Note: Descriptions are shown in the official language in which they were submitted.
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Flow Control Hanger and Polished Bore Receptacle
Field of the Invention
The invention relates to a flow control hanger and polished
bore receptacle for use in completing a well for oil and gas
production.
Background
In oil and gas wells, after the production liners are
installed, a completion string is installed into the well to
produce well fluids. This completion string may contain a
variety of tooling required to produce the wells fluids. In
thermal wells, specialized tooling is required to allow for
thermal expansion.
In thermal applications where steam is injected into the
formation to loosen and fluidize well fluids, the tooling
placed in the well require special seals to withstand the
injection pressures and temperatures of steam, which are in the
range of 350 C at 2500 PSI. Special tooling required for
steaming typically includes a bottom packer, sliding sleeve,
expansion joints as well as pumps and the completion string
connected to the surface. Seals found in the bottom packer,
sliding sleeve, and expansion joints are all known to have seal
failures over time, resulting in a loss of quality and quantity
of steam being delivered to the formation, which in turn also
lead to lowered production rates.
During steaming of the well, the steam can be delivered from
surface either through the completion string or through an
intermediate casing to the production liner in the open hole
below the intermediate casing. In either procedure, the
completion string is subject to thermal changes. Most often,
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steam is delivered through the completion string, which
protects the intermediate casing from thermal expansion, as
well as surface equipment such as the well head. During this
process, the sliding sleeve is in a closed position which
isolates the completion string from the intermediate casing.
During steaming, all seals are subject to steam temperatures
and pressures. As the completion string grows under thermal
expansion, the expansion joints close. During production, the
sliding sleeve is operated in an open position to connect the
completion string and to the intermediate casing annulus. This
is done to vent off any gases that could enter from the pump
side to the intermediate casing side. As the well is produced
and temperatures and pressures slowly decrease, the expansion
joint begins to open again. All these seals, especially the
expansion joint seals, are subject to failure, affecting
wellhead temperatures and cemented casing expansions. This can
result in casing and wellhead failures.
The bottom packer contains seals on its outside diameter which
seal to the intermediate casing and seals on its inside
diameter to seal to the completion string. The bottom packer
is run in the hole to a pre-determined depth and the seals are
set by compressing them to force the seals in an outward
position. The compression continues until the outside diameter
seals of the packer, are forced against the inside diameter of
the intermediate casing. The bottom packers usually consists
of a ratchet ring, which has a one direction movement. As the
seals are compressed, the ratchet ring locks, preventing the
seals from returning to their original position, thus creating
the seal.
Known sliding sleeves consist of a tube within a tube. The
outer tube or sleeve has holes through its wall. The inner
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tube or sleeve consists of two sets of seals to seal against
either side of the holes on the outer sleeve. Movement of the
inner sleeve will open the holes and allow communication
between the completion string and the intermediate casing
annulus.
Expansion joints typically used in the art consist of an inner
sleeve and outer sleeve and a set of seals. The inner sleeve
is connected to the completion string above and the outer
sleeve is connected to the completion string below. As the
completion string expands or contracts, movement of the
expansion joint is meant to relieve any stresses the completion
string would of otherwise be subject to.
In most existing tools, the seals are of elastomeric or
graphite material. As such, it is not uncommon for them to
wash, become brittle from the heat and break. Such seals
typically do not have any memory and do not return to their
original shape after being stressed.
The intermediate casing itself can also aid in creating a poor
seal. The intermediate casing may not always have a uniform
diameter to seal to. API specifications dictate that the
casing wall thickness must be within +/- 12% of the total wall
thickness, which allows for a great deal of variance.
Typically, two types of casing are made; a seamless pipe and an
ERW (electric resistivity weld) pipe. The seamless pipe is
manufactured from a solid bar stock and has no seam, but the
wall thickness will vary within the 12% allowable through the
entire length of the pipe. The ERW pipe has consistent wall
thickness but contains a weld seam that runs the entire length
of the pipes inside diameter. In both cases, either the weld
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seam or the wall thickness variance can affect the seal
performance of the bottom packer.
It is therefore desirable to develop a completion device that
can ensure better sealing against the intermediate casing and
production liner, and also reduce seal failure.
Summary of the Invention
A completion system is provided for completing downhole wells.
The system comprises an upper polished bore receptacle
incorporated into an intermediate casing of the downhole well
and formed with a honed inner bore and a bottom packer for
supporting a completion string within the intermediate casing
and having a first sealing assembly for sealing engagement
against the inner bore of the upper polished bore receptacle.
The first sealing assembly comprises a mandrel having at least
one threaded connection at an end of the mandrel to mate to the
completion string, one or more end caps threaded to an outside
diameter of the mandrel and having angled faces, one or more
pairs of end seals and one or more mid seals placed between
each pair of end seals. A lower polished bore receptacle (PBR)
is also incorporated into the intermediate casing and formed
with a honed inner bore. A flow control hanger (FCH) in the
form of a hollow mandrel is used for hanging a production liner
in the intermediate casing and having a second sealing assembly
for sealing engagement against an inner bore of the lower
polished bore receptacle. The second sealing assembly
comprises a mandrel having at least one threaded connection to
mate to the production liner and a flat faced stop shoulder,
one or more end caps threaded to an outside diameter of the
mandrel and having an angled face, one or more split seals and
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one or more stop rings. A further completion system is
provided for completing downhole wells comprising a polished
bore receptacle (PBR) and a latch down packer having a lower
end to which the PER is connected. A seating nipple is
installed at a lower end of the PBR and a sealing assembly
passes through the latch down packer and is seated inside the
PBR and connected to a completion string.
Brief Description of the Drawings
The present invention is described in greater detail, with
reference to the following drawings, in which:
Figure 1 is an elevation view of a downhole well, depicting one
embodiment of the prior art;
Figure 2 is an elevation view of a downhole well, depicting one
embodiment of the present invention;
Figure 3 is a cross sectional view of one embodiment of the
sealing assembly of the present bottom packer;
Figure 4 is a cross sectional view of one embodiment of the
sealing assembly of the present flow control hanger; and
Figure 5 is an elevation view of a downhole well, depicting a
further embodiment of the present invention.
Description of the Invention
The present invention provides a Flow Control Hanger (FCH) and
Polished Bore Receptacle (PBR) that acts to create a seal that
can withstand the pressures and temperatures of the steam. The
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seal must withstand steam pressures and temperatures while
enduring movement due to thermal expansion and contraction.
The seal needs to be able to withstand 350 C steam temperatures
and 2500 PSI steam pressures. Furthermore, the seal needs to
maintain elasticity and not become brittle. Preferably, the
seal will contain a positive memory at all times to seal to an
uncontrolled casing inside diameter.
Figure 1 represents one example of the prior art. The liner
hanger is run in the hole to a determined depth and the seals
are set. The production liner is connected below the liner
hanger, and drill pipe is connected above the liner hanger to
surface. The liner hanger can be deployed either hydraulically
or mechanically. In either case, the seals are compressed by
pressure or weight to force the seals outwardly. The
compression continues until the seals are forced against the
inside diameter of the intermediate casing. The hangers
usually consist of a ratchet ring, which has a one direction
movement. As the seals are compressed, the ratchet ring locks,
not allowing the seals to return to their original position,
creating the seal. A release mechanism is run in conjunction
with the liner hanger to release
the drill pipe from the liner hanger, after it is set. If
slips are required to hold the production liner off bottom,
these slips are deployed at the same time and in the same
manner as the seals are set.
Since these seal assemblies are compressed and held in this
position by ratchet locking rings, the seal always contains a
negative memory. In other words, if the assembly was to lose
its seal and leak, there is no positive pressure to re-seal the
assembly. The ratchet ring only holds the seal position and
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can't apply positive memory on its own. In some cases, the
ratchet ring can slip, causing the seals to release.
Movement of the seal assembly within the casing, to a different
position in the casing, could change the casing form to the
permanent seal form of the assembly, resulting in a leak.
Any minor change in either the seal form or casing form, using
a permanent set seal with negative memory, will result in a
leak.
Figure 2 depicts one embodiment of the present invention,
illustrating a downhole well fitted with an intermediate casing
6, hung with a completion string 8 and a production liner 18.
The completion string 8 is at ambient temperature when
installed. A bottom packer 2 is positioned at a top portion of
an upper polished bore receptacle (PBR) 4. The completion
string 8 is then hung by a completion string bonnet or hanger
12 from the bottom of the well head equipment 14. As steam
enters the well through the wellhead 14, the completion string
8 is heated and expands in length. As the completion string 8
expands, it advances down the well bore, moving the bottom
packer 2 lower but still within the upper PBR 4. As the
completion string 8 moves within the upper PBR 4, it maintains
a constant seal to the intermediate casing 6 and the bottom
packer 2 slides to compensate for the completion string 8
movement, continuing to seal as it moves. This novel
arrangement serves to combine two different tool functions into
one tool, eliminating the number of seal components required.
Since the present upper PBR 4 replaces the outer barrel of a
traditional expansion joint, there are no restrictions to the
dimensions of the outside diameter of the expansion joint.
This allows the upper PER 4 to be built thicker, and thus
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stronger. As well, the additional room allows for the seal
assembly 10 and seals to be designed with greater strength, as
the only restriction in the design of the associated sliding
sleeve 16 is that the inside diameter must match the completion
string 8 inside diameter. The
bottom packer 2 joint can also
be built larger than traditional packers, to accommodate a
variety of pump sizes and completion string 8 sizes.
The completion string 8, pump barrels and other tools can be
connected to the present bottom packer 2 in the same manner as
known bottom packers in the art. As well, the sliding sleeve
16 can be operated in a similar manner as traditional sliding
sleeves, using the same tooling.
Below the completion string 8 and its sealing equipment resides
a second seal assembly 22 that hangs and seals the production
liner 18 to the intermediate casing 6. The production liner 18
can be a sand control liner or perforated liner that will
deliver the steam to the formation, and transfer the produced
oil from the formation to the completion string pump. The
second seal assembly 22 also requires movement and sealing
characteristics due to thermal expansion of the production
liner 18.
In a preferred embodiment, an upper PBR 4 seals the completion
string 8 and a lower PBR 20 seals the production liner 18. The
upper PBR 4 has a larger outside diameter than the lower PBR
20. This will allow the production liner 18 and the second
seal assembly 22 to pass through the upper PBR 4 and seal to
the lower PBR 20. The seal assembly 22 of the completion
string 8 then seals to the upper PBR 4.
The present bottom packer 2 contains a novel first seal
assembly 10, depicted in Figure 3. Some differences in the
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present bottom packer 2 are the seal material, seal setting
procedure and the removal of inner completion string seals
assembly. The seal material is made of any number of
temperature and pressure resistant materials, including
stainless steel, aluminum, lead and heat resistant plastic or
rubber compounds. The seal material is preferably steel, which
is able to withstand temperatures and pressures higher than
steam. The wear resistance of metals, and particularly steel,
is greater than traditional rubbers or graphite. Furthermore,
metals provide a positive memory, which can preferably be set
at the surface rather than down hole to allow a positive seal
against its mating polished bore receptacle 4.
Figure 3 depicts the present sealing assembly 10 of the bottom
packer 2. The bottom packer 2 comprises a mandrel 30 that
houses the seals, end caps 32 and preferably a spacer ring 34.
The mandrel 30 preferably contains male threads on the end caps
32 and machined shoulders for positioning the spacer ring 34
and one or more set screws 36. The mandrel 30 contains male or
female threaded connections 38 on both ends to mate to the
completion string 8 or other tooling. The threaded connections
38 can preferably be custom threaded to the well requirements.
The inside diameter and outside diameter of the mandrel 30 is
preferably machined to mate to a 4
completion string 8 and
can be further preferably crossed over for a 3 ;1" completion
string 8. In this preferred embodiment, the same bottom packer
2 can be used with a 4 or 3 ;1" completion string pump.
The end caps 32 are threaded onto the outside diameter of the
mandrel 30 and act to hold the seals to the mandrel body and
allow setting of the seals. As the end caps 32 are tightened,
they force the seals together, which in turn abut against the
stationary spacer ring 34. As
the end cap 32 is tightened,
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the angels force the seals closer to the outside diameter of the
mandrel 30, thereby closing a cut on the seals. The more the end
cap 32 is tightened, the more it a) closes the cuts, b) decreases the
gap between the inside diameter of the seals and the outside
diameter of the mandrel 30, c) decreases the Interference fit
between the outside diameter of the seals to the inside diameter of
the polished bore receptacle 3. The end of the caps 32 are secured
to the mandrel 30 with three set screws 36 after adjustments and
assemblies are completed.
Each seal assembly 10 consists of two end seals 40, which are
placed on either side of a mid seal 42. The end seals 40 preferably
have an angled taper on one side to match an optional angle of the
end caps 32 or spacer ring 34, and preferably also have a
shouldered face on the other side to match a mating shouldered
face of the mid seal 42. A scraper profile 80 on each of the end
seals serves to scrape the inner surface of PBR 4 and thereby
prevent ingress of debris between the seal assembly 10 and the
PBR 4. The end seals 40 further preferably have a controlled width
cut which splits the seal along its length. Each end seal 40
preferably has a pin pocket 46 located on its shouldered face at
180 opposite to the cut. The end caps 32 preferably have an
angled face that matches mating angled faces of end seals 40. The
same angle match is located at the spacer ring 34 as well.
The mid seal 42, which is placed between the two end seals 40 of
the seal assembly 10, preferably has shouldered face ends to match
the mating shouldered faces of the end seals 40. The mid seal 42
further preferably has a controlled width cut which splits the seal
along its length. The mid seal 42 also preferably has a pin pocket 46
located on the both shouldered faces, at 180' opposite to the cut.
The spacer ring 34 is placed between the two seals. The spacer
ring 34 has an angled faces on sides to match the angled
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face of the end seals 40. The spacer ring 34 is equipped with
set screws 36, which will hold the spacer ring 34 to the
outside diameter of the mandrel 30 in a permanent position.
End caps 32 located on either side of the seals act to tighten
the seals against the spacer ring 34 on either side.
Preferably, anti-rotation pins 44 are located between each
matching shouldered face of the mid seal 42 to the shouldered
face of the end seal 40. When the seal assembly 10 is
assembled, the anti rotation pins 44 fit into the pin pockets
46 of the seals before they are fitted to each other. This
ensures that no rotational movement of individual seals can
occur, thus eliminating the possibility of seal cuts lining up
and creating a leak path.
Each end cap 32 preferably includes one or more set screws 36,
and more preferably four set screws. Once the end cap 32 has
been tightened to a preferred position, the set screws 36 are
tightened to hold any further rotation of the end caps 32 in
either direction. The set screws 36 tighten to the outside
diameter of the mandrel 30. There are also one or more set
screws 36, and preferably four set screws, on the spacer ring
34. When the spacer ring 36 is installed, it is placed in the
centre of the mandrel 30, over top of a machined outside
diameter shoulder on the mandrel 30. The set screws 36 are
tightened to the outside diameter of the mandrel 30, placing
the set screws 36 within the shouldered groove. This
eliminates any side movement as well as any rotational movement
of the spacer ring 34.
The present bottom packer 2 uniquely acts as both a packer and
as an expansion joint. Since the bottom packer 2 is allowed to
move and is located within the upper PER 4, this configuration
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now resembles an inner and outer sleeve of a typical expansion
joint used in most completion strings and can operate in the
same manner. As the completion string 8 expands and contracts
from thermal expansion, the bottom packer 2 will move with the
completion string 8, continuously keeping a seal to the
intermediate casing 6, or preferably to the upper PBR 4, which
is part of the intermediate casing 6. As the completion string
8 changes in length, the bottom packer 2 within the upper PBR 4
compensates for the change by moving up or down within the
upper PBR 4, operating as the expansion joint and relieving
stresses in the completion string 8.
The bottom packer seal assembly 10 outside diameter is designed
to be slightly larger than the inside diameter of the upper PBR
4, thus allowing the installation of the bottom packer 2 with a
clearance to the intermediate casing 6 above the upper PBR 4.
Once the bottom packer 2 reaches the top of the upper PBR joint
4, the seal assembly 10 will compress or collapse to the inside
diameter of the upper PBR 4. As the bottom packer 2 is placed
within the upper PBR 4, the seal assembly 10 seals against the
inside diameter of the upper PBR 4 with positive memory.
The upper PBR 4 can preferably have two different functions.
Depending on the well, the injection completion string 8 is
sometimes preferably placed inside the production liner 18, for
the length of the production liner 18, and hung down the well.
In this arrangement, the injection completion string 8 has a
different rate of expansion than the production liner 18,
therefore both strings would require separate bottom packers 2
or flow control hangers 22. The upper PBR 4 is preferably used
to hang the injection completion string 8 inside the production
liner 18, while the lower PBR 20 is preferably used to hang the
production liner 18, allowing for each string to have its own
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independent growth and seal. Depending on the designed length
of the upper PBR 4, it can further preferably contain both the
injection completion string 8 to the bottom well bore, as well
as the pump completion string to surface. Alternately, a third
PBR can preferably be installed in the well.
The present polished bore receptacles (PBR) 4, 20 act to
replace typical casing joints in the intermediate casing. The
PBRs 4, 20 have a honed inside diameter to provide a
continuous, controlled surface area against which the seal
assembly 10 of the bottom packer 2 can seal. The present PBRs
4, 20 eliminate inconsistent wall variances often found in
seamless casings and eliminate the welded seam of an ERW
casing. The PBRs 4, 20 are preferably built in lengths to
allow for maximum movement of the completion string 8 due to
thermal expansion and contraction. The PBRs 4, 20 are further
preferably treated for surface hardening and corrosion
resistance to enhance performance of the bottom packer 2.
The lower PBR 20 is preferably machined from a joint of casing
that has a larger casing wall thickness than the intermediate
casing 6 and has a smaller honed inside diameter than the upper
PBR 4. This allows the FCH 22 to pass through the upper PBR 4.
The PBR will be honed to an inside diameter that is smaller
than the nominal inside diameter of the intermediate casing 6,
and larger than the drift diameter of the intermediate casing
6. A "no-go" is preferably machined to the inside diameter
near the bottom of the lower PBR 20, preferably in the form of
a smaller-than-honed inside diameter to stop passage of the FCH
22 through the lower PER 20. The length of the lower PBR 20 is
calculated based on the thermal growth expected while in use.
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The inside diameter of the lower PER 20 is preferably treated
to enhance material hardness and corrosion resistance after
machining is completed. This treatment protects the honed
inside diameter from drilling tool damage, as drilling will
continue through the intermediate casing after it is set.
The flow control hangar 22 is fitted with an associated second
sealing assembly 48. In one embodiment, the sealing assembly
48 can be made using the same design and parts as the sealing
assembly 10 of the bottom packer 2. A preferred embodiment of
the sealing assembly 48 of the FCH 22 is shown in Figure 4.
The sealing assembly 48 comprises a mandrel 50 that houses one
or more split seals 56, one or more end caps 52 and one or more
stop rings 54. The mandrel 50 contains male threads for the
end cap 52, and a machined stop shoulder 58 for the stop rings
54. The mandrel can further contain male or female threaded
connections on both ends to mate to the production liner 18 or
release tools. These connections can also be custom threaded
to particular well requirements. The inside diameter and
outside diameter of the mandrel are honed to mate to the
production liner 18 below it.
The end cap 52 threads on to the outside diameter of the
mandrel 50 and holds the split seals 56 to the mandrel body.
As the end cap 52 is tightened, it forces the split seals 56
together to abut the stationary stop ring 54. The end cap 52
has an angled face which matches a corresponding angled taper
on the ends of each split seal 56. As the end cap 52 is
tightened, the angled face forces the seals closer to the
mandrel 50 outside diameter and closes a controlled width cut
formed on the split seals 56. The more the end cap 50 is
tightened, the more it a) closes the cuts, b) decreases the gap
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between the inside diameter of the split seals 56 and the
outside diameter of the mandrel 50 and c) decreases the
interference fit between the outside diameter of the split
seals 56 to the inside diameter of the polished bore receptacle
20.
Each seal assembly 48 consists of two split seals 56. Each
split seal 56 will have an angled taper to match the angled
face of the end cap 52 or an angled face of the stop ring 54,
and a shouldered side to mate to other split seals. Each split
seal 56 has a controlled width cut along its length. Each
split seal 56 has a pin pocket located on the shouldered face
side, located 180 opposite to the cut.
The stop ring 54 is placed against the stop shoulder 58 of the
outside diameter of the mandrel. The stop ring 54 will have an
angled face on one side to match the angled face of the split
ring 56, and a flat face on the other side to match the flat
face of the stop shoulder 58 on the mandrel 50.
An anti rotation pin located between the matting shoulder
faces of the split seals 56. Each shouldered face on each
split seal 56 will contain a pin pocket which is located 180
degrees opposite the cut. When the split seals 56 are
assembled, the anti rotation pin is placed in the pin pockets
of the split seals 56 before they are fitted to each other.
This ensures that no rotational movement of individual seals
can occur, thus illuminating the possibility of seal cuts
lining up and creating a leak path.
The end cap 52 preferably includes one or more, and more
preferably three, set screws 60. Once the end cap 52 has been
tightened to its preferred position, the set screws 60 are
tightened to hold any further rotation of the end cap 52 in
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either direction. The set screws 60 tighten to the outside
diameter of the mandrel 50.
One notable difference in the present FCH 22 is the seal
material and seal setting procedure. The seal material is
metal, preferably steel. Metal can withstand steam
temperatures and pressures seen during thermal treatment. The
wear resistance of metal versus rubber or graphite is also
better and will not wash. Metal further provides a positive
memory unlike a brittle material such as baked rubber. The
seal assembly 48 is set in accordance with its mating lower
polished bore receptacle 20 which is part of the intermediate
casing 6.
The lower PBR 20 acts to replace the casing joint into which a
traditional casing liner hanger would normally be set. The
lower PBR 20 has a honed inside diameter to provide a
continuous controlled surface area for the seal assembly 48 to
seal to. The present lower PBR 20 address the issue of
inconsistent wall variance found in traditional seamless
casings, while also eliminating the welded seam of ERW casings.
The lower PBR 20 is preferably built in lengths to allow for
maximum movement of the FCH 22 due to thermal expansion and
contraction. The lower PBR 20 is also preferably treated for
surface hardening and corrosion resistance to enhance
performance of the FCH 22. The lower PBR 20 is assembled to
intermediate casing 6 and is placed near the bottom of the
intermediate casing string 6. The bottom of the lower PBR 20
is preferably furnished with a no-go, in the form of a slightly
smaller inside diameter then the honed area above it. This no-
go acts to prevent the FCH 22 from passing thought the lower
PER 20. The present no-go acts in a similar manner to slips
that are typically located on known liner hangers, with the
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exception that the no-go allows the FCH 22 to move within the
lower PER 20, but not to exit the lower PER 20. The present
FCH 22 seal assembly 48 allows the production liner to hang
from the no-go, thereby eliminating the need for traditional
slips.
The present bottom packer 2 and flow control hanger 22 seals
are made of metal, preferably steel, which provides a positive
memory seal to the completion string 8 and the production liner
18.
In operation, the bottom packer 2 is connected to the bottom of
a pump barrel and or completion string 8. The completion
string 8 is run into the cased well bore until the bottom
packer 2 reaches the top of the upper PBR 4. As soon as the
seals of the bottom packer 2 seal to the top of the upper PER
4, there is a reduction of weight of the completion string 8.
As the weight of the completion string 8 on the seals increase,
the seals of the bottom packer seal assembly 10 collapse and
compress until the seal outside diameter matches the inside
diameter of the honed upper PER 4. Once these two diameters
match each other, the seals of the bottom packer 2 slide inside
the upper PER 4 and the controlled width cuts of the end seals
40 and mid seals 42 close and seal any leak path that may have
existed through the cuts. As the cuts close, the inside
diameter of the spacer rings 34 seals to the outside diameter
of the mandrel 30 of the bottom packer 2 and the outside
diameter of the spacer rings 34 seal to the inside diameter of
the upper PBR 4.
Should any passage of fluid through the controlled width cut
exist, these will become sealed at the shoulder face and will
not be allowed to leak further through cuts on adjoining seals.
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The ends of the seal assembly 10 are angled, and mate to the
spacer rings 34 with the same angle. One spacer ring 34 is
stationary, while the second spacer ring 34 is adjustable.
This adjustable spacer ring 34 tightens the seal assembly 10
together. As the adjustable spacer ring 34 is tightened, it
forces itself against the stationary spacer rings 34 and also
compresses the seals, which in turn adjust the outside diameter
of the seal assembly 10. The outside diameter of the seals is
adjusted to a determined outside diameter which is calculated
from the honed inside diameter of the upper PBR 4. The
interference fit between the seal outside diameter and the
upper PBR 4 inside diameter determines how much weight is
required to set the seals into the upper PBR 4. It also
controls how much positive memory is set into the seal, and how
much force is required to move the seal within the upper PBR 4
due to thermal expansion and contraction.
The distance that the bottom packer 2 is set inside the upper
PBR 4 is predetermined. Typically, the installment of the
completion string 8 is at ambient temperature, so the bottom
packer 2 is set in the upper portion of the upper PER 4. The
completion string 8 at surface will be hung from the well head
14. Spacer joints can optionally be installed to the
completion string 8 at the surface to adjust the depth of the
bottom packer 2 in the upper PBR 4. As the completion string 8
expands from heat and its length increases, the bottom packer 2
tends to lower inside the upper PBR 4, while maintaining its
seal to the upper PBR 4. As the completion string 8 cools, is
length decreases, causing the bottom packer 2 to move upward
inside the upper PBR 4, again maintaining its seal.
The production liner 18 is run into the well, with the FCH 22
attached at the top of the production liner 18, through the
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larger intermediate casing 6, and into the open hole that is
drilled below it. When the bottom of the production liner
reaches a predetermined depth, the FCH 22 will reach the top of
the lower PBR 20. The FCH 22 is then pushed into the lower PER
20 by the weight of the drill pipe above it. As the seal
assembly 48 of the FCH 22 enters the top of the lower PBR 20,
the seals compress or contract to fit the inside diameter of
the honed lower PBR 20, and the leak passages of the seals are
closed, eliminating or controlling the amount of leak path.
The "no-go" located at the bottom of the lower PER 20 prevents
the FCH 22 from exiting the lower PER 20. The seals are now
loaded with positive memory and therefore have a tendency to
expand outwardly toward the inside diameter of the lower PBR
20, thus creating a positive seal. As the production liner 18
expands and contracts, the seal assembly 48 moves within the
lower PBR 20, while always maintaining a positive seal. The
metal material of the seals eliminates the chances of washing
or brittle seal failure.
A further alternate embodiment of the present invention is
illustrated in Figure 5. This embodiment allows the present
invention to be combined with an existing latch down packer,
which in turn ensures that the well can be shut in using
conventional seating nipples that are typically found on latch
down packers. Referring to Figure 5, in this alternate
arrangement, the PBR is no longer located within the
intermediate casing 6, but rather this PER 70 is connected to
the bottom of an existing latch down style packer 62. The PER
70 in this embodiment is preferably sized to fit inside the
intermediate casing 6 with at least some clearance. A seating
nipple 64 is attached to a lower end of the PBR 70, which is in
turn attached to a lower end of the latch down packer 62.
CA 02761516 2014-05-28
Similar to workings of the upper PBR 4 installed in the
intermediated casing 6, a sealing assembly of 66 passes through
the latch down packer 62 to seat inside the PBR 70 below. The
well can now be sealed with the latch down packer 62 using the
combined sealing assembly 66 and PBR 70. Once sealed, the well
is then shut in by installing the seating nipple 64 via a wire
line unit 68 to the lower end of the PBR 70. The latch down
packer 62 thus acts to seal the lower open end of the PBR 70
and an annular space around the casing 6. The attachment of
the PBR 70 to the latch down packer 62 prevents movement of the
PBR 70, thus sealing the well and allowing the completion
string, including the sealing assembly 66 to be removed safely
from the well. Connections on the PBR 70 are preferably honed
to match bottom threads of the latch down packer 62 and to
upper threads of the seating nipple 64.
In the foregoing specification, the invention has been
described with a specific embodiment thereof; however, it will
be evident that various modifications and changes may be made
thereto without departing from the scope of the invention.
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