ATMOSPHERIC BARRIER VALVE ON FIRE DEMAND USING A TEC LINE AND A HYDRAULIC OVERPRESSURE ASSEMBLY CROSS-REFERENCE TO AN ASSOCIATED DEMAND

Abstract

The invention relates to embodiments of systems and methods for actuation of a wellbore tool (290), comprising the steps of supplying a conductor (150) having a first end positioned at a surface location and a second end positioned at a downhole location, passing the wellbore through a cycle of varying well fluid pressures, moving a balancing piston (500) with the various well fluid pressures to generate pressure in a hydraulic overpressure assembly (440), transmitting an electrical signal from the top of the wellbore, through the conductor, and to the downhole location, receiving the signal at the downhole location, and using the pressure in the hydraulic overpressure assembly to move the downhole tool from a first configuration to a second configuration in response to the signal.In some embodiments, a hydraulic pressure booster assembly can generate pressure from a well fluid pressure cycle for subsequent use by the system. (Shorthand figure: Figure 1)

Description

Title of the invention: ATMOSPHERIC BARRIER VALVE ON FIRE DEMAND USING A LINE TEC AND A HYDRAULIC BOOSTER ASSEMBLY CROSS REFERENCE TO A RELATED REQUEST

[0001] The present application claims priority from U.S. Provisional Application No. 63 / 537,127, filed on September 7, 2023. CONTEXT

[0002] Wellbores are often drilled through subterranean formations for hydrocarbon exploration and recovery. Completing a well involves various downhole procedures before allowing production fluids to flow, thereby bringing the well online. Valves may be installed downhole to perform a variety of different functions. For example, valves may be installed downhole to form a barrier, isolating a section of the subterranean formation and / or the wellbore. In some cases, the downhole valve may be used to isolate one downhole section of the wellbore from another downhole section of the wellbore so that the integrity of a downhole tubular member (e.g., casing, liner, etc.) may be tested.In other cases, the downhole valve may be used to isolate a target reservoir from other sections of the wellbore, for example, to isolate the target reservoir during the installation of an upper completion. In still other cases, the downhole valve may be used to isolate sections of the wellbore for flow control.

[0003] Wireline tools have been used to operate downhole valves. However, multiple cable interventions into the wellbore may be required to open / close the downhole valve from the wellbore, adding unnecessary expense to drilling operations. Disadvantages of hydraulic control lines are the need for a control line connection from the surface to the downhole valve, which can be problematic when crossing packers and upper / lower completions. Downhole valves have also been operated from the surface using a hydraulic control line. Techniques have also been implemented to send pressure signals from the surface to operate the downhole valves.These techniques typically rely on a pressure signal sent from the surface to switch the downhole valve to a different configuration. The disadvantages of pressure signals are that repeated pressure signals (e.g., example, up to 20 cycles or more) may need to be sent to the downhole valve to actuate it, which may take undesirable drilling time to accomplish. Brief Description of the Drawings

[0004] These drawings illustrate certain aspects of certain embodiments of the present disclosure and should not be used to limit or define the disclosure.

[0005] [Fig-1] illustrates a wellbore system comprising the actuation of a tool downhole according to certain embodiments of the present disclosure.

[0006] [Fig.2] illustrates a cross-sectional view of a downhole tool according to certain embodiments of the present disclosure.

[0007] [Fig.3] illustrates a sectional view of an actuation system according to certain embodiments of the present disclosure.

[0008] [Fig.4] illustrates a sectional view of a latch assembly according to certain embodiments of the present disclosure.

[0009] [Fig.5] illustrates a sectional view of a spring assembly according to certain embodiments of the present disclosure.

[0010] [Fig.6] illustrates a sectional view of a ball valve assembly according to certain embodiments of the present disclosure.

[0011] [Fig.7] illustrates a sectional view of a hydraulic booster assembly according to certain embodiments of the present disclosure. DETAILED DESCRIPTION

[0012] Embodiments of systems and methods for actuating a wellbore tool are provided, including the steps of providing a conductor having a first end positioned at a surface location and a second end positioned at a downhole location, cycling the wellbore through varying well fluid pressures, moving a balance piston with the varying well fluid pressures to generate pressure in a hydraulic booster assembly, transmitting an electrical signal from above the wellbore, through the conductor, and to the downhole location, receiving the signal at the downhole location, and using the pressure in the hydraulic booster assembly to transition the downhole tool from a first configuration to a second configuration in response to the signal.In some embodiments, a hydraulic booster assembly may generate pressure from a cycle of well fluid pressures for subsequent use by the system.

[0013] Other embodiments wherein the downhole tool is a downhole valve, the first configuration is a closed valve, and the second configuration is an open valve. Other embodiments wherein the downhole tool is a downhole valve, the first configuration is an open valve, and the second configuration is a closed valve. Other embodiments wherein the step of using a hydraulic pressure relief assembly comprises releasing hydraulic pressure. Other embodiments further comprise monitoring electrical signals over time to establish a detected signal profile.

[0014] Other embodiments further include comparing the detected signal profile to a target signal profile. Other embodiments further include instructing an actuation system to operate to cause the downhole tool to transition in response to the comparing step. Other embodiments wherein the hydraulic booster assembly includes one or more compressible fluid chambers.

[0015] Embodiments of a system for actuating a downhole tool are provided, including a tubing string extending from a surface location through a first downhole location to at least one second downhole location; a conductor extending from the surface location to the first downhole location; a signal transmitter at the first downhole location that is coupled to the conductor; a signal receiver at a second downhole location that is downhole relative to the first downhole location, wherein the signal receiver is configured to receive electrical signals from the signal transmitter; a decoder at the second downhole location in electrical communication with the signal receiver; an actuator at the second downhole location in electrical communication with the decoder;a hydraulic booster assembly that generates pressure from a cycle of well fluid pressures; and a downhole tool at the second downhole location coupled to the hydraulic booster assembly.

[0016] Other embodiments of the system wherein the downhole tool comprises a downhole valve. Other embodiments of the system wherein the actuator comprises a pin pusher, a gate, one or more pistons and a spring. Other embodiments of the system wherein the hydraulic pressure relief assembly generates pressure in a chamber containing a compressible fluid. Other embodiments of the system wherein the hydraulic pressure relief assembly comprises a low pressure chamber and a high pressure chamber in fluid communication via a non-return valve.

[0017] Embodiments of a system for operating a downhole tool including a tubing string extending from a surface location through a first downhole location to at least one second downhole location; a conductor extending from the surface location to the first downhole location; a signal transmitter at the first downhole location that is coupled to the conductor and configured to transmit an electrical signal along the tubing string; a signal receiver at a second downhole location that is downhole relative to the first downhole location, wherein the signal receiver is configured to receive electrical signals from the signal transmitter that are transmitted through the conductor; a signal decoder at the second downhole location in signal communication with the signal receiver;an actuator at the second downhole location in signal communication with the signal decoder; a latch connected to the actuator that releases a spring-loaded piston when a specific signal is received at the decoder; and a downhole tool at the second downhole location coupled to the piston.

[0018] Other embodiments of the system further include a pin pusher within the actuator that moves toward a barrier member. Other embodiments of the system wherein a fracture of the barrier member establishes fluid communication between a fluid chamber and a discharge chamber. Other embodiments of the system further include a hydraulic pressure relief assembly that applies additional force to the piston in addition to the spring force.

[0019] Other embodiments of the system 16 further include a relief piston in the actuator that moves once fluid communication is established between the fluid chamber and the relief chamber. Other embodiments of the system 18 wherein movement of the relief piston releases a latch within the actuator. Other embodiments of the system wherein the pressure relief assembly includes a high pressure chamber filled with a compressible fluid; a low pressure chamber filled with the same compressible fluid and placed in fluid communication with the high pressure chamber via a check valve; and a balance piston positioned to move in response to changes in well fluid pressure.

[0020] Methods and systems for remotely transitioning a downhole tool 290 between different operational configurations are disclosed. Exemplary embodiments described herein include methods and systems for actuating downhole tools 290 (e.g., downhole valves, such as a ball valve) with a wired signal transmitted from a surface location 120 to a first downhole location 230, and then an electrical signal transmitted from the first downhole location 230 to a second downhole location 270. In some embodiments, the electrical signal may be transmitted via one or more tubulars 200 installed in the wellbore.

[0021] 100 Wellbore System

[0022] 110 Data acquisition control system

[0023] 120 Surface

[0024] 130 Superior Completion Packer

[0025] 140 Upper tubular element

[0026] 150 TEC Line

[0027] 160 Borehole

[0028] 170 Casing tube string

[0029] 180 Superior Completion

[0030] 190 Lower Completion

[0031] 200 Tube Train

[0032] 210 Lower Completion Packer

[0033] 220 Signal transmitter

[0034] 230 First downhole location

[0035] 240 Upper completion joint

[0036] 250 Underground Formation

[0037] 260 Lower tubular element

[0038] 270 Second downhole location

[0039] 280 Actuation system

[0040] 290 Downhole Tool

[0041] 300 Signal receiver

[0042] 310 Decoder

[0043] 320 Battery

[0044] 330 Spindle pusher

[0045] 340 Atmospheric chamber

[0046] 350 Fluid chamber

[0047] 360 Discharge Piston

[0048] 370 Barrier element

[0049] 375 Latch assembly

[0050] 380 Latch

[0051] 390 Valve body

[0052] 395 Spring assembly

[0053] 400 Spring

[0054] 420 Piston

[0055] 430 Ball Valve Assembly

[0056] 435 Ball valve

[0057] 440 Hydraulic pressure relief assembly

[0058] 450 Well fluids

[0059] 460 Low pressure chamber of compressible fluid

[0060] 470 Hydraulic components

[0061] 480 High pressure chamber for compressible fluid

[0062] 490 Piston seal

[0063] 500 Balance Piston

[0064] According to present embodiments, a system may be provided that remotely transitions a downhole tool 290 between different operational configurations. The system may include a control system 110 at the surface. The control system 110 may send a signal via a tube-encapsulated cable ("TEC") line 150 (or other suitable electrical conductor), from a signal transmitter 220 (of any type) to a first downhole location 230. The TEC line 150 may include a shield shell, at least one internal insulator disposed within the shield shell, and at least one electrical conductor disposed within the at least one insulator. The shield shell may include a metal tube (e.g., stainless steel, stainless steel alloys) for protection of the at least one electrical conductor.The signal transmitter 220 receives the signal and converts the signal into an electrical signal (or pulse, pattern, frequency, amplitude, or any combination thereof) which is then transmitted downhole to a second downhole location 270.

[0065] An actuation system 280 located at the second downhole location 270 may include a signal receiver or sensor 300 that listens for some type of electrical signal sent via the TEC line 150. The signal receiver 300 may be powered, for example, by a battery 320 or other suitable means. The actuation system 280 may be coupled to a downhole tool 290, which may be a downhole valve. The actuation system 280 receives the electrical signal, which may be a command to open or close the downhole valve, and triggers the downhole tool 290 to transition to a different configuration. In some embodiments, the actuation system 280 triggers the opening of a downhole valve. In some embodiments, the actuation system 280 triggers the closing of a downhole valve. For example, the actuation system 280 may release a spring 400 to push down and rotate the ball mechanism of the downhole valve. In some embodiments, the opening of the spring 400 may be assisted by a hydraulic pressure relief assembly.

[0066] [Fig.l] illustrates a wellbore system 100 from a surface location 120 through a subterranean formation 250. The wellbore system 100 includes a plurality of wellbore tools interconnected to form a tubing string extending through a casing string 170 that is cemented as a wellbore 160. The wellbore system 100 includes a control system 110 at the surface 120. The downhole system further includes an upper completion 180 and a lower completion 190. A TEC line 150 extends from the control system 110 to an electrical transmitter 220 in the upper completion 180 at a first downhole location 230. The lower completion 190 includes an actuation system 280 and a downhole tool hole 290.

[0067] Although [Fig. 1] depicts the well system in a specific well environment, one skilled in the art should understand that the well system may be used in a variety of different well environments. For example, the well system has a specific completion with completions greater than 180 and less than 190, but it should be understood that the well system may be used in wells that are completed in a different manner. As a further example, although [Fig. 1] depicts a vertical section of a wellbore, one skilled in the art should understand that the described embodiments may be used in wellbores having other configurations, including inclined wells, deviated wells, horizontal wells, or wells having lateral branches.Accordingly, those skilled in the art should understand that the use of directional terms such as above, below, upper, lower, up, down, left, right, and the like are made in connection with the illustrative embodiments as shown in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure. Although the wellbore 160 is shown as being cased, the well system may be used in wellbores that are not cased or that have uncased sections.

[0068] The well system 100 includes a control system 110 at the surface 120. The control system 110 may also include a data acquisition system for receiving signals from the wellbore 160, such as pressure and temperature signals, among others. The control system 110 may provide instructions to the downhole tool 290 located in the wellbore 160. The control system 110 may also receive and process signals from surface sensors 120 and / or downhole sensors (not shown). The control system 110 may present desired operational parameters and other information to an operator via one or more output devices, such as a display, computer screen, speakers, lights, etc., for example, which may be used by the operator to control drilling operations.

[0069] The control system 110 may include any instrument or set of instruments for calculating, classifying, processing, transmitting, receiving, retrieving, generating, switching, storing, displaying, manifesting, detecting, recording, reproducing, manipulating, or using any form of information, intelligence, or data for commercial, scientific, control, or other purposes. For example, the control system may be a personal computer, a network storage device, or any other suitable device and may vary in size, shape, performance, functionality, and price. The control system may include random access memory (RAM), one or more processing resources such as a central processing unit (CPU) or hardware or software control logic, ROM, and / or other types of non-volatile memory.Additional components of the control system may include one or more disk drives, one or more network ports for communication with external devices, and various input and output (1 / 0) devices, such as a keyboard, mouse, and video display. The control system may also include one or more buses for transmitting communications between the various hardware components. The control system may also include models and may process data according to programmed instructions and respond to user commands entered through an input device.

[0070] The well system may include upper 180 and lower 190 completions. The terms "lower completion" and "upper completion" are used to describe separate completion stages that are fluidly coupled or in fluid communication with the next completion stage to allow production fluid to flow. Although not shown, the well system 100 may also include one or more intermediate completions between the upper and lower completions. In some embodiments, the lower completion 190 refers to the portion of the wellbore that passes through the production or injection zone and includes perforations in the case of cemented casing such that production flow can penetrate the interior of the production tubing such that production fluid can flow to the surface.Typically, completion stages can be opened with valves (e.g., a downhole valve), and then the valves are then closed by mechanical or other means so that the completion stages can be . isolated from each other, where appropriate, for example, for fluid loss monitoring, pressure testing, etc.

[0071] The tubing string 200 preferably extends through the upper completion 180. In the upper completion 180, the tubing string 200 may include an upper tubular member 140, which may include one or more pipes or other conduits. The upper completion 180 may include an upper completion packer 130 that forms a seal between the upper tubular member 140 and the casing string 170 (or other outer tubular member). The upper completion 180 may also include an upper completion seal 240 (or other seal assembly) that forms a seal between the upper completion 180 and the lower completion 190. As illustrated herein, the upper completion seal 240 may form a seal between the upper tubular member 140 of the upper completion 180 and a lower tubular member 260 of the lower completion 190.Although the upper completion seal 240 is shown, exemplary embodiments may be leaky without a seal between the upper and lower completions.

[0072] The upper completion 180 further includes a signal transmitter 220 at a first downhole location 230. As illustrated, the signal transmitter 220 may be positioned in the wellbore 160 and coupled to an exterior surface of the upper tubular 140. A TEC line 150 may extend from the surface 120 to the signal transmitter 220. As illustrated, the TEC line 150 may extend from the control system 110 to the signal transmitter 220. The control system 110 may send a signal to the signal transmitter 220 via the TEC line 150. In some embodiments, the TEC line 150 may be attached to the upper tubular 140. In some embodiments, the TEC line 150 may be routed on an exterior surface of the upper tubular 140. In other embodiments (not shown), the TEC line 150 may be routed on an interior surface of the upper tubular member 140.

[0073] The tubing string 200 may extend from the upper completion 180 to the lower completion 190. In the lower completion 190, the tubing string 200 may include a lower tubular member 260, which may include one or more pipes or other conduits. The lower completion 190 may include a lower completion packer 210 that forms a seal between the lower tubular member 260 and the casing string 170 (or other outer tubular member). As illustrated, the lower tubing string 260 may be located near the intersection of the upper and lower completions.

[0074] The lower completion 190 may further include an actuation system 280 and a barrier valve. The actuation system 280 and the barrier valve may both be located at a second downhole location 270. The Actuation system 280 may be attached to the lower tubular member 260. As illustrated, the actuation system 280 may be positioned in the wellbore and coupled to the lower tubular member 260. In some embodiments, the actuation system 280 may be attached to an exterior surface of the lower tubular member 260. In some embodiments, the actuation system 280 may be housed in a sidewall of the lower tubular member 260. The actuation system 280 may be coupled to the downhole valve. The actuation system 280 may be used to operate the downhole tool 290 which may include a valve. The actuation system 280 receives the signal, which may be a command to open / close the downhole valve and triggers the downhole tool 290 to transition to a different configuration.In some embodiments, a downhole valve may be configured to provide a complete blockage of flow through the tubing string 200, for example, as a ball valve assembly 430 having a ball valve 435. In some embodiments, the ball valve assembly 430 having a ball valve 435 is configured to provide a restriction through the tubing string 200, for example, as an adjustable throttle. In still other embodiments, the ball valve assembly 430 having a ball valve 435 may be configured as a circulation valve arranged to selectively direct fluid between the interior and exterior of the tubing string 200.

[0075] [Fig. 2] illustrates a cross-sectional view of a downhole tool 290 according to certain embodiments of the present disclosure. In this embodiment, the downhole tool 290 includes an actuation system 280 that connects to a latch assembly 375. A spring assembly 395 may be placed between the latch assembly 375 and a ball valve assembly 430. Also for this embodiment, a hydraulic pressure relief assembly 440 is used and will be described in more detail below.

[0076] [Fig. 3] illustrates a cross-sectional view of an actuation system 280 according to certain embodiments of the present disclosure. Here, the signal receiver 300 may be positioned to receive electrical signals sent by the signal transmitter 220. A battery 320 may be electrically connected to both the signal receiver 300 and a decoder 310 which may be positioned to trigger a pin pusher 330 in response to receiving a certain signal, pattern, or a combination of both from the signal receiver 300.

[0077] The actuation system 280 may be operable to transition downhole wellbore tools 290 (e.g., downhole valves such as ball valves) between operational configurations. distinct. In some embodiments, the actuation system 280 may be generally housed in a sidewall of the tubing string 200 and includes a signal receiver 300. The signal receiver 300 may be configured to receive electrical signals, convert or decode these signals with a decoder 310. The decoder 310 may be operable to decode the electrical signal into an electronic instruction to thereby determine whether the actuation system 280 should be triggered to transition the downhole tool 290 between operational configurations. Any suitable decoder may be used.In some embodiments, the decoder 310 includes an electronic circuit including various components such as a microprocessor, a digital signal processor, random access memory, read only memory, and the like that are programmed or otherwise operable to recognize the predetermined target electrical profile and thereby determine whether the actuation system should be actuated. When the decoder 310 identifies a match between the received signal values ​​and the target signal profile, the decoder 310 may issue a command to an actuation mechanism, such as a spindle pusher 330, that triggers the downhole tool 290 (e.g., a valve) to transition between operational configurations as described in more detail below. The spindle pusher 330 may include a linear motor, a pneumatic piston, or a similar mechanism.The decoder 310 may also include timing devices to delay or control the time period between detecting the target electrical profile and issuing the command to the spindle pusher 330. The signal receiver 300, the decoder 310, and the spindle pusher 330 may all be operatively coupled to a battery 320 or other downhole power source to receive power therefrom. In some embodiments, the battery 320 may be rechargeable.

[0078] The actuation system 280 further includes a piston 420 that is coupled to a force from the spring 400. In the illustrated embodiments, the piston 420 is slidably disposed in a sidewall of the tubing string 200, which may also be the valve body 390. The spring 400 has a spring force in the first direction (indicated by the arrow "A"). An upper end of the piston 420 includes a latch 380. The latch 380 is positioned between the outer and inner portions of the valve body 390. The latch 380 removably secures the piston 420 in place by a projection on the outside of the valve body 390. Movement of the piston 420 in the first direction is substantially prevented by the latch 380.Upon release of the latch 380, the spring force from the spring 400 and the hydraulic pressure force from the high pressure chamber 480 cause the piston 420 to move downward in the first direction, which causes the downhole tool 290 to change configuration, in certain modes. embodiment, which causes a valve to open. The compressible fluid (e.g., silicone oil) contained in the high-pressure chamber 480 expands as the piston 420 moves in a direction parallel to the wellbore axis so that as the tool 290 moves from one position to another position (e.g., as a valve opens or closes in some cases), the spring force generated by the spring 400 decreases and the hydraulic pressure force from the high-pressure chamber 480 also decreases.

[0079] A barrier element (e.g., a bursting disc) 370 is secured between the fluid chamber 350 and an atmospheric chamber 340 in which the spindle pusher 330 is disposed. In some embodiments, the fluid chamber 350 is filled with a fluid, e.g., hydraulic oil. The barrier element 370 initially prevents the actuator fluid from escaping from the fluid chamber 350 into the atmospheric chamber 340. The barrier element 370 is illustrated as a disc element and may be formed from a metal but could alternatively be made from a plastic, composite, glass, ceramic, mixture of these materials, or other suitable material to initially contain the actuator fluid in a fluid chamber, but selectively fail in response to the target electrical profile identified by the decoder 310 and the command sent to the pin pusher 330.In the illustrated embodiment, the pin pusher 330 advances a pin in the atmospheric chamber 340 toward the barrier member 370 to thereby fracture the barrier member 370. In other embodiments, failure of the barrier member 370 may be selectively induced by other types of actuation mechanisms configured to induce failure of the barrier member 370 through chemical reactions, combustion, mechanical weakening, or other degradation of the barrier member 370. Failure of the barrier member 370 creates an opening in the barrier 370 and establishes fluid communication between the fluid chamber 350 and the atmospheric chamber 340.The actuator fluid can thus exit the fluid chamber 350 and enter the atmospheric chamber 340, which allows the atmospheric piston 360 to be pushed toward the fluid chamber 350 in a second direction (represented by arrow B) by the pressure differential between the atmospheric chamber 340 and the high pressure chamber 480. The movement of the atmospheric piston 360 releases the latch 380 of the piston 420.

[0080] In some embodiments, during operation, the signal receiver 300 detects an electrical signal, for example, from the signal transmitter 220 (for example, shown in [Fig.l]) and provides electrical values ​​to the decoder 310 over time. The decoder 310 monitors the electrical values ​​and determines whether the electrical values ​​over a particular time interval match the target electrical profile stored in the decoder 310. If the decoder 310 identifies the electrical profile in the received electrical values, and thus determines that the actuation system 280 is to be actuated, the decoder 310 issues a command to the spindle pusher 330 to advance the spindle. For example, the decoder 310 may route electrical power from the battery 320 to the spindle pusher 330, immediately or after an appropriate delay, to enable the spindle pusher 330 to operate to induce a failure of the barrier 370. The failure of the barrier 370 creates an opening in the barrier and establishes fluid communication between the fluid chamber 350 and the atmospheric chamber 340.Hydraulic fluid can thus exit the fluid chamber 350 and enter the atmospheric chamber 340, allowing the atmospheric piston 360 to be pushed toward the fluid chamber (arrow B) by pressure acting on the area of ​​the atmospheric piston 360 from the compressed fluid contained in the high-pressure chamber 480. Movement of the atmospheric piston 360 releases the latch 380, causing the piston 420 to be pushed in a first direction (arrow A) by the spring 400. The pressure from the piston 420 and the tube exerts a force causing the tool 290 to operate or, in some embodiments, a valve to open.

[0081] [Fig.4] illustrates a sectional view of a latch assembly 375 according to some embodiments of the present disclosure. As described in more detail below, the latch 380 may be actuated once the actuation system 280 is triggered.

[0082] [Fig. 5] illustrates a sectional view of a spring assembly 395 according to certain embodiments of the present disclosure. Here, one or more springs 400 may be used to apply a horizontal force to the latch 380.

[0083] [Fig.6] illustrates a cross-sectional view of a ball valve assembly 430 according to certain embodiments of the present disclosure, wherein said ball valve assembly 430 is operable by movement of latch 380 to engage a ball valve 435.

[0084] [Fig.7] illustrates a sectional view of a hydraulic booster assembly optional 440 according to some embodiments of the present disclosure. The well fluids 450 may be located at the position above the hole of the tool 290 and are isolated from the fluid of a low pressure chamber 460 by a balance piston 500 which may contain a compressible fluid (preferably silicone oil, but many other compressible fluids would work with the embodiments described herein). The low pressure chamber 460 may be placed in fluid communication with a high pressure chamber 480 located downhole of the low pressure chamber 460. The low pressure chamber 460 may be placed in fluid communication with a high pressure chamber 480 via of one or more hydraulic components 470. A first hydraulic component 470 may be a check valve that provides fluid communication between the two chambers but only allows fluid flow from the low pressure chamber 460 into the high pressure chamber 480.

[0085] A second (optional) hydraulic component 470 may be a pressure relief valve in fluid communication with the high pressure chamber 480 and the low pressure chamber 460 that would automatically trigger at a high pressure threshold, e.g., near 3,000 psi in some embodiments. In this embodiment, if the pressure in the high pressure chamber 480 continues to build due to, for example, an increase in temperature and the pressure in the high pressure chamber 480 becomes too high, the pressure relief valve in the hydraulic components 470 may be used to release some of the compressible fluid from the high pressure chamber 480 into the low pressure chamber 460. The high pressure chamber 480 may also contain the same compressible fluid stored in the low pressure chamber 460.Thus, the hydraulic booster assembly 440 creates additional force with the hydraulic pressure built up and stored in the high pressure chamber 480, which can be quickly expelled to provide additional force (in addition to the spring force of the spring 400) on the latch 380 of the piston 420. The additional force is generated from the trapped high pressure chamber fluid acting on a piston area defined by the piston 420 which is located between the two piston seals 490.

[0086] During standard well operations, many different pressure applications are performed, for example, tests to ensure the gate valve is closed, to set a packer, to test the integrity of the upper and / or lower completion, etc. The hydraulic pressure boost function works by capturing any pressure applied to the wellbore fluids 450 and storing it by compressing the compressible fluid in the high pressure chamber 480. This is important because it means that no multiple pressure cycles or dedicated pressure signals need to be applied to load the hydraulic pressure boost function. Pressure can be built up during these cycles and used when desired, without the need for a large electrical signal, pulse, or battery to create a large force.Hydraulic overpressure has the advantage of improving the available opening force by combining the additional hydraulic pressure stored in the high pressure chamber 480 with the mechanical spring force generated by the spring.

[0087] For brevity, only certain ranges are explicitly disclosed herein. However, ranges from any lower limit may be combined with a any upper limit to cite a range not explicitly cited, likewise, ranges from any lower limit may be combined with any other lower limit in order to cite a range not explicitly cited, likewise, ranges from any upper limit may be combined with any other upper limit to cite a range not explicitly cited. Furthermore, whenever a numerical range with a lower limit and an upper limit is disclosed, every number and range included within the range is specifically disclosed. In particular, every range of values ​​(of the form, "from about a to about b", or, equivalently, "approximately from a to b" or, equivalently, "approximately from ab") disclosed herein is to be understood as stating every number and range included in the larger range of values, even if not explicitly cited.Thus, each individual point or value may constitute its own lower or upper limit combined with any other individual point or value or any other lower or upper limit, to cite a range not explicitly cited.

[0088] Accordingly, the present embodiments are well adapted to achieve the stated objectives and advantages, as well as those inherent therein. The particular embodiments disclosed above are for illustrative purposes only, as the present embodiments may be modified and practiced in different but equivalent ways that will be apparent to those skilled in the art having the benefit of the teachings contained herein. Although individual embodiments are discussed, all combinations of each embodiment are contemplated and covered by the invention. Furthermore, no limitations are intended on the details of construction or design provided herein, other than those described in the claims below. Furthermore, the terms of the claims have plain and ordinary meanings unless otherwise explicitly and clearly defined by the patent owner.It is therefore evident that the particular illustrative embodiments disclosed above may be changed or modified and that all such variations are considered within the scope and spirit of the present invention.

Claims

Claims

1. A method of actuating a wellbore tool (290), comprising the steps of: providing a conductor (150) having a first end positioned at a surface location and a second end positioned at a downhole location (160); cycling the wellbore through varying well fluid pressures; moving a balance piston (500) with the varying well fluid pressures to generate pressure in a hydraulic booster assembly (440); transmitting an electrical signal from above the wellbore, through the conductor, and to the downhole location; receiving the signal at the downhole location; and using the pressure within the hydraulic booster assembly to transition the downhole tool from a first configuration to a second configuration in response to the signal.

2. The method of claim 1, wherein the downhole tool is a downhole valve, the first configuration is a closed valve, and the second configuration is an open valve.

3. The method of claim 1, wherein the downhole tool is a downhole valve, the first configuration is an open valve, and the second configuration is a closed valve.

4. The method of claim 1, wherein the step of passing the wellbore through a cycle of varying well fluid pressures creates pressure in the hydraulic booster assembly.

5. The method of claim 1, further comprising monitoring electrical signals over time to establish a detected signal profile.

6. The method of claim 5, further comprising comparing the detected signal profile to a target signal profile.

7. The method of claim 1, wherein the step of passing the wellbore through a cycle of varying well fluid pressures generates a pressure in the hydraulic booster assembly that is used with spring force to move the tool from a first configuration to the second configuration.

8. The method of claim 1, wherein the hydraulic booster assembly comprises a high pressure chamber filled with a compressible fluid (480); a low pressure chamber filled with the same compressible fluid (460) and placed in fluid communication with the high pressure chamber via a check valve; and a balance piston (500) positioned to move in response to changes in well fluid pressure.

9. An actuation system (280) for a downhole tool (290) comprising: a conductor (150) extending from a surface location to a first downhole location; a signal transmitter (220) at the first downhole location that is coupled to the conductor; a signal receiver (300) at a second downhole location that is downhole relative to the first downhole location, wherein the signal receiver is configured to receive electrical signals from the signal transmitter; a decoder (310) at the second downhole location in electrical communication with the signal receiver; an actuator at the second downhole location in electrical communication with the decoder; a latch (380) connected to the actuator that releases a spring-loaded plunger when a specific signal is received at the decoder;and a downhole tool at the second downhole location coupled to the spring-loaded piston.;

10. The system of claim 9, further comprising a hydraulic booster assembly (440) having a balance piston (500) that is positioned to cycle through well fluid pressures to generate pressure in a chamber.

11. The system of claim 9, further comprising a hydraulic pressure relief assembly (440) that applies additional force to the piston in addition to the spring force.

12. A system according to any one of claims 10 and 11, wherein the pressure relief assembly comprises a high pressure chamber filled with a compressible fluid (480); a low pressure chamber filled with the same compressible fluid (460) and placed in fluid communication with the high pressure chamber via a check valve; and a balancing piston (500) positioned to move in response to changes in well fluid pressure.

13. A system according to any one of claims 10 to 12 wherein the downhole tool comprises a downhole valve.

14. A system according to any one of claims 10 and 11 wherein the hydraulic pressure relief assembly comprises a low pressure chamber and a high pressure chamber in fluid communication via a check valve.

15. The system of any one of claims 9 to 14 further comprising: a pin pusher (330) within the actuator that moves toward a barrier member until fracturing the barrier member that establishes fluid communication between a fluid chamber and a discharge chamber.

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