Procedures for completion assembly preparation

Procedures for Completion Assembly Preparation
This procedure identifies the assembly and test method for all completion subassemblies.
All assembly and testing shall be performed by persons, who have, as a minimum, undergone
indoctrination and been qualified as Functional Test Operator. Assistant(s) shall have undergone
indoctrination of new assembly / disassembly personnel.
Two persons shall always be present during testing.
Prior to commencement, an authorized Company representative shall approve the description of each
sub assembly in writing. The workshop supervisor shall check equipment lists against the written
approval with sub assembly description. This approval shall be retained by the contractor.
Prior to assembly, the workshop personnel shall obtain approved equipment check list and test
procedure from the workshop supervisor. Only properly approved equipment check list may be used.
General Completion Assembly Procedure
The general procedure listed below shall apply to all assembly preparation:
1) The length and composition of subassemblies are largely dictated by available space and handling
considerations. All subassemblies shall be made up and tested onshore at the Cantractor Base(s) for the
completion subassemblies, TRSCSSV and ASV sub assemblies.
2) Every sub assembly shall have a backup available on site eliminating the need for making up
subassemblies offshore.
3) Every sub assembly, complete with suitable thread protectors, shall be transported to the site with
the applicable tubing pup joint connection box up, and the applicable tubing pup joint connection pin
down. For handling and make up purposes, the pup joints shall be approximately 2 metres long.
Procedure for Completion Testing and Assembling
1) All pressure tests shall be recorded on a chart recorder which will then be attached to the equipment
check list to be retained indefinitely by Company.
Test fluid: Soluble oil / water
Duration of test: 15 minutes at 35 bar and 15 minutes at 345 bar
2) All assemblies shall be tested to 345 bar unless otherwise specified.
3) After the pressure test, each assembly shall be drifted with the appropriate API spec. drift. All drift
diameters shall be recorded on the equipment check lists. For assemblies with a No Go nipple, a special
drift shall be used. All drifts shall be inserted from both above and below the assembly to ensure that no
deformation has taken place during make up.

4) All assemblies shall be made up using the Jam system or equivalent. All make up torque-turn and
pressure test charts shall be attached to the equipment check lists. The correct torque values shall be
verified by the tubing make up company.
5) The torque values shall be as follows:
7" 29# Vam AG (13%Cr) Grade L-80: 12380-13750 - 15120 ft/lbs.
7" 29# New Vam (9Cr 1Mo) Grade L-80: 8460 - 9400 - 10340 ft/lbs.
5 1/2" 23# Vam AG (13%Cr) Grade L-80: 9700 -10000 - 10300 ft/lbs.
5 1/2" 23# New Vam (9Cr 1Mo) Grade L-80: 7170 - 7960- 8750 ft/lbs.
6) The above values are specified and approved by Company.
Be aware that torque values used by Company can differ from manufacturers recommended. Torque
values for tubing shall be as per COMPANY recommendation.
7) For nonstandard or not often used equipment, the actual functioning of equipment and wireline
operating tools shall be performed before equipment leaves the contractors site.
Detailed Procedures for preparation of the different subassemblies are given below.
Tailpipe X-Over Assembly
1) Inspect interior and exterior of each component. Ensure that all threads are clean and free from
damage.
2) Ensure that any / all part numbers correspond to the equipment check list.
3) Drift each component with the correct API drift.
4) Apply thread lubricant to box end and by hand make up the connection.
5) Make up all connections to the specified torque value.
6) Drift assembly from above and below.
7) Apply storage grease and install thread protectors.
8) Complete the equipment check list.
Bottom Landing Nipple / Perforated Joint Assembly
damage.

4) Drift the Landing nipple with a special Camco no go drift (manufactured to tolerances corresponding
to the appropriate lock mandrel ).
Bottom Landing Nipple and Packer Assembly
damage.
6) Install steel test pins in the ratchet retainer.
7) Pressure test assembly to 138 bar as per programme.
10) Complete the equipment check list and pressure test chart.
Expansion Joint Assembly
damage.

Top Landing Nipple Assembly
damage.
7) Drift the Landing nipple with a special Camco no go drift (manufactured to tolerances corresponding
to the appropriate lock mandrel).
Side Pocket Mandrel Assembly
damage.
4) Install dummy/dummies in the side pocket. Note. Install the lower pup joint and protect the upper
threads prior to installing the dummy/dummies.

11) The relevant procedures used by Otis for all TRSCSSV and ASV sub assembly make up and testing are
detailed in the Contractor Service Manual.
X-Over Assembly
damage.
TRSSV and ASV

Completion Operations - Gravel Packing Procedures
Perforation prepacking refers to the methods that can be used to pack the perforation tunnels
with gravel prior to filling the screen/casing annulus. The main objective of prepacking is to
maximize the quantity of high permeability gravel placed in the perforation tunnels (or in
cavities behind the casing) which is one of the key factors controlling the productivity of an IGP
completion. Field experience indicates that in many cases standard gravel packing procedures
do not allow proper packing of the perforations.
1 Guidelines for prepacking operations
Introduction
Prepacking can be carried out before or after the GP liner assembly is run in place. When
carried out after perforating operations, prepacking results in more efficient and less damaging
well kill operations, especially when large losses are incurred after perforating without
prepacking.
Applicability
The perforation tunnels are packed with gravel immediately after back surging or back flowing
operations and then sealed with a graded salt LCM system. Hence the risk of impairment is
strongly reduced by keeping the perforations clean. The subsequent LCM removal operations
are also made easier as the LCM is placed as near as possible to the wellbore and the surface
area that the LCM is required to cover is reduced. As an additional benefit, it is easier to size the
LCM to bridge on gravel, which has a more uniform size distribution, than on formation sand.
There are basically no restrictions to the technique outlined below. However the following
factors should be considered when selecting candidate intervals:
·Losses after perforating: Prepacking is especially applicable to intervals which require the use
of fluid loss control material. There is however no reason why this technique could not be used
in situations where serious losses do not occur. The use of graded salt particles to seal the
perforation tunnels will then be superfluous.
·Interval length: Prepacking is considered especially beneficial for longer intervals as field
experience shows that the perforation packing efficiency of standard gravel packing operations
decreases very quickly with increasing interval length (>10 feet).

Operations outline
The following procedure is based on early prepacking trials carried out by BSP. Operators may
need to adjust it to their specific needs. Although this procedure is based on TCP operations,
prepacking can in principle be considered after perforation washing or back surging operations.
Early BSP prepack procedures
Early BSP prepack
1. RIH Otis sump packer with expendable knock-out plug.
2. RIH TCP assembly.
3. RIH MWPT.
4. Detonate gun and flow well till liquid at surface.
5. Record buildup.
6. Retrieve MWPT.
7. Close PCT and open MIRV.
8. Reverse out influx (pump citric acid pill to clean tubing and casing.
9. Close MIRV.
10. Open PCT (in hold open option).
11. Unset packer.
12. Measure loss.
13. Tag fill.
14. Pull gun above perforations set packer.
15. Perform injectivity test.
16. Acidize if injection less than 30L/m perforations.
17. Pump prepack slurry through packer bypass:

- Slurry: 750 kg/m3 Gravel (20/40mesh)
- 12.8 kg/m3 HEC
or
- 53 L/m3 Shellflo-S
- 30 L/m334% HCL
- 015 L/m3HAI -65
- In 12% KCL inhibited brine
- Slurry volume: 40 L/m3 net perfs
18. Close packer bypass and squeeze slurry into perforations.
19. Close PCT open MIRV.
20. Reverse out excess gravel (measure returns).
21. Close MIRV, open PCT unset packer.
22. Measure loss rate.
23. Tag and measure fill.
24. If loss rate excessive and pack factor above 20 L/m then - spot graded salt pill.
25. POOH.
26. RIH WWS with modified washing tool.
27. Washout fill till sump packer and measure return - use jet option if graded salt is used and
wash perforations till pre-LCM loss rate is achieved.
28. Stab into sump packer.
29. Drop dart and set packer.
30. Slurry pack well.

Potential problems
 ·Tool sticking: This is a potential problem when the gravel slurry and LCM pills are pumped down
hole. TCP guns may be dropped prior to pumping the gravel slurry, but this will result in
difficulties in establishing pre-packed gravel volumes. An alternative scheme is to pump the
gravel through a ported sub located above the TCP gun. The guns must be pulled above the top
perforations prior to pumping the gravel to avoid sticking problems.
 ·LCM removal: Salt LCM is removed by circulating under saturated brine along the interval.
Diversion of brine is a potential problem for intervals with a high permeability contrast.
2 Gravel packing procedures
Case where no lower telltale is used
The slurry is circulated down to the gravel pack ports at which stage back-pressure is applied up
to a specified figure. The amount of back-pressure is calculated to limit the pressure on the
formation to 200 psi below the fracture propagation pressure.
The objective of applying back-pressure is to squeeze part of the spacer and slurry into the
formation. Losses during slurry packing are to be expected and are desirable. Injectivity is
essential to ensure that a tight "pack" is obtained in the tunnels.
The following procedure is to be followed:
1. Set the liner hanger packer. Establish the squeeze and circulating positions of the GP tool.
2. With the GP tool in the reverse position, establish circulation pressures at 2, 4, 6 and 8
bbls/min. Check for losses.
Use a low bottom hole pressure ball in the crossover tool if losses are expected.
3. With the GP tool in squeeze position, establish the squeeze pressures at rates of 1/2, 1 and 2
bbl/min not exceeding the surface pressure calculated (BP-max).
The type of pack (slurry pack or conventional pack) installed is determined by the injectivity
test. Where the stabilized injection rate is more than 1 bpm, then the slurry pack will be
performed. Where the injection rate is less than 1 bpm, an acid squeeze (15% HCL, 20 gal/ft of
perforation) will be required and the injectivity test repeated. If the repeated injection rate is
more than 0.5 bpm, then the gravel will be slurry packed, otherwise it should be conventionally
placed.
4. With GP tool in gravel pack position:

 -pump 8 bbls of carrier fluid spacer;
 -pump gravel slurry from mixer/blender;
 -pump 2 bbls of carrier fluid spacer;
 -displace front spacer to the GP ports at 5-6 bbl/min, applying a backpressure sufficient to avoid
U-tubing due to the higher gradient of the slurry;
 -when the front spacer is 2 bbls from the GP port s, increase the backpressure to the value
calculated above (BP), while reducing the pumprate slowly to 2 bbl/min;
 -continue pumping at 2 bbl/min to screen out pressure of 1500 psi above the applied
backpressure;
 -open choke completely and reconfirm screen out with 1500 psi at less than 1/2bbls/min.
5. Set GP tool in reverse circ. position and reverse drill pipe clean. Use settling tank to
determine the quantity of gravel returns.
6. Reconfirm screen out with 1500 psi without backpressure. If no screen out is observed,
perform conventional top up.
7. Reconfirm screen out after 1 hr, with 1500 psi at less than l/2 bbl/min pump rate. If
satisfactory, POH. Otherwise inform base.
Case where a lower telltale is used
1. Set the liner hanger packer. Establish the squeeze, upper and lower gravel pack position of
the GP tool.
2. With the GP tool in the lower gravel pack position establish circulation pressure at 2, 4, 6 and
8 bbl/min. Check for losses.
3. Move into squeeze position and check injection rate for at least two minutes. Do not exceed
3 bpm or FPP whichever come first.
4. With the GP tool in lower gravel pack position:
 pump 8 bbls of carrier fluid spacer;
 pump gravel slurry from mixer/blender;
 pump 2 bbl of carrier fluid spacer;
 circulate slurry in place at 5-6 bbl/min. Reduce rate when slurry reaches the X-over port to 3
bbl/min. Screen out with 500 psi above maximum established injection rate;
 pull into upper gravel pack position and recheck screen out with 1500 psi pump pressure at less
than 0.5 bpm pump rate.
5. Set GP tool in reverse circulating position and reverse drill pipe clean. Use settling tank to
determine the quantity of gravel returns.
6. With the GP tool in the upper gravel pack position reconfirm screen out with 1500 psi pump
pressure.

7. If no screen out is observed, perform conventional top up.
8. Reconfirm screen out in upper gravel pack position after one hour, with 1500 psi at less than
1/2bbls/min pump rate. If satisfactory, POH otherwise inform base.
3 External gravel packing procedures
1. With the liner set and the gravel pack tool in the circulating position establish circulation at
0.5-5 bbl/min.
2. Commence adding gravel at ±l/2 sack per min (i.e. + 118 sack/bbl).
3. Having reached 80-85% of theoretical fill (or earlier if pressures indicate) reduce the gravel
concentration to 1/8-1/4sack/min. When getting close to screen out, it may be necessary to
add 1-2 sacks and displace these completely before adding the next batch of gravel. Care
should be taken that the string is not full of gravel at screen out.
4. Continue packing to screen out at reduced rate with 500 psi above initial pressure at 0.5
bpm. Do not exceed the maximum surface circulation pressure specified in the programme.
5. If there is no screen out or pressure build up after 100% of theoretical annular fill, this could
be due to washing out of the under reamed section or slumping of the pack due to
unconsolidated formation or tool failure resulting in gravel falling on top of running tool or BOL.
In this case, check tool is still free. If there is no indication of tool failure, continue packing at
reduced rate to screen out or a pressure build up followed by losses. (It is a common
observation in some wells that there is only a slight pressure build up usually in conjunction
with losses).
6. If no screen out occurs after 150% theoretical annular fill, double check system for leaks,
packer failure, fill inside liner, etc. Consideration can be given to run gravel pack log to
determine quality of pack (Base to advise).
7. After initial screen out reverse out excess gravel in DP. Wait for one hour and recheck screen
out at same pressure, in circulating position. Repack if necessary.
8.If screen out occurs before 90% theoretical annular fill, consideration should be given to
running a gravel pack log, as it may be necessary to check for bridging to determine whether
the bridge should be jetted or the liner pulled (Consult base).

Completion operations - Setting packers
Whatever type of packer is installed, the manufacturer's instruction for setting and the completion
programme on setting depth and running must be followed if satisfactory results are to be obtained.
There are too many variations in packer design and setting to go into detail, but some points to
remember when installing packers are:
 do not run the packer below the scraped interval;
 ensure the correct completion fluid is maintained at the correct levels and pressure in the tubing
and annulus, as specified in the programme;
 allow for drill pipe/tubing stretch when pressurizing the annulus and/or tubing;
 observe limitations in test pressures for perforated and non-perforated wells;
 ensure that the measuring equipment for weights, pressure and depths are as accurate as
possible and have been recently calibrated;
 carefully observe the setting-down and pulling weight on those packers that have shear pin
controlled functions;
 if tubing is being run with a plug set in the bottom nipple, care must be taken to run slowly so
that pressure surges do not set the hydraulic packer;
 with certain drill pipe set packers, care must be taken not to allow the drill string to turn until
required to release the setting tool;
 with some wireline set packers do not 'tag' the packer to check the setting depth as the collet
latch on the setting tool might re-engage and the logging cable is not strong enough to release
it;
 appropriate safety precautions must be observed when using the explosive setting tool, and the
necessary fishing tools for the setting tool must be on site.
Below gives the procedure for setting a Halliburton RTTS packer to illustrate a typical setting procedure
and necessary checks.
 Check the packer operating envelope, slips and packer elements.
 Make up the RTTS and assemblies on the pipe deck/catwalk if being run together.
 Make up the stand of tubing to the RTTS packer in the mouse hole.

 Pick up the assembly and make up to the pipe on the rotary table.
It is advisable to run a mule shoe when running tailpipe below the packer. Tailpipe up to the limit of the
Mandrel can be used as the circulation point is at the end of the tailpipe.
 Pick up the assembly. When the mechanical slips and drag block body are above the rotary table
work the drag block to ensure movement of the lug through the J-slot and free movement of the
mechanical slips.
 Run packer to below desired setting depth.
 Work the string across the desired setting depth. Record the WIR up and WIR down. Note the
slack off and stretch. Ensure that packer is not set within 5 ft of casing collar.
 Pick up string to desired packer depth and apply right hand torque.
 Release residual torque, slack off until packer starts to take weight. Circulating valve will close
and continue to slack off to the recommended setting weight on the packer.
 Connect kill line.
 Close pipe rams.
 Pressure up on annulus to the recommended pressure to ensure good packer seat and no leaks
on tubing string.
 Open pipe rams.
Attention must be given to the possible damage caused by the packer slips on the casing during setting
and retrieval, especially in H2S environments in which special alloy steels are used.
Packer Setting Mechanism
The following 5 Packer setting mechanisms are discussed in this article:
1. Compression set anchor packer
2. Mechanically set compression packers
3. Mechanically set tension packer

4. Hydraulic set tension/compression packer
5. Action of hydraulic hold-down
1.Compression set anchor packer
The anchor packer is the simplest of the compression packers. In the running-in position, a collet latch is
in a receptacle and the rubber sealing element is retracted allowing it to pass freely down the well.
When the Tail-pipe, run below the packer, encounters the bottom of the well, the weight of the tubing
above the packer causes the collet to snap out of the receptacle. The tubing weight compresses the
sealing element between the top and the bottom subs causing it to extrude and pack-off against the
casing.
If the packer is to be set some distance off bottom, the long tailpipe, required to initiate and maintain
the pack-off, is inexpedient. It is cumbersome, it may buckle badly and, in time, may become sanded in.
2. Mechanically set compression packers
Applications
These packers can be used in drill strings or tubing strings where the pressure differential is expected to
be from above the packer. A mechanically set compression packer is regularly used for drill stem tests or
to locate casing leaks. When this Packer is used for drill stem testing purposes care must be taken to
ensure that the pressure below the packer does not exceed that from above. However, should this occur
the packer will remain seated as long as the resulting upward force is less than the compressive force of
the slacked-off tubing weight.
Operations
The number of slips on this type of packer varies depending on its size. They are evenly spaced around
the slip retainer ring. A stud, projecting through the slip ring, locates in a J-shaped slot, machined in the
outer surface of the packer body. When the stud is located in the short leg of the J-slot, the slip ring and
the slips cannot move up towards the cone. In this mode the packer cannot set. When running into the
well, springs cause the lower part of the slips (the wear pads) to bear against the casing wall. The slip
retainer ring acts as a fulcrum and the upper toothed part of the slips pivot inwards away from the
casing wall. The friction of the wear pads on the wall holds the stud firmly up in the short leg of the J-
slot. This ensures that the slips are retained in a down position clear of the cone.
Setting the packer
On reaching the desired setting depth the tubing is picked up a few inches. The stud will now be located
in the lower end of the short leg of the J-slot. Rotation of the tubing at surface in the prescribed
direction and amount of turns brings the J-slot round until the stud lies in the lower end of the long leg.
The tubing is now lowered and the packer body moves down relative to the slip ring (the length of the

long leg of the J). The expander mandrel moves behind the slips which forces them out against the
casing wall. This mechanically set, retrievable compression packer is supported in the well by the slips.
The Packing element is expanded, and compressed between the body and the cone by slackening-off
the tubing weight. This effects a seal between the tubing and casing.
Retrieving the packer
Prior to retrieval any differential across the packer must be equalized. This packer can now be retrieved
simply by picking up the tubing/drill string weight, plus a slight over pull to unseat the packer. The slight
over pull combined with the upward movement of the tubing/drill string allows the compression
between the body and cone to relax. In turn the packing element contracts to its original form and the
expander mandrel moves up from behind the slips allowing them to retract into the slip carrier. The
packer can now either be retrieved from the well or reset further up the hole.
Operation of J-slot
The J-slot principle, as a means of controlling the slips, is used on many mechanically set packers. It is
simple and, providing the manufacturer's operating instructions are followed, fool-proof. A variant of
the packer described above has the stud fixed in the packer body and the slot cut in the inner surface of
the slip ring. The slot is then in the form of an inverted letter J. Other mechanically set packers use a
screw thread, instead of the J-slot, as a means of controlling the slip ring. Several turns at surface are
required to set these packers.
 Some mechanically set packers set with right hand rotation, and some with left. This must be
checked with the manufactures' operating instructions. In either case the operator who runs the
packer should check the necessary rotation, physically, before starting the packer in the well, at
the same time ensuring that the slip ring is able to move to the set position.
 The weight to be slackened off to effect the seal depends on the hardness off the rubber, and
will vary with the size of the packer. The manufacturer's operating instructions must be
consulted.
 On some mechanically set packers, using the stud and slot principle, the slot is cut such that, on
lifting the tubing to release the packer, the stud automatically 're-jays' back into its running-in
position.
3. Mechanically set tension packer
Applications
This packer was designed for use in installations where the pressure differential is expected to come
from below. In the mechanically set, retrievable, tension packer, the sealing element is below the slip
assembly. When the slips are released from the running-in position, an upward pull on the tubing brings
the cone up under the slips forcing them out to grip the casing. Further upward pull compresses the
packing element and packs it off against the casing wall. Pressure differential from below will set the

packer yet more firmly. If the differential should come from above, the packer will remain seated only as
long as the resulting downward force is less than the tension left in the tubing. Thereafter the packer
will be forced down, further stretching the tubing.
Operations
The packer in the illustration has an inverted J-slot machined in the packer body, engaged by a stud on
the slip ring. To set the packer, the tubing is lowered a few inches, and rotated anti-clockwise at surface
a sufficient amount to give a quarter turn at the packer. The stud is now in the top of the long leg of the
J-slot. Pulling up on the tubing sets the packer. The tubing must be landed in tension. To release, the
tubing must be lowered at least a foot more than is necessary to remove the originally applied tension,
and then rotated clockwise. This last movement brings the short leg of the inverted J-slot under the
stud. The packer may be pulled from the well. Tension packers are often equipped with an additional,
emergency release device. In the case of the packer illustrated this takes the form of a shear ring. If the
normal releasing procedure is not successful, a heavy upward strain on the tubing, considerably heavier
than that required to set the packer, will shear the ring, permitting body, rubber and cone to drop down
the mandrel, thus freeing the slips.
4. Hydraulic set tension/compression packer
Applications
Hydraulically set packers are particularly suited to conditions where tubing manipulation might be
problematic due to well characteristics, e.g. high deviation excessive depth etc. Due to the design of this
packer the tubing can be landed and flanged up prior to it being set. This is especially attractive on semi-
sub or drill ship locations since any "yo-yoing" effect of the tubing is eliminated.
Operations
The hydraulically set packer is actuated by a pressure differential between tubing and casing, at the
packer. A means of temporarily plugging the tubing must be incorporated in the tubing below the
packer, or in the bottom of the packer itself. In Fig. 2391, this is an expendable seat held in place by a
shear pin. On reaching setting depth, a ball is dropped down the tubing, to land on the expendable seat.
The tubing pressure is built up by a pump at surface. Tubing pressure, working in the cylinder, has forced
the body downwards, relative to the mandrel. The rubber sealing element has been compressed to pack
off against the casing, and the cone has been forced down behind the slips, driving them outwards to
grip the casing. The pressure has also actuated the hydraulic hold-down buttons. A shear pin, or pins,
holds the body and the mandrel together in the unset position while running in, to prevent premature
setting. The first action of the setting pressure is to shear the pin. With the packer set, a further increase
of pressure in the tubing will shear the pin and the ball and seat will fall out of the bottom of the tubing.
The setting pressure will now be bled off, but the packer will remain seated as the small internal slips
hold the body and the mandrel relative to one another. This packer does not require tubing weight to
hold it in position. Pressure differential from below could unset it, but for the hydraulic hold-down. The

hydraulic hold-down is not always included, but when it is, the packer becomes a tension-compression
packer.
Retrieval of the packer
The packer is released by raising the tubing. A pull, at the packer, of some 20,000-30,000 lb, depending
on size, shears the release pins. The lower body (l) will slide down to the retaining shoulder, followed by
the slips and the cone, allowing the rubber sealing element to retract.
Hydraulic variation
A variant of the hydraulically set packer is the hydrostatic packer. This has an annular cylinder containing
air at atmospheric pressure incorporated in its body. The upper end of the cylinder is sealed by an
annular piston, temporarily locked in position. A relatively low pump pressure at surface shears a small
pin, unlocking the annular piston. Hydrostatic head in the tubing, acting on the top of the piston, moves
it down, compressing the air. This movement sets the slips and compresses the sealing element. The
movement is locked into the packer by internal slips. Thus in performance and application the
hydrostatic is very similar to the hydraulically set packer. The main difference is the lower surface
pressure required to set it.
5. Action of hydraulic hold-down
Applications
Hydraulic hold-down buttons are an integral part of hydraulic set packers. They are situated at the upper
end of the packer above the packing element. These buttons rely on differential pressure from below
the packer to force them out into the casing wall thus, preventing any upward movement of the packer.
The higher the differential pressure from below the packer, the harder the hydraulic hold-down buttons
will engage the casing wall.
Operations
The button is retained in its port by a steel strip, the button retainer. A deep vertical slot down the face
of the button allows the latter to move outwards. A spring (or springs) in this slot bears against the
retainer strip, and forces the button inward. This keeps the button, when it is not needed, out of contact
with the casing and preserves the teeth from wear. The spring should be sufficiently strong to prevent
pressure surges (temporary differential due to the piston effect) extruding the buttons while running the
packer. The pressure differential across the button is contained by an 'O'-ring seal. The condition of the
seals should be checked before running, or re-running, the packer. If the seal is ineffective, the button
will not set, and, more seriously, a leaking seal is a leaking packer. Pressure from below the packer,
transmitted via the passage in the packer body to the back of the button, is equal to, or less than, the
pressure from above, acting on the face.

Completion equipment checklist
This article describes the following checklist for completion equipment:
1. Completion Equipment Preparation Checklist
2. Well Site Preparation Checklist
3. Make up/ Running Check Procedure
1. Completion Equipment Preparation Checklist
This procedure shall be followed in addition to the Contractors' own procedure. The Contractors shall at
their base as a minimum perform the following:
1. When new equipment arrives at the Contractor's Base, the Contractor shall perform an
extensive series of mandatory inspections. These include initial visual inspection followed by full
function and pressure testing of all relevant equipment.
2. The relevant procedures, applicable standards and specifications for all pre-completion
equipment supplied by Contractors involved in the pre-completion phase shall be detailed in
their respective Quality Assurance Manuals.
3. Equipment arriving at Companies Base shall be packed in designated boxes with appropriate
description on the equipment. Prior to shipment offshore the equipment shall be flushed and
when necessary, cleaned inside and outside with steam. The equipment will then be packed
again in designated boxes for shipment offshore.
4. All assembling and testing shall be performed by persons, who are qualified as Functional Test
Operators.
5. Two persons shall always be present during testing.
6. Prior to shipment, an authorized Company representative shall approve the description of each
sub assembly in writing. The workshop supervisor shall check equipment lists against the written
approval with sub assembly description. This approval shall be retained by the contractor.
7. Prior to assembly, the workshop personnel shall obtain approved equipment check list and test
procedure from the workshop supervisor. Only properly approved equipment check list may
be used.
8. All pressure tests shall be recorded on a chart recorder which will then be attached to the
equipment check list to be retained indefinitely by the Company
9. All assemblies shall be tested to 5000 psi bar unless otherwise specified.

10. After the pressure test, each assembly shall be drifted with the appropriate API spec. drift. All
drift diameters shall be recorded on the equipment check lists. All drifts shall be inserted from
both above and below the assembly to ensure that no deformation has taken place during make
up.
11. All assemblies shall be made up using the Jam system or equivalent. All make up torque-turn
and pressure test charts shall be attached to the equipment check lists.
12. The actual functioning of equipment and tools shall be tested before equipment leaves the
contractors site.
2. Well Site Preparation Checklist
All inspection and testing shall be performed by contractor's personnel and witnessed by the Drilling
Supervisor or his representative. This procedure shall be followed in addition to the Contractors' own
procedure.
1. Ensure that all equipment is clearly marked as it arrives on board.
2. The gravel pack liner/ pre-packed screens liner and down hole service tools required shall be laid
out on deck and the Contractor's pre-completion supervisor (under the supervision of the Rig
DE) will number and measure all items.
3. The gravel pack liner/ pre-packed screens liner and down hole service tools shall be flushed with
water or steam cleaned.
4. Ensure that all equipment is clean and free from scale and paint. Equipment which is painted or
is scaled shall be rejected.
5. Check the threads for damage and scale.
6. Drift all gravel pack/ pre-packed screen liner and down hole service tools.
7. Apply correct Thread Compound and then replace the pin and box protectors.
8. Inspect interior and exterior of each component. Ensure that all threads are clean and free from
damage.
9. Ensure that any/ all part numbers, dimensions, etc. correspond to the equipment check list.
10. Complete the equipment check list.
11. In addition the following specific tool inspections shall be performed:
12.

Pre-packed Screens
a) Screens shall be inspected for damage, correct wire spacing, and presence of holes in base pipe.
Screen should be steam cleaned (or cleaned with high pressure water) if necessary.
b) Ensure that the collar is correctly made-up to the base pipe.
Gravel Pack Packers
a) Ensure that there are no obstructions in the ball seat.
b) Ensure that the correct ball is available.
c) Inspect the packer slips and element for damage.
Shear Out Safety Joint
a) Before picking up assembly, ensure that shear pins are inserted all the way into the ring groove.
Knock-out Isolation Valve
a) Ensure that the flapper valve is operating as specified.
Work String
a) If operationally possible steam clean every joint.
b) The work string shall be drifted.
3. Make up/ Running Check Procedure
This procedure shall be followed in addition to the Contractors' own procedure.
1. In the case of gravel packing ensure, that the well clean-up programme is performed and the
required cleanliness is achieved.
2. Ensure that stripping table, elevators, slips and power tongs are in proper working order, and
that the correct dies are fitted.
3. Do not use pipe wrenches for manual make up.
4. Inspect interior and exterior of each component. Ensure that all threads are clean and free from
damage.
5. Ensure that any/ all part numbers, dimensions, etc. correspond to the equipment check list.
6. Complete the equipment check list

7. Using a small clean paintbrush or pipe dope applicator, apply pipe thread lubricant sparingly to
both pin and box thread, and sealing shoulders.
8. Ensure that the power tongs are set to cut out at the recommended torque. If available a unit
to control the initial make-up speed is recommended.
9. Record all torque values when making up the gravel pack/ pre-packed screen liner assembly.
10. Drift each joint as it is picked up to the drill floor. Connections shall be equipped with protectors
when transported to the rig floor.
11. Screens shall be inspected on rig floor for damage, correct wire spacing, and presence of holes
in base pipe. Screen should be steam cleaned (or cleaned with high pressure water) if necessary
prior to running in hole.
12. Ensure that the shear pins in the shear out safety joint are inserted all the way into the ring
groove before picking up the assembly.
13. After the gravel pack packer is made up to the string, the slips and packing elements should be
inspected.
14. Ensure that there are no obstructions in the gravel pack packer ball seat.
15. The Rig Drilling Engineer and Contractor's Pre-completion Supervisor shall record the serial
number of each item as it is made up to the gravel pack/ pre-packed screen liner.
16. Supervisors keeping a tubing tally should cross check with each other regularly to ensure that
the pre-packed screen/ gravel pack liner is made up according to the programme.
17. It is critical throughout the running of the gravel pack liner assembly to ensure that no shock or
jarring loads are created in the string. Always ensure that string movement is fully stopped
before setting slips. Failure to observe this could result in the safety joint shearing and the
gravel pack screen assembly falling.

Completion Operations - Packer (introduction)
A packer is defined as a sub-surface tool used to provide a seal between the tubing and casing (or wall)
of a well, thus preventing the vertical movement of fluids past this sealing point. Packers are sometimes
referred to as production packers but this term is generally used with reference to a particular class.
The principal reasons for running a packer include:
 production control;
 production testing;
 protection of equipment;
 well repair and well stimulation;
 safety.
Production control
Packers are used:
 to prevent annulus surge (heading);
 with a packer-type gas anchor;
 when a casing pump is installed.
In a gas lift well:
 to keep casing pressure off the formation (intermittent or chamber lift);
 to facilitate kick-off (and, incidentally, to prevent passing well liquids, which might be abrasive,
through the gas lift valves).
 In a dual or multiple completion well, to segregate the producing layers for one of the following
reasons:
 incompatibility of pressures of producing intervals;
 separate production, and gathering, of two crudes of distinctly different qualities;
 control of an individual layer for high GOR, or for water cut.

In a steam injection/steam soak well:
 to maintain an empty annulus and thus prevent loss of heat from the tubing (and reduce
expansion of the casing).
Production testing
Packers are used:
 during the production test of an exploration well, i.e. producing a discovery well, where the
performance and properties of the formation are as yet unknown;
 when testing a producing well to locate the point of gas or water entry (where production
logging services are not ready available).
Protection of equipment
Packers are used:
 to keep undesirably high oil or gas pressures off the casing or the wellhead;
 to protect the casing from the effects of corrosive fluids;
 in an injection well, to keep high water or gas injection pressures off the casing or the wellhead.
Well repair and well stimulation
Packers are used:
 when pressure testing the production casing;
 to locate a casing leak;
 during isolation of a casing leak, either temporarily or permanently;
 during squeeze repair of a casing leak;
 to shut-off temporarily undesirable gas or water entry;
 during squeeze cementation of perforations or part of perforations (particularly on a low
pressure or depleted well);
 during fracturing, to keep high 'frac' pressure off the casing;
 during acidising, to ensure acid enters formation;
 to avoid formation damage by workover fluid during well repair (the packer would probably be
in the well already, for some other purpose).

Safety
Packers are used:
 in a marine well, to protect against the effect of collision, or other surface hazards;
 to reduce the risk of wellhead leaks on a high pressure well;
 to provide environmental protection of prolific high pressure wells in a populated area.

Procedures for completion assembly preparation

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