can world leaders straighten the economy? the strategic
TRANSCRIPT
Can World Leaders Straighten the Economy? The Strategic thinking that Will Fix the Oil Industry Crisis.
Clifford Louis 1, Hassan Khan 1
1World Premier Congress on Natural Gas and Oil.
A R T I C L E I N F O
Article history
Received 10.05.2020
Accepted 02.02.2021 Available online
Published
1. Corresponding author.
Clifford Louis
World Premiere Congress on Natural
Gas and Oil.
https://doi.org/
1 HISTORY
The development of coiled tubing (C.T.) as we know it
today dates back to the early 1960s, and it has become an
integral component of many useful services and workover
applications. While service /workover applications still
account for more than 75% of C.T. use, technical
advancements have increased the utilization of C.T. in
both drilling and completion applications.
2 ORIGIN
Before the Allied invasion in 1944, British engineers
developed and produced very long, continuous pipelines for
transporting fuel from England to the European Continent
to supply the Allied armies. The project was named operation
―PLUTO‖, an acronym for ‖Pipe Lines under the Ocean‖,
and involved the fabrication and lying of several pipelines
across the English Channel. The successful fabrication and
spooling of continuous flexible pipeline provided the
foundation for additional technical developments that
eventually led to the tubing strings used today by the C.T.
industry.
J Clin Pharm Res 2021;1(1):1–19
© 2021 Published by Pragma Journals Licensed under CC BY-NC-ND license (https://creativecommons.org/licenses/by/4.0/)
Journal of Clinical Pharmacy and Research
2
3 EARLIEST COIL TUBING USED:
The first injector heads operated on the principle of two
vertical, contra-rotating chains. This design is still used
in the majority of C.T. units today. The stripper was a
simple, annular-type sealing device that could
hydraulically activate to seal around the tubing at
relatively low wellhead pressures. The tubing string used
for the initial trials fabricates by butt-welding 50 ft.
sections of 1 3/8 in O.D. pipe into a 15,000ft string and
spooling it onto a reel a 9ft diameter core.
4 COIL TUBING APPLICATIONS:
Coil tubing can be used for many reasons. There are different
coil tubing applications; it can be used in the field of drilling,
production wellbore jobs etc. Some of them are mentioned
below:
1. FOR CIRCULATION PURPOSE:
The most popular use for coiled tubing is circulation or de-
liquefaction. A hydrostatic head (a column of fluid in the
wellbore) may be inhibiting the flow of formation fluids due
to its weight (the well is said to have been killed). The safest
(though not the cheapest) solution would be to attempt to
circulate out the fluid, using a gas, frequently nitrogen (Often
called a ’Nitrogen Kick’)
2. PUMPING:
Pumping through coiled tubing can also be used to distribute
fluids to a specific location in the well, such as cementing
perforations or performing chemical washes of downhole
components such as sand screens. Coiled technologies enable
the deployment of complicated pumps, which require
multiple fluid strings on coiled tubing. In many cases, the use
of coiled tubing to deploy a problematic pump can
significantly reduce deployment cost by eliminating the
number of units on-site during the deploy.
3. PRODUCTION:
Coiled tubing is often used as a production string in shallow
gas wells that produce some water. The narrow internal
diameter results in a much higher velocity than would occur
inside conventional tubing or the casing. This higher velocity
helps lift liquids to the surface, which might otherwise
accumulate in the wellbore and eventually ‖kill" the well.
The coiled tubing may be run inside the casing instead or
inside conventional tubing. When coiled tubing run inside
traditional tubing, it often referred to as "velocity string", the
space between the outside of the coiled tubing and the inside
of the conventional tubing referred to as the "micro annulus".
5 COMPARISION OF COIL TUBING WITH
WIRELINE AND SLICK LINE:
WIRELINE:
1. Discover the breadth and depth of tools and
technology.
2. Wireline products include running tools, pulling tools,
shifting tools, kick over, gauge cutters, blind boxes, lead
impression blocks.
3. Fishing tools includes releasable alligator, grabs reliable
overshoots, reliable spears, H.D. (Heavy-duty) pulling
tools, replacement fishing necks, wire finders grabs, and
finder grab bailers.
4. H.D. (Heavy-duty) wireline fishing services includes
a range of jars, accelerators, and quick-lock connects
pressure control equipment.
SLICK LINE:
1. Slick line services are an essential tool for maintaining
production on target and keeping OPEX (operating
expenses) within budget since they are fewer than
wireline and coil tubing.
2. LIVE digital slick line services and Optical Thermal
profile and investigation service have extended the
work scope with the tricky line. The well site engineer
can now monitor what is happening down the hole
and control operations dynamically, with continuous
depth correlation.
6 COIL TUBING SYSTEM AND COMPONENTS: Coiled Tubing services provide customers with reliable,
efficient, vertical, horizontal, highly deviated, and live wells.
The coiled tubing is a continuous length of steel or composite
tubing that is flexible enough to be wound on a large reel for
transportation. The coiled tubing is injected into the existing
production string, unwound from the reel and inserted into the
well.
Coiled tubing is chosen over conventional straight tubing
because traditional tubing must be screw together.
Additionally, coiled tubing does not require a workover rig.
Because coiled tubing is inserted into the well while production
is ongoing, it is also a cost-effective choice and can use on
high-pressure wells.
7 THE BASIC COMPONENTS OF A CT UNIT ARE:
1. Injector and tubing guide arch
2. Service reel with C.T.
3. Power supply/prime mover
4. Control console
5. Control and monitoring equipment
6.
8 TUBING INJECTOR FOR CT UNIT: The injector assembly is designed to perform three essential
functions:
1. Provide the thrust required to snub the tubing into the
well against surface pressure and overcome wellbore
friction forces.
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2. Control the rate of lowering the tubing into the well
under various good conditions.
3. Support the tubing's full weight and accelerate it to
operating speed when extracting it from the well.
Fig. 1 Illustrates a typical rig-up of a C.T. injector and
well-control stack on a wellhead. Several types of counter-
rotating, chain drive injectors working within the industry,
and how the gripper blocks are loaded onto the tubing vary
depending on the design. These injectors manipulate the
continuous tubing string using two opposed sprocket drive
traction chains powered by counter-rotating hydraulic
motors.
Fig. 1: C.T. Injector and Typical Well-Control Stack Rig-Up
(Courtesy of SAS Industries Inc.)
9 WEIGHT INDICATOR:
The injector must be equipped with a weight indicator that
measures the tensile load in the C.T. (above the stripper),
with the weight measurement displayed to the equipment
operator during good intervention or drilling services.
There should also be a weight indicator that measures the
compressive force in the tubing below the injector when
C.T. is being thrust into the well (often referred to as
negative weight). Some weight indicators can measure a
limited amount of negative weight typically equal to the
importance of the chain drive assembly mounted in the
injector frame. If this type of weight indicator is used, the
thrust force applied during the C.T. operation should not
exceed the chain drive assembly's weight.
9 TUBING GUIDE ARCH:
The counter-rotating, opposed-chain drive injectors used in
well intervention and drilling operations utilize a tubing
guide arch located directly above the injector. The tubing
guide arch supports the tubing through the 90◦+ bending
radius and guides the C.T. from the service reel into the
injector chains. The tubing guide arch assembly may
incorporate a series of rollers along the arch to support the
tubing or be equipped with a fluoropolymer-type slide pad
run along the arch's length. The tubing guide arch should
include a series of secondary rollers mounted above the
C.T. to centre the tubing as it travels over the guide arch.
The number, size, material, and spacing of the
rollers can vary significantly with different tubing guide
arch designs. For CT used repeatedly in well intervention
and drilling applications, the tubing guide arch's radius
should be at least 30 times the specified O.D. of the C.T. in
service. This factor may be less for C.T. that will be bend-
cycled only a few times, such as in permanent installations.
The continuous- length tubing should enter and exit the
tubing guide arch tangent to the guide arch's curve. Any
sharp bending angle over which the C.T. passes causes
increased bending strains, dramatically expanding the
fatigue damage applied to the tubing. During normal C.T.
operations, the reel tension applies a bending moment to
the tubing guide arch base. Therefore, the tubing guide
arch must be designed to be strong enough to withstand the
bending caused by the required reel back tension for the
suitable tubing size.
10 STRUCTURE SUPPORT:
The injector should be stabilized when rigged up to minimize
the potential for applying damaging bending loads to the
well-control stack and surface wellhead during the well-
intervention program. The injector may be stabilized above
the wellhead using:
1. Telescoping legs
2.An elevating frame
3.A mast or rig-type structure
The injector support is the means provided to the injector
to prevent a bending moment (such as reel back tension)
from being applied to the wellhead of such magnitude as to
cause damage to the wellhead or well-control stack under
normal planned operating conditions. Precautions should be
taken to minimize the transfer of loads resulting from:
1.The weight of the injector
2.Well-control equipment
3.The hanging weight of the C.T. into the tree along the
axis of the wellhead
11 TELESCOPING LEGS:
Telescoping legs are generally used in rig-ups where the
injector's height or wellhead does not permit the use of an
elevating frame. When telescoping legs are used, the top
sections are inserted into the four cylinders located on the
injector frame's corners and then secured with pins at the
required height.
Footpads are placed beneath each telescoping leg to distribute
the injector's weight to the surface grade. The legs' additional
stiffness is achieved by tightening the turnbuckles mounted
beneath the leg sections. When telescoping portions are used,
the injector and well-control stack assembly's weight and
operating forces are transferred directly to the wellhead,
requiring that the rig-up load be supported with a crane or
travelling block to minimize the burden applied onto the
wellhead.
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12 ELEVATED FRAME:
In rig-up scenarios where a free surface is available (e.g.,
offshore platforms), it is recommended to support the
injector using a hydraulically or mechanically controlled
elevating frame structure. Once the stand's desired height is
achieved, the four legs on the perimeter of the stand are
pinned and secured in place. The base of the elevating
frame
13 REQUIREMENTS WHEN USING A MAST:
In rig-up scenarios in which a mast or derrick is required,
precautions must be taken to minimize the axial load placed
on the wellhead by the injector and well-control stack. The
injector should also be secured in some fashion within the
mast or derrick to minimize the pitch and yaw motion of
the injector during service.
14 SERVICE REEL FOR CT UNIT :
The service reel serves as the coiled tubing (C.T.) storage
apparatus during transport and as the spooling device during
C.T. well-intervention and drilling operations. Fig. 2 and
3 show the side view and front view of a typical service reel.
Fig.2:Side view of typical service reel (courtesy of SAS Industries Inc.)
Fig. 3: Front view of atypical C.T. reel (Courtesy of SASIndustries Inc.
15 INSTALLATION:
The inboard end of the C.T. may be connected either to the
hollow segment of the reel shaft (spoke and axle design) or
to a high-pressure piping segment (concave flange plates),
both of which connects to a high-pressure rotating swivel.
This high-pressure fluid swivel is secure to a stationary
piping manifold, which connects to
the treatment-fluid pumping system. As a result, continuous
pumping and circulation can maintain throughout the job.
A high-pressure shutoff valve should be installed between
the C.T. and reel shaft swivel for emergency use in
isolating the tubing from the surface pump lines. The reel
should also have a mechanism to prevent the drum's
accidental rotational movement when required to remain
stationary. In any event, the reel supporting structure should
be secured to the deck or surface grade on location to
prevent movement during operations.
In addition to the reel's fluid-pumping service, electric
wireline may be installed within the C.T. string to provide
a means for conducting logging and downhole tool
manipulation operations. The wireline is run inside the
C.T., and is terminated at the reel shaft within a pressure
bulkhead on the C.T. manifold. The single or multi-
conductor cable is run from the pressure bulkhead to a
rotating electric connection (slip collector ring) similar to
that found on electric wireline units. On reels equipped for
electric-line service, this electric connection may be
located on the reel shaft opposite the rotating fluid swivel
or at the pressure bulkhead adjacent to the inboard swivel
piping.
16 SERVICE REEL OPERATION:
In preparation for initial installation, a wing union is
typically welded onto the end of the C.T. to be hooked up
to the high-pressure piping within the reel (commonly
referred to as the ―reference‖ end). The mechanical
connection is inserted through a slot in the reel core drum
and made up to the high-pressure piping. Once the link has
been properly terminated, the tube bents over a preset
guide to creating a reasonably smooth bend transition to
the core drum's outer surface.
The tubing's initial layer is spooled across the core
drum until the tubing wrap reaches the opposing flange.
Then, the tubing is spooled back over the base layer, resting
in the recesses between the tubes on the previous layer.
This wrapping process is continued through the remaining
successive layers until the tubing's desired amount is spool
onto the reel. The tubing is wrapped onto the rotation, allows
the tube to be supported within the previously covered
tubing space and offers a unique stacking geometry.
The service reel's core radius defines the tubing's
smallest bending radius. For CT used repeatedly in well
intervention and drilling applications, the core radius should
be at least 20 times the specified outside diameter (O.D.) of
the C.T. This factor may be less for C.T. that will be bend-
cycled only a few times, such as for permanent
installations.The service reel rotation is controlled by a
hydraulic motor, which may be mounted as a direct drive
on the reel shaft or operated by a chain-and-sprocket drive
assembly. This motor is used to provide a given tension on
the tubing, thereby maintaining the pipe tightly wrapped
on the reel.
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Backpressure is kept on the reel motor during deployment,
maintaining tension on the tubing between the injector and
service reel. This tensile load applied to the reel motor's
tubing is commonly called "reel back tension,‖ requiring
the injector to pull the tubing off the reel. The amount of
reel back tension required increases with an increase in
C.T. O.D., yield strength (increased bending stiffness of the
tubing), and the distance between the service reel and
injector. Besides, the required load on the reel drive system
increases as the size of the core radius increases. Note that
this tension results in an axial load imposed onto the tubing
guide arch and creates a bending moment that is applied to
the top of the injector. Therefore, the injector must be
appropriately secured so that the bending moment is not
translated to the well-control stack components or
wellhead.
17 REEL BRAKE:
Additional safety items should also be included in the reel
package to provide for an ancillary remote-activated braking
system. The reel brake's primary function is to stop drum
rotation if the tubing accidentally parts between the reel
and injector and limit tubing-reel rotation if a runaway
condition develops. This braking system is not intended to
halt the uncontrolled dispensing or retrieval of tubing in a
runaway mode but only offers resistance to slow down the
reel rotation. The brake can also minimize tubing on the reel
from springing in the case of loss of hydraulic pressure and
the loss in reel back tension. When the reel is being
transported, the brake should be engaged to prevent reel
rotation. Many units incorporate a device in their hydraulic
power systems to impose backpressure at the motor to slow
the reel down. Other units employ a calliper-type or
friction- pad braking system, which is hydraulically or
mechanically applied onto the reel flange's outer diameter
to aid in slowing the reel rotation down.
18 LEVEL WIND ASSEMBLY:
The tubing is typically guided between the service reel and
injector using a mechanism called the ―level wind assembly,‖
which correctly aligns the tubing as it is wrapped onto or
spooled off the reel. The level wind assembly spans across
the service reel drum's width and can be raised to any
height, which will line up the C.T. between the tubing
guide arch and the reel. Generally, a mechanical depth
counter is mounted on the level wind assembly, which
typically incorporates a series of roller wheels placed in
contact with the C.T. and geared to measure the footage of
the tubing dispensed through it mechanically. The level
wind must be strong enough to handle the bending and
side loads of the C.T. During transportation, the C.T.'s free
end is usually clamped to the level wind to prevent
springing. The level wind may also be equipped with a
hydraulically or pneumatically operated clamp, which can
be manipulated to
secure the C.T. at the crossbar of the level wind frame.
19 PRIME MOVER FOR CT UNIT:
Coiled Tubing (C.T.) power supply units are built in many
different configurations, depending on the operating
environment. Most are hydraulic-pressure pump systems
powered by diesel engines, though a limited few employ
electrical power. In general, the prime mover packages
used on C.T. units are equipped with diesel engines and
multistage hydraulic pumps that are typically rated for
operating pressures of 3,000 to 5,000 psig. The hydraulic
drive unit is supplied in size necessary to operate all of the
C.T. components in use and will vary with the needs of the
hydraulic circuits employed.
20 COMPONENTS :
HYDRAULIC POWER PACK: The most common hydraulic power pack system is
described as an "open-loop" circuit, in which the fluid is
discharged from the prescribed motor and returned to the
hydraulic reservoir at atmospheric pressure. In general,
open-loop power packs are equipped with vane-type
hydraulic pumps and are rated for a maximum of 3,000
psig service pressure applied to the hydraulic circuit. The
pumps in these power packs provide source power for the:
1. Injector
2. Service reel
3. Level wind
4. Well-control stack
5. Console
6. Auxiliary panels as needed
The hydraulic power pack may be designed as a "high-
pressure, open-loop‖ system or as a ―closed-loop‖ system
where additional power to the injector circuit is needed. In
both of these enhanced hydraulic power systems, the high-
pressure circuit is limited to the injector hydraulics, with
the remaining circuits powered by the vane-type pumps.
The increased pressure in the hydraulic circuit for the
injector provides the means for generating higher force loads
within the injector motors as compared to the vane pumps,
which are limited to 3,000 psig service. The high-pressure
open-loop system typically uses a piston pump to provide
hydraulic pressure as high as 5,000 psig to the injector circuit.
The hydraulic fluid is discharged from the injector motors
to the hydraulic reservoir tank at atmospheric pressure.
The closed-loop hydraulic system also provides injector
pressure to a maximum of 5,000 psig, with the distinction
being that the hydraulic fluid is re-circulated to the injector
without returning to the hydraulic reservoir. The hydraulic
fluid losses experienced through the injector motors are
compensated by a charge pump incorporated into the
closed-loop circuit.
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UNLOADER VALVES:
In general, the hydraulic pumps on the power pack are
equipped with pressure-relief valves (or unloader valves)
that limit the amount of hydraulic pressure the pump can
deliver to the prescribed circuit. These unloader valves are
set at the desired pressure for the respective circuit and must
be checked periodically to ensure that they are functioning
correctly.
Specifically, the unloader valve on the injector circuit
should be set at a pressure that limits the amount of force
that can be applied to the tubing in tension (pulling) and
compression (thrust). Before dispatch of C.T. service
equipment from the vendor facility, the unloader valve on
the injector circuit (either on the power pack or in the
console) should be set to a pressure that does not exceed
the safe load limit of the C.T. in service. Tests should be
performed before equipment load-out to verify the sustained
pressure output and fluid flow rate for the hydraulic pumps.
21 ACCUMULATOR CIRCUIT:
In the current power pack design, an accumulator circuit is
typically included to provide fluid volume and pressure for
the well-control stack operation. The number of accumulator
bottles typically ranges from one to six, depending on the
well-control stack's size and pressure rating in service. The
accumulator package for well-control operation must have
sufficient volume and pressure to complete three complete
function cycles of all the rams incorporated within the well-
control stack without recharge from the power pack. These
function cycles are typically described as ―close-open-
close‖ cycles and should be performed periodically to ensure
that the accumulators are pre-charged to the appropriate
pressure and that the circuit is free of hydraulic leaks.
22 CONTROL CONSOLE:
The control-console design for the coiled-tubing (C.T.)
unit may vary with manufacturers, but usually, all control
is positioned on one remote console panel. A diagram of a
typical well-intervention unit control panel is seen in Fig.
4. The console assembly is complete with all controls and
gauges required to operate and monitor all of the
components in use and may be skid-mounted for offshore
use or permanently mounted as with the land units. The
skid-mounted console may be placed where needed at the
well site as desired by the operator. The reel and injector
motors are activated from the control panel through valves
that determine the direction of tubing motion and operating
speed. Also located on the console are the control systems
that regulate the pressure for the drive chain, stripper
assembly, and various well-control components.
Fig. 4: Simplified Layout of a Console Control Panel (Courtesy
SchlumbergerManuals)
23 EQUIPMENT PARAMETERS TO MONITOR :
The coiled-tubing (C.T.) equipment-related parameters that
should be monitored to ensure the equipment is functioning
correctly include:
1. Traction force
2. Chain tension
3. Well-control system hydraulic pressure
4. Reel motor pressure
5. Injector motor pressure
6. Stripper hydraulic pressure
The critical job parameters that must be monitored
throughout- out the job are discussed next.
24 LOAD MEASUREMENT:
The load may be defined as the tensile or compressive force
in the C.T. just above the stripper and is one of the most
important measurements needed for proper operation of the
prescribed service.
The load may be affected by several parameters other
than the hanging weight of the C.T. and include:
1. Wellhead pressure
2. Stripper friction
3. Reel back tension
4. The density of the fluids inside and outside the tubing.
The load should be measured directly using a load
cell that measures the tensile and compressive
forces applied to the C.T. by the injector. A
secondary load measurement may be obtained
indirectly by measuring the hydraulic pressure
applied to the injector motors where the specified
hydraulic pressure-to-load ratio is known.
25 MEASURED DEPTH:
Measured depth is the length of C.T. deployed through the
injector. Measured depth may be significantly different from
the actual centre of the C.T. in the well because of:
1.Stretch 2.Thermal expansion 3.Mechanical elongation
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Measured depth can be directly observed at several places
on a C.T. unit using a friction-type wheel that contacts the
tubing. Measured depth may also be obtained indirectly by
measuring the injector shaft rotation. A CT unit should
not be operated without a dedicated depth measurement
system being displayed to the C.T. operator. Measured
depth should be recorded as a function of time and
concerning internal pressure applied to the C.T. string for
bend-cycle fatigue calculations.
26 SPEED MEASUREMENT:
Speed may be calculated from the change in measured depth
over a specified period.
27 CT INLET PRESSURE:
Pumping pressure at the inlet to the C.T. should be
monitored and displayed to the C.T. operator and recorded
for use in bend-cycle fatigue calculations or post-job
reviews. This pressure-measurement system must
incorporate a method of isolating the pumped-fluid circuit,
eliminating the possibility for pumped fluid to discharge
into the control cabin if gauge failure occurs. It is
recommended that a pressure recorder be incorporated in
the C.T. pressure- monitoring package to record pump
pressure throughout the prescribed service.
28 WELLHEAD PRESSURE :
Well pressure around the outside of the C.T. at the
wellhead should be monitored and displayed to the C.T.
operator and recorded for use in post-job reviews. This
pressure- measurement system must incorporate a method
of isolating the wellbore fluid circuit, eliminating the
possibility for well fluids to discharge into the control
cabin if gauge failure occurs. It is recommended that a
pressure recorder be incorporated in the C.T. pressure-
monitoring package to record well pressure throughout the
prescribed service.
29 WELL-CONTROL STACKS FOR CT
OPERATIONS:
The well-control stack system is a critical part of the coiled-
tubing (C.T.) unit pressure containment package and is
composed of a stripper assembly and hydraulically operated
rams, which perform the functions described next.
30 RAM COMPARTMENTS:
For typical well-intervention service, the four ram
compartments are equipped (from top-down) with:
1. Blind rams
2. Tubing shear rams
3. Slip rams
4. Pipe rams (Fig. 5).
Fig. 5: Typical Quad Ram Well ControlStack Configuration
(Courtesy Schlumberger Manuals)
31 BLIND RAMS:
The blind rams are used to seal the wellbore off at the surface
when well control is lost. Sealing of the blind rams occurs
when the rams' elastomeric elements are compressed
against each other. For the blind rams to work correctly, the
tubing or other obstructions across the ram bonnets must be
removed.
32 TUBING SHEAR RAMS:
The tubing shear rams are used to mechanically break the
C.T. If the pipe gets stuck within the well-control stack or
whenever it is required to cut the tube and remove the
surface equipment from the well. As the shearing blades are
closed onto the C.T., the forces imparted will mechanically
yield the tube's body to failure. The cut is deformed and
typically must be dressed to return to the proper geometry.
33 SLIP RAMS:
The slip rams should be equipped with bidirectional teeth,
which, when activated, secure against the tubing and support
the C.T. and bottom hole assembly (BHA) weight below. An
additional utility of the slip rams is the ability to close onto
the tube and secure movement if those well-pressure risks
blow the tubing out of the borehole. The slip rams are
outfitted with guide sleeves that properly centre the C.T. into
the ram body's grooved recesses as the slips are being closed.
34 PIPE RAMS:
The pipe rams are equipped with elastomeric seals performed
to the specified outside diameter (O.D.) size of C.T. in
service. When closed against the C.T., the pipe rams are used
to isolate the wellbore annulus pressure below the rams.
These rams are also outfitted with guide sleeves that
properly center the C.T. into the preformed recess as the
rams are being closed.
35 COIL CONNECTORS:
1. Coil connectors used and available are of many types,
which are as follows:
2. Crimp-on (Roll-on Style)
3. Cold Roll (Roll-on Style)
4. Dimpled Style
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5. Set-screw Style
6. Internal Slip Style
7. Combination -slip and dimpled/set-screws
8. Welded
9. Threaded
A review of some of these types is explained as follows:
DIMPLE AND ROLL-ON TYPE: The dimple and roll-on type both have almost features
apart from of course some differences their characteristics
are given below:
1. Anti-Rotational
2. Applies to sizes
3. Positive O-ring Seal
4. CT shape is altered to engage corresponding connector
profiles.
5. Provides a threaded connection for BHA’s
Dimple Type: External and Internal
Fig. 6: Roll on Type: Internal Fig no. 6—DimpleType Connectors
(Courtesy Schlumberger Manuals)
The properties of the slip type connector:
1. Anti-Rotational
2. Positive O-ring Seal
3. Applies to all sizes of C.T.
4. Slip is used to engage C
.T.
5. C.T. remains nominal in size
6. May be accompanied by dimple type
7. Provides a threaded connection for BHA’s
Fig. 7: Slip Type (Courtesy Schlumberger Manuals)
36 INTERNAL SLIP STYLE CONNECTORS:
The distinctions of internal slip style connector:
1. Strong connection
2. Not effected greatly by wall reduction
3. Can be challenging to install
4. Sensitive to C.T. Ovality
5. Reduction in I.D.
6. Can be difficult to remove
Fig. 8: Internal Slips Style Connector (Courtesy SchlumbergerManuals)
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37 EXTERNAL SLIP STYLE CONNECTORS:
The specialities of external slip style connectors:
1. Strong connection
2. Can be affected by wall reduction
3. Relatively easy to install
4. Sensitive to C.T.
5. Widely used in the industry.
Fig. 9: External Slip Style Connection (Courtesy Schlumberger-
Manuals)
OTHER CONNECTION METHODS:
1. Welding used for bottom profiles, repair
2. Threaded CT rare, usually weak (thin wall)
3. Suggestion checks every connector with a pull test and
covers the hole.
CHECK VALVES:
1. They are generally attached to C.T. connector at the
end of C.T. string.
2. Prevent the flow of well fluids into C.T.
3. Maintain well security when tubing at surface
fails/damaged
4. Should be part of every C.T. bottom hole assembly
only omitted when the application precludes their
using reverse circulation required
TYPES OF CHECK VALVE:
Flapper check valves
Ball and seat check valves
FLAPPER STYLE:
Features are as follows:
1. Positive O-ring Seal
2. High pressure
3.Large passable I.D. Acts as a safety valve preventing the upward flow of
wellbore fluids or gases into the coil tubing work
string
(a)
(b)
Fig. 10: FlapperStyle (Courtesy Schlumberger Manuals)
BALL / DART TYPE:
Specifications are as follows:
1. The ball and seat provide a seal.
2. A positive metal to metal seal
3. High pressure
4. I.D. is not passable
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Ball / Dart Type (Courtesy Schlumberger Manuals)
Fig. 11: Ball / Dart Type (Courtesy Schlumberger Manuals)
37 SEPARATION TOOLS:
There are three types of separation tools which are:
1.Mechanical type
2.Hydraulic type
3.Single and Dual types
MECHANICAL TYPE: The properties are as follows:
1. Provides the BHA with a separation point, so the C.T.
and the BHA located above the separation sub may be
recovered from the well.
2. Tension release.
3. Release value adjusted by material and number of shear
screws installed.
4.Alternative shears methods available.
Fig. 12: MechanicalType (Courtesy Schlumberger Manuals)
HYDRAULIC TYPES: The specifications are as under:
1. Flow activated release mechanism allows function
without having to seat an actuation ball.
2. Flow rates may be adjusted as required.
3. Shear screws may accompany it.
4. Ball activated release mechanism requires passable
I.D.'s located above.
5. Adjustable pressure as per requirement Variable ball
sizes.
Hydraulic Types (Courtesy Schlumberger Manuals) (a)
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(b)
Fig. 13: Hydraulic Types (Courtesy Schlumberger
Manuals)
SINGLE & DUAL TYPES:
Fig. 14: Single and Dual Types (Courtesy Schlumberger Manuals
Single and Dual Types
Fig. 14: Singleand Dual Types (Courtesy Schlumberger
Manuals
The characteristics of the Single and Dual types are:
1. Provides a secondary means of circulating in the
event the BHA located below the circ. sub becomes
obstructed or may be functioned to shut off flow to
other BHA components.
2. May or may not be ball activated.
3. Pressure adjustable.
4. Burst disc used for safety purposes.
MOTOR HEAD ASSEMBLY:
Motor head assemblies incorporate the previous listed BHA
components into on complete tool serving four purposes:
1. Coil Connector
2. Dual Flapper Check Valve
3. Hydraulic Disconnect
4. Dual Circulation Sub
COIL TUBING BHA IMPACT DEVICES: There are two types of Coil tubing impact systems:
1. Dual Acting Hydraulic Jarring Systems
2. Impact Hammer Systems
DUAL ACTING HYDRAULIC JARRING SYSTEMS:
1. Jarring systems are commonly used to dislodge wellbore
obstructions.
2. Intensifiers used in conjunction with jars to maximize
forces applied to fish.
3. It functioned by reciprocating the C.T. work string.
4. Requires tension and compression loads down hole.
5. Delivers both upward and downward impacts.
6. Passable ID’s.
7. No flow required.
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DRILLING TOOLS: Positive displacement Type and Vain type are discussed
here:
POSITIVE DISPLACEMENT TYPE:
1. Provides bit rotation by converting flow and pressure to
mechanical process and torque.
2. Fluid driven.
3. Sealed or open bearing sections.
4. Various power section configurations.
5. Various speeds, output torques & lengths.
6. Elastomeric used in the stators.
Fig. 15: Positive Displacement Type (Courtesy
SchlumbergerManuals)
VAIN TYPE:
1. No elastomeric used in the power section.
2. It may be driven by gases or harsh fluids.
3. It may be operated in high-temperature environments.
4. Various performance options are available.
5. Generally shorter in length.
6. It sealed bearing assembly.
Fig. 16: Vain Type (Courtesy Schlumberger Manuals)
Milling and drilling tools provide the cutting edge required
to remove wellbore obstructions and manage unwanted
debris or drill geographical formations.
Fig. 17: Milling Tools (Courtesy Schlumberger Manuals)
Fig. 18: Various Milling Tools (Courtesy Schlumberger Manuals)
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MILLING TOOLS:
13
38 SPECIALTY MILLING TOOLS:
UNDER REAMERS: Under reamers, allow a small I.D. to be passed thru and
a larger I.D. to be milled or drilled below.
1. Hydraulically functioned.
2. May be operated in conjunction with PDM’s.
3. Opening parameters may be adjusted.
4. There is no need to remove production tubing to
service the casing or open the hole section below the
tubing bottom.
39 E-LINE COIL TUBING:
Provides a means of connecting the E-line located inside
the coil tubing to a usable electronic connection while
Fig. 19: Under Reamers (Courtesy Schlumberger Manuals)
mechanically connecting to the coil tubing and serving the
motor head assembly's four purposes.
1. Coil Connector.
2. Dual Flapper Check Valve.
3. Hydraulic Disconnect.
4. Circulation Sub.
Fig. 20: E-Line Coil Tubing (Courtesy Schlumberger Manuals)
ISOLATION PACKERS:
1. Isolation packers may be deployed and functioned
via—coil tubing.
2. It may be set in casings or tubing.
3. Mechanical or hydraulic setting mechanisms.
4. Various pressure ratings.
5. It may be operated without killing the well.
Fig. 21: Production Logs May Be Conducted (Courtesy Schlum-
berger Manuals)
Fig. 22: Downhole cameras may be used to troubleshoot wellbore
problems (Courtesy Schlumberger Manuals)
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SELECTIVE PACKERS:
1. Provides the ability to select where stimulation fluids or
gases are placed in the wellbore.
2. It may be used for water shut off, leak testing
injection testing.
3. It may be released and reset.
4. Inflatable designs are available.
(a)
Fig. 23: Selective Packers (Courtesy Schlumberger Manuals)
40 PRESSURE CONTROL TOOLS:
UN-LOADERS, SEQUENCE & SAFETY VALVES:
Provides the ability to preset or control BHA components
by pressure, flow or string tension/compression.
1. It may be used as a safety component.
2. It may be used to increase the BHA flow rate to assist
in well clean up.
3. May control flow rate delivered to the BHA.
Fig. 24: PressureControl Tool (Courtesy Schlumberger
Manuals)
Fig. 25: OrientationTools (Courtesy Schlumberger Manuals)
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BHA PULSATING:
The CT BHA is oscillated by a pulse generated by the tool.
The pulse prevents the onset of the helical lock-up of the
work string. Enhanced weight transfer to the drilling BHA.
41 LATERAL LEG ENTRY TOOLS
Provides the ability to locate and enter multilateral legs in a
well to perform C.T. workover operations.
1. Hydraulically functioned.
2. May be pressure indications when the lateral leg is
entered.
3. C.T. set whip stocks to provide a safe method to
exit the well bore & begin directional drilling
operations.
4. May exit through both tubing and casing.
5. C.T. Retrievable.
Fig. 26: C.T. Well Bore Departure Systems (Courtesy
Schlumberg- erManuals)
Fig. 27: Rotating and Releasing Overshot (Courtesy Schlumberg-
erManuals)
42 PACKER MILLING AND RETRIEVING TOOLS:
Mill and retrieve packers and bridge plugs in a single run.
Extensions can be added between the spear and the packer
mill in both types to provide sufficient length for the spear to
pass through the bore of the packer before the mill engages
the element. Both washover- and blade-type packer milling
and retrieving tools can be released from the packer should
it fail to mill up or disengage.
APPLICATIONS: Removing packers and bridge plugs
BENEFITS:
1. Effective hole cleaning
2. Reliable, heavy-duty milling performance
The packer milling and retrieving tools mill and recover
production packers and bridge plugs in a single run. The
washover-type system mills over the slip section to disengage
the packer. The spear section extends through the packer to
catch and retrieve the element once the slips have been
removed. The packer mill consists of a mill body and a
replaceable mill or long rotary shoe dressed with crushed
carbide.
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43 FIXED BLADE:
The fixed-blade-type system features four blades dressed
with crushed carbide for packer milling. Circulation ports
between the blades allow cuttings to be flushed out of the
wellbore. The catch assembly is equipped with a milling head
dressed with crushed carbide and functions as a guide to
remove any obstructions in the packer bore.
Fig. 28: Fixed Blade Type (Courtesy SchlumbergerManuals)
44 TMC LUBRICATED BUMPER SUB:
Bump up or down to meet fishing objectives, even in harsh
environments. The TMC lubricated bumper sub
incorporates maximum stroke length and high torque
transmission capacity, enabling the operator to bump up or
down until fishing objectives are met. The TMC bumper
sub’s robust design, materials quality, and comprehensive
quality requirements ensure reliable performance in the
harshest downhole environments.
APPLICATIONS:
1. Fishing operations, including stuck pipe, packer
retrieving, tubing removal, milling, and debris
recovery.
2. Plug and abandonment operations, including pipe
recovery and wellhead removal.
45
Fig. 29: TMC Lubricated Bumper Sub
MILLING ASSEMBLY COMPONENTS:
Following are the milling assemblies components:
Fig. 30: Milling Assembly (Courtesy Schlumberger Manuals)
EXTERNAL SLIP COIL TUBING CONNECTOR:
The coil tubing connector is designed to allow means of
connecting a bottom hole assembly to the end of C.T. This slip
type connector is the ideal method for transfer of both tensile
and torque from the C.T. to the bottom hole assembly.
Key Features:
Slip type
Full ID
Torque- Thru
Fig.31: External Slip Coiled Tubing Connector(Courtesy
Schlumberger Manuals)
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DUAL PRESSURE BACK PRESSURE VALVE:
The dual back pressure valve is designed to shut off the coil
tubing from within the well. This tool can simply prevent the
flow up the bottom hole assembly.
Key Features:
Maintains Well Control
Large ID for ball passage
Dual for backup
Fig. 32: Dual PressureBack Pressure Valve (Courtesy Schlumberger
Manuals)
AN ECONOMICAL COMPARISON BETWEEN
CONVENTIONAL HORIZONTAL WELL AND
RE-ENTRY WELLS:
A new horizontal well drilled from the surface costs about 1.4
to 3 times more than a vertical well. A horizontal re-entry
well costs about 0.4 to 1.3 times a vertical well cost. Note,
since Re-entry drilling has never been in Pakistan yet, so
for comparison, we took data from US Marcellus shale
wells.
Conventional Re-Entry
Site Preparation Cost ($) 100,000 30,00
Drilling Contractor Services
Cost ($) 1,200,000
RSS Cost ($) 1,500,000
Logging, Stimulation &
Perforations Cost ($) 400,000 100,000
Power ,Water Disposal Cost ($) 3,700,000 3,000,000
Completion, Labor Cost ($) 200,000 100,000
Coiled Tubing Unit Cost ($)
1,500,00
Window Milling Cost ($)
250,000
Single Lateral Cost ($)
10,000
Additional Surface Facilities
Cost ($) 472,000
Whip Stock Setting Cost
400,000
TOTAL ($): 7,572,000 3,860,000
Vertical Well Cost ($) 4,963,000
Total Cost Times of Vertical
Cost 1.526 0.78
18
49 CONCLUSIONS
The Oil & Gas industry is globally recognized to present the power of
economy and development. Therefore, shareholders and employers give
special attention to maximize the productivity of their oil wells to generate
optimum revenues. Like any other industry, problems within operation and
production of oil and other petroleum materials rise up and hinder the work
progress. Hence, engineers have focused their efforts to come up with
solutions to overcome these problems.
A short time ago, coiled tubing technology was established to
introduce a solution that affords the employer with reliability,
effectiveness, and cost-efficiency. The new method continues to grab more
reputation within the industry and even started to be selected over the
conventional workover rigs. Moreover, technological advances are
currently to be integrated into coiled tubing units such as the internet of
things to boost the system with more functionality and enhanced
performance.
TYPE OF OPERATION
APPLICATION
New field development
Reducing top-down drilling costs Multiplying production capacity several folds
with horizontal, rather than vertical, well
designs Making the development of smaller
fields economically feasible
Sidetracking Enhancing efficiency while creating casing
exits to manoeuvre around wellbore
obstructions, thereby reducing costs
Extended-reach drilling
We are reaching remote drilling targets faster
by minimizing the time required to exit the
main wellbore Overcoming high-dogleg
severity with advanced casing exit and
whipstock assemblies.
Infill drilling Maximizing efficiency when creating
necessary casing exits
Offshore drilling
Rendering access to new economically
feasible reserves, even in light of
comparatively high rig rates, by reducing top-
down drilling costs and the number of subsea
wellheads required Recovering slots on
space-constrained platforms.
Brownfield redevelopment Leveraging existing wellbores to access
bypassed reserves cost-effectively, breathing
new life into mature fields
Enhanced oil recovery
Installing multilateral gas- or water-injection
systems to stimulate production from adjacent
wells
CBM development
Mitigating the high capital expenditures
(CAPEX) associated with CBM projects,
using multilateral systems Dewatering coal seams more quickly to bring production online sooner and at higher rates
Geothermal wells
Maximizing reservoir contact for a thermal
generation with multilateral
Shale resource development Reducing the time, risk and costs of any
departures from the main wellbore
© 2021 Published by Pragma Journals Licensed under CC BY-NC-ND license (https://creativecommons.org/licenses/by/4.0/
CliffordLouis&HassanKhan/Pragma Journals 2021;1(1):1–19
19
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© 2020 Published by Pragma Journals Licensed under CC BY-NC-ND license (https://creativecommons.org/licenses/by/4.0/)