Note: Descriptions are shown in the official language in which they were submitted.
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SEALING ELEMENT FOR DOWNHOLE TOOL
FIELD
100011 This invention relates to tools used in oil and gas wellbores. More
specifically, the
disclosure relates to expansion sealing elements used to prevent fluid flow
through an annulus
formed by a tubing within the well and the wall of the wellbore or casing.
BACKGROUND
[0002] In drilling or reworking of oil wells, a great variety of downhole
tools are used.
Downhole tools such as packers, bridge plugs and frac plugs are often used to
seal the annulus
formed by a tubing within the well and the wall of the wellbore or casing. For
example, but not
by way of limitation, it is often desirable to seal tubing or other pipe in
the casing of the well
when it is desired to pump cement or other slurry down. the tubing and force
the cement or slurry
around the annulus of the tubing or out into a formation.
[0003] The seal for the annulus is generally established by a deformable
element such as
rubber or an elastomer. A compressive force is generally applied to the
deformable element,
causing it to extrude radially outward. The element extends from the outer
portion of the mandrel
of the downhole tool to the wellbore wall or casing and seals between those
structures.
1100041 Problems are encountered in the use of downhole tools because of
variations in
wellbore or casing diameter. Thus, when a downhole tool must be lowered
through a smaller
casing and sealed in a larger casing below the smaller casing, a sealing
element that fits through
the smaller casing may be too small to adequately expand to seal the larger
size casing.
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Additionally, a sealing element of adequate size to seat the larger casing may
be too large to fit
into th.e smaller casing.
100051 Thus, while there are a number of sealing elements available, there
is a need for
further such apparatuses that can meet the needs of different well operations
utilizing different
casing sizes.
BRIEF DESCRIPTION OF THE DRAWINGS
100061 The drawings are provided to illustrate certain aspects of the
invention and should
not be used to limit or define the invention.
[00071 FIG. 1 is a front view of a sealing element in accordance with one
embodiment.
The sealing element is in the run-in or unset configuration.
[00081 FIG. 2 is a sectional view of the sealing element of FIG. 1.
[0009] FIG. 3 is a sectional view of the sealing element of FIG. I when it
is being
changed from the unset configuration to a set configuration.
100101 FIG. 4 is a sectional view of the sealing element of FIG. 1 in the
set configuration.
100111 FIG. 5 is a sectional view of the sealing element in the set
configuration. The
sealing element is set in a smaller diameter casing than that shown for FIGS.
1-4
[0012] FIG. 6 is a partial sectional view of a downhole tool incorporating
the sealing
element of one embodiment. The downhole tool is shown in its run-in or unset
position.
[0013] FIG. 7 is a partial sectional view of the downhole tool of FIG. 5
shown in its set
position.
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DETAILED DESCRIPTION
[00141
Referring now to the drawings, wherein like reference numbers are used
herein to designate like elements throughout the various views, various
embodiments are
illustrated and described. The figures are not necessarily drawn to scale, and
in some instances
the drawings have been exaggerated and/or simplified in places for
illustrative purposes only. In
the following description, the term.s "upper," "upward," "lower," "below,"
"d.ownhole" and the
like, as used herein, shall mean: in relation to the bottom or furthest extent
of the surrounding
wellbore even though the well or portions of it may be deviated or horizontal.
The terms
"inwardly" and "outwardly" are directions toward and away from, respectively,
the geometric
center of a referenced object. Where components of relatively well-known
designs are employed,
their structure and operation will not be described in detail. One of ordinary
skill in the art will.
appreciate the many possible applications and variations of the present
invention based on the
following description.
[00151
Referring now to FIGS. 1. and 2, a seal.in.g element 10 is illustrated in its
first
position. or unset position. Sealing element 10 is shown as being within a
wall 42, which can be a
casing wall or wellbore wall. Sealing element 10 comprises a first sealing
member 12 and a
second sealing member 14. Generally, each sealing member is made from a
deformable element
such as rubber or an elastorneric compound, but can be made of thermoplastic
or other various
soft defomiable materials. First sealing member 12 and second sealing member
14 are each
disposed about a mandrel 16 of a downhole tool. The sealing element 10 is set
between a first
packer shoe 18 and second packer shoe 20, or between two other barriers at
least one of which is
moveable so that compression or longitudinal pressure can be applied to the
sealing element 10.
First packer shoe 18 and second packer shoe 2.0 are also disposed about
mandrel 16
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[00161 As can best be seen from FIG. 2, first sealing member 12 is a
generally cylindrical
sealing element having an outer surface 22, an inner surface 24, a first end
26 and a second end
28. First end 26 abuts first packer shoe 18. Inner surface 24 has an inclined
i.nner wall 30 at
second end 28.
[00171 Second sealing member 14 has an outer surface 32, an inner surface
34, a first end
36 and a second end 38. Second sealing member 14 is at least partially wedged
or truncated.
conical in shape so that outer surface 32 has an inclined outer wall 40.
Inclined outer wall 40 is at
first end 26 of second sealing member 14 and adjacent second end 28 of first
sealing member 12
when sealing element 10 is in its unset position. Thus, first sealing member
12 is longitudinally
separated from second sealing member 14. By "longitudinally separated" it is
meant that the
sealing members are spaced longitudinally along mandrel 16 such that there is
only a minor
portion of overlap or no overlap of the sealing members, that is there is no
overlap that creates
any significant radial expansion and, preferably, no radial expansion of
either sealing member.
As shown in FIG. 2, inclined inner wall 30 and inclined outer wall 40 overlap
when sealing
element 10 is in its unset position; however, as will be noted, neither first
sealing member 12 nor
second sealing member 14 have any radial expansion due to the overlap.
Additionally, second
end 38 of second sealing member 14 can be wedged or truncated conical in
shape, as shown, or
can be another suitable shape such as cylindrical.
[00.181 As will be appreciated from FIG. 2, inner surface 24 and inner
surface 34 are in
contact with mandrel 16 when sealing element 10 is in its unset position.
Also, outer surface 22
and outer surface 32 are exposed to but spaced away from the wall 42 of the
wellbore, which
may be a casing wall if the wellbore is lined. Accordingly, neither outer
surface 22 nor outer
surface 32 are in contact with wall 42.
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[00191 Turning now to FIGS. 3 and 4, sealing element 10 is illustrated in
transition from
its unset position to its second or set position (FIG. 3) and is illustrated
in its set position (FIG.
4). As will be appreciated from the drawings, as packer shoes 18 and 20 exert
compression
pressure on first end 26 of first sealing member 12 and second end 38 of
second sealing member
14, the sealing members 12 and 14 move in relation to each other. During this
relative
movement, inclined inner wall 30 slides over inclined outer wall 40 causing
first sealing member
12 to stretch over second sealing member 14 and come into sealing engagement
with wall 42.
Thus, during the transition from the unset position to the set position, first
sealing member 12
moves from being longitudinally spaced from second sealing member 14 to being
radially
outward from the second sealing member such that outer surface 22 is in
sealing engagement
with waU 42. Also, when sealing element 10 is in its set position, inner
surface 24 of first sealing
member 12 is in sealing engagement with outer surface 32 of second sealing
member 14, and
inner surface 34 of second sealing member 14 is in sealing engagement with
mandrel 16.
[00201 Sealing element 10 represents a more versatile sealing element than
prior
conventional sealing elements. Although designed for a specific casing
diameter ("design size")
such as that shown in FIGS. 1-4, sealing element 10 advantageously can also be
utilized in
smaller diameter casings. As shown in FIG. 5, when sealing element 10 is used
in smaller
diameter casing it achieves sealing without the complete overlap of sealing
member 12 and
sealing member 14. Thus, the amount that first sealing member 12 stretches
over second sealing
member 14 will be determined by the casing size. As illustrated in FIG. 5,
when used in a casing
having a diameter below the design size, first sealing member 12 stretches
over second sealing
member 14 so that only a first portion 44 of first sealing member 12 is
radially outward from
second sealing member 14 with the remaining portion or second portion 46 of
first sealing
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member 12 being longitudinally spaced from second sealing member 14. In this
position, outer
surface 22 of at least the first portion. 44 of first sealing member 14 is in
sealing engagement with
wall 42 and, depending on the size of the casing, a majority or even all of
outer surface 22 can be
in sealing engagement with wall 42. Additionally, the inner surface 24 of a
second portion 46 of
first sealing member 12 is in sealing engagement with mandrel 16 and inner
surface 24 of first
portion 44 is in sealing engagement with outer surface 32 of second sealing
member 14. Inner
surface 34 of second sealing member 14 is in sealing engagement with mandrel
16.
100211 Turning now to FIGS. 6 and 7, the use of an embodiment of the
sealing element
in a downhole tool 100 is shown. While the embodiment of FIGS. 5 and 6
illustrate downhole
tool 100 as a packer tool, it should be understood that the invention is not
limited to use in
packer-type tools but is useful for any downhole tool for use in a wellbore
requiring a fluid tight
seal and is especially useful where there is a change in wellbore diameter
such that the tool and
expansion device must pass through a wellbore of smaller radius before being
received into the
wellbore where it will be placed in the set position. The latter wellbore
having a greater radius
than the wellbore of smaller radius.
00221 Accordingly, in FIGS. 6 and 7, downhole tool 100 is shown in well
comprising
first wellbore or first casing 102 having a diameter DI and a second wellbore
or second casing
104 having a diameter 132. As can bee seen, Di is less than D2. Downhole tool
100 can be
lowered into a well on tubing or can be lowered on a wire line or other means
known in the art
(not shown). FIG. 5 shows the downhole tool 100 in its unset position and FIG.
6 shows
downhole tool 100 in its set position.
[0023] Downh.ole tool 100 comprises a mandrel 106 with an outer surface
108 and inner
surface 110. Mandrel 106 will typically be a drillable material such as a
polymeric composite.
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Mandrel 106 has a bore 112 defined by inner surface 110. Mandrel 106 has upper
or top end 116
and lower or bottom end 118. Bore 112 defines a central flow passage
therethrough. An end
section 120 may comprise a mule shoe 120. Mule shoe 120 is shown as integrally
formed with
the mandrel 106 but can be a separate piece that is connected with pins to
mandrel 106. Mule
shoe 120 defines an upward facing shoulder 122 thereon.
[00241 Mandrel 106 has first or upper outer diameter 130, a second or
first-intermediate
outer diameter 132, which is a threaded outer diameter 132, a third or second-
intermediate outer
diameter 134 and a fourth or lower outer diameter 136. Shoulder 122 is defined
by and extends
between third and fourth outer diameters 134 and 136, respectively. Threads
138 are defined on
threaded outer diameter 132. A head or head portion 140 is threadedly
connected to mandrel 112
and, thus, has mating buttress threads 142 thereon.
[00251 Head portion 140 has an upper end 144 that may comprise a plug or
ball scat 146.
Head 140 has lower end 148 and has first, second and third inner diameters
150, 152 and 154,
respectively. Buttress threads 142 are defined on third inner diameter 154.
Second inner diameter
152 has a magnitude greater than first inner diameter 150 and third inner
diameter 154 has a
magnitude greater than second inner diameter 152. A shoulder 156 is defined by
and extends
between first and second inner diameters 150 and 152. Shoulder 156 and upper
end 120 of
mandrel 106 define an annular space 158 therebetween. In the embodiment
illustrated, a spacer
sleeve 160 is disposed in annular space 158. Spacer sleeve 160 has an. open
bore 162 so that fluid
may pass unobstructed therethrough into and through longitudinal central flow
passage 124.
Head portion 140 may be disconnected by unthreading from mandrel 106 so that
instead of
spacer sleeve 160, a plug may be utilized. The plug will prevent flow in
either direction and, as
such, the tool will act as a bridge plug.
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[00261 A spacer ring 164 is disposed about mandrel 106 and abuts lower end
148 of head
portion 140 so that it is axially restrained on mandrel 106. Downhol.e tool
100 further comprises
a set of expansion apparatuses 166 as described in co-pending US Patent
Application Serial
Number 14/848,323, filed January 31, 2013, the disclosure of which is hereby
incorporated by
reference. Expansion apparatuses 166 comprise first and second or upper and
lower expansion
apparatuses 167 and 168. Upper and lower expansion apparatuses 167 and 168 are
generally
identical in configuration but their orientation i.s reversed on mandrel 106.
Expansion
apparatuses 167 and 168 have slip rings 170. Slip rings 170 are segmented slip
rings and are
shown as having buttons 172 secured to the outer surface thereof. When
downhole tool 100 is
moved to the set position, as shown in FIG. 6, buttons 172 will grippingly
engage second casing
104 to secure downhole tool 100 in th.e wellbore. Buttons 172 comprise a
material of sufficient
hardness to partially penetrate second casing 104 and may be comprised of
metallic-ceramic
composite or other material of sufficient strength. Expansion apparatuses 167
and 168 further
have expansion wedges 174, which are segmented wedges. Expansion wedges 174
are likewise
disposed about mandrel 106. Further, expansion apparatuses 167 and 168 have
wedges 176,
which are disposed about mandrel 106. Wedges 176 are in contact with expansion
wedges 174.
[0027] Sealing element 10, which is an expandable sealing element, as
described above,
is disposed about mandrel 106 and has first and second sealing members 12 and
14. The
embodiment illustrates a single sealing element; however, a multiple piece
packer configuration
can be used. First and second sealing members 12 and 14 abut the ends of
wedges 176 of upper
and lower expansion apparatuses 167 and 168, respectively.
[0028] In operation, the downhole tool 100 in FIG. 6, in run-in
configuration or onset
position, is lowered into (run-in) the well by means of a work string of
tubing sections or coupled
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tubing attached to the upper end 144 of head portion 140. A setting tool can
be part of the work
string. The downhole tool 100, in its unset position, fits through first
casing 102, which has the
smaller diameter of the two casings 102 and 104. Downhole tool 100 is then
positioned in second
casing 104. When downhole tool 100 is at a desired depth in the well, the
setting tool is actuated
and it drives spacer ring 164 from its run-in configuration to the set
position shown in FIG. 7.
Spacer ring 164 as well as other components, such as wedge 176 of upper
expansion apparatus
167, can be held in place during run-in by shear pins. The axial pressure
provided by the setting
tool is sufficient to shear the shear pins to allow the components held by the
shear pins to move
to their set position.
[00291 As the distance between spacer ring 164 and the mule shoe 120 is
decreased, each
expansion apparatus 166 is longitudinally- compressed, as is sealing element
10. With sufficient
compression and sufficient resultant relative movement among the components of
the expansion
apparatuses 166 (wedges 176, expansion wedges 174 and slip rings 170) the
connections
between. the wedge segments of expansion wedge 174 are sheared and the
connections between.
the slip segments of slip ring 170 are sheared thus separating the wedge
segments from each
other and the slip segments from each other.
[0030] With subsequent relative movement among wedge 176, expansion wedge
174 and
slip ring 170, wedge 176 is slid under wedge segments of expansion wedge 174
driving them
radially outward to their expanded configuration. Similarly, the wedge
segments of expansion
wedge 174 is slid under the slip segments of slip ring 170 driving them
radially outward to their
expanded configuration so that buttons 172, or other suitable gripping
elements, grippingly
engage second casing 104. During the reduction in distance between spacer ring
164 and mule
shoe 120, first sealing member 12 and second sealing member 14 are compressed
such that first
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sealing member 12 is stretched over second sealing member 14 and first sealing
member 12 seals
against the second casing 104. FIG. 7 shows the downhole tool 100 in its set
position with
expansion apparatuses 166 in its expanded configuration and with sealing
element 10 sealed
against casing 104.
[00311 In accordance with the above description a. few exemplary
embodiments will now
be described. In a first embodiment there is provided a sealing element for a
downhole tool,
comprising a first sealing member and a second sealing member. The first
sealing member
engages the second sealing member such that the sealing element has a first
position and a
second position. In the second position, the first sealing member stretches
over the second
sealing member. In. one aspect of this embodiment, the first sealing member
can be radially
outward from the second sealing member when the sealing element is in the
second position. In.
another aspect, the sealing element moves from the first position to the
second position under
compression or tension. Also, the first sealing member can have an inner
surface with an inclined
inner wall and the second sealing member can have an outer surface with
inclined outer wall.
The inclined inner wall matches the inclined outer wall so as to facilitate
the stretching of the
first sealing member.
[00321 In a further aspect of this embodiment, when the sealing element is
in the second
position., the outer surface of the first sealing member is in sealing
engagement with a wall of a
wellbore; the inner surface of the first sealing member is in sealing
engagement with the outer
surface of the second sealing member; and the inner surface of the second
member is in sealing
engagement with a mandrel of the downhole tool.
[00331 In another embodiment, there is provided a downhole tool for use in
a we]lbore
comprising a mandrel, a first sealing member and a second sealing member. The
first sealing
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member is disposed about the mandrel. The second sealing member is disposed
about the
mandrel. When the downhole tool moves from an unset position to a set
position, the first sealing
member moves in relation to the second sealing member such that the first
sealing member
sealingly engages the wellbore. Further, when the downhole tool moves from an
unset position to
a set position, the first sealing member sealingly engages the second sealing
member and the
second sealing member sealingly engages the mandrel.
100341 In a further aspect of this embodiment, the first sealing member is
longitudinally
separated from the second sealing member when the downhole tool is in the
unset position, and
the first sealing member is radially outward from the second sealing member
when the downhole
tool is in the second position.
100351 In still a further aspect, the first sealing member stretches over
the second sealing
member when the downhole tool moves from the unset position to the set
position. Also, the first
sealing member can have an inner surface with an inclined inner wall and the
second sealing
member can have an outer surface with inclined outer wall. The inclined inner
wall matches the
inclined outer wall so as to facilitate the stretching of the first sealing
member. Additionally,
when the downhole tool moves from the unset position to the set position,
compressive forces
can be applied to the first sealing member and to the second sealing member
thus moving the
first sealing member from being longitudinally separated from the second
sealing member to
being radially outward from the second sealing member.
[00361 In another embodiment, there is provided a method of operating a
servicing tool
in a wellbore comprising:
longitudinally compressing a sealing element along a central axis, wherein the
sealing element has a first sealing member and a second sealing member and
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the compressing results in relative axial movement of the first sealing member
and the second sealing member;
upon sufficient compression, expanding the first sealing member such that it
stretches over the second sealing member and sealingly engages the wellbore.
100371 In a further aspect of this embodiment, during the relative axial
movement, the
first sealing member moves from being longitudinally separated from the second
sealing member
to being radially outward from the second sealing member. Also, after the
first sealing member
stretches over the second sealing member, the first sealing member sealingly
engages the second
sealing member. hi another aspect of this method, the first sealing member has
an inner surface
with an inclined inner wall and the second. sealing member has an outer
surface with an inclined
outer wall. The inclined inner wall matches the inclined outer wall so that
the first sealing
member stretches over the second sealing member by the inclined inner wall
moving along the
inclined outer wall.
[00381 Other embodiments will, be apparent to those skilled in the art
from a
consideration of this specification or practice of the embodiments disclosed
herein. Thus, the
foregoing specification is considered merely exemplary with the true scope
thereof being defined
by the following claims.
