API Standards lec ( 13 )

5.1.1 Preperation and Inspection Before Running

New tubing is delivered free of injurious defects as
defined in API Specification 5CT and within the practical
limits of the inspection procedures therein prescribed. Some
users have found that, for a limited number of critical well
applications, these procedures do not result in tubing suffi-ciently
free of defects to meet their needs for such critical
applications. Various nondestructive inspection services have
been employed by users to ensure that the desired quality of
tubing is being run. In view of this practice, it is suggested
that the individual user:
a.Familiarize himself with inspection practices specified in
the standards and employed by the respective manufacturers,
and with the definition of “injurious defect” contained in the
standards.
b. Thoroughly evaluate any nondestructive inspection to be
used by him on API tubular goods to assure himself that the
inspection does in fact correctly locate and differentiate injurious
defects from other variables that can be and frequently
are sources of misleading “defect” signals with such inspec-tion
methods.
CAUTION: Due to the permissible tolerance on the outside
diameter immediately behind the tubing upset, the user is cau-tioned
that difficulties may occur when wrap-around seal-type
hangers are installed on tubing manufactured on the high side
of the tolerance; therefore, it is recommended that the user
select the joint of tubing to be installed at the top of the string.

5.1.2 All tubing, whether new, used, or reconditioned,
should always be handled with thread protectors in place.
Tubing should be handled at all times on racks or on wooden
or metal surfaces free of rocks, sand, or dirt other than normal
drilling mud. When lengths of tubing are inadvertently
dragged in the dirt, the threads should be recleaned and ser-viced
again as outlined in 5.1.9.
5.1.3 Before running in the hole for the first time, tubing
should be drifted with an API drift mandrel to ensure passage
of pumps, swabs, and packers.
5.1.4 Elevators should be in good repair and should have
links of equal length.
5.1.5 Slip-type elevators are recommended when running
special clearance couplings, especially those beveled on the
lower end.
5.1.6
Elevators should be examined to note if latch fitting is
complete.
5.1.7 Spider slips that will not crush the tubing should be
used. Slips should be examined before using to see that they
are working together.
Note: Slip and tong marks are injurious. Every possible effort should
be made to keep such damage at a minimum by using proper up-to-date
equipment.

5.1.8 Tubing tongs that will not crush the tubing should be
used on the body of the tubing and should fit properly to
avoid unnecessary cutting of the pipe wall. Tong dies should
fit properly and conform to the curvature of the tubing. The
use of pipe wrenches is not recommended.
5.1.9 The following precautions should be taken in the
preparation of tubing threads:
a. Immediately before running, remove protectors from both
field end and coupling end and clean threads thoroughly,
repeating as additional rows become uncovered.
b. Carefully inspect the threads. Those found damaged, even
slightly, should be laid aside unless satisfactory means are
available for correcting thread damage.
c. The length of each piece of tubing shall be measured prior
to running. A steel tape calibrated in decimal feet (millimeters)
to the nearest 0.01 feet (millimeters) should be used. The measurement
should be made from the outermost face of the
coupling or box to the position on the externally threaded end
where the coupling or the box stops when the joint is made up
power tight. The total of the individual lengths so measured
will represent the unloaded length of the tubing string.
The actual length under tension in the hole can be obtained
by consulting graphs that are prepared for this purpose and
are available in most pipe handbooks.
d. Place clean protectors on field end of the pipe so that
thread will not be damaged while rolling pipe onto the rack
and pulling into the derrick. Several thread protectors may be
cleaned and used repeatedly for this operation.
e. Check each coupling for makeup. If the stand-off is abnormally
great, check the coupling for tightness. Loose
couplings should be removed, the thread thoroughly cleaned,
fresh compound applied over the entire thread surfaces, then
the coupling replaced and tightened before pulling the tubing
into the derrick.
f. Before stabbing, liberally apply thread compound to the
entire internally and externally threaded areas. It is
recommended that a thread compound that meets the
performance objectives of API Bulletin 5A2 be used;
however, in special cases where severe conditions are
encountered it is recommended that high pressure silicone
thread compound as specified in API Bulletin 5A2 be used.
g. Connectors used as tensile and lifting memebersshould
have their thread capacity carefully checked to ensure that
the connector can safely support the load.
h. Care should be taken when making up pup joints and
connectors to ensure that the mating threads are of the same
size and type.
5.1.10 For high-pressure or condensate wells, additional precautions should be
taken to ensure tight joints as follows.
a. Couplings should be removed, and both the mill-end pipe
thread and coupling thread thoroughly cleaned and inspected.
To facilitate this operation, tubing may be ordered with
couplings hankling tight, or may be ordered with the couplings
shipped separately.
b. Thread compound should be applied to both the external
and internal threads, and the coupling should be reapplied
handling tight. Field-end threads and the mating coupling
threads should have thread compound applied just before
stabbing.
5.1.11 When tubing is pulled into the derrick, care should
be taken that the tubing is not bent or couplings or protectors
bumped.

5.2 STABBING, MAKING UP, AND LOWERING

5.2.1 Do not remove thread protector from field end of tubing until ready to stab.

5.2.2 If necessary, apply thread compound over entire sur-face
of threads just before stabbing. The brush or utensil used
in applying thread compound should be kept free of foreign
matter, and the compound should never be thinned.
5.2.3 In stabbing, lower tubing carefully to avoid injuring
threads. Stab vertically, preferably with the assistance of a
man on the stabbing board. If the tubing tilts to one side after
stabbing, lift up, clean, and correct any damaged thread with
a three-cornered file, then carefully remove any filings and
reapply compound over the thread surface. Care should be
exercised, especially when running doubles or triples, to pre-vent
bowing and resulting errors in alignment when the tub-ing
is allowed to rest too heavily on the coupling threads.
Intermediate supports may be placed in the derrick to limit
bowing of the tubing.
5.2.4 After stabbing, start screwing by hand or apply regu-lar
or power tubing tongs slowly. To prevent galling when
making connections in the field, the connections should be
made up at a speed not to exceed 25 rpm. Power tubing tongs
are recommended for high-pressure or condensate wells to
ensure uniform makeup and tight joints. Joints should be
made up tight, approximately two turns beyond the hand-tight
position, with care being taken not to gall the threads. When
the additional preparation and inspection precautions for
high-pressure or condensate wells are taken, the coupling will
“float” or make up simultaneously at both ends until the
proper number of turns beyond the hand-tight position have
been obtained. The hand-tight position may be determined by
checking several joints on the rack and noting the number of
threads exposed when a coupling is made up with a torque of
50 ft-lb (68 N • m).

5.3 FIELD MAKEUP

5.3.1 Joint life of tubing under repeated field makeup is
inversely proportional to the field makeup torque applied.
Therefore, in wells where leak resistance is not a great factor,
minimum field makeup torque values should be used to prolong
joint life. The use of power tongs for making up tubing
made desirable the establishment of recommended torque
values for each size, weight, and grade of tubing. Table 3 con-tains
makeup torque guidelines for nonupset, external upset,
and integral joint tubing, based on 1 percent of the calculated
joint pullout strength determined from the joint pullout
strength formula for 8-round-thread casing in API Bulletin
5C3. All values are rounded to the nearest 10 ft-lb (13.5 N •
m). The torque values listed in Table 3 apply to tubing with
zinc-plated or phosphate-coated couplings. When making up
connections with tin-plated couplings, 80 percent of the listed
value can be used as a guide. When making up round-thread
connections with PTFE (polytetrafluoroethylene) rings, 70
percent of the listed values are recommended. As with standard
couplings, makeup positions shall govern. Buttress
connections with PTFE seal rings may make up at torque val-ues
different from those normally observed on standard but-tress
threads.
Note: Thread galling of gall-prone materials (martensitic chromium
steels, 9 Cr and 19 Cr) occurs during movement stabbing or pulling
and makeup or breakout. Galling resistance of threads is
primarily controlled in two areas—surface preparation and
finishing during manufacture and careful handling practices
during running and pulling. Threads and lubricant must be clean.
Assembly in the horizontal position should be avoided. Connections
should be turned by hand to the hand-tight position before slowly
power tightening.The procedure should be reversed for disassembly.

5.3.2 Spider slips and elevators should be cleaned fre-quently,and slips should
be kept sharp.
5.3.3 Finding bottom should be accomplished with extreme caution. Do not set
tubing down heavily.

5.4 PULLING TUBING

5.4.1 A caliper survey prior to pulling a worn string of tub-ing will provide a
quick means of segregating badly worn lengths for removal.
5.4.2 Breakout tongs should be positioned close to the cou-pling. Hammering
the coupling to break the joint is an injurious practice. When tapping is
required, use the flat face, never the peen face, of the hammer, and tap
lightly at the middle and completely around the coupling, never near the
end or on opposite sides only.
5.4.3 Great care should be exercised to disengage all of thethread before
lifting the tubing out of the coupling. Do not jump tubing out of the
coupling.
Tubing stacked in the derrick should be set on a firm wooden platform
and without the bottom thread protector since the design of most
protectors is not such as to support the joint or stand without damage to
the field thread.
5.4.5 Protect threads from dirt or injury when the tubing is
out of the hole.
5.4.6 Tubing set back in the derrick should be properly supported to prevent
undue bending. Tubing sizes 2 3 / 8 and larger preferably should be
pulled in stands approximately 60 feet (18.3 meters) long or in doubles of
range 2. Stands of tubing sizes 1.900 OD or smaller and stands longer
than 60 feet (18.3 meters) should have intermediate support.
5.4.7 Before leaving a location, always firmly tie a setback of tubing in place.
5.4.8 Make sure threads are undamaged, clean, and well coated with
compound before rerunning.
5.4.9 Distribute joint and tubing wear by moving a length from the top of the
string to the bottom each time the tubing is pulled.
5.4.10 In order to avoid leaks, all joints should be retight-ened occasionally.
5.4.11 When tubing is stuck, the best practice is to use a calibrated weight
indicator. Do not be misled, by stretching of the tubing string, into the
assumption that the tubing is free.
5.4.12 After a hard pull to loosen a string of tubing, all joints pulled on should be
retightened.
5.4.13 All threads should be cleaned and lubricated or should be coated with a
material that will minimize corrosion. Clean protectors should be placed
on the tubing before it is laid down.
5.4.14 Before tubing is stored or reused, pipe and threads should be inspected
and defective joints marked for shopping and regauging.
5.4.15 When tubing is being retrieved because of a tubing failure, it is
imperative to future prevention of such failures that a thorough
metallurgical study be made. Every attempt should be made to retrieve
the failed portion in the “as-failed” condition. When thorough etallurgical
analysis reveals some facet of pipe quality to be involved in the failure,
the results of the study should be reported to the API office.

completion course

Sample Completion Configurations lec ( 12 )

Single Zone
Completion #1

A single zone completion using a hydraulic set retrievable packer is a simple,
very commonly used design.
Design Advantages ❑ Retrievable

• ❑ Allows circulation above the packer
• ❑ Packer may be set after well head installation
• ❑ Flow may be controlled or shut off using the profile nipples and/or

sliding sleeve

• ❑ Design allows for the installation & retrieval of recording devices

and flowing pressure / build up data acquisition.
Design Disadvantages

•  ❑ Suitable for low to medium pressure differentials only
• ❑ Limited ability to handle tubing forces
• ❑ Limited material selection

Additional Equipment
That Could Be Added

• ❑ Flow couplings if required
• ❑ Artificial lift equipment
• ❑ Safety valve

Single Zone
Completion #2

A single zone completion using a high performance retrievable mechanical
double grip packer is a common completion design primarily used in single
zone gas well completions
Design Advantages 

• ❑ Retrievable
• ❑ Allows circulation above the packer
• ❑ Packer may be utilized as a bridge plug
• ❑ Flow may be controlled or shut off using the profile nipples and/or

sliding sleeve

• ❑ Design allows for the installation & retrieval of recording devices
• ❑ Design is capable of handling medium high differential pressures

and high tubing forces
Design Disadvantages 

• ❑ limited material selection
• ❑ Pressure handling capability of some sizes may be limited

Additional Equipment
That Could Be Added

• ❑ Flow couplings if required
• ❑ Artificial lift equipment
• ❑ Safety valve
• ❑ TCP assembly

Single Zone
Completion #3

This is a common completion used in underbalanced perforating of single zone
wells.
Design Advantages 

• ❑ Retrievable
• ❑ W/L setting allows exact depth control
• ❑ Packer may be utilized as a bridge plug
• ❑ Allows flow control using profile nipples
• ❑ Design is capable of handling medium high differential pressures

and high tubing forces.
Design Disadvantages 

• ❑ Limited material selection
• ❑ Pressure handling capabilities of some sizes may be limited

Additional Equipment
That Can Be Added

• ❑ Flow couplings if required
• ❑ Artificial lift equipment
• ❑ Safety valve
• ❑ Sliding sleeve

Single Zone
Completion #4

This is a typical shallow to medium depth permanent seal bore packer completion
primarily used on natural gas wells.
Design Advantages 

• ❑ Good pressure handling capability
• ❑ Suitable for sour completions
• ❑ Good flow control with profile nipples and the sliding sleeve
• ❑ Design allows for use of recording devices in the tail pipe
• ❑ Good material selection

Design Disadvantages 

• ❑ Packer is not retrievable
• ❑ Plugs used in the nipples below the packer are susceptible to fill

Additional Equipment
That Can Be Added

• ❑ Mill out sub
• ❑ Flow couplings if required
• ❑ Artificial lift equipment
• ❑ Safety valve
• ❑ TCP assembly

• ❑ On/off tool

Single Zone
Completion #5

This is an example of a deeper single string gas well completion which allows
for tubing movement.
Design Advantages 

• ❑ Suitable for high pressure sour applications
• ❑ Locator seal assembly can be spaced out to allow for anticipated

tubing movement

• ❑ Mill out sub allows for one-trip removal of the packer and tail pipe
• ❑ Design allows for pressure recorder installation in the tail pipe

Additional Equipment
That Can Be Added

• ❑ Safety valve
• ❑ Sliding sleeve above the seal assembly to allow circulation above

the packer

• ❑ Chemical insection nipple or mandrel above the seal assembly

Single Zone
Completion #6

This is a common permanent packer single string completion used in deeper
hostile environment gas wells.
Design Advantages 

• ❑ Largest possible through bore

• ❑ Primary seal bore is retrievable
• ❑ Sliding sleeve allows circulation above the packer
• ❑ Design incorporates provision for recorders in the tail pipe

Additional Equipment
That Can Be Added

• ❑ Safety valve
• ❑ Chemical infection valve
• ❑ Gas lift equipment

Dual Zone Single String
Completion

This type of completion is commonly used in shallow low pressure sweet
natural gas wells in North America. Lower zone is produced up the tubing
string and upper zone up the annulus.
Design Advantages 

• ❑ Economical
• ❑ Retrievable
• ❑ Packer may be utilized as a bridge plug
• ❑ Good flow control with profile nipples and sliding sleeve
• ❑ Allows for installation and retrieval of recorders

Design Disadvantages 

• ❑ Suitable for shallow “sweet” completions only
• ❑ Suspectable to fill problems from upper zone

Additional Equipment
That Can Be Used

• ❑ Provision for rod pump, plunger lift or siphon tube

Dual Zone Dual String
Completion

This is a common completion type used in those wells where it is advantageous
to produce two zones simultaneously.
Design Advantages 

• ❑ All equipment is retrievable
• ❑ Both zones can be produced independently and simultaneously
• ❑ Packers may be set after the well head is installed
• ❑ Sliding sleeve may be used to open communication between the

tubing strings
Additional Equipment
That Can Be Used

• ❑ Sliding sleeves above the dual string packer
• ❑ Well configurations in both tail pipe assemblies for recorders
• ❑ Selective set packers
• ❑ Gas lift equipment

• ❑ Safety valves

Multi Zone Single String
Completion

This completion design allows the selective production of multiple zones up
one string of tubing.
Design Advantages

• ❑ Allows control of each zone individually
• ❑ Retrievable
• ❑ Hydraulic packers may be set after installation of the well head

Design Disadvantages 

• ❑ Restricts production to one zone at a time
• ❑ Limited material selection in packers
• ❑ Limited ability to handle tubing forces

Additional Equipment

That Can Be Added

• ❑ Sliding sleeve above top packer to allow circulation between the

annulus and tubing

• ❑ Blast joints
• ❑ Recorder provision below lower packer

Completion course

Materials lec ( 11 )

Material Selection

 In general, oil and gas wells are hostile environments. Consequently, careful

consideration must be given to the materials from which completion components
are manufactur. A wide variety of materials, with a range of physical properties,
have been developed specifically for use in downhole completion components.
In severe cases, it may be necessary, or cost effective, to incorporate a system
which resists the harmful effects of agents present in the wellbore or reservoir
fluid.
Proper selection of completion materials is a key factor in ensuring completion
longevity. However, it is important that the design life of the completion is
compatible with the production profile of the well or field (Fig. 8-1).

Well Life Design

Material Selection Criteria

 Completion components must be chosen to resist the damaging effects of

pressure, temperature and corrosion. In addition, recent exploration and
completion operations have resulted in wells being drilled deeper with higher
pressures and temperatures being encountered.
Material selection criteria for oilfield equipment are typically determined by the
following categories:

•  Mechanical properties (function)
•  Operating environment
•  Cost
•  Availability
•  Stock size and shape

These categories relate to the selection of metals, elastomers and plastics used

in construction of downhole tools and equipment. They are not listed in order
of priority since they may change for different applications.

Ferrous Alloy
Compositions
and Characteristics

Non-Ferrous Alloy
Compositions
and Characteristics

Packer Component
Materials

A sample material list for a standard service medium pressure hydraulic set
retrievable packer

Material Applications

 Weight or stress bearing components, such as the outer bodies of safety
valves, packers, etc., are know as stagnant flow components. They may be
made of a different material than the internal components (mandrels, flow tube,
flapper, etc.). Internal components that are exposed directly to corrosive well
fluids are known as flow wetted components.
Examples of material applications are shown in Fig 8-4.

Non-Metallic Components 

Elastomers and plastics are blended and synthesized organic polymers.
Polymers are repeating units of organic compounds. The flexibility of the
linking bonds between these units is what gives elastomers and plastics the
ability to stretch and then return to their original shape. The primary purpose
of elastomers and plastics in downhole tools is to provide seal materials to
isolate pressure, liquids, gases, or heat.
Many elastomers and plastics are available, each with different inherit qualities.
Elastomers function quite well in most wellbore environments but problems
can arise under the following conditions:

•  Certain corrosive environments
•  Wide temperature fluctuations
•  Extreme pressures

The completion technologist should be aware of downhole conditions,
especially temperatures, to enable selection of the correct elastomers (seal
and o-ring) for a specific application.

General Seal
Materials Guide

Elastomers 

There are two major types of polymer materials, elastomers and plastics. They
are differentiated on the basis of their elastic properties although there is no
sharp distinction between them. Polymers may be blended with other materials
to create substances with specific properties. An elastomer is a material which
can be stretched at least twice its length and upon release of the stress will
quickly return to approximately its original length.
Materials are added to elastomers and plastics to increase the strength, stiffness,
oil resistance, low temperature resilience, high temperature resistance and to
lower the friction coefficient. Unfortunately, whenever materials are added to
enhance one quality, another quality often suffers.
Polymers are blended for construction of O-rings, seals and packing elements.
The most common type of elastomer is Nitrile. This substance is also know as
Buna-N or Hycar (brand name). Other common materials are Viton and Aflas
which are fairly strong and resistant to degradation from exposure to wellbore
fluids.
Polymer materials are used as high performance packing for moderate
temperatures, pressures and corrosion. When completion tools must be
installed in wells where the temperature is very high, or in an H2S environment,
elastomers of fluorocarbons are used. Fluorocarbon elastomers can be
compounded with many substances including glass and asbestos, thereby
improving resistance to extrusion.
Plastics are also used in the manufacture of completion tools and equipment.
There are two major types of plastics:

•  Thermoplastic - Formed by melting a resin, pouring the resin into a

mold and letting it cool to harden.

•  Thermosetting plastic. - Plastic in a liquid form is poured into a

mold and heat or hardening agents are applied to produce certain
chemical changes that cause the plastic to harden into the shape
of the mold. Once a thermosetting plastic has been formed it will
not melt, at least not at normal temperature. Examples of
thermosetting plastics are Teflon, Loctite and Eastman 910 (brand
names).
Teflon has probably the greatest oilfield application of the thermosetting
plastics. It has a high resistance to both high and low temperature, very low
friction and is inert to most fluids.
Teflon is used to form seal rings. However, to be efficient they must be
mechanically energized to make and maintain a seal. For this reason, Teflon
seals are usually used as back-up or secondary seals in high pressure
applications.
A number of new exotic plastics have been developed which show a high
degree of resistance to H2S, high pressure, and temperature conditions.
Fig 8-8 illustrates many of the common polymers used in oilfield tools.

Completion course

Forces lec ( 10 )

Tubular Forces 

Determining the stress levels that the completion string and components will
be subjected to, under the best and worst conditions, is a critical step in
completion design. Properly assessing the length and force changes will avoid
premature failures and costly remedial operations.

•  Temperature
•  Pressure
•  Weight
•  Fluid gradients
•  Friction

Tubing Forces

 Each completion will have a variety of downhole conditions which affect the
total design, choice of downhole tools and the operation of the completion
components once in place. Changes in temperature, pressure, applied weight,
fluid gradients and friction are a few of the variables that must be considered.
The choice of completion equipment not only must meet minimum stress
requirements, but they themselves contribute directly to these stress
calculations. The illustration in Fig 7-1 summarizes the principal variables that
need to be considered in a completion operation.For more detailed discussion
on basic forces refer to the “ Completions Hydraulics Handbook.”

Factors Influencing
Completion String Length
and Force Changes

Length and
Force Changes

The most important aspect when evaluating a packer installation is the
determination of the length and force changes due to varying pressures and
temperatures. When the magnitude and direction of these length and force
changes have been calculated, this information can then be used as shown
below.

•  To aid in the packer selection process
•  To determine if tubing damage will occur
•  To determine the proper spacing-out procedure for the packer and completion components

There are four different effects which create length and force changes. Each of
these effects must be analyzed and combined to assess the total effect for any
packer installation.

•  Piston effect
•  Buckling effect
•  Ballooning effect
•  Temperature effect

This piston effect, bucking effect and ballooning effect result from pressure
changes in the system. The temperature effect is related only to temperature
change and is not affected by pressure changes. While some effects are
related to each other, each must be calculated individually. Each calculated
effect will be a magnitude and direction. Once each effect is known, they are
combined to obtain the total effect. The decision to add or subtract when
combining is based on the direction that each effect (resultant force) acts.
The approach used to evaluate packer installation problems will depend on the
type of tubing-to-packer hookup being considered. If the packer system will
not permit length change in the direction of the total effect, then the packer
installation is evaluated by calculating the force changes. If the packer system
permits length change in the direction of the total effect, then the calculation
would be as a length change.

Piston Effect 

See Completions Hydraulics Handbook

Auxiliary Completion Components lec ( 9 )

 Auxiliary Completion Components

The production string is a receptacle for many kinds of flow control devices
and other accessories which are designed to increase the versatility of the
completion. Some of these devices are run as a part of the tubing string while
others are installed and retrieved by wireline or coiled tubing. Items installed
by wireline methods must have a facility in the tubing string which allows
removable devices to be located and secured.

Tubing Landing Devices
– Seating Nipples

Seating nipples are landing devices which have a slightly restricted polished
ID which prevents tools from passing through and allow sealing of devices.
Seating nipples do not have a locking recess. The tool locates on the shoulder
of the reduced ID section and is held in place by pressure from above. The
standing valve is an example of a downhole tool often located in seating nipples.
These nipples are also commonly used to land recipricating rod pumps in.

Subsurface Safety Valves

Nipples

Tubing Landing Devices
– Profile Nipples

Nipples used to land downhole tools fitted with locking mechanisms are known
as profile nipples. In addition to an internal sealing surface, profile nipples
have a profiled locking recess.
There are two basic types of profile nipples, no-go nipples and selective nipples.
These nipples have a restricted ID, or a no-go shoulder at the bottom or top of
the seal surface, on which the downhole tool is located.
Selective nipples (Fig 6-1) can be placed in the tubing string at as many locations
as necessary. Selective nipples in a series can all have the same profile of
locking recess and ID. In this case, the specific nipple must be located by
determining its depth. This is the most common system. However, some
companies manufacture selective nipples with as many as six different profiles.
Such nipples may be run in a specific sequence with special keys conforming
to the position of the desired nipple. The keys on the running mandrel ensure
the device will only locate in the specific nipple desired. This system is not
commonly used anymore. There are several manufacturers of profile nipples,
each of which may have two or more product lines of profile nipples.
It is also possible for a variety of downhole tools to have a nipple profile cut
into them. These profiles may either be selective or no-go and receive a variety
of flow control devices.

Hydraulic Landing Nipples

 For the installation of retrievable surface controlled subsurface safety valves
(SCSSV) that are actuated by hydraulic pressure, it has been necessary to
develop hydraulic landing nipples (Fig 6-3). Again, these nipples may be either
selective or no-go. They have two polished bores with a single port between
the bores for the introduction of hydraulic fluid under pressure.

 

Mandrels

Mandrels
Side Pocket

Side pocket mandrels (Fig 6-4) can also be considered landing devices. Most
side pocket mandrels provide an unrestricted flow path in the tubing string but
can receive a variety of different control devices. Side pocket mandrels have an
offset pocket next to the drift ID at the bottom of the mandrel containing a
polished bore for pressure sealing above and below a port. In addition to
landing gas lift valves, control devices as chemical injection valves, circulating
valves and circulating sleeves may be landed in side pocket mandrels.
A variety of devices for controlling communication between the tubing and the
annulus can be landed in side pocket mandrels. Gas lift valves can be set to
open at a preset pressure in response to either injection gas pressure or
production pressure. As soon as the valve opens, injection gas flows freely
into the fluids of the production conduit (either tubing or annulus, depending
on completion design.).

Mandrels
  Conventional

Conventional mandrels (Fig 6-5) are designed to carry and protect externally
mounted conventional gas lift valves. The internal surface of a conventional
mandrel does not have an upset area or pocket (as with a side pocket mandrel).
The flush internal surface is broken only by a small access port to the externally
mounted gas lift valve.

Down Hole Tubing

 Hangers It is possible to land a section of tubing in a casing hanger nipple that was run
in with the casing. The casing hanger nipple has a no-go in it and is used to
land a tubing hanger attached to the tubing string. The tubing hanger sets in
the casing hanger nipple and supports the tubing. This capability is used
when the tubing may need to be separated above the tubing hanger utilizing a
separation device. The upper section of the tubing string may be pulled without
retrieving the entire string. The tubing string is also landed at the wellhead in
the tubing head. The tubing at the surface is attached to the tubing hanger,
which fits into the tubing head. The restricted ID of the tubing head holds the
slips of the tubing hanger.

Sleeves

Communication Devices Sliding Sleeve
A more efficient method of circulating between tubing and
annulus is to use a sliding sleeve (Fig 6-6) . This device is widely
used to permit circulation between the tubing and the annulus or
for selectively producing a zone. Sliding sleeves can be opened
using wireline methods by either a jar upward or downward with
a special shifting tool. Sliding sleeves have a large circulating
capacity and are excellent devices for communication between
the tubing and annulus for well kill or similar high fluid-volume
applications.

Other communication devices may be placed in side pocket mandrels to control
flow from the annulus to the tubing or vice versa. These circulating devices
include among others:

• Circulating sleeves

Devices to allow circulation in either direction which protect the
side pocket from damage due to the erosive effects of flow.

• Circulating valves

Valves used to circulate in one direction only. Some circulating
valves are designed for flow into the annulus while others are
designed to allow flow into the tubing.

• Dump-kill valves

Valves landed in a side pocket mandrel, which require a
predetermined pressure differential across the tubing before they
will open. Pins are sheared and fluids will flow under pressure
through the valve into the tubing. This device is placed relatively
deep in the well and is used to kill the well.

Tubing String
Protection Devices

Types

 The production string is exposed to many physical forces which can cause
damage. Several devices and tools have been developed to protect the tubing
string and completion equipment from such forces or conditions.

• Safety joint (Fig 6-7)

Safety joints are usually installed above a packer. If the packer
becomes stuck, the safety joint can be separated. This enables a
heavier-fishing string containing jars to be used to retrieve the
stuck packer. Safety joints are available in straight pull or rotation
models.

• Flow coupling

Flow couplings are installed above and below certain components
in the tubing string to protect against erosion damage. Flow
couplings are normally available in lenghts betweeen 4 and 10
feet, and constructed from heavy walled pipe. These sections of
pipe serve to prevent fluid turbulence from eroding the tubing
string (Internal erosion).

• Blast joint (Fig 6-8)

Blast joints are heavy walled joints of pipe, available in lengths
between 2 and 20 feet. Blast joints are installed in the completion
string to withstand the scouring action of fluid flow from
perforations (External erosion).

Tubing Separation
Devices

Types 

On - off tools (Fig 6-9)
If frequent removal of a portion of the tubing is expected during
the life of a well, tubing on-off attachments are available. These
attachments consist of a removable skirt section which is attached
to the tubing string, and a slick joint which usually contains a
wireline profile which stays attached to the packer.
Tubing Seal Receptacles (Fig 6-10)
Generally used in lengths of 10 to 30 ft., tubing seal receptacles
are installed immediately above the packer. These devices
resemble on-off connectors but have a much longer stroke, to
allow for tubing movement. The seal receptacle is normally run in
closed position either utilizing a ‘J’ or shear pins. Once landed
the receptacle skirt is released and spaced out on the slick joint
as required.
The slick joint generally incorporates a profile in the top. The
skirt assembly which contains the seals can be removed from the
slick joint and retrieved leaving the slick joint in place.

Tubing Expansion Devices

Expansion Joints

 Under some conditions the tubing string of a producing well may be subjected
to large stress changes due to pressure or temperature changes These forces
cause the tubing string to expand and contract. If conditions warrant it, it may
be necessary to install an expansion device to avoid buckling or possible
separation of the tubing string. Expansion joints are designed to eliminate the
stress produced during these changes allowing the tubing string to expand
and contract without losing the integrity of the production string. They are
commonly produced in stroke lengths of 2 to 20 feet.
Non-splined expansion joints are free to rotate. No tubing torque can be
transmitted through this type of expansion joint.
Clutch type expansion joints (Fig 6-11) are free to rotate through most of their
stroke, but lock when fully extended or compressed to allow torque transmission
through the expansion joint.
Fully splined expansion joints (Fig 6-12) are locked against rotation throughout
their stroke.

Polished Bore
Receptacle (PBR)

Available in lengths of 10 to 30 ft. long. PBR’s (Fig 6-13) consist of a polished
seal bore above the packer which is attached to the packer and a long seal
assembly which is attached to the tubing and seals into the polished bore. The
seal assembly is generally shear pinned into the seal bore when running. Once
landed the seal assembly is sheared and spaced out as required. The seal
assembly may be retrieved to be redressed or repaired. If it is necessary to
retrieve the polished seal bore it will require a second trip with a retrieving tool.

Seal Bore Extension (SBE)

 A ‘SBE’ is run below a seal bore packer in order to extend the length of the
packer’s seal surface. Normally used in lengths of 10, 20, or 30 ft. long. An
extended locator type seal assembly is run into the seal bore and spaced out as
required.
Adjustable Union

 An adjustable union (Fig 6-14) provides a means of spacing out and connecting
tubing on the short string side between dual packers. The adjustable union
may also be used space out production tubing near the surface.

The deisgn function of a subsurface safety valve is to prevent the uncontrolled
flow of well fluids.

Types

There are two major types of subsurface safety valves:
Subsurface Controlled Safety Valve (SSCSV)
This type of safety valve is controlled by well conditions. When
the downhole pressure or velocity reaches a predetermined
setting, the valve will close. The valves are actuated by the
ambient pressure differential created by increased fluid velocity
which occurs when the integrity of the production string above
the safety valve is broken. Subsurface controlled safety valves
are located in a profile nipple.
Surface Controlled Subsurface Safety Valve (SCSSV)
This type of safety valve is controlled by surface hydraulic
pressure transmitted through a small control line to control the
valve. Pressure is used to keep the valve open. If the control
pressure is released and the valve closes. SCSSVs shut off the
flow of the well completely, producing a pressure tight seal.
SCSSV’s may be tubing retrievable or wireline retrievable. The
tubing retrievable type can be pulled only with the removal of the
entire tubing string. Wireline retrievable valves that are controlled
from the surface must be landed in the hydraulic landing nipple
or inside of a locked out tubing retrievable safety valve.

SAtuaxnildiainrgy vCaolmvepletion Components

A standing valve functions as a downhole check valve. This valve allows flow
in one direction and may be landed in a seating nipple or landing nipple.
Pressure from below normally causes fluids to pass freely into the production
tubing while pressure from above results in the ball forming a seal in the seat.
Standing valves are normally run with an internal equalizing device which
allows the pressure to be equalized.
Pressure equalization is necessary before the standing valve can be removed
from the seating nipple. Standing valves are used primarily for setting hydraulicset
packers or for chamber lift applications.

Pump-out plugs

 Pump-out plugs are often used when it is necessary to place a plug in the
tubing string below the packer. These one-time usage plugs, placed beneath
the packer, hold the pressure necessary for hydraulic-set packers to be set.
When pressure is increased to a specific preset value shear pins are sheared,
allowing the ball and sleeve to be forced down and out of the tubing. Once the
ball has been pumped out, the device can serve as wireline re-entry guide and
has a full open bore for the production of fluids. Pump-out plugs are normally
used only in the long string of dual completions, or in single string completions.

Completion Packers lec ( 8 )

Production Packer

Types

There are several types of production packers. Several of the most common
types are identified below:

•  Retrievable mechanical packers
•  Hydraulic/hydrostatic set retrievable packers
•  Permanent seal bore packers
•  Retrievable seal bore packers

Mechanical Packers

Applications

 Mechanical packers represent the most common packers used in the oil field.
Mechanical packers are set and released by manipulation of the tubing string.
Tubing string rotation and the application of weight or tension at the packer
are required to set or release. Mechanical packers can be set or unset without
being removed from the well for redress.They are suitable for application in the
following general conditions:

• Shallow to medium setting depths
•  Low to moderately high pressures
•  Straight hole or moderate deviation

Types

 There are two basic types of Mechanical packers:

•  Single grip retrievable packers (Fig 5-1) which are set and packed

off with either tubing tension or compression. These packers require
the tension or compression force to be maintained in order for the
packer to remain set and packed off.

•  Double grip retrievable packers (Fig 5-2) which contain some

provision to prevent movement in either direction once the packer
is set. This type of packer may be further divided into two types:

1. Those utilizing hydraulic accuated slips (holddown buttons), to prevent upward movement of the packer once it is set.

     2. Those which are mechanically locked into the set and packed off position. Once locked, these packers remain set independent ofthe tubing and hydraulic forces.

Tension Set Retrievable
Mechanical Packers

Description 

Single grip tension set mechanical packers (Fig 5-3) are not commonly used
nowadays except for shallow low pressure applications. Most models of tension
set packers utilize a secondary shear release system, which allows the packer
to be released by pulling a predetermined amount of tension on the tubing in
case the packer cannot be released using normal procedures.
Generally, tension set mechanical packers are best suited for applications in
which the expected pressure differential is from below, such as shallow injection
or disposal wells.
The model SA-3 (Fig 5-3) and the model ‘T’ retrievable packers (Fig 5-4) are
examples of mechanical tension set packers. The SA-3 is a single grip type in
which the slips hold in one direction only and so the packer will only remain set
so long as a tubing tension is maintained on the packer. The model ‘T’ is an
example of a double grip type tension packer, in that once it is set with the
proper amount of tension, it locks in that position and will remain set and
packed off independent of tubing forces, so long as the shear valve of the
secondary release is not exceeded.

Benefits of
Mechanical Packers

To prevent accidental release or failure, it is essential that an appropriate packer
design be used with the correct compression or tension applied. The benefits
of a retrievable mechanical packers include the following:

•  Cost - Generally these packers require less initial investment
•  Repeated use - The setting mechanism enables the packer to be

set, released, moved and reset without removal and redressing
procedures.

•  Versatile - Packer may be used for a variety of applications including

service work.

Compression Set
Single Grip Retrievable
Mechanical Packers

Description

 Single grip compression set mechanical packers (Fig 5-5) generally utilize one
set of slips, that when activated, prevent the packer from moving down hole.
The continued application of tubing compression packs off the element system
which will remain packed off so long as sufficient compression force is
maintained.
Compression set packers are most suitable for applications in which the expected
pressure differential will be in favor of the annulus.
The model CA is an example of a very simple and basic compression set packer
suitable for shallow low pressure applications. The SR-2 (Fig 5-6) is an example
of a single grip compression set packer with a better element system plus an
equalizing system which makes it more suitable for higher pressure medium
depth applications. Compression set packers were once the most common
type of mechanical packer used, this type has been replaced in most completion
applications by the double grip type packers

Double Grip
Mechanical Packers

Description

 This type of retrievable packer has become the most common type of mechanical
set packers. Double grip mechanical packers are reliable and versatile packers
suitable for shallow to medium depth wells and applications where moderately
high pressures are expected.
Double grip packers are generally packed off with compression force. The
packer is unset with tubing manipulation. Most types of bi-directional packers
utilize a pressure equalizing system to prevent hydraulic problems when
releasing.
The SR-1 (Fig5-7) is an example of a mechanical double grip packer which
utilizes hydraulic upper slips. This type of packer must be set in compression
and tubing compression must be maintained. The hydraulic slips prevent the
packer from being forced up the well due to high pressures on the tubing side.
The SOT-1 (Fig5-8) is an example of a premium bi-directional retrievable packer.
The SOT-1 utilizes two sets of slips placed on either side of the elements. This
allows pressure differential forces across the elements to be taken directly by
the slips. This feature allows the packer to safely handle higher pressures than
other types of double grip packers which have both sets of slips below the
elements. The SOT-1 packer locks into the set position and once set, remains
locked independent of pressure and tubing forces.

Hydraulic Set
Retrievable Packers

Hydraulic and/or hydrostatic-set retrievable packers are set without mechanical
manipulation of the tubing. After the packer is run to depth, hydraulic pressure
is applied to the fluid in the tubing string to set the packer. Once set, the packer
is mechanically locked in the set position. Release mechanisms vary and are
generally right-hand rotation or straight-pull release.
Types of Hydraulic Set Retrievable Packers:

•  Single string differential set retrievable packer
•  Single string hydrostatic set retrievable packer
•  Selective set single string hydrostatic set retrievable packer
•  Dual string hydrostatic set retrievable packer
•  Multiple conduit hydraulic set retrievable packer

Operation 

During the setting operation, the string is temporarily plugged below the packer
to allow pressure to be applied to the setting mechanism. At a preset value,
shear pins are broken allowing the packer slips to be forced out to engage the
casing wall and the sealing elements are compressed. A ratchet mechanism
locks the slips and packing in the set position. The packer can be mechanically
released using either rotation or a straight pull. Most models cannot be reset
once released.
The tubing is plugged during the setting process by one of the following
methods:

•  Positive plug
•  Pump open plug
•  Pump out plug/ball
•  Standing valve

Applications

 Hydraulic set retrievable packers are suitable for application in the following
general conditions:

•  Shallow to medium depths
•  Low to medium pressure applications
•  Multiple packer single string completions
•  Dual string completions
•  Selective set multiple packer completions

Advantages

•  After the packer is set, energy is stored in the ratchet mechanism

that ensures continued force against the element seal and slips to
securing the packer. Therefore, packer setting is not dependent
upon applied tubing force.

•  Since the setting force is mechanically locked into the packer it is

capable of holding differential pressures or tubing forces from
above or below the packer.

•  This type of packer may be set after the wellhead has been installed.

•  Dual tubing string completions and multiple packer applications

generally utilize hydraulic set packers, which require no tubing
movement in the setting process.

Hydro Packers

Differential Set
Hydraulic Packers

This type of packer is set by using the force generated by tubing pressure
acting on a piston against annulus pressure. A specific amount of differential
pressure (in favor of the tubing) has to be applied to complete the setting. The
Hydro-6 packer (Fig 5-9) is an example of this type of hydraulic packer.
With the increased demand for subsurface instrumentation and electric or
hydraulic operated devices, a new type of hydraulic set packer has been
developed to fulfill the requirement for multiple conductors to pass through
the packer without compromising the packers integrity. The model ‘MPP’
hydraulic set packer is an example of this type of packer.

Hydrostatic Set
Hydraulic Packers

These packers utilizing a setting piston similar to differential set packers, but
all or part of the piston area is acting against a chamber containing atmospheric
pressure rather than annulus pressure. This allows the hydrostatic tubing
pressure to assist the setting of the packer. Less pressure is required to generate
a required force than with a hydraulic set Packer. This allows hydrostatic set
packers to have a larger mandrel size than hydraulic set packers
Hydrostatic set packers are more expensive to manufacture than the differential
set and are normally used when larger tubing sizes are required. For example, in
7" casing with 2 7/8 tubing, a differential set packer will work fine but if 3 ½”
tubing is required a hydrostatic packer would be used due to the reduced
piston area resulting from the larger packer mandrel.
The Hydro-8 single string (Fig 5-11) and the Hydro-10 dual string packers are
examples of hydrostatic set packers. The Hydro-8 is also available in a selective
set version as well. Selective setting allows several packers to be run in a
tubing string and each packer to be set independently of the others. The
setting mechanism in each packer is activated by wireline intervention.

Permanent Seal
Bore Packers

Description 

As the name implies, permanent seal bore packers are just that: permanent.
Once set they cannot be unset and if their removal is necessary it must be done
using milling equipment to cut the packer out. This is the main disadvantage of
this type of tool. However, this also allows for several features which are
advantages over retrievable packers.

•  incorporation of full 360º back-up on the packing element
•  elimination of complicated pressure equalizing systems and their

potential leak path

•  much greater slip coverage in the casing I.D.
•  easier and more economical to manufacture in high alloy materials

for hostile environment service

•  most models are suitable for high pressure application in wells of

any depth

•  allow use of larger tubing sizes

Seal bore packers are not designed to attach directly to the tubing as retrievable
packers are, but instead utilize a polished inside seal area into which a seal unit,
that is run as a part of the tubing string, seals into. This polished seal bore can
either be incorporated as a through bore in the packer or it can be incorporated
above the packer to accommodate larger inside seal diameters. Permanent seal
bore packers are run and set by one of the following three methods:

•  Application of hydraulic pressure to an integral setting mechanism
•  Application of hydraulic pressure to a separate recoverable and

reusable setting tool

•  Reusable wireline setting tool utilizing an explosive charge to

generate the setting force

Design

 Figure 5-14 illustrates a basic wireline set permanent seal bore packer showing
the main components of the packer in both the running and set positions.

Options

 Tubing-to-packer attachment and sealing in a seal bore packer is accomplished
using one of three basic seal assembly options.

•  Latched or No-Motion (Also known as an Anchor Seal)-

The tubing string is attached to the packer with a latching seal
assembly. The tubing is not free to move internally in the packer.
Forces on the tubing will be transmitted directly to the packer.
Such forces can result in failure of the top tubing joint (Fig 5-15).

•  Limited-motion (Landed)- The stinger is fitted with dynamic

seals and runs through the packers polished bore. This type of
seal assembly allows limited movement downward, and uses a nogo
diameter to prevent the seals from moving completely through
the packer bore. This is useful for situations where cooling of the
tubing string (injection of cold fluid) and allows contraction of the
string without placing excessive tension of the top joint (Fig 5-16).

•  Stung-through or Free-motion - This is useful in preventing

corkscrewing and tubing separations. The configuration is similar
to an expansion joint and provides some freedom of tubing
movement (Fig 5-17).


Applications

 Permanent seal bore packers are used in the following situations:

•  Medium or deep set applications
•  Deviated and extended reach wells
•  Multiple packer completions
•  Dual string completions with parallel flow tubes
•  Sump packer for gravel packer operations
•  Medium to high pressure application

Retrievable Seal
Bore Packers

Description

 Retrievable seal bore packers utilize a seal bore similar to the permanent seal
bore packers. Because they are designed to be retrievable most retrievable seal
bore packers have a lower pressure rating than permanent seal bore packers
and are generally more expensive. Retrievable seal bore packers are commonly
used in gravel pack operations as well as completions.
The retrievable seal bore packers utilize many of the same accessories such as
setting adapters, seal assemblies, etc. as the permanent packers. They also are
available in both wireline set versions and self contained hydraulic set versions.