Coil Tubing Equipment

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1 General

The coiled tubing operation permits the technique of "snubbing" a continuous length of tubing in and out of a live well through a stripper BOP arrangement. It consist of the following equipment:

  • Coiled Tubing
  • Reel Unit
  • Power Pack
  • Control Unit
  • Tubing Injector Unit
  • Blowout Preventers (including lubricator and stuffing box)

Auxiliary equipment is needed to ensure that the tubing is run to the required depth and that the operating envelope (pressure, weight etc.) of the equipment is not exceeded throughout the duration of the task.

Additional equipment associated with the type of task to be performed is also required, such as nitrogen tanks for nitrogen displacement, or downhole tools, such as a mill and motor for milling operations.

This section provides an overview of the available equipment, however as technology develops, the range of tools may be enhanced for most applications. As an example, gas lift valves, subsurface safety valves and ESP's can now all be run as part of a coiled tubing completion.

A range of coiled tubing packages/units are available from the service companies. Selection of this equipment is predominantly determined by the intended application and well completion conditions, i.e. sour service, CT size, etc. Additionally, hybrid units are available which enable the retrieval of conventional tubulars, or other well preparation tasks requiring conventional operations, prior to commencing the coiled tubing work. These hybrids have been developed predominantly in response to well re-entry requirements and coiled tubing drilling.

2 Surface equipment

The full suite of surface equipment used during coiled tubing operations will vary depending on the job to be performed.

Without exception, however, the following principle items of equipment are considered to be standard:

1. Primary equipment

  • CT reel unit
  • Injector head (incl. gooseneck)
  • Power pack
  • Control cabin (eg. load/depth indicators)

2. Pressure/well control equipment

  • Stuffing box
  • Quad blowout preventers (BOP)
  • Shear seal BOP
  • -Annular BOP (ABOP) (optional, dependent on application)

2.1 Primary equipment

2.1.1 CT reel unit

Coiled tubing is stored on large reels in the same manner as the flexible cable of a wireline unit. The reel is supported on an axle and is rotated by a hydraulic motor through a chain drive. This drive system has a dual function: when uncoiling tubing, i.e. running into the well, the motor acts as a constant-torque brake, thus keeping the tubing to the gooseneck under tension. When coiling, this drive system revolves the reel so as to coil the tubing under a constant tension. The CT reel drive system itself is not used to lower or hoist tubing in the well, which is the purpose of the injector head

2.1.2 Injector head

The injector head is the mechanism which transfers the force necessary to inject, retract or hold the tubing with precision control, while tripping into/out of the well. It grips the coiled tubing between profiled gripper blocks mounted on chains which are hydraulically driven. Hydraulic tensioning mechanisms maintain correct tension on the drive chains to prevent crushing or slippage of the tubing. In addition the hydraulic drive motors have brakes which will hold the tubing should the hydraulics fail.

2.1.3 Power pack

Most conventional units use a diesel engine to power hydraulic pumps, which in turn drive the hydraulic motors in the injector head, tubing reel and well control systems. As an alternative, electric motors may be used to drive the hydraulic power pack. Diesel engines fitted to coiled tubing reel units must be fitted with the following safety devices to comply with hazardous zone 2 requirements: ·Anti-static fan belts ·Exhaust spark arrestor ·Explosion proof instrumentation ·Emergency shut down device ·Air or hydraulic starter

The blowout preventer (BOP) is hydraulically operated by oil stored in an accumulator. A pressure controlled activator maintains the charge in the accumulator, which when fully charged can typically operate the BOP through two complete cycles. A hand pump is provided for emergency operation.

2.1.4 Control cabin

The control cabin is sited to provide a clear view of the wellhead, injector head and the tubing reel. It houses all the controls relevant to the operation, including:

2.2 Pressure control equipment

2.2.1 Stuffing box/stripper rubbers

The stuffing box is the primary sealing mechanism for isolating wellbore fluids whilst under static or dynamic operating conditions. It is mounted directly above the BOP and below the injector head via a quick union. This configuration may change depending on the number of BOPs used, their arrangement and anticipated well hazards.

2.2.1.1 Stripper rubbers

The different types of stripper rubbers are governed by their schure hardness. Typically the low pressure type are 75 Schure hardness (coloured yellow) whilst the high pressure are 90 rated (coloured orange). The efficiency of the stripper rubbers rests primarily on the lubrication medium used, and the impregnation in the stripper rubber to produce low friction properties. Schure hardness is a rating system to determine the suitability of rubber to a pressure environment. The higher the number, the greater the hardness and the more suitable for use with higher pressures. The hardness rating system is used for 'O' rings, stripper rubbers and packer elements.

2.2.1.2 Lubricant

The method of lubricating the reel is not as important as the fluid used.

It is essential that the correct type of lubrication oil is used so that friction is reduced to a minimum, thereby prolonging stripper rubber life. A popular fluid used is diesel oil which initially will appear to lubricate and reduce friction efficiently. However, in the duration of the run into the hole, diesel will cause swelling and deterioration of the stripper rubber and cause added friction at the stuffing box. As a result it is not recommended to use diesel as the lubricant. Century Oil 610T is a commonly used fluid with good lubricating properties.

Within the initial stages of any coiled tubing operation high stripper friction will be experienced. The cause of this can be due to a number of factors, e.g. initial unlubricated pipe, bedding in of the strippers etc. The value of friction will soon reduce and level out at a set rate usually beyond 500 ft into the well. Computer simulator are used to calculate the wellbore friction coefficient.

2.2.2 Blowout preventers (BOP)

The BOP is the primary safety apparatus designed to prevent the uncontrolled release of wellbore fluids. There may be up to three BOPs included in the wellhead hook-up (Quad, shear seal and annular).

2.2.2.1 Quad BOP

The Quad BOP is the principle BOP included in the hook-up and contains four sets of closure mechanisms (rams), namely:

  • Blind rams, which seal against each other (no tubing/tool obstruction)
  • Shear or Cutter rams, which cut the coiled tubing or wireline and seal the well
  • Slip rams, which grip the coiled tubing in the well preventing any up or down movement - The slip toolface can mark the CT and lead to premature failure.
  • Tubing rams, which seal against the outside of the coiled tubing.

Should the stuffing box stripper rubbers lose sealing integrity, the blowout preventer tubing rams can be operated and the stuffing box can be redressed with new stripper rubbers with the tubing in the well, allowing live well operations to continue.

A minimum of two barriers are required when changing out the stripper rubbers.

It is imperative that both sets of equipment, stuffing box and BOP, are properly tested before running the coiled tubing downhole .

2.2.2.2 Shear seal BOP/valves

The shear seal BOP assembly is capable of holding, cutting and sealing coiled tubing in the event of a controlled or emergency well closure. Generally it is used as a back-up to the Quad BOP, and used for jobs where there is a risk that the coiled tubing may need to be cut in an emergency, such as working on bottom, sand clean-outs, cementing, milling etc. In the event that a cut has to be made, the close proximity of the shear rams to the tree valves should allow the coiled tubing to drop below the swab valve.

It is recommended that shear seal BOPs are fitted during coiled tubing applications which preclude the use of downhole check valves, in order to provide additional insurance that the coiled tubing can be sheared should well control be lost as a result of flow through the coiled tubing.

2.2.2.3 Annular BOP (ABOP)

The annular blowout preventer will close and seal blind on wireline, tool strings, or tubing up to full bore. Designed primarily as a static sealing element it will allow stripping into or out of the well in an emergency situation.

The sealing element in the ABOP will also afford a seal should the stuffing box fail whilst tripping the coiled tubing out of the hole. Closure around the downhole tools being run or retrieved on tubing will also affect a seal, as the element has been designed to seal around non-round profiles in addition to conventional tools, and as such will generally be used during running completions/tool strings.

2.2.3 Tool string deployment systems

The tool deployment system allows long coiled tubing tool strings, generally perforating guns, to be deployed into a live well without requiring an injector rig up on top of a long injector/riser configuration. This avoids the need for an extra large crane and an awkward and potentially unstable rig-up.

This type of system, is now used where long lengths of perforating guns facilitate single trip perforating of long intervals. The technique uses a simple wireline system to temporarily position the tool string inside the wellhead where it is remotely latched on coiled tubing and run into the well.

The deployment tool, including a Hydraulic Quick Disconnect and Annular BOP is rigged on top of a conventional quad BOP on the wellhead. The tool itself has wellbore isolation valves, such that those in the BOP need not be used as the standard isolation during tool deployment.

With the tool string assembled on surface, a special Automatic Connect/Disconnect sub (ACD) is used for tool deployment rig-up. The ACD is a two piece coupling system with the bottom half of the sub being attached to the tool string. The top half comes in two varieties, one for wireline use and the other for coiled tubing.

The tool string is initially fitted with the wireline ACD sub, placed in a wireline lubricator which is then raised and installed on top of the deployment tool.

When the integral gate isolation valve in the deployment tool is opened and the wireline lubricator pressurised, the tool string is lowered into the wellbore. The ACD lands in a set of No Go and Lock rams within the deployment tool, at which point the guide rams are closed and the top half of the ACD disengaged. This can then be pulled into the lubricator to allow the isolation valve to be closed. The lubricator is then depressurised and rigged down.

The coiled tubing injector head is then rigged on top of the deployment tool with the upper half of the ACD already installed on the end of the coiled tubing.

With the isolation valve open the coiled tubing is lowered into the deployment tool where the ACD latches on to the tool string. An injector pull test is performed to ensure proper engagement of the ACD after which the deployment rams are retracted. The tool string can then be run downhole.

Removal of the tool string is accomplished in reverse order to the deployment sequence.

The annular BOP provides back-up isolation capabilities in the event of an emergency in which it becomes necessary to seal off around the body of the tool string.

Alternative systems allow the following tasks to be performed:

  1. Installation of accessories in the coiled tubing string through an access window.
  2. Running of cables, ESPs, etc. through a work window.

2.3 Auxiliary surface equipment

2.3.1 Weight indicator

The two principle weight indicator systems include:

  • Mechanical
  • Electrical

The mechanical type is a side mounted load cell which works on the principle of transference of hydraulic pressure.

The electrical type is a strain gauge load cell which may either be centrally or side mounted on to the injector head.

The main check to be carried out before running in hole is to ensure that the weight indicator is reading accurately. Once the injector head, complete with gooseneck and coiled tubing stabbed on, is lifted onto the wellhead a check on the weight indicator can be made. When the injector head is completely tied back and ready for operations, prior to the well being opened up, the weight indicator should read the weight of the tool string only. The amount of coiled tubing in the well is minimal at this stage and will not affect the weight reading. If the reading is not correct at this point the error should be noted so that allowances can be made during the operation.

Allowances also need to be made for the friction in the stripping box.

2.3.2 CT reel connectors

2.3.2.1 Coiled tubing collector (slip ring joint)

During stiff wireline operations it is necessary to provide a means of communication from the wireline, which is turning with the CT reel, to a fixed point. This is accomplished using a slip ring joint (collector) fixed to the side of the CT reel. The collector consists of a series of brushes that rotate with the reel whilst maintaining contact with a stationary conducting ring. Connections from this ring are wired to a brass plug on the collector body, which enables direct communication from the BHA to the surface logging equipment.

2.3.2.2 Rotating joint

The rotating joint enables fluids to be pumped under pressure through the coiled tubing while the reel is either stationary or in motion.

2.3.3 Hydraulic quick connector (HQC)

Installed between the coiled tubing BOP and the stuffing box or riser, the HQC provides a safe and easy method of injector rig-up.

Using standard connection unions with the larger coiled tubing sizes can sometimes result in the injector hanging off-plumb, making stabbing unusually difficult. The HQC has been designed to allow stabbing of the injector with a 10° offset, as the standard HQC has an integral guide to aid alignment of the mating connections.

The HQC has a mechanical latch mechanism which when fully connected provides positive engagement on the locking dogs, as well as actuating an external indicator which shows whether the equipment is correctly "stabbed" on. It is released by applying hydraulic control pressure to the internal piston.

To minimise the overall height of the rig-up, the HQC can be permanently mounted in place of the quick union on the bottom of the stuffing box. This provision allows the HQC to be used while only adding approximately 6" to the stack height. Alternatively, the HQC can be supplied as a self contained unit with quick unions or flanges.

2.3.4 Depth measurement

Two typical types of depth counter systems include:

  1. Mechanical cCounter
  2. Electronic counter

2.3.4.1 Mechanical counter

The measuring wheel of the depth odometer is rotated by frictional contact with the tubing as it passes by, and is mounted on the spooling system of the reel unit. A read-out on the control panel is activated mechanically to provide the operator with the depth of the coiled tubing.

Depth odometers have sufficient accuracy for most jobs, however, their accuracy can suffer if they are not well maintained (e.g. wheels not kept clean) or the coiled tubing surface is coated with wellbore debris (sand, gas, asphaltenes, etc.). More importantly, if coiled tubing running speeds (in or out of hole) are high, i.e. over 100 ft/min, this can cause the odometer wheel to jump and give rise to depth errors. Accuracy may also be reduced in large bore, deviated completions where the coiled tubing can corkscrew/buckle.

2.3.4.2 Electronic counter

This counter is driven from a fixed point on the main drive of the injector head. The signal is sent via a cable through a transducer to an electronic read-out situated inside the control cab, where the weight, running depth and feet per minute are recorded.

2.3.4.3 Depth correction

Downhole forces such as the hanging weight, pressure and buoyancy will stress the coiled tubing and cause it to stretch, while temperature changes will cause the tubing to expand or contract.

The same calculation can be used for determining the "free point" should the CT become stuck downhole. By measuring the stretch in the coil tubing due to a measured pull on the injector, the stress and hence stretched length can be determined.

For special applications requiring precision depth measurement, a tubing end locator can be used to correlate coiled tubing depths with the known depth of the wireline entry guide at the bottom of the production string.

3 Coiled tubing

3.1 General

The most common nominal size range of coiled tubing used in well intervention activities is from 1" through to 2". The availability of larger diameter coiled tubing has increased its application, specifically in drilling (2" and 23/8") and well completions (31/2").

The life of the coiled tubing string is strongly influenced by the tubing size (i.e. bending stresses over surface equipment) and internal pressure cycles. Hence in conjunction with the coiled tubing selection, the impact of the bending radii of the CT reel and gooseneck, and anticipated operating and well pressures, as discussed within the following sections, should not be overlooked.

3.1.1 Manufacturing process

Changes in the manufacture of coiled tubing have resulted in increased material strength and consistent material quality. Heat treatment and metallurgical changes have increased resistance to H2S corrosion while improved welding techniques have enhanced the reliability of coiled tubing. This and a better understanding of how to use coiled tubing using computer simulation models has resulted in a vast increase in its use.

Butt (tube-to-tube) welds produce "weak points" in the tubing string, principally in the heat-affected zones. Additionally the internal weld bead may restrict flow and cause localised turbulence areas. To overcome this problem, bias (angled) welding is employed in the continuous milling process. Flat strips of raw material are prepared and joined together with a high quality bias weld before the tubing is rolled. This distributes the weld area in a helix longitudinally across the surface of the tube. This, in effect, will distribute the mechanical stresses which will be experienced in the weld zone over the length of the helix rather than in a narrow band around the circumference of the tube, resulting in a join as good as the base tube.

The flat strips of bias welded material are fed to one end of the production line, and cold formed by profile rolls, firstly into a "U" form, then into a "C" (gap uppermost) in a continuous process, as it passes along through the line. The edges are heated by high frequency eddy current, and the gap is forced (forged) together by further sets of profiled tools, thereby completing the process of making the strip into a tube. External flash is removed whilst still semi-molten, by a single cutting tool profiled to the tubing OD. Since the flash metal is both free of slag and semi-molten, it comes off as one continuous, malleable strand which greatly facilitates its removal. If flash must be removed from the tubing ID, it is ploughed away by a cutting tool attached to a long bar. This is fixed in a mounting, which is attached to the bed of the line at a point before the gap in the formed strip is closed by the rolls. In this process, the continuous string of flash curls away from the cutting tool and is pulled back, against the direction of pipe travel, and wound onto a reel located at the beginning of the line. Weld seam annealing, eddy current inspection and stress relieving are performed further along the line, before the tubing is finally wound onto its storage/transportation reel.

The ensuing tubing quality has promoted the manufacture of coiled tubing up to 31/2" diameter, where-as 1" and 1.25" were predominant in well service applications in the past. However, quality control within the manufacturing process is not consistent across the manufacturers of coiled tubing and must be addressed.

3.1.2 Field repairs/joints

As noted above butt welds are unreliable, even when performed in factory conditions. When conducted at the well site without adequate heat treatment facilities, the problems are only compounded. Even with "proper" field welding techniques, butt joints have a fatigue life of half that of the base tube and must occasionally be cut out and the tubing rewelded.

A welding technique - Amorphous bonding (diffusion bonding) developed by Daido Steel, may allow quick and effective well site repairs of existing coils. Characteristics of this technique include:

  • Stable and reliable weld zone.
  • High bonding.
  • Applicable to all metals; e.g. Ti, Fe, Steel, Cu.
  • Different metals can be bonded.
  • Skilled operators not required.

3.2 CT stresses

The CT life is primarily governed by the fatigue stress caused when the tubing is bent over the reel and gooseneck. This is compounded when the CT is exposed to internal pressure at the same time. Pressure (internal/external) and tensile load (tension/compression) are further factors which will influence the life of the coiled tubing. The only way to avoid CT failure is to track the fatigue damage occurring to the pipe and replace it before failure occurs. However, simply measuring "operating hours" is not an effective means. Modelling the fatigue in the coiled tubing using computer models provides a coiled tubing management system to predict fatigue and thus predict effective coiled tubing life.

In addition to the stresses imposed during the bending of the tubing over the reel and gooseneck, those expected to be encountered downhole will govern the coiled tubing selection and its ability to perform the task.

3.2.1 Running in the well

The downhole stresses encountered while running into vertical wells are usually a result of the hanging weight of the string and equipment/tools, internal and external pressure conditions, internal and external flow, friction and buoyancy. As the trajectory of the wellbore becomes deviated, advancing the coiled tubing into the well will generate contact reaction forces, resistive friction forces and possibly bending stress due to helical deformation, known as triaxial stress. The maximum allowable triaxial stress during normal coiled tubing operations is 80% of the manufacturers material yield stress rating.

3.2.2 Pulling out of the well

Generally the same forces are present for pulling out as for running in, with some variance. Changing the direction of travel, the contact friction in a deviated wellbore will also change orientation and will resist the motion of the coiled tubing. Also, in a tensile condition, the workstring will not exist in a spiralled or helical shape and therefore the associated bending stress and additional friction effects will not occur.

While identification of these stress conditions is relatively straight forward, accurate quantification and interpretation is not. However, computer simulation software has advanced to predict the effects when running into a specific well and executing the activity programme.

3.3 Pressure and tension limits

In the past, typical pressure limits have been in the order of 5000 psi for burst and 1500 psi for collapse. These were, in general, conservative for the size of coiled tubing and wall thicknesses then employed, as they took into account the fatigue damage accumulated during the working life of the coiled tubing.

Tension limits were typically set at 80% of the coiled tubing pipe vendors published yield limit. In most cases, no compression was considered, as coiled tubing was usually in tension during routine well service operations.

With the advent of larger pipe sizes and use in horizontal wells, these limits are inappropriate, for example it is now predicted that:

  • For a 1.25 in. OD pipe and 0.087 in. wall thickness, the pipe life increases by nearly 300% when the pressure limit is decreased from 5000 psi to 3000 psi.
  • Increasing the gooseneck radius from 50 in. to 72 in. for 1.25 in. OD pipe and 0.087 in. wall thickness, increases the pipe life by 54%.
  • Increasing the wall thickness from 0.087 in. to 0.109 in. for 1.2 in. OD pipe with 5000 psi, increases the pipe life by 127%.
  • Decreasing the pipe diameter from 1.5 in. to 1.25 in. for 5000 psi, increases the pipe life by 171%.

Pressure/tension limit curves can be generated for coiled tubing which plots the differential pressure on the pipe (+ ve burst, - ve collapse) against the axial force (+ ve tension, - ve compression). If the actual working forces, when plotted, are within the curve, operations are within the elastic range of the CT material, otherwise the material is operating in the plastic range.

The working limit curve illustrated in the above figure includes a safety factor to take account of tubing ovality and slight changes in diameter dimensions.

Such (computer) analysis illustrates the criticality of appropriate load/force considerations at all stages of a work programme, especially in CT of 2" and larger and in cases where collapse pressures are anticipated. This is illustrated in the table below, which is a computer simulation prediction of typical Collapse Pressure Limits, with no axial load applied.

It is important to reference the predicted collapse pressure prior to energising stripper rubbers.

3.4 Buckling and lock-up

When pipe is being pushed into a horizontal section, the force required to do so must exceed the weight of the pipe multiplied by the friction factor. This increases as the length of pipe in the horizontal section increases until the resultant axial force is greater than the buckling load. The pipe will then buckle into a sinusoidal shap.

As the axial force increases (continue to push the CT into the horizontal section) helical buckling will occur. The contact forces will further increase the friction force which will eventually cause the pipe to "lock up".

Therefore, when designing the coiled tubing operation for extended reach, horizontal or highly deviated wells, several operating factors need to be considered:

  • How far can the coiled tubing penetrate and push tools into the deviated hole section before lock-up occurs.
  • How much weight can be applied on the tool within the deviated/horizontal section.
  • How can the operator predict when the CT being snubbed into the well is likely to buckle (bend).

Computer simulation models can predict:

  • Sinusoidal and helical buckling and lock-up;
  • CT Forces and stresses;

These predictions will facilitate the coiled tubing selection and define operating limits for specific well configurations and job requirements.

Ongoing development of downhole traction devices will further enhance coiled tubing capabilities in high angled/horizontal/long reach wells.

3.5 Depth limits

The operating depth limit on coiled tubing is governed by the weight and tensile strength of the tubing material. This limitation can be overcome somewhat by fabricating tapered strings in which a thin walled portion of pipe is welded to the bottom end of a medium or thick walled segment. This results in a reduced weight force on the tubing at surface because of the lighter bottom portion. Using this technique, several tapers can be joined end to end to reach depths of 20,000 ft or greater.

The above has taken account of only those stresses imposed in a vertical well. Obviously friction factors for deviated/horizontal wells and pressures (both internal and external) will influence the capability of the tubing to reach, perform and be extracted from the well at extreme (with respect to CT operating parameters) depths.

Software simulation programmes are available for predicting coiled tubing design limits. These should be compared with predicted tubing forces (tubing force model) for particular well characteristics to ensure whether the job is possible.

3.6 Tubing fatigue life

While operating in a well, coiled tubing is subjected to stress loading due to factors such as hanging weight, pressure and bending stress. An equally important parameter is the fatigue stress which is generated when the coiled tubing travels around the tubing reel and over the gooseneck in a state of plastic bending. It is imperative that each of these loading categories be understood to prevent failure downhole and to monitor the safe working life of the coiled tubing string.

Traditionally, manual records have been kept on the cyclic stress reversals each reel of tubing experiences during its operating life. These records usually took the form of a bar chart, so it was instantly visible which portion of the coiled tubing had been exposed to the greatest number of stress reversals.

For operations where a section of tubing is repeatedly run in and out of the well it is often sufficient to cut the "cycled" section out of the string and reuse the remaining tubing.

This method of tracking running feet (cycles) only works if the CT is run to similar depths and with similar pressures.

The presence of internal pressure during cyclic stress reversal has a dramatic effect on the fatigue resistance of coiled tubing. The combined effect of plastic bending and internal pressure produce radial strain in the tubing, which results in diametric growth or ballooning. Exposure to H2S and acid will further affect the CT fatigue life. Because it is difficult to manually record the combination of these factors over the complete coiled tubing string during a typical job, the stress reversal cycles are assumed to have taken place at maximum working pressure. Additionally, one extra tubing cycle should be counted for each acidisation performed. While this represents the safest course of action it does add to the possibility that reels of coiled tubing are retired from service well before their safe working life has been reached.

Computer based monitoring systems have been developed to improve the quality and accuracy for the determination of the accumulated fatigue damage sustained by a reel of coiled tubing during its operating life.

Real time monitoring of the tubing ("tubing integrity monitor") is now possible to measure the ovality of the tubing OD. Since CT is continually plastically strained in operation it becomes more oval and larger in diameter. Hence measurement of the geometry of the tubing provides an indication of fatigue life and warning of pending problems. Limits may be imposed during particular jobs, where for example high collapse pressures are anticipated.

3.7 Computer software

The understanding of the behaviour of coiled tubing and the effects on fatigue life has greatly improved. A number of available software packages exist, developed by various parties, to predict the CT behavior.

Use of the appropriate systems and software will provide a "coiled tubing management system" to greatly enhance job reliability. The management system will addresse the CT design (e.g. mechanical limits, force and fluid dynamic modelling), fatigue parameters and tubing monitoring.

In deep applications, extended reach wells, and horizontal wells, it is recommended to use a tubing force model to ensure that the proposed job is possible. The following list summarises the factors that affect forces on CT, as noted in previous sections.

  • Well geometry (deviation, azimuth, ID, curvature, etc.)
  • Differential pressures (fluids in/outside CT)
  • Varying friction coefficients (open hole/casing)
  • Dogleg severity
  • CT size & weight
  • Tapered strings
  • Yield stress
  • Residual bend in CT
  • Wellhead pressure
  • Stripper drag

4 Sub-surface tools

A vast number of tools are available for use with CT. The following sections provide a general description of the more commonly used tools. A number of the tools may be incorporated into a single assembly termed "motorhead" (so called from their first combined use on milling/drilling jobs). Vendor Service company literature should be referenced for more specific details.

4.1 Release joints

Release joints provide a means of disengaging the coiled tubing from the tool string run beneath it. This is a precaution generally required when running tools with an OD larger than the coiled tubing, i.e. straddle packer tools, bridge plugs, downhole motors, tubing end locators, pressure activated perforating guns, etc. Because of their size, there is an increased risk that these tools may unexpectedly hang up on downhole obstructions (such as liner laps in deviated wells). It is also a precaution in certain operations, such as those which require tagging TD or milling tasks.

The following release tools are in common use:

4.1.1 Ball operated shear sub (BOSS tool)

BOSS tools incorporate an impact cushion assembly which protects the shear pin and permits the tool to be used in jarring and percussion operations.

The ball operated release joint is pressure activated from surface. In order to circulate a ball down the workstring, the coiled tubing reel must be fitted with a ball launcher or at least have some facility whereby a ball can be introduced into the flow path. Each ball and coil size combination has a minimum flowrate required to circulate the ball around the reel and over the gooseneck. At minimum flowrates substantial slippage occurs so timing the ball to bottom is very inaccurate. It is best to station a man near the injector since the passage of the ball is easily heard.

In below hydrostatic wells it is advisable not to pump the ball to bottom but to stop halfway, and allow the fluid and ball to free fall - doing this reduces the hydrostatic, eliminates water hammer and allows the engineer to observe the tool operating. Under pumping conditions, it is possible for the ball to seat with the resulting hydrostatic pressure and water hammer triggering the release without any indication on surface.

When running such a tool, it is recommended that the internal bore of the tool string is drifted, and the bore of the coiled tubing end-fitting checked using the specified ball, to ensure proper clearance and ball seating before the final rig-up.

4.1.2 Pressure activated release joint

This is similar in design to the BOSS, although operated by a differential pressure inside the tubing rather than on a ball. The size of the part to activate the releasing mechanism is dependent upon the depth and fluids in the well and must be checked prior to running in the hole.

4.1.3 Tension activated release joint

This tool incorporates shear screws which only require an applied overpull to release the joint. Great care needs to be exercised in selecting the shear screws to provide the required overpull. This will vary from well to well, depending upon the angle of well deviation, type of fluids etc.

4.2 Check valve

It is standard practice to use a check valve during all coiled tubing operations performed on live or potentially live wells. The check valve is positioned at the end of the coiled tubing to prevent well bore fluids from entering the coil.

There are two categories of check valve: Full bore or not and fail safe or not.

The full bore valve, such as the double flapper allows the passage of balls to function down hole tools. For example, should a bottom hole assembly become stuck a ball can be pumped through the flapper valve to operate a BOSS tool, while still providing reverse flow protection as the CT is retrieval from the well.

The 'dart and ball' check valve will not allow the passage of a ball and is therefore generally used when there is no requirement for a release joint, such as N2 lifting or simple jetting operations. Both the above rely on reverse flow to provide an effective seal.

The fail safe valve is generally a spring operated valve which therefore does not rely on reverse flow to seal closed.

Ensure that the coiled tubing collapse pressure limit is not exceeded whilst running a check valve, e.g. pump fluids while running in the well.

It is common practice to run a double check valve, such as the double flapper or two connected valves. This provides two barriers to the flow up the CT.

4.3 Coiled tubing plug and plug catcher

Coiled tubing plugs have two functions. The principle use is to separate different fluids (e.g. cement and displacement fluid) as they are pumped around the reel and down the coiled tubing. A secondary purpose is to provide a positive indication of when the respective fluid stages reach the end of the coiled tubing. This is seen by the pressure increase which occurs when the plug lands in the profiled coiled tubing end fitting and plugs off further flow. By increasing surface pump pressure the centre of the plug can be sheared out allowing circulation to be re-established until a further plug arrives and seals off once again.

As many as four plugs may be run in sequence with a standard catcher sub.

4.4 Sequence/pressure retaining valve

In principle, the sequence valve is a variable setting, spring loaded, back pressure (check) valve, designed to retain fluid within the tubing. This allows pressure changes resulting from the operation of downhole tools to be observed on surface when operating in sub-hydrostatic pressure wells. Typical applications include drilling, milling, underreaming, and inflatable packer operations. Since the valve also stops fluid "free-fall" it is also used in cementing operations.

A secondary use is to allow pressure to be held inside the coil so that operations in deep, high pressure wells can be performed without risk of collapsing the coiled tubing.

4.5 Tubing end locator

For many coiled tubing operations, depth measurement accuracy is adequately provided by conventional "wheel" driven counters. Their accuracy can, however, suffer if they are not well maintained or if the coiled tubing surface is coated with wellbore debris from previous jobs. Excessive running speeds will also introduce errors which, in conjunction with tubing stretch and temperature effects, may cause problems in applications such as straddle packer tool placements, which require precise downhole positioning.

Tubing end locators allow the operator to detect the precise location of the tubing shoe in relation to the current measured depth. Adjusting the measured value to the known tailpipe depth eliminates any accumulated error from the measuring equipment, as well as tubing stretch and temperature effects.

The tubing end locator tool consists of a "flow through" sub containing three spring loaded centralising arms. Advancing within the production tubing the arms are collapsed. Exiting the tubing shoe, the arms push out and provide spring resistance when pulled back into the tubing. The operator detects the spring force, in changes on the weight indicator, and can then verify the precise tool depth.

4.6 Centralisers/stabilisers

Because of the residual curvature that remains after coiled tubing is spooled off a reel, it is generally difficult to prevent the end of the coiled tubing from following the side of the tubing or casing. To prevent hanging up on landing nipples, side pocket mandrels etc. some form of centralisation is required. In addition, centralisation of the tools for certain operations is important, such as in jetting operations, to ensure that the energy and fluid contact is distributed evenly around the wellbore.

Should it be necessary to run through restrictions, such as a separation packer, then some type of full bore adjustable centraliser is necessary. These exist in two forms, either bow spring operated or hydraulically operated. The appearance of either type is similar, but the hydraulic operated type generally has a stronger stabilising influence. These are ideal for underreaming operations, however, the hydraulic operated type will reduce the fluid power available for the motor, which must be allowed for at the planning stage of motor selection.

Hydraulically operated centralisers do not contact the completion conduit wall until the tool is activated by hydraulic pressure from surface. The bow spring type will be in constant contact during the run into and out of the well.

Drilling/Milling with coiled tubing requires some precaution due to the relatively low rigidity of the workstring in comparison with a conventional drill assembly. If not properly supported, instability during drilling can overwork the coiled tubing above the drilling equipment, causing it to fail. Centralisers/Stabilisers are used to improve the efficiency of applying weight on bit (WOB) and to minimise fatigue and vibrations. Stabilisers are also used to help start and maintain the required trajectory while drilling.

Fluted (grooved) stabilisers should always be used in conjunction with the drill assembly to ensure adequate clearance is provided for effective circulation and cuttings removal.

4.7 Underreamer

An underreamer is designed to pass through a restriction, open up below the restriction to clean the hole to full gauge, and close up again to be retrieved from the hole. The tool is actuated by pumping through the coiled tubing and pressurising a piston which moves within the body to open the blades.

There are several different models of underreamers but most fit into two major categories:

  • Locking
  • Non-locking

Lock-blade tools incorporate a mechanism which locks the blades in place while the underreaming is in progress. This ensures that the blades do not close up, resulting in an undersized hole. The disadvantage of this type of tool is that the lock may not disengage at the end of the operation, making it near impossible to pull the tool back through the restriction. When this occurs, it is necessary to disconnect from the tool, pull the coiled tubing from the hole, and commence fishing operations. In some cases, the production tubing string may need to be retrieved from the well to recover an underreamer which is locked in the open position.

Non-locking tools depend entirely on hydraulic differential pressure to hold the blades open. While the risk of this type of tool locking open is significantly less than the previous type, it is more difficult to keep open and may result in a hole size smaller than expected.

Most underreamers incorporate a pilot mill below the blades. If a smaller hole already exists, a pilot mill will often follow the smaller hole, which may force the underreamer into the side of the casing wall if the hole is not central. This results in increased torque, reduced penetration rate, and potentially, a damaged liner or casing. A three-bladed underreamer design eliminates the pilot mill by placing the underreamer blades at the nose of the tool. This tool is non-locking but is designed such that it is very difficult to pump through the tool without opening the blades.

4.8 Mill/bit

A mill is a very simple type of bit with no moving parts. For coiled tubing operations, the mill basically comes in two shapes, flat bottom and cone type (tapered) and is ported to allow jetting and circulation. Quite often mills are custom built with a specific purpose in mind.

The flat bottomed mill can be used for cleaning out hard fill, cutting scale, milling out sections of collapsed tubing, wireline plugs locking sleeves and dressing fish. A guide cage of thin brass is usually needed to run the flat bottom mill past restrictions in the well. The brass guide cage, brazed to the face of the mill easily breaks off when tagging TD or rotating the mill.

The cone type mill is used to increase the ID of a restriction, or mill fish from the centre out. It may also be used for cleaning out very hard scale.

4.8.1 Types of bit

Several types of bit are available for coiled tubing drilling or milling operations, the specific choice being dependant on the type of application.

Three major types include:

  • Drag bit
  • Diamond matrix bit (DM bit)
  • Tungsten carbide matrix bit (TCM bit)

Cone roller bits are not generally suitable for this type of application because of the high rotational speed of the motors. At such speeds the bearings can fail within one hour. However, developments are ongoing with lower speed, high torque motors.

4.8.2 Drag bit

The drag bit is the oldest and simplest of the current bits available. This type of bit offers a cheaper alternative to the Tungsten Carbide Matrix Bit (TCM) and has primary applications for soft material. However, the advent of high pressure jetting tools to clean out soft material, has led to less utilisation of the drag bit.

4.8.3 Diamond matrix bit (DM bit)

The cutting elements of a diamond bit consist of a large number of small-sized diamonds geometrically distributed across a tungsten carbide body. The diamonds form a matrix with the surface metal of the bit to allow it to drill harder materials such as scale, old cement and mechanical debris.

4.8.4 Tungsten carbide matrix bit (TCM bit)

In a similar principle to the DM bit, the TCM bit consists of a series of tungsten carbide inserts irregularly brazed onto a steel bit body. The individual inserts are evenly sized to give a good tolerance hole diameter but have a rough appearance, which enables the cutting and cleaning action to take place. The individual inserts can vary in magnitude, in order that bits can be designed for both hard and soft applications.

Gauge protection is important to maintain the full hole diameter, hence the wall of the mill is usually tungsten carbide which is ground smooth to the correct gauge to prevent excess wear on tubulars.

4.8.5 Bit selection

For conventional borehole drilling, many tables exist for enabling a decision on bit selection to be made quickly and easily. For coiled tubing applications, the range of materials that require drilling or milling services can be vast in terms of hardness, plasticity, coarseness, etc. To this end bit selection can be somewhat subjective with no hard and fast rules applying. However, some simple guidelines can be followed which will aid in bit selection.

In drilling or milling applications, the harder the material the less volume that can be removed per revolution of the Bottom Hole Assembly (BHA). Therefore since soft material enables greater penetration of the bit, larger inserts should be selected to maximise efficiency. The opposite applies for harder materials since penetration is not as easily achieved.

In well service applications the material type is usually known, i.e. whether scale, sand, cement or metal. Hence, judgement of the correct bit can be made based upon the characteristics of the material, and further experience gained from milling/drilling the material.

4.8.6 Types of motor

Motor selection is critical in achieving maximum drilling time with minimum trips and therefore optimum job duration. Two types of motor are available for coiled tubing applications.

  • Positive displacement motor (PDM)
  • Vane type motor

4.8.6.1 Positive displacement motor

The PDM operates by transferring fluid pressure into rotation. The motor consists of two components: The stator is the outer housing and has a spherical spiral cavity lined with rubber material. The rotor is a solid steel shaft with a circular cross section. The internal profile of the motor is made up of small cavities between the rotor and stator. Rotation occurs when fluid pumped under high pressure is forced into the cavities between the rotor and stator.

Variations in design enable differing levels of torque to be produced.

PDM motors exist in various diameters and power outputs and great care should be exercised when selecting a motor. Too much power can have an adverse effect on the string, especially when drilling/milling in large tubulars, where correct stabilisation (to prevent buckling of the coiled tubing) may be difficult due to the need to run the assembly through various tubing restrictions, i.e. no-go nipples, etc.

If too much weight is set down and the motor stalls, the reactive torque generated will wind up the coiled tubing. Depending on coil size, this can be as much as 20+ turns in 10,000 ft. This stored energy will suddenly be released if weight is taken off the bit and as a result the motor can back off its threaded connection to the coiled tubing. The correct selection of threadforms will help eliminate backing off of the bit.

PDM motors are susceptible to fluids which will attack the rubber stator and cause deformation and jamming. High temperatures may also cause swelling of the stator and result in the motor jamming. Hence both bottom hole temperature and well fluids are important in defining motor selection.

Disadvantages

  • High stall torque
  • Long tool length
  • Non rig serviceable
  • Heavy tool weight

Advantages

  • Proven and Reliable
  • Will operate on mixture of fluids
  • High torque/RPM
  • Low pressure drop through motor during operations

4.8.6.2 Vane motors

The principle of operation is based upon the same as that for a vane pump. The vanes within the motor are a series of solid cylindrical rods positioned within a central rotating shaft.

The shafts move within the individual housing such that they allow the build up and release of pressure as the fluid is forced into the motor causing rotation and then leaving through the exit port. The vane motor offers a more compact design but with reduced torque. The nature of the rods or vanes is such that a filter system is necessary to eliminate the presence of debris. The filter housings have been known to clog causing the motor to cease operating.

Advantages

  • High RPM
  • Rig serviceable
  • Short length
  • Low weight
  • Low minimum flow rate

Disadvantages

  • High pressure drop through motor during operation
  • Low torque
  • Requires filter system

Overall the simplicity and reliability of the PDM design have made it the preferred choice over the vane motor.

The prime factors in selecting the motor for drilling/milling applications are as follows:

  1. Operating flow rate required
  2. Downhole restrictions
  3. Stall torque produced
  4. Downhole temperature

The following guidelines provide an approach to determine the appropriate motor for an operation:

  1. Determine maximum operating flow rate through the coiled tubing. This may be achieved using computer simulator equipment.
  2. Check manufacturers data to determine the largest motor size applicable for the flow rate.
  3. Check that the motor will pass through the minimum completion ID. The motor must have a minimum clearance of 0.25" (6.4 mm) to allow for the necessary larger bit size.
  4. From the manufacturers data, determine the stall torque produced and check for the risk of failure posed to the coiled tubing.
  5. Check that the downhole temperature is within the limits for the motor. Consult the manufacturer on alternative motor availability if necessary.

The size of the coiled tubing required will vary dependant on the fluid carrying capacity and flowrates necessary to complete the task.

4.9 Circulating subs

This type of tool is used in applications, such as drilling, milling and underreaming, and provides two functions;

  1. Enables maximum flow with minimal pressure drop to facilitate efficient cleanout of the wellbore at the end of an operation.
  2. Provides an emergency circulation point if the motor seizes and/or the coiled tubing is stuck downhole.

The circulating sub is ball activated. Care must be taken when selecting the sub to ensure that the ball size is able to pass through the BOSS tool (if present) without causing tool release activation.

4.10 Rotary jetting tool assembly

Research into jetting technology has helped to develop nozzle and flow relationships to optimise jetting operations. Pulses of jetting pressure have been shown to be more effective for scale removal. Cyclic pulsing is achieved by rotating the nozzle assembly.

The assembly includes a filter, centralisers, rotary mechanism and a jetting mole. The filter has a wound stainless steel element that removes particles down to 0.002" to minimise abrasion of nozzle internals and to prevent plugging. Solid centraliser rings fixed to each end of the filter housing maintain optimum positioning of the jetting mole in the wellbore. The tool assembly is supplied with a variety of jetting moles, each designed to optimise standoff geometry for production tubing of a particular ID. The configuration of active nozzles and the orifice diameter in each nozzle are selected to match specific job requirements.

4.11 Rotary indexing sub

The tool is used either as a kick over tool for negotiating past an obstacle (i.e. liner tops) or for orienting in applications such as drilling, fishing, etc.

The spring loaded J-slot indexing tool will rotate through a fixed angle when pressure is applied. When pressure is released the spring returns the index pin to a new position in the J-slot. Re-applying pressure repeats the rotation sequence.

A version of the indexing sub which works on the pressure drop caused by the fluid flow is also available.

4.12 Jars and accelerators

An accelerator acts as a stretch simulator, compensating for the lack of stretch in the coiled tubing during heavy jarring or at shallow depths. However, before using these tools, detailed planning needs to be undertaken to ensure the workstring will remain within the operating envelope.

Large jar and accelerator combinations can develop enormous impact loads. As such, tools run in the bottomhole assembly, which incorporate shear pins, must be designed so that the shear pins are cushioned from the impact. The coiled tubing and connectors should also be sized for the required service duty.

Most jarring operations use upward firing jars, although bi-directional jars are available and are useful for certain operations. The size of the impact generated by jarring downward with coiled tubing is much smaller than the impact generated by jarring upward, because of the limited set down weight available to trigger the jar.

Downward jarring operations can generally be more easily accomplished using hydraulic percussion tools.

A number of conventional jar manufacturers supply ported jars and accelerators which permit circulation through each tool. Hence when coiled tubing is used with regular wireline running tools, which are themselves ported, it is possible to wash over, latch, jar and retrieve all in one trip.

4.13 Hydraulic percussion tools

The percussion drill (or impact hammer) is a vibratory impact drill similar to a "jack-hammer". It can operate on nitrogen, foam, water and other typically encountered oilfield fluids. Percussion tools are finding increasing use in downward jarring applications and, in particular, as part of the operating assembly for manipulating sliding sleeves in horizontal completions.

The stroke of the tool is small and frequency of impact can vary from 1/2 to 30 Hertz depending on make, fluid pump rate and set down weight.

Unlike conventional downhole motors, percussion drills do not use sensitive rubber stators and hence find useful application in operations involving aggressive solvents or high temperatures.

4.14 Inflatable bridge plugs

This type of bridge plug can be run on coiled tubing and accurately set at a chosen depth within the well conduit. In the same operation the coiled tubing can be unlatched and cement placed directly above the packer, thus serving as a permanent plug.

Coiled tubing bridge plug systems typically comprise of the following components:

  • Coiled Tubing End Connector and Plug Catcher
  • Double Flapper Check valve
  • Boss Tool
  • Tubing End Locator - accurate depth referencing is essential if the bridge plug is to be positioned in the right place.
  • Circulating Sub - this allows medium-rate circulation to be carried out while running in hole. As flowrate is increased, this sub will close and communication is made to the bridge plug below.
  • Bypass Sub - a flow operated sub which cushions the packers from shock-loading when the circulating sub closes and avoids inflating the packers too quickly.
  • Pressure Release Sub - this tool allows the packer to be released after inflation. It is similar in operation to the BOSS but operates on pressure alone.
  • Pressure Lock Sub - this tool closes when the packer is inflated to its set pressure and isolates the inflation charge.
  • Inflatable Element
  • Tubing Anchor - optional tool run if excessive cross-flow exists. The anchor grips the casing wall before the packer is fully inflated and prevents the packer moving uphole before it has fully sealed against the casing wall.

4.15 Straddle packer tools/selective placement tool

With retrievable straddle packer tools (selective placement tools) conveyed on coiled tubing, specific regions of the production interval are isolated from the rest of the completion by inflatable rubber elements. Once inflated, a port between the two elements is opened and the treatment fluid is squeezed into the formation. The tool can then be deflated, moved to another location in the completion and reactivated. Designed to pass through minimum IDs while deflated, existing straddle packer elements will create an effective seal in casing sizes up to 7".

Key to the operation of the Selective Placement Tool (SPT) straddle packer is the inflatable packing element. This is designed, not only for multiple high pressure inflations and deflations at full downhole pressures and temperatures, but also to minimise permanent set or swelling of the elastomers.

The packers can thus be safely moved through the smallest restriction in the completion.

When assembled for running, the complete tool string is typically 20 feet in length with an outside diameter of 21/2", allowing it to be run and retrieved through a minimum internal diameter of 23/4".

In its standard configuration, the tool consists of:

  • End Connector and BOSS Tool.
  • Sequence Valve - optional tool depending on hydrostatic gradient of the well.
  • Tubing End Locator - essential tool to ensure squeeze occurs at the desired position downhole.
  • Circulating Sub - this allows medium-rate circulation to be carried out while running in or pulling out of hole. As flowrate is increased, this sub will close and communication is made to the straddle packer tool below.
  • Straddle Packer Tool - this tool consists of two packer elements separated on a sub to allow the desired lengths of interval to be treated. The packers inflate once the circulating sub closes. Communication to the annulus between the inflated packers is then achieved by setting down weight and thus shunting an internal mandrel. After the treatment, picking up weight moves this mandrel back and then re-opens the circulating sub. This allows the packers to deflate to their original dimensions, ready for the next treatment cycle.

4.16 Connectors

A variety of connectors are used in coiled tubing operations to assemble the BHA to the coiled tubing string and in addition make field repairs to the coiled tubing. In general, the choice of connection depends on the type of duty to be performed, as most connectors are not rated to the tubing specifications.

The roll-on fitting, originally developed for 1" coil tubing over a decade ago, works well for light duty operations, if properly engineered and correctly installed. To ensure roll-on fitting strength is achieved, each weight (wall thickness) of coiled tubing requires its own size of fitting and individual crimping wheel.

The roll-on fitting is not designed for heavy duty drilling, percussion or repeated jarring operations where shock loading, tension, vibration are present or rotation is required. For such heavy duty applications a more robust fitting is required such as the external grapple connector. This type of connector has been designed not only for strength but also ease of assembly and disassembly on site.

4.17 Coiled tubing logging connector (CTLC)

Since circulation is often required during coiled tubing logging operations, the CTLC features circulation ports and a check valve in addition to components required to attach the logging tool to the coiled tubing.

The check valve is spring loaded and can be adjusted to provide back pressure if required.

The tool includes an anchor sub which secures the logging cable, and a bulkhead sub where the logging cable is attached to conventional electric line pin connections. Below it is a left hand/right hand connector sub which attaches to the tension release tool (TRT). A spring and collet tension release joint provides an emergency release mechanism and is used in preference to shear pins, which can be damaged under accidental impact loading.

On the bottom of the tension release fishing neck are run a variety of standard crossovers which will connect to all major logging company tools.

4.18 Stiff wireline back pressure valve (SWBPV)

The role of this tool has moved from preventing fluid fall out, to maintaining a positive coiled tubing pressure, to eliminate the risk of coiled tubing collapse.

The valve setting may be adjusted as required, dependent on operating conditions. When selecting a setting it can be tempting to set a high value to ensure that the tubing will be sufficiently pressurised. The danger of setting too high a value is that circulation may not be possible when downhole, due to exceeding the pressure rating of the coiled tubing as a result of the difference in hydrostatic pressures.

As a general rule the valve setting should maintain the coiled tubing pressure around 500 psi above the closed-in wellhead pressure.

4.19 Tension release tool (TRT)

The principle function of this tool is to combine the role of both a shock tool and a weak link during aggressive operations, e.g. perforating with stiff wireline. The result of firing guns on coiled tubing, especially in fluid filled wells, produces a severe shock wave. The shock wave first travels downwards away from the bottom hole assembly (BHA) but is reflected at the bottom of the hole. Upon travelling upwards the shock wave, as it passes through the BHA and coiled tubing, is enough to cause shearing of the conventional weak link/fishing neck arrangement of the stiff wireline back pressure valve (SWBPV). To alleviate this problem the TRT is able to absorb the shock due to the presence of disc springs. The disc springs coupled with a collet arrangement also provide the weak link by enabling release of the BHA upon application of a constant pre-determined load. The TRT fits directly onto the SWBPV by replacing the original shear sub and fishing neck.

A crossover is required to attach the TRT to any logging or perforating tool.

4.20 Logging and perforating tools

Most service companies supply both logging and perforating tools for use with coiled tubing.

Because of the variation in guns and associated equipment, reference must always be made to service company literature when planning this type of application so that the most appropriate tool is selected..

4.21 Fishing tools

4.21.1 Coiled tubing connector

Slip type connectors which employ a fishing neck and a dual sealing system are utilised when fishing with coiled tubing. The primary improvement in this tool is the incorporation of a heavy duty thread, which increases the strength and minimises BHA length by eliminating crossovers.

4.21.2 Check valves

Check valves are utilised during fishing operations when there is wellhead pressure. Flapper type checks must be utilised so that the ball to activate the hydraulic disconnect can pass through.

4.21.3 Overshots and Spears

There are several types of overshots including spiral grapples, rolling dogs and other speciality tools similar to those used in conventional operations. These tools have no releasing mechanism when utilised with coiled tubing. If the fish cannot be retrieved after latching the overshot, it is necessary to activate the hydraulic disconnect leaving additional tools in the hole.

Hydraulic release overshots and spear have helped minimise the amount of additional fish left in the hole, if the fish cannot be retrieved:

  • Hydraulic release overshot: A hydraulic release overshot has been developed which allows the tool to be released from the fish by pumping through the coiled tubing. One specific application is when fishing inflatable bridge plugs. Care needs to be taken as the required size of parts to activate the releasing mechanism is dependent upon the depth and fluids in the well and must be checked prior to running in the hole.
  • Hydraulic release spear: Internal fishing necks are used for most hydraulic disconnect and plug applications, such as the OTIS GS fishing neck. Hydraulic release spears have been developed which latch the fish neck and allow the tool to be disengaged if the fish cannot be dislodged.

4.21.4 Hydraulic disconnect

The hydraulic disconnect operates in a similar manner to the BOSS tool. It should be run as deep in the fishing string as possible to minimise additional fish left in the hole, should it become necessary to disconnect. The tool should be run below hydraulic jars as they complicate the fishing operation if left in the hole. This is not only due to the length of the fish, but also the additional jars often reduce the effectiveness of jarring with the next fishing string.

4.21.5 Hydraulic jar

Hydraulic jars provide impact and help overcome the lack of tensile strength of the coiled tubing. When selecting a jar for use with coiled tubing, there are six primary parameters which must be considered:

  • The length must be minimised in case of lubricator restriction.
  • The jar delay must be sufficient to allow the coiled tubing to be pulled to the appropriate tensile load.
  • It must provide good impact.
  • It must be sufficiently rugged to continue to operate.
  • It must be easily reset.
  • It must have an ID that will pass the hydraulic disconnect activating ball.

4.21.6 Accelerator

The accelerator is designed to enhance the impact force that the jar applies to the fish. The impact force is a function of the mass of the weight bars and the square of the velocity of the weight bars during the jarring action. The accelerator is included to maximise the velocity of the weight bars, thereby maximising the impact force. It also reduces the impact on the coiled tubing string.

4.21.7 Fishing motor

A primary disadvantage of coiled tubing is the inability to rotate the string. During fishing operations, it is often desirable to rotate an overshot utilised with/without a bent sub and/or wall hook. To provide this flexibility, a downhole motor is required. Reference should be made to service company literature when selecting an appropriate fishing motor for the task.

When a motor is used in a fishing string, the hydraulic disconnect must be run above the motor, as the actuating ball will not pass through the motor.

4.21.8 Bait receptacle

The bait receptacle is a two-section tool, much like the hydraulic disconnect, which is run between the motor and fishing tool. Pins connecting two sections of the bait receptacle are sheared by jarring or applying tensile load, which can be adjusted by the number of shear pins installed. This allows the motor to be retrieved from the hole.

The lower section of the bait receptacle incorporates a fishing neck such that once the tool string is out of the hole and the motor removed, a hydraulic release spear may be installed to latch the bait receptacle (fish).

4.21.9 Knuckle joints and bent subs

Knuckle joints and bent subs are used when the fish is small and well away from the centre of the hole. The knuckle joints are employed with hydraulic centralisers while the bent subs (0.5, 1 and 2 degrees) are utilised with motors.

4.21.10 Hydraulic centralisers

In some applications, hydraulic centralisers are utilised to centre the fishing tools in the hole. The centraliser is also commonly used above a bent sub to provide full coverage when rotating on top of the fish, or below a knuckle joint to reach the high side of the hole. An additional benefit of the hydraulic centraliser is the ability to centralise (while pumping) or not to centralise (stop pumping). This provides two positions to attempt to latch onto the fish during one trip into the well.

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