45169970 BJ Coiled Tubing Equipment Manual Version 1

BJ Services Tomball EDC- Training Department

EDC – Tomball, Version 1.01 Revised: April 2005

TCC210 COILED TUBINGEQUIPMENT CORRESPONDENCE

COURSE


EDC – Tomball, Version 1.01 Revised: April 2005 2

Copyright 2005, by BJ Services. All Rights reserved. No part of this manual may be reproduced in any form orby any means (including electronic storage and retrieval or translation into a foreign language) without prioragreement and written consent from BJ Services as governed by United States and international copyright laws

Training DepartmentBJ Services11211 FM 2920Tomball TX 77375

Printing History: First Edition – April 2005

Credits: Training Department: Tim Ramsey, Training Engineer; Jim Wilke Manager Engineering

Training Group; Ken Kenner Manager Corporate Training



INDEX

Subject Page

Introduction 4History of CT 5CT Reel 7Injector Head 12Gooseneck 17Power Pack 18Control Cabin 20Well Control Equipment 22Bottom Hole Assemblies 32CT Manufacturing 69CT Fatigue 75CT Selection Criteria 80Circa 83Cycle 85Monitoring Equipment 87Health & Safety 89



Coiled Tubing Equipment___________________________________________________________________________________

IntroductionThis article was developed with the intention to be a guide for the correspondencecourse TCC210, which forms part of the T-CAP training plan in BJ ServicesCompany. It presents an overview of the coiled tubing equipment, necessary toperform a coiled tubing intervention either on land or offshore.

Over the past decade the number of applications for coiled tubing services withinthe petroleum industry has been increasing exponentially and coiled tubingservices continues to be one of the fastest growing sectors in the industry. BJServices currently owns and operates about one hundred fifty five (155) CoiledTubing Units worldwide - Second largest World CTU Fleet, of which more thanhalf are operated on land.

Coiled tubing growth has been driven by economics, continual technologicaladvances and the successful utilization of CT to perform an ever-growing list offield operations.

• Gas Lifting• Stimulation – Fracturing & Acid treatments• Fill Cleanouts• Cementing• Scale Removal• Workover Drilling / Milling• Electrical Applications – Logging & perforating• Fishing• Force Application -• Ultra-high Pressure• Pipeline Servicing• Permanent Installations – Completions & Gravel Packs•• Vertical / Horizontal Under Balanced Drilling – DUCT



The advantages associated with coiled tubing are:

• The ability to operate on live wells – does not require well to be killed, thusreducing risk of formation damage.

• Quick mobilization and rig up.• Ability to work Rigless – no associated rig costs.• Reduced surface footprint and crew configuration.• Efficient offshore mobilization – skid mounted units.• Ability to perform operations while well is producing – minimizing production

downtime.• No connections and thus ability for continuous circulation during live well

intervention.

The History of Coiled Tubing Extracted from World Oil’s Coiled Tubing Handbook, 1993

In 1944 the first coiled tubing pipeline treatment was executed; Project PLUTO(PipeLines Under The Ocean). The job consisted of laying 23 three-inch (76.2 mm)diameter pipelines across the English Channel to supply allied forces with fuel tosustain the liberation of occupied Europe during World War II. Each pipeline consistedof pre fabricated 4,000 ft (1219 m) sections of pipe, butt-welded together and spooledonto 40 foot (12.2 m) hub diameter reels. Of the 23 pipelines, 17 were about 30 mi.(48.3 km) long and the remaining six were 70 mi. (112.6 km) long.

Injector head designs were first developed for use with submarines. In the early 1960’sBowen Tools was contracted to deploy a radio antennae from submarines. The conceptwas very similar to that of a coiled tubing injector.

In 1962 the California Oil Company and Bowen Tools developed the first coiledtubing unit. The unit was called a ‘continuous-string light workover unit’. The size ofpipe used was 1.315” OD.

The coiled tubing was fabricated from 50ft segments. The steel used was low alloyColombian tubing. The 50ft segments were butt-welded and spooled onto a 9ft-diameter work reel with a total length of 15,000 ft. Through 1963 and 1964 this unitperformed numerous jobs in the Louisiana area. The continued development of coiledtubing may be described as follows:

• 1964: Brown Oil Tools and Esso introduce a new coiled tubing injection system.The unit was built to run ¾” coiled tubing.



• 1967: Bowen introduces a downsized version of the original injector design. Theinjector is the 5M capable of handling 5,000 lb. of ½” coiled tubing. NOWSCOcontracted Bowen Oil Tools to build 12 “5M” coiled tubing units.

• 1968: Bowen developed the “8M” coiled tubing injector head capable of running8,000 lb. of ¾” coiled tubing.

• Late 1960’s to mid 1970’s: Modifications and new designs for coiled tubing units.The common size of coiled tubing in use increased to 1” OD More than 200 coiledtubing units were built in this time frame.

• Late 1970’s: New coiled tubing equipment manufacturers emerged; Uni-Flex Inc.,Hydra Rig Inc., Otis Engineering. The new injectors built were similar to that ofBowen Tools.

• 1975: Uni-Flex introduces a new injector head design. Many of the new featuresinfluenced future injector designs of other manufacturers.

• 1976: Formulation of Quality Tubing Inc., with financial assistance fromNOWSCO.

• 1978: All construction of Uni-Flex and Brown Oil Tools coiled tubing equipmentwas stopped.

• Late 1970’s to early 1980’s: Many design changes and revisions made to improvecoiled tubing equipment. The main suppliers of coiled tubing units were BowenTools, Hydra Rig Inc. and Otis engineering.

• 1985: New coiled tubing injector developed by Fleet Cementers, capable ofsupporting 8,500 ft of 1¾” coiled tubing.

• 1989: Quality Tubing Inc. awarded patent for bias weld procedure. Thisdramatically improved the fatigue life of the coiled tubing.

• 1993: Quality Tubing received a product patent for continuous coiled tubing.

• Dec. 1999 Coiled Line Pipe now established as an API Product



Generally speaking, a Coiled Tubing unit is made up of six basic components:

1. Tubing Reel.2. Injector Head & Gooseneck3. Power Pack.4. Control Cabin.5. Well Control Equipment.

• Stuffing Box (Stripper, Packoff).• Blow-Out Preventers (BOP).

The Coiled Tubing ReelCoiled tubing is stored on a drum that is supported on a shaft and mounted on askid frame. A bi-directional hydraulic motor directly driving the reel via rollerchain and sprockets or by a gear drive system rotates the reel. The drive system hasdual function: when running in hole (RIH), the motor acts as a constant-torquebrake, enabling back tension to be held on the pipe and while pulling out of hole(POOH), more tension is applied to enable efficient spooling of the pipe onto thedrum. The reel will have a brake mechanism to prevent accidental rotationalmovement when it is required. The reel drive system should produce enoughtorque to provide the required tension to the coiled tubing to bend the coiled tubingover the gooseneck and onto the reel. This tension provided by the reel on thecoiled tubing unit between the reel and injector is commonly referred to as ‘reelback-tension’. The tension requirements – thus reel motor drive system- increasesexponentially with coiled tubing diameter because of the increased load/weightsrequired.

Note: This tension is not intended to aid the injector head in pulling the coiledtubing from a well.

The tubing is spooled on/off the drum using a hydraulically raised & loweredlevelwind assembly. The levelwind allows for travel along an adjustable diamondlead screw and is powered by rotation of the reel itself and incorporates a floatingtubing guide to allow for height adjustments. A manual override facility isincorporated to allow for compensation of spooling errors.



Figure 1 Coiled Tubing Reel

Figure 2 Coiled Tubing Levelwind Assembly

LevelwindAssembly

Floating TubingGuide

Reel CT Oiler System

Lead Screw

Reel Motor



The reel is equipped with a rotating joint (swivel) to allow pumping through thecoiled tubing while the reel is rotating; this rotating joint is flange mounted ontothe reel shaft. The inboard end of the coiled tubing is connected to drums externaliron plumbing, via a welded 1502 WECO threadExternal plumbing may consist of:• 2” Fig1502 chicksan• 2” Fig1502 tee• 2” Fig1502 plug valves• Pig launcher assembly

Figure 3 Rotating Joint Figure 4 Reel Iron Manifold

For operations where the offshore platform crane limit is a problem, Drop inDrums can be shipped as two separate loads. The drum with the coiled tubing issent as one load and the support frame as a second load. Once the two separatesections have been lifted onto the platform, the spool is then fitted into the supportframe. The spooler is fitted with the same pumping facilities as the standard reeland can also facilitate e-line coiled tubing.

CT connection to reel iron

Rotating Joint

Pressure Transducer

Reel Iron Manifold

Pig Launcher

Bleed Off Valve Plug / Ball InsertionPort and Plug

Stopper PinKeeps ball or plug from fallingbackwards prior to pumping



The length of coiled tubing of a certain size, which can be stored on a reel, isknown as the reel capacity. The reel capacity differs for different coiled tubingsize. Consideration should also be referenced to the reels Core Diameter and itsbending radius – reference COP’s manual aforementioned extract.

Examples of CT Drum sizes and capacities:

Diameter (in)Core 60 76 84 84 96Flange 100 119 135 148 168Drum Width 60 70 70 70 82

Gross Lift Capacity (lbs) 30,000 48,000 68,000 68,000 115,000

Tubing Capacity (ft)

CT OD (in)1.25 15,000 22,500 25,000 25,000 25,0001.5 10,000 15,100 22,000 25,000 25,000

1.75 - 11,200 15,000 20,000 25,0002 - 8,500 11,000 15,000 22,000

2.375 - - - - 15,000

Diameter (cm)Core 152.4 193.0 213.4 213.4 243.8Flange 254.0 302.3 342.9 375.9 426.7Drum Width 152.4 177.8 177.8 177.8 208.3

Gross Lift Capacity (kgs) 13,608 21,772 30,844 30,844 52,163

Tubing Capacity (m)

CT OD (mm)31.8 4,572 6,858 7,620 7,620 7,62038.1 3,048 4,602 6,706 7,620 7,62044.5 - 3,414 4,572 6,096 7,62050.8 - 2,591 3,353 4,572 6,70660.3 - - - - 4,572

Depth Measurement:

A mechanical odometer for depth measurement with 5-digit read out is usuallyinstalled on the level wind assembly. The measured depth is the length of coiledtubing that is deployed below the injector head into the well. The measured depthcan be directly measured in several places on a coiled tubing unit using a friction



wheel, which is in contact with the coiled tubing. Other than the reel, a depthcounter may be installed on the injector or the gooseneck. Depth can also beobtained indirectly by measuring the rotation of the injector head gear drive shafts.It should be noted that measured depth might be different to actual depth of thecoiled tubing due to the following, well profile and the helical effect, thermalexpansion, stretch and counter efficiency.

CT Reel Minimum Purchase Standards – Extracted from BJ Services CT Operations &Procedures (COP’s Manual)

• The drive system must have a higher top speed than the injector• The shaft torque should be 1.5 times the line pull required for the biggest, heaviest coil

to be utilized• The minimum core diameter needs to be forty-eight (48) times the maximum pipe OD to

be run on the reel. As large as possible i.e. 1.25” / 72”, 1.50” / 90”, etc. (31.8 mm / 182cm, 38.1 mm / 228 cm)

• Dynamic and mechanical reel brakes are required• The levelwind needs to be able to handle 80 degrees of elevation• The internal piping needs to be integral and have a minimum 10,000 psi (70,000 kPa,

690 bar) working pressure rated with at least one plug valve and ball drop “Tee”.• The rotating joint shall be rated at 10,000 psi (70,000 kPa, 690 bar) working pressure.• The rotating joint to have a non obstructed ID equivalent or larger than the maximum

coil ID except 2 7/8” (73 mm) and 3 1/2”(88.9 mm)• All reels shall be counter drilled for “Stiff Wireline” applications.• The plug launcher shall be part of the internal plumbing.• There shall be a hydraulic fail-safe clamp on the levelwind.• A mechanical depth counter shall be mounted on the levelwind.• A pipe lubrication system, non hand spray, will be located somewhere on the unit (i.e. -

the stuffing box or levelwind)• Reel capacity is not the same for different coiled tubing sizes. Capacity for any given

reel can be calculated as follows;

L = ((A-F)/D) X (B/D) X (2C+B)/3.82 L = Reel capacity (feet) A = Reel flange height (inches) F = Reel free board (inches) D = Coiled Tubing diameter (inches) B = Width of reel between flanges

(inches) C = Core diameter (inches)



Coiled Tubing Injector HeadThe injector head is the heart of the coiled tubing unit. This piece of equipmentallows the coiled tubing to be injected (snubbed) and retrieved from the wellbore.Injector head manufacturers include Hydra Rig, Stewart & Stevenson, Bowen,Maritime Hydraulics, Dreco and others; H-R and S & S are considered the twocurrent market leaders. The coiled tubing is gripped between contoured blocks,which are carried by two sets of double row contra-rotating chains. The injectoroperates on the friction drive principle. The injector speed and direction arecontrolled through the use of bi-directional hydraulic motors that provide the forcefor the injector. Hydraulic motors are used to drive the gripper block and chains byturning the chain drive sprockets. Different configurations are available with up tofour motors driving the upper and lower sprockets. The hydraulic counter balancesystem provides dynamic braking when hydraulic pressure is released. Manyinjector motors have built in hydraulically released mechanically actuated brakesthat automatically lock when there is loss off hydraulic pressure to the motor.Separate external manual mechanical brakes are also used on older injector heads.It is important that correct tension of the drive chains be maintained to preventeither crushing the tubing, or letting it slip due to poor grip.

Figure 5 Injector head Blocks & Chain System

The chains and their motor and gearbox drive system are mounted in a subframe,one side of which is hinged. The opposite lower side can rest on a hydraulic loadcell, which is connected to the weight indicator in the control cab. The forces

Chain Drive Sprockets

Contra-rotating chains

Outside Chain TensionCylinder

Gripper BlockTraction Cylinders



exerted by the action of the drive system and the tubing weight are all appliedalong the centerline of the tubing and cause the subframe to pivot; the resultingdeflection measuring direct force or load acting on hydraulic load cell bladder.Individual hydraulic load cells will measure either pipe-heavy (positive weight) orpipe-light (negative weight, less than zero, snubbing).

Another type of weight indicator is an electric strain gauge model. This type ofweight indicator measures the applied load by strain gauges, with output signals inmAmps (4-20mA) or Volts (0-5 V), which are converted in the cab to measureapplied loads – tension (pulling) or compression (snubbing). The load is defined asthe tensile or compressive force in the coiled tubing just above the stripper. It isone of the most important measurements used in the operation of a coiled tubingunit. Load may be effected by several parameters other than the hanging weight ofthe coiled tubing, including wellhead pressure, stripper friction, reel back-tension,gooseneck alignment and the density of the fluids inside and outside the coiledtubing.

Note: Reference individual unit manuals for hydraulic pressure to Lbs. pull/snubratios, to ensure correct operating guidelines and to cross-reference weightindicator reading with hydraulic pressure applied to the injector motors.

Figure 6 & 7 Injector Head Pivot and Load Cells

CT Weight

Pipe Heavy Pipe Light

Pivot

Pipe Heavy load Cell

Pipe Light load Cell



Figure 8 Injector Gripper Blocks & Chain Figure 9 Injector head & Gooseneck

Figure 10 Injector Head Mechanical Counter & Encoder

Mechanical Depth Counter

Depth Encoder



EXAMPLES of HYDRA RIG INJECTOR HEAD CAPABILITIES

HR-125 HR-150 HR-240 HR-260 HR-420 HR-440 HR-480 HR-5100 HR-5200

Maximum Rate Pull - (lbs.) 32,000 42,000 40,000 60,000 18,000 60,000 100,000 100,000 200,000

Maximum Snub Capacity -( lbs.) 10,000 10,000 15,000 15,000 5,000 20,000 40,000 60,000 60,000

Tubing Size Capacity - (in.)Minimum CT OD 1.00 1.00 1.00 1.00 1.00 1.00 1.25 1.25 2.00Maximum CT OD 1.75 2.375 1.75 2.375 1.25 2.375 3.50 3.50 5.50

Approx. Weight w/Gooseneck- (lbs) 7,500 10,000 8,000 11,000 3,600 7,200 13,500 11,500 11,500

HR-125 HR-150 HR-240 HR-260 HR-420 HR-440 HR-480 HR-5100 HR-5200

Maximum Rate Pull - (daN.) 14,234 18,683 17,793 26,689 8,007 26,689 44,482 44,482 88,964

Maximum Snub Capacity -(daN.) 4,448 4,448 6,672 6,672 2,224 8,896 17,793 26,689 26,689

Tubing Size Capacity - (mm.)Minimum CT OD 25.40 25.40 25.40 25.40 25.40 25.40 31.75 31.75 50.80Maximum CT OD 44.45 60.33 44.45 60.33 31.75 60.33 88.90 88.90 139.70

Approx. Weight w/Gooseneck- (kgs) 3,402 4,536 3,629 4,990 1,633 3,266 6,123 5,216 5,216



Injector Head Minimum Purchase Standards– Extracted from BJ Services CTOperations & Procedures (COP’s Manual)

• A minimum of 50% snubbing capability verses pulling.• Snubbing force which is 120% of the maximum anticipated by the Circa

prediction both while the coiled tubing is stationary and while it is moving atspeeds up to 30 ft/min (10 meters/min)

• A dynamic braking system that prevents the coiled tubing from moving when nohydraulic pressure is being applied to the hydraulic motors. Also a secondarymechanical brake which is set automatically or manually when the injector isstopped. Braking systems must be capable of holding the maximum pulling forceand the maximum snubbing force.

• The chains should be able to achieve maximum pull without the aid of coatings.• The ability to change pipe size without the need to remove the chain (i.e. -

inserts).• The maximum speed should be 240 ft/min. (70 m/min)• Some means of support to prevent loads being transmitted to the wellhead.• Note: The base must be strong enough to support the load of tubing suspended in

the well as well as the injector.• The injector frame and pad eyes rated to the injector weight plus the maximum

rated pull.• An accumulator on the skate traction hydraulic system.• An adjustable mounting system for the gooseneck.• The load cell shall be dual acting.• The weight indicator will have “heavy/light” readings when rated above 50,000

lbs (22,200 daN) or is electronic.• A chain tensioning system• A drip tray to catch and contain chain lubrication• Pad eyes for lateral re-strainment• A ladder for access to the gooseneck• A non-slip cover on top of injector• The ability to pull test to 120% of the maximum anticipated by CIRCA

prediction, while stationary and while the coiled tubing is moving at 30 feet/min(10 m/min)

• Must have a maintenance odometer installed.



Gooseneck:

To complete the injector head package there is a tubing roller guide orgooseneck positioned on top off the injector head. The gooseneck aids insupporting, straightening and aligning the coiled tubing as it comes off thework reel and into the gripper blocks on the injector. This is done by a seriesof contoured rollers and cages that contain the coiled tubing as it travels overthe gooseneck. The gooseneck base should also pivot or be flared at reelfacing end, to enable for spooling across a work reel as the coiled tubingtravels along the width of the drum. The gooseneck is designed with anominal radius of curvature appropriate to the coiled tubing size; the radiusneeds to be at least 48 times the coiled tubing OD. This is to enable themaximization of coiled tubing life and thus reduce the effect of fatigue.Common gooseneck sizes are: 72”, 96” and 120”(183 cm, 243cm and305cm).

Figure 8 Gooseneck Sizes Figure 9 Gooseneck Roller

Gooseneck Minimum Purchase Standards– Extracted from BJ Services CTOperations & Procedures (COP’s Manual)

• Needs to be adjustable. The pipe should enter and exit the guide arch tangent tothe curve of the guide arch

• The guide arch radius needs to be at least 48 times the coiled tubing OD. Note: A radius larger than 100 inches (254 cm) does not gain significant advantages.• The closer the rollers are spaced, the better.• The gooseneck needs to be strong enough to handle the combined bending of the

pipe, withstand the bending moment that maximum reel back tension wouldapply and a 5% side moment (fleet angle) that happens when you are spooling atthe extreme sides of the reel.

• The end of the gooseneck should be flared. This flare should accommodate themaximum fleet angle that it will see without the pipe seeing another strainreversal.



Coiled Tubing Power Pack

The most common type of power pack is diesel driven skid/trailer unit madeup of a system of hydraulic pumps, hydraulic pressure control circuits,hydraulic tanks and accumulators to enable the efficient operation of thecoiled tubing package. Power packs are built in many differentconfigurations depending on the operating environment e.g. Electric Units,Zone 2 Certified, Sound Proof, ‘Wet Units – trailer tractor driven’ etc.

The type of injector drive circuit generally classifies power packs:

• Standard Open Loop Power Pack – The standard open loop injectordrive circuit utilizes a fixed displacement double vane pump and a 4-wayvalve. The valve is a pressure compensating directional control valve thatcontrols the speed and direction of the injector motors. The system iscapable of operating at 3,000 psi. (20,684 kPa) and works on theprinciple of oil going from the tank, through the pump and valves and tothe injector motors; oil returns through a filter and air cooler into thehydraulic tank.

• High Pressure Open Loop Power Pack – The high pressure open loopinjector drive circuit utilizes a load sensed, variable displacement,pressure compensated piston type pump. The system is capable ofoperating at 5,000 psi. (34,473 kPa) and works on the principle of oilgoing from the tank, through the pump and valves and to the injectormotors; oil returns to the pump inlet (supercharging the pump) afterpassing through a filter and heat exchanger. A pressure relief valve in thereturn line ensures oil that is not required by the pump is routed back tothe tank; an advantage of this system, is that less heat is generated.

• Closed Loop Power Pack – The closed loop injector circuit utilizes a bi-direction, variable displacement pressure compensated piston pump. Thepump actually comprises of three pumps: main pump, charge pump andservo pump (shifts the swash-plate for directional control). The system iscapable of operating at 5,000 psi. (34,473 kPa) and is a less complicatedsystem when compared to the high-pressure open loop system. Thesystem works on the principle of oil going from the tank, through thepump and valves and to the injector motors; oil returns through a filterand goes directly back to the pump inlet. A charge pump and auxiliaryflushing circuit are always present to replenish fluid that leaked from thehigh pressure elements into the pump’s case and to add cool oil into thelow side of the loop to stabilize the oil temperature.



Hydraulic Circuit FunctionInjector Runs the injectorFlush Flushes injector (Closed loop pumps only)Reel Runs the reelLevelwind Runs the levelwindBOP Runs the BOP systemPriority Runs the controls in the control cabinAuxiliary Runs the powered hose reels, crane, winch etc.

Figure 10 Skid Mounted Power Pack



Coiled Tubing Control Cab The control cabin fully allows the operation and control of all functions ofthe coiled tubing unit from within the cabin. The typical unit is hydraulicallyelevated for better operator vision. The control panel incorporates:

• Injector controls• Reel controls• Dual stripper packer controls• BOP controls• Auxiliary shear seal BOP controls• Hydraulic circuit pressure gauges• Weight indicator• Coiled tubing internal pressure• Wellhead pressure - WHP• Data Acquisition unit• Remote power pack control

The unit is fully insulated with a heater for cold climates and space for airconditioning unit in warm climates.All necessary hoses to control and operate the Injector Head, BOP’s, PowerPack and Tubing Reels are incorporated on hydraulically powered reels onthe front of the skid.

Figure 11 Example of Control Cab Interior



Power Pack and Control Cab Minimum Purchase Standards– Extracted from BJServices CT Operations & Procedures (COP’s Manual)

• The engine size needs to be able to handle the injector plus the auxiliary systems atmaximum load with a 50% safety factor.

• The hydraulic system to be able to dissipate maximum heat output.• The control cab window shall be protected or have bullet proof glass.• The blind and shear ram controls on the control panel shall have positive locks.• The accumulator charge shall be sized to handle Close, Open, Close scenario of all

rams at the maximum BOP rated working pressure.• The hydraulic system for the BOP’s and stuffing box shall have two back-ups (i.e. air

and manual).



Well & Pressure Control EquipmentCoiled tubing well and pressure control equipment is designed to allow forsafe well intervention on a live/pressurised well. The stuffing box and BOPare considered a Primary barrier for well control purposes.

Stuffing Box

The stuffing box is the primary sealing mechanism for isolating/containingwellbore fluids while coiled tubing is under static or dynamic operatingconditions. The stuffing box is attached to the bottom of the injector head bymeans of a flange connection or retaining pins. Operation of the stuffing boxis by means of hydraulic pressure acting on a piston, which compresses apolyurethane element (stripper rubber) forming a seal around the coiledtubing. The packing elements are positioned between sets of brass bushingsand may incorporate Non-Extrusion Rings between bushings and stripperelement.

There are two main stuffing box designs:

1. Top Loading: This is the original (older models) stuffing box designused for coiled tubing operations. The packing elements are positionedbetween sets of brass bushings. A double acting piston compresses thebushings together to squeeze the stripper rubber around the coiledtubing. The upper section of the stuffing box is called the split cap andcomprises of split housing containing the upper wear bushings. The splitcap is held in place with retaining pins or it is threaded into the body.The design allows for the stripper rubbers to be changed out if requiredduring a well intervention by taking out the split cap (not as user friendlyas side door design.)

2. Side Door: This design allows the packing elements to be replacedthrough a door below the injector-mounting interface. Changingelements with this design is easier and safer when changing elementswith coiled tubing in the well. The side doors are unlocked and swingopen and then the piston is retracted to expose the stripper elements –enabling them to be swapped out.

Common stuffing box bore sizes: 2.50”, 3.06” and 4.06” (63.5 mm, 77.7mmand 103mm).



Figure 12 Top Loading Figure 13 Stuffing Box & Injector

Stuffing Box connected toInjector Head

Figure 13 Side Door

Figure 13 Retracting Side Door Entry

Figure 14 Internal Elements

Doors

Stripper Rubber

Non-Extrusion Rings

Bottom Bushings

Top Bushings

Stripper Rubber



Note: Two causes of excessive stripper rubber wear are dry, rusty pipe anddry gas. Lubricating the coiled tubing prior to it going into the stuffing boxwill reduce the wear on the element; this can be done by lubricating thetubing at the reel or utilizing an adapted stuffing box with an inhibitorinjection port.The positioning of the top of the stuffing box should be kept close aspossible to the bottom of the injector chains to help prevent buckling of thecoiled tubing while running in hole (minimize void between the bottom ofthe gripper blocks & chains and the top of stuffing box). This is usuallyachieved by adding an Anti-buckling device (extra set of bushings) whichreduces the gap to approximately 4 inches.

Figure 15 Stripper Rubber

Stuffing Box Minimum Purchase Standards– Extracted from BJ Services CT Operations &Procedures (COP’s Manual)

• Approved vendor• Complies with or exceeds NACE MR 0175 and API standards for well control

equipment• Minimum 10,000 psi (70,000 kPa, 690 bar) working pressure with a 15,000 psi

(100,000 kPa, 1032 bar) test pressure• H2S compatible• Have an injection port below the pack-off• Have a “chemical injection port” above the packer elements to allow 360ºcoverage of

the pipe with a wide variety of anti corrosion chemicals or lubricating oilsPreference is given to :• Systems where the distance from the top of the upper bushings to the chains is

minimized• “Side removable” packer element designs (i.e. side-door, radial, etc.)• Dual acting hydraulic pack-off, ones that hydraulically energize and release• The hydraulic energizing system should have “weep holes” to signify worn

orings/seals• Benoil is the only approved stuffing box packer/energizer vendor for wellhead

operation with pressures exceeding 3000 psi (21000 kPa) and or temperaturesexceeding 2120 F (1000 C)



Blow Out Preventers – BOP’s

The BOP is the primary safety apparatus designed to prevent theuncontrolled release of wellbore hydrocarbons and is usually flanged on topoff the wellhead. A coiled tubing BOP is designed specifically for coiledtubing operations. The BOP consists of several pairs of rams, with each pairof rams having a specific function.

1. Blind rams isolate and seal against open hole when there is no tubing inthe BOP.

2. Shear or Cutter rams have cutting blades to shear the coiled tubing andwire, if stiff-wireline. A Booster cylinder may be incorporated in the ramsystem to aid in shearing larger diameter or heavy wall coiled tubing.

3. Slip rams hold the coiled tubing to prevent it from being pushed out ofthe well or from falling down the well. Note Interrupted Slip Inserts arerecommended to prevent undue marking of the tubing in event of use oframs.

4. Tubing or Pipe rams form a pressure seal around the coiled tubing toisolate well bore and contain pressure.

The number and type of ram pairs in a BOP is determined by theconfiguration:

• Single• Double• Triple• Quad

Blind/Shear Rams

Pipe/Slip Rams

Blind Rams

Shear Rams

Slip Rams

Pipe Rams



Minimum pressure rating for new BOP’s is 10,000 psi (68,947 kPa) and15,000 psi (103,421 kPa) working pressure. The Quad BOP has twoequalizing ports, one on each sealing ram – their function is to equalizepressure across the ram face if required. The BOP will also have a pump inside outlet in-between the slip and shear rams, to enable wellkilling/pumping facility if operationally required.Note this port is not to be used as a flow-line or take returns.

Blow-out Preventer Sizes

BOP Size - (in) 2.56 3.06 4.06 5.12 6.38 7.06

Tubing Size - (in.)Minimum CT OD 0.75 0.75 1 1.25 1.25 1.25Maximum CT OD 2 2.375 2.875 3.50 3.50 3.50

BOP Size - (mm) 65.02 77.72 103.12 130.05 161.93 179.32

Tubing Size - (mm.)Minimum CT OD 19.05 19.05 25.40 31.75 31.75 31.75Maximum CT OD 51 60 73 89 89 89

Figure 16 Ram insetsFigure 18 Quad BOP

Shear Ram

Pipe Ram

Blind Ram

Slip Ram



Figure 18 Interrupted Slip inserts

BOP Minimum Purchase Standards– Extracted from BJ Services CT Operations & Procedures(COP’s Manual)

• Approved vendor• Complies with or exceeds NACE MR 0175 and API standards for well control

equipment• Minimum 10,000 psi (70,000 kPa, 690 bar) working pressure with a 15,000 psi

(100,000 kPa, 1032 bar) test pressure• Minimum 3 1/16” (77 mm) ID• All shall be H2S compatible• All BOP hoses will be fire proofed the first 50 feet (15 m) from the well• All rams to be able to close in 15 seconds or less at minimum temperature• Minimum configuration will be blind, shear, slip and pipe or combination of these• Have a kill port with a minimum 2 1/16” (52 mm) flange• Ability to monitor wellhead pressure below the pipe rams• Pressure equalizing valves across all pressure containing rams• Use of only flanged/metal-to-metal connections below the lowest blind rams• Slip design shall minimize fatigue/deformation damage (interrupted profile, diamond

or other pattern)• Slip rams shall be capable of holding the pipe up to the minimum yield point at the

maximum rated working pressure in a hang-off mode. In a “snub” mode, the shouldhold a minimum of 50% of the minimum yield of the coiled tubing

• Have shear/seal feature• Shear rams capable of shearing the heaviest wall and highest yield OD pipe the BOP

is designed to accommodate at its maximum rated working pressure. Hydraulicpressure utilized to make this cut will be less than 3000 psi (21,000 kPa, 206 bar)

• Shear rams shall be capable of two or more successive cuts of the above pipe whilestill leaving a fishable profile plus flow path through the pipe

• Shear rams must be capable of cutting slick or braided line cleanly



• All rams to have a manual locking device capable of holding maximum workingpressure ratings as well as hydraulic operating pressure. The rams can only beopened hydraulically after the lock has been disengaged

• Accumulator should be sized to operate all rams one-and-a-half cycles (close, openclose) at the maximum rated BOP working pressure

• All BOP’s will have telltale weep holes. Reason: If a seal fails the well fluids orgasses will leak at the BOP rather than travel through the system back to thehydraulic reservoir at the unit

Auxiliary Well Control Equipment

Hydraulic Quick Latches

Installed between the coiled tubing BOP and the stuffing box or riser, thehydraulic quick latch provides a safe and easy method of injector rig-up. Thedevice will incorporate a tapered seal bore that facilitates thestabbing/making the connection. When fully connected the quick latchprovides a positive engagement on the locking dogs as well as an externalindicator. An example of a quick latch is the Texas Oil Tools HydraConn.The quick latch is safer and saves time, as the operator does not need tostand and use their hands to align the flange or quick union.

Annular BOP’s

The annular BOP will close and seal blind on wireline, bottom holeassemblies and coiled tubing up to full-bore. Designed primary as a staticsealing element it will allow stripping into or out of the well. The annularserves as a redundant or backup seal for both the pipe and the blind rams andcan also be used in a deployment system.

Tool String Deployment System

The tool string deployment system allows long coiled tubing strings to bedeployed into a live well with out requiring an injector rig-up on top of along injector/riser configuration. The technique uses a wireline system totemporarily position the tool string inside the wellhead where it is remotelylatched on coiled tubing and run in the well, an Annular BOP can beincorporated in the configuration to aid deployment.



Quick Union and Flanges







Bottom Hole Assemblies

A key element of most coiled tubing jobs is the type of tool or combinationof tools that are needed to bring about a desired result. Many categories oftools exist; the common ones are covered in this overview. Each toolcategory contains various types of tools, but only the most used will bedescribed here. Tool functionality and BHA tool string design will bediscussed, but this is an overview and not intended to be used instead ofStandards & Practices.For specifications and information regarding sizes, material strengths andpressure limits, etc. consult the appropriate tool manual.

The tools covered have been categorized as follows:• Connectors• Valves• Disconnects• Locators• Centralizers & Stabilizers• Wash Tools• Downhole Separator• Impact Tools• Shifting Tools• Stiff Wireline Tools• Fishing Tools• Specialty Tools



Tubing End Connectors

Tubing End Connectors (TEC) are used to attach tools or tool strings to the endof the coiled tubing. There are many types and variations and there areoperating guidelines for which connector to use for a specific operation. Thesize of the coiled tubing is also a factor, as some connectors cannot be used withcertain coiled tubing sizes.The connectors discussed here are the ones most commonly used and includethe roll-on, external grapple and DimpleonTM.

Roll-onThe roll-on connector, fitted with threads on one end, is used to connect thecoiled tubing end to a tool or tool string. A double roll-on can be used to splicetwo coiled tubing strings together (in emergency situations) or to retrieve ahanging string. This connector is used primarily with smaller tool strings andjobs not involving torsion.

InstallationA roller is used to press the walls of the coiled tubing into groves that aremachined into the roll-on. O-rings are used to prevent leaks so the coiled tubingweld seam has to be removed prior to installation to prevent damage to the O-rings. The correct roller size and profile are necessary for correct installation.Over-rolling the coiled tubing, when installing the roll-on connector cansignificantly reduce the coiled tubing yield strength at the connection.

Operational Details• There is a correct roll-on fitting size for each size and thickness of coiled

tubing.• Roll-ons with sharp shoulders give variable performance. BJ roll-ons have

rounded shoulders.• Any thread type can be used.• The roll-on connector is an inline connector, so it does not normally increase

the OD of the coiled tubing but it does decrease the CT inside diameter.• This type of connector is not robust enough to be used in some kinds of

operations such as drilling, percussion or work that involves jarring,vibration and torsion or high axial load operations.



Figure 19 Roll On Connectors

Figure 20 Roll-on Connector

External GrappleThe external grapple is a robust connector that is recommended for milling,fishing and heavy duty coiled tubing operations. There are various models anddesigns but the BJ model gives the best performance.It consists of a grapple that bites into the coiled tubing. The number of slots inthe grapple varies between manufacturers and has a major effect onperformance. The grapple bites harder as the pull on the coiled tubing increases(unless not installed properly). A stepped design allows the grapple to bite allalong its length. The tubing should be cleaned prior to installation to ensure theO-rings seal properly. Several pull tests, using a C-plate, are normally needed toget a proper bite into the coiled tubing.



Designs that use set screws are inferior, as only one set screw tends to hold theapplied torque. The BJ and BDK models do not use set screws.

Operational Details• Since this tool increases the OD of the coiled tubing, it cannot be run through

the injector and stuffing box.• Used for all sizes of coiled tubing although not common for 1-1/4” (31.8

mm) and 3-1/2” (88.9 mm).• The grapple should be replaced after each job.• Grapple surfaces are hardened to enable them to bite.

Figure 21 External Grapple Connector

Dimpleon™This connector is an internal TEC and accordingly is flush with coiled tubingOD; note that it will therefore decrease the available through Id. The Dimpleonconnector is considered secondary compared to the BJ Grapple, as field studieshave shown, prolonged exposure to a H2S environment can cause the coiledtubing to crack in the dimple depressions.The connector slides inside the coiled tubing. The coiled tubing is dimpled intothe connector using a bushing and hydraulic press arrangement. The internalweld bead is removed using reamers.Note: Special fitting tools are required and the connector is CT wall-thicknessspecific.



Operational Details• Used for all sizes of coiled tubing.• Has larger through bores than conventional roll-ons.• Strong in tension and torsion.• Fitting is easier and more consistent than for roll-on or grapple connectors.• The connection is more resistant to H2S than the dimple or grapple

connection.• The connector can be reused.

Figure 22 Dimpleon™ Connector

Figure 23 Dimpleon™ Tools



Valves

Valves are an important part of a coiled tubing tool string and there are very fewapplications in which some type of valve would not be. The primary types thatare discussed here include check valve, sequence valve and dual activatedcirculation sub.

Check ValvesA check valve is required on all jobs, except reverse circulating operations.Check valves are installed as a precaution against back flow up the coiled tubingto surface. The two main types of check valves are the double dart and doubleflapper type.

DartA “double dart” configuration should be run on simple jobs with slick toolstrings. It cannot be used with a hydraulic release tool since its configurationwill not allow the passage of a ball.

Figure 24 Dart Check Valve Figure 25 Double Flapper Check Valve

Double FlapperThe double flapper check valve is the favored valve for most operations since ithas a full bore ID that can accommodate passage of a ball to activate a hydraulicrelease tool or other tools. It contains two cartridges each with a flapper andspring that provide a positive seal. It seals well at low and high pressures.

Operational Details• Both cartridges should be individually pressure tested at high and low

pressures.



• The cartridges should always be staggered by some angle but not completelyopposite to each other. This can prevent a ball from seating between them inhigh angle wells.

• Always placed above the disconnect tool in the tool string. This preventsflow up the coiled tubing when the tool string is disconnected.

Sequence

A sequence valve is a valuable tool that is generally under utilized. Typicaloperations where the tool is used are cementing, setting inflatable packers,drilling and any situation where coiled tubing collapse is a possibility.Coiled tubing collapse scenarios occur in high-pressure gas wells. The mostcommon use of a sequence valve is to provide hydrostatic pressure control inlow-pressure wells, or when a high-density fluid like cement is used.Pressure settings can vary with a spring and piston mechanism. Flow through asequence valve will only occur when the pressure at the tool is greater than thecombined pressure of the tool setting and the pressure outside the tool. Forexample, if the tool is set to 2000 psi and the bottom hole pressure is 2000 psi,then a pressure of 4001 psi would be needed inside the tool to allow flow.

Operational Details• Some sequence valves are suitable for abrasive fluids, such as cement; while

others have to be dressed with tungsten carbide inserts to prevent erosion.• Sequence valves can be stacked in the tool string to provide a higher overall

differential opening pressure.

Figure 26 Sequence Valve



Dual Actuated Circulation Sub

The main function of this tool is to divert flow and bypass the remainder of thetool string. This is often used after milling when the mud motor is bypassed toreduce wear on the motor and prevent scarring on the tubing during pull out. Italso permits higher flow rates to improve hole cleaning.The tool is dual activated such that a ball is pumped from surface which shutsoff flow. Pressure buildup causes shear pins to shear and shift a piston to opencirculation ports. Rupture discs are situated below the ball seat. If the toolstring was plugged so that a ball could not be pumped, then pressure could beapplied to rupture the disc. This results in a flow path so that a ball can becirculated down to the circulation sub or to a disconnect tool.

Operational Details• Placed below the hydraulic disconnect and above the mud motor in milling

jobs or remaining tool string.• Has large ID for high flow rates.

Figure 27 Dual Actuated Circulation Sub (Dump Sub)



Disconnects

Some method of disconnect is needed on most coiled tubing jobs since thebottom hole assemblies (BHA) are typically larger than the coiled tubing OD’s,thus potentially making them susceptible to becoming stuck.

However, disconnect tools may not be needed if the BHA OD is the same sizeas the coiled tubing (slick). Examples of types of jobs using a slick BHA wouldbe gas lifting or unloading fluid from a well.

For stiff wireline jobs the tool of choice is the Bakke flow release cable headtool. An advantage of this tool is that both flow and tensile load are required toexecute the release mechanism. This means that in the normal mode ofoperation, the shear pins are not subjected to an external load and unintentionalrelease is minimized.

Other tools include a shear release tool, which relies solely on shear pins and atension release tool that uses a spring loaded collet instead of shear pins. Thedisadvantage of these tools lies in the fact that the shear pins or spring have tobe set high enough to avoid accidental activation while still allowing release inall circumstances. This can be difficult in deviated or horizontal wells.

Bakke Hydraulic ReleaseThe hydraulic release tool is the tool of choice on all jobs not using an electricline in the coiled tubing. The tools on the market have been internally tested(CTRE) and the Bakke tool has been recommended as the best of all. Thesetools are able to withstand high tensile, torsion and shock forces and can be usedfor fishing and milling jobs.The ball is circulated down the ct and enters the tool and is caught in a ballcatcher, which is situated in a shear pin piston. The ball prevents further flowthrough the piston and the resulting differential pressure will build until shearpins are sheared. The number of shear pins determines the value of thedifferential pressure. Once the shear pins have been sheared, the piston movesdown to release the dogs holding the tool together. The coil then has to bepicked up to separate from the lower connector.

Operational DetailsIn order for the tool to work a ball has to be circulated down through the coiledtubing string. For this reason the coiled tubing reel should contain a balllauncher or a method of launching a ball. There are required minimum flowrates for each size ball and coiled tubing diameter in order to circulate the ball



around the reel and over the gooseneck. Once the ball is in the vertical section,pumping should be discontinued and the ball allowed to freefall. This is toavoid a water hammer effect when the ball seats in the tool. If the tool wassituated a considerable distance into a horizontal section, the ball may have to bepumped in order to reach the BHA.• The smallest hydraulic disconnect size is 1.75” (44.5 mm) which is suitable

for many jobs involving 1.25” (31.8 mm) or 1.5 (38.1 mm) coiled tubing.For larger coiled tubing sizes a larger hydraulic disconnect would be used.

• The Bakke disconnect leaves internal and external fishnecks.• Normally placed below check valves in the tool string. It can be run below

jars and accelerators.

Figure 28 Bakke Hydraulic Release Tool

Motor Head Assemblies (MHA)

Coiled tubing motor head assemblies have been developed to provide acompact, versatile upper BHA component that combines the double flappercheck valve, hydraulic disconnect and a dual circulation sub all in one tool.The tubing end connector is not incorporated in the tool, thus allowing forflexibility in connector selection.



Locators

Locators are used as part of the coiled tubing tool string to locate nipples inproduction tubing, the tubing end, crossovers or sliding sleeve profiles. Thelocators are used so the BHA depth can be determined precisely and the coiledtubing depth counter corrected. The easiest and most common method todetermine BHA location is by locating on a profile or the end of the productiontubing.In many jobs accuracy in depth measurement is necessary i.e. jetting acid acrossa small set of perforations in a deep well. Generally, the section of the well tobe treated will be close to the end of the production tubing. After correlating tothe production tubing-end the additional error in reaching the perforations istypically negligible. Many times it is not possible to tag TD of the well andcalibrate the depth counter as the well may be full of debris in the rat hole andtherefore TD is uncertain.Mechanical Depth Counters (odometers) are reasonably accurate although evenan accurate one (i.e. +/- 0.1 %) gives significant errors in deep wells.Odometers can be affected by debris or coating on the odometer wheel; fastrunning speeds may cause the odometer wheel to skip and introduce error.Stretch and temperature effects change the depth of the tool string. Largecompletions also have an effect as the coil tends to helix or corkscrew.

Tubing End Locator

This type of tool should not be run with expensive BHA’s such as perforationguns as they have been known to cause problems, Instead, a depth correlationrun should be made first and the coiled tubing flagged for reference.The tubing end locator that is typically used is a one-shot locator. A spring armremains collapsed as it is run through tubing, but opens after passing through thebottom of the tubing. As the arm is pulled back into the tubing a weight gainwill be seen on surface to indicate the end of the tubing and a shear pin in thetool will be broken to release the arm. An aluminum hinge pin is sometimesused to hold the arm and it can be broken if the arm doesn’t fold back properly.

Operational Details• The shear pin should always be changed before running in hole and it should

be checked to ensure it fits snugly.• Pull tests should be done carefully to prevent damage to the arm.• Debris can collect in the location of the arm and hinge to prevent the arm

from folding back properly.



• This tool should always be run below the disconnect tool.

Figure 29 Tail Pipe Locator

Nipple Locator

This tool can be used to locate most tubing nipple profiles. Normally, threeprofiled arms, attached to leaf springs, are used to locate the nipples. The armsare sized larger than the minimum nipple ID. The arms are also profiled orcontoured so that they pass through the nipple easily but require an overpull topull back through it. The leaf spring can be adjusted with a screw to increase ordecrease the amount of overpull.

Operational Details• The profile arms need to be gauged with a gauge ring. The tool should drop

through on its own weight. A load cell should be used to measure theamount of pull required to pull the tool back through the gauge ring.

• Leaf springs lose strength if they are used for a long time.• Not a good idea to use this tool as a tubing end locator as there may be

considerable drag while running in hole. A slightly smaller ID in the tubingcould cause a problem because there may be insufficient overpull availableto retrieve the tool string.



Centralizers & Stabilizers

Centralizers are used to center a tool string in tubing or casing. Without anycentralization, the tool string would tend to lie on the wall of the tubing, casingor open hole. This can make passage through restrictions such as landingnipples and side pocket mandrels difficult. Residual curvature in the coiledtubing is a contributing factor to this condition. Centralizers are used to providestandoff in perforating and jetting operations.

Stabilizers are often used to stabilize and centralize tool strings. They are usedfor milling, drilling and fishing operations.Centralizers and stabilizers can be fixed or hydraulically operated.Hydraulically operated types are more commonly used with coiled tubing.

Fluted Stabilizer

The fluted stabilizer uses fins that have shaped or rounded shoulders to providecentralization and stabilization. Fixed stabilizers are normally used when thereis no downhole restriction. Non-rotating stabilizers are more common and theyreduce whirling generated from rotating equipment.

Operational Details• The minimum number of fins to give reasonably good centralization is five.

More fins than five or six could create a flow restriction problem.• Typically run below the disconnect tool and above the motor in milling jobs.• Often used in pairs to provide added stability in drilling operations.

Figure 30 Fluted Stabilizer

Bow Spring

A collapsible centralizer designed for slick tool strings. Some models fit overthe tools or coiled tubing. Bow springs collapse in the restriction and expand to



full OD once past the restriction. Should not be used with coiled tubing due tonumerous problems, such as, trapped debris in spring arm and spring armsfailing in the well.

Operational Details• Needs to be robust.• Disadvantage is that there can be a significant amount of wear when running

through the completion.• Long, thin bow springs do not centralize well.• It is possible to become stuck when pulling back into the production tubing.

Figure 31 Bow Spring CentralizerHydraulic Bow Spring / Stabilizer

This tool is designed for use with coiled tubing as it can be run through small IDtubing and then activated in large ID casing. The bow springs are shorter,thicker and stronger than conventional mechanical bow springs.It is run through tubing and restrictions in a retracted position. Pumping throughan orifice creates a pressure drop and causes a piston to open the springs.Larger orifice sizes can be used to allow more flow through the tool withoutactivation.

Operational Details• Capable of large expansion with a small retracted diameter.• Expansion of the springs can be adjusted.• The bulk of the load is usually at the base of the bow springs, so these areas

should be checked for cracks.• Typically run below a hydraulic disconnect tool and a dual actuated

circulating sub.



Knuckle Joint

Knuckle joints are used in long tool strings to provide flexibility. This may beuseful in maneuvering through tight bends in deviated and horizontal wells.Sometimes they are used in conjunction with a hydraulic centralizer in fishingoperations as they reduce the weight that the centralizer has to support.Problems have been associated with their use. Some designs have flat shouldersthat can hang up on restrictions. They are usually the weak link in the toolstring. Pump pressure can reduce the bending that does occur. Two knucklejoints can be used but are not recommended. Lock up can occur when twoknuckle joints are used.

Operational Details• The knuckle joint will pivot to maximum of 11 degrees.• Single and dual types are available.• In fishing operations they are positioned above a centralizer.

Figure 32 Knuckle Joint



Wash Tools

The type of wash tool used depends on the application. Applications rangefrom simple fluid displacement, to filter cake removal, to difficult scaleremoval. Lift assistance may be necessary with the use of nitrogen. Otherfluids that may be pumped include gelled water, foam or acid. Completion sizeand type will affect the choice of nozzle although a variety of sizes are availablefor each tool.

Cleanout Nozzles

These types of nozzles include straight jet, jet down, jet up and tangential. Thechoice of nozzle orientation is chosen based on the type of job. Most often theyare used for gas lifting, sand cleanouts and spotting fluids such as acid andcement. These jets are not effective for removing filter cake or scales. Thenozzles usually have 5 ports and forward jetting is often optional.

The straight jet nozzle has a single forward jetting nozzle that allows a high flowrate with low backpressure. This nozzle is used when it is necessary to circulatefluids at high rates such as cement or when ‘bullheading’.

Jet down nozzles are used to jet fluid on the wellbore sides. Normally have 5ports, four sets at 30-degree angles from the tool centerline and one forward topenetrate fill (optional). This nozzle may be used for acid washes.

Tangential jets are used to maximize jetting contact with the completion as thejets exit the tool tangentially. Tangential jets provide good mixing of the fluidsin the wellbore. These are also used for acid washes and cement placement.Vortex Nozzle

The Vortex nozzle generates a vortex or fast swirling mass of fluid in thecompletion tubular or open hole. Rotational speeds of the vortex can exceed8,000 rpm. The vortex entrains debris, which improves hole cleaning. TheVortex nozzle is normally used for cleaning wax from tubulars, washingperforations or washing mud filter cake from open-hole well bores. It iseffective against some scales.The tool uses 4 tangentially offset nozzles. The nozzles are more efficient thanconventional designs because specially designed flow guides ‘pre-swirl’ thefluid and jet orifice geometry has been optimized.



Operational Details• The tool is available in a number of sizes {1-3/4” (44.5 mm), 2-1/8” (54

mm) and 2-7/8” (73 mm)} with 3 jet orifice sizes (A, B, or C).• A downhole magnetic filter should always be used with the Vortex nozzle.• The Vortex nozzle is placed below check valves and hydraulic disconnect

tool in the tool string.

Figure 33 Vortex Nozzle

Figure 34 Cut-away of Vortex Nozzle



Roto-Jet™

The Roto-Jet™ tool delivers a powerful jetting stream that can be used toremove hard scales, waxes, filtercake and tar. The nozzles rotate at controlledspeeds to create stress cycling in the scale or filter cake.The components of the Roto-Jet™ consist of a downhole filter, a governorsection, a turbine section, upper and lower bearing sections, and a jetting mole.The turbine section consists of stator and rotor stages. Momentum transfer fromthe pumped fluid causes the rotor shaft to turn. The governor section consists ofrare earth magnets attached to the drive shaft and housed in a copper tube. Therotating magnets induce an electric field. Eddy currents are created in thecopper tube, which resist rotation and prevent over speeding of the shaft. Thejetting mole is connected to the bottom of the turbine shaft and has two jetnozzles. Careful design of the internal flow geometry and orifice geometry hasmade these nozzles extremely efficient.Two different nozzle sizes are available for the Roto-Jet™ tool. One is directeddown at 45 degrees (R45) to the tool axis and the other is at 90 (R90) degrees orperpendicular to the tool axis. The number of magnets may be varied to givethe required rotational speed for a given flowrate.

Operational Details• Each tool size has minimum and maximum flow rates.• An option is available to put all the flow through the turbine or divert a

portion through the turbine shaft.• All types of fluids or nitrified fluid can be pumped through the tool except

toluene.• Nitrogen does reduce the coherence and effectiveness of the jet stream. The

downhole separator should be considered for use with the Roto-Jet™ toolwhen nitrogen is necessary.

• The tool generates only 8-12 ft-lbs (10.8 – 16.3 N*m) of torque, thereforecannot be used in a ‘drilling’ mode.

• The Roto-Jet™ tool is run below check valves and a hydraulic disconnecttool.

• A surface and downhole filter are required when running the Roto-Jet™ tool.• A downhole magnetic filter must always be run.



Figure 35 Roto-Jet ™ Tool



Venturi Junk Basket

The Venturi junk basket is used to clean large debris from vertical andhorizontal wells, i.e. debris that cannot be removed conventially becausesufficient velocities are not possible.The tool uses a venturi effect. Fluid or gas is pumped through one or two smallnozzles which creates a pressure drop within the tool. The fluid exiting thenozzle(s) passes into the wellbore and helps to stir up debris at the front of thetool. Fluid and debris are drawn into the tool and trapped between a screen anda trap door.

Operational Details• Only a small pressure differential is necessary to fill the basket.• Extensions on the tool of 100 ft or more can be used.• Can be run under a motor to pick up debris from a milling operation.

Figure 36 Venturi Junk Basket



Downhole Gas Separator

The downhole gas separator is used to separate gas from fluid above a jettingtool or motor. This is useful since nitrogen is often needed to maintain anunderbalanced condition in the wellbore but detracts from the performance ofthe tool. The Roto-Jet™ tool is the best example of this. Another example iswhen the maximum rate allowed through the BHA, such as a motor, isexceeded.A centrifugal action is created within the tool, which separates most of the gasfrom the fluid. The gas is dumped into the wellbore while the liquid continuesout the bottom of the tool. The pressure drop in the tool is small and less than2% of the gas is carried through with the liquid. The best performance from thetool is maintained when the gas ratio is between 25% and 75%.

Operational Details• Tool sizes that are available are 1-3/4” (44.5 mm), 2-1/8” (54 mm) and

2-7/8” (73 mm).• There are maximum combined flow rates for each size.

Figure 37 Downhole Gas Separator



Impact Tools

Impact tools are used to provide mechanical force to objects. They are usedextensively in fishing operations, pulling plugs and for special operations suchas opening sliding sleeves. These tools include impact hammers, jars,accelerators and shock subs. They can be used in vertical and horizontal wells.

Important Note:A shear pin release tool cannot be used with impact tools. The coiledtubing, coiled tubing connector and release tool have to be properly sizedfor the size of impact tool being used.

Impact Hammers

Also known as a “hydraulic percussion drill”. This tool acts like a jackhammerto provide downward jarring force. They are typically used for opening slidingsleeves, pulling plugs or for fishing operations. The quick repetitive blows areuseful for jarring/vibrating plugs free. Generally, hammers are more effectivethan jars for generating downward force. Dual acting impact hammers are alsoavailable that will provide upward impact as well as downward impact.When the tool is not tagging anything, circulation is through the tool. As soonas the tool tags and weight is applied, circulation stops and the pressure insidebuilds causing the tool to stroke back until circulation ports open, then the tooldrops with considerable force back into the closed position. The stroke is smalland the frequency of impact varies according to the flow rate and set downweight. Higher flowrates result in increased impact frequency but not harderimpacts. Pull up weight is necessary to activate an upward force for bi-directional hammers.The tool operates with water, acid or nitrogen. Acid should be inhibited.

Operational Details• Shock subs or accelerators should always be used with impact hammers.• Sizes vary from 1-1/16” (43 mm) to 6-1/4” (158.8 mm).• A Double flapper check valve and heavy duty hydraulic release tool should

be used.• A fit for purpose bit may be used on the end of the hammer, depending on

the type of operation.



Jars

There are two types of jars, mechanical and hydraulic, and they are used toprovide a powerful upward impact. The hydraulic design is more effective andnormally used. Bi-directional jars that fire downward as well as upward, areavailable. The design of jars and accelerators for a specific application isdifficult so it is very important that the services of a qualified and experiencedjar company be employed.The hydraulic jar is cocked or loaded by pulling up on the coiled tubing. Thiscauses a piston to move in the jar, which transfers oil in a chamber from the topto the bottom. The piston pulls slowly in a restricted area but accelerates once itclears the restricted area to provide impact energy. The amount of overpull withhydraulic jars does not affect impact energy as it does with mechanical jars. Abypass port allows the jar to be reset quickly. Bi-directional jars require setdown weight to fire downward.

Operational Details• Accelerators are always used with jars and they have to be compatible. A

weight bar is normally placed between the jar and accelerator to increase theimpact energy.

• Bi-directional jars may not be suitable with coiled tubing in all cases sinceenough set down weight may not be available to impact downward withsufficient force. An impact hammer may be a better choice for applicationsneeding downward force.

• A jar stroke length is about 6 inches. The stroke length of accelerator isusually 7-8 inches (177.8 – 203.2 mm) and it must exceed the jar strokelength to be effective.

• Oil used in jars is chosen based on bottom hole temperature and availableoverpull. The oil heats during jarring and needs time to cool.

• Disconnect below the jars if possible (disconnect ball must be ableto pass through jar.

Accelerator

Accelerators are used to accelerate or intensify impacts during jarring operationsand also protect the coil tubing and tool string from damaging shock waves.Mechanical and hydraulic types are available although the hydraulic design isnormally used.



The accelerator is either oil or gas filled and it acts like a spring. The stroke ofthe jar releases the energy stored in the accelerator. The accelerator provides thegreater part of the total energy released by the jar/accelerator combination.

Operational Details• Positioned above weight bars and jars.• Disconnect below accelerator and jars if possible (disconnect ball must be

able to pass through jars and accelerator).

Shock Sub

A shock sub is used to cushion the blow from impact hammers and protect thecoiled tubing and coiled tubing tool string. They use disk or beveled springsthat compress and release.

Operational Details• Disconnect below accelerator, jars and shock sub if possible (disconnect ball

must be able to pass through jars, accelerator and shock sub).

Shifting Tools

Shifting tools are used to open and close sliding sleeves. These can be invertical or horizontal wells. Examples of the tools that are commonly employedfor this service are the Baker HB-3 and Power Stroker.

HB-3Designed to work on Baker HL and CM type sliding sleeves. The tool isdressed to shift either up or down.Circulation is through the tool while RIH. An increase in pump pressureactivates the tool by compressing a spring, which allows a second spring toextend a set of linkage arms radial. These arms latch into the sleeve insert. Thesleeve can be shifted up or down by pulling up, setting weight or by using animpact tool. Once the sleeve is shifted, the shifting tool releases. Decreasingthe pump pressure causes the linkage arms to retract so they should not contactthe completion tubulars.

Operational Details• Activation pressure is low.• Depth control is necessary.



Power Stroker

This tool can be used in conjunction with the HB-3 shifting tool. It anchors in atubing profile after the HB-3 has located the sleeve. Pump pressure in the toolgives a downward force to assist the HB-3 in shifting the sleeve. It can be runbetween HB-3 shifting tools to enable sleeves to be opened and closed with onerun. It has an emergency shear release.



Stiff Wireline Tools

These are used to connect tools requiring an electric line to coiled tubing. Usedprimarily in logging and perforating operations, and also for electrical-settingpackers.The Bakke flow release cable head tool has replaced the stiffwireline connectorand tension release tool in most operating locations.

Bakke Flow Release Cable Head Tool

The Bakke flow release cable head tool is used for stiff wireline jobs involvingperforating, logging and setting plugs. The tool is designed to withstand shockfrom heavy perforating guns and can carry heavy loads. It contains an anchorfor a stiffwireline cable, double flapper check valves and a hydraulic releasemechanism.To activate release, fluid is pumped through nozzles to create a pressure drop.The pressure drop is transmitted through a tube to a spring-loaded piston. Themovement of the piston causes mechanical slips to release. The tool’s releasecan then be accomplished by applying a tensile pull to shear pins. The numberof shear pins and nozzle sizes can be adjusted to suit job conditions.

Operational Details• The shear pins do not see any load during normal operations.• Tool is set up so as to ensure its possible to achieve pressures 20% higher

than the required release pressure.• When pressure testing in the riser the pressure has to be bled off slowly so

that the tool does not experience a higher pressure drop than its set value.



Fishing Tools

Items that fishing tools may be used to retrieve include broken or stuck tools,packers and plugs, coiled tubing and junk in a well. There are many methodsand types of fishing tools but the most common types used with coiled tubingcan be grouped as spears and overshots. Hydraulic releasing spears andovershots have been designed specifically for coiled tubing and they are a muchbetter choice than conventional wireline type fishing tools.Generally, specific fishing tools are used for specific tasks. Sometimes a fishhas to be dressed by first latching on with a spear or overshot and thenactivating the hydraulic release tool to leave behind a standard fishing neck. Ora motor and mill may be used to dress the fish and make it retrievable.It is very important that information about the fish be known, such as internaland external dimensions, length and material hardness. This type of informationshould be documented for each tool in the tool string before it is run into thehole.Fishing tools are commonly run with jars and accelerators or impact hammers.Normally, two hydraulic disconnects should be run when jars and acceleratorsare used for fishing. One would be placed above and the other below thejar/accelerator combination. If only one hydraulic disconnect is available, itshould be run below the jars. Jars should never be left behind because theyare very difficult to fish.Other coiled tubing tools that may be used to assist in removing an objectinclude motors, bits, centralizers, knuckle joints, indexing tools and bent subs.

Spears

Spears are used to engage internal fishnecks that may be either a standardsize or slick. Hydraulic spears are typically used with coiled tubing. Aspear, such as an ITCO type, is not good for CT fishing because it can not bebacked off but it may be used to bait a fish. In this case it would be run witha disconnect tool that has a standard GS fishneck. A GS hydraulic releasingspear is used to fish a GS internal fishneck.

Hydraulic Releasing Spear

These tools can be pumped through. A hydraulic releasing fishing neck spearuses collets to latch into the profile of the fishneck. A slick ID hydraulicreleasing spear uses grapples or slips to catch the slick ID fishneck.



In either case, the spear is run as far as possible into the fish. A small set downweight releases the collets or slips, enabling them to latch on to the fish. Anincrease in flowrate detaches the collets or slips from the fish.The material of the slips has to be harder than the fish in order to grab into it.The collets may also be hardened.

Figure 38 Hydraulic Releasing Spear

Fishing Overshots

The overshot is a versatile and efficient fishing tool that is widely used. Thereare many different types but common ones are listed below. They will latch onto standard fishnecks or slick OD objects. Some overshots are designed toswallow coiled tubing and cut coiled tubing. Various types of shoes and guidescan be used to help to locate the fish.These tools are designed to withstand stresses that result from jarring. Flowthrough the tool washes debris from the top of the fish.

Hydraulic Releasing Overshot

This tool can be used for fishing a slick OD fish or grabbing a standard fishingneck. An overshot with collets is used to latch a standard fishing neck whilegrapples are used to engage a slick OD fish.A small set down weight releases the collets or grapples allowing them toengage the fish. The fish can then be pulled or jarring initiated. If the fish will



not release, the pump rate can be increased to disengage the collets or grapples.Jarring down may be necessary to break the grip from the grapples. Thematerial of the grapples has to be harder than the fish in order to bite.

Figure 39 Hydraulic Releasing Overshot

Bowen Fishing Overshots

The overshot can be dressed with either a spiral grapple or a basket grapple.The spiral grapple is used when the diameter of the fish is close to the maximumcatch diameter of the overshot. The basket grapple is used if the fish isconsiderably less (1/2”) than the maximum catch size. As the tool is loweredand engages the fish, the grapple expands allowing the fish to enter it. Then,with an upward pull, the grapple contacts the fish and the wickers bite into it.

Operational Details• Extra length may be put on the front to swallow more of the fish.• A cut lip guide on the end of the overshot with a kick off tool, indexing tool

or motor may be used to assist in locating a fish. A hollow mill may be runon the end to mill on to the fish.

• A mill control packer may be used with a basket grapple to lightly dress thefish before it is engaged although it is not normally used with coiled tubing.



Figure 40 Bowen Overshot

Continuous Coiled Tubing Overshot

This tool is used when the fish is coiled tubing. It may be run with an extensionas it is advantageous to grab the coil as far down as possible. Once the overshotis over the coiled tubing it will engage when the tool is raised. The grapple doesnot put a high compressive load on the coiled tubing.

Operational Details• A cutlip guide or mill guide may be used below the overshot to help locate

and bait the fish. Once the overshot is latched on a shear disconnect wouldbe sheared leaving the baited fish.

Kick-Off Tool

The kick-off tool is a reliable and versatile tool that is used to assist the BHA ingetting past obstacles or restrictions such as landing nipples, gas lift mandrelsand liner laps. To be effective, it has to be used with a kick-off (or mule shoe)nozzle or shoe.When an obstruction is tagged, the tool compresses and an internal key slotcauses it to rotate. A beveled shoe or nozzle on the end of the string deflects the



tool and enables it to clear the obstruction. The tool then resets to its normalposition.

Figure 41 Kick-Off Tool

Indexing Tool

An indexing tool is used to rotate the BHA through a fixed angle. This can beused for getting past an obstacle, orienting an overshot onto a fish or possiblyentering different legs in multi-lateral wells.When an object is tagged the applied force or pressure moves a spring loaded J-slot, which rotates the tool. When the pressure is released, the indexing pinacquires a new position in the J-slot. This process can be continued until asuccessful orientation is found. Another version of this tool works on pressuredrop caused by flow.

Operational Details• Rotating angles usually 15 or 30 degrees.• Tool often used with bent sub or centralizer in larger ID’s.• Tools that work with set down weight could be a problem since the pin in the

J-slot has to handle the entire load (and it won’t take a big load).• A kick off tool may be a better alternative in some instances.

Straight Bar / Weight Bar

A straight bar is used to assist a tool string to pass through restrictions orobstructions by providing a straight section below the coiled tubing. The coiledtubing normally retains some residual curvature which can affect a tools abilityto pass a restriction.



Because straight bars are thicker walled they cannot be sheared with the BOPrams and they should not be confused with deployment bars which are meantfor locating the tool string in the BOP's and which can be sheared with the shearrams.

Impression Block

This is a pump through tool with a lead block that is used in fishing operations.The impression left on the block after tagging a fish may assist the operators indevising a strategy for recovering the fish.

Wire Rope Spear & Stop

This tool is used for fishing wireline. Barbs on the spear help to grab and holdthe wireline. A stopper on the top of the tool prevents wire from bypassing thetool. It is often run with a motor so the tool can be rotated. Over rotationshould be avoided, as a large wire bundle on the spear may be difficult to pullfrom the hole with the coiled tubing. A hydraulic disconnect is run above thetool.



Specialty Tools

Parabow

The parabow tool was designed for cement plug applications utilizing drill pipeand has been adapted for use with coiled tubing. It is an inexpensive buteffective method of providing a stable base for cement plugs, therebyeliminating gravity segregation or ‘density slumping’ from occurring.Activation of the tool is initiated by circulating a ball; this shifts the circulationports and allows the parabow to extrude from the tool and expand across thewellbore. There has to be fluid below to prevent the parabow from slippingdownhole.

Figue 42 Parabow Tool

Sand-Vac / Well-Vac

This tool consists of a modified jet pump and it is run on concentric coiledtubing. It can operate in cleaning or production modes and is used primarily forremoving sand and drilling fluids from heavy oil horizontal wells.In cleaning mode, external jets are used to fluidize sand and debris ahead of andbehind the tool. In production mode the external jets are shut off to maximizeproduction from the well. A lowering of the pump rate causes the tool to shiftfrom one mode to the other. Typically, the tool is run in hole in cleaning modeand pulled out of hole in production mode.Fluid is pumped through the inside string while returns are up the annulus of thetwo strings. The primary components of a jet pump are a power nozzle andthroat and it works by energy conversion. High pressure passes through thenozzle where it is converted to a high velocity and low pressure stream. Thisinduces flow from the well. The combined flow passes into a throat and



diffuser where velocity is slowed and pressure increased high enough toovercome hydrostatic pressure.The current concentric coiled tubing string configuration is 1-1/4” (31.8 mm) in2-3/8” (60.3 mm). The tool OD is 3-3/4”. Different sizes of power nozzles andthroats are available.

Figure 43 Sand-Vac / Well-Vac Tool



Tornado

BJ Services specifically developed its Tornado coiled tubing wash tool aspart of an improved process for well clean-out operations. Used inconjunction with BJ’s Tornado job design software, CTran, thisrevolutionary process provides a highly effective means for removing sandand familiar material from deviated or horizontal wellbores. The Tornadonozzle diverts the flow of jetting fluid in either direction; forward facing jetsto break-up compacted fill while running in the hole and then cycle to thebackward facing jets to efficiently sweep fill from the low side of the wellwhile pulling out of hole –wiper trip. Ctran software calculates how fast thecoiled tubing can be run into the fill and how quickly the coiled tubing canbe pulled out of hole in reverse cleaning mode. The tool is the market leaderin fill removal and with Ctran pre-job modeling, effective fill removal isassured – virtually 100%.

Figure 44 Tornado Tool Process, as Simulated by CTran



Straddle Packer

The 3” (76.2 mm) straddle packer tool is used to isolate perforated zones oropen hole to allow placement of stimulation fluids. It can be reset up to 20times for multi-zone treatment. It will seal in as large as 6-1/4” (158.8 mm)hole. Circulating at a pre-set flowrate activates it; a valve mechanism preventsover-inflation of the packer elements. Pulling up the coiled tubing causes thepacker elements to deflate and the tool to reset – time must be allowed for theelement to deflate fully prior to moving the tool in the wellbore, thus preventingelement damage. The packer elements are rated to a temperature of 284 °F (140°C).

Figure 45 BJ Straddle Packer (showing 1 packer element)



Coiled Tubing Manufacturing

The text in this section has been extracted from the Quality Tubing, Inc. web site.Manufactured coiled tubing strings are designed to specified-length strings ofhigh quality materials, suitable for field operations.

In order to produce long lengths of pipe, QTI welds steel strips together, andproduces pipe from the strip by the high frequency induction (HFI) electricwelding process. This section of the Technical Catalog describes how QTI'spipe is produced from steel strip, and the testing procedures to which both thestrip and pipe are subjected before release to the customer.

Early DesignsThe original idea for coiled tubing came from the project "Pipe Line Under theOcean" (PLUTO) where range II line pipe was butt-welded, rolled onto spools,and laid from boats under the English Channel in 1944 to support the Normandylandings. Coiled tubing continued to be produced by butt-welding on arelatively small scale into the 1960s. The weak link in this form of continuouspipe is the butt-weld; it causes structural weakness and restricts internal flow.

A high percentage of the failures that occur over the life of butt-welded pipe are,breaks that occur in the heat affected zone adjacent to the weld bead. Thematerial in this area fatigues much more rapidly than the parent material,especially in a sour gas environment. The internal circumferential weld bead,which is not generally uniform due to the effects of gravity, restricts fluid flowand causes turbulence. It also restricts operations that require pumping tools orsteel balls through the tube.

Figure 46 – Butt Weld



The Quality DifferenceBecause of the deficiencies of the butt weld, QTI introduced two new ideas.First, a patented strip bias weld process for joining two strips before the tube ismanufactured was introduced. Second, by purchasing premium class coils instrip form, QTI was able to drastically reduce the number of welds in a string oftubing. Thus in some sizes of material, the welds may be over 1000 m (3280 ft)apart. These developments eliminated the weak links and dramatically improvedthe reliability of coiled tubing in the field.

Starting From Flat StripQTI purchases hot rolled coils of flat strip from major approved suppliers. Coilsare rolled to specific sizes and tolerances. Each coil is then split into the requiredstrip widths for pipe production, again to specific tolerances. In the case ofQTI's TRUE-TAPER product, the strip will be thicker at one end than at theother. QTI can then join strips of equal thickness thickness at each end reducingthe stress concentrations caused by non-uniform load transfer when joiningdiffering gauge material.

Patented Strip, Bias Weld ProcessIn 1989, QTI patented a strip welding process that is shown schematically inFigure 1-3 (US patent 4 863 091). The edges of strip to be welded are carefullyprepared by shearing at a fixed angle, and then welded by computer-aidedwelding machines. This strip weld is stress relieved and inspected non-destructively by visual and x-radiographic processes. Customers may alsospecify magnetic particle inspection. The x-radiographic process, which isperformed either with high speed film or a digital real-time X-ray device, iscontrolled ultimately by an ASTM penetrameter and meets or exceeds therequirements of ASME Section V and API 1104. Due to the sensitivity of theinspection technique, no imperfections are permitted in downhole materials inthe region radiographed. Welds for our QTP-52, (Line Pipe grade material),QT-700, QT-800 and QT-1000 (Downhole materials), and HO-60 (Hang offmaterials) are made in this manner. The weld is dressed, stress relieved, andhardness testing is then performed in three regions. These regions are the welditself, the heat affected zones, and the parent metal on either side of the weld.The hardness testing meets the requirements of ASTM A-370 and ASTM E-18.



Finally, at customer request, the weld may be uniquely identified by acidetching. The entire process is shown in Figure 1-4. Upon milling, the weld isdistributed along a helix in the finished tube. This geometry distributes themechanical stresses experienced by the weld zone over the length of the helixrather than concentrating all of the stress in a single narrow band around thecircumference of the tube. The performance of this type of weld is now provenin numerous applications in oil and gas wells, and in pipelines throughout theworld.

Figure 47 Strip Bias Weld

Figure 48

The Forming OperationPipe is manufactured from strip by the use of high frequency electric welding.First, the forming rolls of the mill are set for the diameter of the pipe. The firstseries of rolls encountered by the strip start bending the edges of the stripupwards, gradually forming a "U" shape. The next series of rolls have vertical



fins which extend down past the strip edges. The strip is worked against thesetungsten carbide fins to prepare them for the weld rolls. This is shown in the lefthand part of Fig 4.

Welding the TubingThe formed strip enters a high frequency induction welder where it passes into acoil excited by high frequency current. This current causes magnetic fieldswhich in turn cause eddy currents to flow both around the longitudinal weldedtube and back into the area where the strip is coming together. In this process,the heat for welding the edges is generated by the resistance to the flow of theseeddy currents, which are concentrated at the edges by an internal ferrite corecalled an impeder. In this HF process, the heat is confined to a narrow bandalong the edges of the formed strip. A special set of insulated rolls squeeze theedges together while they are at the fusion temperature to produce the weld. Inthis process, no filler metal is added, keeping the metal composition of the weldline the same as the body of the tube.

During the welding process, the tube is welded slightly oversized, and thenreduced to final specifications in a set of sizing rollers. The tolerance on theouter diameter produced by this process is +/- 0.010 inch.

Flash RemovalThe application of pressure in the fin pass rolls causes hot metal to be extrudedtowards the inner and outer diameter of the tube. Outer diameter flash isremoved with a carbide cutting knife that is contoured to the diameter of thetube being produced. At customer request, inner flash is removed from pipewith IDs greater than 1.25 inches with a contoured cutting tool. This flash issubsequently pumped out of the tube.

Inner surface flash removal leaves a slight groove, which does not reduce thewall thickness below the specified minimum wall. The finished flash removalprocess produces tubes the dimensions of which meet or exceed therequirements of API 5CT, API 5L, and API RP 5C7, the RecommendedPractice for Coiled Tubing Applications.

Figure 49 Scarfing Tool



Seam AnnealerThe longitudinal weld seam is immediately heated to 1650 deg. F by a narrowinduction head in order to austenitize the weld and its heat-affected zone. Thisarea will then have a uniform grain structure throughout.

Full Body Stress ReliefHeat treatment is performed in a full body stress reliever, in which the tube isheated to a predetermined temperature in the region of 900-1300 deg F for aspecified time, determined by the final desired mechanical properties of thematerial. After air cooling and a final water cooling, the tube is wound onto astorage spool.

Standard Services to Coiled Tubing

String Length Measurement: The length of the string is continuouslymonitored throughout its production. The customer is provided with a length oftube which complies with +/- 1% of the specified length on the order, unless thisrestriction is waived by the customer. The finished string may be shipped on ablue QTI spool, bearing a QTI number, or transferred to a customer service rigin our covered service area.

Welding Fittings: QTI will weld fittings onto finished tubing as requested bythe customer – most common are 1502 2” WECO Thread. An externallaboratory approves the welding procedures used for welding for each steel typeand grade fabricated at QTI. Once welded, the integrity of the weld is verifiedby one or more of the following nondestructive testing techniques:

• X Radiography

• Magnetic particle inspection (ASME Section 5, Article 7)

• Liquid penetrant inspection (ASME Section 5, Article 6)

• These inspections may be performed to QTI's written practices or customerrequirements.

Tube-to-Tube Welding: In cases where the customer requires two shorterstrings be joined together, and will accept a tube-to-tube weld, QTI will perform



the weld to written procedures using qualified welders. Should the customeraccept butt-welded sections of QT-700, QT-800 and QT-1000, they will beclassed QT-70, QT-80 and QT-100 material respectively. Hangoff material andpipeline product may also be butt-welded.

Nitrogen Purges and Blankets: Nitrogen is pumped through the coiled tubing,when the tubing is expected to be shipped overseas, or stored indefinitely, theends are capped to maintain a blanket of nitrogen gas to help prevent the onsetof internal corrosion.

Crating: Should the customer require shipment on a QTI spool, the spoolmay be shipped as is, or crated for export.

Quality Tubing Pipe Sizes -Grades



Coiled Tubing Fatigue Theory

Coiled tubing may be considered a consumable product in the coiled tubingbusiness line. As coiled tubing moves off and on the reel and passes over thegooseneck; fatigue is imparted on the coiled tubing. Ballooning of the coiledtubing may also occur. The number of bend reversals to pipe failure ormaximum ballooning is dependent upon the following factors:

• Bend radius

• Internal pressure

• Pipe material

• Imperfections

Bend RadiusThe tighter the bend radius the high the strain on the coiled tubing. As the bendradius decreases the number of cycles to failure decreases.

Internal PressureAs the internal pressure increases the hoop stress imposed on the coiled tubingincreases. As the pressure inside the coiled tubing increases the number ofcycles to failure decreases. The failure characteristics for the various grades ofcoiled tubing will be different. Also, failure characteristics may be differentbetween manufacturers of coiled tubing ie. QT-800 does not have the samefatigue characteristics as HS-80. For most materials as the pressure increasesballooning becomes much more predominant than fatigue.

Pipe MaterialThe fatigue life characteristics of coiled tubing will vary depending upon thegrade of material and the manufacturer of material. Presently Precision TubeTechnology and Quality Tubing Inc. are the two suppliers of coiled tubing. Thehigh carbon, low alloy steels used to make the coiled tubing are typicallyclassified by their minimum yield strength ie. 70 ksi, 80 ksi 90 ksi etc. Thefatigue characteristics for each grade of pipe will differ as well as the fatigue lifefor an equivalent grade of pipe may differ between suppliers.



ImperfectionsThe origin of a fatigue failure is typically some sort of imperfection in the pipe.An imperfection in the pipe may be due to manufacturing methods, heattreatment, environment, handling, residual stresses etc. Imperfections result instress risers. Increased stress translates into accelerated fatigue. A commonstress riser may be a nick in the pipe or corrosion pit.

Failure Due To FatigueA fatigue failure usually begins with the development of a small cracktransverse to the direction of tensile stress. The movement of the pipe on and offthe reel and over the gooseneck results in the coiled tubing being subjected toalternating stress. Alternating stress causes the crack to open and close.Eventually the material is reduced to such a small area that it can no longerwithstand the forces and breaks. Characteristically, the higher the internalpressure the more prominent the crack propagation. A cycle is defined as 6 bendreversals. These reversals are shown in

Figure 50 Fatigue Failure



Figure 51 Fatigue diagram showing 6 bends making 1 cycle

Bend 3: Enter Injector Bend 4: Exiting Injector

Bend: 5 Exiting Gooseneck

Bend 6: Entering Reel

Bend 1: Exiting Reel

Bend 2: Enter Gooseneck



BallooningBallooning is described as the diametrical growth of the coiled tubing. As thediameter grows the wall thickness decreases. A decrease in wall thickness for agiven pressure will result in increased hoop stress, which in turn magnifies theballooning and fatigue of the coiled tubing. Ballooning will also cause the coiledtubing to be less resistant to collapse pressure. Excessive ballooning will resultin the coiled tubing exceeding the stuffing box tolerances. This may result incoiled tubing damage or stuffing box brass damage. The maximum allowableballooning limits are as follows:

BJ Service’s Maximum Allowable Ballooning LimitsCoiled Tubing Size (O.D.)

(in.)Ballooning Limit

(in)1.75” or less 0.05”

Greater than 2.00” 0.07”Maximum Allowable Ballooning Limits

Being that ballooning is the diametrical growth of the coiled tubing, it can bephysically measured. Ballooning is typically measured in thousands of an inch(1/1000”).

As in the previous example, we can increase coil life by roughly 50 cycles if weenlarge the gooseneck to 90" or so. The existing large drum core diameterallows us this option without make any drum core modifications.

Enhancing coil life can be accomplished by simply increasing the goosenecksize, but do logistical issues and modification costs outweigh the benefits? Thatis an operational issue.

Other Ways to Increase Coil Life

• Another way we can increase coil life is to increase the wall thickness. Thisreduces overall hoop stress, which increase the number of cycles to failure.It also increases pipe cost, pipe weight, spool weight, and requiredinjector/spool torque. In order to investigate which is more effective -increasing wall thickness or increasing drum core / gooseneck radius.



• Increasing wall thickness has a greater effect when cycling at high pressureas opposed to low pressure. This is because the thicker walls reduce hoopstress which decreases the effects of dilation.

• For thin walled pipe at high pressures, increasing goose neck radius beyond90" has minimal effect on cycle fatigue. This is because dilation is thedominant damage mechanism for which goose neck size has little effect.

• At high pressures, increasing goose neck size only impacts cycle fatigue ofthick walled pipe. Chances are entire spools of thick wall pipe will never beused, but this information is still applicable to taper strings, where cyclingnormally occurs over the heavier walled portion of the string.

• At lower pressures, increasing goose neck radius has a greater effect thanincreasing wall thickness. For example, Unit 5123, with a 90" drum corediameter (minimal dilation effects) and 72" goose neck radius, would reapgreater benefits from increasing the goose neck to 90" versus increasing wallthickness all the way to .190". The relative logistical concerns must be morefavorable for the goose neck option.

Coiled Tubing Failures

The goal of this section is to bring to light issues relevant to increasing coil life.By understanding all the factors pertinent to the topic, and generatingdiscussions, we can hopefully optimize our coil life management.

The three most prominent causes of coiled tubing failures are corrosion (35%),mechanical damage (22%) and manufacturing flaws (20%) – 2004 statistics.Presently, the issue of manufacturing flaws may not improve much at all, as thestandards for milling coiled tubing are very high. Areas we can improve uponare mechanical damage and corrosion. Improvements in corrosion may consistof better storage inhibition procedures, pigging the coiled tubing to remove rustand debris and improving corrosion inhibition during acid treatments etc.Mechanical damage involves the handling of coiled tubing. Wrapping, injecting,transferring, shipping, improper equipment set-up etc. can all induce mechanicaldamage on the coiled tubing. This is an area we can improve upon.

Note: Coiled Tubing pipe failures result in significant financial losses, not tomention potential risk of human life.



Pipe Selection Criteria

Coiled tubing pipe selection is critical to a coiled tubing business line. The size,grade and supplier of pipe you select will impact your coiled tubing business. Inthe past we have often relied upon work to define our string selectionparameters. Due to advancements in coiled tubing research we now havescientific data to base our decisions on and a software program to analyzefatigue and ballooning of coiled tubing. Some of the considerations to be madewhen selecting a coiled tubing string are as follows:

• H2S?No = Any MaterialYes = HS70 preferred

• High D/t Ratio Required (light pipe)?HS90 and QT900 not recommended

• Tapered String?No = Any MaterialYes = QT1000 not allowed

• QT 1000 Required?Internal Flash Removed Only (parallel string)

• Pipe Size Greater Than 1 ¾”?QT800 recommended

• High Pressure?HS90 not recommendedD/t ratio < 15

• Normal Cycling Pressure Above 4,000 psi?HS90 Not recommended

• Normal Cycling Pressure Above 5,000 psi?HS not recommended

• Majority of Cycling Below 3,000 psi?HS70 and HS80 recommended

• Field Welding Required?70 ksi or 80 ksi grades only



As can be seen from the above bullet list there are a number of considerations tobe thought through when selecting a string of coiled tubing. As with mostdecisions trade-off will be present. It is up to the individual to determine whatthe most critical parameters are and to recognize the pitfalls of the chosen string.For example, 70 ksi coiled tubing is often selected as a work string in Canada.The main reason behind this is due to H2S exposure. Many of the wells inCanada have H2S present. 70 ksi pipe is recommended for sour service. It wouldbe beneficial at times to use a higher grade of pipe however the presence of H2Sis determined to be the over-riding factor in the pipe selection process.

NOTE: Due to increased awareness 80 ksi pipe is now beingexperimented with in the Canadian marketplace. However, 70 ksi pipe isstill the preferred grade for H2S exposure.

BJ Services developed a software program entitled CT MODELS; CTMODELS deals mainly with the ballooning and fatigue associated with coiledtubing. A number of scenarios or iterations can be run to determine the optimumpipe design, to suit the variety of work anticipated. Keep in mind, there are anumber of factors to take into account when selecting a coiled tubing string. CTMODELS only provides insight to the question of fatigue, ballooning,equipment capacities and operating limits.



Figure 52 Flow Chart For CT Pipe Selection

QT800 QT900 QT1000 HS80 HS70HS90

CT Material Selection

H2S ?

No

Yes

OD > 1 3/4"

Tapered String?

Field Welding?

High D/t Ratio?(low weight)

Cycling at< 3,000psi

Large PullCapacity

Required?

Yes

No

No

Yes No

No

Cycling at> 4,000psiYes

HS90 NotRecommended

No

Cycling at> 5,000psiYes

No

Yes90 Grades NotRecommended

No

Yes

Yes

No

No

No SpecificRecommendation

Yes Yes



Coiled Tubing Pre-job Simulation

BJ Services Company has developed the CIRCA™ coiled tubing simulatorover a period in excess of twenty years. The initial version of the softwarewas used to improve well clean out capability using 1” coiled tubing andincluded two phase flow. This first generation program has evolved in to thestate of the art software currently known throughout the petroleum industryas CIRCA™.

As coiled tubing application evolved into a highly technical, multifacetedservice, CIRCA™ been advanced to keep pace. A few enhancements to thecapabilities of the program over the years have included

• addition of a force and stress analysis section,• 3 dimensional modeling of well bore trajectories,• effects of residual curvature on coiled tubing,• apparent mechanical frictional drag, and• the effects of hydro dynamic drag of produced fluids on the coiled

tubing.

The latest version of this software,version 14, is now in constant use. Thisversion incorporates superior graphicsand data displays. Improvements to theengineering functions include the abilityto model the effects of coiled tubing inbuckled completions.Current application of CIRCA™ includes avariety of tasks from prediction ofcirculating and tubing force parametersthrough to history matching circulating and tubing force data on previouslycompleted treatments. The main purposes of this program are to predict:

• Flowrates and pressures when common oil field fluids are circulated in a well usingcoiled tubing

• The effects of solids transport on pressure and flow rates for cleanouts• Forces acting on and stresses induced in the coiled tubing during Running In Hole,

Pulling Out Of Hole and under stationary load conditions• Operating limits in terms of weight indicator readings thereby defining a safe zone of

Operation.



Enron India, Well: PF-2HProduction Parameters - 1.5" CT in Hole

0

500

1000

1500

2000

2500

3000

0 0.5 1 1.5 2 2.5 3

Gas Rate (MMscf/day)

Pres

sure

(psi

)

0

100

200

300

400

500

600

Oil

Rat

e (b

bl/d

ay)

WHFPBHFPOil Rate

PI = 3852 scf/day/psiGLR = 115 bbl/MMscfNo circulation thru CT

-50000

-40000

-30000

-20000

-10000

0

10000

20000

30000

40000

50000

0 2000 4000 6000 8000 10000 12000 14000 16000 18000

Depth (ft)

Wei

ght (

lbf)

Surface WeightFriction LockOperating Limit

Simulated Conditions:

Production: 15 MMscf/dayWellbore: Gas Filled Friction: Tubing @ 0.23 Open Hole @ 0.352 3/8" Coiled TubingWorkstring: Gas Filled

Max. Depth @ 14,800 ft

CIRCA™ Circulation Analysis

Output from a flow analysis includes:(a) Hydrostatic and friction pressure

gradients(b) Velocity (of each phase present)(c) Gas volume fraction/foam quality

and flow type for two phase flow(d) Reynolds number(e) Effective viscosity and shear rate

All of the above listed parameters are output at various measured depthsbetween the wellhead and bottom of hole for both inside the coil and itsannular.

CIRCA™ Tubing Force Analysis

The forces experienced by a workstring vary along its length according to alarge number of variables, some of which are quantified by the circulationmodel, i.e.• Fluid and gas densities (used in the

calculation and buoyancy andgravitational forces)

• Hydrostatic and friction pressuregradients

Output from the tubing forceanalysis includes:• Weight indicator gauge reading• Weight indicator gauge reading at operating limits• Wellhead pressure• String pressure• String injection pressure• Friction force• Tension force• Triaxial stress• Spiral pitch• Collapse differential limits

All of the parameters output from CIRCA™ are available in report form orgraph.



CYCLE™ - COILED TUBING FATIGUE MANAGEMENT

The purpose of the CYCLE™ program is to accurately estimate the life spanof coiled tubing strings based on fatigue, ballooning and corrosion. All ofthe activity that the coiled tubing has been exposed to is recorded in a stringfile. A mathematical model of fatigue determines the life expectancy of thecoiled tubing. Accurate knowledge of tubing damage can prevent fatiguerelated coiled tubing failure.

The CYCLE™ program enables BJ Services operations to:

• ability to provide real time on the job string history update• compile a complete history of work string activities including jobs, runs,

maintenance activities, and coiled tubing failures• assess the service for which each existing string is currently fit based on

fatigue, ballooning and corrosion calculations• view graphs and reports that summarize the history of each string

including the estimated fatigue and the safe working life remaining

The information that is inputinto CYCLE™ is stored in astring file. The string fileprovides a history of all theactivity that the coiled tubinghas been exposed to, from thedate it was purchased until thedate it is taken out of service. Italso provides an assessment ofthe resultant tubing damage,including how much use of thestring remains.

The fatigue and ballooning calculations used to determine tubing damage arebased on the data provided by the string file. They are only as accurate as thedata provided. String file data is critical to safe and efficient coiled tubingoperations. Accurate knowledge of tubing damage can prevent fatigue andrelated coiled tubing failure.



CYCLE™ works in conjunction with another program called CYCLEDB™. The CYCLE DB™ program manages the information captured byCYCLE™.



Monitoring Equipment

Monitoring, recording and control equipment is crucial to job performance.For this reason, BJ uses the most advanced instruments in the field tomonitor job progress. Among them being:

Job Master

BJ Services provide a unique data acquisition system capable of recording,monitoring and displaying all necessary information during coiled tubingoperations. The system is designed to interact with the coiled tubing wellmodel and the cycle/fatigue life program to perform real time update duringthe job. In addition, the system is simple to maintain, interacts with allstandard computing equipment and above all, is user friendly.A Windows driven software program has been developed to ensuresimplicity of operation and download of information. The unique displayand keyboard allows our Engineers or Operators to interact with the systemto change operating parameters if well conditions change. This provides anenvironment where decisions are taken that guarantee safety, maximizeefficiency and ensure well integrity.Information can be downloaded via a CD or large capacity 100 Mb zip diskand then printed out via a standard computer in the field or back in theoffice.

Wireless LAN

The BJ Services Wireless LAN System replaces well site LAN cabling withradio links allowing for zero time deployment at the wellsite of treatmentdata communication. The units directly replace BJ LAN cables or may beused interchangeable with LAN cables. Since cabling is not used, theproblems with maintaining conventional cables are eliminated and thereliability of the signals are improved.

Features and Benefits• Operates in extremely harsh environments with immunity from

interference.

• Eliminates the need to run LAN cables between units and the time ittakes to lay, retrieve, clean and store these cables.

• Supports wireless data transmission between 3305 and remote computersvia the computer serial port.



Figure 53. Wireless LAN Figure 54. Wireless LAN

Wireless Wellhead Unit

The Wireless Wellhead Unit provides complete monitoring capabilities atthe wellhead without the need for cable’s running back to the control cabin.The Wireless Wellhead Unit is designed to operate with BJ's JobMastersystem. The unit is approximately 5 1/2 feet high.

Power Center link for BJ monitoring & miscellaneous equipment:

https://powercenter.bjservices.com/__86256d48004debc5.nsf/WebByCategory?OpenView&Start=1&Count=30&Expand=1#1

https://powercenter.bjservices.com/__86256d48004debc5.nsf/WebByCategory?OpenView&Start=1&Count=30&Expand=1#1



Health and Safety

Continuously improved job procedures and commitment to Health,Safety and Environment, complete with regular audits, provide a safeand healthy working environment for all staff and clientrepresentatives, both on and off locations. Regular safety drills keepstaff alert to their responsibilities, whilst structured trainingprogrammes highlight the safety aspects of their work, ensuring thatHSE remains a primary consideration in all aspects of job design,preparation and execution.

Figure 54. 1st Bowen Injector Head

Figure 55. Before! Figure 56. After?



Acknowledgements:

The author would like to thank Tomball’s Training Department:

References:

BJ Operations and Maintenance Manuals for Coiled Tubing Equipment

BJ Services Training and Product Sales Material

Coiled Tubing Operations & Procedures Manual (COP’s) – Eng 110Fundamentals of Coiled Tubing Manual

API Recommended Practice for Coiled Tubing in Oil and Gas Well Services

BJ Services Iron Manual - Link

BJ Services Products & Services Link

Quality Tubing - Link

Hydra Rig - Link, Texas Oil Tools - Link – Varco.com

https://powercenter.bjservices.com/86256A8E006B1CDA/$defaultview?OpenView

http://www.bjservices.com/website/index.nsf/P&S?openframeset

http://www.qualitytubing.com/

http://www.hydrarig.com/products.htm

http://www.tot.com/

Date post:	24-Oct-2014
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45169970 BJ Coiled Tubing Equipment Manual Version 1

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