Note: Descriptions are shown in the official language in which they were submitted.
CA 02443311 2004-07-19
EXPANDABLE RADIALLY REDUCED TUBULAR MEMBER
BACKGROUND OF THE IN1lENTION
The present invention relates generally to operations performed in
conjunction with subterranean wells and; in an embodiment described herein,
more particularly provides methods and apparatus for interconnecting multiple
wellbores.
It is well known in the art to drill multiple intersecting wellbores, for
example, by drilling a main or parent wellbore extending to the earth's
surface
and then drilling one or more branch or lateral wellbores extending outwardly
from
the parent wellbore. However, interconnecting these wellbores at intersections
thereof still present challenges.
It is important to prevent migration of fluids between earthen formations
intersected by the wellbores, and also to isolate fluid produced from, or
injected
into, each wellbore from communication with those formations (except for the
formations into, or from, which the fluid is injected or -produced).
Hereinafter,
completion operations for production of fluid are discussed, it being
understood
that fluid may also, or alternatively, be injected into one or more of the
wellbores.
An expandable wellbore junction permits a unitized structure to be
positioned at a wellbore intersection. The expandable junction is then
expanded
to provide access to each of the wellbores therethrough. In this manner, the
unitized wellbore junction may be conveyed through the dimensional confines of
the parent wellbore, appropriately positioned at the wellbore intersection,
and
then expanded to provide a tubular portion thereof directed toward each
wellbore..
CA 02443311 2003-09-29
_2_
Unfortunately, methods and apparatus have yet to be developed which
address problems associated with utilizing expandable wellbore connectors. For
example, it would be desirable for minimal dimensional restrictions to be
presented where a liner or casing string extending into each of the wellbores
is
connected to the wellbore connector, in order to provide enhanced fluid flow
and
access therethrough. As another example, in some cases it would be desirable
to
be able to expand the wellbore connector in the parent wellbore prior to
drilling
the lateral wellbore. Additionally, it would be desirable to provide methods
and
apparatus for conveniently and advantageously attaching tubular members to the
wellbore connector. It is accordingly an object of the present invention to
provide
such methods and apparatus.
SUMMARY OF THE INVENTI~DN
In carrying out the principles of the present invention, in accordance with
an embodiment thereof, methods and apparatus are provided which facilitate
interconnection of multiple wellbores in a subterranean well.
In one aspect of the present invention, a method is provided in which a
cavity is formed in a parent wellbore prior to drilling a lateral wellbore.
The cavity
is formed below casing lining the parent wellbore. An expandable wellbore
connector is positioned in the cavity and expanded therein. The wellbore
connector may be cemented in the cavity. The parent wellbore may then be
extended, and the lateral wellbore may be drilled, by passing one or more
cutting
tools through the wellbore connector. Methods and apparatus far sealingly
engaging the wellbore connector with tubular members extending into the
CA 02443311 2003-09-29
-3-
weilbores are also provided. In an alternate method, the cavity may be formed
radially outwardly through the casing.
In another aspect of the present invention, a tubular member is sealingly
attached to a wellbore connector by outwardly deforming the tubular member
within the wellbore connector. The tubular member has a radially reduced
portion
with a sealing material carried externally on the radially reduced portion.
Vllhen
the tubular member is radially outwardly deformed, the sealing material is
radiaily
compressed between the tubular member and the wellbore connector. A grip
member or slip may also be carried on the radially reduced portion of the
tubular
member. The grip member may be circumferentiaify continuous and may be
disposed at least partially within the seating material.
In yet another aspect of the present invention, methods and apparatus for
sealingly attaching two tubular members are provided. One of the tubular
members has a radially reduced portion and a sealing material carried
externally
on the radially reduced portion. The tubular member with the radially reduced
portion is inserted into the other tubular member and the radially reduced
portion
is radially outwardly extended. This may be accornplished by any method,
including swaging, applying fluid pressure within the radialiy reduced
portion,
axially compressing a member within the radially reduced portion, etc. Outward
expansion of the radially reduced portion may also cause outward expansion of
the outer tubular member, and may cause plastic deformation of the outer
tubular
member.
CA 02443311 2003-09-29
-4-
In still another aspect of the present invention, a wellbore connector in a
parent wellbore is interconnected with a tubular structure positioned in a
parent or
lateral weilbore. A tubular member is inserted into one or both of the
wellbore
connector and the tubular structure. A radially reduced portion of the tubular
member is then radially outwardly extended to sealingly engage one or both of
the wellbore connector and the tubular structure. A minimum internal dimension
of the tubular member may thereby be increased.
In another aspect of the present invention, a packer is formed by providing
one or more radially reduced portions on a tubular body. A sealing material is
disposed externally on each of the radially reduced portions. A grip member
may
also be carried on the radially reduced portion and may be molded at least
partially into the sealing material.
In yet another aspect of the present invention, a method of forming an
opening through a sidewafl of a tubular structure lining a wellbore is
provided. A
deflection device having a substantially axially extending guide layer
outwardly
overlying a body of the deflection device is positioned in the welibore. A
cutting
tool is then displaced axially relative to the deflection device. A guide
portion of
the cutting device engages the guide layer, guiding the cutting tool to form
the
opening while cutting through the guide layer.
These and other features, advantages, benefits and objects of the present
invention will become apparent to one of ordinary skill in the art upon
careful
consideration of the detailed description of representative embodiments of the
invention hereinbelow and the accompanying drawings.
CA 02443311 2003-09-29
BRIEF DESCRIPTt~N ~F THE DRAInIINGS
FIGS. 1A-1D are schematic cross-sectional views of a first method of
interconnecting wellbores, the method embodying principles of the present
invention;
FIGS. 2A-2D are schematic cross-sectional views of a second method of
interconnecting wellbores, the method embodying principles of the present
invention;
FIGS. 3A-3B are schematic cross-sectional views of a third method of
interconnecting wellbores, the method embodying principles of the present
invention;
FIGS. 4A-4B are schematic cross-sectional views of a fourth method of
interconnecting weHbores, the method embodying principles of the present
invention;
FIGS. 5A-5D are schematic cross-sectional views of a fifth method of
interconnecting wellbores and apparatus therefor, the method and apparatus
embodying principles of the present invention;
FIGS. 6A-6B are partially elevational and partially cross-sectional views of
a sealing device embodying principles of the present invention;
FIGS. 6C-6F are somewhat enlarged cross-sectional views of alternate
forms of a grip member utilized in the sealing device of FIGS. 6A-6B
FIG. 7 is a cross-sectional view of a method of sealingly attaching tubular
members, the method embodying principles of the present invention;
CA 02443311 2003-09-29
FIG. 8 is a cross-sectional view of a packer and a first method of setting
the packer, the packer and method embodying principles of the present
invention;
FIG. 9 is a cross-sectional view of the packer of FIG. 8 and a second
method of setting the packer, the method embodying principles of the present
invention; and
FIG. 10 is a cross-sectional view of the packer of FIG. 8 and a method of
retrieving the packer, the method embodying principles of the present
invention.
~ETA1LE~ ~ESCRIPTION
Representatively illustrated in FIGS. 1A-1D is a method 10 of
interconnecting wellbores which embodies principles of the present invention.
In
the following description of the method 10 and other methods and apparatus
described herein, directional terms, such as "above", "below", "upper",
"lower",
etc., are used for convenience in referring to the accompanying drawings.
Additionally, it is to be understood that the various embodiments of the
present
invention described herein may be utilized in various orientations, such as
inclined, inverted, horizontal, vertical, etc., without departing from the
principles of
the present invention.
As representatively illustrated in FIG. 1A, initial steps of the method 10
have already been performed. A parent or main wellbore 12 has been drilled
from the earth's surface. The parent wellbore 12 has been lined with
protective
casing 14, and cement 16 has been flowed into the -ar'nular space between the
casing and the wellbore above a casing shoe 18 at the lower end of the casing.
It
is, however, to be clearly understood that it is not necessary for the
wellbore 12 to
CA 02443311 2003-09-29
extend directly to the earth's surface.. Principles of the
present invention may be incorporated in a method in which
the we7_lbore 12 is actually a lateral wellbore or branch of
another wellbore.
After the casing 14 has been cemented in the wellbore
12, a radially enlarged cavity 20 is formed in the earth
below the casing shoe 18. The cavity 20 may be formed by
any known procedure, such as by dril7.ing into the earth
below the casing shoe 18 and then underreaming, hydraulic
jet cutting, explosives, etc. Thus, the cavity 20 may be
formed without milling through the casing 14.
After the cavity 20 has been formed, an expandable
wellbore connector 22 is conveyed into the wellbore l2
attached to a tubular string 24. The wellbore connector 22
is of the type which has a collapsed, contracted or
retracted configuration as shown in FIG. lA, which permits
it to be conveyed within the dimensional confines of the
casing 14, and an extended or expanded configuration as
shown in FIG. 1B, which permits it to be interconnected to
multiple tubular members, at least one of which extends
laterally outwardly therefrom. Examples of wellbore
connectors which may be utilized in the method ~10 are those
described in published European patent application
EP 0795679A2, published PCT patent application WO 97/06345,
and U.S. Patent No. 5,388,648. Other wellbore connectors,
and other types of wellbore connectors, may be utilized in
the method 10 without departing from the principles of the
present invention.
Referring now to FIG. 1B, the wellbore connector 22 is
positioned within the cavity 20. The wellbore connector 22
is oriented with respect to the wellbore
CA 02443311 2003-09-29
12, so that its lateral flow passage 26, when expanded or extended, will be
directed toward a desired lateral or branch welfbore 2$ (see FIG. 1 C). This
orientation of the wellbore connector 22 may be accomplished by any known
procedure, such as by using a gyroscope, high-side indicator, etc. An
orienting
profile 30 may be formed in, or otherwise attached to, the wellbore connector
22
to aid in the orienting operation.
The wellbore connector 22 is expanded or extended, so that at least one
lateral flow passage 26 extends outwardly therefrom: If desired, the lateral
flow
passage 26 may be swaged or otherwise made to conform to a cylindrical or
other shape, to enhance the ability to later attach and/or seal tubular
members
thereto, pass tubular members therethrough, etc.
With the wellbore connector 22 positioned in the cavity 20, oriented with
respect to the lateral wellbore 28 to be drilled, and the lateral flow passage
26
extended, cement 34 is flowed into the cavity and within the casing 14 below a
packer 32 of the tubular string 24. The packer 32 is set in the casing 14
after the
cement 34 is flowed into the cavity 20. A closure 36 may be utilized to
prevent
the cement 34 from flowing into the wellbore connector 22. A similar or
different
type of closure, or a cementing shoe, may be utilized to prevent the cement
from
flowing into a lower axial flow passage 40.
When the cement 34 has hardened, the parent weilbore 12 may be
extended by lowering a drill or cutting tool, such as the cutting tool 38
shown in
FIG. 1 C, through the tubular string 24 and the wellbore connector 22, and
drilling
through the cement 34 and into the earth below the cavity 20. In this manner,
a
CA 02443311 2003-09-29
_g_
lower parent wellbore 42 may be formed extending axially or longitudinally
from
the wellbore connector 22. If, however, the flow passage 40 is other than
axially
or longitudinally directed, the wellbore 42 may also be other than axially or
longitudinally directed as desired.
A liner, casing or other tubular member 44 is then conveyed into the
wellbore 42. The tubular member 44 is cemented in the welibore 42 and
sealingly
attached to the wellbore connector 22 at the flow passage 40 utilizing a
sealing
device 46. The sealing device 46 may be a packer, liner hanger, or any other
type of sealing device, including a sealing device described more fully below.
At this point, the lower parent wellbore 42 may be completed if desired.
For example, the tubular member 44 may be perforated opposite a formation
intersected by the wellbore 42 from which, or into which, it is desired to
produce
or inject fluid. Alternatively, completion of the wellbore 42 may be delayed
until
after drilling of the lateral wellbore 28, or performed at some other time.
Referring now to FiG. 1 C, a deflection device 48 having an upper laterally
inclined deflection surface 50 formed thereon is installed within the wellbore
connector 22. The deflection device 48 is lowered through the tubular string
24,
into the wellbore connector 22, and engaged with the orienting profile 30 (not
visible in FIG. 1 C). The orienting profile 3Q causes the deflection surface
50 to
face toward the lateral flow passage 26.
The cutting tool 38 is then lowered through the tubular string 24. The
deflection surface 50 deflects the cutting tool 38 laterally into and through
the
CA 02443311 2003-09-29
-10-
lateral flow passage 26. The lateral wellbore 28 is, thus, drilled by passing
the
cutting toot 38 through the wellbore connector 22.
Referring now to FIG. 1 D, a liner, casing or other tubular member 52 is
lowered through the wellbore connector 22 and deflected laterally by the
deflection device 48 through the flow passage 26 and into the lateral wellbore
28.
The tubular member 52 is cemented in the wellbore 28 and sealingly attached to
the wellbore connector 22 at the flow passage 26 utilizing a sealing device
54.
The sealing device 54 may be a packer, liner hanger, or any other type of
sealing
device, including a seating device described more fully below.
At this point, the lateral wellbore 28 may be completed if desired. For
example, the tubular member 52 may be perforated opposite a formation
intersected by the wellbore 28 from which, or into which, it is desired to
produce
or inject fluid. Alternatively, completion of the wellbore 28 may be delayed
until
some other time.
The deflection device 48 is retrieved from the wellbore connector 22.
However, the deflection device 48 may be installed in the wellbore connector
22
again at any time it is desired to pass tools, equipment; etc. from the
tubular string
24 into the tubular member 52.
It may now be fully appreciated that the method 10 provides a convenient
and efficient manner of interconnecting the wellbares 42, 28. The tubular
members 44, 52 being cemented in the wellbores 42, 28 and sealingly attached
to
the wellbore connector 22, which is cemented within the cavity 20, prevents
CA 02443311 2003-09-29
-11 -
migration of fluid between the wellbores 12, 42, 28. The tubular string 24 and
tubular members 44, 52 being sealingly attached to the wellbore connector 22
prevents communication between the fluids conveyed through the tubular
members and the tubular string, and any earthen formation intersected by the
wellbores 12, 42, 28 (except where the tubular members may be perforated or
otherwise configured for such fluid communication).
Referring additionally now to FIGS. 2A-21~, another method 60 of
interconnecting wellbores is representatively illustrated. The method 60 is
similar
in many respects to the method 10 described above. However, the method 60
may be utilized where it is not desired to position the wellbore junction
below
casing lining a parent wellbore.
Referring specifically to FIG. 2A, initial steps c>f the method 60 have been
performed. A parent or main wellbore 62 has been drilled from the earth's
surface. The parent wellbore 62 has been lined with protective casing 64, and
cement 66 has been flowed into the annular space between the casing and the
wellbore. ft is, however, to be clearly understood that it is not necessary
for the
wellbore 62 to extend directly to the earth's surface. Principles of the
present
invention may be incorporated in a method in which the wellbore 62 is actually
a
lateral weilbore or branch of another welibore.
After the casing 64 has been cemented in the wellbore 62, a radially
enlarged cavity 68 is formed extending radially outward from the casing. The
cavity 68 may be formed by any known procedure, such as by underreaming,
section milling, hydraulic jet cutting, explosives, etc., or a combination of
known
CA 02443311 2003-09-29
-12-
procedures, such as section milling followed by jet cutting, etc. Thus, the
cavity
68 is formed through the casing 64 and outward into or through the cement 66
surrounding the casing. The cavity 68 may also extend into the earth
surrounding
the cement 66 as representatively illustrated in FIG. 2A.
A liner, casing or other tubular member 70 may be installed in a lower
parent wellbore 72 and cemented therein. This operation may be performed
before or after the cavity 68 is formed. Alternatively, the tubular member 70
may
be conveyed into the lower parent wellbore 72 at the same time as an
expandable
weUbore connector 74 is positioned in the cavity 68 Csee FIG. 2B). As another
alternative, the tubular member 70 may be installed after the wellbore
connector
74 is cemented within the cavity 68, as described above for the method 10 in
which the tubular member 44 was installed in the lower parent wellbore 42
drilled
after the cement 34 hardened. Of course, the tubular member 44 could also be
installed in the method 10 using any of the procedures described for the
tubular
member 70 in the method 60.
Referring now to FIG. 2B, the wellbore connectar 74 is conveyed into the
wellbore 62 attached to a tubular string 76. As representatively illustrated
in FIG.
2B, the tubular member 70 is conveyed into the lower parent wellbore 72 as a
portion of the tubular string 76, it being understood what the tubular member
70
could have already have been installed therein as shown in FIG. 2A, or could
be
installed later as described above for the tubular member 44 in fihe method
10.
The wellbore connector 74 is similar fo the wellbore connector 22 described
above. However, other wellbore connectors, and other types of wellbore
CA 02443311 2003-09-29
_ 33
connectors, may be utilized in the method 60 without departing from the
principles
of the present invention.
The wellbore connector 74 is positioned within the cavity 68. The wellbore
connector 74 is oriented with respect to the wellbore 62, so that its IateraP
flow
passage 78, when expanded or extended, will be directed toward a desired
lateral
or branch welibore 80 (see FIG. 2C). This orientation of the wellbore
connector
74 may be accomplished by any known procedure, such as by using a gyroscope,
high-side indicator, etc. An orienting profile 82 (see FiG. 2D) may be formed
in,
or otherwise attached to, the wellbore connector 74 to aid in the orienting
operation. When the wellbore connector 74 has been properly oriented, a packer
84 of the tubular string 76 is set in the casing 64.
Referring now to FIG. 2G, the wellbore connector 74 is expanded or
extended, so that at least one lateral flow passage 78 extends outwardly
therefrom. If desired, the lateral flow passage 78 may be swaged or otherwise
made to conform to a cylindrical or other shape, to enhance the ability to
later
attach andlor seal tubular members thereto, pass tubular members therethrough,
etc.
FIG. 2C shows an alternate method of interconnecting the wellbore
connector 74 to the tubular member 70. Another tubular member 88 is conveyed
into the well already attached to the weiibore connector 74. The tubular
member
88 is sealingiy engaged with the tubular member 70 when the wellbore connector
74 is positioned within the cavity 68. For example, the tubular member 88 may
carry a sealing device 90 thereon for sealing engagement with the tubular
CA 02443311 2003-09-29
~14~
member 70, such as a packing stack which is stabbed into a polished bore
receptacle attached to the tubular member, etc. Alternatively, the seating
device
90 may be a conventional packer or a sealing device of the type described more
fully below.
With the wellbore connector 74 positioned in the cavity 68, oriented with
respect to the lateral wellbore 80 to be drilled, and the lateral flow passage
78
extended, cement 86 is flowed into the cavity surrounding the wellbore
connector
74. Of course, the packer 84 may be upset during the cementing operation and
then set thereafter. One or more closures, such as the closure 36 described
above, may be used to exclude cement from the flow passage 78 andlor other
portions of the wellbore connector 74.
When the cement 86 has hardened, the parent wellbore 62 may be
extended if it has not been previously extended. This operation may be
performed as described above for the method 10, or it may be accomplished by
any other procedure. If the lower parent wellbore 72 is drilled after the
wellbore
connector 74 is positioned and cemented within the cavity 68, the tubular
member
70 is then installed and cemented therein.
At this point, the lower parent welibore 72 may be completed if desired.
For example, the tubular member 70 may be perforated opposite a formation
intersected by the wellbore 72 from which, or into which, it is desired to
produce
or inject fluid. Alternatively, completion of the wellbore 72 may be delayed
until
after drilling of the lateral wellbore 80, or performed at some other time.
CA 02443311 2003-09-29
-15-
A deflection device 92 having an upper laterally inclined deflection surface
94 formed thereon is installed within the wellbore connector 74. The
deflection
device 92 is lowered through the tubular string 76, into the wellbore
connector 74,
and engaged with the orienting profile 82 (not visible in FIG. 2C, see FIG.
2D).
The orienting profile 82 causes the deflection surface 94 to face toward the
lateral
flow passage 78.
A cutting tool 96 is then lowered through the tubular string 76. The
deflection surface 94 deflects the cutting tool 96 laterally into and through
the
lateral flow passage 78. The lateral wellbore 80 is, thus, drilled by passing
the
cutting tool 96 through the welPbore connector 74.
Referring now to FiG. 2D, a liner, casing or other tubular member 98 is
lowered through the wellbore connector 74 and deflected laterally by the
deflection device 92 through the flow passage 78 and into the lateral wellbore
80.
The tubular member 98 is cemented in the wellbore 80 and sealingly attached to
the wellbore connector 74 at the flow passage 78 utilising a sealing device
100.
The sealing device 100 may be a packer, liner hanger, or any other type of
sealing device, including a sealing device described more fully below.
Note that FiG. 2D shows the tubular member 70 as if it was conveyed into
the well attached to the wellbore connector 74, as described above in relation
to
the alternate method 60 as shown in FIG. 2B. In this case, the tubular member
70 may be cemented within the lower parent wellbore 72 at the same time the
wellbore connector 74 is cemented within the cavity E:rB.
CA 02443311 2003-09-29
_ 1g ..
At this point, the lateral wellbore 80 may be completed if desired. For
example, the tubular member 98 may be perforated opposite a formation
intersected by the welibore 80 from which, or into which, it is desired to
produce
or inject fluid. Alternatively, completion of the wellbore 80 may be delayed
until
some other time.
The deflection device 92 is retrieved from 'the wellbore connector 74.
However, the deflection device 92 may be installed in the wellbore connector
74
again at any time it is desired to pass tools, equipment, etc. from the
tubular string
76 into the tubular member 98.
!t may now be fully appreciated that the method 60 provides a convenient
and efficient manner of interconnecting the wellbores 72, 80. The tubular
members 70, 98 being cemented in the wellbores 72, 80 and sealingly attached
to
the wellbore connector 74, which is cemented within the cavity 68, prevents
migration of fluid between the wellbores 62, 72, 80. The tubular string 76 and
tubular members 70, 98 being sealingly attached to the wellbore connector 74
prevents communication between the fluids conveyed through the tubular
members and the tubular string, and any earthen formation intersected by the
wellbores 62; 72, 80 (except where the tubular members may be perforated or
otherwise confrgured for such fluid communication).
Referring additionally now to FIGS. 3A~3B, another method of
interconnecting wellbores 310 is representatively illustrated. The method 110
differs from the previously described methods 10, 60 in large part in that
CA 02443311 2003-09-29
_17-
wellbores interconnected utilizing an expandable wellbore connector are not
drilled, in whole or in part, through the wellbore connector.
As shown in FIG. 3A, a parent or main wellbore 112 has protective casing
114 installed therein. Cement 116 is flowed in the annular space between the
casing 114 and the wellbore 112 and permitted to harden therein. A packer 118
having a tubular member 12Q sealingly attached therebelow and an orienting
profile 122 attached thereabove is conveyed into the wellbore 112. It is to be
clearly understood, however, that it is not necessary for these elements to be
separately formed, for the elements to be positioned ~rvith respect to each
other as
shown in FIG. 3A, or for all of these elements to be simultaneously conveyed
into
the wellbore 112. For example, the tubular member '120 may be a mandrel of the
packer 118, may be a polished bore receptacle attached to the packer, the
orienting profile 122 may be otherwise positioned, or it may be formed
directly on
the tubular member 120 or packer 118, etc.
The packer 118, tubular member 120 and orienting profile 122 are
positioned in the parent wellbore 112 below an intersection of the parent
wellbore
and a lateral or branch wellbore 124, which has not yet been drilled. The
packer
118, tubular member 120 and orienting profile 122 are oriented with respect to
the
lateral wellbore 124 and the packer is set in the casing 114.
A deflection device or whipstock 126 is then conveyed into the well and
engaged with the orienting profile 122. The orienting profile 122 causes an
upper
laterally inclined deflection surface 128 formed on the deflection device 126
to
face toward the lateral wellbore-to-be-drilled 124. Alternatively, the
deflection
CA 02443311 2003-09-29
_ 18-
device 126 could be conveyed into the well along with the packer 118, tubular
member 120 and orienting profile 122.
In a window milling operation well known to those skilled in the art, at least
one cutting tool, such as a window mill (not shown) is conveyed into the well
and
laterally deflected off of the deflection surtace 128. The cutting tool forms
a
window or opening 130 through the casing 114. One or more additional cutting
tools, such as drill bits (not shown), are then utilized to drill outwardly
from the
opening 130, thereby forming the lateral wellbore 124.
A liner, casing or other tubular member 132 is lowered into the lateral
wellbore 124 and cemented therein. The liner 132 may have a polished bore
receptacle 134 or other seal surface art an upper end thereof. The deflection
device 126 is then retrieved from the well.
Referring now to FIG. 3B, an assembly 136 is conveyed into the well. The
assembly 136 includes an upper tubular member 138, a packer 140 sealingly
attached above the tubular member 138, an expandable wellbore connector 142,
a lower tubular member 144 sealingly attached below the uvellbore connector,
and
a sealing device 146 carried at a lower end of the tubular member 144. The
wellbore connector 142 is sealingly interconnected between the tubular members
138, 144. The wellbore connector 142 may be similar to the wellbore connectors
22, 74 described above, and the sealing device 146 may be any type of sealing
device, such as packing, a packer, a sealing device described more fully
below, a
etc.
CA 02443311 2003-09-29
_19-
When conveyed into the well, the wellbore connector 142 is in its
contracted configuration, so that it is conveyable through the casing 114 or
other
restriction in the well. The tubular member 144 engages the orienting profile,
causing the wellbore connector to be rotationally oriented relative to the
lateral
wellbore 124, that is, so that a lateral flow passage 148 of the wellbore
connector,
when extended, faces toward the lateral wellbore. At this point, the sealing
device 146 may be sealingly engaged within the packer 118 or tubular member
120, for example, if the sealing device 146 is a packing stack it may be
stabbed
into a polished bore receptacle as the tubular member 144 is engaged with the
orienting profile 122. Alternatively, if the sealing device is a packer or
other type
of sealing device, it may be subsequently set within, or otherwise sealingly
engaged with, the packer 118 or tubular member 120. The packer 140 may be
set in the casing 114 once the wellbore connector '142 has been oriented with
respect to the lateral wellbore 124.
The wellbore connector 142 is extended or expanded, so that the lateral
flow passage 148 extends outwardly toward the lateral wellbore 124. A portion
of
the welibore connector 142 may extend into or through the opening 130.
A tubular member 150 is conveyed through the wellbore connector 142
and outward through the lateral flow passage 148. This operation may be
accomplished as described above, that is, by installing a deflection device
within
the welibore connector 142 to laterally deflect the tubular member 150 through
the lateral flow passage 148. Of course, other methods of conveying the
tubular
CA 02443311 2003-09-29
-20-
member 150 may be utilized without departing from the principles of the
present
invention.
The tubular member 150 has sealing devices 152, 154 carried at upper
and lower ends thereof for sealing engagement with the wellbore connector 142
and tubular member 132, respectively. The sealing devices 152, 154, or either
of
them, may be of any of the types described above, or one or both of them may
be
of the type described more fully below. If the tubular member 132 has the
polished bore receptacle 134 at its upper end, the sealing device 154 may be a
packing stack and may be sealingly engaged with the polished bore receptacle
when the tubular member 150 is displaced outwardly from the lateral flow
passage 148.
With the sealing device 146 sealingly engaged with the packer 118 or
tubular member 120, the packer 140 set within the casing 114, and the tubular
member 150 sealingly interconnected between the ~rveflbore connector 142 and
the tubular member 132, undesirable fluid migration and fluid communication
are
prevented. The wellbores 112, 124 may be completed as desired. Dote that
cement (not shown), or another cementitious material or other material with
appropriate properties, may be placed in the space surrounding the wellbore
connector 142 if desired, to strengthen the wellbore junction and for added
protection against undesirable fluid migration and fluid communication.
Referring additionally naw to t"IGS. 4A&4B another method of
interconnecting wellbores 150 is representatively illustrated. The method 160
is
similar in many respects to the method 110 described above. Elements which are
CA 02443311 2003-09-29
-21-
similar to those previously described are indicated in FIGS. 4A&4B using the
same reference numbers, with an added suffix "a".
In FIG. 4A it may be seen that the lateral wellbore 124a has been drilled by
deflecting one or more cutting tools off of a whipstock 162 attached above the
packer 118x. The whipstock 162 may be hollow, it may have an outer case and
an inner core, the inner core being relatively easily drilled through, etc.
Note,
also, that the whipstock is oriented with respect to the lateral wellbore 124a
without utilizing an orienting profle.
After the lateral wellbore 124a has been drilled, the tubular member 132a
is positioned and cemented therein. Another liner, casing or other tubular
member 164 is then conveyed into the well, and a lower end thereof laterally
deflected into the lateral wellbore 124a. A sealing device 166 carried on the
tubular member 164 lower end sealingly engages the tubular member 't 32a, and
a packer, liner hanger, or other sealing andlor anchoring device 168 carried
on
the tubular member 164 upper end is set within the casing 114x.
The tubular member 164 is then cemented within the parent and lateral
wellbores 112x, 124a. Gf course, the cement 170 may be placed surrounding the
tubular member 164 before either or both of the sealing devices 168, 166 are
sealingly engaged with the casing 114a and tubular member 132a, respectively
Note that, although the tubular members 164, 132a are shown in FIGS.
4A&4B as being separately conveyed into the well and sealingly engaged
therein,
it is to be clearly understood that the tubular members 164, 132a may actually
be
CA 02443311 2003-09-29
- 22
conveyed into the well already attached to each other, or they may be only a
single tubular member, without departing from the principles of the present
invention.
When the cement 170 has hardened, a cutting tool (not shown) is used to
form an opening 172 through a portion of the tubular member 164 which overlies
the whipstock 162 and extends laterally across the parent wellbore 112a. The
opening 172 is formed through the tubular member 164 and cement 170, and also
through the whipstock 162 inner core.
Referring naw to FIG. 4B, an assembly 174 is conveyed into the tubular
member 164. The assembly 174 includes an expandable wellbore connector
176, tubular members 178, 180, 182, and sealing devices 184, 186, 188. Each of
the tubular members 178, 180, 182 is sealingly interconnected between a
corresponding one of the sealing devices 184, 186, 188 and the wellbore
connector 176. The tubular member 180 and sealing device 186 connected at a
lateral flow passage 190 of the wellbore connector 176 may be retracted or
contracted with the lateral flow passage to permit their conveyance through
the
casing 114a and tubular member 164.
Alternatively, the representatively illustrated elements 176, 178, 180, 182,
184, 186, 188 of the assembly 174 may be conveyed separately into the tubular
member 164 and then interconnected therein, various subassemblies or
combinations of these elements may be interconnected to other subassemblies,
etc. For example, the sealing device 188 and tubular member 182 may be
initially
installed in the well and the sealing device sealingly engaged within the
packer
CA 02443311 2003-09-29
-23-
118a or tubular member 120x, and then the wellbore connector 17fi, tubular
members 178, 180 and sealing devices 184, 186 may be canveyed into the well,
the wellbore connector 176 extended or expanded, the wetlbore connector
sealingly engaged with the tubular member 182, and the sealing devices 184,
186
sealingly engaged within the tubular member 1 fi4. As another example, the
sealing device 186 and tubular member 180 may be installed in the tubular
member 164 before the remainder of the assembly 174. Thus, the sequence of
installation of the elements of the assembly 174, and the combinations of
elements installed in that sequence, may be varied without departing from the
principles of the present invention.
The wellbore connector 176 is oriented within the tubular member 1 fi4, so
that the lateral flow passage 190 is directed toward the lateral wellbore
124a. For
this purpose, an orienting profile (not shown) may be attached to the packer
118a
as described above. The sealing devices 184, 188 are seaiingly engaged within
the tubular member 164, and the tubular member 120a and/or packer 118a,
respectively.
The wellbore connector 176 is expanded or extended, the tubular member
180 and sealing device 186 extending into the tubular member 164 below the
opening 172. The sealing device 186 is then sealingly engaged within the
tubular
member 164. Note that it may be desired to displace the wellbore connector 176
while it is being expanded or extended, to facilitate passage of the tubular
member 180 and sealing device 18fi into the tubular member 164 below the
opening 172, therefore, the sealing devices 184, '188 may not be sealingly
CA 02443311 2003-09-29
_24_
engaged with the tubular member 164 and packer 118a andlor tubular member
120a, respectively, until after the wellbore connector has been expanded or
extended and the sealing device 186 has been sealingly engaged within the
tubular member 164.
Referring additionally now to FIGS. 5A-5D, another method of
interconnecting wellbores 200 is representatively illustrated. The method 200
utilizes a unique apparatus 202 for forming an opening 204 through casing 206
lining a parent or main wellbore 208.
As shown in FIG. 5A, initial steps of the method 200 have been performed.
The apparatus 202 is conveyed into the well and positioned adjacent a desired
intersection of the parent wellbore 208 and a desired lateral wellbore 210
{see
FIG. 5D). The apparatus 202 includes a deflection device or whipstock 212, an
orienting profile 214, a packer or other sealing andlor anchoring device 216,
a
tubular member 218, and a cutting tool or mill 220.
The mill 220 is shown as being attached to the whipstock 212 by means of
a shear member 222, but it is to be clearly understood that the mill and
whipstock
may be otherwise attached, and the mill and whipstock may be separately
conveyed into the well, without departing from the principles of the present
invention. Similarly, the whipstock 212 is shown as being engaged with the
orienting profile 214 as they are conveyed into the well, but the packer 216,
orienting profile and tubular member 218 may be conveyed into the well
separate
from the whipstock and mill 220. The whipstock 212 may be secured relative to
CA 02443311 2003-09-29
-25-
the orienting profile 214, packer 216 and/or tubular member 218 using a
conventional anchoring device, if desired.
The apparatus 202 is oriented relative to the desired lateral wellbore 210
and the packer 216 is set within the casing 206. With 'the whipstock engaged
with
the orienting profile 214, an upper laterally inclined deflection surface 224
of the
whipstock 212 faces toward the desired lateral wellbore 210.
Referring now to FPG. 5B, the mill 220 is displaced downwardly to shear
the shear member 222, for example, by applying the weight of a drill string or
other tubular string 226 attached thereto to the mill. The mill 220 is rotated
as a
downwardly extending generally cylindrical guide portion 228 is deflected
laterally
by the deflection surface 224. Eventually, the mill 220 is displaced
downwardly
and laterally sufficiently far for the mill to contact and form the opening
204
through the casing 206.
The whipstock 212 includes features which permit the mill 220 to
longitudinally extend the opening 204, without requiring the mill 220 to be
displaced laterally any more than that needed to cc.~t the opening through the
casing 206. Specifically, the whipstock includes a body 230 having a guide
layer
232 attached to a generally longitudinally extending guide surface 234. Thus,
the
mill 220 cuts through the guide layer 232, but does not penetrate the guide
surface 234 of the body 230. The guide layer 232 may be made of a material
having a hardness substantially less than that of the body 230, thereby
permitting
the mill 220 to relatively easily cut through the guide layer.
CA 02443311 2003-09-29
-zs-
The guide portion 228 bears against the guide layer 232 as the mill 220 is
displaced longitudinally downward, thereby preventing the mill from displacing
laterally away from the casing 206. The guide portion also prevents the mil!
220
from cutting into the guide surface 234. In this manner, the opening 204 is
cut
through the casing 208 and axially elongated by longitudinally displacing the
mill
relative to the whipstock 212.
The miff 220 may also cut through cement 236 surrounding the casing 206.
The mill 220 may cut the opening 204 sufficiently laterally outward that an
expandable wellbore connector 238 (see FIG. 5G) may be expanded or extended
therein. Alternatively, the opening 204 may be enlarged outward to form a
cavity
240 using conventional procedures, such as hydraulic jet cutting, etc., in
order to
provide sufficient space to expand or extend the wellbore connector 238.
After the opening 204 has been formed, the mill 220, drill string 226 and
whipstock 212 are retrieved from the well. The mill 220, whipstock 212 and any
anchoring device securing the whipstock to the orienting profile 214, packer
216
and/or tubular member 218 may be retrieved together or separately. For
example, the mill 220, drill string 226 and whipstock 212 may be retrieved
together by picking up on the drill string, causing the mill to engage a
structure,
such as a ring neck (not shown}, attached to the whipstock, which applies an
upwardly directed force to the whipstock and disengages the whipstock from the
orienting profile 214, packer 216 andlor tubular member 218. The packer 216,
orienting profile 214 and tubular member 218, however, remain positioned in
the
casing 206 as shown in FIG. 5~.
CA 02443311 2003-09-29
-27-
Referring now to FIG. 5C, an assembly 242 is conveyed into the well and
engaged with the orienting profile 214. The assembly 242 includes the wellbore
connector 238, an upper packer or other sealing andlor anchoring device 244, a
lower sealing device 246, an upper tubular member 248 sealingly interconnected
between the packer 244 and the welibore connector, and a lower tubular member
250 sealingly interconnected between the sealing device 246 and the wellbore
connector. Engagement of the assembly 242 with the orienting profile 214
causes a lateral flow passage 252 of the wellbore connector 238 to face toward
the opening 204 when the wellbore connector is expanded or extended as shown
in FIG. 5C.
With the wellbore connector 238 oriented as shown, the sealing device 246
is sealingly engaged with the packer 216 andlor the tubular member 218. The
packer 244 is set in the casing 206, thereby anchoring the wellbore connector
238
in the position shown in FIG. 5C. The welibore connector 238 is expanded or
extended, so that the lateral flow passage 252 extends outwardly therefrom.
Note
that cement may be placed in the space surrounding the wellbore connector 238,
as described for the methods 10 and 60 above, the parent wellbore may be
extended, etc., without departing from the principles of the present
invention.
A deflection device 254 is positioned within the wellbore connector 238.
An upper laterally inclined deflection surface 255 formed on the deflection
device
254 faces toward the flow passage 252. The deflection device 254 may be
engaged with an orienting profile 258 (see FIG. 5D) formed on, or attached to,
the
wellbore connector 238.
CA 02443311 2003-09-29
-28-
Referring now to FIG. 5C?, the lateral wellbore 210 is drilled by passing a
cutting tool (not shown) through the tubular member 248 and into the wellbore
connector 238, laterally deflecting the cutting tool off c~f the deflection
surface 256
and through the flow passage 252, and drilling into the earth. A liner,
casing, or
other tubular member 260 is then installed in the lateral wellbore 210. A
sealing
device 262 carried at an upper end of the tubular member 260 is sealingly
engaged with the wellbore connector 238 at the flow passage 252.
The tubular member 260 may be cemented within the lateral wellbore 210
at the same time, or subsequent to, placement of cement, if any, surrounding
the
wellbore connector 238. Alternatively, the tubular member 260 may be sealingly
engaged with another tubular member (not shown) previously cemented within
the lateral wellbore 210, in a manner similar to that shown in FIG. 3B and
described above.
Referring additionally now to FIGS. 6A&6B, a sealing device 266 and a
method of sealingly interconnecting tubular members 268 are representatively
illustrated. The sealing device 266 may be utilized for any of the sealing
devices
described above, and the method 268 may be utilized for sealingly
interconnecting any of the tubular members or tubular portsons of elements
described above.
Referring now to FIG. 6A, the sealing device 266 includes a tubular
member 270 having a radially reduced portion 272. A sealing material 274 is
carried externally on the radially reduced portion 272. A circumferentially
CA 02443311 2003-09-29
continuous grip member or slip 276 is also carried externally on the radially
reduced portion 272.
The sealing material 274 may be an elastomer, a non-elastomer, a metallic
sealing material, etc. The sealing material 274 may be molded onto the
radially
reduced portion 272, bonded thereto, separately fitted thereto, etc. As shown
in
FIG. 6A, the sealing material 274 is generally tubular in shape with generally
smooth inner and outer side surface, but the sealing material could have
grooves,
ridges, etc. formed thereon to enhance sealing cr~ntact between the sealing
material and the tubular member 270, or another tubular member in which it is
expanded. Additionally, backup rings (not shown) or other devices for
enhancing
performance of the seating material 274 may also be positioned on the radially
reduced portion 272.
The grip member 276 is representatively illustrated in FIG. 6A as being
molded within the sealing material 274, but the grip member could
alternatively be
separately disposed on the radially reduced portion 272, or on another
radially
reduced portion formed on the tubular member 270. The grip member 276 has a
generally diamond-shaped cross-section, with an apex 278 thereof extending
slightly outward from the sealing material 274, and an apex 280 contacting the
radially reduced portion 272.
When the radialiy reduced portion 272 is radially ouhnrardly extended, as
described more fully below, the apex 280 bites into and grips the radially
reduced
portion 272 and the apex 278 bites into and grips the tubular member or other
structure 282 (see FIG. 6B) in which the sealing device 266 is received. The
CA 02443311 2003-09-29
-30-
diamond or other shape may be used to create a metal-to-metal seal between the
tubular members 270, 282, provide axial gripping force therebetween, etc.
However, it is to be clearly understood that the grip member 276 could be
shaped
otherwise, and could grip the tubular members 270, 282 and other structures in
other manners, without departing from the principles of the present invention.
For
example, alternate shapes for the grip member 276 may be utilized to increase
gripping force, provide sealirsg ability, limit depth of penetration into
either tubular
member 270, 282, etc.
The grip member 276 extends continuously circumferentially about the
radially reduced portion 272. As it extends about the radially reduced portion
272,
the grip member 276 undulates longitudinally, as may be clearly seen in the
left
side elevational view portion of FIG. 6A. Thus, the grip member 276 is
circumferentially corrugated, which enables the grip member to be conveniently
installed on the radially reduced portion 272, prevents the grip member from
rotating relative to the radially reduced portion (that is, maintains the
apexes 278,
280 facing radially outward and inward, respectively), and permits the grip
member to expand circumferentially when the radially reduced portion is
extended
radially outward. It is, however, not necessary in keeping with the principles
of
the present invention for the grip member 276 to be circumferentially
continuous,
for the grip member to be circumferentially corrugated, or for the grip member
to
be included in the sealing device 266 at all, since the sealing device may
sealingly engage another structure without utilizing the grip member.
CA 02443311 2003-09-29
_31
The grip member 276 is shown as being made of a metallic material, such
as hardened steel, but it is to be understood that it may alternatively be
made of
any other type of material. Far example, the grip member 276 could be an
aggregate-covered non-elastomeric material, the aggregate gripping the tubular
member 270 and the structure in which it is received when the radially reduced
portion 272 is radially outwardly extended. Additionally, note that the grip
member 276 may serve as a backup for the sealing material 274, preventing
extrusion of the sealing material when fluid pressure is applied thereto.
Indeed,
multiple grip members 276 could be provided for axially straddling the sealing
material 274, so that the sealing material is confined therebetween when the
radially reduced portion 272 is radially outwardly extended.
The radially reduced portion 272 presents an internal diametrical restriction
within the tubular member 270 as representatively illustrated in FIG. 6A.
Preferably, but not necessarily, the radially reduced portion 272 presents the
minimum internal dimension of the tubular member 270, so that when the
radially
reduced portion is radially outwardly extended, the minimum internal dimension
of
the tubular member is increased thereby. In this manner, access and fluid flow
through the tubular member 270 are enhanced when the radially reduced portion
272 is radially outwardly extended.
Referring now to FIG. 6~; the sealing device 266 is representatively
illustrated received within another tubular member 282, with the radially
reduced
portion 272 radially outwardly extended. The tubular member 282 could
alternatively be another type of structure, not necessarily tubular, in which
the
CA 02443311 2003-09-29
- 32 _
radially reduced portion 272 may be extended and the sealing material 274 may
be sealingly engaged.
The grip member 276 now grippingly engages both tubular members 270,
282. The apex 280 has pierced the outer surface of the radially reduced
portion
272, and the apex 278 has pierced the inner surface of the tubular member 282.
Relative axial displacement between the tubular members 270, 282 is, thus,
prevented by the grip member 276. Additionally, since the grip member 276 is
circumferentially corrugated (or other~nrise may extend at least partially
longitudinally between the tubular members 270, 282), relative rotational
displacement between the tubular members is also prevented. It will also be
readily appreciated that the grip member 276 ray form a metal-to-metal or
other
type of seal between the tubular members 270, 282 and, thus, the grip member
may itself be a sealing material.
The sealing material 274 now extends radially outward beyond the outer
side surface of the tubular member 270 and sealingly engages the inner side
surface of the tubular member 282. Note that, prior to radially outwardly
extending the radially reduced portion 272, the sealing material 274, as well
as
the grip member 276, is radially inwardly disposed relative to the outer side
surFace of the tubular member 270 (see FIG. 6A), thus preventing damage to
these elements as the tubular member is conveyed within a well, inserted into
or
through other structures; etc.
When the radially reduced portion 272 is radially outwardly extended, a
longitudinal portion 284 of the tubular member 282 may also be radially
outwardly
CA 02443311 2003-09-29
-33-
displaced as shown in FIG. 6B. The radially reduced portion 272 is preferably,
but not necessarily, plastically deformed when it is radially outwardly
extended, so
that it remains radially outwardly extended when the force causing the outward
extension is removed. As shown in FIG. 6B, the radially reduced portion 272
may
actually extend radially outward beyond the remainder of the outer side
surface of
the remainder of the tubular member 276 when the force is removed.
The longitudinal portion 284 is also preferably, but not necessarily,
plastically deformed when it is radially outwardly displaced. In this manner,
the
longitudinal portion 284 will continue to exert a radially inwardly directed
compressive force on the sealing material 274 andlor grip member 276 when the
force causing the outward extension is removed from the radialfy reduced
portion
272.
It wih be readily appreciated by one skilled in the art that the sealing
device
266 and method 268 described above and shown in FIGS. 6A&6B permits a
tubular member to be sealingly engaged with another tubular member or other
structure utilizing very little cross-sectional thickness. Thus, minimal
internal
dimensional restriction, if any, is caused by the sealing device 266 after it
is
radially outwardly extended. Additionally, very little internal dimensions!
restriction is presented by the radially reduced portion 272, even when it has
not
been radially outwardly extended.
Representatively illustrated in FIGS. 6C-6F are examples of alternate
forms of the grip member 276. It will be readily appreciated by a person
skilled in
the art that FIGS. 6C&D demonstrate forms of the grip member 276 which limit
CA 02443311 2003-09-29
-34-
penetration of the grip member into the tubular members 270, 282, FIGS. 6~&F
demonstrate that the grip member 276 is not necessarily symmetrical in shape,
FIG. 6F demonstrates that the grip member does not necessarily penetrate the
surfaces of the tubular members, and FIG. 6E demonstrates that the grip member
may be longitudinally grooved or otherwise provided with alternate types of
gripping surfaces. Thus, the grip member 276 may have any of a variety of
shapes without departing from the principles of the present invention.
Referring additionally now to FIG. 7, a method 286 of radially outwardly
extending the sealing device 266 is representatively illustrated. The sealing
device 266 is shown in FIG. 7 in dashed lines before it is radially outwardly
extended, and in solid lines after it is radially outwardly extended.
To radially outwardly extend the sealing device 266, a tool, such as a
conventional roller swage 288 (shown schematically in dashed lines in FIG. 7)
or
other swaging tool, etc., is installed in the tubular member 270. The swage
288 is
rotated and longitudinally displaced throdgh at least the radially reduced
portion
272. The radially reduced portion 272 is thereby radially outwardly extended
and
the sealing device 266 sealingly and grippingly engages the tubular member
282.
Additionally, the swage 288 may be displaced through all or a portion of
the remainder of the tubular member 270 as shown in FIG. 7. In this manner,
the
tubular member 270 may more conveniently be installed in, passed through,
etc.,
the tubular member 282 before it is radially outwardly extended by the swage
288. Furthermore, the swage 288 may also be used to radially outwardly extend
the tubular member 282 or conform it to a shape more readily sealingiy engaged
CA 02443311 2003-09-29
_35_
by the sealing device 266. For example, if the tubular member 282 is a
previously
contracted or retracted portion of a wellbore connector (such as the tubular
structure surrounding the lateral flow passage 26 of the wellbore connector 22
shown in FIG. 1 D), which has been expanded or extended, the swage 288 may
be used to appropriately shape the flow passage 26 prior to insertion of the
tubular member 52 therethrough.
Note that, as shown in FIG. 7, after the sealing device 266 is radially
outwardly extended, the internal diameter of the tubular member 270 is at
least as
great as the internal diameter of the tubular member 282. Thus, the sealing
device 266 permits the tubular members 270, 282 to be sealingly and grippingly
engaged with each other, without presenting an internal dimensional
restriction,
even though one of the tubular members is received within, or passed through,
the other tubular member.
Referring additionally now to FIG. 8, another method of radially outwardly
extending a sealing device 290 is representatively illustrated. Additionally,
a
sealing device configured as a packer 292 is representatively illustrated.
Elements which are similar to those previously described are indicated in FIG.
8
using the same reference numbers, with an added suffix °'b".
The packer 292 includes a generally tubular member 294 having two
longitudinally spaced apart radially reduced portions 272b formed thereon. A
sealing material 274b and grip member 276b is carried externally on each of
the
radially reduced portions 272b. It is to be clearly understood, however, that
the
packer 292 may include any number of the radially reduced portions 272b,
CA 02443311 2003-09-29
-36-
sealing materials 274b and grip members 276b, including one, and that any
number of the sealing materials and grip members may be carried on one of the
radially reduced portions. For example, multiple sealing materials 274.b
andlor
grip members 276b may be disposed on one radially reduced portion 272b.
Additionally, the packer 292 may actually be configured as another type of
sealing
andlor anchoring device, such as a tubing hanger, plug, etc.
At opposite ends thereof, the tubular member 294 has latching profiles 296
formed internally thereon. Seal bores 298 are formed internally adjacent the
latching profiles 296. The latching profiles 296 and seal bores 298 permit
sealing
attachment of tubular members, tools, equipment, etc. to the packer 292. ~f
course, other attachment and sealing elements may be used in addition to, or
in
place of the latching profiles 296 and seal bores 298. For example, the packer
292 may be provided with internal or external threads at one or both ends for
interconnection of the packer in a tubular string.
As representatively depicted in FIG. 8, a setting tool 300 is latched to the
upper latching profile 296 for conveying the packer 292 into a well and
setting the
packer therein. The setting tool 300 has axially spaced apart annular
elastomeric
members 302 disposed on a generally rod-shaped mandrel 304.. An annular
spacer 306 maintains the spaced apart relationship of the elastomeric members
302. Each of the elastomeric members 302 is thus positioned radially opposite
one of the radially reduced portions 272b.
With the setting tool 300 in the configuration shown in FIG. 8, the packer
292 may be conveyed within a tubular member (not shown) in a well. However,
CA 02443311 2003-09-29
37 _
when the setting tool 300 is actuated to set the packer 292, the radially
reduced
portions 272b are radiaily outwardly extended, so that the packer sealingly
and
grippingly engages the tubular member (see FIG. 10). Radially outward
extension of the radially reduced portions 272b is accomplished by displacing
the
mandrel 304 upward as viewed in FIG. 8 relative to the portion of the setting
tool
latched to the latching profiie 296. The elastomeric members 302 will be
thereby
axially compressed between a radially enlarged portion 308 formed on the
mandrel 304, the spacer 306, and the portion of the setting tool latched to
the
upper latching profile 296. When the elastomeric members 302 are axially
compressed, they become radially enlarged, applying a radially outwardly
directed
f~rce to each of the radially reduced portions 272b.
The mandrel 304 may be upwardly displaced to compress the elastomeric
members 302 in any of a number of ways. For example, fluid pressure could be
applied to the setting tool 300 to displace a piston therein connected to the
mandrel 304, a threaded member of the setting tool engaged with the mandrel
could be rotated to displace the mandrel, etc.
Referring additionally now to FIG. 9, yet another method 310 of setting the
packer 292 is representatively illustrated. In the method 310, a setting tool
312 is
latched to the upper latching profile 296, in a manner similar that used to
latch the
setting tool 300 to the packer 292 in the method 290 described above. The
setting tool 312 includes spaced apart seals 314, 3'16, which internally
sealingly
engage the tubular member 294 above and below the radiafly reduced portions
272b. A flow passage 318 extends internally from within the setting tool 312
to
CA 02443311 2003-09-29
_38_
the annular space radially between the setting tool and the tubular member 294
and axially between the seals 314, 316.
When it is desired to set the packer 292, fluid pressure is applied to the
flow passage 318. The fluid pressure exerts a radially outwardly directed
force to
the interior of the tubular member 294 between the seals 314, 316, thereby
radially outwardly extending the radially reduceei portions 272b. The fluid
pressure may be applied to the flow passage 318 in any of a number of ways,
for
example, via a tubular string attached to the setting tool 312, combustion of
a
propellant within the setting tool, etc.
Referring additionally now to FIG. 10, the packer 292 is representatively
illustrated set within casing 322 lining a wellbore 324. The packer 292
sealingly
and grippingly engages the casing 322. Note that the casing 322 is radially
outwardly deformed opposite the radially outwardly extended radially reduced
portions 272b, but such deformation is not necessary according to the
principles
of the present invention.
FIG. 10 representatively illustrates a method 320 of upsetting the packer
292 after it has been set, so that the packer may be retrieved or otherwise
displaced from or within the well. A service tool 326 is conveyed into the
casing
322 and inserted into the packer 292. The service tool 326 is latched to the
upper
and lower latching profiles 296 in a conventional manner.
Fluid pressure is then applied to a piston 328 attached to, or formed as a
portion of, an elongated mandrel 330, which is latched to the lower latching
profile
CA 02443311 2004-07-19
_3g_
296. An axially downwardly directed force is thereby applied to the mandrel
330.
This force causes the lower end of the tubular member 294 to be displaced
axially
downward relative to the upper end thereof, axially elongating the tubular
member
and causing the tubular member to radialfy inwardly retract.
When sufficient force is applied to elongate the tubular member 294, the
sealing material 274b and grip members 276b will disengage from the casing
322,
permitting the packer 292 to be retrieved tram the well or otherwise displaced
relative to the casing. The fluid pressure may be applied to the piston 328 in
any
of a number of ways, such as via a tubular string attached to the tool 326,
combustion of a propellant within the setting tool, etc.
Of course, many modifications, additions, substitutions, deletions, and
other changes may be made to the various embodiments of the present invention
described above, which changes would be obvious to a person skilled in the
art,
and these changes are contemplated by the principles of the present invention.
Accordingly, the foregoing detailed description is to be clearly understood as
being given by way of illustration and example only, the spirit and scope of
the
present invention being limited solely by the appended claims.
