U.S. patent application number 13/884244 was filed with the patent office on 2014-01-09 for remote operation of setting tools for liner hangers.
The applicant listed for this patent is Lev Ring, Sorin Gabriel Teodorescu. Invention is credited to Lev Ring, Sorin Gabriel Teodorescu.
Application Number | 20140008083 13/884244 |
Document ID | / |
Family ID | 44999972 |
Filed Date | 2014-01-09 |
United States Patent
Application |
20140008083 |
Kind Code |
A1 |
Ring; Lev ; et al. |
January 9, 2014 |
Remote Operation of Setting Tools for Liner Hangers
Abstract
Methods and systems are provided for remotely operating a
setting tool for a liner hanger (402) independent of a ball seating
or dart landing. Operating the setting tool independent of the ball
seating or dart landing may allow for a sufficient pressure
differential to properly set the liner hanger.
Inventors: |
Ring; Lev; (Houston, TX)
; Teodorescu; Sorin Gabriel; (The Woodlands, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Ring; Lev
Teodorescu; Sorin Gabriel |
Houston
The Woodlands |
TX
TX |
US
US |
|
|
Family ID: |
44999972 |
Appl. No.: |
13/884244 |
Filed: |
November 11, 2011 |
PCT Filed: |
November 11, 2011 |
PCT NO: |
PCT/US11/60465 |
371 Date: |
June 17, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61413233 |
Nov 12, 2010 |
|
|
|
61429676 |
Jan 4, 2011 |
|
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61491755 |
May 31, 2011 |
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Current U.S.
Class: |
166/382 ; 166/70;
166/72 |
Current CPC
Class: |
E21B 23/06 20130101;
E21B 47/13 20200501; E21B 47/16 20130101; E21B 33/05 20130101; E21B
47/12 20130101; E21B 43/105 20130101; E21B 23/01 20130101; E21B
33/13 20130101 |
Class at
Publication: |
166/382 ; 166/72;
166/70 |
International
Class: |
E21B 47/12 20060101
E21B047/12; E21B 33/13 20060101 E21B033/13; E21B 43/10 20060101
E21B043/10; E21B 33/05 20060101 E21B033/05; E21B 23/01 20060101
E21B023/01; E21B 47/16 20060101 E21B047/16 |
Claims
1. A method for remotely operating a setting tool for a liner
hanger in a wellbore, the method comprising: exchanging signals
between a first device and a second device via a medium in
connection with the setting tool, wherein the second device is
adjacent to the setting tool; and performing operations of the
setting tool corresponding to the exchanged signals.
2. The method of claim 1, wherein the medium is a metal pipe.
3. The method of claim 1, wherein the first device is located at a
rig floor of the wellbore.
4. The method of claim 1, wherein the signals comprise acoustic
signals and electromagnetic (EM) signals.
5. The method of claim 4, wherein the acoustic signals are
transmitted by an acoustic transmitter that is in physical contact
with the medium.
6. The method of claim 4, wherein the acoustic signals are
transmitted longitudinally, transversely, or a combination of both
with respect to the medium.
7. The method of claim 4, wherein the EM signals are exchanged by
toroidal coils that are not in physical contact with the
medium.
8. The method of claim 4, wherein the EM signals are exchanged by a
single-wire line transmission system.
9. The method of claim 1, wherein exchanging the signals comprises
transmitting a signal for actuating the operations of the setting
tool, wherein the signal is transmitted from the first device to
the second device.
10. The method of claim 1, further comprising receiving a signal
confirming the operations of the setting tool, wherein the signal
is received at the first device, originating from the second
device.
11. The method of claim 10, wherein the operations comprise
actuating at least one of a valve, a tool, and a monitoring
sensor.
12. The method of claim 11, wherein receiving the signal comprises
receiving confirmation of actuation of at least one of the valve,
the tool, and the monitoring sensor.
13. The method of claim 10, wherein receiving the signal comprises:
receiving a signal comprising force and displacement measurements
of the liner hanger; and confirming proper setting of the liner
hanger based on the signal.
14. The method of claim 1, wherein exchanging the signals comprises
exchanging signals through a body of water using sonar or an
acoustic modem.
15. The method of claim 1, further comprising: exchanging other
signals between the first device and a third device via a medium in
connection with a cementing head, wherein the third device is
adjacent to the cementing head; and performing cementing head
operations corresponding to the other exchanged signals.
16. The method of claim 15, wherein exchanging the other signals
comprises transmitting a signal for actuating operations of the
cementing head, wherein the signal is transmitted from the first
device to the third device.
17. The method of claim 16, further comprising receiving a signal
confirming the operations of the cementing head, wherein the signal
is received at the first device, originating from the third
device.
18. The method of claim 17, wherein sensors confirm the operations
of the cementing head.
19. The method of claim 15, wherein the cementing head operations
comprise dropping plugs, darts, tool activation, and confirmation
devices into the wellbore.
20. The method of claim 19, further comprising: receiving a signal
confirming proper placement of the plugs into the wellbore, wherein
the signal is received at the first device, originating from the
second device; and upon receiving the signal confirming the proper
placement, performing the operations of the setting tool.
21. The method of claim 20, wherein sensors confirm proper
placement of the plugs into the wellbore.
22. A system for remotely operating a setting tool for a liner
hanger in a wellbore, the system comprising: a first device located
at a rig floor of the wellbore; a second device adjacent to the
setting tool; and a control unit for remotely operating the setting
tool, wherein the control unit is configured to: exchange signals
between the first device and the second device via a medium in
connection with the setting tool; and perform operations of the
setting tool corresponding to the exchanged signals.
23. The system of claim 22, wherein the signals comprise acoustic
signals and electromagnetic (EM) signals.
24. The system of claim 22, the control unit configured to exchange
the signals comprises transmitting a signal for actuating the
operations of the setting tool, wherein the signal is transmitted
from the first device to the second device.
25. The system of claim 22, wherein the control unit is configured
to receive a signal confirming the operations of the setting tool,
wherein the signal is received at the first device, originating
from the second device.
26. The system of claim 25, wherein the control unit configured to
receive the signal comprises: receiving a signal comprising force
and displacement measurements of the liner hanger; and confirming
proper setting of the liner hanger based on the signal.
27. The system of claim 22, wherein the control unit configured to
exchange the signals comprises exchanging signals through a body of
water using sonar or an acoustic modem.
28. The system of claim 22, further comprising: a third device
adjacent to a cementing head; and another control unit for remotely
operating the cementing head, wherein the other control unit is
configured to: exchange other signals between the first device and
the third device via a medium in connection with the cementing
head; and perform cementing head operations corresponding to the
other exchanged signals.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims benefit of U.S. Provisional Patent
Application Ser. No. 61/413,233, filed Nov. 12, 2010, Ser. No.
61/429,676, filed Jan. 4, 2011, and Ser. No. 61/491,755, filed May
31, 2011, which are herein incorporated by reference.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] Embodiments of the present invention generally relate to
remote operation of a setting tool for a liner hanger.
[0004] 2. Description of the Related Art
[0005] In wellbore construction and completion operations, a
wellbore is initially formed to access hydrocarbon-bearing
formations (i.e., crude oil and/or natural gas) by the use of
drilling. Drilling is accomplished by utilizing a drill bit that is
mounted on the end of a drill support member, commonly known as a
drill string. To drill within the wellbore to a predetermined
depth, the drill string is often rotated by a top drive or rotary
table on a surface platform or rig, or by a downhole motor mounted
towards the lower end of the drill string. After drilling to a
predetermined depth, the drill string and drill bit are removed and
a section of casing is lowered into the wellbore.
[0006] An annulus is thus formed between the string of casing and
the formation. The casing string is temporarily hung from the
surface of the well. A cementing operation is then conducted in
order to fill the annular area with cement. The casing string is
cemented into the wellbore by circulating cement into the annulus
defined between the outer wall of the casing and the borehole. The
combination of cement and casing strengthens the wellbore and
facilitates the isolation of certain areas of the formation behind
the casing for the production of hydrocarbons.
[0007] It is common to employ more than one string of casing or
liner in a wellbore. In this respect, the wellbore is drilled to a
first designated depth with a drill bit on a drill string. The
drill string is removed. A first string of casing is then run into
the wellbore and set in the drilled out portion of the wellbore,
and cement is circulated into the annulus behind the casing string.
Next, the wellbore is drilled to a second designated depth, and a
second string of casing or liner, is run into the drilled out
portion of the wellbore. If the second string is a liner, the liner
string is set at a depth such that the upper portion of the second
liner string overlaps the lower portion of the first string of
casing. The second liner string is then fixed, or "hung" off of the
existing casing using a liner hanger to fix the new string of liner
in the wellbore. The second liner string is then cemented.
[0008] A tie-back casing string may then be landed in a polished
bore receptacle (PBR) of the second liner string so that the bore
diameter is constant through the liner to the surface. This process
is typically repeated with additional liner strings until the well
has been drilled to total depth. As more casing or liner strings
are set in the wellbore, the casing or liner strings become
progressively smaller in diameter in order to fit within the
previous casing string. In this manner, wells are typically formed
with two or more strings of casing and/or liner of an
ever-decreasing diameter.
[0009] The process of hanging a liner off of a string of surface
casing or other upper casing string involves the use of a liner
hanger. The liner hanger is typically run into the wellbore above
the liner string itself. The liner hanger is actuated once the
liner is positioned at the appropriate depth within the wellbore.
The liner hanger is typically set through actuation of slips that
ride outwardly on cones in order to frictionally engage the
surrounding string of casing. The liner hanger operates to suspend
the liner from the casing string. However, it does not provide a
fluid seal between the liner and the casing. Accordingly, a packer
may be set to provide a fluid seal between the liner and the
casing.
[0010] However, due to insufficient pressure, the liner may not be
positioned at the appropriate depth within the wellbore for
actuating the liner hanger. For example, a ball or dart may not be
properly seated in a valve of the liner, which may lead to a lack
of pressure for causing the liner to be positioned at the
appropriate depth. Accordingly, what is needed are techniques and
apparatus for installing a liner (e.g., activating liner hanger
operations) independently of a ball seating or a dart landing.
SUMMARY OF THE INVENTION
[0011] One embodiment of the present invention provides a method
for remotely operating a setting tool for a liner hanger in a
wellbore. The method generally includes exchanging signals between
a first device and a second device via a medium in connection with
the setting tool, wherein the second device is adjacent to the
setting tool, and performing operations of the setting tool
corresponding to the exchanged signals.
[0012] Another embodiment of the present invention is a system for
remotely operating a setting tool for a liner hanger in a wellbore.
They system generally includes a first device located at a rig
floor of the wellbore, a second device adjacent to the setting
tool, and a control unit for remotely operating the setting tool.
The control unit is typically configured to exchange signals
between the first device and the second device via a medium in
connection with the setting tool and perform operations of the
setting tool corresponding to the exchanged signals.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] So that the manner in which the above recited features of
the present invention can be understood in detail, a more
particular description of the invention, briefly summarized above,
may be had by reference to embodiments, some of which are
illustrated in the appended drawings. It is to be noted, however,
that the appended drawings illustrate only typical embodiments of
this invention and are therefore not to be considered limiting of
its scope, for the invention may admit to other equally effective
embodiments.
[0014] FIG. 1 illustrates a drilling system, according to an
embodiment of the present invention.
[0015] FIGS. 2A-B illustrate the setting of a liner string in an
outer casing string, according to an embodiment of the present
invention.
[0016] FIG. 3 is a flow diagram of exemplary operations for
actuating operations of a setting tool for a liner hanger,
according to an embodiment of the present invention.
[0017] FIGS. 4A-C illustrate deployment and installation of a liner
assembly, according to an embodiment of the present invention.
DETAILED DESCRIPTION
[0018] FIG. 1 illustrates a drilling system 100, according to an
embodiment of the present invention. The drilling system 100 may
include a derrick 110. The drilling system 100 may further include
drawworks 124 for supporting, for example, a top drive 142. A
workstring 102 may comprise joints of threaded drill pipe connected
together, coiled tubing, or casing. For some embodiments, the top
drive 142 may be omitted (e.g., if the workstring 102 is coiled
tubing). A rig pump 118 may pump drilling fluid, such as mud 114,
out of a pit 120, passing the mud through a stand pipe and Kelly
hose to the top drive 142. The mud 114 may continue into the
workstring 102. The drilling fluid and cuttings, collectively
returns, may flow upward along an annulus formed between the
workstring and one of the casings 119i,o, through a solids
treatment system (not shown) where the cuttings may be separated.
The treated drilling fluid may then be discharged to the mud pit
120 for recirculation. A surface controller 125 may be in data
communication with the rig pump 118, pressure sensor 128, and top
drive 142.
[0019] After a first section of a wellbore 116 has been drilled, an
outer casing string 119o may be installed in the wellbore 116 and
cemented 111o in place. The outer casing string 1190 may isolate a
fluid bearing formation, such as aquifer 130a, from further
drilling and later production. Alternatively, fluid bearing
formation 130a may instead be hydrocarbon bearing and may have been
previously produced to depletion or ignored due to lack of adequate
capacity. After a second section of the wellbore 116 has been
drilled, an inner casing string 119i may be installed in the
wellbore 116 and cemented 111i in place. The inner casing string
119i may be perforated and hydrocarbon bearing formation 130b may
be produced, such as by installation of production tubing (not
shown) and a production packer.
[0020] For some embodiments, the inner casing string may be set at
a depth such that the upper portion of the inner casing string
overlaps the lower portion of the outer casing string. The inner
casing string may be known as a liner string. The liner string may
then be fixed, or "hung" off of the outer casing string using a
liner hanger (e.g., by the use of slips that utilize slip members
and cones to frictionally affix the inner casing string in the
wellbore).
[0021] FIGS. 2A and 2B illustrate the setting of a liner string 200
in an outer casing string 201. In one embodiment, a liner 200 may
be assembled conventionally on a rig floor. The liner 200 may be
suspended from the rig floor and held in place using slips, such as
from a spider or a rotary table. A false rotary table may be
mounted above the slips holding the liner 200. Then, an inner
string 220 may be run into the liner 200, as shown in FIGS. 2A and
2B.
[0022] FIG. 2A is an external view of the liner 200, and FIG. 2B is
an internal view of the liner 200. The liner 200 may include a
casing shoe 230 disposed at an end thereof. A lower portion of the
inner string 220 may include a device, such as a seal cup 225, to
allow pressurizing the internal area 215 of the liner 200 between
the shoe 230 and the seal cup 225. In one embodiment, the inner
string 220 may include a piston assembly instead of or in addition
to the seal cup 225. The inner string 220 may also include an
anchoring or latching device 240 to prevent relative axial movement
between liner 200 and the inner string 220. In one embodiment, the
inner string 220 may be a drill pipe (e.g., workstring 102). The
inner string 220 may also include an expansion tool 260, such as a
rotary expander, a compliant expander, and/or a fixed cone
expander, to expand at least a portion of the liner 200.
[0023] The inner string 220 may be run all the way to the shoe 230
or to any depth within the liner 200. After the inner string is
located in the liner 200, the anchoring device 240 may be actuated
to secure the inner string 220 to the liner 200. After the inner
string 220 is assembled, the liner 200 may be released from the rig
floor and run into the wellbore 250 to a particular depth. The
depth to which the liner 200 is run may be limited by torque or
drag forces. In one embodiment, a ball 232 or dart is dropped to
close a circulation valve at the shoe 230. In another embodiment,
circulation may also be closed using a control mechanism, such as a
velocity valve or another closure device known to a person of
ordinary skill.
[0024] When the released ball 232 passes by the anchor device 240,
the ball 232 may de-actuate the anchor device 240 to release the
liner 200 from the inner string 220. After the ball 232 closes
circulation, pressure is supplied to increase the pressure in the
internal area 215 between the seal cup 225 and the shoe 230. The
pressure increase exerts an active liner pushing force against the
shoe 230, thereby causing the liner 200 to travel down further into
the wellbore 250. In this respect, the active liner pushing force
is equal to the pumping pressure multiplied by the piston area
within the liner 200. The internal pressurization of the liner 200
may help alleviate a tendency of the liner 200 to buckle as it
travels further into the wellbore 250. In one embodiment, the
active liner pushing force is provided in a direction that is
similar or parallel to the direction of the wellbore 250. In this
respect, the effect of the drag forces is reduced to facilitate
movement of the liner 200 within the wellbore 250.
[0025] After the liner 200 has been extended into the wellbore 250,
the pressure in the internal area 215 may be released. The inner
string 220 may then be lowered and/or relocated in the liner 200,
thereby repositioning the seal cup 225. The tools, such as the seal
cups 225, may be positioned at the top or at any location within
the liner 200. The seal cups 225 may be stroked within the liner
200 numerous times. The pressure may again be supplied to the
internal area 215 to facilitate further movement of the liner 200
within the wellbore 250. This process may be repeated multiple
times by releasing the pressure in the liner 200 and re-locating
the inner string 220.
[0026] In one embodiment, a hydraulic slip 270, or other similar
anchoring device, may be coupled to the liner 200 and/or the inner
string 220 to resist any reactive force provided on the string or
the liner that will push the string or liner in an upward direction
or in any direction toward the well surface. The hydraulic slip 270
may be operable to prevent the inner string 220 from being pumped
back to the surface, while forcing the liner 200 into the wellbore
250. In one embodiment, the hydraulic slip 270 may be coupled to
the interior of the liner 200 to engage the inner string 220. In
one embodiment, the hydraulic slip 270 may be coupled to the inner
string 220 to engage the liner 200. In one embodiment, the
hydraulic slip 270 may be coupled to the exterior of the liner 200
to engage the wellbore 250.
[0027] However, issues may arise wherein the ball 232 may not
properly land to close the circulation valve at the shoe 230.
Therefore, there may not be a sufficient pressure increase for
causing the liner 200 to travel down further into the wellbore 250
or for a liner hanger of the liner 200 to be set in the wellbore.
Accordingly, what is needed are techniques and apparatus for
installing a liner (e.g., activating liner hanger operations)
independently of a ball seating or a dart landing.
[0028] FIG. 3 illustrates operations 300 for remotely operating a
setting tool for a liner hanger independently of a ball seating or
a dart landing, according to certain embodiments of the present
invention. Examples of operations of the setting tool generally
include actuating at least one of a valve, a tool, and a monitoring
sensor. The operations may begin at 302 by exchanging signals
between a first device (e.g., located at a rig floor of the
wellbore) and a second device via a medium (e.g., a metal pipe) in
connection with the setting tool, wherein the second device may be
adjacent to the setting tool.
[0029] At 304, operations of the setting tool corresponding to the
exchanged signals may be performed. Exchanging the signals
generally includes transmitting a signal (e.g., acoustic or EM) for
actuating the operations of the setting tool, wherein the signal is
transmitted from the first device to the second device. For some
embodiments, the first device may then receive a signal originating
from the second device, confirming the operations of the setting
tool. For example, the first device may receive a signal comprising
force and displacement measurements of the liner hanger, and then
confirm proper setting of the liner hanger based on the signal.
[0030] For some embodiments, remote operation of the setting tool
may be combined with other oilfield operations, such as cementing
head operations (e.g., dropping plugs, darts, tool activation,
and/or confirmation devices--such as balls, radio-frequency
identification tags, etc.--into the wellbore). For example, signals
may be exchanged between the first device and a third device via a
medium in connection with a cementing head, wherein the third
device may be adjacent to the cementing head, and cementing head
operations may be performed corresponding to the exchanged signals.
The exchanged signals generally include transmitting a signal for
actuating operations of the cementing head, wherein the signal may
be transmitted from the first device to the third device. For some
embodiments, a signal confirming the operations of the cementing
head may be received at the first device, originating from the
third device. For example, sensors, such as proximity sensor, may
confirm the operations of the cementing head.
[0031] As an example of combining operations of the setting tool
and cementing head operations, a signal confirming proper placement
of the plugs into the wellbore may be received at the first device,
originating from the second device, and, upon receiving the signal
confirming the proper placement, operations of the setting tool
described above may be performed. For some embodiments, sensors,
such as proximity sensors, may confirm proper placement of the
plugs into the wellbore.
[0032] FIGS. 4A-C illustrate deployment and installation of a liner
assembly, according to an embodiment of the present invention. A
setting tool and liner assembly may be run into the wellbore 250
using a workstring 220. The setting tool and liner assembly may be
lowered into the wellbore until progress is impeded by frictional
engagement of the liner assembly with the wellbore 250. The liner
assembly may include an expandable liner hanger 402 (slips and
cones may be used instead of the expandable liner hanger 402), a
polished bore receptacle (PBR) (not shown), the shoe 230, and the
liner string 200. Members of the liner assembly may each be
longitudinally connected to one another, such as by a threaded
connection.
[0033] The workstring 220 may include a string of tubulars, such as
drill pipe, longitudinally and rotationally coupled by threaded
connections. The setting tool may include a latch 240, cones 404,
and a piston assembly 406. The setting tool may be longitudinally
connected to the workstring 220, such as by a threaded connection.
Members of the setting tool may each be longitudinally connected to
one another, such as by a threaded connection. The cones 404 may be
operable to radially and plastically expand the liner hanger 402
into engagement with the casing string 201 (or another liner
string) previously installed in the wellbore 250. The cones 404 may
be driven through the hanger 402 by the piston assembly 406.
[0034] FIG. 4A illustrates pumping cement through the setting tool.
After deployment of the liner assembly, fluid, such as drilling
mud, may be circulated to ensure that all of the cuttings have been
removed from the wellbore 250. A bottom dart 408 may be launched.
Cement slurry 409 may then be pumped from the surface into the
workstring 220. A spacer fluid (not shown) may be pumped in ahead
of the cement slurry 409. Once a predetermined quantity of cement
slurry 409 has been pumped, a top dart 410 may be pumped down the
workstring 220 using a displacement fluid, such as drilling
mud.
[0035] FIG. 4B illustrates the liner assembly cemented to the
wellbore 250. The bottom dart 408 may seat in a bottom wiper plug
432, release the bottom dart/plug from the setting tool, and land
in the shoe 230. Alternatively, the liner assembly may include a
float collar, the float valve may be located in the float collar,
and the bottom dart/plug may land in the float collar. A diaphragm
or valve in the bottom dart 408 may then rupture/open due to a
density differential between the cement slurry 409 and the
circulation fluid and/or increased pressure from the surface.
[0036] Pumping of the displacement fluid may continue and the top
dart 410 may seat in a top wiper plug 434, thereby closing the bore
therethrough and releasing the top wiper plug 434 from the setting
tool. The top dart/plug may then be pumped down the liner 200,
thereby forcing the cement slurry 409 through the liner 200 and out
into the liner annulus. Pumping may continue until the top
dart/plug seat against the bottom dart/plug, thereby indicating
that the cement slurry 409 is in place in the liner annulus.
[0037] However, as described above, the bottom dart 408 and/or top
dart 410 may not land properly (not shown) in the shoe 230 to close
the circulation valve, which may prevent the cement slurry 409 from
fully moving through the liner 200 and out into the annulus. In
addition, there may not be a sufficient pressure differential for
activating the setting tool for the liner hanger, as described
above.
[0038] Therefore, techniques and apparatus are provided for
installing a liner (e.g., activating liner hanger operations)
independently of a ball seating or a dart landing. FIG. 4B
illustrates a system for remotely operating a setting tool for a
liner hanger, according to an embodiment of the present invention.
The system generally includes a lower device 420 and an upper
device 412 for exchanging signals via a medium in connection with
the setting tool. The signals exchanged between the devices 412,
420 may actuate operations of the liner assembly, as will be
discussed further herein.
[0039] An example of a medium generally includes a metal pipe, such
as the workstring 220. As illustrated, the upper device 412 may be
located at the rig floor 424 and the lower device 420 may be
adjacent to the setting tool. The devices 412, 420 may each include
a control unit and a battery pack, although the devices 412, 420
may be powered by other various sources. The upper device 412 may
be controlled by a handheld device (not shown), for example, from
within a dog house (i.e., a safe distance from the wellbore;
outside zone zero). The handheld device may be wired to the control
unit of the upper device 412. For some embodiments, the system may
be a single-wire line transmission system, wherein the setting tool
may be used as the conductor, while both ends of the system use a
common path for the return current (e.g., earth return).
[0040] The signals 428 received by the lower device 420 may be
processed by the local control unit (dedicated microcontroller) and
actuate operations of the setting tool. The signals may be acoustic
or electromagnetic (EM) signals. When the signals 428 transmitted
by the upper device 412 are acoustic signals (e.g., transmitted by
a piezoelectric stack or a solenoid), the lower device 420 may
include piezoelectric sensors (e.g., accelerometer) for detecting
acoustic vibrations generated along an acoustic throughpipe (e.g.,
workstring 220).
[0041] For longer range communications (e.g., downhole), a solenoid
may be preferred over a piezoelectric stack. For some embodiments,
the acoustic signals may originate from a piezoelectric stack
clamped around the workstring 220. When using acoustic signals, the
signals may be transmitted longitudinally, transversely, or a
combination of both, with respect to the medium. For acoustic
signals, the devices 412, 420 may be in physical contact with the
medium (e.g., rigid contact with workstring 220). However, for EM
signals, the devices 412, 420 may not be in physical contact with
the workstring 220, allowing the workstring to rotate as well
during operations of the setting tool.
[0042] When the signals exchanged between the devices 412, 420 are
EM signals, the devices 412, 420 may include toroidal coils, as
will be discussed further herein. Various parameters of the
toroidal coils may be adjusted, such as the coil size, magnetic
core permeability, wire size, and the number of windings. More
specifically, each device 412, 420 may include two toroidal coils:
one for transmitting and another for receiving. A transmission
between the devices 412, 420 may be achieved by energizing the
winding of a transmission coil (e.g., the transmitting toroidal
coil of the upper device 412). As described above, the transmission
may be initiated by the handheld device.
[0043] The current that flows through the winding may produce a
magnetic flux in the core, which than induces a current in a
conductor positioned in the center of the toroid (e.g., workstring
220), which can represent various signals. The current generated
has to be high enough to overcome potential noise, yet low enough
to conserve power. If a string of voltage pulses is applied to the
coil, a corresponding string of current pulses may be induced in
the workstring 220.
[0044] The transmission may be received at the lower device 420
(e.g., by the receiving toroidal coil of the lower device 420) by
converting the current pulses flowing through the workstring 220
into voltage pulses. Confirmation of the operation may be indicated
by a signal transmitted from the lower device 420 to the upper
device 412. For some embodiments, the handheld device may receive
an indication of the confirmation. For some embodiments, multiple
confirmations may be received. For example, acknowledgment of
receipt of the command transmitted from the upper device 412 may be
received. As a further example, successful execution of the command
or an error may be indicated on the handheld device, which can lead
to the ability to troubleshoot the issue.
[0045] For some embodiments, each device 412, 420 may include a
single toroidal coil with a first winding for transmitting signals,
and a second winding for receiving signals, wherein the windings
may have different configurations. Examples of configurations that
may differ between the windings generally include a different
number of windings and a different diameter of wiring for the
winding. The receiver may require increased sensitivity to
compensate for noise that may be received (signal-to-noise ratio
(SNR)).
[0046] As described above, the lower device 420 may receive signals
428 from the upper device 412 for actuating operations of the liner
assembly. The operations may comprise actuating at least one of a
valve, a tool, and a monitoring sensor. Confirmation of actuation
of at least one of the valve, the tool, and the monitoring sensor
may be received. For some embodiments, after receiving the signal
428, the lower device 420 may decode the signal 428 to close a
flapper 418 (e.g., by a device), which may isolate the pressure in
the workstring 220 from the pressure in the wellbore 250.
[0047] In other words, the liner hanger 402 may be set independent
of a ball seating or a dart landing. Pressure may then be increased
in the workstring 220 to fracture shear screws 422 and operate the
piston assembly 406, thereby pushing the cones 404 through the
liner hanger 402 (FIG. 4C). Operations of a liner assembly are
discussed in U.S. Publication 2009/0272544, which is hereby
incorporated by reference in its entirety.
[0048] FIG. 4C illustrates the liner hanger 402 expanded into
engagement with the casing 201. The liner hanger 402 may rely on a
certain force or displacement to be fully set and/or sealed.
Therefore, measurements may need to be taken (e.g., by a load cell)
to confirm proper setting of the liner hanger 402. For some
embodiments, the lower device 420 may transmit the measurements via
a signal 430 through a casing (e.g., workstring 220) to the upper
device 412 located at the rig floor 424. The upper device 412 may
process the received signal to confirm proper setting of the liner
hanger 402. As described above, the signal 430 may be an acoustic
or electromagnetic signal. For some embodiments, the lower device
420 may transmit a signal indicating the release of the bottom and
top wiper plugs 432, 434 as described earlier.
[0049] Once the hanger 402 is expanded into engagement with the
casing 201 (or another liner), the setting tool may be retrieved to
the surface. Before retrieval to the surface, the setting tool may
be raised and fluid, such as drilling mud, may be reverse
circulated (not shown) to remove excess cement above the hanger 402
before the cement cures. Once the cement cures, the wellbore may be
completed, such as perforating the liner 200 and installing
production tubing to the surface, and the hydrocarbon-bearing
formation may be produced.
Remote Operation of Setting Tools For Liner Hangers in Subsea
Operations
[0050] Communications between a vessel and a subsea well that is
separated by a body of water may be performed by coupling at least
two means of communication. For example, it may be useful to
determine whether a liner hanger in the subsea well has properly
set a liner (e.g., by a load cell measurement). For some
embodiments, a transmitter (e.g., a piezoelectric stack or a
solenoid) wrapped around a well casing in the subsea well may
transmit a first signal through the well casing up to a floor of
the sea. As described above, the signal may be an acoustic signal
or an EM signal (e.g., using a toroidal coil). A device (receiving
unit) located at the floor of the sea may receive the first signal
transmitted from the transmitter and transmit a second signal up to
a surface of the sea using sonar or an acoustic modem.
[0051] Due to transmitting between multiple mediums (e.g., seawater
and within the wellbore), coupling of the first signal with the
second signal may be required for successfully determining whether
the liner hanger was properly set. For some embodiments, the second
signal may be transmitted by a remotely operated vehicle (ROV) that
is plugged in at a convenient location (e.g., at a blowout
preventer or a wellhead of the subsea well). For some embodiments,
a buoy may receive the second signal transmitted through the sea
and transmit a signal to a receiver located on the deck of the
vessel. The receiver located on the deck may process the signal to
confirm proper setting of the liner hanger.
[0052] For some embodiments, the direction of signal transmission
between the buoy and the device located at the sea floor may be
downwards when a signal is transmitted from the vessel to the
subsea well. For example, to install a liner independent of a ball
seating or dart landing, a signal may be transmitted from the
vessel to close a flapper in the subsea well, as described
above.
[0053] While the foregoing is directed to embodiments of the
present invention, other and further embodiments of the invention
may be devised without departing from the basic scope thereof, and
the scope thereof is determined by the claims that follow.
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