U.S. patent application number 09/934734 was filed with the patent office on 2002-01-03 for communicating with devices positioned outside a liner in a wellbore.
Invention is credited to Booker, John A., Johnson, Michael R., Kosmala, Alexandre G.E., Pringle, Ronald E., Rayssiguier, Christophe M..
Application Number | 20020000317 09/934734 |
Document ID | / |
Family ID | 24105246 |
Filed Date | 2002-01-03 |
United States Patent
Application |
20020000317 |
Kind Code |
A1 |
Rayssiguier, Christophe M. ;
et al. |
January 3, 2002 |
Communicating with devices positioned outside a liner in a
wellbore
Abstract
A downhole string includes a liner and devices positioned
outside the liner. One or more control lines extend from the liner
devices along the exterior of the liner to one or more connectors
that provide connection points inside the liner. The one or more
connectors may include electrical connectors (e.g., direct contact
connectors), inductive connectors (e.g., inductive couplers),
optical connectors (e.g., fiber optic connectors), and hydraulic
connectors. The one or more control lines may be electrical lines,
fiber optic lines, or hydraulic lines. The downhole string may also
be used with a cement protector during cementing operations to
protect both the inside of the liner as well as the one or more
connectors attached to the liner. The cement protector includes a
sleeve that isolates cement from the inside of the liner during a
cementing operation so that a liner wiper plug is not needed. The
cement protector is engageable to a pulling tool that is attached
to a running tool. The running tool in turn is connected to a pipe
through which a cement slurry can be pumped. The cement slurry
pumped through the inner bore of the pipe enters the sleeve of the
cement protector. One or more ports are provided in the cement
protector sleeve to enable communication of the cement slurry to an
annulus region between the outer wall of the liner and the inner
wall of the wellbore. If the apparatus and method is used with a
casing, then a running tool may be omitted.
Inventors: |
Rayssiguier, Christophe M.;
(Houston, TX) ; Johnson, Michael R.; (Sugar Land,
TX) ; Pringle, Ronald E.; (Houston, TX) ;
Booker, John A.; (Missouri City, TX) ; Kosmala,
Alexandre G.E.; (Houston, TX) |
Correspondence
Address: |
Schlumberger Reservoir Completions /
Schlumberger Technology Corporation
14910 Airline Road
P.O. Box 1590
Rosharon
TX
77583-1590
US
|
Family ID: |
24105246 |
Appl. No.: |
09/934734 |
Filed: |
August 22, 2001 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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09934734 |
Aug 22, 2001 |
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09528334 |
Mar 17, 2000 |
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6302203 |
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Current U.S.
Class: |
166/285 ;
166/177.4; 166/242.6; 166/242.8; 166/380; 166/65.1 |
Current CPC
Class: |
E21B 43/10 20130101;
E21B 47/017 20200501; E21B 17/028 20130101; E21B 17/003 20130101;
E21B 33/14 20130101 |
Class at
Publication: |
166/285 ;
166/380; 166/65.1; 166/177.4; 166/242.6; 166/242.8 |
International
Class: |
E21B 033/00; E21B
019/16 |
Claims
What is claimed is:
1. An apparatus for use in a well having a well surface and a
wellbore lined with a liner, comprising: a device positioned
outside the liner; a control line connected to the device and
extending outside the liner; and a connector connected to the
control line and providing a connecting point accessible from
inside the liner below the well surface.
2. The apparatus of claim 1, wherein the liner has a lower end, the
connector positioned in the proximity of the liner lower end.
3. The apparatus of claim 2, wherein the liner includes an inner
bore and the connector is positioned to mate with a component
lowered through the liner inner bore.
4. The apparatus of claim 3, wherein the component includes a
corresponding connector.
5. The apparatus of claim 3, further comprising: another connector
positioned in the proximity of the liner lower end; and an
orienting profile to orient the component with respect to the
connectors.
6. The apparatus of claim 5, wherein the component includes plural
corresponding connectors.
7. The apparatus of claim 2, further comprising: a liner shoe
attached to the liner lower end; and a connector sub including the
connector, the connector sub positioned proximal the liner
shoe.
8. The apparatus of claim 1, wherein the device includes an
electrical device.
9. The apparatus of claim 8, wherein the device includes a
resistivity electrode.
10. The apparatus of claim 1, wherein the device includes a
hydraulic device.
11. The apparatus of claim 1, further comprising at least another
device positioned outside the liner.
12. The apparatus of claim 1, wherein the connector is selected
from the group consisting of an electrical connector, an inductive
coupler, an optical connector, and a hydraulic connector.
13. The apparatus of claim 1, further comprising a cement protector
removeably positioned in the liner and covering the connector.
14. A well communication system for a well having a liner, the
system comprising: a device positioned outside the liner; a control
line extending from the device to a lower end of the liner; and a
connector connected to the control line and accessible from within
the liner.
15. The system of claim 14, further comprising a control line
extending from the connector through the liner to the well
surface.
16. The system of claim 14, further comprising a cement protector
removeably positioned in the liner and covering the connector.
17. A downhole communication apparatus, comprising: a liner having
a lower end; and a communication connector assembly attached to the
liner.
18. The apparatus of claim 17, further comprising the communication
connector positioned at the lower end of the liner.
19. The apparatus of claim 18, wherein the communication connector
assembly includes a connector and a sub attached to the liner lower
end.
20. A method for communicating with a device positioned outside a
liner, the method comprising: routing one or more control lines
from the device to an internal passageway of the liner and to the
surface.
21. The method of claim 20, further comprising providing one or
more connectors in the one or more control lines between the
outside of the liner and the internal passageway of the liner.
22. The method of claim 21, further comprising placing the one or
more connectors proximal a lower end of the liner.
23. The method of claim 22, further comprising running a tool into
the internal passageway of the liner, the tool including one or
more connectors adapted to mate with the one or more liner
connector.
24. An apparatus for use in a wellbore having a liner with an inner
bore, comprising: a cement protector to prevent or reduce
communication of cement into the liner inner bore during a
cementing operation, the cement protector including a sleeve and
one or more ports; and a running string attached to the cement
protector, the running string adapted to communicate cement through
the one or more cement protector ports to a region outside the
liner.
25. The apparatus of claim 24, wherein the cement protector further
includes a locking device to releasably engage the cement protector
to the liner.
26. The apparatus of claim 25, wherein the cement protector further
includes a profile, wherein the running string is adapted to engage
the profile to release the locking device to enable retrieval of
the cement protector.
27. The apparatus of claim 26, further comprising a connector sub
including one or more connectors, the cement protector defining a
chamber in communication with the one or more connectors to isolate
cement from the one or more connectors.
28. The apparatus of claim 27, wherein the chamber is filled with a
fluid to protect the one or more connectors.
29. The apparatus of claim 27, wherein the one or more connectors
each includes a connector selected from the group consisting of an
electrical connector, an inductive coupler, an optical connector,
and a hydraulic connector.
30. The apparatus of claim 24, wherein the running string includes
a running tool releasably engaged to the liner.
31. The apparatus of claim 30, wherein the liner is part of a liner
string that further includes a liner hanger and a nipple, the
running tool being releasably attached to the nipple.
32. The apparatus of claim 30, wherein the running string is
moveable longitudinally upon release to engage the cement
protector.
33. The apparatus of claim 30, wherein the running tool includes a
ball seat to receive a ball, the running tool including an inner
bore and a locking device to releasably engage the liner, the
locking device adapted to be released by an increase in pressure in
the running tool inner bore after the ball is sealingly engaged in
the ball seat.
34. The apparatus of claim 33, wherein the ball seat is releasably
attached to a housing of the running tool, wherein a further
increase in pressure causes the ball seat to be released and to
enable the ball to drop through the ball seat.
35. The apparatus of claim 34, wherein the running string further
includes a second ball seat below the first ball seat, the second
ball seat adapted to receive the ball after the ball drops through
the first ball seat.
36. The apparatus of claim 35, wherein the running string further
includes one or more ports to enable fluid communication between
the inside and outside of the running string after the ball has
dropped into the second ball seat.
37. A method of completing a well having an inner wall, comprising:
running a liner string including a liner having an inner bore into
the wellbore; running a cement protector into the liner; and
introducing a cement slurry into the wellbore, the cement slurry
communicated through the cement protector to an annulus between the
liner and the wellbore inner wall, the cement protector isolating
the cement slurry from the liner inner bore.
38. The method of claim 37, wherein running the liner string and
running the cement protector are performed in the same run.
39. The method of claim 37, wherein running the liner string
includes running the liner string releasably attached to a running
string.
40. The method of claim 39, further comprising releasing the
running string and moving the running string to engage the cement
protector.
41. The method of claim 40, wherein introducing the cement slurry
includes introducing the cement slurry through the running
string.
42. The method of claim 41, further comprising retrieving the
running string and cement protector after the cementing
operation.
43. A method for use in a wellbore, comprising: running a liner
string into the wellbore, the liner string including a liner having
an inner bore, a device positioned outside the liner, a control
line connected to the device and extending outside the liner, and a
connector connected to the control line and accessible from the
liner inner bore; and running a second string into the wellbore,
the second string having a connector; and mating the liner string
connector with the second string connector.
44. The method of claim 43, wherein running the second string
includes running a production string including a production
tubing.
45. The method of claim 43, wherein the liner string includes
plural connectors and the second string includes plural connectors,
the method further comprising orienting the second string
connectors to align with corresponding liner string connectors.
46. A liner running and cementing apparatus, comprising: a run-in
tool releasably connectable to an upper portion of the liner; a
run-in tool receiver positioned proximal a lower end of the liner;
and the run-in tool receiver adapted to receive the run-in
tool.
47. The apparatus of claim 46, wherein the run-in tool receiver
comprises a lower protector sleeve releasably attached to a lower
end of the liner.
48. The apparatus of claim 46, further comprising a communication
conduit attached to the run-in tool providing fluid communication
from a well surface to the run-in tool.
49. A method for use in a wellbore, comprising: running a liner
into the wellbore on a run-in tool; moving the run-in tool to a
bottom end of the liner; connecting the run-in tool to a structure
proximal the liner bottom end; and flowing cement through the
run-in tool and then through the bottom end of the liner.
Description
BACKGROUND
[0001] The invention relates to communicating with devices
positioned outside a liner in a wellbore.
[0002] Oil and gas wells may be completed with a variety of
downhole devices to produce hydrocarbons from, or inject fluids
into, formations beneath the earth surface. Completion equipment
have been developed for many types of wells, including vertical or
near-vertical, horizontal, deviated, and multilateral wells.
Typical completion equipment include valves, tubing, packers, and
other downhole devices, as well as electrical, optical, or
hydraulic devices to monitor downhole conditions and to control
actuation of downhole devices (e.g., opening or closing valves,
setting packers, and so forth).
[0003] Sensors and control devices may also be mounted on or
positioned outside of a liner, which is typically cemented to the
wall of the wellbore. A special type of liner includes casing,
which is a liner that extends to the well surface. A liner may also
be connected below a casing to extend further into the wellbore or
into a lateral branch of a multilateral well. One type of sensor
that may be mounted on the outside of a casing includes resistivity
electrodes, which are used to monitor the resistivity of a
surrounding formation reservoir. Based on the resistivity
information, various characteristics of the formation may be
determined.
[0004] A conventional technique of communicating with the sensors
mounted on the outside of casing includes running a control line
outside the casing to the well surface. However, running one or
more control lines in the cement layer creates a potential leak
path to the well surface, which is undesirable. In addition, for
liners that do not extend to the well surface, use of this
technique may not be available. Another drawback of running a
control line on the outside of the casing is that the control line
may have to cross wellhead equipment at a relatively inconvenient
location.
[0005] A need thus exists for a mechanism to provide Communication
with downhole sensors or control devices that are positioned
outside of liners in a wellbore.
SUMMARY
[0006] In general, according to one embodiment, an apparatus for
use in a well having a well surface and a wellbore lined with a
liner includes one or more devices positioned outside the liner and
one or more control lines connected to the devices and extending
outside of the liner. One or more connectors are connected to the
control lines and provide one or more connecting points accessible
from inside the liner below the well surface.
[0007] Other embodiments and features will become apparent from the
following description, from the drawings, and from the claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] FIG. 1 illustrates an embodiment of a liner string in a
wellbore, the liner string including a liner, devices positioned
outside the liner, a control line connected to the devices, and a
connector connected to the control line.
[0009] FIG. 2A illustrates an embodiment of a completion string for
use with the liner string of FIG. 1, the completion string
including a connector adapted to be mated to the liner string
connector.
[0010] FIGS. 2B-2D illustrate other arrangements of liner strings
and completion strings.
[0011] FIG. 3 illustrates an embodiment of a string cooperable with
the liner string of FIG. 1 to perform cementing operations in
accordance with an embodiment.
[0012] FIGS. 4A-4I illustrate a sequence of operations involving
the string of FIG. 3, the liner string of FIG. 1, and a completion
string.
DETAILED DESCRIPTION
[0013] In the following description, numerous details are set forth
to provide an understanding of the present invention. However, it
will be understood by those skilled in the art that the present
invention may be practiced without these details and that numerous
variations or modifications from the described embodiments may be
possible.
[0014] As used here, a "liner" refers to any structure used to line
the wall of any section of a wellbore, either in the main bore or
in a lateral branch. Thus, "liner" may refer to either a liner or
casing, which extends to the well surface.
[0015] As used here, the terms "up" and "down"; "upper" and
"lower"; "upwardly" and downwardly"; and other like terms
indicating relative positions above or below a given point or
element are used in this description to more clearly described some
embodiments of the invention. However, when applied to equipment
and methods for use in wells that are deviated or horizontal, such
terms may refer to a left to right, right to left, or other
relationship as appropriate. Also, when used in a horizontal
section of a wellbore, the terms "below" and "deeper" refer to a
direction of the wellbore that is more distal from the wellbore
surface.
[0016] Referring to FIG. 1, a liner string according to one
embodiment in a wellbore 10 is illustrated. An upper segment of the
wellbore 10 is lined with casing 12. The liner string includes a
liner 14 that lines a lower segment of the wellbore 10, with the
liner 14 attached below a liner hanger 16 engaged to the inner wall
of the casing 12. One or more control and/or monitoring devices 18
may be positioned outside the outer wall of the liner 14. In one
arrangement, the control and/or monitoring devices may be mounted
or attached to the outer wall of the liner 14. In another
arrangement, the control and/or monitoring devices may be
positioned outside the liner 14 but not in contact with the liner
outer wall.
[0017] Such control and/or monitoring devices may include sensors
(such as pressure and temperature gauges, resistivity electrodes,
and so forth) to monitor wellbore or formation characteristics, and
control elements (such as microcontrollers, microprocessors, or
other electronic circuitry) to perform various control operations,
such as opening valves, turning on or off sensors, and so forth.
More generally, such control and/or monitoring devices may be
referred to as "liner devices," which are downhole devices
positioned or mounted outside of a liner. The liner devices may be
electrical, hydraulic, optical, or other types of devices. One
example of a liner device includes an array of resistivity
electrodes that are used to create a resistive image of the
surrounding formation reservoir to predict the arrival of water
during production. In a different embodiment, the liner devices may
be positioned outside the casing 12 instead of the liner 14.
[0018] In accordance with some embodiments, a control line 20 (or
plural control lines) is connected to the liner devices 18. As
illustrated, the control line 20 extends below the liner devices 18
deeper (or more distally) into the wellbore to the lower end of the
liner 14. The control line 20 extends along the outside of the
liner 14 and may be secured to the liner with protectors (usually
at every coupling). At the lower end, a special liner shoe 22 is
attached to the liner 14, with the control line 20 extending
through the shoe 22. The shoe 22 may be connected to (or in the
proximity of) a connector sub that includes a connector 24 (or
plural connectors) connected to the control line 20. The
combination of the connector sub and connector 24 is one example of
a communication connector assembly. The connector assembly is
accessible from within the liner 14. The connector 24 may be an
electrical connector (e.g., a direct contact connector), an
inductive coupler, an optical connector (e.g., a fiber optic
connector), a hydraulic connector, or other connector. The control
line 20 may be an electrical line, a fiber optic line, a hydraulic
line, or other control line. The control line 20 is adapted to
carry both telemetry and power signals.
[0019] In other arrangement, the connector does not need to be
positioned at or in the proximity of the lower end of the liner 14
but may be positioned at another location along the liner. However,
in such other arrangements, the connector is still positioned at a
depth below the well surface so that the control line running from
the liner devices to the connector does not compromise the seal
provided by the cement layer surrounding the liner. Thus, a benefit
offered by any arrangement in which the connector 24 is positioned
below the well surface is that a connection mechanism to the liner
devices is made available without having to run a control line in
the cement layer all the way to the well surface, which may create
an undersirable leak path. Also, this avoids having to run a
control line through the liner hanger 16. Further, in the
arrangement of FIG. 1, another benefit of positioning the connector
24 at or near the proximity of the lower end of the liner 14 is to
avoid creating an obstruction in the inner bore of the liner 14
when other tool strings are run downhole. In the arrangements
discussed, the connector 24 is positioned so that it can mate with
a corresponding connector or other component run into the inner
bore of the liner 14.
[0020] To install the liner string shown in FIG. 1 after the casing
12 has been installed in the wellbore 10, the liner string
(including the liner 14, liner hanger 16, shoe 22, connector 24,
control line 20, and liner devices 18) is run into the wellbore to
the desired depth. Once positioned in the desired depth, the liner
14 is cemented in place. The cement is pumped (in slurry form) into
the inner bore of the liner 14 and through the shoe 22 at the lower
end to introduce the cement slurry into the annulus region between
the outside of the liner and the inner wall of the wellbore 10. The
introduced cement slurry flows upwardly in the annulus region to
form the cement layer. The cement slurry is also flowed into a
region 31 where the liner 14 and casing 12 overlap. Due to the
absence of a control line running between the liner 14 and the
casing 12, the cement in the region 31 between the liner 14 and the
casing 12 provides a good seal to prevent wellbore fluids from
leaking through the annulus between the outer wall of the liner 14
and the inner wall of the casing 12.
[0021] Referring to FIG. 2A, a completion string is run into the
wellbore 10 after the liner string has been installed. In one
example embodiment, the completion string includes a tubing 30,
e.g., a production tubing, an injection tubing, or some other type
of pipe. A connector 32 (or plural connectors) may be mounted at
the lower end of the tubing 30. The connector 32 is adapted to
connect to the connector 24 included in the connector sub of the
liner string. The connector 32 may be an electrical, inductive,
optical, hydraulic, or other connector.
[0022] The tubing connector 32 is in turn connected to a control
line 34 (or plural control lines), which may be an electrical,
optical, hydraulic, or other control line. The control line 34 runs
along the outside of the tubing 30 to the well surface. In one
arrangement, the control line 34 may be secured to the tubing 30
with protectors (usually at every coupling). At the well surface,
the control line 32 extends through a tubing hanger 38 to a surface
control module 36. The surface control module 36 may be a power
supply and computer for electrical control lines, an optical sensor
for fiber optic control lines, a hydraulic console for a hydraulic
control line 24, another type of module, or a combination of the
different consoles.
[0023] Centralizer mechanisms may be used to orient the connector
32 with respect to the liner connector 24 to help mate the
connectors. If plural connectors are arranged in parallel, an
orientation profile may be placed on the liner 14 above the liner
connectors 24 so that a pin located on the tubing can orient the
production string and position its connectors 32 to line up with
the liner connectors 24.
[0024] FIGS. 2B-2D illustrate different arrangements of the liner
string and completion string. In the FIG. 2B example, a control
line 20B extends outside the liner 14 to the upper end of the
liner. At the upper end, the control line 20B reaches a connector
sub 24B. The connector 24B is attached to the liner 14B and may be
mated with the connector 32B of the tubing 30B.
[0025] Referring to FIG. 2C, in yet another arrangement, the
control line 20C extends from the devices 18. In the example shown,
the control line 20C extends through an opening 21C in the liner
14C. The control line 20C is then connected to a connector sub 23C
inside the liner 14C. In another arrangement, the control line 20C
may extend above the devices 18 instead of below the devices.
[0026] Referring to FIG. 2D, another arrangement has a control line
20D extending to an opening 21D in the liner 14D. The control line
20D is provided through the opening 21D to an annular connector 24D
inside the liner 14D. The tubing 30D is attached to an annular
connector 32D that is capable of mating with the connector 24D.
[0027] Other arrangements are also possible. For example, the
connector on FIG. 2D may be placed on one side of the liner.
[0028] In accordance with a further embodiment of the invention, a
cement protector may be used to protect the inner wall of the liner
14 during cementing operations. After the liner string is lowered
to a desired depth, the liner 14 needs to be cemented to the
wellbore wall. Conventionally, in performing a cementing operation,
a cement slurry may be flowed inside the liner 14. To remove the
cement from the inner bore of the liner 14 after the cementing
operation has completed, a wiper plug may be used to wipe out the
cement. The presence of the liner connector 24 may be incompatible
with the use of cement or a wiper plug. The cement inside the inner
bore or subsequent use of the wiper plug may also damage the
connector 24.
[0029] The cement protector in accordance with some embodiments may
be used to isolate the cement from the inner wall of the liner 14
and the connector 24 during a cementing operation. This reduces the
likelihood that Connector 24 and the inner wall of the liner are
damaged during the cementing operation.
[0030] By not polluting the inside of the liner with cement, use of
a wiper plug can be avoided, which can reduce the number of runs
needed to perform a cementing operation to as little as a single
run. A safe operation is provided since the cement protector may be
retrieved to the well surface before the cement dries. In an
alternative arrangement, the cement protector may be a cover that
isolates cement from the connector 24 but not necessarily the liner
14.
[0031] Referring to FIG. 3, a tool string that includes a cement
protector 100 in accordance with one embodiment is illustrated. The
liner string shown in FIG. 1 including the casing 12, liner hanger
16, liner 14, connector(s) 24, liner shoe 22, control line(s) 20,
and liner devices 18, is also illustrated in FIG. 3. The cement
protector 100 is positioned above a connector sub 102 that includes
the connector(s) 24. The connector sub 102 is located above the
liner shoe 22, which includes a check valve 106 that is pushed by a
spring 108 to an upward and sealed position against a seat member
109. Plural check valves may be used for redundancy. During
cementing operations, a cement slurry applied under pressure pushes
the check valve 106 away from the seat member 109 to allow the
cement slurry to flow through openings 107 into an annulus region
105 between the outside of the liner 14 and the inner wall of the
wellbore 10.
[0032] The cement protector 100 includes a sleeve 110 with an inner
bore 111. The bottom of the cement protector 100 provides a cover
or cap that defines a chamber 112 which may be filled with a clean
fluid such as grease or dielectric oil to protect the connector(s)
24 from pollution by cement or debris.
[0033] One or more ports 132 are provided at the lower end of the
cement protector sleeve 110 to allow outflow of cement slurry from
the inner bore 111 of the cement protector sleeve 110. One or more
corresponding conduits 134 are provided in the connector sub 134.
The one or more fluid flow paths provided by the one or more ports
132 and the one or more conduits 134 enable the communication of
cement slurry to the shoe 22. Seals 104 may be provided around the
one or more ports 132 and conduits 134 to prevent communication of
cement slurry with any part of the inner bore of the liner 14.
[0034] The cement protector 100 also includes a locking device that
includes locking dogs 114 and a locking sleeve 116. The locking
device releasably engages the cement protector 100 to the liner 14.
The locking dogs 114 are positioned in corresponding windows in the
cement protector sleeve 110. A shearing mechanism (not shown) may
be used to fix the locking sleeve 116 in place until a sufficient
force is applied to move the locking sleeve 116 upwardly to release
the locking dogs 114. This translation opens a bypass orifice (not
shown) cut into the protector sleeve 110, so that any differential
pressure can be equalized before removing the cement protector 100.
In the illustrated position of FIG. 3, the locking dogs 114 are
held in position by the locking sleeve 116 inside a groove 118
formed in the inner wall of the liner 14.
[0035] A recess 120 is provided in the locking sleeve 116. The
recess 120 is adapted to engage a pulling tool 130 so that the
cement protector 100 may be retrieved from the wellbore after the
cementing operation is complete. The cement protector 100 also
includes a seal bore 122 that allows the pulling tool 130 to
sealingly engage the inner bore of the cement protector sleeve
110.
[0036] The pulling tool 130 includes elements to engage
corresponding elements of the cement protector 100 so that upward
movement of the pulling tool 130 pulls the cement protector 100
upwardly. The lower end of the pulling tool 130 includes a seat 146
for a ball that may be dropped from the well surface. In addition,
one or more angled conduits 148 are provided in the housing 131 of
the pulling tool 130 to enable communication between the inside of
the pulling tool 130 and the outside when the ball is positioned in
the seat 146. A groove is also formed in the pulling tool housing
131 to carry a seal 144, which may be an O-ring or V-packing seal
assembly, that is adapted to engage the seal bore 122 of the cement
protector 100.
[0037] Fingers 136 are provided on the outside of the pulling tool
130. The lower ends of the fingers 136 include protruding portions
142. The combination of each finger 136 and protruding portion 142
forms a collet. In the illustrated position, the inner surfaces of
the protruding portions 142 abut on the pulling tool housing 131.
The upper end 138 of the fingers 136 are engaged to a coiled spring
140. The coiled spring 140 is contained inside a chamber defined by
the pulling tool housing 131.
[0038] An upward force applied on the fingers 136 may move the
fingers 136 upwardly against the spring 140. When the protruding
portions 142 have moved up a sufficient distance to a recessed
section of the pulling tool housing 131, the protruding portions
142 may be collapsed radially inwardly. The ability to collapse the
protruding portions 142 enable the protruding portions 142 to
engage the recess 120 of the locking sleeve 116 in the cement
protector 100.
[0039] As an option, the pulling tool body 110 may be equipped with
spring-energized keys (not shown). These keys can expand into slots
cut into the top of the orienting profile 210. In this way, a
torque applied to the running string at the surface can be
transmitted to the liner, if desired.
[0040] Attached above the pulling tool 130 is a running tool 150.
The running tool 150 is attached below a tubing or pipe 170 and
includes a mechanism for releasably securing the running tool 150
to the liner 14. Collectively, the pipe 170, running tool 150, and
pulling tool 130 make up an example of a running string. The
running tool 150 is adapted to be released once the liner hanger 16
is engaged to the casing 12. Effectively, the running string is
releasably attached proximal an upper end of the liner 14 when the
liner string is being run in.
[0041] The running tool 150 includes dogs 152 that are fitted
through openings in the running tool housing 162 to engage slots
154 formed in a nipple 156 connected to the liner hanger 16. Torque
can be applied to the running string for transmission to the liner
if needed. The dogs 152 are maintained in position by a locking
sleeve 158 in the running tool 150. The locking sleeve 158 is
capable of translating longitudinally inside the running tool
housing, but is fixed in position by a shearing mechanism (not
shown).
[0042] The running tool 150 also provides a seat 160 for a ball
that can be dropped from the well surface. The ball sealingly
engages the seat 160 so that pressure may be increased inside the
running tool 150 above the ball. This pressure increase creates a
differential pressure across the locking sleeve 158, which is
equipped with two different seals 171A and 171B on the two sides of
a chamber 159. If a sufficient force is applied by the differential
pressure, the shearing mechanism of the locking sleeve 158 breaks
to allow translation of the locking sleeve 158 to free the dogs 152
into the sleeve groove 157.
[0043] The ball seat itself 160 may be locked in position by a
shearing mechanism (not shown) having a larger shear strength than
the locking sleeve 158 shearing mechanism. Once a sufficient force
is applied to shear the shearing mechanism of the ball seat 160,
the ball seat 160 can be moved downwardly until it impacts an inner
shoulder 163 of the pulling tool housing 131. At this point, the
force applied against the ball can push the upper ring 161 of the
ball seat 160 outwardly so that the ball 200 can pass through the
ball seat 160. Then the ball 200 drops into the pulling tool 130 to
sit in the seat 146, pushed by the differential pressure. In
another embodiment, the two seats 161 and 146 can be combined. The
seat 146 in this other embodiment can be cut in a sliding sleeve
locked in place by a shearing mechanism. The translation of this
sleeve may open the conduits 148.
[0044] FIGS. 4A-4I illustrate a sequence of operations including
installation of the liner string of FIG. 1, a cementing operation,
and installation of a completion string inside the liner string
after the cementing operation.
[0045] In FIG. 4A, the liner string of FIG. 1 (including the liner,
liner hanger, liner devices, control line, and connector) along
with the tool string of FIG. 3 are run together into the wellbore
10. As shown, the running tool 150 is connected by the dogs 152 to
the nipple 156 connected to the liner hanger 16. Once the liner
hanger 16 has been set against the inner wall of the casing 12, a
ball 200 can be dropped to sealingly engage a seat 160 in the
running tool 150, as shown in FIG. 4B. An applied elevated pressure
inside the pipe 170 attached to the running tool 150 creates a
differential pressure across the locking sleeve 158. If a
sufficient differential pressure is created, the force applied on
the locking sleeve 158 causes breakage of the shearing mechanism
and upward movement of the locking sleeve 158. A groove 157 of the
locking sleeve 158 allows the locking dogs 152 to drop away from
the recess 154 of the nipple 156 when the locking sleeve 158 has
moved upwardly by a sufficient distance. This causes the running
tool 150 to disengage from the nipple 156, as shown in FIG. 4B.
[0046] Once the dogs 152 are disengaged, a further increase in the
differential pressure across the ball 200 sitting in the seat 160
may shear the shearing mechanism attaching the ball seat 160 to the
running tool 150. The ball seat 160 then translates downwardly to
impact the shoulder 163 of the pulling tool housing 131. At this
point, the force applied against the ball 200 can push the upper
ring 161 of the ball seat 160 outwardly so that the ball 200 can
pass through the ball seat. The ball 200 drops into the pulling
tool 130 to sit in the seat 146 of the pulling tool, as shown in
FIG. 4C. The running string including the pipe 170, the running
tool 150, and the pulling tool 130 is then lowered to engage the
pulling tool 130 inside the cement protector 100. If the liner
devices are positioned outside the casing 12 instead of the liner
14, then the running tool 150 may be omitted.
[0047] As shown in FIG. 4D, as the pulling tool 130 is lowered into
the cement protector sleeve 110, the fingers 136 are pushed
upwardly and radially collapsed by abutment with the upper end of
the cement protector sleeve 110. As the pulling tool 130 is pushed
further into the cement protector sleeve 110, the seals 144 carried
by the pulling tool 130 are sealingly engaged in the seal bore 122
of the cement protector sleeve 110, as shown in FIG. 4E. Also, the
protruding portions 142 of the fingers 136 are engaged in the
recess 120 of the locking sleeve 116.
[0048] When running in, the running string is releasably attached
to an upper end of the liner string to avoid two generally
concentric tubular structures (the liner 14 and the pipe 170)
traversing a large distance together, which may greatly increase
the weight of the run-in assembly. Instead, according to some
embodiments, the running string is moved downwardly from the upper
end of the liner string to the lower end to engage the cement
protector 100 after the liner hanger 16 is set.
[0049] More generally, the running string may be replaced with any
type of run-in tool, and the cement protector 100 may be replaced
with any type of run-in receiver. The general concept is that the
run-in tool lowers a liner or some other downhole structure into
the wellbore, followed by releasing the run-in tool. Next, the
run-in tool is lowered into the wellbore until it is received by
the run-in receiver or coupled to the liner 14.
[0050] When the pulling tool 130 is engaged in the cement protector
sleeve 110, fluid communication is provided between the inside of
the running string 170 and the inside of the cement protector
sleeve 110 through the angled conduits 148. As further shown in
FIG. 4E, the cementing operation is started, in which a cement
slurry 202 is pumped through the angled conduits 148 of the pulling
tool 130 into the inner bore of the cement protector sleeve 110.
The cement slurry is pumped by downward movement of a cement plug
203 (not shown in FIG. 4E but shown in FIG. 4F). As elevated
pressure is applied above the plug 203 to supply the downward
movement. The cement slurry flows through the ports 132 of the
cement protector 100 and conduits 134 of the connector sub 102 into
the liner shoe 22 through the check valve 106. The cement slurry
continues through liner shoe openings 107 into the annulus region
105 between the outer wall of the liner 14 and the inner wall of
the wellbore 10. As shown in FIG. 4F, the cement slurry continues
up an annulus region 174 between the outside of the liner 14 and
the inside of the casing 12. The cementing operation may be stopped
once the plug 203 contacts the ball 200. The cement between the
outside of the liner 14 and the inside of the casing 12 provides a
relatively good seal to prevent leakage of wellbore fluids up the
annulus region between the liner and casing.
[0051] After the cementing operation has been completed, the
running string may be pulled out of the wellbore 10. As shown in
FIG. 4G, an upward shifting of the running string causes the
protruding portions 142 of the fingers 136 to pull upwardly on the
locking sleeve 116 of the cement protector. Upward movement of the
locking sleeve 116 enables release of the locking dogs 114 so that
the cement protector 100 is released from the liner 14. At this
point, the running string and cement protector 100 may be pulled
out of the wellbore, as shown in FIG. 4H. The cement protector 100
may be easily retrieved before the cement has dried. As the cement
protector 100 is retrieved, the cement remains inside the cement
protector sleeve 110, with the inner wall of the liner 14 remaining
substantially clear of cement. It is noted that some leakage of
cement may flow into the inner bore of the liner 14. However, the
amount of such leakage may be small enough so that a subsequent
cleaning operation is not needed.
[0052] As further illustrated in FIG. 4H, an orienting profile 210
is provided in the inner wall of the liner 14 to allow alignment of
connector(s) of the completion string with the connector(s) of the
liner 14. Next, as shown in FIG. 4I, the completion string,
including a flow control device 212 (in one example embodiment) and
a connector sub 214, may be run into the wellbore. The connector
sub 214 is oriented by the orienting profile 210 to align the
connector(s) 32 to the liner connector(s) 24.
[0053] In accordance with some embodiments, downhole components
have been described to enable connection between devices positioned
outside of a liner and components inside the liner. This may be
accomplished by running one or more control lines from the liner
devices to one or more connectors that provide connection points
inside the liner below the well surface. The one or more connectors
may include electrical connectors (e.g., direct contact
connectors), inductive connectors (e.g., inductive couplers),
optical connectors (e.g., fiber optic connectors), hydraulic
connectors, or other connectors. The one or more control lines may
be electrical lines, fiber optic lines, hydraulic lines, or other
control lines.
[0054] In accordance with further embodiments, a cement protector
may be used during cementing operations to protect both the inside
of the liner as well as the one or more connectors attached to the
liner. The cement protector includes a sleeve that isolates cement
from the inside of the liner during a cementing operation. The
cement protector is engageable to a pulling tool that is attached
to a running tool. The running tool in turn is connected to a pipe
through which a cement slurry can be pumped. The cement slurry
pumped through the inner bore of the pipe enters the sleeve of the
cement protector. One or more ports are provided in the cement
protector to enable communication of the cement slurry to an
annulus region between the outer wall of the liner and the inner
wall of the wellbore.
[0055] While the invention has been disclosed with respect to a
limited number of embodiments, those skilled in the art will
appreciate numerous modifications and variations therefrom. It is
intended that the appended claims cover all such modifications and
variations as fall within the true spirit and scope of the
invention. For example, instead of using locking dog assemblies in
the described attachment mechanisms, other releasable attachment
mechanisms may be used, such as those including collets. Also,
instead of using a ball dropped from the well surface to create
isolation for generating an elevated pressure, a valve (e.g., a
ball valve) may be used instead.
* * * * *