TECHNICAL FIELD

The present disclosure relates to a subsea tool assembly. The present disclosure also relates to a subsea tool communication system including the subsea tool assembly and a method of operating a subsea tool.

BACKGROUND

In subsea gas and oil drilling, completion and production operations, subsea tools can be used for a variety of purposes. Commonly, subsea tools are used to run-in and land (i.e. , secure) different subsea equipment in a wellhead or downhole in a wellbore. Such subsea tools include mechanically or hydraulically powered control devices that can be activated to operate the tool to set subsea equipment in place. In one such example, a tubing hanger running tool (THRT) is used to run-in, land and set a tubing hanger within a wellhead. THRTs can employ pressurised hydraulic fluid to energise dogs or seals of the tubing hanger such that they engage with the wellhead and fix the tubing hanger in place. Other examples include, but are not limited to, using subsea tools to run-in, land and/or operate packer devices, production tubing and/or valves.

Umbilicals are typically run from a platform or vessel at a sea surface to the tool to supply the necessary hydraulic fluid or electrical power for operation of the tool. Owing to the depths of subsea gas and oil operations, such umbilicals are very long, time consuming to deploy/retrieve, and heavy. This can make their storage and deployment in subsea operations cumbersome and costly. Moreover, the umbilicals will move around during operation owing to vessel and marine riser movements, for example as a consequence of subsea currents and surface wind conditions. This can put the umbilicals under harmful stresses and be put them at risk of detaching from the tool or the platform/vessel. This can lead to costly operational downtime, as the umbilical would need to be retrieved from beneath the surface and then repai red/reattached before operations can be resumed.

Accordingly, it may be desirable to provide a subsea tool assembly that removes the need for any connections to the sea surface via an umbilical.

Furthermore, after such subsea tools have been operated and the subsea equipment set in place, it may be necessary to have to conduct a separate testing operation to confirm that the subsea equipment has been set correctly. This operation requires pulling of the subsea tool to the sea surface and replacing it with a separate subsea testing apparatus that must then be placed downhole and operated to test the setting of the equipment. This can add significant downtime and cost to a subsea gas and oil operation. Moreover, should such testing indicate a fault with the setting of the equipment, the testing apparatus must be pulled and the tool operation repeated. This can increase costs and downtime further.

Accordingly, it may also be desirable to provide a subsea tool assembly that can remove the need for a separate testing apparatus to be employed after operation of the subsea tool.

There is also a general desire to allow live monitoring of the conditions downhole of the tool, and adapt the operation of the tool to react appropriately thereto.

The present disclosure looks to employ features that address some or all of the above concerns.

SUMMARY

From one aspect, the present disclosure provides a subsea tool assembly. The assembly comprises a string having a tubular body; a tool suspended from the string; and a package operatively connected to the tool and the string. The package houses at least a tool control device for controlling operation of the tool, a controller configured to selectively operate the tool control device, a first acoustic communication node configured to receive and transmit acoustic signals through the tubular body of the string, and an electrical power source for powering the tool control device, the first acoustic communication node, and the controller. The controller is in electronic communication with the first acoustic communication node, and is configured to decode acoustic control signals received thereby and selectively operate the tool control device in response thereto.

In an embodiment of the above, the tool control device is a hydraulic accumulator in fluid communication with the tool, and the controller selectively operates the hydraulic accumulator to supply hydraulic fluid to the tool.

In a further embodiment, the hydraulic accumulator includes a closed volume for containing hydraulic fluid enclosed within the package.

In yet a further embodiment, the hydraulic accumulator includes an electronically controlled valve that can be selectively opened or closed by the controller to allow hydraulic fluid to exit the closed volume or prevent hydraulic fluid from exiting the closed volume. In one example, the electronically controlled valve is a solenoid valve.

In a further embodiment of any of the above, the package further comprises a hydraulic fluid conduit in fluid communication with the hydraulic accumulator. The hydraulic fluid conduit extends from the package into the tool to supply hydraulic fluid to the tool.

In a further embodiment of any of the above, the electrical power source is a battery.

In a further embodiment of any of the above, the package is removably coupled to the string at a first axial end and removably coupled to the tool at an opposing, second axial end. In a particular embodiment, the package is threadably coupled to the string at the first axial end and threadably coupled to the tool at the second axial end. In one example, the first axial end and second axial end form tool joints with the string and tool, respectively.

In a further embodiment of any of the above, the assembly further comprises a second acoustic communication node positioned on the tubular body and spaced from the first acoustic communication node. The second acoustic communication node is configured to receive and relay acoustic signals from and to the first acoustic communication node through the tubular body of the string.

In a further embodiment of any of the above, the assembly further comprises a sensor for detecting data relating to an operational downhole or tool condition and configured to transmit the data reflecting the operational downhole or tool condition for communication to the first acoustic communication node. The first acoustic communication node generates an acoustic signal indicative of the operational downhole or tool condition from the data relating to the operational downhole or tool condition and transmits this uphole through the tubular body of the string.

In a further embodiment of any of the above, the subsea tool assembly is a landing tool assembly, the string is a landing string, and the tool is a tubular hanger running tool for running a tubing hanger into a wellhead. In one particular example, the tool control device is configured to actuate the tubular hanger running tool (THRT) to lock the tubing hanger in position within the wellhead.

From another aspect, the present disclosure provides a wireless subsea tool communication system. The system comprises the subsea tool assembly of the above aspect or any of its embodiments, a control terminal configured to selectively generate tool control signals for communication downhole, and a control communication device configured to receive tool control signals from the control terminal and convert these to acoustic signals. The control communication device is further configured to transmit the acoustic signals downhole through the tubular body of the string.

In an embodiment of the above, the control terminal and control communication device are located on an oil platform or vessel at a sea surface.

From yet another aspect, the present disclosure provides a method of operating a subsea tool. The method comprises the steps of: sending acoustic signals through a tubular body of a string; receiving the acoustic signals at a first acoustic communication node of a package operatively connected to the string; communicating the acoustic signals to a controller of the package; decoding the acoustic signals using the controller to provide a control signal for operating the subsea tool; sending the control signal to a tool control device; and activating the tool control device using the control signal to operate a tool operatively connected to the package.

In an embodiment of the above, the step of sending acoustic signals through a tubular body of a string further comprises: using a control terminal above a sea surface to provide the control signal; transmitting the control signal to a control communication device; converting the control signal to acoustic signals using the control communication device; and transmitting the acoustic signals through the tubular body of the string using the control communication device.

In a further embodiment of the above, the method further comprises the steps of: using a sensor to sense data relating to an operational downhole or tool condition; transmitting the data relating to an operational downhole or tool condition to the controller or the first acoustic communication node; generating an acoustic signal indicative of the operational downhole or tool condition using the first acoustic communication node; and transmitting this uphole through the tubular body of the string.

In further embodiment of the above, the method further comprises the steps of: using the control communication device to receive the acoustic signal indicative of the operational downhole or tool condition; converting the acoustic signal indicative of the operational downhole or tool condition to electronic data indicative of the operational downhole or tool condition; transmitting the electronic data indicative of the operational downhole or tool condition to the control terminal. In yet a further embodiment of the above, the method further comprises the steps of: outputting or interpreting the digital/electronic data indicative of the operational downhole or tool condition on the control terminal; and/or inputting a control signal via the control terminal in response to the digital/electronic data indicative of the operational downhole or tool condition.

Although certain advantages are discussed below in relation to the features detailed above, other advantages of these features may become apparent to the skilled person following the present disclosure.

BRIEF DESCRIPTION OF DRAWINGS

One or more non-limiting examples will now be described, by way of example only, and with reference to the accompanying figures in which:

Figure 1 shows a schematic representation of a subsea installation having features in accordance with embodiments of the present disclosure;

Figure 2 shows a schematic cross-sectional view of the package shown in FIG. 1;

Figure 3 shows a flow diagram depicting a method according to embodiments of the present disclosure; and

Figure 4 shows a flow diagram depicting a further method according to embodiments of the present disclosure.

DETAILED DESCRIPTION

FIG. 1 illustrates a subsea installation 1 including a wellbore 2 located on the sea floor 4 and a wellhead 6 positioned at an upper end (i.e. , an uphole end) of the wellbore 2. The depicted wellbore 2 has production tubing 5 secured therein in fluid communication with the wellhead 6. A blowout preventer (BOP) stack 7 is fitted to the wellhead 6 for operation, and in some examples, the wellhead 6 may include further valves or Christmas tree structures disposed thereon (not shown), as may be necessary for particular subsea oil and gas formations, equipment types, and applications. A riser 8 extends from the BOP stack 7 to a platform 9 floating on the sea surface 3. Although the depicted platform 9 is a floating platform, any other suitable type of oil and gas platform could be used, such as a platform fixed to the sea floor 4. In other embodiments, the platform 9 could instead be a suitable vessel, such as a floating drilling production storage and offloading (FDPSO) vessel. A subsea tool assembly 10 extends from the platform 9 to the wellhead 6 within the riser 8 and the BOP stack 7. The subsea tool assembly 10 includes a string 12 having a tubular body and a tool 14 suspended from the string 12. By suspended, it should be understood that the tool 14 is connected to the string 12 and extends downhole therefrom. A package 20 is operatively connected to the tool 14 and the string 12. By operatively connected, it should be understood that the package 20 is connected to both the string 12 and tool 14 in any suitable manner that permits the operation thereof (which will be discussed in further detail below). In the depicted embodiment, the package 20 is connected between the tool 14 and the string 12, and acts an intermediate member connecting the two. As discussed further below in relation to FIG. 2, the depicted package 20 is thus secured to the string 12 and tool 14 at respective opposing axial ends 28a, 28b.

In the depicted embodiment, the subsea tool assembly 10 is a landing tool assembly, the string 12 is a landing string, and the tool 14 is a tubular hanger running tool (THRT) for running a tubing hanger 16 into the wellhead 6. The tool 14 may also be used to recover the tubing hanger 16 from the wellhead 6. As discussed in more detail below, the package 20 includes a tool control device 21 that is configured to energise/actuate the THRT to lock the tubing hanger 16 in position within the wellhead 6. As is known in the art, such an activity may be conducted as part of a well completion operation. Once the tubing hanger 16 is secured within the wellhead 6, the subsea tool assembly 10 can be hydraulically disconnected, pulled uphole and removed from the installation 1. The use and operation of such THRTs and similar subsea landing tools are well-known in the art, and so do not warrant detailed discussion here.

Although the depicted subsea tool assembly 10 is a landing tool assembly for landing tubing hanger 16, it should be understood that the present disclosure extends to any other suitable type of subsea tool assembly. This may include, but is not limited to, a packer tool assembly including a casing string and a packer tool for securing casings downhole, a production landing tool assembly including a production string and production landing tool for securing production elements together, and the operation of multistage valves e.g., for completion operations. Indeed, generally, the present disclosure can extend to any subsea tool assembly in which elements need to be selectively energised/secured using a subsea tool.

With reference to FIG. 2, a schematic cross-section of the package 20 in accordance with one embodiment is shown. The package 20 houses a tool control device 21 for controlling operation of the tool 14, a controller 22 configured to selectively operate the tool control device 21, a first acoustic communication node 23, and an electrical power source 24 for powering the tool control device 21, the first acoustic communication node 23, and the controller 22.

The electrical power source 24 can also be used to power any additional components that may be housed within the package 20 and require electrical power to operate. Such components may include, but are not limited to, one or more sensors 29 (as discussed in greater detail below) or actuatable locking members (e.g., that can be used to lock the package 20 in place downhole). The electrical power source 24 can be any suitable electrical power storage device, such as a battery or a capacitor. In the depicted embodiment, the electrical power source 24 is a battery or a bank of batteries that are rechargeable/replaceable. Suitable types of battery include, but are not limited to, a Li-ion battery or a Na-ion battery. Such battery types can be readily integrated into the package 20 and can be configured to provide a high reserve of power. As will be appreciated, the power reserve of the battery can be readily tailored to meet the duration needs of a particular subsea operations. This allows the tool assembly 10 to be remotely operated by the package 20 for long enough to complete an operation without the risk of the electrical power source 24 needing to be recharged/replaced.

The first acoustic communication node 23 is configured to receive and transmit acoustic signals. In one embodiment, the node 23 includes one or more acoustic transducers that are operable to generate and transmit acoustic signals and/or receive acoustic signals. Of course, the node 23 can employ any other suitable type of device to receive and/or transmit acoustic signals, such as an acoustic modem.

As the first acoustic communication node 23 is housed in the package 20, which is operatively connected to the string 12, acoustic signals propagating through the tubular body of the string 12 will be readily received by the node 23. Likewise, acoustic signals generated by the node 23 will propagate through the tubular body of the string. In this manner, the first acoustic node 23 is configured to receive and transmit acoustic signals through the tubular body of the string 12. As will be discussed in more detail below, this can provide a particularly advantageous way to wirelessly control operation of the tool 14 from the platform 9.

The depth of subsea operations and thus the length of the string 12 needed to conduct them can be up to a few kilometres (km) (or several thousands of feet (ft)). In order to ensure acoustic signals are communicated more reliably through such long lengths of tubular body of the string 12 from the sea surface (i.e. , platform 9), a second acoustic communication node 33 can be optionally positioned on the tubular body of the string 12 uphole of the first acoustic communication node 23. The second acoustic communication node 33 is used to receive and transmit acoustic signals in the same manner as first acoustic communication node 23. In this manner, the second acoustic communication node 33 can receive and relay acoustic signals from and to the first acoustic communication node 23 through the tubular body of the string 12. The second acoustic communication node 33 may include its own electrical power source (e.g., a battery) to permit its independent operation.

The first and second acoustic communication nodes 23, 33 can be spaced any suitable distance apart, but in one example may be spaced apart by between 0.5-1.5 km (or around 1,500-5,000 ft).

In further embodiments, there may be additional (i.e., a plurality of second) acoustic communication nodes 33 disposed on the string 12. The plurality of acoustic nodes 33 will be spaced apart along the string 12 and act to receive and relay acoustic signals through the tubular body of the string 12 to the next adjacent acoustic communication node 33. This may permit more reliable communication for longer strings 12/deeper subsea operations. In this manner, the first and second communication nodes 23, 33 can form an acoustic communication network that can transmit acoustic signals up and down the tubular body of the string 12 from the platform 9 and/or the package 20.

In yet further embodiments, there may be additional (i.e., third) acoustic communication node(s) disposed downhole below the package 20 that can communicate to the first acoustic communication node 23. Such additional node(s) can be disposed in any suitable subsea location, such as on the tool 14, on the BOP stack 7, in the wellhead 6, or on the production tubing 5 or elsewhere in the wellbore. As will be appreciated by the skilled person, such additional node(s) can be used to e.g., communicate monitoring data on operational downhole or tool conditions (e.g., from a downhole sensor) or the success of a particular tool operation (e.g., using sensed data) uphole to the first acoustic communication node 23. This can then be relayed to the platform 9 via the second acoustic communication node(s) 33, as necessary. The controller 22 is in electronic communication with the tool control device 21 and is operable to send electronic signals to the tool control device 21 to selectively active and deactivate the tool control device 21 to operate the tool 14 as desired for a subsea operation. As discussed above, in the depicted embodiment, the tool control device 21 controls the landing of a tubing hanger 16 in the wellhead 6.

The controller 22 is also in electronic communication with the first acoustic communication node 23, and is configured to decode acoustic control signals received by the first acoustic communication node 23. The controller 22 is then able to selectively operate the tool control device 21 in response to the acoustic control signals received by the first acoustic communication node 23. In this manner, the package 20 can be used to control operation of the tool 14 remotely (e.g., from an uphole and/or sea surface location, such as platform 9) by sending acoustic control signals through the string 12.

The controller 22 can include any suitable combination of components to permit it to function in this manner. For example, the controller 22 can include an acoustic decoder, a processor and a memory. The acoustic decoder is configured to convert the acoustic control signal into electronic/digital data that can be interpreted by the processor utilising instructions stored on the memory, and communicated to the tool control device 21 as appropriate. In an embodiment, the controller 22 is a microcontroller that incorporates such components therein. As discussed further below, the controller 22 can further include an acoustic encoder that can convert electronic/digital data to acoustic signal data that is sent to the first communication node 23 to generate and transmit the acoustic signal. The controller 22 can also include a communication device, which may be a wireless communication device, such as an antenna, modem or other signal receiver that can receive signals from other downhole components, such as sensors. As discussed in more detail below, this can allow for encoding and communication of sensor data to the first acoustic communication node 23 for communication uphole.

In the depicted embodiment, the tool control device 21 is a hydraulic accumulator that is in fluid communication with the tool 14. The hydraulic accumulator stores pressurised hydraulic fluid that can be selectively deployed to energise the locking mechanism for the tool 14. In this manner, the controller 22 accordingly selectively operates the hydraulic accumulator to supply hydraulic fluid to the tool 14 (which in turn operates the tool). The depicted hydraulic accumulator includes a closed volume 25 for containing the hydraulic fluid that is enclosed within the package 20. The closed volume 25 can be filled with hydraulic fluid that can be pressurised and sealed therein before the package 20 is connected to the tool 14 and the string 12 and the assembly 10 is deployed downhole. In one exemplary embodiment, the closed volume can contain up to 15 litres of hydraulic fluid, and the hydraulic fluid can be pressurised to around 20.7 MPa (3,000 psi). Of course, different volumes and pressures can be employed depending on the operation being conducted and the force needed to operate the tool 14 in question.

The hydraulic accumulator also includes an electronically controlled valve 26, such as a solenoid valve, that can be selectively opened or closed by the controller 22 to allow the hydraulic fluid to exit or return to the closed volume 25 or prevent hydraulic fluid from exiting the closed volume 25. In this manner, the valve 26 is used to control the distribution of hydraulic fluid from the closed volume 25 to permit operation of the tool 14 when signaled by the controller 22. The package 20 further includes a hydraulic fluid conduit 27 that is in fluid communication with the hydraulic accumulator and electronically controlled valve 26. The hydraulic fluid conduit 27 extends from the package (e.g., axially in a downhole direction) into the tool 14 to supply hydraulic fluid thereto. The hydraulic fluid conduit 27 can be connected into the tool 14 when the package 20 is connected thereto, and permits the hydraulic fluid to be communicated to the necessary area/means to operate the tool 14. The hydraulic fluid conduit 27 can also include or form a slick joint with the tool 14 to allow for relative movements between the tool 14 and package 20 when the two are connected during operation.

As discussed above, the package 20 is operatively connected to both the string 12 and tool 14. In the depicted embodiment, the package 20 includes opposing axial ends 28a, 28b that are configured to provide for a removable connection to the string 12 and tool 14, respectively. In one example, first axial end 28a is threaded in a complementary manner to the string 12 and is threadably joined thereto, and the opposing, second axial end 28b is threaded in a complementary manner to the tool 14 and is threadably joined thereto. In particular, the first axial end 28a can include a box thread that receives a pin thread from the string 12, and the opposing axial end 28b includes a pin thread that is received in a box thread of the tool 14 (or vice versa). The box and pin threaded connections between the string 12 and the package 20 and the package 20 and the tool 14 form tool joints. Such tool joints permit secure attachment of the package 20 to survive the demanding conditions of subsea operations, and also permit more simple and convenient assembly and disassembly of the assembly 10 before and after such operations.

Although threaded connections have been exemplified, it should be understood than any other suitable removable connection can be used within the scope of the present disclosure. For example: the axial ends 28a, 28b could provide an interference fit with the string 12 and the tool 14 when inserted therein; the axial ends 28a, 28b could include keying members that lock into slots in the string 12 and the tool 14 when inserted therein; or the axial ends 28a, 28b could be locked in place within the string 12 and tool 14 using external locking bolts or members passing there through. If desired, the package 20 can also be fixedly attached to one or both of the string 12 and the tool 14. For example, the axial ends 28a, 28b may be welded or brazed to the string 12 and tool 14, respectively. Although possible, this may reduce operational flexibility and ease of storage and installation compared to the removable attachment means, which allow the string 12, tool 14 and package 20 to be readily separated from each other when not in use.

As shown, the fluid conduit 27 is housed in the package 20, and is shown passing through the axial end 28b for connection and communication with the tool 14. However, in alternative embodiments, the fluid conduit 27 can extend externally from a different part of the package 20 (e.g., a side or base of the package 20) and be connected to the tool 14 in any appropriate manner (e.g., by being received in a port in the side or base of the tool 14).

Although the aforementioned tool control device 21 has been depicted as a hydraulic accumulator, it should be understood that any other type of tool control device 21 that can be electrically controlled by the controller 22 can be employed within the scope of the present disclosure. For example, the tool control device 21 could instead include electrically controllable actuators that can be selectively operated to energise locking members in the tool 14 for landing of a subsea component. Other hydraulic control devices could also be used, such as an electrohydraulic servo valve (e.g., controlling a hydraulic spool valve) to selectively communicate pressurised hydraulic fluid to the tool 14.

By housing the aforementioned components within the package 20 and enabling wireless control thereof through the tubular body of the string 12 via the first acoustic communication node 23, the need to run an umbilical to the tool 14 to supply electrical and/or hydraulic power thereto from the sea surface is removed. In other words, the package 20 permits the assembly 10 to be used without an umbilical being attached thereto. This can provide several operational benefits, such as reducing the costs associated with the storage and running of subsea tools into the wellhead 6 or wellbore 2, and reducing the potential points of failure and operational downtime during when using the tool 14. Moreover, running the wireless control signals through the tubular body of the string 12 as acoustic signals allows the signals and data to be received and transmitted reliably in many different environments and operations, regardless of fluid, flow, formation, and depth. This can be an advantage over other methods that e.g., transmit data through a subsea fluid column passing through the assembly 10, a component of the wellhead 6, such as the BOP stack 7, or through part of the subsea formation/wellbore 2.

The subsea tool assembly 10 can further include a sensor 29 which detects data relating to an operational downhole or tool condition. Such an operational downhole or tool condition can relate to several different parameters of the tool 14, a subsea component or the formation, such as pressure, tension, compression, temperature, torque, and bending moment. A plurality of sensors 29 can also be implemented to measure different parameter and/or take measurements at multiple locations of interest along the wellbore 2, the tool 14 and/or wellhead 6 or other subsea component. A sensor communication device can be included with the sensor 29 to transmit the data reflecting the operational downhole or tool condition to the controller 22, which can encode the data to provide corresponding acoustic signal data that is communicated to first acoustic communication node 23. The first acoustic communication node 23 can then generate an acoustic signal indicative of the operational downhole or tool condition and transmit this uphole through the tubular body of the string 12.

In the depicted embodiment, a sensor 29 is provided as part of the package 20. It is powered by the electrical power source 24 and is electrically connected to the controller 22. In such an embodiment, the sensing means of the sensor 29 may be placed on an internal or external part of the package 20 in order to detect an operational downhole or tool condition relating thereto (e.g., pressure, temperature or loading). For example, the sensor 29 may be used downhole to monitor well barrier and well conditions. However, the sensor 29 needn’t be part of the package 20 and can be positioned in any suitable subsea location, such as on the tool 14, the wellhead 6, the tubing hanger 6, the production tubing 5, the BOP stack 7 or other subsea component, or indeed in the wellbore 2/formation itself.

If the sensor 29 is located externally to the package 20 then it can be provided with its own electrical power source (e.g., battery) so it can operate independently, and can include a wireless communication means (e.g., antenna or modem) that can wirelessly communicate sensor data to the controller 22. If the sensor 29 is placed more remotely from the package 20, it can communicate the data to a further acoustic communication system (e.g., another subsea controller and acoustic communication node arrangement) that can relay the sensor data acoustically to the first acoustic communication node 23 directly. For example, using the additional (i.e. , third) acoustic communication node(s) disposed downhole below the package 20 as discussed above.

Many different types of sensors can be used depending on the operational downhole or tool condition being investigated. For example, azimuth sensors can be used to detect rotational movements, e.g., of the tool 14 or subsea component being installed, and downhole gauges can be used to detect a variety of parameters, such as downhole pressure, temperature and/or flow. All such types of sensors are envisaged for use within the scope of the present disclosure.

In all these embodiments, the sensor 29 is generally configured to transmit the sensor data for communication to the first acoustic communication node 23, which can then generate acoustic signals to further communicate the data uphole.

When present, the second acoustic communication node 33 can further receive and relay the acoustic signals uphole. In this manner, in addition to the acoustic communication nodes 23, 33 being able to provide an acoustic control network for controlling the package 20 and operation of the tool 14, they can further provide an acoustic telemetry network for monitoring operational downhole or tool conditions.

As discussed further below, the sensor data/acoustic telemetry network can be used in a wider subsea tool communication system to allow operators to actively monitor wellbore 2 and wellhead 6 conditions during tool operation to determine if the use of a tool 14 was successful or not. This may advantageously avoid the need to conduct separate test operations to determine if the operation of the tool 14 was successful or not. For example, the sensor data can be used to determine if the correct setting loads were imparted to a tool/subsea component, or if the tool/subsea component are correctly aligned to provide a successful setting operation. In further examples, the sensor data can be used to determine if an adequate seal has been made, e.g., between the wellbore 2 and a subsea component, and/or to verify that the well barrier is intact and functional prior to recovery of the tubing hanger 16.

As shown in FIG. 1, a control terminal 30 and control communication device 32 can be provided on the sea surface on the platform 9 (or vessel). In combination with the subsea tool assembly 10, these can be said to provide a subsea tool communication system.

The control terminal 30 is configured to selectively generate tool control signals for communication downhole to the package 20 to control operation of the tool 14. The control communication device 32 is configured to receive the tool control signals from the control terminal 30 and convert these to acoustic control signals. The control communication device 32 is then further configured to transmit the acoustic control signals downhole through the tubular body of the string. In the depicted embodiment, the control communication device 32 is disposed on the string 12, although it may otherwise simply be in acoustic communication therewith. As discussed above, the acoustic control signals from the control communication device 32 will be received by the first acoustic communication node 23 (e.g., via node 33) and instruct the controller 22 to operate the tool 14 using the tool control device 21.

In the depicted embodiment, the control terminal 30 communicates wirelessly with the control communication device 32 (e.g., using a WiFi, Bluetooth, radio wave or other wireless communication means). This permits the control terminal 30 to be used remotely and/or at a safer distance from any operations. Alternatively, however, the control terminal 30 may be electrically connected to the control communication device 32.

If sensor data is being transmitted acoustically uphole as discussed above, the control communication device 32 is further configured to receive these acoustic sensor signals and convert and transmit this sensor data to the control terminal 30. The control terminal 30 can then interpret and/or display the sensor data that to allow monitoring of the operational downhole or tool condition from the sensor data. In this manner, the control terminal 30 may include a display that can output the operational downhole or tool condition data for an operator to view. The operator can accordingly use the control terminal 30 to input control signals for tool operation depending on the operation downhole or tool condition data. For example, if the operational downhole or tool condition data indicated that a setting or sealing operation was unsuccessful, the operator could send follow up control signals to operate the tool 14 a subsequent time or adjust the operation of the tool 14 using the package 20 (e.g., supply more energy thereto/rotate tool more) until the setting or sealing operation is successful. Of course, the control terminal 30 can use a computer program to automate such operational responses from the control terminal 30 if desired. The use of such feedback from the sensors via the subsea tool assembly 10 can avoid costly and time consuming pulling, testing and redeployment of tool operations.

FIG. 3 shows an exemplary method 300 of operating the subsea tool 14 utilising the subsea assembly 10 in accordance with the embodiments of the present disclosure. The method 300 includes the steps of: sending acoustic signals through the tubular body of the string 12 (step 305); receiving the acoustic signals at the first acoustic communication node 23 (step 306); communicating the acoustic signals to the controller 22 (step 307); decoding the acoustic signals using the controller 22 to provide the control signal for operating the subsea tool 14 (step 308); sending the control signal to a tool control device 21 (step 309); and activating the tool control device 21 using the control signal to operate the tool 14 (step 310).

As discussed above, when utilising the control terminal 30 and control communication device 32, prior to the above steps, the method 300 can further include the steps of: using the control terminal 30 above the sea surface to provide the control signal (step 301); transmitting the control signal wirelessly to the control communication device 32 (step 302); converting the control signal to acoustic signals using the control communication device 32 (step 303); transmitting the acoustic signals through the tubular body of the string 12 using the control communication device 32 (step 304).

FIG. 4 shows a further method 400 of operating the subsea tool when used in conjunction with embodiments including one or more sensors 29 as discussed above. The method 400 can be used in conjunction with method 300, and includes the steps of: using the sensor 29 to sense data relating to an operational downhole or tool condition (step 401); transmitting the data relating to the operational downhole or tool condition to the controller 22 or the first acoustic communication node 23 (step 402); generating an acoustic signal indicative of the operational downhole or tool condition using the first acoustic communication node 23 (step 403); and transmitting this uphole through the tubular body of the string 12 (step

404).

As discussed above, when utilising the control terminal 30 and control communication device 32, the method 400 can further include the steps of: using the control communication device 32 to receive the acoustic signal indicative of the operational downhole or tool condition (step 405); converting the acoustic signal indicative of the operational downhole or tool condition to digital/electronic data indicative of the operational downhole or tool condition (step 406); transmitting the digital/electronic data indicative of the operational downhole or tool condition to the control terminal (step 407). Step 407 permits the operator or a computer program to advantageously determine if a tool operation was successful and/or if further tool operation is required. For this purpose, the method can also further include the steps of: outputting or interpreting the digital/electronic data indicative of the operational downhole or tool condition on the control terminal 30 (step 408); and inputting a control signal via the control terminal 30 in response to the digital/electronic data indicative of the operational downhole or tool condition (step 409).

Although certain embodiments have been described and depicted, these are by way of example only, and various modifications and alternative embodiments may fall within the scope of the present disclosure as defined by the appended claims, communication device