U.S. patent application number 12/835684 was filed with the patent office on 2012-01-19 for downhole packer having tandem packer elements for isolating frac zones.
Invention is credited to Henry Joe Jordan, JR., James F. Wilkin.
Application Number | 20120012342 12/835684 |
Document ID | / |
Family ID | 44279178 |
Filed Date | 2012-01-19 |
United States Patent
Application |
20120012342 |
Kind Code |
A1 |
Wilkin; James F. ; et
al. |
January 19, 2012 |
Downhole Packer Having Tandem Packer Elements for Isolating Frac
Zones
Abstract
A tandem packer seals a wellbore annulus with first and second
seals. The packer has a body defining a bore therethrough and has a
shoulder disposed on the body. A compressible element is disposed
on the body adjacent the shoulder. A piston is movably disposed on
the body adjacent the compressible element and is activated by
fluid pressure communicated through a port in the packer's bore.
When actuated, the piston fits between the compressible element and
the body to initially expand it outward. With further fluid
pressure, the piston compresses the compressible element against
the shoulder to expand the element radially outward and produce a
first seal with a surrounding surface. A swellable element also
disposed on the body is swellable in the presence of an agent and
expands radially outward to produce a second seal with the
surrounding surface.
Inventors: |
Wilkin; James F.; (Sherwood
Park, CA) ; Jordan, JR.; Henry Joe; (Willis,
TX) |
Family ID: |
44279178 |
Appl. No.: |
12/835684 |
Filed: |
July 13, 2010 |
Current U.S.
Class: |
166/387 ;
166/141 |
Current CPC
Class: |
E21B 33/1285 20130101;
E21B 23/06 20130101; E21B 33/1208 20130101; E21B 33/1243 20130101;
E21B 33/124 20130101 |
Class at
Publication: |
166/387 ;
166/141 |
International
Class: |
E21B 33/12 20060101
E21B033/12 |
Claims
1. A downhole packer for sealing an annulus, comprising: a body
defining a bore therethrough; a first sealing element disposed on
the body, an actuator movably disposed on the body adjacent the
first sealing element, the actuator actuatable to compress the
first sealing element, the first sealing element expandable
radially outward when compressed to produce a first seal with a
surrounding surface; and a second sealing element disposed on the
body, the second sealing element being engorgable by an agent
radially outward to produce a second seal with the surrounding
surface.
2. The packer of claim 1, wherein the actuator is hydraulically
actuatable by fluid pumped through the bore of the body.
3. The packer of claim 1, wherein the first sealing element
comprises a compressible sleeve disposed on the body and composed
of metal, plastic, elastomer, or combination thereof.
4. The packer of claim 1, wherein the second sealing element
comprises a swellable sleeve disposed on the body and composed of
an elastomeric material swellable by the agent selected from the
group consisting of a liquid, a gas, an oil, water, production
fluid, and drilling fluid.
5. The packer of claim 4, wherein a first shoulder on the body
retains one end of the swellable sleeve, and a second shoulder on
the body retains another end of the swellable sleeve.
6. The packer of claim 1, wherein the second sealing element
comprises an inflatable sleeve disposed on the body and inflatable
by pumped fluid as the agent filing the inflatable sleeve.
7. The packer of claim 1, wherein the first sealing element has a
first axial length along the body, and wherein the second sealing
element has a second axial length along the body that is greater
than the first axial length.
8. The packer of claim 1, wherein the second sealing element is
disposed on a downhole portion of the body, and wherein the first
sealing element is disposed on an uphole portion of the body.
9. The packer of claim 1, further comprising a third sealing
element disposed on the body so that the first sealing element is
interposed on the body between the second and third sealing
elements, the third sealing element being engorgable by the agent
radially outward to produce a third seal with the surrounding
surface.
10. The packer of claim 1, wherein the body defines a port from the
bore, and wherein the actuator comprises a piston axially movable
along the body, the piston acted upon by fluid pressure
communicating from the port, a portion of the piston fitting
between the first sealing element and the body and expanding the
first sealing element an initial expansion amount.
11. The packer of claim 10, wherein a connection temporarily
affixes the piston to the body until a predetermined fluid pressure
is applied to the piston.
12. The packer of claim 10, wherein the actuator comprises an outer
housing disposed about the body and the piston, the outer housing
being engageble by the piston and being movable with the piston,
the outer housing compressing the first sealing element against a
shoulder on the body and expanding the first sealing element a
subsequent expansion amount.
13. The packer of claim 12, wherein a connection temporarily
affixes the outer housing to the body until a predetermined fluid
pressure is applied.
14. The packer of claim 12, wherein a connection temporarily
affixes the shoulder to the body until a predetermined force is
applied.
15. A downhole packer for sealing an annulus, comprising: a body
defining a bore therethrough; first means being compressible on the
body for expanding radially outward to produce a first seal with a
surrounding surface; means for actuating the first means; and
second means being engorgable on the body by an agent for expanding
radially outward to produce a second seal with the surrounding
surface.
16. The packer of claim 15, wherein the means for actuating the
first means comprises means fitting between the first means and the
body for expanding the first means an initial expansion amount.
17. The packer of claim 16, wherein the means for actuating the
first means comprises means for compressing the first means to
expand the first means a subsequent expansion amount.
18. The packer of claim 15, wherein the second means comprises
means for swelling on the body in the presence of the agent.
19. The packer of claim 18, wherein the agent is introduced
downhole.
20. The packer of claim 18, wherein the agent is naturally
occurring downhole.
21. The packer of claim 15, wherein the second means comprises
means for inflating on the body by interaction with pumped fluid as
the agent.
22. A packer actuating method, comprising: 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
expanding the compressed first sealing element against a
surrounding surface; and creating a second seal in the annulus of
the borehole with the packer by engorging a second sealing element
on the packer with an agent and expanding the engorged second
sealing element against the surrounding surface.
23. The method of claim 22, wherein compressing the first sealing
element comprises actuating a piston disposed on the packer by
pumping fluid pressure to the packer.
24. The method of claim 23, wherein actuating the piston comprises
fitting a first portion of the piston between the first sealing
element and a body of the packer and expanding the first sealing
element an initial expansion amount.
25. The method of claim 24, wherein actuating the piston comprises
compressing the first sealing element with a second portion of the
piston against a shoulder on the packer and expanding the first
sealing element a subsequent expansion amount.
26. The method of claim 22, wherein engorging the second sealing
element comprises swelling the second sealing element by
interacting an agent with the second sealing element.
27. The method of claim 26, wherein interacting the agent comprises
pumping the agent downhole.
28. The method of claim 22, wherein interacting the agent comprises
subjecting the swellable element to the agent as naturally
occurring downhole.
29. The method of claim 22, wherein engorging the second sealing
element comprises inflating the second sealing element by filling
the second sealing element with pumped fluid as the agent.
30. The method of claim 22, wherein creating the first and second
seals comprises creating the second seal with a greater axial
length along the packer than the first seal.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is concurrently filed with U.S. patent
application Ser. No. __/______ entitled "Downhole Packer Having
Swellable Sleeve" by the same inventors, which is incorporated
herein by reference in its entirety.
BACKGROUND
[0002] Selective frac operations of multiple isolated zones can
improve a well's production capabilities. To isolate multiple zones
of a formation, operators deploy a tool string that has a number of
port subs separated by packers into a borehole through the
formation. The borehole may be an open hole or may be lined 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 closed so that frac treatment can be applied to
specific isolated zones of the formation.
[0003] Different types of conventional packers can been used to
isolate 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. Being compression-set,
the element's length is limited by practical limitations because a
longer compression-set element would experience undesirable
buckling and collapsing during use. However, the shorter
compression-set element may not be able to adequately seal against
irregularities of the surrounding borehole wall.
[0004] Another type of packer uses an inflatable element with a
differential pressure limitation to produce a seal. Inflatable
packers can be significantly more costly than compression-set
packers and can be more difficult to implement and 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 with the borehole wall. Unfortunately, high
differential pressures or an absence of the fluid that initially
caused the element to swell can compromise the swellable element's
seal.
BRIEF DESCRIPTION OF THE DRAWINGS
[0005] FIG. 1A illustrates a downhole packer having tandem packer
elements for isolating zones in a borehole.
[0006] FIG. 1B illustrates the downhole packer of FIG. 1A set in
the borehole.
[0007] FIG. 2A illustrates a downhole packer having tandem packer
elements in partial cross-section as initially deployed
downhole.
[0008] FIG. 2B illustrates the downhole packer of FIG. 2A with both
packer elements set in the borehole.
[0009] FIG. 2C illustrates the downhole packer of FIG. 2A in a
stage of retrieval.
[0010] FIG. 3A illustrates a downhole packer having a
compression-set packer portion and an inflatable packer
portion.
[0011] FIGS. 3B-3C show alternative arrangements for packers having
tandem packer portions.
[0012] FIG. 4A illustrates a downhole packer having a swellable
element in partial cross-section deployed in a borehole.
[0013] FIG. 4B illustrates the downhole packer of FIG. 3A in an
initial stage of deployment.
[0014] FIG. 4C illustrates the downhole packer of FIG. 3A in a
subsequent stage of deployment.
[0015] FIG. 4D illustrates the downhole packer of FIG. 3A in a
further stage of deployment.
DETAILED DESCRIPTION
[0016] A downhole packer 100 illustrated in FIG. 1A deploys in a
borehole 10. The packer 100 can be used to isolate the annulus 12
into separate zones for treatment in a frac operation. In general,
the borehole 10 may be an open hole or 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
packer portions 120/170 are capable of different forms of sealing.
In particular, the first (upper) packer portion 120 provides a
compressible form of sealing and includes an upper piston 130, a
lower piston 140, a compression-set element 150, 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 disposed on the body 110.
[0017] As shown in FIG. 1B and further detailed below, pumped fluid
flowing in the body 110 hydraulically actuates the upper packer
portion 120 by forcing the upper and lower pistons 130/140 towards
the fixed lower shoulder 160. The pistons' movements compress the
compression-set element 150 and set the element 150 against the
inside of the borehole 10. By contrast, the swellable 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, or the like) and engorging the
swellable element 180 in the agent's presence.
[0018] When set, the elements 150/180 create dual, tandem seals to
isolate the annulus into a zone above the packer 100 and a zone
below. Use of the two 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. In particular, the
compression-set element 150 provides high-pressure containment in
the borehole 10, while the swellable element 180 having a longer
element can accommodate irregularities in the borehole 10.
[0019] 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 packer portion 120 can operate in a manner similar
to a packer disclosed in U.S. Pat. No. 6,612,372, which is
incorporated herein by reference in its entirety. As discussed
herein, fluid pressure can activate the compression-set element 150
on the packer 100. However, other forms of activation could also be
used, such as mechanical activation using a pulling tool or the
like.
[0020] When the packer 100 as part of a tool string is positioned
to a desired location in the borehole 10, operators pump fluid down
the tool string. The pumped fluid reaches the packer 100 and passes
from the bore 112, through a port 114, and into a lower annular
chamber 146 between the body 110 and an outer piston housing 144.
Fluid pressure building in this chamber 146 acts against a piston
140 slideably disposed on the body 110. Once the fluid pressure
reaches a 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 by the applied
pressure.
[0021] As shown in FIG. 2B, the freed piston 140 moves along the
body 110, and expansion portion of the piston 140 travels
underneath the compression-set 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
relative to the outer piston housing 130, a lock ring and groove
arrangement 148 becomes engaged between the piston 140 and the
outer piston housing 144. Once engaged, the piston 140 and the
outer piston housing 144 will move together along the body 110 as
one unit.
[0022] Eventually, fluid pressure reaches a predetermined value to
break shear pins (133; FIG. 2A) holding the upper piston 130. Once
freed, the upper piston 130 can move together with the lower piston
140. Pumped fluid passes through a second port 113 into an upper
annular chamber 136 and acts against a 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 initial position against upper shoulder 138.
[0023] As the pistons 130 and 140 travel along the body 110, they
compress the compression-set element 150 against the lower fixed
shoulder 160 so that the compression-set element 150 expands
radially outward a subsequent expansion amount. As shown set in
FIG. 2B, the second chamber 136 has increased in volume, the outer
piston housing 144 has axially pressed against the element 150, and
the axially compressed element 150 has fully expanded in the radial
direction to effectively seal the annulus 12 of the borehole
10.
[0024] In addition to the seal from the compression-set portion
120, the packer's swellable packer portion 170 also sets in the
annulus 12 of the borehole 10 to provide a second (tandem) seal
between zones. As shown in the initial stage of 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 swellable element 180 may be positioned between upper
and lower rings 182 and 184 affixed to the body 110 with shear
pins, although this may not be necessary in some
implementations.
[0025] 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 in the borehole 10, the swellable
element 180 can be set either concurrently with the activation of
the compression-set packer portion 120 or sometime before or after
depending on the implementation. For example, pumped fluid passed
through the 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 inside of the borehole 10.
Alternatively, the swellable element 180 may begin swelling by
interacting with existing fluid downhole or with fluid introduced
at a later stage of operation. Regardless of the activation method,
the swellable element 180 becomes engorged by the activating agent
and swells radially outward. As then shown in FIG. 2B, the swollen
element 180 forms a secondary, tandem seal that isolates the
annulus 12 in conjunction with the compression-set element 150.
[0026] In general, the compression-set element 150 can be composed
of any expandable or otherwise malleable material such as metal,
plastic, elastomer, or combination thereof that can stabilize the
packer 100 and withstand tool movement and thermal fluctuations
within the borehole 10. In addition, the compression-set element
150 can be uniform or can include grooves, ridges, indentations, or
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 an elastomeric material as
detailed later that can swell in the presence of an activating
agent, such as a fluid (e.g., liquid or gas) existing or introduced
downhole.
[0027] As intimated previously, use of the compression-set packer
portion 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 different types of packer
elements 150 and 180 improve the isolation of the borehole's
annulus beyond what can be achieved using just a single packer
element as is common in the art. More particularly, the swellable
element 180 with 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 other hand,
the compression-set element 150 gives the packer 100 the ability to
seal against higher differential pressures.
[0028] In FIG. 2C, the packer 100 is shown during a stage of
retrieval. To release the activated packer 100, forces are applied
to the packer 100 to break shear pins (162; FIG. 2B) that hold the
lower shoulder 160 fixed to the body 110. 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 relaxes the compression-set element 150, allowing this
packer portion 120 to be removed from the borehole 10. The
ratcheting assembly 132 may also be released and free to move
axially along the body 110.
[0029] During retrieval, the removal or absence of the activating
agent downhole may allow the swellable element 180 to decrease in
size, thereby disengaging it from the borehole 10 and making the
swellable packer portion 170 removable from the borehole 10. In
addition or in the alternative, the forces applied to the packer
100 may also free the swellable element 180 by breaking shear pins
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 from the borehole 10.
[0030] The packer 100 shown in FIG. 2A has the engorgable portion
170 that uses the swellable element that swells in the presence of
an activating agent. In 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 discussed
previously. Here, operation of the compression-set packer portion
120 can be similar to that discussed previously. The inflatable
packer portion 175 has an inflatable sleeve or bladder 190 disposed
about the body 110 and fixed at the ends by retainers 192 and 194.
The inflatable sleeve 190 can be composed of an elastomeric
material reinforced with metal slats or other material. When
activated, the inflatable sleeve 190 becomes engorged by an agent
filing the sleeve 190 so that the sleeve 190 expands radially
outward to the surrounding borehole 10.
[0031] In general, the agent filing the sleeve 190 can be the fluid
pumped downhole. This pumped fluid enters a port 196 on the body
110 that allows the fluid from the bore 112 to fill inside the
sleeve 190, causing it to expand and seal with the surrounding
borehole wall. Any suitable valve arrangement 198 can be used on
the 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 manual manipulation by an ancillary
tool can be used. In fact, control of the inflation of the
inflatable packer element 190 can be linked to the operation of the
compression-set packer portion 120. In this way, as fluid pressure
activates the compression-set portion 120, the fluid pressure can
also inflate the inflatable packer element 190.
[0032] The packer 100 as shown in FIG. 2A shows the compression-set
packer portion 120 on the uphole end of the packer 100 and the
swellable packer portion 170 on the downhole end. As shown in FIG.
3B, the packer 100 can have a 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 swellable
packer portion 170A and a lower swellable packer portion 170B. With
this arrangement, the high pressure differential seal created by
the compression-set element 150 is complemented on both sides by
the engorged seal of the swellable elements 180A and 180B. Any one
or both of the swellable packer portions shown in FIGS. 3B-3C could
also be an inflatable packer portion as disclosed herein.
[0033] To produce tandem seals to isolate zones for a frac
operation, the 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 packer 200
illustrated in FIG. 4A has a single element 250 for isolating zones
in a borehole 10. This element 250 is engorgable (i.e., swellable)
in the presence of an agent and may also be compressible. The
swellable element 250 disposes on the 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
suitable shape.
[0034] Also on the packer 200, an upper shoulder 220 supports the
outer piston housing 230 on the body 210 with shear pins 222, and
an inner piston 240 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 between the body 210
and the outer piston housing 230 and separates the space into a
lower chamber communicating with bore port 214 and an upper chamber
communicating with an exterior port 234.
[0035] 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 treated by a frac operation. When
deployed, the swellable element 250 remains unswelled, and the
piston 240 remains in an unextended condition retained by shear
pins 243. Likewise, shear pins 222 hold the outer piston housing
230 in an unextended condition to the upper shoulder 220.
[0036] In a subsequent stage of deployment shown in FIG. 4B,
operators 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 annular chamber below
seal 232, and pushes against the sealed end 242 of the piston 240.
With increase pressure, the shear pins (243; FIG. 4A) that
initially held the piston 240 break, and the fluid pressure pushes
the piston 240 downwardly. As 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 the
surrounding borehole 10.
[0037] Eventually as shown in FIG. 4C, the partially expanded
sleeve 250 interacts with an activating agent, such as drilling
fluid, hydrocarbons, or the like, 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 outwardly a subsequent expansion amount to increase the
sealing capability. Being fixed between the housing 230 and
shoulder 260 and swelling outward from the body 210, the sleeve 250
expands radially outward to create a seal with the surrounding
borehole wall.
[0038] As discussed above, the piston's expansion member 244 in
expanding the sleeve 250 may only fit between the packer's body 210
and the sleeve 250 so that the sleeve 250 is pushed radially
outward from the body 210. In some implementations, this expansion
in combination with the swelling of the sleeve 250 may produce the
desired seal with the surrounding borehole 10. In addition to this
expansion and swelling, however, the packer 200 may also compress
the sleeve 250 against the fixed shoulder 260 to expand the
swellable element 250 an additional expansion amount. In this way,
the seal produced can be generated by the initial expansion,
swelling, and compression of the swellable element 250.
[0039] As shown in FIG. 4D, for example, an arrangement of the
outer housing 230, piston 240, and sleeve 250 shows how the packer
200 can both expand and compresses the swollen sleeve 250 during
operation. Here, fluid 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 housing 230 can
move together. With continued fluid pressure, the shear pins (222;
FIG. 4C) holding the top of the outer piston housing 230 break.
With the housing 230 free to move, the fluid pressure against the
piston 240 moves the outer piston 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 moves,
teeth on its ratchet mechanism 236 engage grooves on the body 210
to prevent retraction, and the housing's lower end 238 compress the
sleeve 250 against the fixed shoulder 260.
[0040] The packer 200 can perform the combination of enlarging,
swelling, and compressing the swellable sleeve 250 in different
orders. For example, the expansion member 244 of the piston 240 can
initially enlarge the sleeve 250. The material of the initially
expanded sleeve 250 can be swelled in the presence of the desired
agent, and the packer 200 can then compress the swollen sleeve 250
to seal up the borehole 10. Alternatively, the expansion member 244
of the piston 240 can initially enlarge the sleeve 250, and then
the packer 200 may further compress the sleeve 250 in an axial
direction. Then, the material of the sleeve 250 can be swelled in
the presence of the desired agent. Yet still, the sleeve 250 can
first be swollen, then initially expanded, and finally
compressed.
[0041] Regardless of the order, the enlarged, swollen, and
compressed sleeve 250 may offer a differential pressure rating
similar to that achievable with a compression-set element. Because
the swellable sleeve 250 is initially expanded 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 swellable sleeve 250 can be made longer than
conventional compression-set packer elements because it may not
suffer some of the undesirable effects of buckling and collapsing.
With these benefits, the swellable sleeve 250 may 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 packer elements.
[0042] The packer 200 can be retrieved by removing the activating
agent that causes the swellable element 250 to swell. Once the
agent is absent, the 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 packer discussed
previously, the lower shoulder 260 may have shear pins (not shown)
that can be dislodged by jarring movements. Once freed, the
shoulder 260 can move along the body 210 and enable the element 250
to relax so the packer 200 can be retrieved from the borehole
10.
[0043] The swellable elements 180/250 disclosed above are composed
of a 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 (EPDM), ethylene propylene
copolymer (EPM) rubber, styrene butadiene rubber, natural rubber,
ethylene propylene monomer rubber, ethylene vinylacetate rubber,
hydrogenated acrylonitrile butadiene rubber, acrylonitrile
butadiene rubber, isoprene rubber, chloroprene rubber and
polynorbornen, nitrile, VITON.RTM. fluoroelastomer, AFLAS.RTM.
fluoropolymer, KALREZ.RTM. perfluoroelastomer, or other suitable
material. (AFLAS is a registered trademark of the Asahi Glass Co.,
Ltd., and KALREZ and VITON are registered trademarks of DuPont
Performance Elastomers). The swellable material of these elements
180/250 may or may not be encased in another expandable material
that is porous or has holes.
[0044] What particular material is used for the elements 180/250
depends on the particular application, the intended activating
agent, and the expected environmental conditions downhole.
Likewise, what activating agent is used to swell the elements
180/250 depends on the properties of the element's material, the
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, water, hydraulic oil,
production fluid, drilling fluid, or any other liquid or gas
designed to react with the particular material of the swellable
element 180/250.
[0045] The foregoing description of preferred and other embodiments
is not intended to limit or restrict the scope or applicability of
the inventive concepts conceived of by the Applicants. Although the
packers disclosed herein have been 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 contained herein, the Applicants desire all patent rights
afforded by the appended claims. Therefore, it is intended that the
appended claims include all modifications and alterations to the
full extent that they come within the scope of the following claims
or the equivalents thereof.
* * * * *