ProTech1Ch6 PDF

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Completion Equipment
CONTENTS
1 PRODUCTION TUBING
1.1 Tubing Diameter
1.2 Tensile Strength
1.3 Internal Pressure
1.4 External Pressure
1.5 Corrosion
1.6 Coupling Types
1.7 Specification of Tubing
7 TUBING - ANNULUS CIRCULATION

EQUIPMENT
7.1 Sliding Side Door or Sliding Sleeve
7.2 Side Pocket Tubing Mandrel With Injection or
Shear Valve
SUMMARY
EXERCISE
2 WELLHEAD SYSTEMS
2.1 Conventional Spooled Wellheads
2.2 Compact Spool System
2.3 Mud Line Suspension System
3 XMAS TREE
4 PACKERS
4.1 Packer Applications
4.2 Basic Packer Components and Mechanics
4.3 Classification of Packers
4.4 Running and Setting Procedures
4.5 Permanent Packers
4.6 Retrievable Packers
4.7 Packer Selection
4.8 Packer/Tubing Seal or Connection Equiptment
4.8.1 Seal Requirements
4.8.2 Specification of the Seal Bore
4.8.3 Specification of Seal Assembly
4.9 Packer Tail-pipe System
4.10 Permanent Packer Retrieval Systems
5 WIRELINE NIPPLE AND MANDREL SYSTEMS
5.1 Selective Landing Nipple System
5.2 Non Selective Landing Nipples
5.3 Available Nipple/Mandrel Systems
5.4 Setting Mandrels Not Requiring a Nipple
Profile
5.5 Ancillary Equiptment For Nipples
6 SUB SURFACE SAFETY SYSTEMS
6.1 Direct Controlled Sub Surface Safety Valve
6.2 Remotely Controlled Sub Surface Safety
Valves
6.3 Injection Well Safety Valves
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Learning Objectives:
Having worked through this chapter the Student will be able to:
For each of the major completion components listed below, discuss and review the
main equipment options, advantages and disadvantages:
Tubing for production / injection
Wellheads
Xmas trees
Packers
Seal assemblies
Subsurface safety valves
Nipple profiles
Flow control and circulation devices
Specify metallurgy recommended for a range of operating condition.
Evaluate force balance across packers.
Select a packer for a design load condition.
1 PRODUCTION TUBING
The bulk of the completion string comprises threaded joints of tubing which are
coupled together. The integrity of the tubing is vital to the safe operation of a
production or injection well. The specification of a production tubing must be carried
out based upon the mechanical and hydraulic operating conditions envisaged, the
proposed operating environment and "life of well" considerations. The tubing must
be specified to provide the following capabilities:
(1) The inside diameter of the tubing must provide a produced fluid velocity to
minimise the total pressure loss as defined by the tubing performance relationship.
(2) The tensile strength of the string of made up tubing must be high enough to
allow suspension of all the joints to the production zone without tensile failure
occurring of any of the joints above.
(3) The completion string must be able to withstand high internal pressures as a
result of fluid flow entry into the tubing.
(4) The completion string must be able to withstand high external differential
pressures between the annulus and the tubing.
(5) The tubing must be resistant to chemical corrosion which may arise because of
fluid contact in the wellbore, and might ultimately accelerate string failure by
one of the loads and stresses mentioned above (2)-(4).
Each of the above facets of tubing selection are discussed below.
1.1 Tubing Diameter

Conventionally the outside diameter of the tubing is specified. The inside diameter
is defined by the wall thickness of the steel through the weight per feet of the tubing
(lbs/ft). The decision as to the wall thickness to be used will influence the tensile
strength of the steel as well as its resistance to failure with high internal or external
pressure differentials. The tubing is thus specified as being of a certain outside
diameter and of a specific weight/foot which thus specifies the wall thickness
e.g. 41/2" O.D. x 13.5 lbs/ft or, say, 7" O.D. x 26 lbs/ft.
1.2 Tensile Strength

The tensile load that can be tolerated by a joint of tubing without the occurrence of
failure is determined by the tensile strength of the steel specified for the tubing, the
wall thickness of the tubing (and hence the plain end area) and the tensile strength
of the threaded coupling. Normally the tensile load tolerable without failure of the
threaded coupling, greatly exceeds that of the tubing wall or pipe body itself.
There are several grades of steel considered as standards by the API, namely H-40, J55, C-75, L-80, N-80 and P-105. The numbers after the letter grading signify the
minimum yield strength in units of a thousand psi. The letter grades indicate the
manufacturing process or subsequent treatment of the steel to modify its properties,
Department of Petroleum Engineering, Heriot-Watt University
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e.g. the C and L grades are heat treated to remove martensitic steels which will thus
lower their susceptibility to H2S adsorption and subsequent sulphide stress cracking/
hydrogen embrittlement and consequent failure. Thus the C-75 and L-80 grades are
useful in some environments. In general the higher the yield strength created by
working the steel, the more susceptible it would be to embrittlement and failure, if it
comes into contact with even small H2S concentrations.
The minimum yield strength defines the minimum tensile strength in psi. However,
since the tensile load is taken by the plain end area or wall section area of the pipe, the
weight/foot of the pipe will also affect the tolerable tensile load. Since each joint
suspends the joint immediately beneath it, the design on the basis of tensile load will
require an increasing tensile strength in the joints nearest surface.
The other aspect of tensile strength, although normally not the limiting one, is the type
of threaded coupling. The threaded coupling provides a female connection at the top
of each joint which will mate with a pin or male screw connector at the base of the joint
immediately above it. The threaded coupling has to provide two basic functions;
firstly to transmit tensile load up the tubing string and secondly to produce a
connection which provides a seal to retain internal pressure within the tubing.
The design of a completion string to withstand a given tensile load will obviously be
dependent upon the depth to which the completion string will be run but the following
aspects will also be considered.
(a) The minimum tensile strength of the pipe utilised for the design will be based
upon the manufacturers data or API specification but will be reduced by the
application of a safety factor which will normally have a value in the range
of 1.6 to 2.0.
(b) The effect of tensile load on a suspended string will be to cause elongation of
the string with a subsequent reduction in the plain end area or wall thickness
and this will have to be taken into account when considering the possibility of
failure due to high external pressures by derating the nominal collapse resistance.
This is done by application of the Biaxial Stress Theorem.
1.3 Internal Pressure

Since the tubing string is designed to convey the fluids to surface it must be capable
of withstanding the anticipated internal pressures. However, it is not the magnitude
of internal pressure which is important but rather the magnitude of differential
pressure by which the internal exceeds the external pressure. This condition is referred
as burst and the limiting condition is usually encountered at surface where the
external pressure is at its minimum. The level of burst pressure to be tolerated is
normally defined on the assumption that the string is gas filled, i.e. the tubing head
pressure (T.H.P.) equals the reservoir pressure minus the hydrostatic head of gas in the
well.
In tubing design the A.P.I. figures are derated by a safety factor which varies from 1.0
to 1.33.
1.4 External Pressure

The burst condition referred to above is reversed if the external pressure exceeds the
internal pressure and this is defined as being a potential collapse condition. This
condition is prevalent at the position of maximum pressure on the outside of the tubing
in the annulus. Collapse is therefore most likely to occur deeper in the well.
In calculating the collapse condition the criteria for collapse are defined using the
published minimum collapse data with the application of a safety factor of 1.0 to 1.125
and derating the calculated values to account for tensile load.
1.5 Corrosion
There are two principal types of corrosion encountered in oil and gas production wells
namely:
(1) Acidic Corrosion - due to the presence of carbonic acid (from CO2), or organic
acids within the produced hydrocarbon fluid.
(2) Sulphide Stress Cracking/Hydrogen Embrittlement - due to the presence of
H2S in the flowing well fluids from the reservoir. H2S can also be generated
by the growth and subsequent action of sulphate reducing bacteria in stagnant
fluids, e.g. in the casing-tubing annulus.
Since most corrosion is selective, e.g. pitting, an even reduction in wall thickness due
to corrosion will not normally occur and no allowance on wall thickness can be made
initially to compensate for corrosion. Corrosion inhibitor treatments will assist in
minimising corrosion damage due to acidic compounds. For low partial pressures of
H2S, the procedure is to recommend a reasonably low grade steel since these are less
susceptible to embrittlement, e.g. C 75 or N-80.
1.6 Coupling Types

There are two general classes of threaded coupling:
(1) Connections which require internal pressure to produce a pressure tight seal API regular couplings.
This type of coupling includes the API round thread and buttress connection
whereby a thread compound applied to the threads must be compressed by external
pressure acting on the coupling causing it to fill any void spaces within the coupling.
(2) Metal to metal or elastomeric seal connection - Premium threads.
This class of coupling includes the Extreme Line as well as a range of specialised
couplings of specific commercial design, e.g. Hydril or VAM designs. The
couplings do not always utilise the threads to give the pressure seal but allow torque
to be applied to bring together seal shoulders or tapered surface within the coupling.
In other specialised couplings, resilient seal rings are also used to provide an
additional seal system.
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Coupling can also be classified as being Integral or External couplings. An external
coupling such as the VAM coupling shown in figure 1 below requires that a male
thread be cut on each end of the tubing joints and that a female: female coupling be
screwed onto one of the male threads. The external coupling features a larger effective
wall thickness in the coupling section giving it higher load capacity compared to an
integral coupling. The integral coupling as shown in figure 2 has a male and female
thread cut on opposite ends of the pipe.
An external upset coupling uses an increased wall thickness of pipe at one end of the
pipe allowing a female thread to be cut without sacrificing too much of the tensile load
carrying capacity. A flush joint is one in which there is a inform ID through the make
up connection. An internal upset coupling is one in which there is a small section of
increased ID in the coupling.
D
d
L4
NL
W
Wc
Figure 1
VAM Threaded Coupling
(external coupling)
D
d
Lm
Figure 2
Hydril Tubing Coupling
1.7 Specification of Tubing

The string is defined initially by the well productivity analysis which suggests the
optimum tubing ID based upon a range of available sizes. Frequently the completion
string will comprise lengths of several different diameter tubings, with the diameter
decreasing towards the bottom of the well. The use of larger diameter tubing higher
up the well may be useful to counter the increasing flow velocities as the fluid expands
and gas is liberated from solution as pressure declines up the tubing. The reduction
in tubing size in the lower sections of the well may be necessary because of limited
equipment availability and mechanical limitation, e.g. production liner inside diameter.
Once the size is specified, the design based upon the 3 mechanical conditions of
tension, burst and collapse is undertaken.
Ultimately the design will yield a specification for a string comprising one or more
types of tubing defined as follows:
Length
of tubing
- tubing
OD
e.g. 7000' - 51/2
- tubing - grade
- coupling - joint
wt/ft
of steel
type
length
- 23 lb/ft - C-75
- Hydril Super EU - Range 3
2 WELLHEAD SYSTEMS
Before describing the equipment options available for a wellhead, it is necessary to
define the functions of a wellhead.
The wellhead is the basis on which the well is constructed and tubulars suspended
during the drilling and completion operation. The wellhead serves three important
functions:
(a) Each of the casing strings which are run, cemented and have an extension to
surface or the seabed, as well as the production tubing string(s), are physically
suspended within the wellhead.
(b) The wellhead provides the capability of flanging up a device to control the flow
of fluid from or into the well. In the drilling phase, this flow control device is
known as a blowout preventer stack (B.O.P.) and this remains in place until the
production tubing string has been suspended in the well. Once the completion
string is in place, the B.O.P. is removed and the production flow control system,
known as the Xmas Tree, is installed on top of the wellhead.
(c) Each wellhead spool or landing area offers a flanged outlet allowing hydraulic
communication into that annulus.
In this section we will limit the discussion to wellheads utilised on offshore platforms
or on land based wells, i.e. for the time being subsea completions will be excluded.
There are 3 basic wellhead designs in frequent use, namely:
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(1) Conventional Spool System
(2) Compact Spool Systems
(3) Mud Line Suspension System
2.1 Conventional Spooled Wellheads

With this type of wellhead, the running of the conductor or surface string is performed
and, a casing head housing is either screwed or welded on to the top joint of casing.
The internal profile of the casing head housing provides a tapered seat from which the
next casing string to be run, will be suspended. To accomplish this suspension, a
hanger must be attached to the last joint of casing. The type of hanger known as a slip
hanger is a wrap around type consisting of a hinged pair of semi-circular clamps with
a tapered external profile which matches the tapered profile on the inside of the casing
head spool or housing. This type of hanger, e.g. the Cameron A.W. hanger is only
suitable for low to intermediate suspended weight. The alternative hanger is one
which is circular with a tapered external profile but it is coupled to the top casing joint
with a screw thread. This type of hanger is usually referred to as a boll-weevil hanger.
Subsequently, to accommodate sequentially each string of casing, a casing head spool
has to be added to the wellhead to suspend the next string of casing to be run. The
spools are either flanged or clamped together. Finally, prior to running the production
tubing string, a spool known as the tubing head spool is added to the top of the upper
casing head spool.
Since the annulus for each casing string must have no communication with any other
annulus nor to atmosphere, it is imperative that the wellhead provide an effective
pressure sealing system. The pressure sealing is achieved by creating pressure
isolation by at least two of the following for each possible annulus or potential leakage
area:
(1) The creation of a pressure seal between flanges so that if annular pressure exists
it cannot escape from the wellhead. This is accomplished by the use of so called
ring gaskets.
(2) The creation of a seal area either above or within the hanger on the tapered
shoulder.
(3) If the casing projects into the base of the next casing head then a seal ring system
will provide isolation in the contact area between the extended neck of the
casing and the internal profile in the base of the spool.
The ring gaskets are constructed of metal and are laid into a recess on the flange faces.
As the flanges are bolted together, the gasket is compressed and the seal effected.
Various types of ring gasket exist, each type having a specific cross sectional shape.
Gaskets exist for regular applications with a low to intermediate pressure sealing
capability - the API R ring joint gasket, to the API type BX gasket for high
pressure wellheads.
The system of sealing in the other wellhead areas, e.g. on the hanger seal, can be
accomplished by the compression of a rubber element or by plastic injection into the
seal area.
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Ring gasket seal

Casing head spool
Casing hanger
Side outlet
Casing head housing
Figure 3a (left)
Wellhead
Figure 3b (right)
Simple Wellhead Assembly
including Casing Spools
and Xmas Tree
2.2 Compact Spool System

A disadvantage of the conventional wellhead is that for a spool to be installed at each
stage of the well, the B.O.P. stack has to be removed and this is potentially hazardous
for the safety of the well if ineffective primary cement job has been conducted,
particularly in the lower sections of the well where zones containing hydrocarbons
may be encountered at high pressure.
Most wellhead companies also offer a one piece spool which will provide the hangoff areas for the suspension of say the last 2 casing strings, e.g. 1 intermediate casing
string and the production casing string, as well as the production tubing string.
Assuming that a 30" conductor has been set, the 26" hole would be drilled and
subsequently the 20" casing run into the well and cemented. A casing head housing
attached to the top joint of 20" casing provides internally the hang-off shoulder for the
next casing, i.e. the 133/8" casing. Once the 133/8" casing is landed off and cemented,
the compact spool can be flanged up on top of the 20" casing head housing the B.O.P.
nippled up to the top of the compact spool. The compact spool thereafter provides the
facilities to suspend either a 95/8" intermediate casing, a 75/8" production casing and
the production tubing or alternatively if a production liner is run through the pay zone
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and not tied back to surface, a spacer/seal system is installed between the 95/8" casing
hanger and the tubing hanger.
A complex system of sealing is employed as follows:
(1) A ring gasket is located on the flange face between the compact spool and the
20" casing head housing.
(2) The 133/8" hanger has seal rings both on the tapered seat which locates in the
20" casing head housing and on the extended neck of the hanger which locates
in the base of the compact spool.
(3) Sealing is provided around the neck of the hangers within the spool by the
injection of plastic.
(4) The tubing hanger also has seals both at the base of the hanger as well as on the
extended neck which projects out of the compact spool.
During production there will be a gradual warm up of all casing strings but the
possibility of this either:
(1) causing mechanical damage, or
(2) causing failure of a seal system
is minimised since the suspended weight of the subsequent casing is landed on top.
However, the tubing hanger has no such weight to prevent upwards movement and
would be held in place by the equipment bolted on top of the wellhead if it were not
for tie down bolts. These bolts are screwed in from the wellhead body until they
contact the upper tapered shoulder on the hanger thus preventing its upward
movement.
The compact spool is the terminology used by Cameron to market their version of
this wellhead whilst FMC describe their system as a UNIHEAD.
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Xmas tree
Tubing hanger
Adaptor spool
Spacer spool to compensate

for abence of 7" / 7 5/8"
tie break
Compact spool
9 5/8" casing hanger

13 3/8" casing hanger
20" casing head housing
36" conductor
20"
13 3/8
9 5/8
Figure 4
Compact spool with xmas
tree in place.
Production tubing
2.3 Mud Line Suspension System

In this system the wellhead is built up on the sea bed but the production well will be
completed back to the platform or production well jacket. Thus although the well will
be controlled above sea level hence requiring its completion back to that point, the
weight of the suspended casing strings cannot be transmitted to the jacket or platform.
The two facilities required of the wellhead are therefore separated positionally in that:
(a) a wellhead built up on the seabed will be used to suspend casing strings
(b) in addition each casing will have an extension string from the seabed wellhead
to a subsidiary wellhead at the platform where the BOP and subsequently the
Xmas Tree will be attached.
If the well is to be completed then it can be done so either with a sea bed Xmas Tree
or alternatively if a small jacket is used, above sea level. If the well is completed with
a jacket then a single Xmas Tree can be installed. However, if the well is to be
completed at sea bed, then the casing extensions can be removed using the running
tools and retrieved. The Xmas Tree would then be clamped on to the extended neck
of the 7" casing.
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Alternatively, if the well is to be suspended temporarily, it can be capped after
retrieving the casing string extensions from the mudline.
3. XMAS TREE
The Xmas Tree is the production flow control system and it is a system of valves which
control physical or hydraulic access into the tubing string or the annulus between the
production casing and tubing string (often termed the A-annulus). The access
capabilities required are as follows:
(a) A capability to inject into or produce from the production tubing - access is
provided through the flow wing valve or kill line valve.
(b) A capability to lower into the production tubing a wireline service tool string
- the vertical access is provided through the swab value.
(c) A capability to completely close off the well.
The simplest type of Xmas Tree utilises a series of valves connected to each leg of a
cross piece. Refer to figure 3(b). The valve located between the cross piece and the
wellhead is referred to as the master gate valve and in the majority of modern well
completions, especially on platforms, this valve is duplicated by the installation of one
manually controlled valve and a remotely controlled valve (usually hydraulically). In
addition whilst the swab valve, ie the valve at the top of the tree remains manually
operated the flow wing valve for production is usually also remotely operated from a
separate control room. In some instances the kill wing valves have also been installed
as remote valves.
The cross piece Xmas Tree possesses one major disadvantage and that is that it
contains a large number of flanges and hence a significantly increased possibility of
leakage.
An alternative design of tree utilises a solid block construction of a yoke piece
configuration. Figure 4. This type of tree allows overhauls to replace faulty valves or
actuators.
Normally the Xmas Tree is connected by a flange or clamp to the top of the wellhead
but because of incompatibility in flange sizes, an adaptor spool may be required to
reduce the top flange diameter to accept the Xmas Tree. In such cases pressure sealing
between the flanges is provided by ring gaskets. Pressure isolation internally is
achieved by sealing between the tubing hanger and the internal bore of the Xmas Tree,
adaptor flange and wellhead using elastomer seal rings.
4 PACKERS
A packer provides physical isolation of the casing/tubing(s) annulus above the
production zone.
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4.1 Packer Applications

Packers are an essential piece of completion equipment in a large number of wells.
The reasons for their use varies from well safety considerations to production flow
stability.
Some of the more common reasons for using packers are outlined below:
(1) Well Protection
Since the packer isolates the casing/tubing annulus above the production zone, it is
designed to prevent the formation fluids communicating up the annulus and provides:
(a) Corrosion Protection - contact of well fluids containing H2S, CO2 or organic
acids with the casing and outside wall of the tubing is prevented.
(b) Abrasion Protection - since no flow occurs up the annulus, abrasion due to
solids such as sand entrained within the produced fluids is prevented.
(c) Casing/Wellhead Burst Protection - the elimination of reservoir pressure
communication prevents the generation of high annular casing pressures at
surface. e.g. In a gas well where the liquid in the annulus unloads and gas then
fills the annulus and exerts a casing head pressure.
(2) Production Stability
In oil wells producing from a reservoir with a solution gas drive reservoir or where the
bubble point is reached close to the perforation, the flow of a 2 phase mixture into the
tubing string can lead to gas segregation and its accumulation in the annulus where
its volume will gradually increase until it offloads by U-tubing up the production
tubing. This phenomenon is known as an "annulus heading cycle.
(3) Zonal Isolation
In wells designed to produce either up a single tubing string completed selectively
over several zones or where a tubing string is provided for each zone, a packer is
required to isolate between each zone to prevent comingling of production or interzone fluid flow.
(4) Annulus to Tubing Injection e.g. gas lift wells
In a variety of completions, fluids are injected into the annulus and the completion
string is designed to allow these fluids to enter the tubing string at specific depths and
at a certain flowrate. The types of fluid injected can be chemicals such as corrosion
inhibitors or pour point depressants but very commonly it is gas injected to assist in
the vertical lift process. In such cases, the use of a packer prevents the fluid merely
U-tubing at an uncontrolled rate via the bottom of the tubing which would lead to
ineffective production of hydrocarbon.
(5) Injection Operations
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In injection operations such as water or gas reinjection, or stimulation operations such
as fracturing, the use of high surface pressures is necessary either to generate an
economic injection rate or to exceed the fracture initiation pressure. Without the use
of a packer, these pressures would be communicated up the annulus and might cause
concern regarding the burst criteria for the casing/wellhead.
(6) Temporary Isolation
In some cases it is necessary to provide some degree of protection across the
production zone to prevent the loss of fluid into the reservoir from a higher density
fluid in the wellbore during workover operations and well closures. In such cases
running a bridge plug - a type of full bore packer capable of being run down through
the tubing, and setting it just above the perforations would provide zonal isolation and
protection.
4.2 Basic Packer Components and Mechanics

A typical packer figure 5 comprises the following components:
(a) Sealing Element(s)
The isolation of the annulus is normally provided by the extrusion of the sealing
element by some form of axial compression, such that it fills the annulus at the packer
between the completion string and the casing. The sealing element consists of one or
more rings of elastomer or combination of elastomers. Obviously the material of
construction of the sealing element must be able to withstand the anticipated
conditions in the wellbore with regard to pressure, temperature and chemical composition of the fluids likely to exist in the wellbore. For example, in H2S or CO2
conditions, Teflon or Viton seals would be specified.
Baker packers usually utilise a single element whilst Otis packers frequently use a
system of 3 elements.
Since the element is exposed to high pressures and temperatures for all its service life
in the extruded state, it will suffer degradation. The Otis-favoured system of 3 sealing
elements is designed such that the upper and lower seal rings are of a harder
composition and are thus able to restrict the extrusion of the centre element. The softer
central element will seal on any surface imperfections.
In addition, to provide a mechanical barrier to prevent excessive extrusion and hence
element failure, most packers, with a long anticipated service life, utilise a metal back
up system to the packer elements. Baker use a series of back up rings whilst Otis
packers incorporate a top and bottom back up shoe.
(b) Slip System
The system of slips comprise a set of mechanical latch keys which are located either
above or below, or both above and below the sealing element. The purpose of the slips
is to support the packer during the setting operation and subsequently, in some cases,
to prevent the unplanned reversal of the element extrusion process. The slips act by
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being forced into contact with the inside wall of the casing and the serrations on the
surface of the dog segments, dig into the casing wall. The packer may be required to
support some of the slackened off tubing weight onto the inside wall of the casing.
(c) Setting and Release Mechanism
The packer can either be set independent to the completion string or as an integral part
of the string. Since it will be desired to set the packer at a specified depth, it is
necessary to be able to control the actuation of the setting mechanism only when
required.
Similarly, the release of the packer has to be actuated as required.
(d) Hold Down Buttons
During production operations variation in bottomhole pressure beneath the packer can
lead to significant changes in the differential pressure exerted across the packer i.e. the
differential between the pressure beneath the packer and pressure in the annulus above
the packer. Some designs of packer incorporate a feature known as hydraulic hold
down buttons whereby the pressure in the packer bore is used to force a set of
additional slips outwards onto the inside wall of the casing, thus preventing any
vertical upwards movement of the packer i.e. particularly where high bottomhole
pressures may exist such as in injection wells.
Upper Seal
Sealing Element
Bypass
Upper Cone
Slips
Lower Cone
Left - Hand
Screw Head
Inner Mandrel
Friction Blocks
Upper Split Nut

Lower Split Nut
Figure 5
Components of a Typical
Packer
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4.3 Classification of Packers
The primary method of classifying packers is with regard to their permanency in the
hole,i.e. whether the packer is retrievable or permanent. The retrievable packer, as
the name suggests, can be unset and pulled from inside the casing normally by
manipulation which allows the reversal of the setting process to take place. A
permanent packer figure 6 is designed to remain in the hole and although it can be
pulled from the hole, the retrieval process is not simply the reverse of the setting
procedure.
The second characteristic of a production packer is the stress state of the completion
string, i.e. whether it is set in tension, compression or in a neutral state. This stress
state could apply at the time of setting but subsequent pressure and temperature effects
during production could cause a significant change in the stress state.
A third characteristic of packers is the nature of the setting mechanism which is used
to compress the sealing element system. A number of options are available, namely:
Drag Springs
Slips
Upper system
Cone
Cone
Lower system
Slips
Figure 6
Permanent Packer
4.4 Running and Setting Procedures

The variety of methods available for providing the setting mechanism for the seal
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elements of a packer, leads to a significant number of options for installing and

completing a well.
Consider firstly therefore the setting methods for packers.
I. Setting Methods for Packers
Each of the possible methods for setting a packer are outlined below:
(a) Weight-Set or Compression Set Packers figure 7
This type of packer can either be set independently or can be run in as an integral part
of a tubing string and set when the string is landed off.
Normally weight set packers utilise a slip and cone assembly which can be actuated
to supply the compression of the seal element, once the drag springs or friction blocks
can engage the inside wall of the casing. The means to release the slips is usually
obtained using a J slot device which upon activation allows string weight to be
slackened off and thus compress the sealing element. Release of the element can be
obtained by picking up string weight.
This type of packer setting mechanism will only be suitable if weight can be applied
at the packer which may not be the case in highly inclined wells. In addition the packer
will unseat if a high pressure differential exists from below the packer.
(b) Tension Set Packers
This type of packer is effectively a weight set packer run upside down, i.e. the slip and
cone system are located above the sealing element. They are particularly useful for
applications where a high bottomhole pressure and thus a differential pressure from
below the packer exists. This situation occurs in water injection wells, where the
injection pressure will assist in maintaining the packer set. Care should be taken to
ensure that any temperature increase in the string and consequent string expansion will
not provide a force capable of unseating the packer.
(c) Roto-Mechanical Set Packers
In this type of packer, the packer setting mechanism is actuated by tubing rotation. The
rotation of the string either (a) forces the cones to slide behind the slip and thus
compress the seal, or (b) releases the inner mandrel such that tubing weight can then
act upon the cones to compress the sealing element.
17
Figure 7
Mechanically Set
Compression Packer
Figure 8
Mechanically Set Tension
and Compression Packer
Figure 9
Hydraulically Set
Compression Packer
Figure 10
Permanent Packer
18
(d) Hydraulic-Set Packers figure 9

In this type of packer, hydraulic pressure generated within the string is used to either:
(1) drive a piston to effect movement of the slip and cone system thus comprising
the seal element, or alternatively
(2) actuate a set of upper slips in the packer which will then fix the packer position
and allow tension to be pulled on the packer and compress the seal system.
In the former arrangement, once the hydraulically driven piston has actuated movement
of the cone, return movement of the cone must be prevented by a mechanical lock
device.
To allow the hydraulic pressure to be generated in the tubing prior to the setting of the
packer, 3 main techniques are available for plugging the tubing:
(1) The installation of a blanking plug such as a Baker BFC plug inside an
appropriate nipple such as the Baker BFC seating nipple.
(2) The use of an expendable seat into which a ball can be dropped down the
tubing string. Upon applying overpressure after setting the packer, the ball
and seat shears out and drops into the well sump. An alternative design
features an expandable collet which will move down and expand into a recess
once overpressure shears the pins, thus allowing the ball to pass through.
(3) The use of a differential displacing sub, which allows the tubing fluid to be
displaced through ports on the sub prior to setting the packer. The ball when
dropped, will seat on an expandable collet which will allow pressure to be
generated. Once over pressure is applied the collet moves downwards and
in so doing, closes the circulation valve and allows the ball to drop through.
(e) Electric Wireline Setting Packers
In this system, a special adaptor kit is connected to the packer, with or without the
tailpipe, and the system is run into the well on the wireline with a depth correlation
instrument such as the casing collar locator C.C.L. At the setting depth, an electrical
signal transmitted down the cable ignites a slow burning explosive charge located in
the setting tool which gradually builds up gas pressure and actuates a movement of a
piston to compress the seal system.
This type of system leads to more accurate setting depth definition for a packer plus
a fairly fast setting/installation procedure. The disadvantages are the difficulty of
running wireline in high angle wells and the fact that the packer must be set separately
from the subsequent installation of the tubing.
19
1
II. Running Options for Packers
Packers can be run in any of the following ways:
Setting Piston
Setting Ball
Setting Seat
Setting Sleeve
Shear Sleeve
Locator
Seal Assembly
Seal Guide
Figure 11
Hydraulic Setting Tool with
Setting-Shear Sleeve and
Type WB Packer
20
(a) As an integral part of the completion string using a hydraulic compression/

tension weight set or roto-mechanical setting procedures. This usually provides
the most direct method of installing a completion but requires the applicability
of tubing manipulation or hydraulic setting. Figures 11 and 12.
(b) The packer being preset in the wellbore and the entire tubing string being
subsequently run in through the bore of the packer or to latch into the top of the
packer. This option allows the use of the wireline setting option.
(c) The packer with the lower tubing section or tailpipe suspended below it is run
into the well and set on a workstring or with electric wireline. Figure 13. The
rest of the tubing string is then run down to seal into the packer bore or to seal
and latch into the top of the packer.
Upward pull of
tubing releases
packer
Hold - down
buttons
activated by
zone pressure
By pass
Shear Pin for

releasing packer
to set position
Large OD guide
Figure 12
Hydraulically set
retrievable packer using
ball and seat assembly and
incorporating hydraulic
hold down buttons.
Internal slips
to hold packer
in set position
Shear Pin for

releasing packer
to retrieving position
Sealing ball
Schematic 1
"Running - In"
Schematic 2
"Set -Position"
Schematic 3
"Retrieving
-Position"
21
1
Cross-Link Sleeve
Firing Head
Setting Mandrel
Adjusting Nut
Vent for
Pressurised Gas
Pressure Chamber
Power Charge
Adaptor Sleeve
Manual Bleeder Valve

Body
Emergency Vent for
Pressurised Gas
Release Stud
Floating Piston
Upper Cylinder
Release Sleeve
Cylinder Connector
Piston
Mandrel
Setting Sleeve
Packer Body
Mandrel Guide
Piston Rod
Lower Cylinder
Cylinder Head
Vent for Compressed Air
Cross-Link
Cross-Link Sleeve
Setting Mandrel
4.5 Permanent Packers

Permanent packers are thus described because their design permits the sealing
elements, once extruded onto the inside of the casing wall, to be mechanically locked
in place. This is accomplished by having two opposing sets of mechanical slips, one
located below and the other above the sealing element. Thus the packer is designed
to create an effective seal independent of any subsequent changes in wellbore
conditions following the completion operation. Permanent packers can be set by any
of the following methods:
(1) Electric wireline set.
(2) Run on tubing/drillpipe and set by mechanical manipulation - rotation.
(3) Run on tubing and set by internal hydraulic pressure.
Permanent packers do find wide application in a variety of well completions and their
22
Figure 13
(a) Wireline Pressure
Settiing Assembly
(b) Wireline Adaptor Kit
installed in Retainer
Production Packer
application is highly suited to deep, high pressure wells and in wells where there is
likely to be significant forces acting, as a result of well conditions, to unseat the packer.
Conversely, permanent packers provide effective annulus isolation by being designed
for permanent installation and are therefore difficult to retrieve from the well.
A wide range of permanent packers are available for use with wireline, mechanical
and hydraulic setting operations.
One of the earlier designs of permanent production packer the Baker Model D which
is frequently set using electrical conductor wireline but can also be set on tubing or
drill pipe. It features two opposing sets of full circular slips and the element is
prevented from over extrusion by metal back up rings. The bore of the packer is
smooth throughout its length to provide a long sealing area. The Baker Model DA is
of similar design to the Model-D but offers a larger seal bore at the top of the packer.
Upper slip and cone

Sealing element
Lower slip and cone
Figure 14
Baker model D packer
The Baker Model F packer offers a larger bore but is still based upon the Model D
packer and offers the same mechanical design features. Similarly, the Model FA
packer offers the larger bore of the Model-F with an increased seal bore capability at
the top of the packer. Again the Models F and FA packers are designed for mechanical
setting or setting using an electric wireline system. The hydraulic setting option is
offered by the Baker Model SB-3, which is of similar mechanical construction to the
Baker Model-D packers. The packer is run on a shear release assembly which after
setting will act as the retrievable setting system. The packer will set with a tubing
pressure of 2500 psi which is generated against a ball dropped down the string onto
a shear out seat assembly at the bottom of the packer. The SB-3 is designed to
withstand differential pressures up to 10,000 psi. Hydraulically set versions of the DA
and FA Baker packers are also available known as the Model SAB packers but these
are run on a K-22 anchor seal assembly.
The Baker Model-N packer is a mechanically set packer which is run and set with a
Roto-Set seal assembly. The packer is run to the setting depth, and, using right hand
rotation, release of the upper slips is achieved. Pulling upwards with 20000-30000 lbs
pull will achieve the setting of the element and the lower slips. Release and retrieval
of the roto set seal assembly is achieved using right hand rotation and upwards pull.
23
1
An alternative range of permanent packers is available from Halliburton and referred
to as the Perma-Drill range figure 15. The Perma drill packers are available for
wireline setting (type WB), for tubing setting (type TB) and for hydraulic setting (type
(HB). The tubing set version uses a rotational setting tool. For the hydraulic setting
system, a ball is dropped onto a seat or a plug placed in a nipple beneath the packer
allowing pressure to be built up to the 2000 psi required to set the packer. The Perma
Drill utilises 3 seal elements with metal back up shoes above and below the element.
In addition, a J-latch receiving head is available for connecting seal units.
Several other vendors offer a competitive range of permanent packers.
4.6 Retrievable Packers

Retrievable packers are normally set using either a mechanical setting mechanism or
a hydraulic system whereby the packer is usually run as a part of the completion string.
A limited number of packers are available for wireline. An example of the later is the
RETRIEVA - range of packers produced by Baker. The range features Models D, A
and B and are largely based upon the principle of using an opposing pair of slips to
prevent upwards or downwards movement of the packer. The packer is usually
retrieved by a straight pull on the tubing.
The Baker Model R-3 is a compression set packer which features a set of lower slips
beneath the 3 element seal system and optionally an upper set of hydraulic hold down
buttons (double grip or single grip systems). It has application for a range of
production wells where low to moderate bottomhole pressures can be anticipated. The
packer is set by pulling up at the setting depth, applying right hand rotation and
slackening off weight. Retrieval requires only an upwards pull to unseat the packer.
The Lok-Set range of packers (Baker) use a system of slips to oppose upwards and
downwards movement and these are located beneath the 3 element sealing system.
The packer is claimed to have application for withstanding differential pressures in
either direction and does not use hydraulic holddown. The packer is run on tubing to
the setting depth and set by rotation. In sequence, the packer requires 6000 lbs setdown
weight with rotation to release and set the upper slips, followed by 10-12000 lbs to
release lower slips and finally 6-10000 lbs to lock the seal element. To release and
retrieve the packer requires upstrain and right hand rotation.
A simple compression set packer is provided by the Model G (Baker). To set the
packer, it is run down to 1 ft below the setting depth, picked up to the setting point and
after 1/4 turn right hand rotation, the weight is slackened off. To retrieve the packer
requires only an upwards pull.
Hydraulic set retrievable packers offer a very useful facility since they allow
flexibility and simplicity in completion operations particularly in deviated wells
where mechanical reciprocation may be ineffective and undesirable. The Baker FH
hydrostatic packer is run as an integral part of the tubing string and is set by pressure
generated within the tubing against a ball and seat sub or a plug located in a nipple.
Normally 1000 psi pressure above the annulus pressure will shear the screws and
actuate the hydraulic setting mechanism although this can be increased to 2000 psi if
required. The ball and seat sub will be set to shear at 3500 psi in the event of the higher
24
setting pressure being used. The packer is normally unseated by applying an upwards
pull in excess of 30000 lbs.
Like Baker, Halliburton also offer a range of retrievable packers. The Otis Permatrieve is designed to offer a similar capability to a permanent packer with the provision
of a slip system both above and below the 3 element seal system. The Perma-trieve
can be run and set on electric wireline, hydraulic or on tubing with rotation. The
retrieval of the packer can be accomplished without milling using either tubing or non
electric wireline. The opposing slip principle gives the packer the ability to withstand
high differential pressures from above or below.
Halliburton also offer a hook-wall packer which is retrievable with or without
hydraulic hold down button, types MH-2 and MO-2 respectively. Both packers are
designed to be run and set on tubing. The packer is run to the setting depth, picked
up, rotated 1/3 turn to the right and setting down 8000 lbs weight. Retrieval requires
a straight upwards pull to unseat the packer. The type MH-2, with the hold down
buttons, will be suitable where differential pressures exist from above or below the
packer, i.e. if higher pressure exists in the annulus then it will support the weight set
mechanism. However if higher pressure exists below, it will actuate the hold down
button.
Hydraulic set retrievable packers are also available as single string (type RH), dual
string (type RDH) and triple string (type RTH) from Halliburton. These packers
utilise a set of slips below the 3 ring sealing element with hydraulic hold down buttons
above it. These packers are set with a differential pressure in the tubing which can be
preset to between 800-3500 psi and are released by an upward pull.
Several other vendors offer a competitive range of retrievable packers.
4.7 Packer Selection

All the major completion equipment suppliers offer packers for comparable applications and if the product is established it will no doubt have been field proven. The
choice of packer will primarily be dependent upon the application and operating
conditions envisaged. Aspects to be considered include:
(1) Casing size, tubing size.
(2) Depth of well and anticipated bottom hole pressure both during completion and
in production with maximum drawdown.
(3) Annular fluid type and magnitude of pressure differential.
(4) The extent of thermal stress on the tubing and the potential forces which could
thus be generated on the packer.
(5) Whether tubing retrieval without the packer would be a useful facility.
(6) The bore offered by the packer and the restriction thus created for running
wireline be low the packer or the increased flowing pressure loss which could
occur.
25
1
(7) Completion string equipment compatibility.
(8) The deviation angle for the hole will influence any setting mechanism utilising
tubing manipulation or electric wireline.
(9) The design, length and hence the weight of the tailpipe might negate the use of
electric wireline to set the packer because of weight limitations.
Schematic 1
Schematic 2
Schematic 3
Schematic 4
Schematic 5
Electric
Wireline
Set
Hydraulic
Set
Rotation
Set
Releasing
Retrieving
4.8 Packer/Tubing Seal or Connection Equipment

In all cases where the packer is not run as an integral part of the completion string
assembled at surface, it is subsequently necessary to seal and optionally latch the
completion string into the bore of the packer. The integrity of the seal system is
fundamental to the effectiveness of the packer to isolate the annular space. The
simplest type of seal system is one where the bore of the packer alone will provide the
only internal seal surface and into which will be inserted on the base of the tubing, a
tube which has a series of seal rings located around its outside diameter.
4.8.1 Seal requirements

The seals arranged on the outside of the tubing seal have to be specified with respect
to:
(1) Geometrical Seal Design
Some designs utilise a seal ring whilst others utilise a Chevron Seal System. The
26
Figure 15
Different scenarios using
the permatrieve packer
system.
Chevron type packing consists of a series of directionally actuated seal rings mounted
in opposing directions such that differential pressure acting across the seal area will
cause the Chevron seal ring to deflect outwards to fill the gap between the seal bore
and the seal tube.
(2) Chemical Composition of Seals
The composition of the seals must be specified to ensure that it is resistant to any
chemicals in the wellbore, e.g. H2S, CO2 or other corrosive materials. A standard seal
material is nitrile rubber but a range of materials are available for more corrosive
service such as viton. Figure 16. The seals are usually spaced out along the length of
the seal tube. A standard seal stack consists of a series of seal rings of the same
material. A premium seal stack consists of a series of different types of seal rings e.g.
it may consist of elastomeric rings separated by metal and/or teflon back up rings.
Figure 17.
Rubbers
HARDNESS SCALES
70
80
90 95
45
DUROMETER A
55
65
75
PHENOLICS
60
ACRYLIC
50
NYLON
40
POLTSYRENES
30
POLYPROPYLENES
20
FLUROCARBON
Plastics
DUROMETER B
Figure 16
Hardness of elastomers and
plastics
Figure 17
Premium seal stack
elastomer combinations
RUBBER
BAND
INNER
TUBE
AUTO
TYRE
TREAD
50
90
110
130
150
ROCKWELL R
KTR
RTR
VTR
KALREZ
RYTON
VITON
TEFLON
TEFLON
TEFLON
RYTON
RYTON
RYTON
KTR SEAL
BREAKDOWN
(3) Length of Seal System

Once the seal is located within the packer bore, any expansion or contraction of the
tubing will lead to movement of the seal system within the seal bore. To maintain an
effective seal under all conditions, adequate length of seals must be provided. In
addition, under certain circumstances it may be preferable to increase the seal bore
27
1
length such that the available length of sealing is increased and the possibility of
leakage reduced.
To design a sealing assembly, the maximum contraction and expansion must be
defined so that the envisaged tubing travel can be compensated for. This will result
in the specification not only of the type of seal rings but also:
(1) the length and arrangement of the seal bore
(2) the type of seal assembly which will be utilised to seal the tubing to the packer system.
4.8.2 Specification of the seal bore

The diameter and length of seal bore is highly dependent upon the type of packer
selected as well as the casing size in which the packer is designed to be set. It is
preferable to maximise the seal bore to reduce any potential restriction to flow but this
also leads to an increased circumferential seal length.
Frequently, however, to increase the length of seal area and hence minimise the
possibility of seal failure, a seal bore extension is coupled direct to the bore of the
packer. This is accomplished by fitting a B-guide (Baker or similar) directly to the
bottom of the packer which offers a box thread for the coupling up of the seal bore
extension. If a retrievable packer is used or permanent packer which will not be
retrieved using the milling tool/catch system, the seal bore extension will be coupled
directly to the base of the packer. However, if the permanent packer is to be retrieved
using the packer milling tool, then a millout extension is located directly below the
packer and the seal bore extension beneath that.
4.8.3 Specification of Seal Assembly
Locator
Shoulder
Anchor
Lock
Seal
Stack
Seal
Stack
(a)
(b)
The simplest tubing seal assemblies can be supplied with either:

(1) a seal system only in which case they are referred to as locator tubing seal
assembly, figure 18(a).
28
Figure 18
(a) Locator sub - tubing
seal assembly and (b)
anchor sub-tubing seal
assembly
(2) a seal system with a mechanical latch above it which will engage in the upper
bore of the packer, an anchor tubing seal assembly figure 18(b).
Both offer a variable length for the seal system and its configuration to suit a specific
seal bore layout by adding additional seal element sections which are coupled
together. Figure 19.
Figure 19
Spacer and locator, anchor
seal system
Locator
Anchor
Tubing Seal Tubing Seal
Assembly
Assembly
Spacer
Locator
Seal
Spacer Seal
Assembly
Assembly
The design of the seals to resist corrosion is primarily accomplished by specifying the
seal material, however, solids deposition on the seals and sealbore, can damage the
seal integrity and thus a barrier must be fitted to stop solids deposition in the seal
system.
An alternative type of seal system is one which attaches to the top of the packer and
consists of a seal receptacle which offers an internal seal bore and a seal assembly.
One such system offered by Baker is known as an extra long tubing seal receptacle
ELTSR and is designed for use where significant tubing movement is expected. The
ELTSR consists of two concentric sleeves; the inner pin points upwards and is latched
into the top of the packer using an anchor seal assembly and an outer receptacle, which
is built up from a series of segments containing internal seal rings. The facility exists
at the top of the slick joint to instal a model-F seating nipple to accept a wireline plug
for isolation. In the running position, the slick joint and seal receptacle are in the
closed position and connected by a J slot. The ELTSR is run down, stabbed into the
packer bore and after unlatching the J-slot the seal receptacle is pulled back to space
29
1
out the completion tubing. The spacing out is designed such that at maximum
expansion the seal receptacle will not bottom out on the packer and for maximum
contraction it will not be pulled off the top of the slick joint. The J slot can be specified
to provide either right hand or left hand rotational release. The system is retrieved by
initially pulling back the seal receptacle on the base of the tubing string and then
running a slick joint retrieval tool with a J slot which runs over the slick joint, engages
with a J slot and after pulling upwards with rotation, the anchor seal assembly backs
out.
Shear Pins
J-Latch Lug
Sealing Elements
Impact Ring
Outer Mandrel
Inner Mandrel
Figure 20
Tubing Travel Joint
An alternative system is the Baker Expanda joint shear release system which is similar
to the ELTSR except that :
(1) the seal rings are located on the pin or slick joint assembly and hence the outer
seal receptacle offers the internal seal bore
30
(2) the slick joint and seal receptacle can both be retrieved with the tubing for seal
inspection and replacement.
An alternative system supplied by Halliburton known as the Travel Joint figure 21
effectively uses the same principle of two concentric sleeves as exists on the ELSTR
but the seal receptacle is attached to the packer and points upwards, whilst the seal
assembly is located on the downwards slick joint. The joints are normally run in the
fully closed position and released to accommodate travel when they are in position by
setting down tubing weight and disengaging the sleeves with wireline or with a shear
pin release system. To retrieve the travel joint, tubing weight is slackened off, a J-slot
is engaged and the system pulled from the wellbore. Travel joints are available in
multiple units of 10 ft.
Two systems giving very limited movement of 1-2 ft are available and these are the
telescoping keyed joint and the telescoping swivel joint.
31
1
4.9 Packer tail-pipe system
Perforater
Prod.
Lead-In
Sub
Knock-Out
Plug
Packer
Seal
Nipple
Locator
Sub
Latch-In
Sub
The tailpipe suspended beneath the packer performs a number of functions:

(1) Provides an entry flow path for produced fluids into the tubing.
(2) Provides a nipple capability for plugging the tubes beneath the packer.
32
Figure 21
Seal, packer and tailpipe
assembly option
(3) Provides a nipple capability for landing off pressure and temperature gauge
systems for monitoring flow.
(4) Provides a millout extension as a latch area for packer retrieval operations.
(5) Provides additional seal bore length.
(6) Allows for easy re-entry of wireline tools back into the tubing.
Working from the bottom up, a wireline entry guide or mule shoe is normally located
at the base of the tailpipe. This has a funnel guide so that wireline tools being pulled
back into the tubing are properly aligned. Above the WEG is normally located a
seating nipple which will accept the landing off and mechanical latching of a gauge
system run on wireline. Above the lower nipple, a perforated flow tube provides
maximum flow area for fluid entry thus: (i) preventing turbulence and potential tool
damage at the WEG, and (ii) entry for fluid if the lower nipple is plugged by a gauge.
Above the perforated flow tube is located a nipple for the pressure isolation of the
production zone in the event of a workover or the need to pull tubing. The seal bore
extension is located above that and then the millout extension immediately beneath
the packer.
4.10 Permanent Packer Retrieval Systems

If a permanent packer is used then the seal element cannot be released if the opposing
slips above and below the packer remain in place. The requirement is to mill away the
internal sleeve which holds the top slips in place and then the packer wil be free to be
pulled from the well. The milling operation normally takes between 3-6 hours and the
millhead is guided into the packer and maintained in place by a guide rod which passes
through the packer bore. The milling tool is also fitted with a retrieval tool which
incorporates a catch sleeve which will collect the remains of the packer when the
milling operation is complete and the tool retrieved. Figure 22
Baker Junk
Basket
Retainer
Production
Packer
Figure 22
Packer Milling Tool
illustrating one trip milling
and retrieval
Baker
Packer
Milling
Milling
Shoe
Retrived
Portion of
Packer
Catch
Sleeve
33
1
If the packer is run with a tailpipe, a millout extension sleeve must be run immediately
below the packer in which the catch sleeve will locate.
5 WIRELINE SERVICED NIPPLE AND MANDREL SYSTEMS

A nipple is a tubing sub which has a box and pin threaded connection, and a precisely
machined and configured, internal bore. This internal bore will accept a suitably sized
mandrel having a matching external profile which can be run down the inside of the
tubing string using wireline. The nipple normally provides two facilities:
(a) a facility to allow latching of the mandrel within the nipple profile.
(b) a sealing capability for the mandrel within the bore of the nipple.
The nipple therefore has to offer a landing/locking profile and a seal bore. To avoid
mechanical damage, the seal bore is generally located beneath the locking profile.
A variety of nipple/mandrel systems are available to offer the following capabilities:
(1) Isolation or plugging of the tubing string for well shut in, workover or for
hydraulically setting packers.
(2) A ported device which allows communication between the tubing and the
annulus.
(3) Emergency closure of the tubing or annular flow conduit by remote or direct
control.
(4) Downhole regulation or throttling of the flow.
(5) The installation of downhole pressure and temperature recording gauges.
Two basic types of landing nipple are available: the selective and the non-selective.
5.1 Selective Landing Nipple System

There are 3 methods of obtaining selectivity in a landing nipple system:
(a) selectivity based upon a variable internal profile
(b) selectivity associated with the setting tool
(c) selectivity based upon pre-spaced magnets
(a) Selective Internal Profile
In this system, it is necessary to match the internal profile of the nipple to a set of
locating keys on a lock mandrel. Normally nipples are available with 5 to 7 selective
positions. The nipples must then be run as part of the completion string in the sequence
denoted by the selective location keys. It is important that the nipples are run
sequentially and that a note of the depth of each nipple is made to assist mandrel
placement during subsequent work.
34
(b) Setting Tool Selective Nipples

With this system, the setting tool which includes its removable locking and sealing
device is designed with a system of fixed external profiles. Thus it is the setting tool
which locates the nipple and positions the lock mandrel and seal in the appropriate
nipple. Using this system of selectivity an unlimited number of this type of landing
nipples of the same size can be installed in the string.
(c) Prespaced Magnet Selectivity
This type of nipple system usually comprises a lower section which contains the
locking profile and sealing section and an upper section in which two prespaced
magnet rings are located. For a mandrel to be inserted and locked into such a nipple,
two magnets also prespaced, on the running tool must correspond with the location of
the rings within the nipple. The mandrel is locked in position by a mechanical locking
mechanism actuated by a small explosive charge detonated by the electric circuit
created when the mandrel lands in the nipple. Up to six of these nipples, of the same
size, can be run in the same string.
For most applications, selectivity is preferred on the basis of variable profile or
setting tool actuation.
5.2 Non Selective Landing Nipples

This type of landing nipple is frequently referred to as a no-go nipple and operates such
that the outside diameter of the mandrel will be slightly larger than the minimum
inside diameter of the nipple and hence prevents its passage through the nipple. In a
string designed with a number of nipples to be operated on this basis, it is imperative
that the nipples be designed to sequentially reduce in diameter as their installation
depth in the string increases. The clearance of a mandrel through the upper nipples
should be based upon the size of the locking section of the mandrel and normally the
sealing bore of the nipple. The no-go profile of the nipple can be designed to be at the
top or bottom of the nipple.
5.3 Available Nipple/Mandrel Systems

All the major completion equipment supply companies offer a wide range of nipple
systems of varying internal profile for a range of applications.
(1) Common Baker nipple systems
Two commonly used Baker nipple systems are the Model F and Model R seating
nipples. Figure 23
35
BFC Model 'F'

Non-Ported
Seating Nipple
BFC Model 'R'

Bottom-NoGo
Non-Ported
Seating Nipple
BFC Flow
Coupling
The Model F seating nipple features a top no-go shoulder and a locking groove above
the lower seal bore section. This type of nipple can be operated on a selective or top
no-go landing lock system. This type of nipple is used for a range of tubing operations
including:
(a) Setting a blanking plug to isolate production
(b) Landing directly controlled sub surface safety valves, check valves, downhole chokes.
(c) To land off pressure and temperature recording gauges.
The Model R nipple is a bottom no-go seating nipple which includes a honed internal
sealing bore and a locking groove/bottom no-go shoulder. It can be used for the same
type of applications as the Model F nipple.
The type X and R nipples offered by Halliburton are commonly utilised in completion
strings. Both the type X and R are running tool selective nipple systems. Figure 24
36
Figure 23
Baker non selective nipple
systems
Selective Landing Nipple

Type 'X' for Standard
Tubing Weight and Type 'R'
For Heavy Tubing Weight
Locking Mandrel
Equalising Sub
Figure 24
Halliburton types X and R
equipment
Subsurface
Flow Control
The type X nipple was originally designed for completions using standard weight
tubings, e.g. 31/2" or 41/2" dia. maximum in wells where the pressures would not
exceed 10,000 psi. The type R nipple was developed for heavier weight or larger bore
tubing strings. Both nipples were designed to offer a maximum seal bore diameter and
hence minimal flow resistance. For the X and R nipples, the seal bore is located
beneath the locking profile.
The mandrels used with these nipples are designed such that the locking keys are
retracted allowing passage through the nipple system with minimum resistance.
For both the X and R type nipples, a no-go version is available, the type XN and RN
respectively, and one of these is normally placed at the bottom of a series of type X
or R selective nipples.
37
Fish Neck
Expander Sleeve
Key Retainer Sleeve

Spring
Key (Selective)
Key (No-Go)
Packing Mandrel
Female Packing Adaptor

V - Packing
Male Packing Adaptor
Back-Up-Ring
38
Figure 25
Representation of type X
(selective) and type XN (nogo) locking mandrels
(Halliburton)
Fish Neck
Expander Sleeve
Key Retainer Sleeve

Spring
Key (Selective)
Key (No-Go)
Packing Mandrel
Female Packing Adaptor

V - Packing
Figure 26
Representation of type R
(selective) and type RN (nogo) locking mandrels
(Halliburton)
Male Packing Adaptor

Back-Up-Ring
The mandrels for the type X and R equipment and their respective versions with the
bottom no-go, figures 25 and 26 are designed to hold high differential pressure from
above or below. In the event of unseating a mandrel with a high differential pressure,
pulling could be difficult or hazardous. In the event of a high differential pressure
from below, the force on the mandrel could be sufficient to blow it up the tubing string.
Conversely, if the pressure differential were reversed, it may require significant force
to unseat the mandrel. In such cases, it is essential to equalise pressures across the
mandrel prior to it being unseated. This is done by the installation of an equalising sub
at the base of the mandrel. The sub has a port which is normally closed off by an
internal sleeve but a prong on the mandrel pulling tool, when engaged, will open the
sub.
Two other nipple systems offered by Halliburton are the type S selective and type N
no-go which is non selective.
39
1
The type S nipple is a system based upon selectivity by the locating mandrel. It features
7 predetermined relative landing locations in a single tubing string into which a
mandrel can be landed through the use of selective locating keys. The use of this
system allows up to 7 different nipple locations to be employed. The type S nipple
offers a large bore; can handle differential pressures in either direction but is only
available for tubing sizes up to 41/2" O.D.
The type N no-go nipple is a non selective landing nipple which is frequently
employed as the bottom nipple on a string comprising several type S nipples.
5.4 Setting Mandrels not requiring a nipple profile

In a properly designed well completion, nipple locations are identified and this
provides the capability for installing downhole equipment based upon the landing and
locking profile so provided. However, occasionally the need arises to be able to land
off equipment in the tubing where a nipple is not available, e.g.
(1) where a nipple seat has been damaged or access to the locking profile is difficult
(2) where a mandrel cannot be retrieved from a nipple
(3) where a suitable nipple location has not been provided.
In these circumstances mandrels are available for setting within the tubing or in some
specific designs within the collar of tubular threaded couplings. Obviously, since the
locking system will be based upon slips engaging the tubing wall or dogs entering the
tubing coupling collar, the efficiency of the mechanical locking will not be as effective
as a proper mandrel/nipple system. These mandrels are only suitable for differential
pressures less than 1500 psi. In addition the mandrels are not recommended if the
differential pressure is from above.
The type D mandrel is designed to lock in a tubing collar (for API thread couplings
only) and subsequent upwards jarring provides compression of the seal element within
the tubing wall. Figure 27
40
Inside Fishing Neck
Locking Sleeve
Collet Lock
Outer Sleeve
O-Ring
Lock Mandrel
Dogs
Tapered Retaining
Ring
O-Ring
Resilient Element
Packing Mandrel
Figure 27
Type D mandrel
(Halliburton)
Adaptor Sub
An attentive system in corporating opposite slips and capable of withstanding high

differential pressures is known as the slide plug (petroline).
5.5 Ancillary Equipment for Nipples

Any wireline nipple installed within a tubing string with or without the relevant
mandrel system, will cause some restriction to flow. The convergence and divergence
effects associated with entry to and exit from the nipple system will cause severe
turbulence and eddying currents. This turbulence can lead to substantial abrasive
action on the tubing wall and nipple system. To protect against this abrasion, flow
couplings are installed above and below the nipple to act as flow straightening devices.
Figure 28
41
Flow Coupling
Seating Nipple
or Sleeve
Flow Coupling
Figure 28
Correct installation of
Baker flow coupling
6 SUB SURFACE SAFETY SYSTEMS

For well isolation or closure under normal operating conditions, the production wing
valve and mastergate valve will be used. The advantage of these valves is that if the
valve malfunctions, then it can be repaired or replaced with little difficulty. These
valves are therefore defined as being the primary closure system for the well.
However, in the absence of an effective surface closure system, well security is
endangered. This could occur in a variety of situations:
(1) Xmas tree removal during workover preparations to pull tubing
(2) Removal of valves or valve components for servicing
(3) Accidental damage to Xmas tree
(4) Leakage on wellhead - Xmas tree flange seals
To provide some degree of security in the event of any of the above situations
occurring, it would be ideal to have a safety valve system located beneath the wellhead
within the tubing system. This component is termed a Sub-Surface Safety Valve or
SSSV. These valves are available based upon two different control philosophies,
namely:
(1) Direct Controlled SSSV (D.C.SSSV) which are designed to close when
downhole well conditions of pressure/flowrate vary from preset design
42
values. These valves are often refered to as "storm chokes".

(2) Remotely or Surface Controlled SSSV (S.C.SSSV) whereby closure and
opening of the valve is actuated and accomplished using a surface control
system which feeds hydraulic pressure directly to the downhole valve assembly.
Both valve systems are designed to provide protection in the event of a catastrophic
loss of well control.
6.1 Direct Controlled Sub Surface Safety Valve

These valves are installed on the basis of a design flow condition within the tubing
string. The valves can be run and installed within specific landing nipples within the
production tubing.
The preset control for closure of these valve systems is:
either
(1) Pressure differential operated valves assume a specific fluid velocity through a
choke or bean, which is part of the valve assembly. The valve has a spring to apply
the closure force. The valve will remain open provided the differential pressure does
not exceed the present design value. If an increase in flowrate occurs sufficient to
increase the differential pressure beyond the preset level, then the spring will affect
valve closure.
or
(2) Ambient type or precharged dome/bellows valves utilise a precharged gas
pressure in a dome to act as the valve control. If the flowing pressure drops below
the precharged pressure,then the valve will automatically close.
Direct controlled valves are available from all the major equipment supply companies.
The available valve systems vary in the valve configuration applied, e.g. the following
alternatives are frequently used:
(a) poppet type valve and seat
(b) ball valve and seat
(c) flapper valve and seat
(1) Differential pressure operated safety valves
The type F safety valve (Halliburton) is a differential pressure operated valve which
operates using a spring loaded flow bean or choke. During normal operation, the valve
is held open by the upstream pressure compressing the spring. When the preset
flowrate is exceeded, the flowing pressure decline will give rise to spring expansion
downwards and valve closure. The valve can be run and retrieved on wireline and can
be landed in any appropriate nipple using the applicable mandrel system.
43
1
The type J valve utilises a ball valve and cage system. Compared to the type F, the
valve has a larger bore and is designed for higher flowrate wells being available in
sizes up to 3.72" O.D./2.0" I.D. The spring in its extended state holds the valve offseat
and hence in the open condition. An increase in flowrate gives rise to a higher
differential pressure across the bean and hence spring compression occurs and as the
bean retracts upwards, the ball is designed to rotate and seal via the control arm.
Top Sub
Wiper Ring
Spring
Assembly
Body
Bean
Seat
Valve Housing
Seat Insert
Spring
Bean
Extension
Prong
Pin
Flapper Valve
The type M valve (Halliburton) is similar in operation to the type J except that a spring
loaded flapper is used as the valve. Figure 29. An increase in flowrate through the bean
produces compression of the spring and as the flowtube retracts upwards, the flapper
springs shut across the flow area. The flapper and ball valve types offer similar flow
dimensions.
(2) Ambient or precharged type safety valves
The type H valve (Otis) is designed with a piston loaded with a spring. Below the
44
Figure 29
Type M pressure
differential tubing safety
valve (storm choke)
Halliburton
piston, the chamber is filled with fluid precharged to a set pressure whilst above the
piston tubing pressure is applied through a port in the flow tube. If the tubing pressure
in the flow tube falls below the precharged dome pressure, the flow tube retracts by
spring expansion and the effect of pressure on the piston and the ball valve rotates to
the shut position. The type of closure is a more positive means of obtaining closure
since it does not depend upon pressure differential created by flow through a choke
as this may be unreliable. The type H is available with a bore up to 2 inches.
The type K ambient safety valve again uses a precharged dome pressure to act on a
piston to effect closure. The valve responds to a reduction in well pressure which, due
to the imbalance in pressure compared to the dome pressure, drives the rod upwards
and the valve onto the seat to close the valve. This valve offers the maximum bore
available with any directly controlled safety valve.
All the above safety valves can be run into the tubing string on wireline or coiled tubing
and landed off using an appropriate mandrel nipple combination.
To reopen the valves after closure requires equalisation of pressures across the valve
by
either
(1) the application of tubing pressure above the valve to equilibriate fluid pressure
or
(2) the use of a wireline prong to open the valve.
Advantages of Direct Controlled Sub Surface Safety Valves
(1) Simple construction and operating principle
(2) Easy installation and retrieval since no control line from surface is required
(3) Cheaper installation cost
Disadvantages of Direct Controlled Sub Surface Safety Valves
(1) The valve systems are not 100% reliable since they depend upon preset
deliverability and pressure conditions.
(2) Especially for the choke type valves, the valve performance and closure may
be affected by wax deposition or erosion of the orifice. It is imperative that with
these systems the valve is pulled and regularly inspected or replaced.
(3) The valve system can only be designed to reliably operate if an extreme
condition occurs in relation to changing flowrate and pressure.
(4) Declining productivity may make it impossible for the designed closure
conditions to be actually realised.
45
1
(5) Testing of valve closure (if possible) is not easily accomplished.
6.2 Remotely Controlled Sub Surface Safety Valves

These valves are designed to be installed downhole in the tubing string and are held
open by hydraulic pressure supplied to the valve via a control line. Figure 30. The
closure mechanisms utilised in these valves are either ball or flapper type assemblies.
OPEN
CLOSED
Landing
Nipple
Sheer Pin
Control
Line
Snap Ring
Shifting Sleeve
Spring
Ball
Spring
The valves available are of two distinct types, namely, the tubing retrievable and the
wireline retrievable valves.
The tubing retrievable valve system is a screwed tubular component which is made up
as an integral part of the tubing string and run into the well. Removal of the valve can
only be accomplished by pulling back the tubing string.
The wireline retrieval valve system consists of a conventional wireline nipple which
will accept the appropriate mandrel which in this case is the valve assembly itself.
1. Tubing Retrievable Sub Surface Safety Valves
The tubing retrievable valve is a threaded top and bottom tubular component whereby
the valve assembly is held open by hydraulic pressure fed down the control line on the
outside of the tubing.
In all cases the valve assembly consists of a spring loaded flow tube and piston
assembly, whereby hydraulic pressure fed into the cylinder above the piston provides
compression of the spring beneath the piston. The resultant downwards movement of
the flow tube serves to keep the ball valve or flapper open. If hydraulic pressure is bled
off the control line, the spring supplies the return pressure to cause upwards movement
of the flow tube and closure of the valve.
46
Figure 30
"Dual Application" remote
controlled sub-surface
tubing safety valve
The type QLP and DL tubing retrievable safety valves (Halliburton) are examples of
a flapper and ball type safety valves respectively. These valves offer minimal
restriction to flow with their large bores. For the valves it is recommended that tubing
pressure above and below the valve be equalised prior to applying hydraulic pressure
down the control line.
A modified flapper system is available with the Baker FV series tubing retrievable
SSSV. These valves use a flapper which is designed for self equalisation through
the use of a small spring loaded plunger on the flapper. As the flow tube moves down
when hydraulic pressure is applied, the end of the flow tube contacts and opens the
plunger allowing pressure equalisation.
Most applications of a tubing retrievable SSSV also incorporate a special nipple
known as a wireline extension for a tubing retrievable SSSV. This device is installed
immediately above the tubing retrievable SSSV as part of the tubing string and in the
event of valve failure, a wireline retrievable SSSV mandrel can be installed which
locks open the tubing retrievable valve and the hydraulic pressure from the control line
is redirected onto the wireline valve.
2.
Wireline Retrievable Sub Surface Safety Valves
Again the completion equipment supply companies offer a range of wireline retrievable SSSV. The operating conditions are similar to the procedures employed with the
tubing retrievable valves except that the valve is run on a wireline mandrel into a
special tubing nipple profile (figure 31) and not a tubing sub. This type of valve is
available either as a ball type system or as a flapper valve.
The type DK (Halliburton) is an example of a wireline retrievable ball type valve
whereby the valve has an outer lower seal assembly and an upper latch assembly
compatible with the appropriate nipple. The valve and sealing surfaces are partially
protected from wellbore fluids to restrict corrosion and abrasion during flowing
conditions. Further, each time the valve is opened, the design incorporates a system
to wipe clean the ball and seat.
As with the tubing retrievable ball valve it is recommended that pressure be equalised
above and below the valve prior to opening with the application of hydraulic pressure.
47
Representative of types
XEL & XEP
48
Representative of types
RQE & RQF
Figure 31
Wireline retrievable valve
nipple systems
(Halliburton)
Locking Mandrel
Safety Valve Nipple

Hydraulic Control Line
Cage Assembly
Piston
Spring
Equalising Port
(DK & DR Models)
Valve Seat
Valve
Figure 32
Type DK Halliburton
tubing safety valve installed
in safety-valve nipple
Ball Seat
Ball
One additional feature with this type of valve is that if hydraulic pressure is bled off,
fluid can be pumped down through the tubing for well killing operations. The
comparable flapper type valve is the type QO
Figure 33
Operation of DK tubing
safety valves Halliburton
Equalising
Open
Closed
49
1
A system of comparable wireline retrievable flapper valves is also offered by Baker.
In addition an alternative system for locking open a malfunctioning tubing retrievable
valve is offered by Baker, whereby a wireline installed valve is installed in place of
a separation sleeve which seals across the bore of a locked open tubing retrievable
valve. This system is termed an insert wireline valve.
3.
Comparison of Wireline and Tubing Retrievable Valves
In terms of valve mechanics both valve systems are very similar, the distinguishing
characteristics are as follows:
(1) The tubing retrievable valve must be reliable for it to be effective, as otherwise
its retrieval is a more involved and costly operation.
(2) The tubing retrievable valve offers a much larger flow area compared to the
wireline retrievable valve and hence will cause less flowing pressure drop and
not reduce attainable production rate. It is also more likely to be large enough
to allow wireline operations to be conducted through it. The wireline retrievable
valve offers much greater flow resistance.
4.
Ancillary Equipment for Surface Controlled SSSV (Figure 34)
Surface controlled SSSV require the installation of a control line into the valve or
valve nipple and this control line must be run in continuously as the tubing is installed.
In addition, to protect the control line from damage downhole, it should be strapped
to the outside of the tubing. The control line is normally strapped to the tubing using
a fluted control line protector.
50
Tubing
Control
line
Double Control
Line Installations
Collar
Guard line
Protector
Cable
Installations
Dual Encapsulated
Control Lines
With or Without
Stress Cable
Figure 34
Control line cable
installation equiptment
Control Line Reel

Package
The control line itself is normally stainless steel or monel and is available as 1/8" or
1/4" O.D. The line is normally supplied on a reel and is unwound and attached to the
tubing as the tubing is lowered into the well. Care must be taken to avoid the control
line being trapped between the tubing and the slips.
The control line is connected into the downhole valve but also has to connect into the
base of the tubing hanger.
Normally, when the tubing with a safety valve nipple is being run, precautions must
be taken to prevent debris entering the control line. In such cases, normally a dummy
sleeve or separation sleeve is positioned across the nipple and this provides a seal
allowing a positive pressure to be held on the control line which not only ensures that
no debris will enter the line but gives rapid detection of leakage or line damage.
51
1
When a safety valve is set very deep, there have in the past been occurrences where
the pressure due to the hydrostatic head of control fluid has led to incomplete closure
of the valve when surface pressure has been bled off. This effect can be counteracted
by running a dual control line where one line provides the surface control pressure and
the other line provides hydrostatic balance across the piston on the operating flow
tube.
6.3 Injection Well Safety Valves

In injection wells, significant tubing head pressures are often employed to maximise
injectivity. The use of one way check valves in water or gas injection wells can serve
a very useful purpose in that as soon as injection ceases, the valve will spring shut and
prevent backflow.
The valves are in effect direct controlled SSSVs. The valve systems available are the
ball, flapper and stem/seat systems. The type JC (Otis) figure 35 is a ball type valve
in which the inner mandrel is kept in the down position by pressure differential from
above, i.e. the injection pressure. Once injection ceases, the hydrostatic head is
insufficient to keep the valve open and the mandrel moves upwards, allowing the ball
to rotate and close in its upward movement. The type MC (Otis) figure 36 is a flapper
valve and operates in a similar fashion to the type JC. Both valves are reopened by
recommencement of injection.
Top Sub
Orifice
Spring
Mandrel
Seat
Body
Weldment
Ball & Seat
52
Figure 35
Type JC Halliburton
injection safety valve
Top Sub
Orifice
Spring
Guide
Seat
Seat Insert
Figure 36
Type MC Halliburton
Flapper Valve
& Spring
Assembly
Another injection safety valve is the type T figure 37 which offers a very large flow
area through the valve cage. Once injection pressure drops off, the restoring force of
the spring moves the valve stem upwards onto its seat.
Bean Cage
Valve Bean
Spring
Figure 37
Type T Halliburton
All 3 valves are designed for installation in a nipple using an appropriate mandrel
system with wireline. For simplicity the valves referred to are examples of Halliburton
systems
53
1
7 TUBING - ANNULUS COMMUNICATION EQUIPMENT
One vital operation which frequently has to be performed on a well is to circulate
between tubing and annulus. This is required during the following situations:
(1) To displace out the tubing contents during completion to provide a fluid
cushion which will initiate production. This is normally done by displacing
down the tubing and taking returns up the annulus, i.e. forward or normal
circulation.
(2) To displace out the tubing contents to a heavier kill fluid to provide hydrostatic
over balance of reservoir pressure prior to pulling tubing or other workover
activities.
(3) To allow continuous or intermittent injection from the annulus into the tubing
of fluids, e.g.,
pour point depressant
corrosion or scale inhibitor
gas for a gas lift process
There are 3 principal items of down hole equipment designed to provide selective
communication capability:
(a) Sliding side door or sliding sleeve
(b) Side pocket mandrel with shear valve
(c) Ported nipple
All three systems are dependent upon wireline or coiled tubing techniques to service
the equipment.
7.1 Sliding Side Door or Sliding Sleeve

Equipment of similar design is available from the major service companies but all
designs feature a tubing sub with external ports through the tubing wall within which
is located an inner mandrel with slots and seal rings above or below the slots figure
38. In the closed position, the inner mandrel or sleeve is located such that the ports
in the outer tubing wall are isolated by seals above and below on the inner mandrel.
Movement of the inner sleeve either upwards or downwards can produce alignment
of the slots on the inner mandrel with the ports in the outer tubing. After completion
of the circulation operation, movement of the inner sleeve in the reverse direction will
return the circulation device to its closed position. To achieve the movement of the
inner sleeve requires the running of a shifting tool to open and close the sleeve. The
shifting tool lands in the top or bottom of the inner sleeve and by jarring, the sleeve
can be moved up or down. Normally movement of the sleeve cannot be accomplished
if a extremely high differential pressure exists across the sleeve. Any number of
sleeves of the same size can be run in the same completion.
54
Top Sub
Nipple
O-Ring
Male Packing Adapter
Split Ring
Female Packing Adapter
O-Ring
Closing Sleeve
V-Packing
O-Ring
Female Packing Adapter
Figure 38
Sliding side door. If failure to close the sleeve on jarring occurs it might be due to solids
in the seal area or the effect of well deviation and the resultant inefficient jarring. In
such cases if the sleeve cannot be closed, a separation sleeve could be run which will
land inside the sliding sleeve and seal in the seal bores above and below the slotted
section of the inner sleeve.
Halliburton market sliding side doors which are based upon a tubing sub with a type
X or R nipple profile. The inner sleeve can be specified as opening by upwards or
downwards jarring as does the Baker sliding sleeve. The Halliburton sliding side door
does feature an equalising port which allows the pressure inside and outside the sleeve
to be equalised before jarring operations commence. The type XA and type XO are
available for the smaller tubing size and are opened by jarring upwards or downwards
respectively.
They differ in the seal configuration between the inner and outer sleeves. The type
XD is available for larger tubing sizes.
The benefits of the sliding sleeve/door systems are that they provide a reasonably large
cross sectional area for flow which permits acceptable circulation rates to be achieved
without hydraulic erosion.
55
1
7.2 Side Pocket Tubing Mandrel with Injection or Shear Valve
Section AA
Figure 39
Side pocket mandrel SPM
The side pocket tubing mandrel consists of a tubing mandrel with ports located on its
outside wall figure 39. Two basic types of mandrel exist:
(a) The side pocket mandrel where the pocket which will contain a wireline
replaceable valve device, is located within the mandrel body.
(b) Conventional mandrel in which the valve is located external to the tubing mandrel.
1.
Side Pocket Mandrels
Side pocket mandrels can be of round or asymmetrical oval cross section but at one
side of the mandrel, an inner sleeve or pocket is located. This side pocket has ports
56
in the outer wall of the mandrel through which communication between the annulus
and tubing can be accomplished. Using wireline tools a variety of valve devices can
be installed and retrieved. These valves have external seals which seal in the pocket
above and below the ports hence annular communication is through the valve.
Figure 40
The setting and retrieving
of a valve in an SPM
57
1
Some of the more common valve devices are:
(a) a fluid injection valve, which allows the injection of a chemical or gas from the
annulus into the tubing. The valve opens by either reaching an absolute pressure
in the annulus or a differential pressure between tubing and annulus.
(b) a shear valve, which has shear screws designed to shear under preset differential
pressure conditions and hence provide communication. To seal off the ports
after circulation requires the retrieval of the valve and its replacement with a
new one.
The installation of valves, even in highly deviated wells can be accomplished using
a kickover tool provided as obstruction exists in the entry area to the pocket. Figure
40.
2.
Ported Nipples
These are constructed from a standard type of wireline nipple with a port drilled
through the seal bore wall. During normal operation, the port is isolated by packing
elements located above and below it on a mandrel placed within the nipple. To initiate
communication the mandrel must first be pulled to reveal the ports.
SUMMARY
In this section, we have discussed the functionality requirements for and principal
design features of downhole completion equipment such as:
Production tubing
Wellheads and trees
Packers
Subsurface safety valves
Flow control and circulation devices
The concepts metallurgy and elastomer selection have been discussed.

In terms of materials selection the compromise between strength, cost, corrosion
resistance has been discussed. The section has discussed equipment options on a
functional basis stressing what the operational objectives or capabilities each item of
equipment offers.
58
EXERCISE 1.
PACKER FORCE CALCULATION - HIGH GOR WELL
A well in the North Sea has been completed with 7" OD tubing (6.33" ID) inside 9 5/8"
OD casing (8.625" ID). The tubing is latched into a permanent packer at 9000' TVD.
The packer fluid in the annulus is CaC12/CaBr2 brine of density 0.690 psi/ft.
When the well is closed in, phase separation takes place in the tubing resulting in the
following static conditions:
(a) THP = 2000 psig
(b) Gas column down to 4000' TVD, of density 0.15 psi/ft
(c) Oil column from 4000' down of density 0.375 psi/ft
When the well is flowing, the pressure just below the packer is reduced by 1000 psig
because of both drawdown on the reservoir and vertical lift flowing pressure loss
across the reservoir interval.
Calculate the imbalance of forces on the packer in both the static and dynamic phase.
59
1
EXERCISE 1. Solution
PACKER FORCE CALCULATION - HIGH GOR WELL
Simplified Schematic:
< 6.33" ID >
< 6" >
STATIC CASE
BHP at packer = 2000 + (4000 x 0.15) + (5000 x 0.375) = 4475 psi
Assuming packer is of negligible width:
Force upwards
8.6252 62 )
(
4
= (74.39 36)x x 4475 = 134861 (Upward )

4
= 4475x
Force downwards = tubing force + annular force
(6.332 62 )x4475
4
+(9000 x0.690)x (8.6252 72 )

4
= 14294 + 123775 lbs = 138069 (Downward )
Resultant force = 3208 (Downward)

Pressure below the packer
= 4475 1000 psi = 3475 psi
Force upwards
= 3475x (8.6252 62 ) = 104723 lbs (Upward)

4
Force downwards
= (6.332 62 ) x 3475 + 123775

4
60
= 11099 + 123775 = 134875 (Downward)

Resultant force
= 3015 1 (Downward)
61

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6

7 TUBING - ANNULUS CIRCULATION

1.1 Tubing Diameter

1.2 Tensile Strength

1.3 Internal Pressure

1.4 External Pressure

1.6 Coupling Types

Department of Petroleum Engineering, Heriot-Watt University

1.7 Specification of Tubing

e.g. 7000' - 51/2

- Hydril Super EU - Range 3

2.1 Conventional Spooled Wellheads

Ring gasket seal

2.2 Compact Spool System

Spacer spool to compensate

9 5/8" casing hanger

2.3 Mud Line Suspension System

4.1 Packer Applications

4.2 Basic Packer Components and Mechanics

Upper Split Nut

Department of Petroleum Engineering, Heriot-Watt University

4.4 Running and Setting Procedures

elements of a packer, leads to a significant number of options for installing and

Department of Petroleum Engineering, Heriot-Watt University

(d) Hydraulic-Set Packers figure 9

Department of Petroleum Engineering, Heriot-Watt University

(a) As an integral part of the completion string using a hydraulic compression/

Shear Pin for

Shear Pin for

Department of Petroleum Engineering, Heriot-Watt University

Manual Bleeder Valve

4.5 Permanent Packers

Upper slip and cone

4.6 Retrievable Packers

4.7 Packer Selection

4.8 Packer/Tubing Seal or Connection Equipment

4.8.1 Seal requirements

(3) Length of Seal System

4.8.2 Specification of the seal bore

4.8.3 Specification of Seal Assembly

The simplest tubing seal assemblies can be supplied with either:

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The tailpipe suspended beneath the packer performs a number of functions:

4.10 Permanent Packer Retrieval Systems

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5 WIRELINE SERVICED NIPPLE AND MANDREL SYSTEMS

5.1 Selective Landing Nipple System

(b) Setting Tool Selective Nipples

5.2 Non Selective Landing Nipples

5.3 Available Nipple/Mandrel Systems

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BFC Model 'F'

BFC Model 'R'

Selective Landing Nipple

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Key Retainer Sleeve

Female Packing Adaptor

Key Retainer Sleeve