Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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1 "SWELLING PACKER ASSISTED BY EXPANDER"
2
3 FIELD
4 Embodiments herein are related to downhole packers. More
particularly a packer can include at least one swellable element actuated by
an
6 agent and which can be provided as at least one of the elements of a
tandem
7 downhole packer.
8
9 BACKGROUND
Selective frac operations of multiple isolated zones can improve a
11 well's production capabilities. To isolate multiple zones of a
formation, operators
12 deploy a tool string that has a number of port subs separated by packers
into a
13 borehole through the formation. The borehole may be an open hole or may
be lined
14 with a casing having perforations. When activated, the packers isolate
the borehole
annulus into separate zones. The individual port subs can then be opened and
16 closed so that frac treatment can be applied to specific isolated zones
of the
17 formation.
18 Different types of conventional packers can been used to isolate
19 zones in the borehole. One type of packer uses a compression-set element
that
expands radially outward to the borehole wall when subjected to compression.
21 Being compression-set, the element's length is limited by practical
limitations
22 because a longer compression-set element would experience undesirable
buckling
23 and collapsing during use. However, the shorter compression-set element
may not
24 be able to adequately seal against irregularities of the surrounding
borehole wall.
1
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1
Another type of packer uses an inflatable element with a differential
2
pressure limitation to produce a seal. Inflatable packers can be significantly
more
3
costly than compression-set packers and can be more difficult to implement and
4
deploy. Yet another type of packer uses a swellable element. Once these
packers
are run into position, a fluid enlarges the element until it swells to produce
a seal
6
with the borehole wall. Unfortunately, high differential pressures or an
absence of
7
the fluid that initially caused the element to swell can compromise the
swellable
8 element's seal.
9
SUMMARY
11
In a broad aspect of the invention, a downhole packer is provided for
12
sealing an annulus, the packer comprising a body defining a bore therethrough,
a
13
first sealing element disposed on the body, an actuator movably disposed on
the
14
body adjacent the first sealing element, the actuator actuatable to compress
the first
sealing element, the first sealing element expandable radially outward when
16
compressed to produce a first seal with a surrounding surface, and a second
17
sealing element disposed on the body, the second sealing element being
18
engorgable by an agent radially outward to produce a second seal with the
19 surrounding surface.
In another broad aspect of the invention, a downhole packer is
21
provided for sealing an annulus, the packer comprising a body defining a bore
22
therethrough, first means being compressible on the body for expanding
radially
23
outward to produce a first seal with a surrounding surface, means for
actuating the
2
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1 first means, and second means being engorgable on the body by an agent
for
2 expanding radially outward to produce a second seal with the surrounding
surface.
3 In another broad aspect of the invention, a packer running
method
4 comprises running a packer into a borehole, creating a first seal in an
annulus of the
borehole with the packer by compressing a first sealing element on the packer
and
6 expanding the compressed first sealing element against a surrounding
surface, and
7 creating a second seal in the annulus of the borehole with the packer by
engorging
8 a second sealing element on the packer with an agent and expanding the
engorged
9 second sealing element against the surrounding surface.
In another broad aspect of the invention, a packer is provided for
11 sealing an annulus, the packer comprising a body defining a bore
therethrough, a
12 swellable element disposed on the body, and an expander movably disposed
on the
13 body adjacent the swellable element, wherein the expander is actuatable
to fit
14 between the swellable element and the body for expanding the swellable
element
radially outward an initial expansion amount, and wherein the swellable
element
16 being swellable in the presence of an agent downhole radially outward to
produce a
17 seal with a surrounding surface.
18 In another broad aspect of the invention, a packer is provided
for
19 sealing an annulus, the packer comprising a body defining a bore
therethrough,
means disposed on the body for swelling radially outward in the presence of an
21 agent to produce a seal with a surrounding surface; and means disposed
on the
22 body for expanding the swelling means radially outward an initial
expansion
23 amount.
3
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1 In another broad aspect, a packer actuating method comprises
2 running a packer into a wellbore, expanding a swellable element on the
packer an
3 initial expansion amount in an annulus of the wellbore; and creating a
seal in the
4 annulus of the wellbore with the swellable element by interacting the
swellable
element with an agent swelling the swellable element against a surrounding
6 surface.
7
8 BRIEF DESCRIPTION OF THE DRAWINGS
9 Figure 1A illustrates a downhole packer having tandem packer
elements for isolating zones in a borehole;
11 Figure 1B illustrates the downhole packer of FIG. 1A set in the
12 borehole;
13 Figure 2A illustrates a downhole packer having tandem packer
14 elements in partial cross-section as initially deployed downhole;
Figure 2B illustrates the downhole packer of FIG. 2A with both packer
16 elements set in the borehole;
17 Figure 2C illustrates the downhole packer of FIG. 2A in a stage
of
18 retrieval;
19 Figure 3A illustrates a downhole packer having a compression-set
packer portion and an inflatable packer portion;
21 Figures 3B-3C show alternative arrangements for packers having
22 tandem packer portions;
4
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1
Figure 4A illustrates a downhole packer having a swellable element in
2 partial cross-section deployed in a borehole;
3
Figure 4B illustrates the downhole packer of FIG. 3A in an initial stage
4 of deployment;
Figure 4C illustrates the downhole packer of FIG. 3A in a subsequent
6 stage of deployment; and
7
Figure 4D illustrates the downhole packer of FIG. 3A in a further stage
8 of deployment.
9
DETAILED DESCRIPTION
11 A
downhole packer 100 illustrated in FIG. 1A deploys in a borehole
12
10. The packer 100 can be used to isolate the annulus 12 into separate zones
for
13
treatment in a frac operation. In general, the borehole 10 may be an open hole
or
14
may be lined with a casing (not shown) having perforations. The packer 100 has
a
body 110 with first and second packer portions 120/170 disposed thereon. These
16
packer portions 120/170 are capable of different forms of sealing. In
particular, the
17
first (upper) packer portion 120 provides a compressible form of sealing and
18
includes an upper piston 130, a lower piston 140, a compression-set element
150,
19
and a lower shoulder 160. The second (lower) packer portion 170 provides an
engorgable (i.e., swellable) form of sealing and includes a swellable element
180
21 disposed on the body 110.
22
As shown in FIG. 1B and further detailed below, pumped fluid flowing
23
in the body 110 hydraulically actuates the upper packer portion 120 by forcing
the
5
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1 upper and lower pistons 130/140 towards the fixed lower shoulder 160. The
2 pistons' movements compress the compression-set element 150 and set the
3 element 150 against the inside of the borehole 10. By contrast, the
swellable
4 element 180 of the lower packer portion 170 swells and sets against the
inside of
the borehole 10 by interacting with an activating agent (e.g., well fluid,
drilling fluid,
6 or the like) and engorging the swellable element 180 in the agent's
presence.
7 When set, the elements 150/180 create dual, tandem seals to
isolate
8 the annulus into a zone above the packer 100 and a zone below. Use of the
two
9 types of packer elements 150/180 allows the best features of each type to
complement and improve the seal rating of the packer 100 between isolated
zones.
11 In particular, the compression-set element 150 provides high-pressure
containment
12 in the borehole 10, while the swellable element 180 having a longer
element can
13 accommodate irregularities in the borehole 10.
14 The downhole packer 100 is shown in further detail in FIG. 2A as
initially deployed in the borehole 10. On the packer 100, the compression-set
16 packer portion 120 can operate in a manner similar to a packer disclosed
in U.S.
17 Pat. No. 6,612,372. As discussed herein, fluid pressure can activate the
18 compression-set element 150 on the packer 100. However, other forms of
19 activation could also be used, such as mechanical activation using a
pulling tool or
the like.
21 When the packer 100 as part of a tool string is positioned to a
desired
22 location in the borehole 10, operators pump fluid down the tool string.
The pumped
23 fluid reaches the packer 100 and passes from the bore 112, through a
port 114, and
6
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1 into a lower annular chamber 146 between the body 110 and an outer piston
2 housing 144. Fluid pressure building in this chamber 146 acts against a
piston 140
3 slideably disposed on the body 110. Once the fluid pressure reaches a
4 predetermined value, shear pins 143 that initially hold the piston 140 to
the housing
110 break, freeing the piston 140 to move axially along the outside of the
body 110
6 by the applied pressure.
7 As shown in FIG. 2B, the freed piston 140 moves along the body
110,
8 and expansion portion of the piston 140 travels underneath the
compression-set
9 element 150 and expands the element 150 an initial expansion amount
closer to the
inner surface of the borehole 10. As the piston 140 then reaches a lower
position
11 relative to the outer piston housing 130, a lock ring and groove
arrangement 148
12 becomes engaged between the piston 140 and the outer piston housing 144.
Once
13 engaged, the piston 140 and the outer piston housing 144 will move
together along
14 the body 110 as one unit.
Eventually, fluid pressure reaches a predetermined value to break
16 shear pins (133; FIG. 2A) holding the upper piston 130. Once freed, the
upper
17 piston 130 can move together with the lower piston 140. Pumped fluid
passes
18 through a second port 113 into an upper annular chamber 136 and acts
against a
19 ratcheting assembly 132 of the upper piston 130. A slip ratchet with
teeth on this
ratchet assembly 132 prevents the upper piston 130 from travelling back
towards its
21 initial position against upper shoulder 138.
22 As the pistons 130 and 140 travel along the body 110, they
compress
23 the compression-set element 150 against the lower fixed shoulder 160 so
that the
7
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1 compression-set element 150 expands radially outward a subsequent
expansion
2 amount. As shown set in FIG. 2B, the second chamber 136 has increased in
3 volume, the outer piston housing 144 has axially pressed against the
element 150,
4 and the axially compressed element 150 has fully expanded in the radial
direction to
effectively seal the annulus 12 of the borehole 10.
6 In addition to the seal from the compression-set portion 120,
the
7 packer's swellable packer portion 170 also sets in the annulus 12 of the
borehole 10
8 to provide a second (tandem) seal between zones. As shown in the initial
stage of
9 FIG. 2A, the swellable element 180 of this portion 170 disposes on the
outside of
the packer's body 110 and can be a sleeve or any other suitable shape. The
11 swellable element 180 may be positioned between upper and lower rings
182 and
12 184 affixed to the body 110 with shear pins, although this may not be
necessary in
13 some implementations.
14 When initially deployed, the swellable element 180 does not
engage
the inside of the borehole 10. Once the packer 100 is located in its desired
position
16 in the borehole 10, the swellable element 180 can be set either
concurrently with
17 the activation of the compression-set packer portion 120 or sometime
before or after
18 depending on the implementation. For example, pumped fluid passed
through the
19 packer 100 to set the compression-set element 150 as discussed above can
also
cause the swellable element 180 to swell, filling the annulus 12 and engaging
the
21 inside of the borehole 10. Alternatively, the swellable element 180 may
begin
22 swelling by interacting with existing fluid downhole or with fluid
introduced at a later
23 stage of operation. Regardless of the activation method, the swellable
element 180
8
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1 becomes engorged by the activating agent and swells radially outward. As
then
2 shown in FIG. 2B, the swollen element 180 forms a secondary, tandem seal
that
3 isolates the annulus 12 in conjunction with the compression-set element
150.
4 In general, the compression-set element 150 can be composed of
any
expandable or otherwise malleable material such as metal, plastic, elastomer,
or
6 combination thereof that can stabilize the packer 100 and withstand tool
movement
7 and thermal fluctuations within the borehole 10. In addition, the
compression-set
8 element 150 can be uniform or can include grooves, ridges, indentations,
or
9 protrusions designed to allow the element 150 to conform to variations in
the shape
of the interior of the borehole 10. The swellable element 180 can be composed
of
11 an elastomeric material as detailed later that can swell in the presence
of an
12 activating agent, such as a fluid (e.g., liquid or gas) existing or
introduced downhole.
13 As intimated previously, use of the compression-set packer
portion
14 120 in combination with the swellable packer portion 170 enhances the
pressure
containment provided by the packer 100 during a frac operation. In general,
these
16 different types of packer elements 150 and 180 improve the isolation of
the
17 borehole's annulus beyond what can be achieved using just a single
packer
18 element as is common in the art. More particularly, the swellable
element 180 with
19 its increased axial length and ability to engage irregular surfaces can
enhance the
packer 100's seal by sealing against any irregularities in the borehole 10. On
the
21 other hand, the compression-set element 150 gives the packer 100 the
ability to
22 seal against higher differential pressures.
9
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1
In FIG. 2C, the packer 100 is shown during a stage of retrieval. To
2
release the activated packer 100, forces are applied to the packer 100 to
break
3
shear pins (162; FIG. 2B) that hold the lower shoulder 160 fixed to the body
110.
4
Once released, the shoulder 160 travels axially along the body 110 until it
reaches a
profile (164; FIG. 2B) on the body 110. The release of the shoulder 160
thereby
6
relaxes the compression-set element 150, allowing this packer portion 120 to
be
7
removed from the borehole 10. The ratcheting assembly 132 may also be released
8 and free to move axially along the body 110.
9
During retrieval, the removal or absence of the activating agent
downhole may allow the swellable element 180 to decrease in size, thereby
11
disengaging it from the borehole 10 and making the swellable packer portion
170
12
removable from the borehole 10. In addition or in the alternative, the forces
applied
13
to the packer 100 may also free the swellable element 180 by breaking shear
pins
14
that retain one or both of the retaining rings 182 or 184. With the rings
182/184
freed, the swollen element 180 can relax axially so this portion 170 can be
removed
16 from the borehole 10.
17
The packer 100 shown in FIG. 2A has the engorgable portion 170 that
18
uses the swellable element that swells in the presence of an activating agent.
In
19
FIG. 3A, the downhole packer 100 again has the compression-set packer portion
120 but includes an inflatable packer portion 175 rather than the swellable
portion
21
discussed previously. Here, operation of the compression-set packer portion
120
22
can be similar to that discussed previously. The inflatable packer portion 175
has
23
an inflatable sleeve or bladder 190 disposed about the body 110 and fixed at
the
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1 ends by retainers 192 and 194. The inflatable sleeve 190 can be composed
of an
2 elastomeric material reinforced with metal slats or other material. When
activated,
3 the inflatable sleeve 190 becomes engorged by an agent filing the sleeve
190 so
4 that the sleeve 190 expands radially outward to the surrounding borehole
10.
In general, the agent filing the sleeve 190 can be the fluid pumped
6 down hole. This pumped fluid enters a port 196 on the body 110 that
allows the fluid
7 from the bore 112 to fill inside the sleeve 190, causing it to expand and
seal with the
8 surrounding borehole wall. Any suitable valve arrangement 198 can be used
on the
9 port 196 to control the flow of fluid. For example, a control valve can
be used.
Alternatively, a valve that is activated using a ball drop, tubing movements,
or
11 manual manipulation by an ancillary tool can be used. In fact, control
of the inflation
12 of the inflatable packer element 190 can be linked to the operation of
the
13 compression-set packer portion 120. In this way, as fluid pressure
activates the
14 compression-set portion 120, the fluid pressure can also inflate the
inflatable packer
element 190.
16 The packer 100 as shown in FIG. 2A shows the compression-set
17 packer portion 120 on the uphole end of the packer 100 and the swellable
packer
18 portion 170 on the downhole end. As shown in FIG. 3B, the packer 100 can
have a
19 reverse arrangement. In addition, FIG. 3C shows the packer 100 having
the
compression-set packer portion 120 interposed on the body 110 between an upper
21 swellable packer portion 170A and a lower swellable packer portion 170B.
With this
22 arrangement, the high pressure differential seal created by the
compression-set
23 element 150 is complemented on both sides by the engorged seal of the
swellable
11
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1 elements 180A and 180B. Any one or both of the swellable packer portions
shown
2 in FIGS. 3B-3C could also be an inflatable packer portion as disclosed
herein.
3 To produce tandem seals to isolate zones for a frac operation,
the
4 packer 100 disclosed above uses tandem packer elements¨e.g., one
compressible
and one engorgable (i.e., swellable or inflatable). As an alternative, a
downhole
6 packer 200 illustrated in FIG. 4A has a single element 250 for isolating
zones in a
7 borehole 10. This element 250 is engorgable (Le., swellable) in the
presence of an
8 agent and may also be compressible. The swellable element 250 disposes on
the
9 packer's body 210 between an outer piston housing 230 and a lower
shoulder 260.
As shown, this swellable element 250 can be a sleeve, but it can have any
other
11 suitable shape.
12 Also on the packer 200, an upper shoulder 220 supports the outer
13 piston housing 230 on the body 210 with shear pins 222, and an inner
piston 240
14 movably positions in an annular space between the body 210 and the outer
piston
housing 230. A seal 232 attached to the body 210 fits into the annular space
16 between the body 210 and the outer piston housing 230 and separates the
space
17 into a lower chamber communicating with bore port 214 and an upper
chamber
18 communicating with an exterior port 234.
19 In an initial deployment stage shown in FIG. 4A, the packer 200
deploys in the borehole 10 to isolate the annulus 12 into separate zones that
can be
21 treated by a frac operation. When deployed, the swellable element 250
remains
22 unswelled, and the piston 240 remains in an unextended condition
retained by
12
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1 shear pins 243. Likewise, shear pins 222 hold the outer piston housing
230 in an
2 unextended condition to the upper shoulder 220.
3 In a subsequent stage of deployment shown in FIG. 4B, operators
4 pump fluid down the tubing string, and the fluid reaches the packer 200.
The fluid
pressure enters the bore port 214 from the housing's bore 212, fills an
adjacent
6 annular chamber below seal 232, and pushes against the sealed end 242 of
the
7 piston 240. With increase pressure, the shear pins (243; FIG. 4A) that
initially held
8 the piston 240 break, and the fluid pressure pushes the piston 240
downwardly. As
9 the piston 240 moves, its expansion member 244 fits behind the swellable
sleeve
250 and causes it to expand radially outward an initial expansion amount
towards
11 the surrounding borehole 10.
12 Eventually as shown in FIG. 4C, the partially expanded sleeve
250
13 interacts with an activating agent, such as drilling fluid,
hydrocarbons, or the like,
14 either introduced or existing downhole. As the activating agent
interacts with the
sleeve 250, the agent engorges the sleeve 250 and causes the sleeve 250 to
swell
16 outwardly a subsequent expansion amount to increase the sealing
capability. Being
17 fixed between the housing 230 and shoulder 260 and swelling outward from
the
18 body 210, the sleeve 250 expands radially outward to create a seal with
the
19 surrounding borehole wall.
As discussed above, the piston's expansion member 244 in expanding
21 the sleeve 250 may only fit between the packer's body 210 and the sleeve
250 so
22 that the sleeve 250 is pushed radially outward from the body 210. In
some
23 implementations, this expansion in combination with the swelling of the
sleeve 250
13
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1 may produce the desired seal with the surrounding borehole 10. In
addition to this
2 expansion and swelling, however, the packer 200 may also compress the
sleeve
3 250 against the fixed shoulder 260 to expand the swellable element 250 an
4 additional expansion amount. In this way, the seal produced can be
generated by
the initial expansion, swelling, and compression of the swellable element 250.
6 As shown in FIG. 4D, for example, an arrangement of the outer
7 housing 230, piston 240, and sleeve 250 shows how the packer 200 can both
8 expand and compresses the swollen sleeve 250 during operation. Here,
fluid
9 pressure has forced against the inner piston 240 until a lock ring and
groove
arrangement couples it to the outer piston housing 230 so that the piston 240
and
11 housing 230 can move together. With continued fluid pressure, the shear
pins (222;
12 FIG. 4C) holding the top of the outer piston housing 230 break. With the
housing
13 230 free to move, the fluid pressure against the piston 240 moves the
outer piston
14 housing 230 downward as well, and excess fluid in the chamber above the
seal 232
is allowed to exit the external port 234 on the housing 230. As the housing
230
16 moves, teeth on its ratchet mechanism 236 engage grooves on the body 210
to
17 prevent retraction, and the housing's lower end 238 compress the sleeve
250
18 against the fixed shoulder 260.
19 The packer 200 can perform the combination of enlarging,
swelling,
and compressing the swellable sleeve 250 in different orders. For example, the
21 expansion member 244 of the piston 240 can initially enlarge the sleeve
250. The
22 material of the initially expanded sleeve 250 can be swelled in the
presence of the
23 desired agent, and the packer 200 can then compress the swollen sleeve
250 to
14
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1 seal up the borehole 10. Alternatively, the expansion member 244 of the
piston 240
2 can initially enlarge the sleeve 250, and then the packer 200 may further
compress
3 the sleeve 250 in an axial direction. Then, the material of the sleeve
250 can be
4 swelled in the presence of the desired agent. Yet still, the sleeve 250
can first be
swollen, then initially expanded, and finally compressed.
6 Regardless of the order, the enlarged, swollen, and compressed
7 sleeve 250 may offer a differential pressure rating similar to that
achievable with a
8 compression-set element. Because the swellable sleeve 250 is initially
expanded
9 and swelled, the amount of compression applied to the sleeve 250 may be
less than
traditionally applied to a compression-set packer element. Consequently, the
11 swellable sleeve 250 can be made longer than conventional compression-
set
12 packer elements because it may not suffer some of the undesirable
effects of
13 buckling and collapsing. With these benefits, the swellable sleeve 250
may
14 advantageously be able to cover a significantly longer section of the
borehole and
can form a better seal against borehole irregularities than produced by
existing
16 packer elements.
17 The packer 200 can be retrieved by removing the activating agent
that
18 causes the swellable element 250 to swell. Once the agent is absent, the
19 expansion of the swellable element 250 may reduce so that it dislodges
from the
borehole 10 and allows the packer 200 to be removed. In addition, as with the
21 packer discussed previously, the lower shoulder 260 may have shear pins
(not
22 shown) that can be dislodged by jarring movements. Once freed, the
shoulder 260
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1 can move along the body 210 and enable the element 250 to relax so the
packer
2 200 can be retrieved from the borehole 10.
3 The swellable elements 180/250 disclosed above are composed of a
4 material that an activating agent engorges and causes to swell. For
example, the
material can be an elastomer, such as ethylene propylene diene M-class rubber
6 (EPDM), ethylene propylene copolymer (EPM) rubber, styrene butadiene
rubber,
7 natural rubber, ethylene propylene monomer rubber, ethylene vinylacetate
rubber,
8 hydrogenated acrylonitrile butadiene rubber, acrylonitrile butadiene
rubber, isoprene
9 rubber, chloroprene rubber and polynorbornen, nitrile, VITON
fluoroelastomer,
AFLAS fluoropolymer, KALREZID perfluoroelastomer, or other suitable material.
11 (AFLAS is a registered trademark of the Asahi Glass Co., Ltd., and
KALREZ and
12 VITON are registered trademarks of DuPont Performance Elastomers). The
13 swellable material of these elements 180/250 may or may not be encased
in
14 another expandable material that is porous or has holes.
What particular material is used for the elements 180/250 depends on
16 the particular application, the intended activating agent, and the
expected
17 environmental conditions downhole. Likewise, what activating agent is
used to
18 swell the elements 180/250 depends on the properties of the element's
material, the
19 particular application, and what fluid (liquid and gas) may be naturally
occurring or
can be injected downhole. Typically, the activating agent can be mineral-based
oil,
21 water, hydraulic oil, production fluid, drilling fluid, or any other
liquid or gas designed
22 to react with the particular material of the swellable element 180/250.
16
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1 The foregoing description of preferred and other embodiments
is not
2 intended to limit or restrict the scope or applicability of the
inventive concepts
3 conceived of by the Applicants. Although the packers disclosed herein
have been
4 described for use in a lined or open borehole, it will be appreciated
that the packers
can also be used through tubing. In exchange for disclosing the inventive
concepts
6 contained herein, the Applicants desire all patent rights afforded by
the appended
7 claims. Therefore, it is intended that the appended claims include all
modifications
8 and alterations to the full extent that they come within the scope of
the following
9 claims or the equivalents thereof.
17
