Remote Operation of Setting Tools for Liner Hangers

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.

DETAILED DESCRIPTION

FIG. 1illustrates a drilling system100, according to an embodiment of the present invention. The drilling system100may include a derrick110. The drilling system100may further include drawworks124for supporting, for example, a top drive142. A workstring102may comprise joints of threaded drill pipe connected together, coiled tubing, or casing. For some embodiments, the top drive142may be omitted (e.g., if the workstring102is coiled tubing). A rig pump118may pump drilling fluid, such as mud114, out of a pit120, passing the mud through a stand pipe and Kelly hose to the top drive142. The mud114may continue into the workstring102. The drilling fluid and cuttings, collectively returns, may flow upward along an annulus formed between the workstring and one of the casings119i,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 pit120for recirculation. A surface controller125may be in data communication with the rig pump118, pressure sensor128, and top drive142.

After a first section of a wellbore116has been drilled, an outer casing string119omay be installed in the wellbore116and cemented111oin place. The outer casing string1190may isolate a fluid bearing formation, such as aquifer130a, from further drilling and later production. Alternatively, fluid bearing formation130amay 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 wellbore116has been drilled, an inner casing string119imay be installed in the wellbore116and cemented111iin place. The inner casing string119imay be perforated and hydrocarbon bearing formation130bmay 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).

FIGS. 2A and 2Billustrate the setting of a liner string200in an outer casing string201. In one embodiment, a liner200may be assembled conventionally on a rig floor. The liner200may 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 liner200. Then, an inner string220may be run into the liner200, as shown inFIGS. 2A and 2B.

FIG. 2Ais an external view of the liner200, andFIG. 2Bis an internal view of the liner200. The liner200may include a casing shoe230disposed at an end thereof. A lower portion of the inner string220may include a device, such as a seal cup225, to allow pressurizing the internal area215of the liner200between the shoe230and the seal cup225. In one embodiment, the inner string220may include a piston assembly instead of or in addition to the seal cup225. The inner string220may also include an anchoring or latching device240to prevent relative axial movement between liner200and the inner string220. In one embodiment, the inner string220may be a drill pipe (e.g., workstring102). The inner string220may also include an expansion tool260, such as a rotary expander, a compliant expander, and/or a fixed cone expander, to expand at least a portion of the liner200.

The inner string220may be run all the way to the shoe230or to any depth within the liner200. After the inner string is located in the liner200, the anchoring device240may be actuated to secure the inner string220to the liner200. After the inner string220is assembled, the liner200may be released from the rig floor and run into the wellbore250to a particular depth. The depth to which the liner200is run may be limited by torque or drag forces. In one embodiment, a ball232or dart is dropped to close a circulation valve at the shoe230. 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 ball232passes by the anchor device240, the ball232may de-actuate the anchor device240to release the liner200from the inner string220. After the ball232closes circulation, pressure is supplied to increase the pressure in the internal area215between the seal cup225and the shoe230. The pressure increase exerts an active liner pushing force against the shoe230, thereby causing the liner200to travel down further into the wellbore250. In this respect, the active liner pushing force is equal to the pumping pressure multiplied by the piston area within the liner200. The internal pressurization of the liner200may help alleviate a tendency of the liner200to buckle as it travels further into the wellbore250. In one embodiment, the active liner pushing force is provided in a direction that is similar or parallel to the direction of the wellbore250. In this respect, the effect of the drag forces is reduced to facilitate movement of the liner200within the wellbore250.

After the liner200has been extended into the wellbore250, the pressure in the internal area215may be released. The inner string220may then be lowered and/or relocated in the liner200, thereby repositioning the seal cup225. The tools, such as the seal cups225, may be positioned at the top or at any location within the liner200. The seal cups225may be stroked within the liner200numerous times. The pressure may again be supplied to the internal area215to facilitate further movement of the liner200within the wellbore250. This process may be repeated multiple times by releasing the pressure in the liner200and re-locating the inner string220.

In one embodiment, a hydraulic slip270, or other similar anchoring device, may be coupled to the liner200and/or the inner string220to 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 slip270may be operable to prevent the inner string220from being pumped back to the surface, while forcing the liner200into the wellbore250. In one embodiment, the hydraulic slip270may be coupled to the interior of the liner200to engage the inner string220. In one embodiment, the hydraulic slip270may be coupled to the inner string220to engage the liner200. In one embodiment, the hydraulic slip270may be coupled to the exterior of the liner200to engage the wellbore250.

However, issues may arise wherein the ball232may not properly land to close the circulation valve at the shoe230. Therefore, there may not be a sufficient pressure increase for causing the liner200to travel down further into the wellbore250or for a liner hanger of the liner200to 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.

FIG. 3illustrates operations300for 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 at302by 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.

At304, 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.

FIGS. 4A-Cillustrate 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 wellbore250using a workstring220. 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 wellbore250. The liner assembly may include an expandable liner hanger402(slips and cones may be used instead of the expandable liner hanger402), a polished bore receptacle (PBR) (not shown), the shoe230, and the liner string200. Members of the liner assembly may each be longitudinally connected to one another, such as by a threaded connection.

The workstring220may include a string of tubulars, such as drill pipe, longitudinally and rotationally coupled by threaded connections. The setting tool may include a latch240, cones404, and a piston assembly406. The setting tool may be longitudinally connected to the workstring220, 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 cones404may be operable to radially and plastically expand the liner hanger402into engagement with the casing string201(or another liner string) previously installed in the wellbore250. The cones404may be driven through the hanger402by the piston assembly406.

FIG. 4Aillustrates 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 wellbore250. A bottom dart408may be launched. Cement slurry409may then be pumped from the surface into the workstring220. A spacer fluid (not shown) may be pumped in ahead of the cement slurry409. Once a predetermined quantity of cement slurry409has been pumped, a top dart410may be pumped down the workstring220using a displacement fluid, such as drilling mud.

FIG. 4Billustrates the liner assembly cemented to the wellbore250. The bottom dart408may seat in a bottom wiper plug432, release the bottom dart/plug from the setting tool, and land in the shoe230. 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 dart408may then rupture/open due to a density differential between the cement slurry409and the circulation fluid and/or increased pressure from the surface.

Pumping of the displacement fluid may continue and the top dart410may seat in a top wiper plug434, thereby closing the bore therethrough and releasing the top wiper plug434from the setting tool. The top dart/plug may then be pumped down the liner200, thereby forcing the cement slurry409through the liner200and out into the liner annulus. Pumping may continue until the top dart/plug seat against the bottom dart/plug, thereby indicating that the cement slurry409is in place in the liner annulus.

However, as described above, the bottom dart408and/or top dart410may not land properly (not shown) in the shoe230to close the circulation valve, which may prevent the cement slurry409from fully moving through the liner200and 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.FIG. 4Billustrates 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 device420and an upper device412for exchanging signals via a medium in connection with the setting tool. The signals exchanged between the devices412,420may actuate operations of the liner assembly, as will be discussed further herein.

An example of a medium generally includes a metal pipe, such as the workstring220. As illustrated, the upper device412may be located at the rig floor424and the lower device420may be adjacent to the setting tool. The devices412,420may each include a control unit and a battery pack, although the devices412,420may be powered by other various sources. The upper device412may 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 device412. 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 signals428received by the lower device420may 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 signals428transmitted by the upper device412are acoustic signals (e.g., transmitted by a piezoelectric stack or a solenoid), the lower device420may include piezoelectric sensors (e.g., accelerometer) for detecting acoustic vibrations generated along an acoustic throughpipe (e.g., workstring220).

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 workstring220. 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 devices412,420may be in physical contact with the medium (e.g., rigid contact with workstring220). However, for EM signals, the devices412,420may not be in physical contact with the workstring220, allowing the workstring to rotate as well during operations of the setting tool.

When the signals exchanged between the devices412,420are EM signals, the devices412,420may 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 device412,420may include two toroidal coils: one for transmitting and another for receiving. A transmission between the devices412,420may be achieved by energizing the winding of a transmission coil (e.g., the transmitting toroidal coil of the upper device412). 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., workstring220), 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 workstring220.

The transmission may be received at the lower device420(e.g., by the receiving toroidal coil of the lower device420) by converting the current pulses flowing through the workstring220into voltage pulses. Confirmation of the operation may be indicated by a signal transmitted from the lower device420to the upper device412. 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 device412may 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 device412,420may 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 device420may receive signals428from the upper device412for 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 signal428, the lower device420may decode the signal428to close a flapper418(e.g., by a device), which may isolate the pressure in the workstring220from the pressure in the wellbore250.

In other words, the liner hanger402may be set independent of a ball seating or a dart landing. Pressure may then be increased in the workstring220to fracture shear screws422and operate the piston assembly406, thereby pushing the cones404through the liner hanger402(FIG. 4C). Operations of a liner assembly are discussed in U.S. Publication 2009/0272544, which is hereby incorporated by reference in its entirety.

FIG. 4Cillustrates the liner hanger402expanded into engagement with the casing201. The liner hanger402may 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 hanger402. For some embodiments, the lower device420may transmit the measurements via a signal430through a casing (e.g., workstring220) to the upper device412located at the rig floor424. The upper device412may process the received signal to confirm proper setting of the liner hanger402. As described above, the signal430may be an acoustic or electromagnetic signal. For some embodiments, the lower device420may transmit a signal indicating the release of the bottom and top wiper plugs432,434as described earlier.

Once the hanger402is expanded into engagement with the casing201(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 hanger402before the cement cures. Once the cement cures, the wellbore may be completed, such as perforating the liner200and 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

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.