Patent Application
20140008083
1. Field of the Invention
Embodiments of the present invention generally relate to remote operation of a setting tool for a liner hanger.
2. Description of the Related Art
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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).
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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).
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).
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.
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.
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.
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.
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)).
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.
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 (
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.
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.
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.
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.
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.
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.
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/US11/60465 | 11/11/2011 | WO | 00 | 6/17/2013 |
| Number | Date | Country | |
|---|---|---|---|
| 61413233 | Nov 2010 | US | |
| 61429676 | Jan 2011 | US | |
| 61491755 | May 2011 | US |
