Can World Leaders Straighten the Economy? The Strategic

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

https://doi.org/

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.

CliffordLouis&HassanKhan/ 2021;1(1):1–19

3

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.

CliffordLouis&HassanKhan/Pragma Journals 2021;1(1):1–19

4

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.


5

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.


6

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

CliffordLouis&HassanKhan/Pragma Journal 2021;1(1):1–19

7

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


8

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


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)


9

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:


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


10

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)


11

(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.

CliffordLouis&HassanKhan/Pragma 2021;1(1):1–19

12

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)


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)


14

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)

CliffordLouis&HassanKhan/Pragma Journals 2021;x(x):1–19

15

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.


16

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)


Clifford Louis & Hassan Khan / STAR Journal of Oil and Gas 2021;x(x):1–19

17

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/


19

REFERENCES

1. Luft H B, Pelensky P J, Wilde G. Insulated and/or concentric coiled tubing: U.S. Patent 6,015,015[P]. 2000–1-18.

2. Palmer A. Technical and analytical aspects of pipe laying in deep water in. In: Proceedings, Institute of marine

engineers/society for underwater technology joint conference on pipelining in the north sea. London; 1975.

3. Mitchell R F. Tubing buckling—The state of the art. SPE 104267, 2006.

4. Gere J M, Timoshenko S P. Mechanics of materials, pws[J]. 1990.

5. Miyahara, M. and Tokimasa, K.: ―Creep-Fatigue Damage Rule Under Variable Straining Based On Strain Range

Partitioning Concept,‖ Materials Science Research Intl., 3, No. 1 (1997), 49–55.

6. Clancy T F, Falk K L, Duque L. Concentric coiled tubing well-vacuuming technology for complex horizontal wells in

eastern Venezuela [C]. SPE/ ICoTA Coiled Tubing Roundtable, 2000.

7. Well Vacuuming Technology With Concentric Coiled Tubing: Best Practices and Lessons Learned from Over 600

Operations[C]//SPE Asia Pacific Oil and Gas Conference and Exhibition. Society of Petroleum Engineers, 2008.

8. Dong, H., Shi, H., Norris, L.H. et al. 2011. A New Coiled Tubing Application To Enhance Operating Envelope for

Deepwater Production. Presented at the SPE Annual Technical Conference and Exhibition, Denver, 30 October–2

November. SPE-147601-MS.

© 2020 Published by Pragma Journals Licensed under CC BY-NC-ND license (https://creativecommons.org/licenses/by/4.0/)

Documents

Can World Leaders Straighten the Economy? The Strategic