

Upper lateral leg

Lower lateral leg

Figure 4.7 Schematic

wellbore for a

multilateral sidetrack

42

Nu

mb

er 2

1, 1

99

8


CT connector

Disconnector Nonrotatingjoint

Orienter MWD system

Flexible jointCirculating sub

Bent sub

Figure 4.9 The acidizing assembly used to stimulate

the multilateral well

Figure 4.8 CTD operations offshore Dubai, showing drilling barge and platform

at a depth of 8400 ft (MD) at an inclinationof 41°. This leg was kicked off from theexisting openhole by orienting the bent subto the low side of the hole and time drilling.The lower leg was drilled to a total depthof 10,500 ft (MD), achieving a lateral lengthof 1700 ft in the lower porosity interval.

Both laterals were drilled overbalancedand stimulated with a 28% solution of hydro-chloric acid. A special bent sub and measure-ment-while-drilling (MWD) methods wereused to selectively guide the tubing into thelaterals for stimulation. The total measureddepths of the laterals were specifically

planned to be different. This would allow theengineers conducting the workover to deter-mine into which of the two lateral holes thestimulation tool had been run.

For acidizing, the downhole assembly(Figure 4.9) was oriented to the high side ofthe well and run to total depth. The depthwas confirmed to ensure that the coiledtubing was in the upper lateral leg beforethe stimulation procedure began. Beforeany acid was released, the assembly wasrotated until the tool was directed towardsthe low side of the well. This was done toensure that the assembly could be run intothe lower lateral for the second phase ofthe acidizing operation.

The well was drilled as a dual lateralopenhole completion sidetracked from theexisting wellbore (Figure 4.8). The upperlateral was drilled with a build rate of40°/100 ft for a total depth of 10,600 ftmeasured depth (MD) and a lateral dis-placement of 2054 ft in the upper porosityinterval. The lower lateral leg was side-tracked from the wellbore of the upper leg

43

Nu

mb

er 2

1, 1

99

8


��yyyyyyzzzzzzzz{{{||||

��yyyyzzzz{{{{{{{{||||||||��yyyyzzzz{{{{||||

��yyzz{{||

��yz{|��yz

��yyyyzzzz{{{{||||��yyz{{{{||��yyyyzz{{|

��

��yyyyzzzz

{{{{||||��yyyzz{{{||

��yyzz{{||

��yyzz{{{{||||

��yyzz{{||

��yyyyzzzz{{||�

��

��yyzz

{{||

��

��yyzz

{{||

��yyyyzzzz{{{{||||��yyzz{{||

��yyyyzzzz{{||

��yyyzz

1 and 23,4 and 5

200 ft

200 ft

(1)

(2)

(3)

(4)

(5)

Figure 4.10 Acidizing the formation after drilling the multilateral well. The acidizing

assembly was run to total depth in the upper lateral (1) and rotated so that the bent

sub pointed to the low side of the well (2). Acid was pumped down the well as the

tubing was drawn back towards the junction between the laterals. Acidizing was

stopped at a point 200 ft from the junction (3) and the assembly was then run into

the lower lateral (4) where the acidizing procedure was repeated (5), again stopping

200 ft from the junction

Downhole control: the keyto CTD efficiencyTo be effective, CTD systems must drawupon and improve the best coiled tubingand rotary drilling technologies. In CTDoperations the tubing does not rotate and amud motor is required to turn the bit. Thedriller must be able to orient the bit quicklyand accurately and the system mustemulate rotary drilling for optimum rates ofpenetration and straight well paths.

The upper lateral was stimulated back toa depth 200 ft below the junction. Acidizingwas stopped there to prevent erosion ofthe formation at the junction between thelaterals. With the tool face still pointed tothe low side of the hole, the assembly wastripped into the lower lateral. Depth checkswere conducted to confirm that the subhad entered the correct hole and the lowerleg was acidized to a point 200 ft from thejunction (Figure 4.10).

A CTD system must perform well inaerated fluids during underbalanced drilling.It must be able to measure pressuresdownhole to optimize mud-motor per-formance, ensure the underbalanced con-dit ions are maintained to protect theformation and ensure wellsite safety. Thesystem must be capable of transmitting datain the presence of aerated fluids and mustmaintain depth correlation while in thecasing or during drilling. Reliable, accuratedirectional survey data and the ability toconduct formation evaluations are alsoessential requirements.

44

Nu

mb

er 2

1, 1

99

8


The next generation

The VIPER* slimhole CTD MWD andmotor system (Figure 4.11) provides real-time drilling information, precise orientationcontrol and pressure sensors to monitorbottomhole pressure. The VIPER system isa wireline-controlled bottomhole assembly(BHA) that consists of a downhole orientingtool for directional control and an MWDsystem for directional measurements.Orienting-while-drilling ensures accurate,continuous directional control. The VIPERsystem uses an electromechanical orientingtool that rotates in either direction, con-tinuously or in 1° increments, to controlthe wellpath. Fine downhole adjustmentscan be made in real time by inputting thedesired toolface corrections into the surfacecomputer of the VIPER systems.

Drilling head module

Coiled tubingand wireline Check valves

Wet connect Electricaldisconnect

Pressure transducersand electronics

Telemetryand power

GR sensorsand electronics

Direction and inclinometry sensors and electronics

Motor, gear trainand bearing section

Motor/powerelectronics Articulation

Nonmagneticpower section

Surface-adjustablebent housing

Logging tool

Orienting tool Steerable motor

Figure 4.11 The VIPER slimhole CTD MWD and motor system

Straight and smooth

The slow, continuous rotation of the VIPERtool enables it to drill boreholes that arestraighter and smoother than can beachieved with conventional methods.Generating up to 1000 ft-lbf torque, theVIPER tool rotates at 1 rpm to eliminate theeffect of the fixed-bend motor. Thestraighter wellbore provides:• faster penetration rates• reduced drag and longer reach• easier running of completions• more efficient workover operations• better hole cleaning

Staying on track

Using gamma ray and casing collar locatorsensors, drillers can reduce the depth dis-crepancies often encountered in CT oper-ations. These discrepancies are usuallycaused by buckling of the CT as it is pushedinto the wellbore. The gamma ray sensorsof the VIPER system identify formations, orhorizons within them, for reliable depthcorrelation. The casing collar locator sensoris also useful during reentry drilling foraccurate depth control (Figure 4.12).

The VIPER system BHA can be orientedwhile drilling. Fine downhole adjustmentsare possible by inputt ing the desiredtoolface corrections into the surface com-puter system. The orienting tool’s ability toturn continuously allows the driller torotate and slide while drilling curves andlaterals, resulting in faster rates of pen-etration and less tortuous well paths.

Linked to the orienting tool is a reliableand robust directional surveying package.Azimuth, inclination and toolface measure-ments are transmitted to the surfacethrough its high data rate wireline telemetrysystem to give the driller more control forsophisticated well paths and tighter targets.

The tool’s gamma ray sensor can beused for geological correlation. This allowsa simple form of geosteering to increasethe accuracy of the well path. Somegeological interpretation is possible and thegamma ray sensor can be used torecognize marker formations and so aiddepth correlation.

Pressure control

The VIPER system logging module usesadvanced pressure sensor technology tomonitor internal (CT) and external(annular) pressure during drilling, trippingand circulating the well. When drillingunderbalanced wells with a gasified liquidfluid, the annular pressure sensor allowsgreater control of the hydrostatic pressureacting on the reservoir. This helps thedriller to avoid killing the well and damagingthe formation by fluids or solids invasion.The pressure sensor measurements arealso used to keep the motor running atpeak performance for maximum pen-etration rates, and to prevent stalling.

45

Nu

mb

er 2

1, 1

99

8


Working with the wireline

Using a wireline system for data transfermeans that the VIPER tool can transmit highdata volumes much faster than systems thatrely on mud-pulse transmission. Drillinginformation, for example, can be trans-mitted at rates of around 100,000 bits persecond in the VIPER system wireline, com-pared to only 3–6 bits per second in mud-pulse transmission.

Wireline telemetry can transmit data tothe surface regardless of the drilling fluidbeing used. Data are transmitted equallywell in underbalanced or overbalancedconditions. The data rates are very high,giving the dri l ler almost real-t imeinformation from the sensors. Because datatransmission is instantaneous, no time is lostwaiting for mud pulses to be established.The high data-transmission capacity of thewireline will allow the addition of otherLWD tools to the BHA in the future.

��

��

��

��

yyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyyy

zzzzzzzzzzzzzzzzzzzzzzzzzzzzzzzzzzzzzzzz

{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{{

|||||||||||||||||||||||||||||||||||||||||||||��{{{{{{|||||

Gamma ray Casing collar locatorDepth

Figure 4.12 The VIPER system uses gamma ray and casing collar locator sensors to check

its position within the well

Designed for easy maintenance andhandling, the VIPER tool can be split intotwo parts, each with built-in check valves toallow deployment into wells under press-ure. Tool length has been minimized to aiddeployment without using excessively longlubricators, and make-up torque has alsobeen minimized. The tool’s modular designallows sensors to be replaced quickly andmakes it easy to incorporate other sensorpackages for drilling data or formation evalu-ation. The size and configuration of the toolallow short radius curves to be drilled.

To retain the benefits of the small foot-print of a coiled tubing operation, the sur-face data acquisition and display systems arebased on a laptop computer installed in thecoiled tubing control cabin. Data from theBHA and the coiled tubing unit are com-bined in one display. Monitors can beinstalled in the company representative’soffice and the control cabin. Satellite trans-mission of the data to the oil company’soffice is also possible. With no separatelogging cabin required, rig site equipment iskept to a minimum.

Built-in benefits

The VIPER system is an integral part of theCTD system. Designed to work in a widerange of temperatures and pressures, itssensors can withstand the high shockenvironment encountered at the bit. Thewireline telemetry system works in all fluidsand can transmit real-time sensor and con-trol data, increasing the engineer’s controlover the drilling process.

The orienting tool will bring the greatestbenefits to the CTD process. The tool’sorientation can be continuously adjusted toallow well paths to be drilled to closer toler-ances. Precise corrections and changes to thetoolface orientation can be made while drill-ing to avoid nonproductive time. Continuousrotation of the VIPER BHA adds a rotarycapability to improve drilling performanceand the control over the well path. Byintegrating the BHA into the CTD process,the efficiency of the whole operation hasbeen increased.

46

Nu

mb

er 2

1, 1

99

8


Coping with cuttingsThe traditional guidelines for hole cleaningusing unweighted, unviscosified fluids are aminimum annular velocity of 50 ft/min invertical holes and 100 ft/min in horizontalholes. These values are lower than wouldnormally be applied in conventional drillingdue to the high downhole motor rpm andlow weight on the bit, resulting in smallercuttings with coiled tubing drilling.

There are two major points that dif-ferentiate hole cleaning in CT drilling oper-ations from hole cleaning in conventionalrotary drilling:• in rotary drilling the drilling fluid must be

able to support the cuttings when thepumps are switched off while making aconnection: in CT drilling, shutting downflow is infrequent

• in rotary drilling the rotation of thedrillpipe contributes to hole cleaning bycontinually entraining the cuttings backinto the mainstream from the lower sideof the hole: in CT drilling the pipe doesnot rotate above the motor

��

��

��yyyyyyyyyyyyyyyyyyyyy

zzzzzzzzzzzzzzzzzzzzz

{{{{{{{{{{{{{{||||||||||||||��yyyyyyyzzzzzzz

Cuttings bypassedby bit

Rotating bitCoiled tubing

Cuttings bed

Cuttings suspended in mud

Pulling out of hole

Mud without cuttings

��

��

��yyyyyyyyyyyyyyyyyyyyy

zzzzzzzzzzzzzzzzzzzzz

{{{{{{{{{{{{{{||||||||||||||��yyyyyyyzzzzzzz{{{{{{{|||||||Rotating bitCoiled tubing

Cuttings bed

Cuttings suspended in mud

Mud without cuttings

Running into hole

Figure 4.14 When a

coiled tubing drillstring is

being run into the hole,

cuttings will fall out of

suspension

Figure 4.13 When a

coiled tubing drillstring is

being pulled out of hole

cuttings will be drawn up

the hole by the bit and

will accumulate as

shown

1 IC Walton (1995). Eddy diffusivity of solid particles in a

turbulent liquid flow in a horizontal pipe. AIChE Journal

41, pp1815–1820

These differences are substantial and callfor new techniques for designing fluids forCT drilling. Thus the central requirement forrotary drilling—a high yield stress—is neithernecessary nor sufficient in CT drilling.

A recent study1 of cuttings transport inCTD wells showed that hole cleaning ismore efficient if a low-viscosity fluid ispumped in turbulent flow rather than ahigh-viscosity fluid in a laminar flow. Holecleaning with a viscous fluid in a laminar flowis inefficient because of the fluid’s inability topick up the cuttings on the low side of thehole; with conventional drilling the rotationof the string is used to agitate the cuttingsbeds and introduce the solids into the flowpath. To achieve turbulent flow requireshigher pumping rates, which are limited bythe circulation pressure of the tubing andflow rate through the downhole equipment.

47

Nu

mb

er 2

1, 1

99

8


The fluid’s inability to clean the holemeans that alternative methods must beapplied. One wat to help solve the holecleaning problem is the use of wiper trips. Awiper trip simply involves pulling the BHAback to a selected point and then redrilling asnecessary back to the bottom of the hole.Wiper trips may be required for numerousoperational reasons unconnected with holecleaning, but the ability to circulate whilerunning in-hole or pulling out of hole canhelp to resolve cuttings transport problems.In addition to the traditional drilling methodsof monitoring drag and returns, the CTDtechnique uses an annular pressuremeasurement to monitor trends in annulusloading. When cuttings beds are en-countered, possible solutions include:• progressive wiper trips: with coiled

tubing drilling more wiper trips arerequired as a substitute for rotation andto monitor bed buildup behind the BHA

• raking the low side of the borehole toclear cuttings from low spots: the bentsub is oriented down towards the lowside of the hole and the bit is worked upthe hole rather than downCuttings beds often develop in the build

section even when the horizontal section ofthe wellbore is clear. The driller must becareful, when pulling into the build section,not to wedge the BHA in the cuttings bedand risk it becoming stuck.

When pulling out of hole, the bit will shiftthe cuttings up the hole. Cuttings from thewiper trip will accumulate as shown inFigure 4.13. This means that the cuttingsbed will reach maximum thickness justabove the bit and may cause sticking. Oncethe cuttings have formed a bed, only the bitor turbulent flow can move them.

When running into the hole, the higherannular velocity caused by metal dis-placement may clean more effectively if itresults in turbulent flow. However, if theflow is laminar, the cuttings will fall out asshown in Figure 4.14.

In underbalanced wells with large inflow,sections of more than 1000 ft have beendrilled without a wiper trip. The inflow,which may nearly double the annularvelocity, helps to stir up cuttings from thebed and provides more turbulent mixing tohelp keep them in suspension. Cuttingsfrom underbalanced drilling are generallylarger than those from overbalanced wellsbut the inflow means that this is not usuallya problem.

Several underbalanced wells drilled todate have shown no signs of hole cleaningproblems, but problems have beenencountered in the build section. This isprobably because there is no inflow in thebuild section to stir up the cuttings beds thatform there.

I f the hole cannot be cleaned withturbulent flow the simple estimation ofcuttings transport distance will allow thedriller to base wiper trip design on easilycalculated parameters rather than a ‘bestguess’. Fewer short trips and less viscousmuds are both potential cost reducers.Even if the number of short trips remainsthe same, a less viscous mud will providelower pump pressure and direct savings asa result of increased CT life.

ConclusionsSuccessful CTD operations call for closecooperation from experts in a number ofdisparate technical disciplines. Without theright combination of drilling, logging, wellengineering, testing and software skills noCTD operation could succeed. For under-balanced or just-balanced drilling, through-tubing drilling or conventional slimholereentry, the CTD technique is an alter-native to conventional drilling. As CTDtechnology improves and its environmentalbenefits are more widely recognized, therange and number of drilling operationsconducted with coiled tubing looks certainto increase.

Documents

Coiled Oil