COILED TUBING PRESSURE CONTROL

1. COILED TUBING PRESSURE CONTROL

1.1 REVIEW OF COILED TUBING OPERATIONS
Coiled tubing is utilised for a variety of operations Figure 1 and Figure 2, including:

Workovers Stimulation
Cleanout wellbore debris Removal of wellbore skin damage
Acid washing Spotting diverter agents
Spotting cement plugs Clean out un-displaced fracture proppant
Setting straddle packers/bridge plugs
Fishing
Production Services Drilling Operations
Gas Lifting Freeing stuck drill pipe
Small bore permanent strings Drilling out flash set cement
Cementing
Drilling slim hole
Side tracking
Logging Operations Testing Operations
Stiff wireline (horizontal wells) Gas lifting
Wellbore cleanup

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Figure 1 - Sand Cleanout with Coiled Tubing

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Figure 2 - Gas Lift

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1.2 COILED TUBING PRIMARY SURFACE EQUIPMENT

1.2.1 Reel Unit
Coiled tubing is stored on large reels in the same way as electric cable is stored for downhole
logging operations. The reel is supported on an axle and is rotated by a drive chain driven by
an hydraulic motor. The drive system has a dual function:
• When uncoiling tubing i.e. when running into the well, the motor acts as a
constant torque brake, keeping the tubing between the reel and the gooseneck in
constant tension.
• When coiling tubing, the reel rotates in order to keep the tubing under constant
tension.
The reel drive system is not used to raise or lower tubing into the well.
To ensure that the tubing is correctly coiled onto itself a reeling guide’is synchronised with the
rotation of the reel by a chain drive taken from the axle.
The inner end of the coiled tubing is connected to the hub of the reel, which incorporates a
rotating joint. Fluids can be pumped through this joint and down the coiled tubing while the
reel is stationary, or rotating, at any pressure up to the specific working limit of the coiled
tubing itself. In order to be able to circulate a ball down the work string, to operate downhole
tools, the coiled tubing reel is fitted with a ball launcher. The launcher allows the ball to be
introduced into the coiled tubing without the need to depressurise or break any connections.
Typically two coiled tubing reels are supplied for each operation in case of a failure of the
primary reel.

Without tubing 9,000 lbs

With 15,000 ft 11/2” tubing (0.125 wall) 36,000 lbs
Tubing length
11/4” 17,000 ft
1
1 /2” 13,000 ft
Dimensions
Length 12 ft
Width 8 ft
Height 10 ft
Table 1 - Reel Unit Dimensions

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Figure 3 - Typical Coiled Tubing Rig Up

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1.2.2 Coiled Tubing Operational Life

As the types of services being performed with coiled tubing increase, the demands on the
coiled tubing pipe itself increase. It is important that the limitations of the coiled tubing pipe
are thoroughly understood, before these more demanding services are performed. Typical
properties are given in Table 2.
Since its introduction in the mid 60’s, coiled tubing has developed a somewhat checkered
history. There were too many stories about pieces, or entire strings of coiled tubing left in
wells. During the 70’s and early 80’s the use of coiled tubing reached a plateau, primarily
because of its poor service quality record. In recent years, tremendous improvements have
been made in the quality of coiled tubing pipe and in the understanding of coiled tubing
limitations. These improvements have resulted in a decrease in coiled tubing pipe failures, and
an increased acceptance of coiled tubing applications.
There are four coiled tubing limitations that must be understood:
1. Life Limits When being run on and off the reel and over the
gooseneck. (often with internal pressure on the pipe)
2. Tension Limits Which vary with depth and weight of coiled tubing.
3. Pressure Limits Burst and collapse pressure vary with tension and
compression.
4. Diameter and Ovality Limits Real time monitoring of the pipe is required to ensure
that the pipe is not ballooned, ovaled, or mechanically
damaged.
It is important that all these limits are considered together. For example the life limits allow
1.25” OD coiled tubing with a 0.087” wall thickness, made of 70,000 psi yield material, with
5,000 psi internal pressure, to be cycled in and out of the hole about 40 times before reaching
the limit.
This means that the pipe will not fail due to fatigue before this point. However, when the pipe
reaches this limit, it will have grown from 1.25” OD to 1.5” OD, which is far beyond the
acceptable diameter limit.

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Pressure capacity
Dimensions Weight Load
OD ID psi
(ins) wall lbs/ft capacity
yield min lbs Burst
Tested
nom nom nom nom yield
0.875 0.087 0.701 0.737 14,455 10,624 13,280
1.00 0.067 0.866 0.688 12,982 7,056 8,820
1.00 0.075 0.850 0.741 14,505 7,952 9,940
1.00 0.087 0.826 0.848 16,738 9,296 11,620
1.00 0.095 0.810 0.918 18,191 10,192 12,740
1.00 0.102 0.796 0.978 19,262 10,864 13,580
1.00 0.109 0.782 1.037 20,492 11,648 14,560
1.25 0.075 1.100 0.941 18,409 6,362 7,952
1.25 0.087 1.076 1.081 21,301 7,437 9,296
1.25 0.095 1.060 1.172 23,194 8,154 10,192
1.25 0.102 1.046 1.250 24,595 8,691 10,864
1.25 0.109 1.032 1.328 26,210 9,318 11,648
1.25 0.125 1.000 1.506 29,375 10,573 13,216
1.25 0.134 0.982 1.597 31,583 11,469 14,336
1.25 0.156 0.938 1.840 35,867 13,261 16,576
1.50 0.095 1.310 1.425 28,197 6,795 8,493
1.50 0.102 1.296 1.522 29,928 7,243 9,053
1.50 0.109 1.282 1.619 31,928 7,765 9,707
1.50 0.125 1.250 1.836 35,862 8,885 11,107
1.50 0.134 1.232 1.955 38,620 9,557 11,947
1.50 0.156 1.188 2.245 44,004 11,051 13,813
1.75 0.109 1.532 1.910 37,645 6,656 8,320
1.75 0.125 1.500 2.190 42,350 7,552 9,440
1.75 0.134 1.482 2.313 45,657 8,192 10,240
1.75 0.156 1.438 2.660 52,140 9,472 11,840
2.00 0.109 1.782 2.201 43,363 5,824 7,280
2.00 0.125 1.750 2.503 48,837 6,608 8,260
2.00 0.134 1.732 2.671 52,694 7,168 8,960
2.00 0.156 1.688 3.072 60,277 8,288 10,360
2.375 0.125 2.125 3.010 58,568 5,565 6,956
2.375 0.134 2.107 3.207 63,250 6,036 7,545
2.375 0.156 2.063 3.710 72,482 6,979 8,724
Table 2 - Sizes, Dimensions, Pressure Ratings and General Information about Commercially
Available Coiled Tubing.

Load capacity - Yield minimum calculated on minimum wall.

Tested: Test pressure value - 80% of internal yield pressure rating.
Maximum working pressure is a function of tube condition and is determined by user.
All data is for new tubing at minimum strength.

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In order to more accurately track fatigue loading conditions in the field, most coiled tubing
companies have developed computer based systems to quantify and record the historical job
exposure of each string. Depending on the internal pressure present in each section of the
coiled tubing while reeling, unreeling or travelling over the gooseneck, varying factors are
applied to the cycle count to adjust the cycle life of that section. Past and present job data are
merged and kept on file to maintain up-to-date records for each string.
The calculation and table below serve to demonstrate how coiled tubing is stressed beyond its
elastic limit each time it is run over the gooseneck or spool. Yield strength is reduced
considerably when stressed with internal pressure.
The minimum bend radius for coiled tubing around the reel or gooseneck can be calculated
using:
R = E (D/2) / Sy (answer in inches)
E = 30 × 106 psi (modulus of elasticity for steel)
D = OD of coiled tubing
Sy = material yield strength
for 70,000 psi coiled tubing:

Coiled tubing OD Minimum bending radius (ft)

0.75 13
1.00 18
1.25 22
1.50 27
1.75 31
2.00 36
2.375 42
Table 3 - The Minimum Bending Radius

Beyond this minimum bending radius the steel will be stressed beyond its elastic strain limit.
When coiled tubing is initially spooled plastic deformation will take place. There are six
bending and straightening cycles. (Refer to Figure 4)

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Figure 4 - Bending Cycles

1&6 Pipe is pulled off or spooled on by the injector head. The reel hydraulic motor
resists placing the coiled tubing in tension and straightens the primary bend in the
coiled tubing.
2&5 Around the gooseneck the coiled tubing is bent around a similar radius to the reel.
3&4 The pipe is straightened again as it passes through the injector and into or out of
the well.
Buckling can also be a problem when running coiled tubing. If upward drag forces are greater
than downward injector forces then the coiled tubing will be in compression, and helical
buckling can occur. A contributory factor is the material microstructure due to the spooling
process.

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1.2.3 Tubing Injector Head

The injector head is mounted above the BOPs and stripper and drives the tubing to be run
into and out of the well under pressure.
The coiled tubing is gripped between contoured blocks which are carried by two sets of
double row chains. The chains are driven hydraulically to inject or retract the tubing with
precise control.
It is important that the correct pressure be maintained on the drive chains to prevent the
tubing from being crushed or letting it slip, through insufficient grip. This is achieved by
hydraulic tensioning cylinders which act on the chains through a roller system. Two opposed
rows of drive blocks are forced inward by a series of hydraulically controlled rollers to provide
the friction drive system with the necessary force. This also provides the flexibility necessary
to maintain uniform loading on the work string without loss of traction.
Units are available with pulling power of up to 60,000 lbs. A high and low gear is available to
run the coiled tubing at speeds of 125 and 250 ft/min respectively.
The chains and their motor and gearbox drive system are mounted in a sub-frame, one side of
which is hinged. The opposite lower side rests on a hydraulic load cell which is connected to a
weight indicator in the control unit. The forces exerted by the action of the driving system and
the tubing weight are all applied along the centre line of the tubing and cause the frame to
pivot. The deflection is small and is controlled by the compressibility of the load cell.
The injector head is also equipped with a roller guide, a gooseneck, on the top of the main
frame which is used to receive coiled tubing from the reel and guide it into the chain blocks;
Figure 5.
Weight 10,000 lbs (with gooseneck)
Length 10 ft (including skid)
Width 8 ft
Height 11 ft
Table 4 - Injector Dimensions

Injector head weight indicators are the main source of information on downhole coiled tubing
performance and as such are the single most important instrument on a coiled tubing unit.
Strain gauge instruments are the most accurate type and are becoming more prevalent.

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Figure 5 - Injector Head

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1.2.4 Power Systems And Controls

All coiled tubing surface power and control systems are hydraulic. A hydraulic pump provides
oil for the drive motors of the injector, while a second pump is used to drive the reel. Output
regulators are used to control the operation of the injector and reel. In response to the
operators demand, the regulators are used to impose a given oil pressure on the hydraulic
motors which is converted directly up to a maximum attainable torque.
Adjustable relief valves on the injector drive circuit can be set to limit pressure, restricting pull
and thrust to within the safe working limits of the coiled tubing. This is particularly important
when working with small to medium sized coiled tubing strings, in large casing, where critical
buckling loads are only a few thousand pounds.
The hydraulic tensioner for the injector chains and the stuffing box control are hydrostatic
systems, each with its own hand pump. The BOP is hydraulically controlled by oil stored in an
accumulator. The accumulator is charged by a hydraulic pump by means of an activator valve.
When the accumulator is fully charged, the blowout preventer can be taken through two
complete cycles before recharging is necessary. A hand pump is provided for emergency
operation after the accumulator is depleted. The BOP can also be operated manually.

1.2.5 Control Cabin

The coiled tubing control cabin is sited to provide a clear view of both the injector head and
the coiled tubing reel. It houses all the controls relevant to the operation, including: (Refer to
Figure 6)
• The main hydraulic control panel (to control the injector reel and spooler system)
• Well control package (Stuffing box, BOP functions)
• Recording instrumentation
• Depth correlation.

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Figure 6 - Coiled Tubing Unit Control Panel

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1.3 COILED TUBING PRIMARY PRESSURE CONTROL EQUIPMENT

Pressure control equipment includes:
• Stripper sealing devices
• Annular BOP
• Riser/flanges/quick unions/hydraulic latches
• Multifunction remote controlled BOPs
• Shear seal BOPs
• Kill lines and valves.
At least two barriers should be available at all stages of an operation to prevent the release of
hydrocarbons.
All connections between the wellhead and the nearest barrier device capable of forming 100%
blind seal should be metal ringed sealed flange.
BOP should have the following as a minimum:
• Blind
• Shear
• Slip
• Pipe
• Flanged connection below the blind rams
• Equalising valve across the pipe ram
• Equalising valve across the blind ram.
Hydraulic connectors should only be used above the primary shear and seal BOP. The release
mechanism should be designed so that:
• It cannot be activated when the connector is exposed to wellhead pressure
• It remains latched by means of a simple pressure mechanical system
• An indication device displays the latch status.

1.3.1 Stripper Packer

The stripper packer (or stuffing box) is the primary sealing mechanism for isolating wellbore
fluids while under static or dynamic operating conditions. A conventional stripper is shown in
Figure 7.

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Figure 7 - Conventional Stripper

Conventional Design
The conventional stripper packer uses an hydraulic piston operating from below, to compress
a polyurethane element to effect a seal around the outside of the coiled tubing.
Wear bushings made of brass are run above and below the sealing element to centralise the
tubing before entering the packer insert. A Teflon non extrusion ring above the packing
element is required to minimise extrusion for maximum packer seal life.
For changing out packer inserts and wear bushings with the coiled tubing in situ, a split cap at
the top of the stripper packer is removed allowing the consumable parts to be replaced.

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Side Door Stripper

The side door design of a stripper has the following advantages over the conventional design.
(Refer to Figure 8)
It minimises the distance between the stripper and the injector chains, thus substantially
reducing the length of unsupported tubing.
It permits replacement of the stripper element, energiser and bushings from the open space
below the injector, thus stripper element change out is always easier particularly when tubing
is in the well.
The side door stripper is more commonly used than the conventional one.

Dual Strippers
The use of two strippers in one stack of coiled tubing pressure containing equipment is
becoming increasingly popular. The lower element is not energised and therefore kept in
reserve. Should the upper element become worn, the lower element can be energised and
either:
• The operation continued utilising the lower element as the primary seal
• The upper element can be replaced and the lower element de-energised. (Refer to
Figure 9)

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Figure 8 - Side Door Stripper

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Figure 9 - Tandem Side Door Stripper

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Figure 10 - Radial Stripper

1.3.2 Annular BOP

The coiled tubing annular BOP is designed to provide a seal around the outside of the tubing
in normal operations. The annular BOP can be used to seal on tool strings of different
diameters, collapsed tubing, wireline or to seal blind. Typically run below the quad or combi
BOPs, but can also be run below a single stripper/packer, as a backup, instead of having a
dual stripper. (Refer to Figure 10)
The annular BOP should only be used in addition to a multifunction BOP.
Annular BOPs will be described in detail in the snubbing section.

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1.3.3 Risers And Connectors

Risers with quick unions or ring sealed flanged connectors are used on coiled tubing
operations. There is a tendency to use the flanged connectors if possible. Some authorities
insist upon flanged connectors. In high pressure operations it would be essential. The flanged
connector is more reliable than the quick union. However, it takes longer to rig up than the
quick union. Depending upon the operation, wellhead pressure, availability, and cost, a
judgement would have to be made.
The hydraulic connector is used as an interface between pressure control devices. It provides a
quick means of rig up. Originally designed for use on floating vessels, the hydraulic connector
is becoming standard in all rig ups for some operators and service companies. Hydraulic
connectors should be:
• Only used above the primary shear/seal preventer
• Fail safe
• Mechanically latched
• Able to indicate latch status.

1.3.4 Multi-Function Remote Controlled BOP or Quad BOP

A quad BOP has four pairs of ram actuators with the following functions, in order, from the
top down (Refer to Figure 11)

Used to seal the well bore off at surface when well control is lost. Sealing of
Blind the blind rams is achieved when the elastomeric elements in the rams are
rams compressed against each other. For the blind rams to seal correctly the tubing
must be removed. The rams are designed to hold pressure from below only.
Used to cut coiled tubing in an emergency. Rams have replaceable blades
specifically for coiled tubing applications. As the shearing plates are closed on
Shear
the coiled tubing, the forces imparted mechanically yield the body of the tube
rams
to failure. The cut will leave the tubing open ended so that circulation is still
possible.
Designed to hold the tubing and prevent upward or downward movement.
Rams have replaceable inserts for changing tubing size. To prevent damage of
the tubing, by the slips, longer inserts are available adding 75% to the contact
Slip rams
area. In order to break up the stress risers (caused by circumferential slip
marks) the teeth have vertical grooves cut to interrupt the slip marks on the
tubing.
The pipe rams are equipped with elastomeric seals sized to the diameter of the
Pipe tubing in use. When closed on the tubing they isolate the well annulus below
rams the rams. Guide sleeves fitted to the ram assembly centralise the coiled tubing
as the rams close.

BOPs are available in 5,000, 10,000 or 15,000 psi ratings. The bore range is 2.5 to 6.4 inch.

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The blind rams and shear rams are separated from the slip rams and pipe rams by a flanged
outlet in the BOP body which is used as a kill line during well control. This line can be used to
reverse circulate fluids however it is not recommended as the pipe rams and slip rams would
be exposed to debris which could impair their operation. Returns should either be taken via
the Xmas Tree or through a flow-tee mounted directly below the BOPs.

Figure 11 - Quad BOP

NOTE: Some operators prefer not to function slip rams unless absolutely
necessary. The extent of slip ram damage cannot be easily quantifiable by
visual inspection.

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The blind ram and pipe ram compartments of the BOP stack body are equipped with ports,
which when activated, equalise pressure within the ram body. Since the rams are self-actuating,
the pressure above and below must be equalised before they are opened. It is good practice to
monitor the opening and closing hydraulic pressure. A high opening pressure could indicate
that the riser pressure is not equalised. In this case the surge an opening can cause buckling or
other damage.
Should a situation arise where the tubing has to be cut, the order of operation should be:
• Close the slip & pipe rams
• Cut the coiled tubing with the shear rams
• Using the injector pull the remaining coiled tubing above the blind rams
• Close the blind rams.
Circulation down the coiled tubing is then possible via the circulating port in the BOP body
and into the cut end of the coiled tubing. (Refer to Figure 12)
There are six ways of closing the BOP:
• Hydraulic pressure from the BOP control circuit
• Accumulator pressure from the BOP control circuit
• Haskel pump
• Manual override for Haskel pump
• Manual hydraulic hand pump
• Manual handles on the BOP rams.

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Figure 12 - Coiled Tubing Cut

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1.3.5 Separate Shear/Seal BOP

This item sometimes referred to as the safety head is rigged up directly on to the Xmas Tree.
It should always be considered especially when a live well situation could be induced as it
protects the riser. It is essential for emergency shutdown situations. (Refer Figure 13 and
Figure 14)

1.3.6 Combi BOPs

The combi BOP has the same features as the quad BOP but combines the functions of two
rams in one actuator: (Refer to Figure 15 and Figure 16)
• Quad BOP blind and shear rams become combination shear/seal rams
• Quad BOP slip and pipe rams become combination pipe/slip rams (see slip
rams).
Consequently with combi rams a quad BOP becomes a dual BOP. This reduces height, weight
and the number of hydraulic hoses required.
The advantages of the combi BOP over the quad BOP is that the coiled tubing does not need
to be pulled out above the blind rams in order to affect a seal, thus enabling the well to be
secured more rapidly in a emergency situation.
All rams are operated hydraulically via a 10 gallon accumulator bottle with a 3,000 psi
operating pressure. The bottle is automatically recharged when the pressure falls to 2,700 psi.
The 10 gallon bottle provides enough usable fluid to close all the BOP functions should the
power pack not be running.

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Figure 13 - EH44 Single BOP

Figure 14 - Shear Seal Actuator Assembly

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Figure 15 - Wellhead Combination BOP

Figure 16 - Combi BOP Ram Assemblies

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1.3.7 Check Valves

When using coiled tubing on a live well it is standard practise to incorporate a check valve
(non-return valve) in the bottom hole assembly. Its function is to guard against a blow out if
the tubing leaks or parts at surface by preventing flow back up the string. There are four types
of check valve commonly available. (Refer to Figure 17)
• Ball
• Dome
• Dart
• Flapper.
The flapper valve is designed for use in conjunction with ball operated tools because the dart
valve will not allow the passage of a ball. Should a bottom hole assembly become stuck a ball
can be pumped through the flapper to operate the shear sub, while still providing check valve
protection for the coiled tubing as it is retrieved from the well. Hence the flapper valve is in
more common use and typically two valves are run in tandem or a dual flapper valve is used to
give backup in case of one flapper failing to seal.

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Figure 17 - Coiled Tubing Check Valves

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1.3.8 Release Joints

Although not strictly an item of primary pressure control equipment, the release joint provides
a means of disengaging the coiled tubing from the BHA, in case it is unexpectedly stuck down
hole. Because of its larger size the BHA has a tendency to hang up on down hole obstruction
especially on a highly deviated wells.
There are three basic types of Release Joints:
• Ball operated shear sub (BOSS tool)
• Hydraulic disconnect
• Tension disconnect.

Ball Operated Shear Sub

The BOSS tool is activated by circulating a ball through the coiled tubing into a seat at the top
of the tool. A pre-determined pressure applied through the coiled tubing shears out a lock pin
and moves an internal sleeve down to release the retaining lugs. This allows the two halves on
the tool to separate leaving a standard internal fishing neck looking up. The ball is introduced
into the flow path through a ball launcher, which is fitted to the coiled tubing reel unit. Boss
tool operation can be seen in Figure 18.

Hydraulic Disconnect
The hydraulic disconnect is similar in design to the BOSS tool, but does not rely on a ball for
activation. The tool is operated by applying a differential pressure inside the coiled tubing. It
requires a much larger differential pressure because the surface area on which it is acting is
much smaller.

Tension Disconnect
These are simply two components pinned together such that they will separate upon
application of a straight pull on the coiled tubing, leaving a standard fishing neck looking up.
It is not generally recommended to use the tension disconnect as part of the down hole tools
because of the lack of control over down hole tension forces and the possibility of premature
release.

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Figure 18 - Boss Tool Operation

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1.4 TYPICAL EQUIPMENT CONFIGURATIONS

1.4.1 Land Based Rig Up
Typically for land based coiled tubing operations the BOPs can be rigged up directly onto the
Xmas Tree with no need for a riser. However if the toolstring configuration is complex and
hence long in length a riser can be installed below the BOPs.

1.4.2 OffShore Platform Rig Up

Figure 3 shows a typical rig up for an offshore platform where the injector head and BOPs are
positioned on a higher deck (probably the drill floor) than the wellhead. A riser connects the
BOPs and the Xmas Tree which acts as a lubricator for long toolstrings. In order to be able to
secure the well in an emergency and have the ability to depressurise the riser a shear/seal BOP
is usually included in the rig up, directly above the Xmas Tree.

1.4.3 Sub-sea Rig Up

Sub-sea coiled tubing operations from a floating rig require the injector head and BOPs etc. to
be compensated to allow for rig movement. The injector head, BOPs and stripper are housed
in a lift frame which is suspended from the drilling blocks. The riser and sub-sea BOPs are in
turn suspended from beneath the lift frame, commonly through a hydraulic connector for ease
of rig up, and are kept in constant tension when attached to the sub-sea Xmas Tree to avoid
buckling of the riser joints.
The sub-sea completion BOP will have the same functions as the shear/seal BOP run above
the tree on a platform rig up. A hydraulic control umbilical is run back to surface to allow
remote operation of the tree valves, SCSSV and BOP functions. There will be an emergency
disconnect sub above the BOP to allow the riser to be released and the rig moved off location,
in the event of a problem, leaving the well secured with the BOPs. (Refer to Figure 19)

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Figure 19 - Movement Compensated Coiled Tubing Assembly

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1.5 EQUIPMENT TEST PROCEDURES

1.5.1 Pre-Load Out Checks
In addition to the pre-job offshore testing the following measures could be taken prior to the
equipment leaving the base.
The coiled tubing unit should be run and full function checks performed.
With straight bar inserted apply a pressure test to the stuffing box to check the operation.
Record on a chart. Pressure test all coiled tubing reels that are going on the job with water to a
high and low pressure. Record on a chart.
A depth flag (paint mark or ring) positioned +/- 300 ft from the end of the coiled tubing for
counter verification when pulling out of hole.
Coiled tubing pickled in HCl to remove any corrosion/debris deposits and then neutralised
and tested to maximum rated pressure.
Displace a ball of suitable diameter through coiled tubing reel(s) with N2. Leave tubing purged
with N2 at atmospheric pressure.
Test cut a section of coiled tubing with pipe and slip rams closed. Inspect cut for deformation
and inspect all ram contact areas. Replace shear cutters. (If stiff wireline operations are to be
undertaken, test shear coiled tubing and cable together). Replace shear cutters.
BOP body test to maximum rated pressure and to 200-300 psi low pressure. Record on a
chart.

1.5.2 Pre-job Test Procedures

1. Shear/Seal BOP
Fill up the riser and BOP via the test line to the tree valve. Close the blind rams.
Increase pressure in 500 psi increments to maximum and hold for the prescribed time.
Record on a chart. (Refer to Figure 20)
2. Blind Rams and Riser
This should be tested once the BOP is rigged up on the tree and after function testing
all rams. Close the lower master valve, fill the tree through the open swab valve. Close
the blind ram and test from below via the wing valve on the tree using the cement pump
and seawater or water/glycol. Increase the test pressure in 500 psi increments to
maximum and hold stabilised pressure for the prescribed time. Record on a chart. (Refer
to Figure 21(3)).
3. Stripper
Position the straight bar across the BOP. Fill up via the reel until water overflows from
the stripper. Stop the pump, close the swab valve and energise the stripper packer.
Increase pressure in 500 psi increments to 5,000 psi and hold for 15 minutes. (Refer to
Figure 21(4))

NOTE: Applying too much stripper pressure may damage the coiled tubing.

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Figure 20 - Pre-job Test Procedures

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Figure 21 - Pre-job Test Procedures (Continued)

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4. Coiled Tubing Reel and Running Tools

Fill the coiled tubing reel with test water from the cement unit. Displace at least twice
the tubing volume to prevent any possible plugging of the coiled tubing small diameter
tools by contaminants from any previous work done with the cement unit. During this
circulation a chevron pig and stainless steel ball can be used to clear the tubing and
establish the reel volume whilst filling up the reel. Suspend the injector by the travelling
block and attach the coiled tubing tools; tubing connector, straight bar connections,
check valves, shear sub, test cap and valve. Close the test cap and pressure up in 500 psi
increments. Hold stabilised pressure for the prescribed time. Record on a chart. Bleed
off both ends. Remove the test cap and attach the tools for the impending job.

NOTE: The end of the string should be as close to deck as possible.

5. Pipe Rams
With pressure still maintained from the stripper test close the pipe rams. Bleed the
pressure from above via the BOP circulating port. Observe the pressure which is now
being applied to the underside of the pipe rams for the prescribed time. Equalise the
pressure above the rams via the equalising valve on the BOP. Open the pipe rams.
(Refer to Figure 22(5)).
6. Check Valves
Attach the valves to the coiled tubing in the reverse direction including a bleed off
manifold. Position as close to deck as possible. Pressure up in 500 psi increments. Hold
for the prescribed time. Bleed pressure off at both ends of the reel. Reinstate the check
valves in the string the correct way round. (Refer to Figure 22(6)).
Alternatively, after the pipe ram test, bleed off the coiled tubing pressure to 1,000 psi
and monitor the check valves are holding the pressure still inside the BOP body. This is
assuming the string is good for a differential equal to at least the test pressure being
used.

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7. To Reinstate The System

Equalise the pressure in the coiled tubing. Bleed down the pressure from the BOP and
riser to equal the well pressure. Ensure all BOP rams are open. Reduce stripper packer
to required level. It will be necessary to free the coiled tubing from the high force
applied by the stripper during testing. Do this in the upward direction with the injector
chains.

NOTE: Ensure that when running coiled tubing into a riser, and the well is closed
in, that a vent is open to prevent pressure build up which could result in
pipe collapse.

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Figure 22 - Pre-job Test Procedures (Continued)

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1.6 EMERGENCY PROCEDURES

1.6.1 Production Platform Considerations
Specific procedures will vary depending upon the installation but the following are useful
guidelines.

1.6.2 Yellow Alert (Production Shut down)

1. If pumping is in progress, stop and shut down the pumping unit and close valve to
isolate flow line.
2. If a washing or milling operation is in progress the tubing should be lifted above the
worked interval and at least above any perforations (to prevent differential sticking if
well is taking fluid) prior to shutting down the coiled tubing unit and to prevent solids
settling in the annulus.
If time permits pull up the equivalent distance from the BOP to the DHSV. If the
situation deteriorates (e.g. prepare to abandon) then the coiled tubing can be sheared
and dropped so as it falls to below the DHSV which can then be closed.
3. If the coiled tubing end is above the DHSV, the valve should be closed. A decision to
remove this valve from any ESD circuit should have been taken. If the coiled tubing is
below the DHSV close the pipe rams and apply the injector brake on the quad and lock
them. Close the wing valve.
4. Shut down the coiled tubing unit, hand back permits.

1.6.3 Red Shutdown (Muster Stations)

As per yellow shut down steps 1 to 3 but essential personnel to stay with unit.

1.6.4 Prepare To Abandon

1, 2 and 3 as per yellow shut down.
4. If the well is live and a separate shear/seal head is rigged up it can be activated. When
this is done if the coiled tubing was far enough off bottom the Xmas Tree valves can
then be closed.
5. If the well is live and no shear/seal rams are available, the pipe can be sheared using the
quad after the slips are closed. The coiled tubing can then be dropped below the tree
and the tree valves closed. The DHSV can also be closed if possible.
If a situation arises where the coiled tubing cannot be pulled off bottom and the well is live
the only way to shut the well in is by using the blind rams after shearing the tubing. The
remaining coiled tubing must be pulled above the blind rams.
If the well is not live, pull the remainder of the coiled tubing out of the BOP and close the
blind rams. Close the Xmas Tree valves and DHSV.
Shut down the coiled tubing unit.

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1.7 SPECIFIC OPERATIONAL AND CONTAINMENT PROBLEMS

1.7.1 Controlling Formation Pressure
Killing a well during coiled tubing operations would normally be done by bullheading. For
example, if coiled tubing collapse occurs. The well can be bullheaded down the coiled tubing,
the annulus or both, depending upon the circumstances. However, there are occasions when a
well will need to be killed by a circulation method. For example, if coiled tubing is actually
being used to perform a kill operation prior to a rig workover. A specific rig up to take returns
via a choke will be required. The responsibility for the kill operation being with the operator.

Figure 23 - Coiled Tubing Circulating Rig Up With Option To Rig Choke

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Figure 24 - Internal Pressure Drop Curves

1.7.2 Well Circulation For Solids Removal

Mostly this type of operation is performed to establish communication with an open
completion interval. It is therefore important to balance the fluid pressure used to that of
reservoir pressure to avoid fluid loss or formation damage.
There are a number of factors to be considered:
• Fluid type - to control solids carrying ability
• Fluid density - to control hydrostatic pressure.

1.7.3 Fluid Type

The compatibility of well fluids and treatment fluids on the well control equipment should be
considered:
• H2S or CO2
• Elastomer seal behaviour
• Metal reaction.
There are two types of fluid; compressible and incompressible.
Incompressible fluids can be subdivided into Newtonian and Non-Newtonian.

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Properties of Newtonian and Non-Newtonian fluids

Viscosity Turbulent flow Solids carrying

AV must be greater than

Newtonian e.g. water, TPSV
Low Annulus
brine
Poor
Non-Newtonian e.g. mud, High Coiled Tubing Good
gels

Wash fluids must be capable of transporting solids out of the well. Lack of hole cleaning can
lead to getting stuck and being unable to circulate, thereby compromising our primary means
of well control.
If circulation rates will achieve annular velocities exceeding terminal particle settling velocity
(TPSV), Newtonian fluids are generally adequate. It is important to bear in mind the different
annular capacities when the coiled tubing is washing inside the production tubing or below the
tailpipe.
It is common practise to use brine or water and to circulate non-Newtonian viscous pills
periodically to assist in solids removal. With a Newtonian fluid solids will settle out when
circulation is below the TPSV, therefore a gel wash fluid may be considered more desirable.
Hole deviation has a great affect on solids removal. With wells of 45 degrees deviation the
annular velocity should be twice the TPSV. In horizontal wells the ratio should be at least
10:1. TPSV calculations are possible for Newtonian and non-Newtonian fluids, the latter
being more complex. Computer programmes are made available by service companies at the
planning stage of coiled tubing operations.
Compressible fluids are more difficult to design and use than incompressible fluids. They can
be used on wells with low reservoir pressures or to lift solids when annular velocities will be
too low with liquid fluids. Compressible fluids consist of a single gaseous phase or a liquid and
gaseous phase (nitrogen) as foams. In the annulus the gas fraction of the foam will expand as
it is circulated out of the well. This assists with solids removal but does create higher annular
pressure losses as compared with liquids.

1.7.4 Washing With Nitrogen

In low reservoir pressure wells nitrogen can be used as a wash medium. The solids removal is
entirely dependant on the annular velocity. Stopping pumping will immediately cause solids
settling. Erosion of coiled tubing and surface production equipment is also a concern.

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1.7.5 Washing With Foam

Foam is formed by commingling a liquid phase (treated with surfactants) with nitrogen gas to
create a homogeneous emulsified fluid. Foam can be generated in densities equivalent to 0.35
to 0.057 psi/ft depending on wellbore pressures and temperatures. Foam can most closely be
compared to a non-Newtonian fluid.
The volumetric gas quantity in a foam is known as quality:
Qf = N2 Volume / Liquid Volume + N2 Volume x 100%
Foams of quality 60 to 85 percent possess some useful properties.
• Solids suspension is up to 10 times greater than incompressible fluids
• The foam can withstand up to 1,000 psi pressure with minimal fluid loss to the
formation.

1.7.6 System Frictional Pressure Losses

The capability of coiled tubing to withstand theoretical maximum internal pressure (based on
API BULLETIN 5C3) is still a topic of discussion because the effects of plastic deformation,
caused by the surface equipment, is not fully understood. A maximum circulating pressure
should be decided upon prior to any job being planned, after discussion with the service
company. As an example one operator chose the following parameters when performing an
under-reaming operation with 13/4” coiled tubing, 1.91 lbs/ft, 0.109” wall thickness (WT).

Published properties Operating parameters

Tensile strength 39,300 lbs 32,000 lbs
Burst 10,380 psi 3,800 psi
Collapse 7,260 psi 2,500 psi

Friction pressure losses in coiled tubing and coiled tubing/tubing annulus can be predicted
using computer programmes. Annular pressure losses are of the order 10 psi/1,000 ft whereas
internal pressure losses are of the order 100 psi/1,000 ft. These figures are quoted to
demonstrate the difference in order of magnitude; exact figures would vary depending on
individual cases.
Formation fluid can influence a wash programme. If the system becomes underbalanced and
the formation flows, this can help the removal of solids. If a gas well is being worked on,
under balance will lead to a gas influx. Whilst this could also assist with solids removal it is
advisable to be prepared for an increase in return flow rate. Additionally, as the gas expands, it
will displace the wash fluid either at surface or into the reservoir. A large influx of gas into the
annulus will reduce the solids carrying capability. An influx of oil may degrade the foam and
cause the same problem.

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1.7.7 Fluid Density

In a well planned operation the hydrostatic pressure of the wash fluid plus the annular
pressure loss (APL) should balance the reservoir pressure.
As a general guide:
Reservoir Pressure Wash Fluid
0.100 - 0.400 psi/ft Foam
0.434 - 0.465 psi/ft Brine
> 0.465 psi/ft Heavier brine or weighted fluid

1.7.8 Considerations When Unloading A Well

This technique is used to initialise flow during a DST, recommence flow after a workover or
when a well has killed itself due to overbalance from produced fluids after a shutdown. As
with any unloading technique it is important, particularly in unconsolidated formations, not to
shock the formation by unloading too quickly and causing perforation tunnel collapse.
On normally and abnormally pressured wells (> = 0.465 psi/ft) an under balance condition
can be achieved by running in with coiled tubing to a predetermined depth and displacing a
height of fluid to provide the required draw down, whilst maintaining constant BHP by means
of an adjustable choke. The coiled tubing is then pulled out of the well and an equivalent
volume of formation fluid is drawn into the wellbore.
On wells that are sub-normally pressured, and are unable to support a full column of fluid,
nitrogen can be used. The most effective method of nitrogen lifting is to run into the well to
the fluid level and commence circulating nitrogen while slowly running in hole. This allows for
a gradual reduction in the wellbore fluid density causing a controlled flow from the formation.
There are some complex considerations when unloading with nitrogen due to the high
annulus frictional pressure losses that can be induced in certain coiled tubing/tubing
configurations. Basically the smaller the annulus cross sectional area the higher the pressure
loss, which can cause cessation of flow when the coiled tubing is pushed below a certain
depth.

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1.8 EQUIPMENT FAILURE

1.8.1 Introduction
Coiled tubing is most likely to fail due to buckling when it encounters an object or catches on
a change in ID. It is therefore important that the coiled tubing unit operator has a copy of the
completion schematic with all IDs clearly indicated and possible hang up points discussed
with the company representative.

1.8.2 Run In And Pull Out Of Hole Procedures

Potentially most coiled tubing operational failures can occur when running coiled tubing in the
hole. The most likely form of failure is due to buckling when the tubing hits some object or
catches on a change of diameter. The potential for buckling is a function of the coiled tubing
wall thickness, diameter, and the size of the tubing or casing that the coiled tubing is being run
into. A full analysis is necessary to determine the minimum weight indicator reading allowable
whilst running in the hole.
Running Speeds
• The maximum running speed in hole for normal operation will be 50 feet per
minute (15 m/min). This may be increased for reasons such as PLTs only if the
hole section has been previously traversed to ensure that no restrictions are
evident.
• The maximum running speed is to be reduced to 10 feet per minute (3 m/min),
when running through restrictions such as sliding side doors, nipples and gas lift
mandrels amongst others. This reduced running speed will be applied for 50 feet
(15 m), before and 50 feet (15 m), after the position of the downhole obstruction
to allow for any discrepancies in the depth readings.
• Pulling out of hole speed is not as critical, but will be limited to a maximum of
100 feet per minute (30 m/min). The same speed reductions are to be applied
when pulling through restrictions.
• Pulling out of hole speed will be reduced to 10 feet per minute (3 m/min), when
within 100 feet (30 m), of the wellhead or BOP, until the end connector contacts
the stuffing box.
• At all times when running in or pulling out of the hole the injector thrust must be
set at the minimum required to move the tubing.

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1.8.3 Running In Hole Procedure

Prior to running in the hole, the coiled tubing supervisor will have the following information
available:
• Well bore profile or completion diagram
• Deviation profile of well bore
• Operating limit predictions
• The maximum allowable pressure rating of the tubing and the maximum
allowable pull
• Fishing diagram of bottom hole assembly
• Details of any wireline drift run prior to coiled tubing operations.
Ensure all wellhead and BOP valves are open via a physical check and commence running in
hole limiting running speeds as outlined above.
Perform pull tests every 1,000 feet (300 metres) or less if circumstances require to ensure that
the pick up weight does not exceed the operating limit. These pull tests should not be done at
exactly 1,000 feet increments, but should be varied so as to prevent fatiguing the coiled tubing
at the same point each time a pull test is performed.

Special Precautions
Control of remote actuated well valves, while coiled tubing is in a well, must be removed from
the automatic shutdown system.
Wellhead valves may either be locked open with fuseable discs or control transferred to a
separate control skid. Sub surface safety valves may be removed and sleeved, sleeved only, or
control transferred to a separate control skid. They should not be held open by locking in
hydraulic control pressure at the wellhead as pressure can bleed off over time and allow the
valve to close.
The wellbore fluid and geometry must always be considered before any coiled tubing
operation. The size of the bottom hole assembly in relation to the completion diameter can
have a significant effect on the running in and pulling out weight. In the case of large bottom
hole assemblies in relatively small tubulars, the annular clearance can be such that significant
pistoning effects can occur which resist the movement of the coiled tubing and can cause
swabbing of the well. High viscosity fluids in the annulus can also cause this effect.
High wellhead pressures cause a significant up thrust on coiled tubing, dependent on the cross
sectional area of the tubing. This means that in high pressure wells the weight indicator will
read negative until sufficient weight of coiled tubing is in the well to overcome the effect of
pressure. In these situations the injector head requires a large amount of hydraulic thrust to
‘snub’ the tubing in the well.
The thrust required from the injector reduces as more tubing is in the well and it is important
to reduce the thrust setting on the injector as the tubing is run in the well. This means that in
the event of the tubing hitting an unexpected object (such as hydrate plug), only a minimal
amount of extra thrust will be applied by the injector, reducing the possibility of buckling the
tubing. If at all possible circulate through coiled tubing while run in hole.

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Should buckling occur while running in hole the pipe will form a hinge that will in effect
prevent circulation. If pumping liquid this will be noticed by a rapid increase in circulating
pressure. In many instances of buckling failure the tubing has been folded over repeatedly
before the injector has been stopped, resulting in a difficult fishing operation.
Stripper rubbers have a significant effect on apparent coiled tubing weight and low friction
strippers must be used at all times. Correct lubricating oil should be used as required to reduce
stripper friction further in high pressure dry conditions.

NOTE: Never use diesel.

1.8.4 Stuffing Box/Stripper Failure

The operational life of the stuffing box packings are very dependant on the type of operation
being undertaken. Incorrect stuffing box hydraulic pressure, high wellhead pressures, poor
external surface of the tubing, and corrosive well bore fluids will accelerate the wear process
which may result in the stripper elements failing. (Refer to Figure 25)
In the event of stuffing box failure during coiled tubing operations:
• Increase hydraulic pressure to stuffing box in an attempt to stop leak. Normally
operating at 200 psi with large operating margin up to 2,500 psi.
If this proves unsuccessful then:
• Stop both pipe movement and circulation
• Engage injector brake, close pipe rams
• Bleed off pressure above pipe rams
• Close lower stripper (if used)
• Open (upper) stripper and replace sealing elements. Re-test stripper
• Equalise pressure and open pipe rams
• Release injector brake
• Re-commence operations.

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Figure 25 - Stripper Failure

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1.8.5 Major Riser Assembly Leak

In the event of a major riser assembly leak developing between the Xmas Tree and coiled
tubing BOPs, that cannot be repaired during the coiled tubing operation, the following
procedures should be followed: (Refer to Figure 26 and Figure 27)
If the leak occurs with a short string of coiled tubing in the hole:
1. Pull out of hole to above the Xmas Tree (and shear/seal BOP if used).
2. Close the swab valve on the Xmas Tree.
3. Close hydraulic or manual master valve on the Xmas Tree.
4. Bleed off pressure in riser and repair leak.
5. Pressure test all broken connections and re-commence operations.
If the leak occurs with a long string of coiled tubing in the hole:
1. Pull sufficient coiled tubing out of hole to ensure that the string will drop below the
Xmas Tree master valve when the shear rams (or shear/seal BOPs) are activated.
2. Close shear rams (or shear/seal BOPs) to cut coiled tubing.
3. Close Xmas Tree swab and master valves.
4. Repair leak in riser and pressure test all broken connections.
5. Commence fishing operations.

NOTE: If it is not possible to establish two mechanical barriers below the leak
normally the well will have to be killed before any repairs are commenced.

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Figure 26 - Riser Assembly Leak With Long String Of Coiled Tubing In Hole

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Figure 27 - Riser Assembly Leak With Short String Of Coiled Tubing In Hole

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1.8.6 Pinhole At Surface

If a pinhole leak is observed at surface, coiled tubing operations should be suspended. (Refer
to Figure 28 and Figure 29)
If bottom hole assembly contains check valves:
• Monitor coiled tubing pressure and observe leak to ensure check valves are
holding
• Pull out of hole to position the leak on the lower part of the reel (be prepared to
deal with containment of any hazardous fluid)
• Displace coiled tubing to leak with water if hazardous fluid being used if this is
considered a safer option
• Pull out of hole and replace coiled tubing reel.
If valves are not holding or have not been included in bottom hole assembly:
• Observe severity of leak and decide whether it is safe to pull out of hole. Factors
such as fluid type and area of dispersion will influence decision.
If leak is too severe to continue pulling out of hole:
• Close slip and pipe rams
• Operate shear rams to cut pipe
• Circulate well to kill fluid through coiled tubing left in well
• Retrieve remainder of coiled tubing.

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Figure 28 - Pinhole Leak (1)

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Figure 29 - Pinhole Leak (2)

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1.8.7 Tubing Parted At Surface

In the event that the coiled tubing parts at surface: (Refer to Figure 30 and Figure 31)
• Attempt to spool as much coiled tubing back on to the reel to avoid whiplash.
Equally important attempt to run excess coiled tubing through the gooseneck
• Stop injector, close slip and pipe rams
• If personnel are in danger from fluid release and/or the check valves are not
holding, operate the shear/seal rams and commence well kill operations.
Otherwise:
• Monitor WHP while contingency plans are reviewed
• Kill well and make necessary repairs to coiled tubing
• Remove injector and feed coiled tubing back through injector chains
• Install fishing spear. (Depending on the tubing stick-up, other methods of
attachment may be more appropriate)
• Rig up injector and stab into top of fish, pull test spear then release slips and pull
out of hole.

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Figure 30 - Tubing Parted at Surface Check Valves Holding

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Figure 31 - Tubing Parted At Surface Check Valves Not Holding

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1.8.8 Tubing Parted Downhole

Breakage of the coiled tubing downhole will be indicated by a sudden reduction in weight and
circulating pressure. Thereafter: (Refer to Figure 32)
• Continue to maintain circulation with water at all times to prevent migration of
well fluids up the string. Circulation rate to be kept to a minimum
• Determine approximate length of coiled tubing remaining from pick-up and
hanging weights
• Pull out of the hole slowly until close to surface then begin to cycle tree swab
valve (if possible) every X ft, (where X is less than, or equal to, the riser length), to
determine when the end of the coiled tubing has cleared the xmas tree when end
of coiled tubing is clear of tree stop pulling out of the hole and close tree swab
and master valves
• Depressurise riser and continue pulling out of hole
• Commence fishing operations.
The leak should appear as a sudden change in pressure which depends on the circumstances,
e.g. if jetting or pumping the coiled tubing pressure will be greater than well pressure and a
leak will appear as a sudden reduction in pump pressure (and an increase in injection rate).

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Figure 32 - Tubing Parted Down Hole

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1.8.9 Internal Coiled Tubing Well Pressure

During most operations well pressure will be prevented from entering the coiled tubing by the
dual check valves. If these fail, the tubing itself becomes perforated, or the BHA is lost, well
fluids will be able to enter the coil. In this situation it will not be possible to depressurise the
coil until the point of leakage is out of the well. If coiled tubing pressure is greater than well
pressure i.e. if jetting or pumping, then the leak may appear as a sudden reduction in pump
pressure.
In the event of well pressure being present inside the coiled tubing:
• Stop pipe movement
• Stop circulating for long enough for the pressure to stabilise and perform a
hydrostatic calculation to identify the point of leakage
• Displace the reel to water and continue circulating at a low rate to stop migration
of well fluids up the coiled tubing.
It will be difficult to calculate the exact location of the leak and its severity and hence in most
cases it would be advisable to kill the well before attempting to pull out. However if the
wellhead pressure is low it may be possible to take the following action:
• Continue pulling out of hole while circulating and observe the injector head for
signs of leakage passing the stuffing box. If the fluid escaping is the fluid being
pumped it may be possible to continue pulling out, after cutting back the
circulating rate to a minimum to reduce the risk of a washout parting the pipe
• If the leak is too severe then run back into the well, set the slips, close the pipe
rams, shear the pipe and close the blind rams.

1.8.10 Loss Of Power

In the event of a power pack failure:
• Engage injector brake
• Close pipe rams and manually lock
• Close manual stems on pipe and slip rams as back-up
• Apply the reel brake if it is not fail-safe applied
• While maintaining circulation (if possible), repair or replace power pack
• Equalise pressure across pipe rams and open pipe and slip rams
• Release injector brake
• Re-commence coiled tubing operations.

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1.8.11 Coiled Tubing Collapse

Coiled tubing can collapse when exposed to higher than design differential pressures. If
collapse occurs, it should be evident from a rapid rise in circulating pressure, or becoming
stuck when trying to pull the collapsed section of tubing through the stuffing box. Should the
pipe become stuck downhole stretch measurements should be made to determine the stuck
point. (Refer to Figure 33)
With a 5,000 lbs over pull, the stretch for each 1,000 ft of coiled tubing is;
11/4” 6”/1,000 ft
11/2” 5”/1,000 ft

NOTE: In this situation, stripping the coiled tubing through the pipe rams is not
an option because if the collapsed section of tubing straddles the BOPs
then they will not be able to seal.

Once it has been established that the coiled tubing is stuck in the stuffing box:
• Hang off coiled tubing in slips
• Kill the well
• Install clamps on the coiled tubing
• Split the stuffing box and open the slips
• Attempt to pull the coiled tubing with the injector head
• If the injector head is unable to pull the tubing, break the connection above the
BOP and raise the injector. Connect to block and pull tubing out of hole to
remove collapsed section leaving 4-6 ft of good coiled tubing sticking up for the
BOP
• Set slips
• Re-connect the injector head, splice the coiled tubing, and pull out of hole.

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Figure 33 - Coiled Tubing Collapse

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1.8.12 Coiled Tubing Runaway

In both of the following cases the action to be taken will depend on the severity of the
situation. The quickest method, but not necessarily the most satisfactory, would be to close
the shear/seal rams.
Coiled tubing running into well: This is most likely to occur on low THP gas wells where
snubbing forces are lowest and string weight greatest. Runaway tubing can occur because of a
lack of grip between the drive chains and pipe, caused by under gauge tubing or loss of
hydraulic pressure. Once runaway has started it may be difficult to stop, however the
following actions can be taken:
• Stop injector head movement and apply more inside tension
• Increase stripper pressure to a maximum in an attempt to slow down rate of
runaway
• As a last option close the slip rams. This will probably lead to pipe breakage but is
the safest option left
• Under certain circumstances if the runaway tubing is at a speed above the critical
speed, the back-pressure created by the circulating hydraulic fluid may prevent the
injector motor brakes from actuating. If this situation occurs, select the pull mode
for the injector and increase system hydraulic pressure until the tubing comes to a
standstill.
Coiled tubing is ejected out of the well: This condition is most likely to occur near surface on
high THP wells where snubbing forces are highest. In this situation:
• Increase stuffing box pressure to a maximum
• Close slip rams (only effective if slips are double acting).

NOTE: If the tubing is ejected from the well the blind rams must be closed and
injector stopped before coiled tubing passes through the injector chains.

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1.8.13 Stuck Coiled Tubing

When a pull of more than 80% of the yield strength is required to pull the coiled tubing out of
the hole, the pipe is defined as being stuck. Before any more pull force is applied, it is essential
to analyse the problem and take the necessary precautions.
Coiled tubing can get stuck in the following situations:
• Solids settling and packing off around pipe caused by pump failure in cleanout
operations
• Unexpected increase in friction drag
• Obstruction in well
• Differential sticking.
How to react in the event of getting stuck:
• Try to work the coiled tubing free without exceeding 80% of the yield strength of
the pipe. Be aware of the fact that moving the pipe up and down over the
gooseneck rapidly weakens the pipe. Pumping while working the pipe should be
avoided if possible as this greatly accelerates the fatigue problem. (Check fatigue
cycle log to assess if further cycling is possible). Maintain circulation when not
cycling
• If stuck due to drag, circulate a pill of slick fluid to reduce the friction between the
pipe and tubing/casing wall
• Rapidly bleed off annulus pressure (if possible) while pulling on the pipe. This
may cause sufficient backflow to dislodge debris
• Try to increase the buoyancy by pumping heavier fluid into the annulus and
displacing the coiled tubing to nitrogen. Be aware of the risk of collapse.
• Release the BHA by using ball operated shear sub if circulation is possible.
If it does not prove possible to get free using any of the above methods then:
• Determine the stuck point by pull tests
• Hang off the coiled tubing in the slip rams
• Kill the well
• Cut the coiled tubing at surface
• Run chemical cutter* and cut pipe above free point
• Fish for remainder of coiled tubing as necessary.
* Chemical cutters are run on electric line and can be used to cut tubing down to 1” OD
(cutters are available down to an OD of 0.688”). The cut is flare free, burr free, and
undistorted and hence provides a good profile for fishing. When making the cut the coiled
tubing pressure should be slightly overbalanced to avoid the cutter being blown up the well.

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1.8.14 Well Shrinkage

It is likely that as workover fluids are introduced into a well that has been on production that
some shrinkage will occur due to the cooling effect of the workover fluid. This can put the
surface support frame into unacceptable compression. Frames have buckled in the past due to
this.
Allowance has to be made for this possibility. Support frames are available with hydraulic feet
that can be adjusted if shrinkage occurs. (Refer to Figure 34)

Figure 34 - Well Shrinkage

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1.9 CASE HISTORIES

A north sea gas injection well was being worked over with a coiled tubing unit when a small,
uncontrolled gas leak to atmosphere occurred. The gas leak was brought under control by
activating the BOPs, however, attempts to kill the well from the top were unsuccessful and
because of a complex tubing fish, the well was both time consuming and costly to secure.

Figure 35 - Case History Coiled Tubing Rig Up

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1.9.1 Riser And BOP Rig Up

The primary barrier was the quad (upper) BOP and the secondary barrier was the shear/seal
(lower) BOP with independent control systems. (Refer to Figure 35)

1.9.2 Operational Summary

A tubing end locator on 1.25” coiled tubing was being run into the well, to determine the
depth of a cement plug, while seawater was being pumped at a rate of 6 l/min. At an
odometer depth of 290 m the injector head stalled.
The operator, assuming that he was actually at 290 m, pulled out 3.5 m to ensure he was not
stuck downhole. During these operations the pump pressure was fluctuating which could have
been an indication of the coiled tubing breaking. Upon determining that the coiled tubing was
not stuck the operator increased the hydraulic pressure to the injector and attempted to run
past the assumed blockage. The injector head once again stalled at an odometer reading of
290m and at this time a gas leak was observed around the coiled tubing stuffing box. The
operator attempted to pull the tubing slowly out of the well to obtain a better seal between the
coiled tubing and the stuffing box and increased the hydraulic pressure to the stuffing box.
These actions did not decrease the leak.
The operator in conjunction with the drilling supervisor decided to close the slip and tubing
rams in the upper set of BOPs, which reduced, but did not stop the leak. The tubing and slip
rams were opened to attempt to pull out of the hole, however after pulling about one meter
the gas leak became stronger, and further attempts to control the leak using the pipe rams
were unsuccessful.
It was decided to cut the coiled tubing using the shear rams of the upper BOP, pull out of the
stuffing box and close the blind rams, which stopped the leak. The lower Shear rams were
closed as an additional barrier.
To establish the status of the Xmas Tree, closing of the swab valve was attempted and at 114
turns of a required 188 turns the gate valve met resistance. Subsequent X-rays of the riser
revealed that the coiled tubing had been packed into the cross sectional area of the riser,
which was later confirmed when the riser was rigged down and six strings of coiled tubing
were found in place. The coiled tubing operator believing he was at 290 m was never deeper
than 112 m.
Due to unsuccessful attempts to bullhead and lubricate the well dead, it was decided to freeze
the crossover between the Xmas Tree and the lower BOP. The riser was removed and a gate
valve installed and tested. The remainder of the coiled tubing was then fished successfully with
a snubbing unit.

1.9.3 Conclusions And Recommendations

The gas leak could have been avoided if the hydraulic pressure to the injector head motors
had been limited to less than that required to break the coiled tubing, or if better
instrumentation in the control unit had helped the operator to realise that an obstruction had
been encountered and the coiled tubing was breaking.
Indications of possible coiled tubing failure should have been identified from the fluctuating
pump pressures, however, probably due to inexperience on the part of the operator these were
not picked up on at the time.

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