Note: Descriptions are shown in the official language in which they were submitted.
Temperature Compensated Element and Associated Methods
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to U.S. application number 14/601,077
and to U.S.
application number 14/337,892, which claims priority from U.S. provisional
application
number 61/857,092, filed July 22, 2013.
Technical Field/Field of the Disclosure
[0002] The present disclosure relates to downhole tools for forming a well
seal in an annulus
between an inner tubular and either an outer tubular or a borehole wall, or
forming a plug with
the outer tubular or borehole wall.
Background of the Disclosure
[0003] Swellable packers are isolation devices used in a downhole wellbore to
seal the inside
of the wellbore or a downhole tubular that rely on elastomers to expand and
form an annular
seal when immersed in certain wellbore fluids. Typically, elastomers used in
swellable packers
are either oil- or water-sensitive. Various types of swellable packers have
been devised,
including packers that are fixed to the OD of a tubular and the elastomer
formed by wrapped
layers, and designs wherein the swellable packer is slipped over the tubular
and locked in
place.
Summary
[0004] The present disclosure provides for a temperature compensated element.
The
temperature compensated element may include a mandrel. The mandrel may be
generally
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tubular and may have a central axis and an exterior cylindrical surface. The
temperature
compensated element may further include a housing coupled to the mandrel. The
housing may
define a fluid expansion chamber between an inner wall of the housing and the
exterior
cylindrical surface of the mandrel. The temperature compensated element may
further include
a piston positioned about the mandrel. The piston may have a piston head
positioned within
the fluid expansion chamber and adapted to slide along the mandrel. The piston
head may
form a seal against the housing and the mandrel to enclose the fluid expansion
chamber. The
temperature compensated element may further include a thermally expanding
fluid positioned
within the fluid expansion chamber. The temperature compensated element may
further
include an end ring positioned about the mandrel. The end ring may be coupled
to the piston.
The end ring may be adapted to slide along the mandrel in response to a
sliding of the piston.
The temperature compensated element may further include a degradable ring
coupled to the
mandrel. The degradable ring may be positioned adjacent to the end ring and
adapted to
prevent sliding of the end ring before the degradable ring has at least
partially dissolved. The
temperature compensated element may further include a packer including a
packer element
coupled to the exterior cylindrical surface of the mandrel. The packer may
have a first end and
a second end. The first end may be adapted to slide along the mandrel in
response to a sliding
of the end ring. The second end may be fixedly coupled to the mandrel, so that
a sliding of the
first end of the packer toward the second end causes the packer element to
decrease in length
and increase in radius.
[0005] The present disclosure also provides for a method of isolating a
section of wellbore.
The method may include providing a temperature compensated element. The
temperature
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compensated element may include a mandrel. The mandrel may be generally
tubular and may
have a central axis and an exterior cylindrical surface. The temperature
compensated element
may further include a housing coupled to the mandrel. The housing may define a
fluid
expansion chamber between an inner wall of the housing and the exterior
cylindrical surface
of the mandrel. The temperature compensated element may further include a
piston positioned
about the mandrel. The piston may have a piston head positioned within the
fluid expansion
chamber and adapted to slide along the mandrel. The piston head may form a
seal against the
housing and the mandrel to enclose the fluid expansion chamber. The
temperature
compensated element may further include a thermally expanding fluid positioned
within the
fluid expansion chamber. The temperature compensated element may further
include an end
ring positioned about the mandrel. The end ring may be coupled to the piston.
The end ring
may be adapted to slide along the mandrel in response to a sliding of the
piston. The
temperature compensated element may further include a degradable ring coupled
to the
mandrel. The degradable ring may be positioned adjacent to the end ring and
adapted to
prevent sliding of the end ring before the degradable ring has at least
partially dissolved. The
temperature compensated element may further include a packer including a
packer element
coupled to the exterior cylindrical surface of the mandrel. The packer may
have a first end and
a second end. The first end may be adapted to slide along the mandrel in
response to a sliding
of the end ring. The second end may be fixedly coupled to the mandrel. The
method may
further include coupling the temperature compensated element to a downhole
tubular
assembly, running the downhole tubular assembly into a wellbore, and heating
the downhole
tubular assembly. The method may also include dissolving the degradable ring.
The method
may further include expanding the thermally expanding fluid, causing the
piston, end ring, and
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first end of the packer to move along mandrel so that the packer element
decreases in length
and increases in radius, defining an actuated position. The method may further
include
contacting the wellbore with the outer surface of the packer.
[0006] The present disclosure also provides for a delayed compensation
element. The delayed
compensation element may include a mandrel. The mandrel may be generally
tubular and may
have a central axis and an exterior cylindrical surface. The delayed
compensation element may
further include a housing coupled to the mandrel. The delayed compensation
element may
further include an end ring positioned about the mandrel. The end ring may be
adapted to slide
along the mandrel. The delayed compensation element may further include a
spring positioned
between the housing and the end ring. The spring may be adapted to force the
end ring away
from the housing. The delayed compensation element may further include a
degradable ring
coupled to the mandrel. The degradable ring may be positioned adjacent to the
end ring and
adapted to prevent sliding of the end ring before the degradable ring has at
least partially
dissolved. The delayed compensation element may further include a packer
including a packer
element coupled to the exterior cylindrical surface of the mandrel. The packer
may have a first
end and a second end. The first end may be adapted to slide along the mandrel
in response to a
sliding of the end ring. The second end may be fixedly coupled to the mandrel,
so that a
sliding of the first end of the packer toward the second end causes the packer
element to
decrease in length and increase in radius.
Brief Description of the Drawings
[0007] The present disclosure is best understood from the following detailed
description when
read with the accompanying figures. It is emphasized that, in accordance with
the standard
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practice in the industry, various features are not drawn to scale. In fact,
the dimensions of the
various features may be arbitrarily increased or reduced for clarity of
discussion.
[0008] FIG. 1 is an elevation view of a temperature compensated element in a
run in
configuration consistent with at least one embodiment of the present
disclosure.
[0009] FIG. 2 is an elevation view of the temperature compensated element of
FIG. 1 in an
actuated configuration.
[0010] FIG. 3 is a partial quarter-section view of a piston of a temperature
compensated
element consistent with at least one embodiment of the present disclosure.
[0011] FIG. 4 is a partial cutaway view of a temperature compensated element
consistent with
at least one embodiment of the present disclosure.
[0012] FIG. 5 is a cross section of a temperature compensated element
consistent with at least
one embodiment of the present disclosure.
[0013] FIG. 6 is a cross section of the temperature compensated element of
FIG. 5.
Detailed Description
[0014] It is to be understood that the following disclosure provides many
different
embodiments, or examples, for implementing different features of various
embodiments.
Specific examples of components and arrangements are described below to
simplify the
present disclosure. These are, of course, merely examples and are not intended
to be limiting.
In addition, the present disclosure may repeat reference numerals and/or
letters in the various
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examples. This repetition is for the purpose of simplicity and clarity and
does not in itself
dictate a relationship between the various embodiments and/or configurations
discussed.
[0015] FIGS. 1 and 2 illustrate one embodiment of a temperature compensated
element 20 for
positioning downhole in a well to seal with either the interior surface of a
borehole or an
interior surface of a downhole tubular. Temperature compensated element 20 is
coupled to
mandrel 5. Mandrel 5 may be included as part of a well tubular string (not
shown). One having
ordinary skill in the art with the benefit of this disclosure will understand
that the well tubular
string may be a drill string, casing string, tubing string, or any other
suitable tubular member
for use in a wellbore, and may have multiple components including, without
limitation,
tubulars, valves, or packers without deviating from the scope of this
disclosure.
[0016] In at least one embodiment, temperature compensated element 20 may
include housing
22, end ring 24, and swellable packer 26. Swellable packer 26 may include
packer element 29.
Swellable packer 26 may include a plurality of slats 28 at either end to, for
example, form an
extrusion barrier for packer element 29, couple swellable packer 26 to mandrel
5 and help
prevent flow of the swellable packer material when in a swelled state.
Swellable packer 26
may also include retainer ring 27 positioned to, for example, couple swellable
packer 26 to
mandrel 5 and to prevent any movement of swellable packer 26 along mandrel 5.
One having
ordinary skill in the art with benefit of this disclosure will understand that
although the packer
is described as a swellable packer throughout this disclosure, a non-swellable
elastomeric
packer element may be substituted without deviating from the scope of this
disclosure.
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[0017] Housing 22, end ring 24, and swellable packer 26 may be positioned
about mandrel 5
and may be coupled thereto. As depicted in FIG. 4, housing 22 of temperature
compensated
element 20 may be coupled to mandrel 5 by set screw 21. One having ordinary
skill in the art
with the benefit of this disclosure will understand that housing 22 may be
coupled to mandrel
.. 5 by any suitable mechanism without deviating from the scope of this
invention, including
without limitation a set screw, shear wire, adhesive, etc.
[0018] Housing 22 may include a fluid expansion chamber 30. Fluid expansion
chamber 30
may be filled with a thermally expanding fluid which may volumetrically expand
in response
to an increase in temperature caused by, for example, steam being passed
through the interior
of mandrel 5 or higher temperature hydrocarbons produced within the well. In
some
embodiments, the thermally expanding fluid may be selected to remain in a
liquid phase
throughout the temperatures and pressures to which it may be exposed during
operation of
temperature compensated element 20.
[0019] As depicted in FIGS. 3, 4, fluid expansion chamber 30 may be an annular
space
defined by the outer surface of mandrel 5, the inner surface of housing 22,
and piston 32.
Housing 22 may include at least one seal 23 to fluidly seal fluid expansion
chamber 30 against
mandrel 5. Piston 32 may include a piston head 34, a piston extension 36, and
a piston
operating body 38. Piston 32 may be positioned to slide within fluid expansion
chamber 30
along the outer surface of mandrel 5 in response to a volumetric expansion of
the fluid within
.. fluid expansion chamber 30 as the fluid is heated. The fluid presses on
piston head 34, causing
a sliding displacement of piston 32 along mandrel 5. Piston head 34 may
include one or more
seals 40 positioned to prevent the fluid from escaping expansion chamber 30.
As piston 32
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moves, piston operating body 38 contacts end ring 24 and causes it to likewise
slide along
mandrel 5. The movement of end ring 24 towards swellable packer 26 causes a
compression of
swellable packer 26 along mandrel 5, which causes swellable packer 26 to
mechanically
expand in the wellbore.
[0020] As depicted in FIG. 4, end ring 24 may, in some embodiments, include a
body lock
ring 42 positioned within a recess in the interior surface of end ring 24.
Body lock ring 42 may
include teeth 44 on its interior positioned to interlock with wickers 46, here
depicted as formed
on the outer surface of mandrel. Body lock ring 42 may be positioned so that
once piston 32
has moved in response to the thermal expansion of the fluid in the fluid
expansion chamber
30, teeth 44 mesh with wickers 46 and prevent end ring 24 and piston 32 from
returning to the
run-in position from, for example, elastic reaction forces of swellable packer
26. One having
ordinary skill in the art with the benefit of this disclosure will understand
that body lock ring
42 may be positioned in other locations, such as piston extension 36, slats
28, etc. without
deviating from the scope of this disclosure. Furthermore, one having ordinary
skill in the art
with the benefit of this disclosure will understand that wickers 46 may be
formed in a separate
member and not directly in the surface of mandrel 5. One having ordinary skill
in the art with
the benefit of this disclosure will understand that body lock ring 42 may be
positioned along
mandrel 5 with wickers positioned on end ring 24, piston extension 36, or
slats 28.
[0021] Swellable packer 26 may be formed from a material which swells in
response to the
absorption of a swelling fluid, generally an oil or water-based fluid. The
composition of the
swelling fluid needed to activate swellable packer 26 may be selected with
consideration of
the intended use of the packer. For example, a packer designed to pack off an
area of a well at
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once may be either oil or water-based and activated by a fluid pumped
downhole.
Alternatively, a delayed-use packer may be positioned in a well for long
periods of time
during, for example, hydrocarbon production. A swellable packer 26 which
swells in response
to an oil-based fluid would prematurely pack off the annulus. A swellable
packer 26 which
swells in response to water would therefore be used.
[0022] When swellable packer 26 is activated, the selected swelling fluid
comes into contact
with swellable packer 26 and may be absorbed by the material. In response to
the absorption
of swelling fluid, swellable packer 26 increases in volume and eventually
contacts the
wellbore, or the inner bore of the surrounding tubular. Continued swelling of
swellable packer
26 forms a fluid seal between mandrel 5 and the wellbore or surrounding
tubular. Pressure
may then be applied from one or more ends of swellable packer 26.
[0023] Swellable packer 26 may likewise expand or contract in response to
variations in
temperature. For example, during a cycling steam stimulation (CSS) operation
or steam-
assisted gravity drainage (SAG-D) operation, high-pressure steam may be forced
through a
tool string. This steam will heat swellable packer 26 and may cause a thermal
expansion in
addition to any swelling expansion. When steam injection is halted, a
conventional swellable
packer may thermally contract, thereby potentially compromising the seal
created by the
swelling expansion of the swellable packer. As illustrated in FIG. 2 and
previously described,
swellable packer 26 may be mechanically expanded by the movement of end ring
24 as the
thermally expanding fluid in fluid expansion chamber 30 is heated. This
mechanical expansion
may, for example, compensate for any thermal contraction as swellable packer
26 cools.
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[0024] In some embodiments, housing 22 may include a pressure relief apparatus
to prevent
damage to temperature compensated element 20 caused by too much pressure
within fluid
expansion chamber 30. The pressure relief apparatus may be positioned to, at a
selected
threshold pressure, release at least some thermally expanding fluid from fluid
expansion
chamber 30 into, for example, the surrounding wellbore. In some embodiments,
the pressure
relief apparatus may include, for example and without limitation, a relief or
safety valve,
blowoff valve, or a rupture disc such as rupture disc 48 as depicted in FIG.
4. Rupture disc 48
may be positioned in the wall of fluid expansion chamber 30. Rupture disc 48
may be
calibrated to mechanically fail once the fluid in fluid expansion chamber 30
reaches a selected
threshold pressure to, for example, prevent damage to temperature compensated
element 20 or
swellable packer 26. When rupture disc 48 fails, fluid from fluid expansion
chamber 30 may
flow into the surrounding wellbore. Rupture disc 48 may be calibrated by
varying, for
example, its diameter, thickness, and by placing weakening grooves in its
structure.
[0025] In some embodiments, temperature compensated element 20 may include a
backup
system to, for example and without limitation, prevent or delay the extension
of piston 32
while in the wellbore. In some embodiments, as depicted in FIGS. 5, 6,
temperature
compensated element 20 may include at least one backup ring 50. Backup ring 50
may, in
some embodiments, be coupled between end ring 24 and swellable packer 26. In
some
embodiments, at least a part of backup ring 50 may include degradable ring 52.
Degradable
ring 52 may be formed from a material selected to be initially solid and to
degrade when
exposed to one or more selected conditions. For example and without
limitation, degradable
ring 52 may be adapted to dissolve when exposed to, for example and without
limitation, high
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temperature, oil or water based fluids, acidic or basic fluids, or by chemical
reaction with a
dissolving agent introduced into the wellbore. In some embodiments, degradable
ring 52 may
be formed from a material which requires a selected amount of time to dissolve
when exposed
to the selected conditions. For example and without limitation, in some
embodiments,
degradable ring 52 may be formed from PLA.
[0026] In some embodiments, as depicted in FIG. 5, degradable ring 52 may be
coupled to
mandrel 5. Degradable ring 52 may be positioned to prevent the extension of
end ring 24
before degradable ring 52 at least partially dissolves. Once degradable ring
52 sufficiently
dissolves, end ring 24 may be extended as discussed herein as depicted in FIG.
6.
[0027] In some embodiments, as depicted in FIG. 5, degradable ring 52 may be
contained
within encapsulation 54. In some embodiments, encapsulation 54 may surround
degradable
ring 52 to, for example and without limitation, prevent damage to degradable
ring 52 while
allowing fluid contact between degradable ring 52 and the wellbore. In some
embodiments,
encapsulation 54 may be, for example and without limitation, formed as a metal
mesh. In
some embodiments, encapsulation 54 may be formed from a material selected such
that
encapsulation 54 does not interfere with the extension of end ring 24. In some
embodiments,
encapsulation 54 may be adapted to be crushed between end ring 24 and
swellable packer 26
as depicted in FIG. 6.
[0028] One having ordinary skill in the art with the benefit of this
disclosure will understand
that backup ring 50 may be used in conjunction with any mechanism configured
to compress a
swellable packer 26 including, for example and without limitation, a spring
positioned to
11
extend end ring 24. In such an embodiment, an end ring is biased to compress a
swellable
packer as discussed hereinabove, but is prevented from moving by backup ring
50 until
degradable ring 52 has sufficiently dissolved.
[0029] In order to understand the operation of a temperature compensated
element as
described herein, an exemplary operation thereof will now be described.
Although this
example describes only a cycling steam stimulation operation, one having
ordinary skill in the
art with the benefit of this disclosure will understand that the example is
not intended to limit
use of the temperature compensated element in any way to one particular
operation, and the
temperature compensated element described may be used in other operations
without
deviating from the scope of this disclosure.
[00301 In a CSS operation, as understood in the art, high-pressure steam may
be injected into
a formation through a downhole tubular. The steam heats the formation and any
hydrocarbons
contained therein to, for example, reduce viscosity thereof and thereby allow
a higher flow
rate. Once the desired heating has been effected, the steam injection is
halted, and
hydrocarbons may flow through the tubular more rapidly than before the CSS
operation.
Cycles of heating and production may be repeated multiple times.
[00311 Temperature compensated element 20 as depicted in FIG. I may be
included as a part
of the downhole tubular assembly (not shown). In one embodiment, the downhole
tubular
assembly may be a string of production casing. Temperature compensated element
20 may be
run-into the wellbore (not shown) in the run-in position depicted in FIG. 1.
Once in position in
the wellbore, fluids in the wellbore may be absorbed by swellable packer 26.
Swellable packer
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26 volumetrically expands as swelling fluids are absorbed, causing swellable
packer 26 to
form a seal against the surrounding wellbore. Temperature compensated element
20 may be
left to expand for a period of time before enhanced recovery operations
commence, i.e. during
primary and/or secondary recovery operations. During this time, swellable
packer 26 may
operate as a normal swellable packer in the wellbore to isolate the formation
on one side of
temperature compensated element 20 from the wellbore on the other side of
temperature
compensated element 20.
[0032] At some point it may be decided to run a CSS operation. At this time,
steam may be
injected through the downhole tubular assembly including through mandrel 5 of
temperature
compensated element 20. The hot steam causes the thermally expanding fluid in
fluid
expansion chamber 30 to expand, forcing piston 32 and end ring 24 along
mandrel 5 as
previously discussed. Swellable packer 26 may be compressed along mandrel 5.
This
deformation causes swellable packer 26 to increase in radius and/or press more
firmly against
the surrounding wellbore. Once the desired expansion has been achieved, body
lock ring 42
engages wickers 46, thereby locking swellable packer 26 in the actuated
position depicted in
FIG. 2. When steam injection is halted, body lock ring 42 maintains the
actuated position even
as fluid in the fluid expansion chamber cools.
[0033] In some embodiments, temperature compensated element 20 may be heated
by fluids
within the formation naturally or artificially heated in the formation. For
example, in a SAG-D
operation as understood in the art, a temperature compensated element 20
located within the
production well may be heated by the hydrocarbons heated by the steam
injection well. In
other embodiments, produced hydrocarbons may naturally exist at a higher
temperature than
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the wellbore when drilled. Therefore, the production of the hydrocarbons
themselves may
serve to heat the fluid within temperature compensated element 20.
[0034] In embodiments utilizing a backup ring 50 as depicted in FIG. 5,
although the pressure
in fluid expansion chamber 30 has risen, backup ring 50 may prevent unwanted
or premature
extension of end ring 24. Only once degradable ring 52 has sufficiently
dissolved, by the
application of a dissolving agent, fluid, or heat as determined by the
composition of
degradable ring 52, may end ring 24 extend.
[0035] In some embodiments, rupture disc 48 may be included in the wall of
housing 22, and
may be calibrated such that the pressure necessary to achieve full actuation
will cause rupture
disc 48 to fail, allowing the pressurized fluid within fluid expansion chamber
30 to flow into
the surrounding wellbore, relieving pressure on piston 32.
[0036] In some embodiments of the invention, the fluid in fluid expansion
chamber 30 may be
heated to between 200 F and 900 F. In other embodiments, the fluid in fluid
expansion
chamber 30 may be heated to between 200 F and 650 F. In some embodiments, the
pressure
of fluid in fluid expansion chamber 30 may be increased to between 500 and
4000 psi. In other
embodiments, the pressure of fluid in fluid expansion chamber 30 may be
increased to
between 500 and 2200 psi.
[0037] The foregoing outlines features of several embodiments so that a person
of ordinary
skill in the art may better understand the aspects of the present disclosure.
Such features may
be replaced by any one of numerous equivalent alternatives, only some of which
are disclosed
herein. One of ordinary skill in the art should appreciate that they may
readily use the present
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disclosure as a basis for designing or modifying other processes and
structures for carrying out
the same purposes and/or achieving the same advantages of the embodiments
introduced
herein. One of ordinary skill in the art should also realize that such
equivalent constructions do
not depart from the spirit and scope of the present disclosure and that they
may make various
changes, substitutions, and alterations herein without departing from the
spirit and scope of the
present disclosure.
