Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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1 FRICTION BITE WITH SWELLABLE ELASTOMER ELEMENTS
2 TECHNICAL FIELD
3 The present invention relates to the field of downhole tools, and in
particular
4 to swellable packers.
BACKGROUND ART
6 In the field of hydrocarbon exploration and production, various tools are
used
7 to provide fluid seals between two components in a wellbore. Annular
barriers have been
8 designed for preventing undesirable flow of wellbore fluids in the annulus
between a
9 wellbore tubular and the inner surface of a surrounding tubular or the
borehole wall. In
many cases, the annular barriers provide a fluid seal capable of holding a
significant
11 pressure differential across its length. In one application, a wellbore
packer is formed on the
12 outer surface of a completion string that is run into an outer casing in a
first condition having
13 a particular outer diameter. When the packer is in its desired downhole
location, it is inflated
14 or expanded into contact with the inner surface of the outer casing to
create a seal in the
annulus. Similar wellbore packers have been designed for use in openhole
environments, to
16 create a seal between a tubular and the surrounding wall of the wellbore.
17 Conventional packers are actuated by mechanical or hydraulic systems. A
18 force or pressure is applied from the wellhead to move a mechanical packer
element radially
19 into contact with the surrounding surface. In an inflatable packer, fluid
is delivered from the
wellhead to inflate a chamber defined by a bladder around the tubular body.
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1 More recently, wellbore packers have been developed which include a mantle
2 of swellable material formed around the tubular. The swellable material is
selected to
3 increase in volume on exposure to at least one predetermined fluid, which
may be a
4 hydrocarbon fluid or an aqueous fluid or brine. The swellable packer may be
run to a
downhole location in its unexpanded state, where it is exposed to a wellbore
fluid and
6 caused to increase in volume. The design, dimensions, and swelling
characteristics are
7 selected such that the swellable packer element expands to create a fluid
seal in the annulus
8 to isolate one wellbore section from another. Swellable packers have several
advantages
9 over conventional packers, including passive actuation, simplicity of
construction, and
robustness in long-term isolation applications.
11 In addition, swellable packers may be designed for compliant expansion of
12 the swellable mantle into contact with a surrounding surface, such that the
force imparted on
13 the surface prevents damage to a rock formation or sandface, while still
creating an annular
14 barrier or seal. Swellable packers therefore lend themselves well to
openhole completions in
loose or weak formations.
16 The materials selected to form a swellable element in a swellable packer
vary
17 depending on the specific application. Swellable materials are elastomeric
(i.e. they display
18 mechanical and physical properties of an elastomer or natural rubber).
Where the swellable
19 mantle is designed to swell in hydrocarbons, it may comprise a material
such as an ethylene
propylene diene monomer (EPDM) rubber. Where the swellable mantle is required
to swell
21 in aqueous fluids or brines, the material for example may comprise an N-
vinyl carboxylic
22 acid amide-based cross-linked resin and a water swellable urethane in an
ethylene propylene
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1 rubber matrix. In addition, swellable elastomeric materials may be designed
to increase in
2 volume in both hydrocarbon fluids and aqueous fluids.
3 One failure mode of packing elements that seal in an annular space is
4 extrusion. Mechanical backups have been used to bridge off the extrusion gap
and help
retain the swellable packing element, but these are not always practical or
possible.
6 SUMMARY OF INVENTION
7 In one embodiment, a downhole apparatus is disclosed. The downhole tool
8 comprises a swellable element. The swellable element comprises a swellable
elastomeric
9 material selected to increase in volume on exposure to at least one
predetermined fluid; and
a first area, disposed with the swellable element and operable to increase
friction between
11 the swellable element and a surrounding surface upon swelling of the
swellable element.
12 In another embodiment, a swellable element for a downhole tool is
disclosed.
13 The swellable element comprises a swellable elastomeric material selected
to increase in
14 volume on exposure to at least one predetermined fluid; and a friction-
enhancing material,
disposed on a first annular area of an outer surface of the swellable
elastomeric material.
16 In yet another embodiment, a method of reducing axial extrusion of a
17 swellable element of a downhole tool is disclosed. The method comprises
disposing a
18 friction-enhancing material on a portion of an outer surface of the
swellable element.
19
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1 BRIEF DESCRIPTION OF DRAWINGS
2 The accompanying drawings, which are incorporated in and constitute a part
3 of this specification, illustrate an implementation of apparatus and methods
consistent with
4 the present invention and, together with the detailed description, serve to
explain advantages
and principles consistent with the invention. In the drawings,
6 Figure 1 is a cutaway view of a downhole tool according to one embodiment.
7 Figure 2 is a cutaway view of a downhole tool according to another
8 embodiment.
9 Figure 3 is a cutaway view of a downhole tool according to yet another
embodiment.
DESCRIPTION OF EMBODIMENTS
11 In the following description, for purposes of explanation, numerous
specific
12 details are set forth in order to provide a thorough understanding of the
invention. It will be
13 apparent, however, to one skilled in the art that the invention may be
practiced without these
14 specific details. In other instances, structure and devices are shown in
block diagram form in
order to avoid obscuring the invention. References to numbers without
subscripts or suffixes
16 are understood to reference all instance of subscripts and suffixes
corresponding to the
17 referenced number. Moreover, the language used in this disclosure has been
principally
18 selected for readability and instructional purposes, and may not have been
selected to
19 delineate or circumscribe the inventive subject matter, resort to the
claims being necessary to
determine such inventive subject matter. Reference in the specification to
"one embodiment"
21 or to "an embodiment" means that a particular feature, structure, or
characteristic described
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1 in connection with the embodiments is included in at least one embodiment of
the invention,
2 and multiple references to "one embodiment" or "an embodiment" should not be
understood
3 as necessarily all referring to the same embodiment.
4 FIG. 1 is a cutaway view of a portion of a swellable packer 100 according to
one embodiment. Some common features of the swellable packer known to the art
are
6 omitted for clarity of the drawing. The swellable packer 100 comprises a
central body 110,
7 such as a tubular or mandrel, about which is disposed a swellable elastomer
mantle 120. The
8 swellable mantle 120 may be formed of one or more sections as desired, using
any known
9 technique for forming a swellable mantle about a central body. In one
embodiment, the
swellable mantle 120 may be bonded or otherwise attached to the body 110. The
swellable
11 mantle 120 is formed of an elastomer designed to swell when exposed to an
aqueous
12 solution, such as water or brine, or a hydrocarbon fluid.
13 Upon insertion into the well, the elastomer of the mantle 120 swells upon
14 exposure to the fluid surrounding the packer 100 in the wellbore. As the
elastomer of the
mantle 120 swells, it expands radially outwardly, engaging a surrounding
casing or open
16 hole wellbore (not shown in FIG. 1) sealing the packer 100 in an annular
space around the
17 packer 100, typically to the casing or wellbore. The elastomer of the
mantle 120 may also
18 swell axially, and if not prevented from doing so, may extrude axially
around the other
19 elements disposed at the ends of the mantle 120, reducing the pressure that
is exerted by the
expanded mantle 120 on the surrounding casing or wellbore.
21 To prevent this extrusion, mechanical backup units 130 may be provided.
22 Axial expansion of the mantle 120 is limited by the backup units 130, which
typically
23 expand under axial pressure, reducing extrusion around the expanded backup
units.
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1 Although backup units 130 are disposed at both ends of the swellable mantle
120 as
2 illustrated in FIG 1, in some embodiments, the backup unit 130 may be
disposed at only one
3 end of the mantle 120, or a different technique for reducing extrusion may
be employed at
4 the end of the mantle 120 axially distal from the backup unit 130. Although
mechanical
backups 130 have been used to bridge off the extrusion gap and help retain the
swellable
6 packing element, these are not always practical or possible. Furthermore,
some extrusion
7 may occur around the backup units 130.
8 By increasing the friction factor between the mantle 120 and the bore, the
9 extrusion resistance is increased, and thus the pressure holding capability
of the packer 100.
Various embodiments disclosed herein use implanted mechanical components
disposed on
11 or embedded into the outer surface of the swellable mantle 120 to increase
the friction or
12 gripping capability of the mantle 120. These mechanical components may
include particles,
13 slip segments, wire-mesh sheet, etc. that would either bite into the bore,
or provide a
14 rougher, stronger surface than the swellable rubber. These mechanical
components may
increase the tensile holding capability of the element, as well as increasing
the pressure
16 holding capability of the packer 100.
17 There are different ways of increasing the friction coefficient of the
surface of
18 the mantle 120. In FIG 1, the friction enhancement is achieved by disposing
particles 140
19 onto the outer surface of the mantle 120, or embedding the particles 140
into the outer
surface. The particles 140 provide an increased friction coefficient for the
entire surface of
21 the mantle 120. As illustrated in FIG 1, the particles 140 are randomly
distributed across the
22 surface of the mantle 120. In other embodiments, the particles 140 may be
randomly
23 distributed across one or more portions of the outer surface of the mantle
120, preferably at
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1 least in areas proximal to the ends of the mantle 120, where extrusion of
the elastomer
2 around the backup units 130 may occur.
3 In yet other embodiments, the friction-enhancing particles 140 may be
4 patterned across the entire or portions of the outer surface of the mantle
120, using any
desired pattern.
6 The friction increasing particles 140 in one embodiment may comprise
7 carbide particles, designed to bite into the surrounding surface of the
casing or wellbore.
8 Other friction-enhancing particles 140 may be used that are not hard enough
to bite into the
9 surrounding surface, but which add frictional improvement to the mantle 120,
such as
elastomers or plastic particles that are harder than the elastomer forming the
mantle 120.
11 The particles 140 may be of any desired size, and the density of
distribution
12 of the particles 140 may be any desired density. The particles 140 may be
deposited on or
13 embedded into the elastomer of the mantle 120 before disposition of the
mantle 120 on the
14 body 110, or may be added after the mantle 120 is disposed on the downhole
tool 100.
In an alternate embodiment, instead of using particles 140 added to the outer
16 surface of the mantle 120, the outer surface of the mantle 120 may be
scored or roughened
17 mechanically producing random or patterned scorings or roughened areas to
increase the
18 friction coefficient of the surface of the mantle 120.
19 FIG. 2 is a cutaway view of a downhole tool 200 according to one
embodiment in which, instead of discrete particles 140, a mesh 240 is disposed
about the
21 mantle 120 to provide friction enhancement. The mesh 240 may be formed of
wire, such as a
22 stainless steel wire, or any other desired materials. As with the
embodiment of FIG 1, the
23 mesh 240 may be formed of the material hard enough to bite into the
surrounding surface of
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1 the casing or wellbore, but may alternately simply be harder than the
elastomer used to form
2 the mantle 120. The mesh 240 may be disposed on the outer surface of the
mantle 120 or
3 may be embedded into the surface of the mantle 120.
4 FIG 3 is a cutaway view of a downhole tool 300 according to yet another
embodiment. In this embodiment, one or more areas of wickers 340 may be
disposed
6 annularly about the outer diameter of the mantle 120 to provide the desired
friction
7 enhancement. As illustrated in FIG 3, six areas of wickers 340 are provided,
but the number
8 and placement of the wicker areas 340 is illustrative and by way of example
only. Any
9 number of wicker areas 340 may be placed in any desired arrangement on the
mantle 120.
Preferably, wicker areas 340 are placed proximal to the ends of the mantle 120
where
11 extrusion around backup units 130 may occur.
12 The wickers may be formed of stainless steel or any other material. In one
13 embodiment, the wickers may be formed of a material of sufficient hardness
to bite into the
14 surrounding surface. In another embodiment, the wickers do not need to be
hard enough to
bite into the surrounding surface, but simply are harder than the mantle 120,
thus increase
16 frictional drag on the mantle 120.
17 The wickers may have any desired shape configured to increased friction,
and
18 do not need to be capable of anchoring the mantle 120 to completely prevent
movement of
19 the mantle 120 relative to the surrounding surface.
Although as described above the friction-enhancing material is disposed on
21 the outer surface of the mantle 120, and other embodiments the friction-
enhancing elements,
22 whether separate particles, meshes, wickers, or other forms, may be
embedded into the
23 elastomer of the mantle 120 below the outer surface. Under pressure from
the expanded
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1 mantle 120 against the surrounding surface, the subsurface embedded friction-
enhancing
2 elements may, instead of directly engaging the surrounding surface to resist
movement,
3 pinch the elastomer of the mantle 120between the friction-enhancing elements
140, 240, or
4 340, enhancing friction between the mantle 120 and the surrounding surface.
By increasing friction between the mantle 120 and the surrounding surface,
6 the friction-enhancing elements 140, 240, and 340 reduce axial extrusion of
the elastomer of
7 the mantle 120 around the support assemblies or backup rings 130 disposed at
the ends of
8 the mantle 120. By reducing extrusion, the pressure on the surrounding
surface caused by
9 the expansion of the elastomer radially outwardly may be increased.
It is to be understood that the above description is intended to be
illustrative,
11 and not restrictive. For example, the above-described embodiments may be
used in
12 combination with each other. Many other embodiments will be apparent to
those of skill in
13 the art upon reviewing the above description. The scope of the invention
therefore should be
14 determined with reference to the appended claims, along with the full scope
of equivalents
to which such claims are entitled. In the appended claims, the terms
"including" and "in
16 which" are used as the plain-English equivalents of the respective terms
"comprising" and
17 "wherein."
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