electric downhole safety valve free sample

Our downhole safety valves provide your testing operations with fail-safe sustained control downhole in the event of an emergency or to facilitate test procedures.

Surface-controlled subsurface safety valves (SCSSVs) are critical components of well completions, preventing uncontrolled flow in the case of catastrophic damage to wellhead equipment. Fail-safe closure must be certain to ensure proper security of the well. However, this is not the only function in which it must be reliable—the valve must remain open to produce the well. Schlumberger surface controlled subsurface safety valves exceed all ISO 10432 and API Spec 14A requirements for pressure integrity, leakage acceptance criteria, and slam closure.

Through decades of innovation and experience, Schlumberger safety valve flapper systems are proven robust and reliable. The multizone dynamic seal technology for hydraulic actuation of subsurface safety valves is a further improvement in reliability performance when compared with traditional seal systems in the industry.

The multizone seal technology is currently available in the GeoGuard high-performance deepwater safety valves, which is validated to API Spec 14A V1 and V1-H.

This disclosure relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in one example described below, more particularly provides a safety valve with an electrical actuator and tubing pressure balancing.

In this disclosure, systems and methods are provided which bring improvements to the arts of isolating well tool actuators from well fluids, and actuating well tools. One example is described below in which an actuator is exposed to a dielectric fluid isolated from an interior flow passage. Another example is described below in which various sensors can be used to control actuation of the well tool.

In one aspect, this disclosure provides to the art a well tool for use with a subterranean well. In one example, the well tool can include a flow passage extending longitudinally through the well tool, an internal chamber containing a dielectric fluid, and a flow path which alternates direction. The flow path provides pressure communication between the internal chamber and the flow passage.

In another aspect, a method of controlling operation of a well tool can include actuating an actuator positioned in an internal chamber of the well tool, a dielectric fluid being disposed in the chamber, and the chamber being pressure balanced with a flow passage extending longitudinally through the well tool; and varying the actuating, based on measurements made by at least one sensor of the well tool.

In yet another aspect, a safety valve for use in a subterranean well is described below. In one example, the safety valve can include a flow passage extending longitudinally through the safety valve, an internal chamber containing a dielectric fluid, a flow path which alternates direction, and which provides pressure communication between the internal chamber and the flow passage, an actuator exposed to the dielectric fluid, an operating member, and a closure member having open and closed positions, in which the closure member respectively permits and prevents flow through the flow passage. The actuator displaces the operating member, which causes displacement of the closure member between its open and closed positions.

In the FIG. 1 example, a tubular string 12 is installed in a wellbore 14 lined with casing 18 and cement 16. Well fluid 20 (in this case, produced from an earth formation 22 penetrated by the wellbore 14) enters the tubular string 12 via a flow control device 24 (such as, a sliding sleeve valve, a variable choke, etc.). A packer 26 seals off an annulus 28 formed radially between the tubular string 12 and the wellbore 14.

A well tool 30 selectively permits and prevents flow of the fluid 20 through a longitudinal flow passage 32 formed through the well tool and the substantial remainder of the tubular string 12. In this example, the well tool 30 comprises a safety valve. However, in other examples, the well tool 30 could comprise a flow control device (such as the flow control device 24) or another type of well tool (such as the packer 26, a chemical injection tool, a separator, etc.).

The actuator 38 in the example described below comprises an electrical actuator, such as a direct current stepper motor. One advantage of such a motor is that a torque and/or force output of the motor can be conveniently regulated, and a position of an operating member displaced by the actuator 38 can be conveniently determined by monitoring a number of step pulses transmitted to the motor. However, other types of electrical actuators, and other types of actuators, may be used in keeping with the scope of this disclosure.

One or more lines 40 extend from the well tool 30 to a remote location (such as the earth"s surface, a rig, a subsea location, etc.). The lines 40 can include one or more electrical conductors for conveying electrical power to the electronic circuit 36, transmitting commands, data, etc. to the well tool 30, receiving data, etc. from the well tool, etc. The lines 40 may include optical waveguides (such as optical fibers, ribbons, etc.), hydraulic conduits, and/or other types of lines, if desired.

A control system 42 is located at the remote location, and is connected to the lines 40. The control system 42 may include a computing device 44 and a display 46, along with suitable memory, software, firmware, connectivity (e.g., to the Internet, to a satellite, to a telephony line, etc.), processor(s), etc., to communicate with and control operation of the well tool 30. Alternatively, the control system 42 could be as simple as a switch to either apply electrical power, or not apply electrical power, to the well tool 30.

The actuator 38 is positioned in the chamber 62. A dielectric fluid 54 (e.g., a silicone fluid, etc.) surrounds the actuator 38 in the chamber 62. The fluid 54 also fills a substantial majority of the flow path 50.

A floating piston assembly 56 (see FIGS. 9A & 10) isolates the dielectric fluid 54 from the well fluid 20, which enters the flow path 50 via an opening 58. The assembly 56 permits pressure to be balanced (e.g., at substantially equal levels) between the flow passage 32 and the chamber 62 via the flow path 50, without any mixing of the fluids 20, 54.

Note that the floating piston assembly 56 is reciprocably and sealingly received in a radially enlarged section 50 iof the flow path 50. This allows the floating piston assembly 56 to displace more volume per unit of translational displacement, thereby allowing more expansion of the dielectric fluid 54 with increased temperature, and allowing for a greater range of pressure transmission (although, if the dielectric fluid 54 is substantially incompressible, very little volume change would be expected due to pressure in a typical downhole environment). A pressure relief valve or other pressure relief device 68 is provided in the floating piston assembly 56 to relieve excess pressure in the flow path 50 due, for example, to increased temperature.

Alternating opposite ends of adjacent ones of the flow path sections 50 a-nare placed in fluid communication with each other by the manifolds 72, 74. In addition, electrical conductors and/or optical waveguides can extend through openings in the manifolds 72, 74 (see FIG. 5).

For example, as depicted in FIG. 2A, the lines 40 can extend through the upper manifold 72 to a bulkhead connector 76 in the chamber 60. The connector 76 isolates the chamber 60 from a conduit 78 extending external to the well tool 30. The conduit 78 (and the lines 40 therein) could extend to, for example, another well tool (such as, another safety valve, the telemetry device 48, etc.), a remote location, the control system 42, etc.

In other examples, the bulkhead connector 76 may not be used, and the conduit 78 can be in fluid communication with the flow path 50 and chambers 60, 62, 64, 66. In this manner, the dielectric fluid 54 (or another fluid, such as, a chemical treatment fluid, etc.) could be injected into the flow path 50 and chambers 60, 62, 64, 66 from a remote location via the conduit 78.

For example, after installation of the well tool 30 in a well, dielectric fluid 54 could be pumped through the conduit 78 from the remote location to the flow path 50 and chambers 60, 62, 64, 66. Sufficient pressure could be applied to cause the pressure relief device 68 to open, thereby allowing the fluid to be pumped into the flow passage 32 from the flow path section 50 i.

This would ensure that the flow path 50 and chambers 60, 62, 64, 66 are filled with the dielectric fluid 54. This can also allow a chemical treatment fluid (such as, a corrosion inhibitor, a precipitate reducer, etc.) to be pumped into the flow passage 32 via the conduit 78, flow path 50 and relief valve 68.

The motor (via suitable gearing, clutch, brake, etc., not visible in FIGS. 3A & B) displaces a shaft 90 upward or downward (as viewed in the drawings). A sealing rod piston 92 is displaced with the shaft 90. The sealing rod piston 92 isolates the dielectric fluid 54 in the chamber 62 from the well fluid 20 in the flow passage 32.

The operating member 84 can be displaced to any position by the actuator 38 at any time. For example, the operating member 84 can be displaced to a position in which the closure member 34 is fully closed, a position in which the closure member is fully open, a position in which an equalizing valve 100 (see FIG. 2D) is opened, etc.

When actuating the well tool 30 from its open to its closed configuration, the actuator 38 can displace the operating member 84 to its equalizing position (thereby opening the equalizing valve 100), stop at the equalizing position (e.g., using a brake of the actuator) and then continue to the open position (in which the closure member 34 is fully open). The operating member 84 can remain stopped at the equalizing position until the sensor 80 indicates that pressure in the flow passage 32 above the closure member 34 has ceased increasing, until a certain time period has elapsed, until a differential pressure sensor (not shown) indicates that pressure across the closure member 34 has equalized, etc.

It may now be fully appreciated that significant improvements are provided to the arts by the principles set forth in this disclosure. In an example described above, electrical connections (e.g., the bulkhead connector 76, connections at the position sensor 82, sensor 88, actuator 38, etc.), a downhole electronics housing 70 weldment, a position sensor 82 and an electrical actuator 38 are installed inside of dielectric fluid 54 filled chambers 60, 62, 64, 66. All of the dielectric fluid 54 filled chambers 60, 62, 64, 66 are pressure balanced to the flow passage 32 using a flow path 50 which alternates direction multiple times.

The illustrated configuration contains only one electric actuator, one downhole electronics housing weldment, and one position sensor. However, any number of these elements may be used, as desired.

There are seven alternating dielectric fluid filled gravity assisted “U” flow path sections (fourteen total sections) to separate the production fluid from the dielectric fluid, in the illustrated configuration. However, any number of flow path sections may be used, as desired.

The passageway ports that are used for the passage of the dielectric fluid balance pressure can also be used to route electrical conductors or other types of lines from chamber to chamber. These ports can be sealed with static double o-ring seals (which always have substantially no differential pressure across them).

If desired, these ports could be laser welded instead of being sealed with o-rings. However the pressure balance device in other examples could include a chamber where the dielectric fluid is separated from the well fluids by bellows or other types of seals.

Typically, the main limitation on safety valve dimensions is the wall thickness needed for the actuator. The required wall thickness can be much smaller with the illustrated design, since the electric actuator can be smaller than conventional designs.

The electric actuator for the illustrated configuration does not have to be as powerful or as large as conventional electrical safety valve actuators. The actuator in the illustrated configuration must only be strong enough to overcome the force of the biasing device 86 and friction. Since there is no differential pressure on any seals, the friction should be minimal.

A conventional rod piston 92 with leak-proof seals 96 is used in the depicted safety valve example. Note that multiple rod piston seals (or even a bellows, diaphragm, etc.) could be used in place of the leak-proof seals, since there is preferably substantially no differential pressure across the seals.

A hybrid electronics package design that is long with a small OD is used in the depicted safety valve example. This hybrid circuit design provides a significant size reduction. Longevity at high temperatures is also increased.

The tubing pressure balancing feature is integrated into the depicted safety valve example. This can also result in substantial cost reductions. However, in other examples, the tubing pressure balancing feature could be provided by a separate component that is connected to the dielectric fluid filled chambers.

The illustrated safety valve example also provides for addition of a downhole electronic pressure and/or temperature gauge as part of the safety valve. Such a pressure/temperature gauge can be installed into one of the pressure balancing chambers which are maintained at the pressure in the flow passage. This downhole gauge could transmit pressure and temperature information to a remote location on a same line as is used to control operation of the safety valve.

Complete system redundancy can be provided in at least three ways, due at least in part to the reduced cost of the safety valve example described above:

a. Multiple safety valves could be installed. A secondary valve could be pinned or temporarily locked in an open position. The secondary valve could be actuated (e.g., via a wireline trip) when a primary safety valve fails.

c. A safety valve could include multiple actuators, multiple control lines, and multiple sets of electronics. In the illustrated configuration, the number of alternating flow paths may be reduced, if the multiple actuators, etc. are to fit in the same size wall of the safety valve. If dielectric fluid contamination is a concern, more “U” tubes could be added, or a metal bellows pressure balancing system could be used instead, etc.

The floating piston assembly 56 forms a physical barrier between the well fluids and the dielectric fluid, thereby preventing mixing of the fluids. The floating piston could move inward and outward with changes in pressure, but its inward movement could be limited by the compressibility of the dielectric fluid, and its outward movement could be limited by the expansiveness of the dielectric fluid.

A basic combination described above is a chamber filled with a dielectric fluid, with one end of a flow path connected to the chamber, and another end of the flow path in communication with the flow passage. While this integral pressure balancing feature is primarily described for an electrically actuated safety valve, it could potentially be used with other well tools, such as sliding sleeves, chemical injection valves, separators, etc.

The depicted electric safety valve system can include an electric actuator with downhole electronic circuitry, a downhole telemetry device (transmitter and/or receiver), and a control system at a remote location (such as, at the earth"s surface, a rig, an underwater facility, etc.).

The control system can display when the safety valve should be fully open, for example, after a preset number of stepper motor steps have been executed. This control system computer display indication can be independent of the position sensor, so that a failure of the position sensor does not affect the opening/closing functions of the safety valve.

The control system can display when the valve is in the closed position, when the control system"s computer program is running. The safety valve will preferably automatically close if the control system is shut down, electric power to the safety valve is lost, or a computer used to run the computer program fails.

In another example, the safety valve could go into a hold state if the control system fails or is shut down, instead of the safety valve automatically closing. The reason for the failure or shutdown could be a system maintenance issue that does not require the well to be shut-in.

The force sensor 88 periodically reports to the control system the measured force output by the actuator. These force measurements can comprise a secondary indication of the safety valve operation, which may be used in case the position sensor 82 fails.

If the safety valve is a self-equalizing type (e.g., comprising the equalizing valve 100), the electronic circuitry or the control system can be preprogrammed to displace the operating member only to the equalizing position, and then set the brake until the operator issues a command to the control system to continue to open the safety valve to the fully open position.

The temperature, pressure, vibration, etc. of the electronic circuitry can be reported periodically to the control system. For example, this information can be displayed after the safety valve is closed. The temperature, pressure, vibration, etc. could also be displayed and/or recorded in real time.

The pressure and temperature in the tubular string 12 (e.g., as measured by the sensor 80) may be reported periodically to the control system 42 (e.g., the safety valve is open), or after the valve is closed, and/or in real time. This can be accomplished with an integral downhole pressure/temperature gauge or other dedicated sensors.

If the force on the actuator or the force required to open the flapper exceeds a preset limit, indicating that pressure across the flapper is not equalized, the electronic circuitry can automatically command the safety valve to close (e.g., causing the actuator to reverse direction), and the force overload can be reported to the control system.

The operator can then set this force limit to a higher level, if desired. However, the stepper motor will likely dither and not open the safety valve if the maximum motor torque is reached. In this circumstance, the operator can increase the tubing pressure to equalize the pressure above the flapper to the pressure below the flapper.

The torque output of the stepper motor can be increased by decreasing a frequency of electrical step pulses transmitted to the motor. The time to open the safety valve can be optimized by increasing the frequency of the pulses at the beginning of the displacement when the force output by the biasing device is lowest, and decreasing the frequency at the end of the displacement when the spring force is highest.

In order to optimize electrical power usage, the safety valve can have a demand system, whereby the power is continuously monitored, and is maintained within a narrow range. The safety valve will likely have an optimum power at which it performs its function. This optimum power is sufficient to operate the valve, with a minimum amount of excess power. In this manner, smaller electrical components can be used and less heat is generated in the downhole electronic circuitry, actuator, etc.

In one example, if the flow passage 32 pressure is below or above a preset limit, the valve would automatically close. A warning with a predetermined override time limit could be displayed by the control system 42 before this happens, so the valve would not be closed unless circumstances warrant.

This would allow the operator to override the closure if the downhole pressure gauge failed or the pressure limits are incorrect. The pressure limits could be reset at the control system 42. If the override command is not received during the given time period, the valve could automatically close.

Note that the electric actuator 38 and other components used in the illustrated configuration could also be used to operate a downhole choke, sliding sleeve valve, etc., instead of a subsurface safety valve. For a downhole choke, other sensors such as resistivity and a differential pressure flow meter could be included in the design, so that operation of the choke could be controlled, based on the outputs of such sensors.

Another self-equalizing function can be included as part of the safety valve. The operating member 84 can be displaced from the closed position to a predetermined equalizing position, at which the equalizing valve 100 opens. The brake would be set, holding the operating member 84 in the equalizing position. The pressure gauge could be monitored, until the pressure above the closure member 34 stops increasing for a predetermined time period, then the operating member 84 would be displaced to the open position.

A well tool 30 for use with a subterranean well is described above. In one example, the well tool 30 can include a flow passage 32 extending longitudinally through the well tool 30, an internal chamber 60, 62, 64, 66 containing a dielectric fluid 54, and a flow path 50 which alternates direction, and which provides pressure communication between the internal chamber 60, 62, 64, 66 and the flow passage 32.

The well tool 30 can also include a floating piston 102 in the flow path 50. The floating piston 102 may prevent the dielectric fluid 54 from flowing into the flow passage 32. The floating piston 102 can be positioned in an enlarged section 50 oof the flow path 50.

The well tool 30 may include an electrical actuator 38 in the dielectric fluid 54. The actuator 38 can displace a pressure transmission device (e.g., piston 92, bellows 98, etc.) which isolates the chamber 60, 62, 64, 66 from the flow passage 32. The pressure transmission device may comprises a bellows 98 and/or a piston 92.

The chamber 60, 62, 64, 66 can be in fluid communication with a source of the dielectric fluid 54 via a conduit 78 extending to a remote location. A line 40 may extend through the conduit 78 to an actuator 38 in the chamber 62.

The well tool 30 can include a pressure relief device 68. The pressure relief device 68 may permit the dielectric fluid 54 to flow into the flow passage 32 in response to pressure in the chamber 60, 62, 64, 66 exceeding a predetermined pressure level.

The well tool 30 can include an actuator 38 in the dielectric fluid 54, and a force sensor 88 which senses a force applied by the actuator 38. The force applied by the actuator 38 may be controlled, based on measurements made by the force sensor 88.

The displacement of the operating member 84 may cause displacement of a closure member 34 which selectively permits and prevents flow through the flow passage 32. The displacement of the operating member 84 can actuate an equalizing valve 100 which equalizes pressure across the closure member 34.

The well tool 30 can include at least one of the group comprising temperature, force, pressure, position, and vibration sensors in the dielectric fluid 54. At least one of the sensors (e.g., vibration sensor 106, see FIG. 8B) and an electronic circuit 36 may be disposed in an enclosure 71 isolated from pressure in the chamber 66.

A method of controlling operation of a well tool 30 is also described above. In one example, the method can include actuating an actuator 38 positioned in an internal chamber 62 of the well tool 30, a dielectric fluid 54 being disposed in the chamber 62, and the chamber 62 being pressure balanced with a flow passage 32 extending longitudinally through the well tool 30; and varying the actuating, based on measurements made by at least one sensor 80, 82, 88, 106 of the well tool 30.

The well tool 30 may comprise a safety valve. The actuator 38 may cause a closure member 34 to be alternately opened and closed to thereby respectively permit and prevent flow through the flow passage 32.

In particular, the above disclosure describes a safety valve 30 for use in a subterranean well. In one example, the safety valve 30 can include a flow passage 32 extending longitudinally through the safety valve 30, an internal chamber 60, 62, 64, 66 containing a dielectric fluid 54, a flow path 50 which alternates direction, and which provides pressure communication between the internal chamber 60, 62, 64, 66 and the flow passage 32, an actuator 38 exposed to the dielectric fluid 54, an operating member 84, and a closure member 34 having open and closed positions, in which the closure member 34 respectively permits and prevents flow through the flow passage 32. The actuator 38 can displace the operating member 84, which causes displacement of the closure member 34 between its open and closed positions.

The present invention is a surface controlled subsurface safety valve (SCSSV) for use in a well, preferably a hydrocarbon producing well. Many hydrocarbon producing wells contain a subsurface safety valve located down hole in the production string to shut off hydrocarbon flow in the event of an emergency. Well production strings continue to increase in depth, particularly for offshore wells, due to increases in both well and water depths. In order to prevent injury to personnel and to protect the environment and equipment, the present invention addresses the need for a subsurface safety valve that closes quickly and reliably when installed at any depth, and especially these increased depths, within a well.

The present invention is a surface controlled subsurface safety valve (SCSSV) for use in a well, preferably a hydrocarbon producing well. The SCSSV comprises a valve body having a longitudinal bore for fluid to flow through, a bore closure assembly, a pressure balanced drive assembly, and a fail safe assembly. The bore closure assembly is positioned and normally biased to close the bore to fluid flow. The drive assembly is coupled to the bore closure assembly for driving the bore closure assembly to an open position. The fail safe assembly is positioned and configured to hold the bore closure assembly in the open position in response to a hold signal and to release the valve to return to the safe, closed position upon interruption of the hold signal.

FIG. 1 shows a surface controlled subsurface safety valve (SCSSV) 45 of the present invention installed in an offshore hydrocarbon producing well. The wellhead 10 rests on the ocean floor 15 and is connected by a flexible riser 25 to a production facility 30 floating on the ocean surface 20 and anchored to the ocean floor by tethers 17. The well production string includes flexible riser 25 and downhole production string 35 (FIG. 1) positioned in the wellbore below the wellhead 10. The SCSSV 45 is mounted in the downhole production string below the wellhead. As shown in FIG. 2, the SCSSV 45 is preferably mounted between upper section 37 and lower section 39 of downhole production string 35 by threaded joints 47. The exact location that the subsurface safety valve is mounted in the downhole production string is dependent upon the particulars of a given well, but in general the SCSSV is mounted upstream from the hydrocarbon gathering zone 50 of the production string, as shown in FIG. 1.

Referring to FIGS. 2 and 3, the SCSSV 45 comprises a valve body 52 having an upper assembly 42, a lower assembly 43, and a longitudinal bore 54 extending the length of the valve body. The longitudinal bore forms a passageway for fluid to flow between the lower section 39 and the upper section 37 of the downhole production string. The SCSSV further comprises a pressure balanced drive assembly 75 coupled to a bore closure assembly 60. As used herein, a pressure balanced drive assembly means a drive configuration in which the driving force need only overcome the resistance force that normally biases the bore closure assembly to a closed position (e.g., the force of spring 64). Preferably, the pressure balanced drive assembly 75 uses a mechanical linkage 95 to drive the bore closure assembly 60 to an open position in response to a control signal. A fail safe assembly 90 is positioned and configured to hold the bore closure assembly in the open position while the control signal is being received and to release the bore closure assembly to return to the safe, closed position upon interruption of the control signal. A unique feature of the pressure balanced drive assembly is that it need not overcome any additional force created by differential pressure or hydrostatic head of control fluid from the surface.

The bore closure assembly is positioned and normally biased to close the longitudinal bore to fluid flow. In a preferred embodiment shown in FIG. 3, the bore closure assembly 60 is a flapper valve disposed within longitudinal bore 54 near the lower end of SCSSV 45. As its name implies, a flapper valve opens and closes the SCSSV to fluid flow by rotation of a flapper 61 about a hinge 69 on axis 62 transverse to the axis 55 of the longitudinal bore. The conventional means of actuating the flapper is to employ an axially movable flow tube 65 that moves longitudinally within the bore 54, the lower end 66 of the flow tube abutting the flapper 61 and causing the flapper to rotate about its hinge and open the SCSSV to fluid flow upon a downward movement by the flow tube. The flapper valve is normally biased to close the longitudinal bore to fluid flow. Compression spring 64, positioned between the flow tube ring 67 and a flapper seat 68, normally biases the flow tube 65 in the upward direction such that the lower end 66 of the flow tube in the valve closed position does not press downward upon the flapper 61. With the flow tube in a retracted position, the flapper 61 is free to rotate about axis 62 in response to a biasing force exerted by, for example, a torsion spring (not shown) positioned along axis 62 and applying a force to hinge 69. Flapper 61 rotates about axis 62 such that the sealing surface 63 contacts the flapper seat 68, thereby sealing bore 54 to fluid flow.

In an alternative preferred embodiment (not shown), the bore closure assembly is a ball valve disposed within longitudinal bore 54 near the lower end of SCSSV 45. Ball valves employ a rotatable spherical head or ball having a central flow passage which can be aligned with respect to the bore to open the SCSSV to fluid flow. Rotation of the ball valve through an angle of 90 degrees will prevent flow through the central flow passage, thereby closing the SCSSV to fluid flow. The ball valve is normally biased to close the longitudinal bore to fluid flow. An example of a suitable ball valve bore closure assembly is shown in U.S. Pat. No. 4,467,870, incorporated herein by reference in its entirety.

Conventionally, flapper and ball valves are actuated by an increase or decrease in the control fluid pressure in a separate control line extending from the SCSSV to the ocean surface, in the case of an SCSSV installed in an offshore well. As SCSSVs are installed at deeper and deeper depths, the length of the control line increases, resulting in an increase in the pressure of the control fluid at the SCSSV due to the hydrostatic head associated with the column of control fluid in the control line. As a result of the higher pressure, significant problems are encountered with a hydraulic control signal from the surface such as a significant delay in valve closure time and the extreme design criteria for the equipment, both downhole and at the surface. Thus, in the present invention, a pressure balanced (also referred to as a pressure compensated) drive assembly is used to actuate the bore closure assembly in place of a hydraulic control signal from the surface.

Referring to FIGS. 2-5, the pressure balanced drive assembly 75 comprises an actuator coupled by a mechanical linkage 95 to the bore closure assembly 60 for driving the bore closure assembly to open the SCSSV 45 in response to an electronic control signal from the surface. The actuator may be an electric (e.g., electric motor 76 in FIG. 3) or hydraulic (e.g., pump 102 in FIGS. 4 and 5) actuator. In the preferred embodiments shown in FIGS. 3-5, the pressure balanced drive assembly comprises an actuator housed in a sealed chamber 77 filled with an incompressible fluid, for example dielectric liquids such as a perfluorinated liquid. The actuator is surrounded by a clean operating fluid and is separated from direct contact with the wellbore fluid. Preferably, the actuator is connected by connector 78 to a local controller 79 such as a circuit board having a microcontroller and actuator control circuit. The local controller is preferably housed in a separate control chamber that is not filled with fluid and that is separated from the chamber 77 by high pressure seal 86, provided however that the local controller could be housed in the same fluid-filled chamber as the actuator so long as the local controller is designed to survive the operating conditions therein. The local controller is capable of receiving control signals from the surface and sending data signals back to the surface, for example by an electrical wire 80 to the surface or by a wireless communicator (not shown). Alternatively, the controller may be positioned remotely rather than locally, for example at the surface, and may communicate with the SCSSV, for example by electrical wire 80 or by wireless transmission. Where an electrical wire is used, the control signal is preferably a low power control signal that consumes less than about 10 watts in order to minimize the size of the wire required to transmit the signal across the potentially long distances associated with deep-set SCSSVs. Power to the actuator may be supplied by direct electrical connection to the electrical wire 80 or through the wall of the sealed chamber 77 by an inductive source located outside the chamber through use of inductive coupling, which eliminates the need for the connector 78.

Preferably, a mechanical linkage 95 is used by the drive assembly 75 to exert an actuating force on the bore closure assembly 60 to open the SCSSV to fluid flow, provided however a mechanical linkage need not be employed in all embodiments, as shown by the direct electrically actuated embodiment of FIG. 6 described below. The mechanical linkage may be any combination or configuration of components suitable to achieve the desired actuation of the bore closure assembly. In the preferred embodiment of FIG. 3, the mechanical linkage comprises a gear reducer 97 and a ball screw assembly 98, or alternatively a roller screw assembly in place of the ball screw assembly. FIG. 3A shows a preferred ball screw assembly and bellows arrangement. The ball screw assembly further comprises ball screw 150, the upper end of the ball screw is connected to the gear reducer 97 and the lower end of the ball screw is threaded into a drive nut 155. The gear reducer 97 serves to multiply the torque of the electric motor 76 delivered to the ball screw assembly 98, and more than one gear reducer may be employed as needed along the drive line between the motor 76 and the ball screw assembly 98. The lower end 157 of the drive nut 155 contacts the end face 159 of the bellows 81. The bellows 81 is fixedly connected at the edge 160 of the sealed chamber 77, and is arranged to expand or contract upward from edge 160 and into the sealed chamber 77. The lower side of end face 159 of the bellows 81 is in contact with the upper end 162 of power rod 99, which is exposed to the wellbore fluid as noted by reference numeral 83. The lower end 164 of power rod 99 is in contact with, and preferably is fixedly connected to, the flow tube ring 67. In response to rotation of the ball screw 150 by the gear reducer 97, the drive nut 155 is restrained from rotating and thus travels axially as the ball screw 150 rotates, thereby moving the power rod 99 and the flow tube ring 67 downward to open the SCSSV to fluid flow. Alternatively, the drive nut 155 can be rotated while the ball screw 150 is held from rotating, but allowed to travel axially to actuate the flow tube.

In the hydraulically actuated embodiments shown in FIGS. 4 and 5, the pressure balanced drive assembly 75 comprises a hydraulic actuator 100 further comprising a pump 102 and a control valve 104 housed within the sealed chamber 77 filled with an incompressible fluid. The sealed chamber 77 further comprises a hydraulic loop 103, with a suction side of the loop in fluid communication with a bellows 106, a discharge side of the loop in fluid communication with a bellows 108, and a fluid jumper line 105 containing the control valve 104 connecting the discharge side of the loop with the suction side of the loop. The control valve preferably is a normally open electric control valve that is powered closed and controlled by a control circuit, preferably the local controller 79 as described previously for the electromechanical actuated embodiment of FIG. 3. The control valve blocks the hydraulic pressure within the hydraulic loop and may be any type of valve suitable for the particular incompressible fluid, such as a solenoid valve, a spring-biased check valve, or a flow switch (used with an MR fluid, as described below).

Preferably, the pump 102 is an electric pump that is powered and controlled by a control circuit, preferably the local controller 79 as described previously. As an alternative to a direct electrical connection, the electric pump can be powered by inductive coupling. The suction side of the pump 102 is connected to the reservoir side of the hydraulic loop. To open the SCSSV, the control valve 104 is powered closed and the pump is activated. The incompressible fluid from the reservoir formed by the bellows 106 is pumped into the discharge side of the hydraulic loop. As fluid fills the discharge side, hydraulic pressure is exerted on the bellows 108, thereby expanding the bellows 108 and forcing a shaft 110, and likewise the flow tube 65, downward and opening the flapper 61. The shaft 110 serves as the mechanical linkage 95 and is exposed to the wellbore fluid as noted by reference numeral 83. The lower end 111 of shaft 110 is in contact with, and preferably is fixedly connected to, the flow tube ring 67 on the flow tube 65. The upper end 112 of the shaft 110 is in contact with the end face 113 of the bellows 108. As discussed previously, the bellows 106 and 108 are in fluid communication with the wellbore fluid, and thus further comprise the means for balancing the pressure of the incompressible fluid with the pressure of the wellbore fluid contained within longitudinal bore 54.

Once the SCSSV is fully opened, the fail safe assembly is set (as discussed below), the pump is deactivated, and the signal which closed the control valve 104 is removed (thus allowing the control valve to open). Opening the control valve equalizes the hydraulic pressure on the discharge side of the hydraulic loop, which, upon the occurrence of a fail safe event, allows the bellows 108 and the shaft 110 to retract and flow tube 65 to move upward, closing the flapper 61. Equalizing the hydraulic pressure by opening the control valve 104 also preserves the bellows 108 by minimizing the amount of time that the bellows 108 is exposed to a pressure differential between the incompressible fluid and the wellbore fluid. Alternatively, the hydraulic pressure can be maintained on the discharge side of the hydraulic loop, and the electronically controlled control valve 104 can serve as the fail safe assembly by remaining closed in response to a hold signal (thereby holding the bore closure assembly in the open position) and by opening and releasing the hydraulic pressure upon interruption of the hold signal (thereby allowing the shaft 110 to retract and the bore closure assembly to close). Where hydraulic pressure is maintained on the discharge side of the hydraulic loop, the local controller preferably monitors a means for sensing and communicating the position of the bore closure assembly (as described in more detail below) and activates the pump in the event that the bore closure assembly begins to creep shut, for example due to a loss of hydraulic pressure across the pump seals.

In an alternative embodiment, one or more sealed pistons are used in place of one or more of the bellows in FIGS. 3 and 4. In a preferred alternative embodiment shown in FIG. 5, the shaft 110, which serves as the mechanical linkage to stroke flow tube ring 67, contains one or more seals 116 that replace the bellows 108. As fluid fills the discharge side of the hydraulic loop, hydraulic pressure is exerted on the upper end 112 of the shaft 110 (sealed by the seal 116 against the inside wall 117 of chamber 77), thereby forcing the shaft 110, and likewise the flow tube 65, downward and opening the flapper 61 as discussed previously. Preferably, once the fail safe assembly is set as described below, hydraulic pressure extending the piston is bled-off across the control valve 104, thereby preserving the piston seals. Alternatively, the hydraulic pressure can be maintained on the discharge side of the hydraulic loop and the position of the bore closure assembly monitored as described previously.

In an alternative, direct electrically actuated embodiment shown in FIG. 6, the pressure balanced drive assembly comprises a linear induction motor 180. The linear induction motor 180 may be housed within a sealed chamber, or alternatively may be in contact with the wellbore fluid, provided that it is designed to withstand such contact. Preferably, the linear induction motor 180 comprises a plurality of stator coils 185 a-185 farranged concentric with and longitudinally along the axis 55 of the bore. A movable armature 190 is integral with or connected (via a suitable mechanical linkage as discussed above) to the bore closure assembly. Preferably, the movable armature 190 is integral with the flow tube 65. A magnetic field created by progressively stepping an electrical current through the stator coils 185 (using a controller as described previously) drives the armature in a longitudinal direction parallel to the axis 55 of the bore, which in turn actuates the bore closure assembly (e.g., the flapper 61 or a ball valve) to open the SCSSV as described previously. The bore closure assembly is held in the open position by the fail safe assembly as described below.

Referring to FIG. 2, the fail safe assembly 90 is positioned and configured to hold the bore closure assembly 60 in the open position (commonly referred to as the “fully open” position) while the control signal is being received and to release the bore closure assembly to return to the safe, closed position upon interruption of the control signal. The fail safe assembly serves as a means for holding the bore closure assembly open in response to a control signal. The fail safe assembly 90 holds the valve in the open position in response to receipt of a control signal to do so, also referred to as a “hold” signal. Preferably, the hold signal is communicated through a wire or by wireless communication from a control center located at the surface. In the event that the hold signal is interrupted resulting in the fail safe assembly no longer receiving the hold signal (i.e., upon the occurrence of a fail safe event), the fail safe assembly releases and allows the valve to automatically return to the safe, closed position. In other words, the SCSSV according to this invention is a fail-safe valve. The hold signal might be interrupted, for example, unintentionally by a catastrophic failure along the riser, wellhead, or production facility, or intentionally by a production operator seeking to shut-in the well in response to particular operating conditions or needs such as maintenance, testing, or production scheduling. In effect, the pressure balanced drive assembly is what “cocks” or “arms” the SCSSV by driving the SCSSV from its normally biased closed position into an open position, the fail safe assembly serves as the “trigger” by holding the SCSSV in the open position during normal operating conditions in response to a hold signal, and interruption or failure of the hold signal is what causes the SCSSV to automatically “fire” closed.

In the preferred embodiment of FIG. 3, the fail safe assembly comprises an anti-backdrive device 96 and an electromagnetic clutch 91. The fail safe assembly is preferably configured such that electromagnetic clutch 91 is positioned between the anti-backdrive device 96 (which is connected to motor 76) and the gear reducer 97 (which is connected to the ball screw assembly 98), provided however that the individual components of the fail safe assembly may be placed in any operable arrangement. For example, the electromagnetic clutch 91 may be positioned between the gear reducer 97 and the ball screw assembly 98. Alternatively, the electromagnetic clutch 91 may be interposed between gear reducer sets. When engaged, the electromagnetic clutch 91 serves as a couple for the motor 76 to drive the ball screw assembly 98. Conversely, when the electromagnetic clutch 91 is disengaged, the motor 76 is mechanically isolated from the ball screw assembly 98. The local controller 79 engages the electromagnetic clutch 91 by applying an electrical current to the clutch and disengages the clutch by removing the electrical current to the clutch.

In response to a control signal to open the SCSSV, the electric motor 76 is powered and the electromagnetic clutch 91 is engaged to drive the ball screw assembly 98, thereby forcing the flow tube 65 downward against the flapper 61 and opening the SCSSV 45 to fluid flow. The electric motor drives the bore closure assembly to a predetermined (i.e., fully) open position, as sensed and communicated to the drive assembly (i.e., electric motor) by a means for sensing and communicating the position of the bore closure assembly. An example of a suitable means for sensing and communicating the position of the bore closure assembly is a feedback loop sensing the position of the bore closure assembly (for example, the location of the flow tube 65, flapper 61, ball nut of the ball screw assembly 98, or ball valve (not shown)) and communicating the position to the drive assembly, preferably via the local controller. Alternative means for sensing and communicating the position of the bore closure assembly include an electrical current monitor on the drive assembly, wherein a spike in current indicates that the drive assembly has driven the bore closure assembly to a limit (i.e., to the open position) or a driving cycle counter on the drive assembly, wherein the number of driving cycles (i.e., revolutions, strokes, etc.) is calibrated to the position of the bore closure assembly.

The fail safe assembly holds the bore closure assembly in the open position in response to a hold signal. In FIG. 3, the anti-backdrive device prevents the ball screw assembly from reversing. A preferred anti-backdrive device conveys a rotational force in only one direction, for example a sprag clutch. In response to rotation by the electric motor 76, the sprag clutch freewheels and remains disengaged. Conversely, in response to a reversal or back-drive force transmitted by the spring 64 through the ball screw assembly 98, cogs in the sprag clutch engage, thereby preventing counter rotation and locking the bore closure assembly in the open position. Alternative anti-backdrive devices include (but are not limited to) a non-backdriveable gear reducer, an electromagnetic brake, a spring-set brake, a permanent magnet brake on the electric motor 76, a means for holding power on the electric motor 76 (i.e., “locking the rotor” of the electric motor), a locking member (as described below), a piezoelectric device (as described below), or a magneto-rheological (MR) device (as described below).

The anti-backdrive device holds the bore closure assembly in the open position so long as electromagnetic clutch 91 remains engaged. Thus, the hold signal for the embodiment shown in FIG. 3 is the electric current powering and thereby engaging the electromagnetic clutch 91. As described previously, the hold signal can be interrupted either intentionally (for example, by a person signaling the local controller to close the valve) or unintentionally (for example, due to a failure of power or communications to the SCSSV). Upon interruption of the hold signal, the electromagnetic clutch 91 disengages, allowing the ball screw assembly to reverse, the flow tube 65 to move upward in response to the biasing force of the spring 64, and the flapper 61 to rotate closed about the axis 62. The electromagnetic clutch 91 isolates the electric motor 76 from reversal or backdrive forces transmitted across the mechanical linkage, thereby preventing damage to electric motor 76 and facilitating quick closure of the SCSSV (preferably, closure in less than about 5 seconds).

In an alternative embodiment shown in FIG. 7, the fail safe assembly comprises a piezoelectric device 200 having a stator 205, a flexible band 210, a piezoelectric stack 215, and an electrical connector pad 220. The piezoelectric device is positioned such that a moving member of the drive assembly 75, fail safe assembly 90, mechanical linkage 95, or bore closure assembly 60 is surrounded in a close tolerance relationship by the band 210. In the preferred embodiment shown in FIG. 7, the band 210 is connected at one end to the stator 205 and at the other end to the piezoelectric stack 215. Alternatively, piezoelectric stacks could be positioned at both ends of the band 210. In the preferred embodiment, the band 210 is designed to surround a collar 225 on the mechanical linkage 95, thus providing a close tolerance relationship upon the mechanical linkage moving downward (as shown by arrow 230) as the bore closure assembly is driven to the open position, as described previously. The upper end 230 of the mechanical linkage 95 is connected to the drive assembly 75 and the lower end 240 of the mechanical linkage 95 is connected to the bore closure assembly 60. Alternatively, the piezoelectric device 200 could be placed to surround, upon the bore closure assembly being driven to the open position, the drive nut 155 in FIG. 3A or to surround the shaft 110 in FIGS. 4 and 5 or a collar on the shaft 110 (not shown). While the preferred embodiment of FIG. 7 shows the movable member (i.e., the collar 225) moving in the longitudinal direction upon actuation of the bore closure assembly, it should be understood that the piezoelectric device 200 is also applicable to a movable member that rotates about an axis rather than moving longitudinally. For example, the piezoelectric device 200 could be placed around and in a close tolerance relationship with the gear reducer 97 in FIG. 3A.

Upon application of an electrical signal via wires 222 to the connector pad 220, the piezoelectric stack deforms, thereby tightening the band 210 (as shown by arrow 235) around the moving member (i.e., the collar 225) and locking the moving member into place against the stator 205. The piezoelectric stack is preferably a stack of piezoceramic material sized to provide adequate deformation and thus adequate holding force (via the tightening of the band 210 around the collar 225) to overcome backdrive forces. An alternative deformable member can be used in place of a piezoelectric stack, for example electrostrictive stacks actuated by application of an electrical field or magnetostrictive actuators actuated by application of a magnetic field, typically produced by running an electric current through an electromagnet. The band 210 and/or the stator 205 may be lined with a suitable friction-producing material or mechanical engagement device such as teeth, as shown by reference numeral 212. Additionally, the braking force produced by the stack may be amplified by levers. The piezoelectric device preferably is electronically controlled such that the piezoelectric device remains engaged in response to a hold signal and releases upon interruption of the hold signal as described previously. A piezoelectric device may be used as the fail safe assembly on any of the embodiments shown in the figures.

The piezoelectric device may be used in the hydraulically actuated embodiments of FIGS. 4 and 5, and in a preferred embodiment in cooperation with the shaft 110 as described previously. The piezoelectric device may be used with the direct electrically actuated embodiment of FIG. 6, for example by placing the piezoelectric device around and in a close tolerance relationship with the movable armature 190 or other appropriate movable member of the bore closure assembly.

In the electro-mechanically actuated embodiment of FIG. 3, the piezoelectric device preferably is used in combination with the electromagnetic clutch 91, wherein the piezoelectric devices serves as the anti-backdrive device and the clutch serves to isolate the electric motor 76 from reversal or backdrive forces, thereby preventing damage to the electric motor 76 and facilitating quick closure of the SCSSV. Where the piezoelectric device is located between the electric motor and the electromagnetic clutch, a hold signal to the electromagnetic clutch serves as the primary “trigger” for firing the SCSSV closed upon the occurrence of a fail safe event (provided however that the piezoelectric device and the electromagnetic clutch typically would release simultaneously, especially in the event of a catastrophic failure resulting in a loss of power to the SCSSV). Where the electromagnetic clutch is located between the electric motor and the piezoelectric device, a hold signal to the electromagnetic clutch may serve as the primary “trigger” for firing the SCSSV closed upon the occurrence of a fail safe event, or alternatively a hold signal to the piezoelectric device may serve as the primary “trigger” and the electromagnetic clutch can be disengaged beforehand (or simultaneously with the piezoelectric device).

In an alternative embodiment, the fail safe assembly comprises a locking member such as a latch, a cam, a pin, or a wrap spring that, when engaged, holds the bore closure assembly in the open position. The locking member preferably is electronically controlled such that the locking member remains engaged in response to a hold signal and releases upon interruption of the hold signal as described previously. The locking member may be positioned to hold the flapper 61 open, for example the latch 92 in FIG. 3, or to hold the flow tube in an extended position, for example the retractable pin 93 in FIG. 3. It should be understood that multiple fail safe assemblies are shown on FIG. 3 for convenience, and that while multiple fail safe assemblies can be employed on a SCSSV (for example, for backup purposes), typically only a single fail safe assembly will be used. Furthermore, a locking member may be used as the fail safe assembly on any of the embodiments shown in the figures, provided however that if a locking member is used in the electro-mechanically actuated embodiment of FIG. 3, the locking member is preferably combined with the electromagnetic clutch 91 as described previously for the piezoelectric device 200.

In an alternative embodiment, the fail safe assembly is a magneto-rheological (MR) device comprising an MR fluid and a means for applying a magnetic field to the MR fluid. The MR fluid is an incompressible fluid filled with ferromagnetic particles that bind together magnetically when a magnetic field is applied, resulting is a dramatic increase in the viscosity of the fluid. An example of a suitable MR fluid is Rheonetic brand MR fluid available from Lord Corporation of Cary, N.C. Alternatively, an electro-rheological (ER) fluid activated by an electrical field and a means for applying an electrical field can be used in place of an MR fluid and a means for applying a magnetic field. The MR device is positioned such that a moving member of the drive assembly 75, fail safe assembly 90, mechanical linkage 95, or bore closure assembly 60 is locked into place upon application of the magnetic field to the MR fluid. The MR device preferably is electronically controlled such that the MR device remains engaged in response to a hold signal and releases upon interruption of the hold signal as described previously. An MR device may be used as the fail safe assembly on any of the embodiments shown in the figures.

In a preferred embodiment, the fail safe assembly comprises an MR device used as the anti-backdrive device in FIG. 3, wherein the MR fluid is used as the incompressible fluid contained within the sealed chamber 77. Preferably, the MR device is combined with the electromagnetic clutch 91 as described previously for the piezoelectric device 200. As shown by reference numeral 94 in FIG. 3, the walls of the chamber 77 form a close-tolerance annular gap with at least one movable member of a component housed within the chamber. For example, gear reducer 97 and the walls of the chamber 77 form a close-tolerance annular gap filled by the MR fluid. In the absence of a magnetic field, the MR fluid flows freely within the annular gap in response to movement by the moveable member (e.g., the gear reducer 97). Upon application of a magnetic field to the MR fluid to engage the MR device, the MR fluid becomes very viscous and forms a bridge that occludes the annular gap, thus “freezing” into place at least one movable member of a component housed within the chamber (e.g., the gear reducer 97). Any suitable means for applying a localized magnetic field may be employed, such as an electromagnetic coil located adjacent to the chamber 77. The MR device preferably is electronically controlled such that the MR device remains engaged in response to a hold signal and releases upon interruption of the hold signal as described previously.

In an alternative embodiment, the fail safe assembly comprises an MR fluid used as the incompressible hydraulic fluid in the chamber 77 in FIGS. 4 and 5. The control valve 104 is a flow switch capable of producing a magnetic field such that the jumper line 105 is occluded from fluid flow upon application of the magnetic field, thereby maintaining the hydraulic pressure in the discharge side of the hydraulic loop and holding the bore closure assembly in the open position. The flow switch preferably is electronically controlled such that the flow switch remains engaged in response to a hold signal and releases upon interruption of the hold signal, thereby reducing the hydraulic pressure in the discharge side of the hydraulic loop and allowing the shaft 110 to retract and the flow tube 65 to move upward as described previously.

Halliburton provides proven, high-performance tubing-retrievable and wireline-retrievable subsurface safety valves (SSSV) designed to reliably shut-in (fail safe) if a catastrophic event occurs, allowing operators to maintain safe operations.

This invention relates in general, to the operation of a subsurface safety valve installed in the tubing of a subterranean wellbore and, in particular, to an apparatus and method for locking out a subsurface safety valve and communicating hydraulic fluid through the subsurface safety valve.

One or more subsurface safety valves are commonly installed as part of the tubing string within oil and gas wells to protect against unwanted communication of high pressure and high temperature formation fluids to the surface. These subsurface safety valves are designed to shut in production from the formation in response to a variety of abnormal and potentially dangerous conditions.

As these subsurface safety valves are built into the tubing string, these valves are typically referred to as tubing retrievable safety valves (“TRSV”). TRSVs are normally operated by hydraulic fluid pressure which is typically controlled at the surface and transmitted to the TRSV via a hydraulic fluid line. Hydraulic fluid pressure must be applied to the TRSV to place the TRSV in the open position. When hydraulic fluid pressure is lost, the TRSV will operate to the closed position to prevent formation fluids from traveling therethrough. As such, TRSVs are fail safe valves.

As TRSVs are typically incorporated into the tubing string, removal of the tubing string to replace or repair the malfunctioning TRSV is required. As such, the costs associated with replacing or repairing the malfunctioning TRSV is quite high. It has been found, however, that a wireline retrievable safety valve (“WRSV”) may be inserted inside the original TRSV and operated to provide the same safety function as the original TRSV. These insert valves are designed to be lowered into place from the surface via wireline and locked inside the original TRSV. This approach can be a much more efficient and cost-effective alternative to pulling the tubing string to replace or repair the malfunctioning TRSV.

It has been found, however, that operating conventional TRSVs to the locked out position and establishing this communication path has several inherent drawbacks. To begin with, the inclusion of such built-in lock out sleeves in each TRSV increases the cost of the TRSV, particularly in light of the fact that the built-in lock out sleeves are not used in the vast majority of installations. In addition, since these built-in lock out sleeves are not operated for extended periods of time, in most cases years, they may become inoperable before their use is required. Also, it has been found, that the communication path of the pre-machined radial bore creates a potential leak path for formation fluids up through the hydraulic control system. As noted above, TRSVs are intended to operate under abnormal well conditions and serve a vital and potentially lifesaving function. Hence, if such an abnormal condition occurred when one TRSV has been locked out, even if other safety valves have closed the tubing string, high pressure formation fluids may travel to the surface through the hydraulic line.

The present invention disclosed herein comprises an apparatus and method for establishing a communication path for hydraulic fluid to a wireline retrievable safety valve from a rod piston operated tubing retrievable safety valve. The apparatus and method of the present invention do not require a built-in lock out sleeve in the rod piston operated tubing retrievable safety valve. Likewise, the apparatus and method of the present invention avoid the potential for formation fluids to travel up through the hydraulic control line associated with a pre-drilled radial bore in the tubing retrievable safety valve.

In broad terms, the apparatus of the present invention allows hydraulic control to be communicated from a non annular hydraulic chamber of a rod piston operated tubing retrievable safety valve to the interior thereof so that the hydraulic fluid may, for example, be used to operate a wireline retrievable safety valve. This may become necessary when a malfunction of the rod piston operated tubing retrievable safety valve is detected and a need exists to otherwise achieve the functionality of the rod piston operated tubing retrievable safety valve.

The rod piston operated tubing retrievable safety valve of the present invent