U.S. patent application number 13/190865 was filed with the patent office on 2013-01-31 for degradable layer for temporarily protecting a seal.
This patent application is currently assigned to Baker Hughes Incorporated. The applicant listed for this patent is James Doane, Bennett Richard. Invention is credited to James Doane, Bennett Richard.
Application Number | 20130025887 13/190865 |
Document ID | / |
Family ID | 47596295 |
Filed Date | 2013-01-31 |
United States Patent
Application |
20130025887 |
Kind Code |
A1 |
Richard; Bennett ; et
al. |
January 31, 2013 |
DEGRADABLE LAYER FOR TEMPORARILY PROTECTING A SEAL
Abstract
A packer arrangement for forming a seal between an inner member
and an outer tubular string in a borehole includes an outer tubular
string member having a chamber portion; and a packer device
disposed at least partially within the chamber portion and
including a sealing element for forming a seal against an inner
member, the packer device including a degradable layer, the
degradable layer temporarily and at least partially protecting the
sealing element and method of establishing a seal.
Inventors: |
Richard; Bennett; (Kingwood,
TX) ; Doane; James; (Friendswood, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Richard; Bennett
Doane; James |
Kingwood
Friendswood |
TX
TX |
US
US |
|
|
Assignee: |
Baker Hughes Incorporated
Houston
TX
|
Family ID: |
47596295 |
Appl. No.: |
13/190865 |
Filed: |
July 26, 2011 |
Current U.S.
Class: |
166/387 ;
166/142; 166/186 |
Current CPC
Class: |
E21B 33/1285
20130101 |
Class at
Publication: |
166/387 ;
166/142; 166/186 |
International
Class: |
E21B 33/12 20060101
E21B033/12 |
Claims
1. A packer arrangement for forming a seal between an inner member
and an outer tubular string in a borehole, the packer arrangement
comprising: an outer tubular string member having a chamber
portion; and a packer device disposed at least partially within the
chamber portion and including a sealing element for forming a seal
against an inner member, the packer device including a degradable
layer, the degradable layer temporarily and at least partially
protecting the sealing element.
2. The packer arrangement of claim 1 further comprising a setting
member for selectively actuating the sealing element between set
and unset positions.
3. The packer arrangement of claim 1 wherein the sealing element
comprises an elastomeric seal.
4. The packer arrangement of claim 1 wherein the sealing element
comprises a metallic seal.
5. The packer arrangement of claim 2 further comprising a locking
mechanism for securing the setting member such that the sealing
element is maintained in the set position.
6. The packer arrangement of claim 5 wherein the locking mechanism
comprises a body lock ring.
7. The packer arrangement of claim 5 wherein the setting member
comprises: a compression member that is axially moveable within the
chamber portion; and an engagement profile for selectively securing
the compression member to a setting tool component.
8. The packer arrangement of claim 7 wherein the setting member
comprises a camming member that is axially moveable within the
chamber portion between a first position wherein the sealing
element is unset and a second position wherein the camming member
urges the sealing element radially inwardly by camming toward the
set position.
9. The packer arrangement of claim 7 wherein the setting member
comprises: a generally cylindrical compression member having a
helical interface with the outer tubular string member such that
rotation of the compression member results in movement of the
compression member axially within the outer tubular string
member.
10. The packer arrangement of claim 1 wherein the degradable layer
is disposed in the chamber portion.
11. The packer arrangement of claim 2 wherein the degradable layer
is removed before the sealing element is actuated.
12. The packer arrangement of claim 1, wherein the degradable layer
is disposed radially inwardly of the sealing element.
13. The packer arrangement of claim 1, further comprising a seal
engagement member having a plurality of radially extending pips for
engaging into the seal element.
14. The packer arrangement of claim 2 wherein the setting member
comprises a hydraulically-actuated setting piston.
15. The packer arrangement of claim 1 wherein: the packer device
comprises a sealing element within the chamber portion; and the
inner tubular string includes a ductile tube that is expandable
radially outwardly to form a sealing engagement with the sealing
element within the chamber portion.
16. The packer arrangement of claim 15 wherein the sealing element
comprises an elastomeric sealing element.
17. The packer arrangement of claim 15 wherein the sealing element
comprises a metallic sealing element and the sealing engagement of
the ductile tube and the sealing element forms a biting retention
to withstand high axial tubing loads.
18. The packer arrangement of claim 15 wherein the ductile tube is
expanded radially outwardly by hydraulic inflation.
19. The packer arrangement of claim 15 wherein the ductile tube is
expanded radially outwardly by mechanical swaging.
20. A borehole production system comprising: an outer tubular
string defining a central bore; a packer device associated with the
outer tubular string, the packer device including a sealing element
actuatable between set and unset positions, the packer device
including a degradable layer for temporarily and at least partially
protecting the sealing element, wherein the sealing element of the
packer device is moved radially inwardly to engage an inner tubular
string for forming a seal against the inner tubular string.
21. The borehole production system of claim 20 further comprising a
setting member for selectively actuating the sealing element from
the unset position to the set position.
22. The borehole production system of claim 21 wherein the setting
member comprises: a compression member that is axially moveable
within the chamber portion; and an engagement profile for
selectively securing the compression member to a setting tool
component.
23. The borehole production system of claim 22 wherein the setting
member comprises a generally cylindrical compression member having
a helical interface with the outer tubular string member such that
rotation of the compression member results in movement of the
compression member axially within the outer tubular string
member.
24. The borehole production system of claim 23 further comprising
an inner tubular string for production of hydrocarbons against
which the packer device is set.
25. The borehole production system of claim 23 wherein the sealing
element comprises an elastomeric seal.
26. The borehole production system of claim 23 wherein the sealing
element comprises a non-elastomeric seal.
27. The borehole production system of claim 23 wherein the sealing
element comprises a metallic seal member.
28. The borehole production system of claim 23 further comprising a
locking mechanism for securing the setting member such that the
sealing element is maintained in the set position.
29. The borehole production system of claim 28 wherein the locking
mechanism comprises a body lock ring assembly.
30. A method of establishing a seal within a borehole between an
outer tubular string member and an inner tubular string member,
comprising the steps of: disposing an outer tubular string within a
borehole, the outer tubular string containing an outer tubular
string member having an enlarged diameter chamber portion with a
packer device residing at least partially within the chamber
portion, the packer device being actuatable between an unset
position and a set position and including a degradable layer for
temporarily and at least partially protecting the packer device;
disposing an inner tubular string within the outer tubular string;
actuating the packer device from the unset position to the set
position to create a seal between the outer and inner tubular
strings.
31. The method of claim 30 wherein the step of actuating the packer
device comprises axially compressing a packer element to cause the
packer element to be expanded radially inwardly against the inner
tubular string.
32. The method of claim 30 wherein the step of actuating the packer
device comprises urging a compression member axially against a
sealing member to cause the sealing member to expand axially
inwardly against the inner tubular string.
33. The method of claim 32 wherein the step of urging the
compression member axially against the sealing member comprises:
engaging an engagement profile on the compression member with a
portion of the inner tubular string, and moving the inner tubular
string axially with respect to the outer tubular string to cause
the compression member to be urged against the sealing member.
34. The method of claim 33 further comprising securing the packer
device in a set position with a locking mechanism.
35. The method of claim 30 wherein the degradable layer is disposed
in the chamber portion.
36. The method of claim 30 further comprising removing the
degradable layer before the step of actuating packer device.
Description
BACKGROUND
[0001] Packers are used for securing production tubing inside of
casing or a liner within a borehole, for example. Packers are also
used to create separate zones within a borehole. Unfortunately,
conventional packers and techniques for setting packers results in
a reduction of usable diameter within the well. This is because the
packer is carried by a conveyance tubular (such as a production
tubing string) that is of smaller diameter than the tubing or
casing against which it is set. The packer is then set within the
annular space between the conveyance tubular and the outer tubing
or casing. Once set, the useable diameter of the well (i.e., the
diameter through which production fluid can flow or tools can be
passed) becomes the inner diameter of the conveyance tubular.
However, the components of the packer device (including slips,
elastomeric seals, setting sleeves and so forth) inherently occupy
space between the inner and outer tubulars. For example, a borehole
having standard 21.40 lb. casing with an outer diameter of 5
inches, would have an inner diameter of 4.126 inches. It would be
desirable to run into the casing a string of tubing having an outer
diameter of approximately 4 inches, which would allow for a tubing
string with a large cross-section area for fluid flow and tool
passage. However, the presence of packer components on the outside
of the tubing string will dictate that a smaller size tubing string
(such as 27/8'') be run. Over an inch of diameter in usable area is
lost due to the presence of both the inner production tubing string
and the packer device that is set within the space between the
production tubing string and the casing.
SUMMARY
[0002] A packer arrangement for forming a seal between an inner
member and an outer tubular string in a borehole includes an outer
tubular string member having a chamber portion; and a packer device
disposed at least partially within the chamber portion and
including a sealing element for forming a seal against an inner
member, the packer device including a degradable layer, the
degradable layer temporarily and at least partially protecting the
sealing element.
[0003] A borehole production system includes an outer tubular
string defining a central bore and a packer device associated with
the outer tubular string, the packer device including a sealing
element actuatable between set and unset positions, the packer
device including a degradable layer for temporarily and at least
partially protecting the sealing element, wherein the sealing
element of the packer device is moved radially inwardly to engage
an inner tubular string for forming a seal against the inner
tubular string.
[0004] A method of establishing a seal within a borehole between an
outer tubular string member and an inner tubular string member,
including the steps of disposing an outer tubular string within a
borehole, the outer tubular string containing an outer tubular
string member having an enlarged diameter chamber portion with a
packer device residing at least partially within the chamber
portion, the packer device being actuatable between an unset
position and a set position and including a degradable layer for
temporarily and at least partially protecting the packer device;
disposing an inner tubular string within the outer tubular string;
and actuating the packer device from the unset position to the set
position to create a seal between the outer and inner tubular
strings.
BRIEF DESCRIPTION OF DRAWINGS
[0005] FIG. 1 is a side, cross sectional view of an exemplary
packer device constructed in accordance with the present
invention;
[0006] FIG. 2 is a side, cross sectional view of the packer device
shown in FIG. 1, now having been set;
[0007] FIG. 3 is a side, cross-sectional view of an alternative
packer device constructed in accordance with the present
invention;
[0008] FIG. 4 is a side, cross-sectional view of the packer device
shown in FIG. 3, now with having been set;
[0009] FIG. 5 is a side, cross-sectional view of a further
alternative packer device constructed in accordance with the
present invention;
[0010] FIG. 6 is a side, cross-sectional view of the packer device
shown in FIG. 5, now having been set;
[0011] FIG. 7 is a side, cross-sectional view of an alternative
packer device constructed in accordance with the present invention
and utilizing a hydraulic setting arrangement for setting the
packer device;
[0012] FIG. 8 is a side, cross-sectional view of the packer device
shown in FIG. 7, now having been actuated to a set position;
[0013] FIG. 9 is a side, cross-sectional view of an alternative
packer device also utilizing a hydraulic setting arrangement;
[0014] FIG. 10 is a side, cross-sectional view of the packer device
shown in FIG. 9, now having been actuated to a set position;
[0015] FIG. 11 is a side, cross-sectional view of a further
exemplary packer device, which incorporates a ductile, radially
expandable tube;
[0016] FIG. 12A is a side, cross-sectional view of a packer device
generally in accordance with FIG. 1, but with a protective layer
provided for a seal element;
[0017] FIG. 12B is a quarter-sectional view of another packer
device embodiment disclosed herein.
DETAILED DESCRIPTION
[0018] FIGS. 1 and 2 illustrate an exemplary borehole 10 that has
been drilled through the earth 12. The borehole 10 is lined with a
string of casing, of which two casing sections 14, 16 are depicted.
A casing coupler 18 interconnects the casing sections 14, 16 to
form a casing string 17 that defines a central bore 19 along its
length. Cement 20 surrounds the casing sections 14, 16 and casing
coupler 18. It is noted that the casing coupler 18 has a greater
diameter than the casing sections 14, 16 and is secured to each of
the casing sections 14, 16 via threaded connections 22, 24,
respectively.
[0019] The casing coupler 18 includes an axial bore 26 for passage
of tools and fluid through the casing coupler 18. The bore 26 has
an enlarged diameter chamber portion 28. A packer device 30 is
disposed within the enlarged diameter chamber portion 28. The
packer device 30 includes a cylindrical elastomeric packer sealing
element 32 and a cylindrical setting sleeve 34. The setting sleeve
34 is a compression member that is axially moveable within the
enlarged diameter portion 28 of the bore 26. The setting sleeve 34
features an axial bore 36 with an engagement profile 38 within. A
ratchet-style body lock ring assembly 37, of a type known in the
art, is associated with the outer radial diameter surface of the
setting sleeve 34. The body lock ring assembly 37 provides for
limited one-way movement of the setting sleeve 34 with respect to
the surrounding casing coupler 18.
[0020] FIGS. 1 and 2 depict actuation of the packer device 30 to
create a seal between the casing string 17 and a string of
production tubing 40, the lower end of which is visible in FIG. 2.
The lower end of the production tubing string 40 includes a setting
tool 42 for actuation of the packer device 30. In FIG. 1, the
packer device 30 is in an initial, unset position. In one
embodiment, the setting tool 42 includes a cylindrical tool body 44
having a plurality of collets 46 extending axially therefrom. Each
of the collets 46 carries a radially enlarged portion 48 that
presents a stop shoulder 50 and a tapered camming surface 52. The
enlarged portion 48 is shaped and sized to fit within the
engagement profile 38 of the setting sleeve 34.
[0021] To activate the packer device 30, the production tubing
string 40 and setting tool 42 are inserted into the casing string
17. The tapered camming surface 52 of each collet 46 will contact
the upper ends of the sealing element 32 and the setting sleeve 34
and deflect the collet 46 radially inwardly. When the radially
enlarged portion 48 of each collet 46 becomes aligned with the
engagement profile 38 of the setting sleeve 34, each collet 46 will
snap radially outwardly so that the radially enlarged portion 48
becomes disposed within the engagement profile 38, as shown in FIG.
2. Once the setting tool 42 is attached to the setting sleeve 34 in
this manner, the tubing string 40 is then pulled upwardly to cause
the setting sleeve 34 to be moved axially upwardly within the
enlarged diameter portion 28 of the bore 26. The collets 46 are not
disengaged from the engagement profile 38 due to abutting contact
between the stop shoulder 50 and the upper end 54 of the profile
38. The sealing element 32 is thereby axially compressed by the
setting sleeve 34 and, when axially compressed, will be extruded
radially inwardly against the tool body 44 of the production tubing
string 40. The body lock ring assembly 37 will prevent the setting
sleeve 34 from moving back downwardly with respect to the
surrounding casing coupler 18, thereby preventing the packer device
30 from becoming unset.
[0022] Because the components of the packer device 30 are retained
within an enlarged diameter portion 28 of the casing coupler 18,
the gap between the exterior of the tubing string 40 and the
interior of the casing string 17 can be quite small. For example,
in a casing string made up of 35.3 lb. Casing sections with an
external diameter of 5 inches, an interior diameter of 4.126 inches
would be available. With the large bore, external packer
arrangement described above, it would be possible to insert a
tubing string 17 having a diameter approximating 4 inches, rather
than a smaller diameter tubing string (i.e., 27/8''). In fact, the
use of a larger diameter tubing string is desirable for two
reasons. First, the resulting available cross-sectional flow and
work bore area of the tubing string 17 will be larger. Second, the
sealing element 32 of the packer device 30 can more easily and
securely seal against the larger diameter tubing string 17.
[0023] FIGS. 3 and 4 illustrate an alternative embodiment of the
invention wherein a packer device 30' has a sealing element 32 and
a setting sleeve assembly 60. The setting sleeve assembly 60
includes an inner setting sleeve member 62 having an external
helical thread 64 and an internal helical thread 66 that is formed
on the interior of the enlarged diameter portion 28. It is noted
that the external and internal threads 64, 66 are interengaged with
one another in a well-known manner such that rotation of the sleeve
member 62 within the casing coupler 18 will move the sleeve member
62 axially within the coupler 18. One or more key slots 68 are
located on the radial interior of the sleeve member 62.
[0024] In FIG. 3, the packer device 30' is in an unset, initial
position. In FIG. 4, a production tubing string 40 has been
inserted into the casing string 17. A setting component 70 is
secured to the lower end of the production tubing string 40 and
presents radially extending keys 72 that are shaped and sized to
fit within the key slots 68. It is noted that the keys 72 are
preferably spring-biased radially outwardly from the body of the
setting component 70 so that they may be compressed radially
inwardly as needed for disposal down through the casing string 17
and to pop radially outwardly upon encountering the key slots 68.
When the keys 72 are located within the key slots 68, the inner
sleeve member 62 is secured rotationally with respect to the
setting component 70 such that rotating the tubing string 40 and
setting component 70 will rotate the sleeve member 62. In order to
set the packer device 30', the tubing string 40 is rotated at the
surface to cause the sleeve member 62 to move axially upwardly with
respect to the casing coupler 18, thereby radially compressing the
sealing element 32 and causing it to seal against the tubing string
40. In this embodiment, no body lock ring is required to maintain
the packer device 30' in the set position. The inward compressive
force exerted by the sealing element 32 upon the outer radial
surface of the tubing string 40 should be sufficient to prevent
counter-rotation of the tubing string 40 within the casing string
17 that might cause the packer device 30' to become unset.
[0025] FIGS. 5 and 6 depict a further alternative embodiment for a
packer device 30'' constructed in accordance with the present
invention. The packer device 30'' includes a sealing element 72
having a ductile metallic body 74 and elastomeric sealing portions
76. A suitable sealing element of this type is the "ZX" packing
element that is available commercially from Baker Oil Tools of
Houston, Tex. It is noted that the exterior radial surface 77 of
the sealing element 72 is substantially conical in shape such that
the lower axial end 78 of the sealing element 72 presents a smaller
diameter than the upper axial end 80.
[0026] Also included in the packer device 30'' is a setting sleeve
member 82 having a generally cylindrical sleeve body 84 that
defines a central axial bore 86 with an interior engagement profile
88. A body lock ring assembly 37 is associated with the outer
radial surface of the sleeve body 84 and provides for limited
one-way movement of the setting sleeve member 82 with respect to
the surrounding casing coupler 18. A tapered bore portion 90 is
located proximate the upper end 92 of the body 84 thereby providing
a ramped surface that is in abutting contact with the outer radial
surface 77 of the sealing element 72.
[0027] FIG. 5 depicts that packer device 30'' in an unset
condition. In FIG. 6, a production tubing string 40 has been
disposed into the casing string 17. A setting tool component 94 is
secured to the lower end of the tubing string 40 and presents
axially extending collets 96 with radially outwardly projecting
portions 98 that are shaped and sized to reside within the
engagement profile 88 of the setting sleeve member 82. As the
tubing string 40 is lowered through the casing string 17, the
collets 96 are deflected radially inwardly until the outwardly
projecting portions 98 encounter the engagement profile 88 and snap
radially outwardly to reside within the engagement profile 88 to
secure the tubing string 40 to the setting sleeve member 82. Then,
the tubing string 40 is raised to cause the setting sleeve member
82 and urge the ramped surface of tapered bore portion 90 axially
against the outer radial surface 77 of the sealing element 72. This
axial movement causes the body 74 of the sealing element 72 to be
cammed radially inwardly and deformed radially inwardly against the
production tubing string 40. Operation of the body lock ring
assembly 37 will maintain the packer assembly 30'' in the set
position.
[0028] Variations on the packer device 30'' are possible wherein
the sealing element 72 is formed entirely of metal and without the
elastomeric sealing portions 76. When the packer device 30'' is
set, a metal-to-metal seal is formed. Such a variation may be
advantageous in many instances wherein, for example, there is a
minimum amount of movement of the components needed to form an
effective seal. Where a fully metallic sealing element is employed,
the sealing element may be a bellow-type seal or a hydroformed seal
or ring element. Additionally, a metal-to-metal seal may
incorporate toothed slips, of a type known in the art, or other
mechanisms for creating a biting engagement between the tubing
string 40 and the surrounding casing string 17.
[0029] Currently, each of the packer devices 30, 30' and 30'' are
permanently set packer devices. They may be removed from the
borehole, if desired, by use of a suitable milling tool, as is
known in the art.
[0030] FIGS. 7 and 8 illustrate a further exemplary packer device
100 that employs an energy source that is contained within the
casing string 17 prior to disposing the tubing string 40 into the
casing string 17. The enlarged diameter chamber 28 of the casing
coupler 18 contains an outer collar 102 and an inner collar 104.
The inner collar 104 is disposed radially within the outer collar
102, and a chamber 106 is defined radially between the two collars
102, 104. Flanged end portions 108 and seals 110 are provided for
each of the collars 102, 104. The outer collar 102 presents an
upper axial end portion 112 that lies in contact with the sealing
element 32. A recess 114 is inscribed within the interior radial
surface 116 of the outer collar 102. An annular seal member 118 is
fixedly secured to the inner collar 104 and is, in turn, secured to
a split ring, or C-ring member 120. In the unset position, depicted
in FIG. 7, the split ring 120 resides within the recess 114 of the
outer collar 102. As noted, the chamber 106 is defined radially
between the inner and outer collars 102, 104, at its upper end by
seal 110, and at its lower end by seal member 118. A split ring
actuator 122 (visible in FIG. 7) is operably interconnected with
the split ring 120. The split ring actuator 122 preferably
comprises a programmable electronic transceiver that is designed to
receive a triggering signal from a transmitter. Signal transmitter
124 is incorporated within the tubing string 40. In one currently
preferred embodiment, the signal transmitter 124 may comprise an
RFID (radio frequency identification) tag or chip that is designed
to emit a triggering signal upon passing within a certain proximate
distance of the actuator 122. The actuator 122 is operably
associated with the split ring 120 to retract the split ring 120
radially inwardly and out of the recess 114 upon receipt of the
signal from the transmitter 124. Radial refraction of the split
ring 120 may be done by the actuator mechanically, magnetically, or
using other suitable known techniques.
[0031] The chamber 106 may be an atmospheric chamber or a more
highly pressurized chamber, which will create a pressure
differential across the seal member 118 which will urge the end
portion 112 of the outer collar 102 toward the sealing element 32
and a set position. In variations on this embodiment, the chamber
106 could be replaced with a mechanical spring to serve as an
energy source to bias the outer collar 102 toward the sealing
element 32. Additionally, the transmitter 124 and actuator 122
could be replaced by a mechanical trigger arrangement wherein the
spring is mechanically released from a compressed state by engaging
a release latch for the spring with an engagement member within the
tubing string 40.
[0032] In operation, the packer device 100 is in the initially
unset position shown in FIG. 7. The tubing string 40 is lowered
into the casing string 17 until the transmitter 124 is located
proximate the actuator 122. The triggering signal is received by
the actuator 122, which then releases the split ring 120 from the
recess 114. If desired, a delay could be incorporated into the
programming of the actuator 122 such that a predetermined period of
time elapses between the time the triggering signal is received by
the actuator 122 and the split ring 120 is released from the recess
114. When the split ring 120 is released from the recess 114, fluid
pressure within the chamber 106 will urge the outer collar 102
axially upwardly so that the upper end 112 will compress the
sealing element 32. The sealing element 32 will be deformed
radially inwardly to seal against the tubing string 40, as depicted
in FIG. 8 to create a seal.
[0033] Referring now to FIGS. 9 and 10, a further exemplary packer
device 130 is depicted which utilizes hydraulic setting via the
tubing string 40. The sealing element 32 is retained within the
chamber 28 along with a setting piston 132. The setting piston 132
features an enlarged compression head portion 134 that abuts the
sealing element 32 and a reduced diameter stem portion 136 that
extends downwardly from the head portion 134. A ratchet mechanism
138 is located at its lower end of the stem portion 136 and
operates in the manner of a body lock ring to ensure one-way
sequential movement of the setting piston 132 with respect to the
surrounding casing coupler 18.
[0034] A fluid chamber 140 is defined between the setting piston
132 and the casing string 17 within the enlarged chamber 28. Fluid
flow ports 142 are disposed through the setting piston 132 to
permit fluid communication between the fluid chamber 140 and the
interior flowbore 144 of the setting piston 132. Fluid seals 146
are provided between the setting piston 132 and the casing coupler
18 to ensure fluid tightness of the fluid chamber 140.
[0035] The lower end of the tubing string 40 is closed off by a
plug 148. The plug 148 is preferably a temporary or removable plug
that can be removed to allow flow through the tubing string 40 at a
later point during production operations. Ports 150 are disposed
through the side of the tubing string 40.
[0036] In operation, the packer device 130 is initially in the
unset position depicted in FIG. 9. The tubing string 40 is then
disposed into the casing string 17 until the ports 150 of the
tubing string 40 are generally aligned with the fluid flow ports
142 in the setting piston 132. The interior flowbore 152 of the
tubing string 40 is then pressurized so that fluid is flowed
through the aligned ports 150 and 142 and into the fluid chamber
140. The setting piston 132 is urged upwardly by the fluid pressure
so that the enlarged head portion 134 compresses the sealing
element 32. Axial compression of the sealing element 32 causes the
sealing element 32 to deform radially inwardly and seal against the
tubing string 40, as depicted in FIG. 10. The ratchet mechanism 138
ensures that the packer device 130 remains in the set position.
[0037] FIG. 11 depicts a further exemplary embodiment of the
invention wherein a sealing element 200 is contained within the
chamber 28 of the casing coupler 18 and an inflatable, or radially
expandable, ductile tube 201 is made up into the production tubing
string 40. The ductile tube 201 is formed of a material that
permits the tube 201, or portions thereof, to be deformed radially
outwardly. One such material is a nickel alloy. To create a seal,
the ductile tube 201 is inflated or expanded radially outwardly
until its radially outer surface is brought into sealing contact
with the sealing element 200. The ductile tube 201 can be inflated
or expanded radially outwardly using a number of techniques for
radially expanding ductile tubular members. One technique for
inflating the ductile tube 201 is to seat a dart, ball, or other
pug member 202 upon a seat 204 to seal off the flowbore 152 of the
tubing string 40 below the ductile tube 201. Fluid pressure is then
increased within the flowbore 152 above the plug member 202 to
cause the ductile tube 201 to expand radially outwardly, as
illustrated in FIG. 11. In this embodiment, as well, the plug
member 202 may be a temporary or removable plug member.
Alternatively, a mechanical means, such as a suitable swaging
instrument, can be used to radially expand the ductile tube 201
radially outwardly.
[0038] The sealing element 200 may be a metallic sealing element or
a non-metallic sealing element. In one embodiment, the sealing
element 200 is an elastomeric sealing element. In another
embodiment, the sealing element 200 is a mechanical sealing element
and contains toothed portions to form a biting engagement with the
ductile tube 201. The design of the sealing element 200 will
preferably provide fluid sealing and mechanical retention between
the inflatable tubing 201 and the casing coupler 18. The sealing
contact between the ductile tube 201 and the sealing element 200
forms a retention device between the tubing string 40 and the
surrounding casing string that is capable of withstanding high
axial tubing loads.
[0039] Those of skill in the art will appreciate that the present
invention provides a novel borehole packer arrangement as well as a
borehole production system that includes an outer tubular string
having an enlarged diameter chamber portion; an inner tubular
string; and a packer device disposed at least partially within the
enlarged chamber to form a seal against the inner tubular
string.
[0040] The present invention also provides methods of establishing
a seal between inner and outer tubular string members within a
borehole wherein a packer device is disposed within an enlarged
diameter chamber portion of an outer tubular string. The outer
tubular string, such as a string of casing or liner, is run into a
borehole and cemented in place. At this point the packer device is
in an unset position. Next, the inner tubular string is run into
the outer tubular string to a predetermined depth or position
within the outer string. The predetermined depth or position will
typically correspond to the proper location of a tool, such as a
production nipple, inside the outer tubular string. The packer
device is then actuated from an unset to a set position to form a
seal against a member of the inner tubular string.
[0041] In each of the embodiments hereof, a disintegratable,
dissolvable, corrodible, decomposable, or otherwise easily
defeatable protector layer may be employed, for example, a
protective layer 205 is shown in FIG. 12A. With the exception of
protective layer 205, FIG. 12A exactly resembles FIG. 1, and the
description given above is therefore applicable also to FIG. 12A.
In this embodiment, the chamber portion 28 is provided with a
radial depth greater than a radial thickness of the seal element 32
in order to enable the application of the protective layer 205 for
the seal element 32. As illustrated, the layer 205 is radially
inwardly disposed of the element seal 32. In one embodiment, the
layer is within the recess 28. The protective layer 205 is a
degradable layer whose purpose is to temporarily protect the seal
element 32. "Degradable" is intended to mean that the layer is
disintegratable, dissolvable, corrodible, or otherwise easily
removable. It is to be understood that any use herein of the term
"degrade", or any of its forms, incorporates the stated
meaning.
[0042] In one embodiment, for example, the layer 205 is removed by
exposure to a downhole fluid, such as water, oil, acid, etc. After
the layer 205 has been removed, the packer device 30 would operate
as described above with respect to FIGS. 1 and 2, for forming a
seal as shown in FIG. 2. It is to be appreciated that any of the
other embodiments described herein could be similarly modified in
order to include a degradable layer for temporarily protecting the
corresponding seal element in each embodiment.
[0043] Another embodiment is shown in FIG. 12B. Specifically, a
packer arrangement 500 includes a casing pup 502 and a packer
mandrel 504 for setting a seal element 506 located in a cavity or
chamber 508 of the casing pup 502. The seal element 506 is
initially protected by a degradable layer 510, which substantially
resembles the layer 205 described above. After degrading the layer
510, an arm 512 carrying a seal engagement member 514 is actuated
into engagement with the seal element 506. For example, the packer
mandrel 504 include a wedge-like, conical, frustoconical, or
otherwise tapered surface and be actuated toward the arm 512, or
vice-versa, for urging the seal engagement member 514 radially
toward the seal element 506. For example, in another embodiment a
piston could actuate the seal engagement member 514 into the packer
mandrel 504. The seal engagement member 514 includes a plurality of
radially extending pips 516 for "biting" into the seal element 506,
thereby setting the seal element and reducing extrusion thereof.
The arm 512 could include a body lock 518 for allowing movement of
the member 514 in one direction with respect to the tapered surface
of the mandrel 504, but not the other direction, thereby locking
the member 514 in place once actuated.
[0044] Materials appropriate for the purpose of degradable
protective layers as described herein are lightweight,
high-strength metallic materials. Examples of suitable materials
and their methods of manufacture are given in United States Patent
Publication No. 2011/0135953 (Xu, et al.), which Patent Publication
is hereby incorporated by reference in its entirety. These
lightweight, high-strength and selectably and controllably
degradable materials include fully-dense, sintered powder compacts
formed from coated powder materials that include various
lightweight particle cores and core materials having various single
layer and multilayer nanoscale coatings. These powder compacts are
made from coated metallic powders that include various
electrochemically-active (e.g., having relatively higher standard
oxidation potentials) lightweight, high-strength particle cores and
core materials, such as electrochemically active metals, that are
dispersed within a cellular nanomatrix formed from the various
nanoscale metallic coating layers of metallic coating materials,
and are particularly useful in borehole applications. Suitable core
materials include electrochemically active metals having a standard
oxidation potential greater than or equal to that of Zn, including
as Mg, Al, Mn or Zn or alloys or combinations thereof. For example,
tertiary Mg--Al--X alloys may include, by weight, up to about 85%
Mg, up to about 15% Al and up to about 5% X, where X is another
material. The core material may also include a rare earth element
such as Sc, Y, La, Ce, Pr, Nd or Er, or a combination of rare earth
elements. In other embodiments, the materials could include other
metals having a standard oxidation potential less than that of Zn.
Also, suitable non-metallic materials include ceramics, glasses
(e.g., hollow glass microspheres), carbon, or a combination
thereof. In one embodiment, the material has a substantially
uniform average thickness between dispersed particles of about 50
nm to about 5000 nm. In one embodiment, the coating layers are
formed from Al, Ni, W or Al.sub.2O.sub.3, or combinations thereof.
In one embodiment, the coating is a multi-layer coating, for
example, comprising a first Al layer, a Al.sub.2O.sub.3 layer, and
a second Al layer. In some embodiments, the coating may have a
thickness of about 25 nm to about 2500 nm.
[0045] These powder compacts provide a unique and advantageous
combination of mechanical strength properties, such as compression
and shear strength, low density and selectable and controllable
corrosion properties, particularly rapid and controlled dissolution
in various borehole fluids. The fluids may include any number of
ionic fluids or highly polar fluids, such as those that contain
various chlorides. Examples include fluids comprising potassium
chloride (KCl), hydrochloric acid (HCl), calcium chloride
(CaCl.sub.2), calcium bromide (CaBr.sub.2) or zinc bromide
(ZnBr.sub.2). For example, the particle core and coating layers of
these powders may be selected to provide sintered powder compacts
suitable for use as high strength engineered materials having a
compressive strength and shear strength comparable to various other
engineered materials, including carbon, stainless and alloy steels,
but which also have a low density comparable to various polymers,
elastomers, low-density porous ceramics and composite
materials.
[0046] While one or more embodiments have been shown and described,
modifications and substitutions may be made thereto without
departing from the spirit and scope of the invention. Accordingly,
it is to be understood that the present invention has been
described by way of illustrations and not limitation.
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