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Coil Tubing Applications

1 General

Advances in coiled tubing manufacturing techniques and stress/fatigue prediction, have reduced the risk of coiled tubing failure.

In principle, live/flowing well can be introduced in an uninterrupted (no joints) length of tubing. However, there are three basic limitations:

  • Life limits - primarily due to the fatigue by bending that occurs to the pipe when being run on/off the reel and over the gooseneck. Other factors such as internal pressure cycles, corrosion due to exposure or acids, and H 2S environments will affect the fatigue life.
  • Pressure and tension limits - burst and collapse pressures and maximum tension and compression forces.
  • Diameter and ovality limits - pipe monitoring is required to ensure that it is not ballooned, ovaled or mechanically damaged.

4 range of applications of Coiled Tubing (CT) have been identified:

  • Pumping services; hydraulic applications that involve circulation of fluids.
  • Work-string applications; mechanical services that involve the downhole conveyance of required tools or equipment.
  • Stiff wireline applications; electrical services that employ downhole tools which are powered by or transmit through an electrical cable.
  • Completions; permanent applications with coiled tubing installed either as the producing conduit or part of it for flow control or other requirements (e.g. ESP conveyance).

2 Pumping services

The most common coiled tubing application is that of providing pumping services, such as tubing cleanouts and acid stimulation work which eliminates the need for killing the well, bullheading, or contact of the live acid with the tubing string, etc. Nitrogen lifting is used to reduce the hydrostatic pressure of the column to induce production after a well closure or well intervention activity.

Of particular importance in pumping applications is the pressure cycling effect on coiled tubing fatigue life, and the susceptibility of CT to collapse pressure.

2.1 Fluid displacement (nitrogen lifting)

When wells fail to flow on re-opening, they may be "lifted" back into production by the circulation of nitrogen at depth through coiled tubing.

Historically this operation has been performed using slickline (swabbing) techniques. Coiled tubing offers the following advantages:

  • Faster (continuous process).
  • Less likelihood of fishing requirements (swab cups, wireline breakage etc..
  • Greater degree of well control.

Fluid dynamics

While nitrogen lifting can be a relatively straight forward operation, the advent of ever increasing sizes of coiled tubing requires that nitrogen pump rates for each well be considered with some care. Too high a pump rate can form a nitrogen cushion which will not allow formation fluids to enter the wellbore, and too low a rate will result in an inefficient lift. Both extremes will result in extended job times, excessive use of nitrogen and, in the worst case, will not unload enough fluid to allow the well to flow.

The fluid dynamics and associated forces need to be modelled at the job planning stage.

For instance, when running 13/8" coiled tubing into 23/8" production tubing, this provides only a 0.23" annulus. In low pressure wells the friction encountered unloading the well quickly through such a small annulus can exceed the well bottom hole pressure (BHP). This results in most of the nitrogen being pumped straight into the formation.

For large production tubing sizes the friction loss is often very small and liquid slippage becomes the dominating factor. In this situation coil size is not a significant factor other than its effect on possibly limiting the achievable maximum nitrogen injection rates. If the nitrogen supply rate is limited a foaming agent can be used to overcome the liquid slippage.

Of equal importance is the presence of restrictions in the completion - especially near the surface, such as a downhole safety valve. If extreme pressure drops take place near the surface, excessive velocities will be generated and the particulates in the fluid stream can cause erosion of the coiled tubing at the completion restrictions. At very high nitrogen rates this effect should be evaluated in the planning phase of the operation.

It is good practice to start the nitrogen lift at a few hundred standard cubic feet per minute (scfm) soon after the coiled tubing has reached the liquid level (liquid column can be lightened while running in the well, and thus speed up the gas lifting operation. Keep nozzles and check valves clean).

The rate at which gas lifting should be started is variable dependant on the specific well configuration. Most standard gas lift operations are carried out at between 100 to 250 SCFM of nitrogen.

However, it should be noted that when running into a liquid, the hydrostatic pressure at the bottom of the coiled tubing increases. Therefore the nitrogen pressure in the coiled tubing must be increased to overcome hydrostatic pressure before any nitrogen will enter the well conduit. If the internal pressure is not maintained, the tubing may collapse.

The use of accurate nitrogen flowmeters enable bottom hole pressures to be predicted during nitrogen lifting. Real-time drawdown can be predicted and the nitrogen rates adjusted accordingly.

2.2 Reservoir/well improvement (acid washing/stimulation)

2.2.1 Acid washing

Coiled tubing may be used to spot hydrochloric acid (HCL) or other fluids to dissolve scale, such as calcium carbonate. The scale is generally deposited in high water-cut wells and is normally found where a pressure drop occurs, such as the Subsurface Safety Valve and other restrictions.

Other techniques, such as the use of CT with jet nozzles or milling tools and placement of acid with wireline run dump bailers, are viable alternatives to acid washing.

2.2.2 Acid stimulation (matrix acidising)

Coiled tubing may be employed to spot an acid treatment over the perforations, from where it can be squeezed into the formation.

Coiled tubing is used in acid washing/stimulation operations for several reasons:

  • Spotting the treatment fluid across the perforations is more effective than bullheading large quantities of fluids.
  • Spotting avoids squeezing potentially contaminating wellbore fluids and tubing solids into the formation.
  • Allows complete coverage of the producing interval (although it does not ensure uniform injection) by moving the CT while spotting the fluid.
  • Reduces the well conduit exposure to the acid, which is important for some exotic or chrome tubulars.
  • Accurate and controlled placement of treating fluid can be performed with the use of straddle packer tools (refer to Section 3.4.15).
  • Permits jet washing to remove superficial scale. By using high nozzle jetting energy and cycling over the target zone, contact with the scale material can be maximised (refer to Section 2.2.3).

The technique of underbalanced acid washing is sometimes proposed. It involves the circulation under conditions designed to ensure a positive drawdown of the formation while washing to assist in the removal of damaging fines. However, this begs the question as to whether the acid then actually enters the formation as intended on a localised basis, directly adjacent to the CT nozzle(s).

Particular attention should be given to planning the corrosion inhibitor schedule for acidising treatments. Most inhibitor schedules have been developed for standard concentrations of regular acids in contact with regular steel tubulars. New types of chrome and duplex steels are more prone to acid attack which has prompted the development of completely new inhibitor/intensifier packages.

2.3 Fill cleanouts (sand removal/pressure jetting)

An important consideration in fill clean-out operations is the well configuration and calculation of fluid velocity at every restriction to prevent serious abrasive damage. This and the fluid carrying capabilities/dynamics are best modelled on a computer simulation to ensure optimum job planning.

In broad terms cleanouts are divided into two categories:

  • Removing Solids - formation sand, frac sand etc.
  • Removing Sludge

The removal of sludge is generally best accomplished by breaking up and dispersing the sludge through the combined action of chemicals (surfactants and solvents) and vigorous mechanical agitation (achieved by high pressure jetting). The resulting liquid dispersion can then be readily circulated out of the well.

Solid fill, however, is substantially heavier than the typical fluids which are currently available for well servicing. As a result, the mechanics of particle transport determine the method of fill removal.

There are several different coiled tubing cleanout techniques available, each having distinct advantages for specific well conditions. Each cleanout technique relies on generating circulation conditions in which the circulated media develops optimum transport characteristics for the fill material present.

In vertical wells with high pressures, cleanouts are readily performed simply by running the workstring into the fill while pumping water. With the flow in the annulus carrying the fill to surface, the particle transport velocity can be determined as a function of Stokes law. For most fill types encountered, the fluid velocity is designed to be at least twice the particle fall rate. When required, viscosity enhancing agents such as gellants can be used to achieve this ratio.

When pressure conditions in the wellbore are too low to support the annular flow conditions created by the cleanout, introducing nitrogen or foam into the fluid lift medium to reduce hydrostatic pressure becomes necessary.

Good quality foam (75% or better) has excellent fill carrying capability but suffers from two disadvantages:

  • Foam generates significant flow friction making cleanout operations slow and inefficient when used in small annulai.
  • High costs associated with handling and breakdown of the foam returns at surface.

Alternatively, nitrogen pumped in stages (slugs) will reduce hydrostatic pressures for cleanout operations. If proportioned properly, the same hydrostatic pressure reduction can be realised as for foam cleanouts. The advantage is that high flow friction resulting from the shearing of stable foam will not be encountered and returns to surface are more easily handled.

Fill cleanouts in deviated profiles require a completely different approach to be successful. The coiled tubing and particles will be lying on the low side and the fluid velocity in the area will be relatively "stagnant"

Once deposited on the stagnant side of the hole, neither high viscosity fluids, gels nor foam can develop enough turbulence to re-establish particle transport. A secondary problem with foam is that some liquid will also break out of the foam, fluidising the settled particle bed and causing it to run down the wellbore.

The simplest way to remove this settled fill layer is to generate extreme turbulence within the carrying fluid so that the fill can be picked up and moved further up the hole. Water, having a low viscosity, is more easily made sufficiently turbulent such that moderate size fill can be successfully cleaned out of deviated wells. In larger diameter completions water/nitrogen slugs may be required to achieve the required annular velocity.

In exceptional cases it may be necessary to flow the well and use the production co-mingled with the cleanout fluid to achieve the required critical velocity. However, the safety and surface treatment implications of this technique need to be fully evaluated.

2.3.1 High pressure jetting

High pressure water jetting is well established in general industry for cutting, cleaning and surface preparation.

Water jetting operations, or hydra blasting as it is sometimes known, is also being applied downhole where the precise control required to maintain optimum jetting conditions is much more difficult to achieve. A significant factor of consideration in the use of HP jetting is the effect that the pressure has on the life of the coil of tubing.

A variety of factors influence the effectiveness of a water jet, with pressure being the most significant. However, since the coiled tubing operating life is shortened significantly by higher operating pressures, it is generally not economically viable to use jetting nozzle pressure drops much above 2,500 psi.

As with any fluid delivery system, there is a trade-off between pressure and the volume flowrate available to the tool. Jetting tools which employ high pressure drops at the expense of volume flowrate (usually very small nozzle diameters) are less effective than a more balanced combination. Similarly, high volume flowrates achieved at the expense of jet pressure are not very effective.

Tensile stress is the predominant failure mechanism for rock and chemical scale subjected to high pressure jets. High pressure water penetrates surface cracks creating local areas of tensile loading. Cyclical stress via pulsation of the jet, or rotation of the jetting tool, accelerates the rate of material removal.

The standoff distance between nozzle and target is very important. The design of the nozzle profile will maximise the effective standoff distance and permit higher individual volume flowrates for the same pressure drop and ID. Tools with higher individual flowrates through a small number of nozzles are more effective than tools with smaller flowrates through a large number of nozzles, provided the entire target surface is covered during tool rotation.

Additives are commonly used to make water more effective as a jetting medium. The use of long-chain polymer friction reducers (most commonly polyacrylamide) increases the effective standoff distance by reducing the tendency of the jet to diverge as it travels away from the nozzle. Also, very important in downhole applications, is the significant increase in pressure available at the nozzle as a result of reduced pressure drop due to friction along the coiled tubing.

2.4 Remedial/abandonment (sand consolidation/cementing)

Coiled tubing may be employed as the mechanism through which sand consolidation or cementing tasks are performed. This prevents the need for either bullheading or circulating up the tubing/casing annulus.

2.4.1 Chemical sand consolidation

Sand consolidation systems attempt to control sand influx by treating the formation around the wellbore with a fluid containing a binding agent. This increases the integrity of the sand without a significant loss in permeability. Plastic sand consolidation (SCON) systems can be pumped downhole by a number of means, such as through the drill string, work string, production tubing, snubbing unit or coiled tubing. The treatment is generally applied as part of the initial completion of the well, when the rig is on-site, by pumping down the clean completion string. However, in remedial instances the use of coiled tubing may in some cases be more cost effective.

The use of coiled tubing gives the following advantages:

  • Displacement volumes are small, reducing job duration
  • The treatment fluid is kept clean more easily (from tubing/liner scale)
  • Reduces commingling of fluid treatment stages
  • Allows precise placement of treatment fluid

The Selective Placement Tool (SPT), also referred to as the Straddle Packer Tool, has been successfully used to treat several intervals sequentially. The characteristics of the narrow workstring facilitate pumping in turbulent flow to prevent mixing of the treating fluid with the spacer fluids. Additionally plugs may be used.

2.4.2 Cementing

For the same reasons as discussed above, coiled tubing may be used to carry out cement jobs, such as:

  • Squeeze cementing: This involves cement being precisely spotted at the perforations. Additional pressure is then applied to dehydrate the cement slurry within the perforation tunnels in order to isolate selected perforated zones. (Generally this technique is not particularly successful for perforation isolation.)
  • Cement plugs: This involves the placement of a column of cement within the production casing to isolate the lower section from above. The minimum slurry volume to be placed which would form an effective plug downhole, will depend on the casing ID. Generally 0.75 bbl is accepted as the minimum quantity that can be pumped. For such small jobs, use of displacement plugs is essential, refer to Section 3.4.3. To provide a platform on which the cement rests until it sets, bridge plugs, high viscosity gel pills or sand is commonly used.

Assuming that the maximum working pressure of the coiled tubing is not exceeded, there is no limit to the quantity of slurry which can be pumped through coiled tubing. However there are other limiting factors which must be considered, i.e. pressure/stress limitations and friction considerations.

The design of a coiled tubing cement job is no different from any other, not withstanding the coiled tubing fatigue and dynamics limitations. Full details on all aspects of cementing are provided in EP 50500, Cementing Manual.

3 Work string

Coiled tubing was originally developed for workover services in live wells, which is one of its main advantages as a work string. It permits through tubing well intervention to perform a range of tasks from setting bridge plugs in the production casing to milling and drilling operations.

The fatigue of the coiled tubing is an important consideration when used as a work string, in conjunction with well control and equipment deployment. The tubing size favours slimhole drilling and it finds application in multi-drain hole drilling. Many of the drilling operations are conducted together with electric wireline.

Coiled tubing lends itself to underbalanced drilling, as the continuous tube eliminates connections and improves well control. The equipment is smaller than that of conventional rigs, which results in reduced location size, lower mobilisation costs, and a reduced environmental impact. This also makes coiled tubing a cost effective alternative for use in well re-entries, such as to mill windows in the production casing (dependant on casing size and window length) and to drill directional drainholes.

Within the producing phase of the well life, coiled tubing will more commonly be used for scale/fill removal where drilling/milling is required, fishing operations within or through the production tubing and "standard" wireline operations in horizontal, long reach or highly deviated wells. In these applications it is necessary to fully evaluate the operating envelope of the coiled tubing, with particular reference to buckling and stress effects.

Tool string deployment systems have been developed to accommodate the connection and disconnection of long bottom hole assemblies (BHA).

3.1 Drilling/milling

The operation uses a coiled tubing to which a downhole motor coupled with a bit is attached. This is used to break up downhole deposits such as scale or cement, or to mill out an obstruction or side window within the completion.

When planning this type of operation, the type of bit and motor required significantly affect the efficiency of the task to be performed.

3.2 Underreaming (within cased hole)

Underreaming with coiled tubing has become a cost effective method of cleaning out the production casing and liner e.g. of scale or cement after a squeeze operation.

When utilising an underreamer, stabilisation is critical since coiled tubing weight is being applied in large ID tubulars. The application of weight on bit (WOB) increases the buckling tendency which may be minimised with the appropriate use of adjustable stabilisers.

3.3 Fishing

Tools have been developed which have significantly increased the use of coiled tubing for fishing operations.

There are a large number of different types of spears, overshots, mills, guide shoes etc., now available. The technique for running them requires experience with the tools and also the way the coil tubing and injector head behave. Precise control of the injector, low stuffing box friction and good weight indicator performance are all factors which can influence the outcome of a fishing operation.

Equipped with jarring tools and percussion equipment, high pulling and pushing forces can be developed to free objects downhole. Combined with the ability to circulate fill from the hole, deliver acid or rotate with hydraulic indexing tools, a number of techniques can be performed which are not available with conventional wireline fishing.

3.4 Coiled tubing slickline operations

The ability of coiled tubing to be "snubbed" into the well provides it with a horizontal reach capability. Jobs normally performed by wireline in vertical wells, such as moving sliding sleeves, need to be performed using coiled tubing in horizontal, long reach and highly deviated wells. For such applications careful consideration needs to be given to the coiled tubing buckling tendencies. Additionally, development work is ongoing with downhole traction systems to overcome the coiled tubing "push" limitations.

4 Stiff wireline

Stiff wireline operations should not be confused with coiled tubing conducted "slick line" operations, e.g. pulling plugs, etc. Stiff wireline, by definition, involves the transfer of an electrical signal from the bottom hole assembly (BHA) back to surface, and is the term given when using coiled tubing to carry out operations normally carried out with electric wireline. The most obvious example is a production logging operation but stiff wireline operations also include electric set packers, perforating and downhole video. Most drilling operations using coiled tubing also employ the stiff wireline technique in order to steer the BHA.

Reservoir zones are being increasingly targeted away from the fixed drilling location. As a result, horizontal or high angle, long reach wells with excessive wellbore friction may not permit the entry of conventional gravity propelled electric wireline equipment. Electric wireline has therefore been placed inside coiled tubing to use the coiled tubing's horizontal reach capability. In the case of downhole video, it is used when fluid circulation is required in conjunction with the task.

For regular logging operations, a seven conductor logging cable is available inside 11/4", 11/2" and 13/4" diameter coiled tubing. The annulus between the logging cable and coiled tubing is sufficient to permit nitrogen or other fluids to be circulated during data gathering operations.

Stiff wireline applications use the same surface equipment as any other coiled tubing operation, with the addition of a coiled tubing collector or slip ring assembly mounted on the reel. This provides a means of communication from the electric wireline, which is on the reel, to a fixed point allowing communication between the bottom hole assembly and the control unit. The collector is normally attached to the reel.

Many applications for stiff wireline, for example perforating, may require long BHAs, which are accommodated using tool string deployment systems.

4.1 Logging

The following cased hole logging operations may be carried out using stiff wireline:

  • Fluid Density
  • Flowmeter
  • Hydro
  • Pressure
  • Temperature
  • Combination Production

Production logging of low pressure wells can be carried out effectively by circulating nitrogen gas through the workstring, creating both the necessary formation drawdown and lift to bring returns to surface.

The sub-surface equipment used is similar to other coiled tubing applications with the addition of a Stiff Wireline Back Pressure Valve (SWBPV).

4.2 Perforating

The deployment of tubing conveyed perforating guns and other explosive devices using coiled tubing allows perforating tasks to be performed in underbalanced (live) well conditions.

Conventional or pressure activated perforating guns can be run on coiled tubing, however, shear pin release tools should NOT be used. The resulting shock wave from firing the guns can easily generate enough force to shear the largest of any conventionally rated pins.

Since the use of some form of release tool is always advised, alternatives to shear pins are necessary, such as the Tension Release Tool which fits directly on the SWBPV mentioned above.

Completion design, Perforating Perforating, describes perforating techniques in greater detail.

4.3 Downhole video camera

Visual inspection of downhole conditions has been made possible with the development of downhole camera systems. In conventional operations this equipment is run in the well on special coaxial wireline and is limited to use in wells with clear fluids, gas, filtered water, etc.

By making coiled tubing/coaxial wireline strings in the same way coiled tubing/logging strings are assembled, clear fluids can be pumped through the workstring and spotted around the camera permitting visual inspection in wellbores containing opaque fluids.

5 Completions

The initial use of coiled tubing in completions was to hang the coiled tubing off inside the well completion to reduce the flow area. These coiled tubing (velocity) strings increased the velocity in gas wells allowing them to unload the wellbore fluids.

The development of larger sizes of coiled tubing have increased the application and development of coiled tubing completions and associated hardware accessories, such as gas lift mandrels which can be spooled. The main advantage over conventional tubing is that it can be run quickly into the well without having to make up or break tubing joints, and hung off under live well conditions. The application of coiled tubing with "spool" (horizontal) Xmas trees further enhances the benefits for use in wells which require "frequent" intervention, such as ESP wells.

The goal of the CT completion system is to deliver, to the well site, a completion string assembled and tested ready to run in the hole without having to kill the well. Equipment available for running with integral completions includes:

  • Gas lift valves.
  • SCSSVs with integral control line
  • Nipples
  • Inflatable external casing packers (ECP)
  • Permanent and retrievable packers
  • ESPs
  • Liner hangers and liners

The coiled tubing material, of which the most widely used is high strength low alloy (HSLA) steel, is a factor which needs to be considered in conjunction with the well parameters, particularly the fluid environment. The potential use of exotic materials, such as titanium and a Kevlar-Composite, in harsh well environments, is under development.

The biggest challenge, however, to the widespread application of coiled tubing completions, is the logistics associated with the transport and siting of large, heavy reels. Offshore cranes have limited lifting capacities and space availability is restricted for 15 ft or larger diameter reels spooled with 3.5 in tubing. The development of connectors and welding techniques (amorphous bonding) allow separate coiled tubing reels to be transported and connected together while running the completion.

5.1 Production and velocity strings

5.1.1 Velocity strings

Velocity strings are tubing hung off in existing gas well completions to enhance production. When the gas velocity in a given completion is too low to effectively remove all of the produced fluids, a steady build up of wellbore static fluid will occur and result in the well eventually killing itself.

To overcome this problem, coiled tubing can be "hung off" inside the production tubing to reduce the flow area and increase the gas velocity. Careful job design will ensure that the increased gas velocity will transport the produced liquids while keeping flow velocities at sufficiently moderate values to minimise friction pressure losses.

The flow can either be directed up the coiled tubing itself, or up the coiled tubing/production tubing annulus, whichever is determined to provide optimum flow conditions.

Whether flowing up the production string or the annulus, the gas velocity will steadily increase as the pressure decreases and the gas expands. With this increase in velocity, flow friction may become high, negating the anticipated velocity gains.

To overcome this effect, strings with an outside diameter taper (diameters reducing up the velocity string or down the production string) can be designed to compensate for the gas expansion and produce a uniform friction gradient throughout the flow conduit.

5.1.2 Production strings

Coiled tubing production strings may consist of an externally upset system (whereby the accessories, such as gas lift mandrels etc., are connected to the tubing on site) or the spoolable system (where the accessories are installed within the coiled tubing during the fabrication process).

5.2 Injection strings

Depending on the specific well conditions, it may be necessary to periodically or continuously deliver various treatment fluids downhole. Small diameter coiled tubing strings can readily be used in the completion to act as a conduit for fluids such as inhibitors, solvents or heated liquids. Other applications include using an injection string to act as a gas lift "kick-off" system to assist in unloading wellbore fluid.

5.3 Tubing patches

Tubing patches are utilised to isolate a section of tubing in the event that the tubing is holed. The patch consists of two Straddle Packers with a section of coiled tubing in between. The packers are run until they are positioned above and below the holed section of tubing. The packer rubbers are then inflated effectively sealing off the damaged tubing. (Mechanical type straddle packers are also available).

This technique may also be utilised if there is a problem with SCSSV control line leakage or a damaged control line nipple.