Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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DOWNHOLE PACKER AND METHOD OF TREATING A
DOWNHOLE FORMATION USING THE DOWNHOLE PACKER
BACKGROUND OF THE DISCLOSURE
1. Field of the Invention
[0001] The present disclosure relates to a packer constructed to
operate repeatedly in very sandy conditions.
2. Description of the Related Art
[0002] Sand can be used in various perforating and fracturing
operations, which can cause packers to seize or get stuck and not be
operational in a wellbore. When packers become nonoperational, or get
stuck in the wellbore, various problems occur. One major problem is that
the packer can no longer be used and no other zones in the wellbore can
be perforated or fractured.
[0003] Accordingly, there is a need for a packer that is better
equipped to stay operational when sand is present in the wellbore.
SUMMARY OF THE DISCLOSURE
[0004] The disclosure is directed toward a method of using a
specially designed packer. The method includes running a packer
downhole into a casing adjacent to a formation. Once the packer, which
has two or more relative areas of rotation, is run down into the hole, the
packer can be set in casing. The formation can also be abrasively
perforated and the resulting perforations can be fractured.
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[0005] The disclosure is further directed toward a method of using a
specially designed packer. The method includes running a packer
downhole into a casing adjacent to a formation. Once the packer, which
has a mandrel having a plurality of debossed areas to reduce places
where sand can accumulate and prevent operation of the packer and a
plurality of holes disposed in the side of the mandrel, is run down into the
hole, the packer can be set in casing. The formation can also be
abrasively perforated and the resulting perforations can be fractured.
[0006] The disclosure is also directed toward a method of supplying
fluid into an annular treating area via downhole piping during a fracturing
operation. The method includes setting a packer at a predetermined
location in a casing, the packer included in a bottom hole assembly. The
method also includes the step of perforating a formation and fracturing
the formation by supplying fracturing fluid in the casing and outside of the
downhole piping. The method further includes pumping fluid through the
downhole piping and out an opening disposed in a bottom hole assembly
while the fracturing fluid is in the annular space.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] FIG. 1 is a cross-sectional view of a packer constructed in
accordance with the present disclosure.
[0010] FIG. 2 is a cross-sectional view of the packer constructed in
accordance with the present disclosure.
[0011] FIG. 3A is a perspective view of a mandrel of the packer
constructed in accordance with the present disclosure.
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[0012] FIG. 3B is another perspective view of the mandrel of the
packer constructed in accordance with the present disclosure.
[0013] FIG. 3C is yet another perspective view of the mandrel of the
packer constructed in accordance with the present disclosure.
[0014] FIG. 3D is an engineering layout view of the mandrel of the
packer constructed in accordance with the present disclosure.
DETAILED DESCRIPTION OF THE DISCLOSURE
[0015] The present disclosure relates to a packer 10 run down into
casing 12 in a wellbore. The packer 10 is used to hydraulically isolate an
upper area 14 in the casing 12 from a lower area 16 in the casing 12.
The upper area 14 can include perforations that could be subject to high
pressure fracturing operations and the lower area 16 can include fractures
from earlier fracturing operations, where it is desirable to prevent
additional fracturing via high pressure fracturing fluid. The packer 10
described herein is generally described as a packer used with coiled
tubing but it should be understood that the packer 10 can be used with
any type of downhole piping, such as coiled tubing, drill pipe, drill
string, etc.
[0016] Referring now to FIGS. 1 and 2, shown therein is the
packer 10 in a first position (FIG. 1) and a second position (FIG. 2). In
the first position, shown in FIG. 1, the packer 10 can be moved inside the
casing 12 and disposed at a predetermined location/depth inside the
casing 12. In the second position, shown in FIG. 2, the packer 10 is
shown in a set position inside the casing 12. When the packer 10 is in the
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set position, the upper area 14 in the casing 12 is hydraulically isolated
from the lower area 16 in the casing 12.
[0017] In the embodiment shown in FIG. 1, the packer 10 includes a
top sub 18 for connecting the packer 10 to another downhole tool (e.g.,
abrasive perforator) or downhole piping, a mandrel 20 rotatably
supported by the top sub 18, at least one packer element 22 disposed
around a portion of the mandrel 20 for selectively engaging the casing 12
and providing the hydraulic isolation between the upper and lower
areas 14 and 16, and at least one slip element 24 slidably and rotatably
disposed around a portion of the mandrel 20 for selectively engaging the
casing 12 and preventing the packer 10 from moving inside the casing 12
when the packer 10 is in the set position. The packer 10 further includes
a wedge element 26 slidably disposed around a portion of the mandrel 20
for engaging the at least one slip element 24 to force the at least one slip
element 24 toward the casing 12 when the packer 10 is moved into the
second position, and a drag block assembly 28 slidably and rotatably
disposed around a portion of the mandrel 20 for frictionally engaging the
casing 12 to substantially maintain the position of the packer 10 in the
casing 12 while the packer 10 is manipulated into the second position.
The packer 10 can also include a lower sub 30 attached to the mandrel 20
for preventing the drag block assembly 28 from sliding off the mandrel 20
and for possible connection to other downhole tools.
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[0018] The
top sub 18 can include a first interior portion 32 that is in
fluid communication with any tool or downhole piping disposed above the
packer 10 and a second interior portion 34 in fluid communication with
the mandrel 20. The first and second interior portions 32 and 34 of the
top sub 18 are separated by a fluid blocking member 35 and are not in
fluid communication with each other. The second interior portion 34
includes a port 36 disposed therein for permitting fluid in the lower
area 16 to be forced into the upper area 14 of the casing 12, which is
above the at least one packer element 22. When the packer 10 is in the
second (or set) position, the at least one packer element 22 is engaged
with the casing 12 and the area in the casing 12 above the at least one
packer element 22 can accumulate sand and compromise the operational
integrity of the packer 10. In
one embodiment, the first interior
portion 32 of the top sub 18 includes an opening 38 disposed therein to
permit high pressure fluid to flow out and circulate through the
opening 38 and around the area in the casing 12 above the at least one
packer element 22. This flow also prevents sand from settling in that
area, which can prevent the packer 10 from working properly. In another
embodiment, the opening 38 can be a jet port or a nozzle for creating a
turbulent flow of the fluid exiting the opening 38 to better prevent the
sand from settling about the packer 10 above the at least one packer
element 22. In yet another embodiment, the opening 38 can be a nozzle
constructed and designed to be abrasive resistant so as to withstand
abrasive fluids used in perforating and fracturing operations.
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[0019] In another embodiment, the packer 10 includes a check
valve 40 disposed in the packer 10, the check valve 40 having a top
portion 41 in fluid communication with the upper area 14 above the at
least one packer element 22 and a bottom portion 43 in fluid
communication with the lower area 16 below the at least one packer
element 22 in the casing 12. The check valve 40 also allows fluid to
bypass the packer 10 while running the packer 10 into the casing 12.
When the packer 10 is being set, or after the packer 10 is set, the check
valve 40 permits fluid (gas or liquid) under pressure to pass through the
mandrel 20 and the check valve 40 and exit the packer 10 via the port 36
of the top sub 18. The check valve 40 prevents a hydraulic force from
forming in the lower area 16 in the casing below the packer 10 which can
be greater than the available setting force from the downhole piping. In
one exemplary embodiment, the check valve 40 can include a ball 42 and
a seat 44 whereby the ball 42 is unseated from the seat 44 when the
pressure below the packer 10 becomes greater than the pressure above
the packer 10. Once the ball 42 is unseated, fluid below the packer 10
can pass through the port 36 and enter the upper area 14 in the
casing 12.
[0020] In a further embodiment, the packer 10 includes an unloader
valve 46 that permits fluid to flow through the packer 10 instead of only
being able to flow around the outside of the packer 10 when the
packer 10 is being run, moved or unset in the casing 12. The unloader
valve 46 includes at least one passageway 48 disposed therein for
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allowing fluid to pass from an inside portion of the packer 10 to an
outside portion of the packer 10 above the at least one packer element 22
via the at least one passageway 48 when the packer 10 is being run,
moved or unset in the casing 12. Similarly, fluid is allowed to pass from
the outside portion of the packer 10 above the at least one packer
element 22 to the inside portion of the packer 10 via the at least one
passageway 48. When the packer 10 is in the set position, blockage
elements 50 of the unloader valve 46 engage a face seal 52 to prevent
fluid from flowing through the unloader valve 46.
[0021] The mandrel 20 includes a first end 54 rotatably supported by
the top sub 18 and a second end 56 disposed adjacent to the lower
sub 30. In one embodiment, the mandrel 20 is rotatably connected to the
top sub 18 via a ported housing 57. The first end 54 includes a lip 58
positioned adjacent to the at least one packer element 22 to prevent the
at least one packer element 22 from sliding upward (i.e., in the uphole
direction, even when the packer 10 is used in a horizontally disposed
wellbore) when the packer 10 is moved into the set position. The at least
one packer element 22 is disposed around the first end 54 of the
mandrel 20 and adjacent to the lip 58. The wedge element 26 is disposed
around the mandrel 20 on the opposite side of the at least one packer
element 22. As the at least one slip element 24 engages the wedge
element 26, the wedge element 26 is forced against the at least one
packer element 22 which causes the expansion of the at least one packer
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element 22 into the casing 12. This hydraulically seals the upper area 14
in the casing 12 from the lower area 16 in the casing 12.
[0022] Referring now to FIGS. 3A-3D, shown therein is the
mandrel 20 constructed in accordance with the description herein. The
second end 56 of the mandrel 20 includes a plurality of debossed
areas 60 that include a plurality of holes 62 disposed therein to allow for
sand to pass through the packer 10 and not build up and prevent the
operation of the packer 10. The debossed areas 60 also help prevent
sand from causing the packer 10 to stick and become nonoperational.
The second end 56 of the mandrel 20 also includes a 3-slot area 64 for
receiving and guiding a 3-pin 66 rotatably disposed in the drag block
assembly 28, which is disposed around the second end 56 of the
mandrel 20. The 3-slot area 64 is designed such that the 3-pin 66 is
permitted to redundantly move around the mandrel 20. In one
embodiment, at least 50% of the cylindrical surface area of the
mandrel 20 is comprised of the debossed areas 60 and/or the holes 62.
[0023] In one embodiment, the 3-pin 66 includes a collar 68 rotatable
disposed within the drag block assembly 28 and at least one extension
element 70 disposed inside the collar 68 for being guided through the
3-slot area 64. The 3-slot area 64 includes at least one shoulder 72 for
engaging the extension element 70 of the 3-pin 66, at least one
downward corridor 74 extending in a downhole direction from a central
area 76 of the 3-slot area 64, and at least one upward corridor 78
extending in an uphole direction from the central area 76 of the 3-slot
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area 64. It should be understood and appreciated that as the extension
element 70 of the J-pin 66 is guided in the various parts of the 3-slot
area 64 in the downhole and uphole directions, the drag block
assembly 28 is also moved in the downhole and uphole direction via the
extension element 70 of the 3-pin 66.
[0024] When the extension element 70 of the 3-pin 66 is engaging
the at least one shoulder 72, the packer 10 is typically in the run in
position (forced downward or downhole in the casing) which corresponds
to the packer 10 being in the first position. When attempting to set the
packer 10 in the casing 12, the 3-pin 66 will generally need to be moved
from the at least one shoulder 72 to the at least one upward corridor 78.
This is accomplished by lifting up on the packer 10 which permits the at
least one extension element 70 of the 3-pin 66 to disengage the at least
one shoulder 72 and contact a first ridge 80 positioned beneath the at
least one shoulder 72 (in a downhole direction) and angled downwardly to
force the extension element 70 of the 3-pin 66 ultimately into the
downward corridor 74. Once the extension element 70 of the 3-pin 66 is
in the downward corridor 74, weight is then placed back onto the
packer 10 which forces the extension element 70 of the 3-pin 66 upward
and out of the downward corridor 74 into a second ridge 82 positioned
above the downward corridor 74 (in an uphole direction) and angled
upwardly to force the extension element 70 of the 3-pin 66 through the
central area 76 of the 3-slot area 64 and ultimately into the upward
corridor 78.
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[0025] As the extension element 70 of the J-pin 66 travels up the
upward corridor 78, the drag block assembly 28 and the at least one slip
element 24 are forced towards the wedge element 26. Eventually, the at
least one slip element 24 is forced to engage the wedge element 26. In
addition to squeezing the at least one packer element 22 and
hydraulically sealing the casing 12 as described herein, the at least one
slip element 24 is forced outward and into the casing 12 until the at least
one slip element 24 is engaged with the casing 12 such that the
packer 10 will not move in the casing 12 up to predetermined hydraulic
pressures. Once the at least one slip element 24 and the at least one
packer element 22 are fully engaged with the casing 12, the packer 10 is
in the set position (or second position shown in FIG. 2). The at least one
slip element 24 can be any type of slip element known in the art. The slip
element 24 can include buttons, wickers, or a combination thereof.
[0026] After the packer 10 has been set and it is desirable for the
packer 10 to be unset and moved in the casing 12, upward force can be
applied to the packer 10. The upward force causes the wedge element 26
to disengage from the at least one slip element 24, which permits the at
least one slip element 24 and the drag block assembly 28 to move away
from the wedge element 26 and allows the wedge element 26 to stop
squeezing the at least one packer element 22. The at least one packer
element 22 will no longer hydraulically seal the upper area 14 in the
casing 12 from the lower area 16 in the casing 12. Additionally, the at
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least one slip element 24 will disengage from the casing 12 and permit
the packer 10 to again be moved in the casing 12.
[0027] Once the at least one slip element 24 is disengaged from the
wedge element 26, the drag block assembly 28 and the 3-pin 66 (and the
extension element 70 of the J-pin 66) rotatably disposed therein can now
move in the downhole direction in the upward corridor 78. The extension
element 70 of the J-pin 66 then exits the upward corridor 78 and crosses
the central area 76 of the 3-slot area 64 and contacts a third ridge 84
positioned beneath the upward corridor 78 (in a downhole direction) and
angled downwardly to force the extension element 70 of the 3-pin 66
ultimately into a second downward corridor 86. The upward force applied
to the packer 10 causes the drag block assembly 28 (and thus the
extension element 70 of the 3-pin 66) to travel in the downhole direction.
The drag block assembly 28 is prevented from coming off the mandrel 20
by the lower sub 30.
[0028] The packer 10 is now back in the first position (or run
position) and can now be moved uphole in the casing 12 and moved to
another location and reset. The packer 10 can also be moved back in the
downhole direction in the casing 12 if desired. In this scenario, the
extension element 70 of the 3-pin 66 will travel in the uphole direction in
and out of the second downward corridor 86 and across the central
area 76 of the J-slot area 64. Once across the central area 76 of the 3-
slot area 64, the extension element 70 of the J-pin 66 will contact a
fourth ridge 88 positioned above the second downward corridor 86 (in an
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uphole direction) and angled upwardly to force the extension element 70
of the 3-pin 66 ultimately into a second shoulder 90.
[0029] In
another embodiment, the mandrel 20 includes two
shoulders 72 disposed on opposite sides of the mandrel 20 from each
other, two upward corridors 78 disposed 900 from the shoulders 72 and
on opposite sides of the mandrel 20 from each other, and four downward
corridors 74. In a further embodiment, the collar 68 of the 3-pin 66
includes two extension elements 70. In
this embodiment, the two
extension elements 70 engage the shoulders 72 at the same time, then
engage two of the four downward corridors 74 and then the two extension
elements 70 will engage the two upward corridors 78 at the same time.
The two extension elements 70 can then engage the other two downward
corridors 74 followed by the extension elements 70 then engaging the
shoulders 72 again. The 3-pin 66 can continuously maneuver around the
mandrel 20 as depicted herein.
[0030] The
drag block assembly 28 can include at least one drag
block 92 for frictionally engaging the casing 12. The packer 10 can also
include at least one sleeve 94 with a plurality of perforations 96 disposed
therein.
Similar to the holes 62 disposed in the mandrel 20, the
perforations eliminate stagnant areas that are prone to collecting sand.
The perforations 96 and holes 62 permit the packer 10 to be cleaned from
accumulated sand as the packer 10 is moved up and down in the
casing 12. The wedge element 26 can also include openings 98 disposed
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therein to provide the same functions as the perforations 96 and the
holes 62.
[0031] For the packer 10 to remain operational, the 3-pin 66 has to
be able to rotate around and slide uphole and downhole on the
mandrel 20. Relative rotation areas on the packer 10 are important
because the packer 10 is ultimately connected to downhole piping (not
shown) which does not rotate like a drill pipe can. The more areas of
relative rotation allows the 3-pin 66 to have more ways to be able to
move about the 3-slot area 64 of the packer 10 and allow the packer 10
to move from the first position to the second position and back to the first
position. In one embodiment of the present disclosure, the packer 10 has
at least two relative rotational areas. One area of relative rotation of the
packer 10 is between the downhole piping (not shown) or the top sub 18
and the mandrel 20. Another area of relative rotation for the packer 10 is
between the drag block assembly 28 and the mandrel 20. A third area of
relative rotation for the packer 10 is between the 3-pin 66 and the drag
block assembly 28. It should be understood that the areas of relative
rotation are capable of 360 rotation.
[0032] The present disclosure is also directed to a method of using
the packer 10 in downhole operations such as perforating and fracturing
operations conducted on downhole formations. The packer 10 can be run
down into the casing 12 as an inclusion of a bottom hole assembly (BHA).
In one embodiment, the packer 10 can be run down into the casing 12
with the BHA and set at a predetermined depth/location. The formation
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can then be abrasively perforated after the packer 10 is set. Once the
abrasive perforation operation is concluded, the formation can then be
subjected to a fracturing operation. In another embodiment of the
present disclosure, the formation can be abrasively perforated prior to
setting the packer 10.
[0033] In
another embodiment, the packer 10 (and the BHA the
packer 10 is incorporated into) can be unset and moved to a second
location in the casing 12 without being removed from the casing 12. The
packer 10 can then be reset at the second location. Once the packer 10
is set at the second location, the formation can be abrasively perforated
to create additional perforations in the formation. Another fracturing
operation may be implemented to fracture the perforations generated at
the second location. It
should be understood that the abrasive
perforating could be done prior to setting the packer at the second
location. Additionally, it should be understood and appreciated that the
methods disclosed herein can be repeated at numerous locations in the
casing 12.
[0034] The
disclosure herein is also related to a method for
circulating fluid in the upper area 14 in the casing 12 and a method for
monitoring annular treating pressure via the downhole piping. The
annular treating pressure can be the pressure of the fluid used during
fracturing operations which is provided down into the casing 12 outside of
the downhole piping and any components of the BHA disposed above the
at least one packer element 22. More specifically, the annular treating
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pressure can be the pressure of the fracturing fluid in the area
substantially adjacent to where the perforations in the formation were
created via a perforation operation.
[0035] In one embodiment, a relatively low flow of fluid is pumped
into the downhole piping during a fracturing operation. The fluid is
pumped at a low flow rate so that the fluid will experience very little
frictional pressure drop through the downhole piping. The low flow rate
can be any flow rate less than about 0.5 barrels per minute. When the
frictional pressure drop is low across the downhole piping, BHA and/or
any particular component of any tool in the BHA, the the pressure
required to pump the fluid into and through the downhole piping, BHA
and/or components of tools in the BHA can provide a fairly accurate
measurement of the annular treating pressure at a desired location in the
casing 12. The annular treating pressure is approximately the sum of the
surface treating pressure (or surface injection pressure) and the
calculated hydrostatic pressure (based on vertical depth) at a
predetermined location/depth inside the downhole piping or the BHA.
[0036] In one exemplary embodiment, the components of tools in the
BHA that fluid can be pumped through when measuring the annular
treating pressure can include, but are not limited to, the opening 38 in
the packer 10 and a nozzle in an abrasive perforator that may be included
in the BHA.
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[0037] In yet another embodiment, a fluid can be pumped through
the downhole piping and out the opening 38 in the packer 10 during
fracturing operations to circulate fluid in the upper area 14 in the casing
12 above the at least one packer element 22. This fluid circulation stirs
and flushes proppants in the fracturing fluid, such as sand, away from the
top of the packer 10 to prevent the sand from accumulating on and/or
around the packer 10. Accumulation of sand atop and/or around the
packer 10 can prevent the unsetting and subsequent resetting of the
packer 10. For this embodiment, the fluid can be pumped through the
downhole piping at a low flow rate and the annular treating pressure can
be measured while circulating fluid to flush the sand. The fluid can also
be pumped through the downhole piping at higher flow rates to better
ensure the sand is stirred and flushed from atop and/or around the
packer 10.
[0038] From the above description, it is clear that the present
disclosure is well adapted to carry out the objectives and to attain the
advantages mentioned herein as well as those inherent in the disclosure.
While presently preferred embodiments have been described herein, it will
be understood that numerous changes may be made which will readily
suggest themselves to those skilled in the art and which are accomplished
within the spirit of the disclosure and claims.
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