Background

The present specification relates to an apparatus for controlling downhole devices.

It is necessary to control the actions of downhole valves and other tools from the surface. Valves or other downhole tools frequently need to be opened and closed at different stages of drilling, operating and maintaining a wellbore, so controllers may be used to achieve the remote opening and closing of the valve in the well as needed.

Activation and de-activation of downhole devices often involve steps such as dropping activation or deactivation balls from the surface. One disadvantage of these methods is that time between dropping the ball from the surface and the ball landing on the designated tool seat is a variable factor in the method. For very long wells it can take, for example, up to 60 minutes to switch a tool on and another 60 minutes to drop a second ball to switch the tool off. These methods also limit the number of on/off cycles that are possible because the number of balls that can be dropped and retained in the ball catcher is limited, and once the ball catcher is full, the tool must be retrieved to the surface and the ball catcher must be emptied before the tool can be re-set.

It is also known to control tools in the well using pressure changes transmitted via fluid in the wellbore, which shuttles a sleeve axially relative to a pin. Such arrangements are typically called J-slot devices, as the sleeve is slotted with a J-shaped slot in which the pin moves. The sleeve is caused to rotate relative to the stationary pin which is constrained to travel along the J-shaped slot. When the pressure is increased, the sleeve moves down, the pin is at one position in the slot, and the valve is open for example, and when the pressure is decreased, the sleeve moves up relative to the pin, which is guided into another relative position of the pin and the slot, in which the valve can be closed. The slot can be formed in a loop around the sleeve, with the two ends of the loop connected, so that the sleeve continually moves around its axis sequentially opening and closing the valve. The pressure acting on the sleeve can be wellbore pressure.

Improved slot-based apparatus are disclosed in WO 2013/079929 A2 and WO 2014/184551 A2, the entire contents of which are incorporated herein by reference. A control slot is provided having a loop and at least one elongated track spaced around the body with respect to the at least one loop. The pin can move in the at least one elongated axial track between different configurations of the pin and slot which correspond to configurations of the downhole device.

During assembly of these devices, a significant volume of air is trapped within the body at atmospheric pressure. As the tool is functioned, this air will become pressurized. This air is also compressed when the sleeve is moved. If the air were unable to escape, it would prevent the device from operating. Traditionally, a vent hole to the outside of the body was provided to allow the air to dispel. However, on the return stroke of the sleeve any fluids in the annulus would then be drawn back into the cavity and contaminate the inner workings of the device.

There is therefore a need for an improved apparatus for controlling a downhole device in an oil, gas or water well.

US 2016/130897 A1 discloses apparatus for controlling a downhole device in a well, comprising a body having a control slot engaging a pin.

EP 2 955 320 A1 discloses a multifunctional downhole wireline tool for fluid sampling and fluid jetting in a well downhole.

Summary

An apparatus for controlling a downhole device in an oil, gas or water well is provided according to claim 1 .

This provides an apparatus which can quickly and reliably change the operating state of a downhole device, while preventing external fluids from entering the operating parts of the device. The first piston assembly may comprise the first seal, and/or the second piston assembly may comprise the second seal.

The central cavity may be separated into a primary cavity and a secondary cavity with a flow pathway between the primary cavity and the secondary cavity, the first piston assembly arranged within the primary cavity and the second piston assembly arranged within the secondary cavity. Separating the cavities further helps isolate components of the device and can allow for easier assembly. The apparatus may further comprise a flow restrictor nozzle arranged within the flow pathway. The flow restrictor can act as a damper for the movement of the pistons. In a time-dependent operation this controls the speed of movement of the piston and the relative speed of the pin and slot.

Either: a) the first piston assembly may comprise a control slot and the outer body may comprise a pin engaging the control slot; or b) the outer body may comprise a control slot and the first piston assembly may comprise a pin engaging the control slot, wherein the pin is arranged to move along the control slot as the first piston assembly moves with respect to the outer body to thereby switch the downhole device between an at-rest mode, a drilling mode, and a circulation mode. This allows the downhole device to quickly and reliably be switched between the various states.

The control slot may have first loops wherein the pin is moveable between different configurations of the downhole device, and second loops spaced with respect to the first loops. The pin may be moveable in the second loops between different configurations of the downhole device. At least one of the loops may have a transition portion for switching the pin between the first loop and the second loops. The pin may be cycleable between the different configurations within each one of the first and second loops without switching between the first and second loops. Each of the first loops may have a first axial portion at one end, and each of the second loops may have a second axial portion at the same end, with a length different from that of the first axial portion. The control slot may have alternating first and second loops spaced circumferentially around the body. This allows the downhole device to be effectively cycled through the various states. Of course, any of the slots may be open ended depending on the machining requirements. Each axial portion may be blind ended.

The control slot may have at least one loop having an axial portion, wherein the pin is moveable between different configurations of the downhole device, and at least one elongated axial track arranged in an axial direction of the outer body and having a length in the axial direction longer than the axial portion. The pin may be moveable in the at least one elongated axial track between different configurations of the downhole device. Each of the at least one elongated axial track may be connected to one of the at least one loop via a deviate branch track, which is configured to track the pin from one of the at least one elongated axial track into one of the at least one loop. The pin may be switchable between each of the at least one elongated track and one of the at least one loop. The pin may be cycleable between the different configurations within each one of the at least one loops without switching from said loop to an adjacent elongated axial track. The control slot may have no separate, dedicate return path for returning the pin from the deviate branch track to the elongated axial track. This allows the downhole device to be effectively cycled through the various modes. Each axial portion may be blind ended.

The first biasing member may be arranged to provide a weaker biasing force than the second biasing member. This prevents the hydraulic fluid from going into a negative pressure in use.

The apparatus may further comprise an end stop arranged to limit movement of the first piston assembly in the first direction. This ensures that the first piston assembly does not move excessively.

The apparatus may further comprise a valve arranged between the first seal and the second seal for filling the sealed hydraulic reservoir with the hydraulic fluid. This allows easy filling of the hydraulic reservoir.

A method of controlling a downhole device in an oil, gas or water well is provided according to claim 9. This method exhibits the benefits discussed above in relation to the apparatus.

Brief Description of the Drawings

The present specification references, by way of example only, the accompanying drawings in which:

Figure 1 shows a cross-sectional view of an apparatus for controlling a downhole device in an at-rest mode;

Figure 1 A shows an expanded cross-sectional view of a first end of a first piston assembly of an apparatus for controlling a downhole device in the at-rest mode;

Figure 1 B shows a perspective partial cross-sectional view of a control slot in a first piston assembly of an apparatus for controlling a downhole device in the at-rest mode;

Figure 2 shows a cross-sectional view of the apparatus of Figure 1 in a drilling mode; Figure 2A shows an expanded cross-sectional view of a first end of a first piston assembly of an apparatus for controlling a downhole device in the drilling mode;

Figure 2B shows a perspective partial cross-sectional view of a control slot in a first piston assembly of an apparatus for controlling a downhole device in the drilling mode;

Figure 3 shows a cross-sectional view of the apparatus of Figure 1 in a circulation mode;

Figure 3A shows an expanded cross-sectional view of a first end of a first piston assembly of an apparatus for controlling a downhole device in the circulation mode;

Figure 3B shows a perspective partial cross-sectional view of a control slot in a first piston assembly of an apparatus for controlling a downhole device in the circulation mode;

Figure 4 shows an expanded view of a flow pathway between a primary cavity and a secondary cavity of an apparatus for controlling a downhole device;

Figure 5 shows an exploded view of a first piston assembly for use in an apparatus for controlling a downhole device;

Figure 5A is a schematic view of a control slot as if the surface of the piston were split axially and unrolled into a flat plane;

Figure 5B is a schematic view of a further control slot as if the surface of the piston were split axially and unrolled into a flat plane;

Figure 6 shows an exploded view of a sealing section between components of the first piston assembly of Figure 5;

Figure 7 shows an expanded cross-sectional view of a sealing section between a first piston assembly and an alignment sub;

Figure 8 shows an expanded cross-sectional view of a sealing section between a first piston assembly and an outer body of an apparatus for controlling a downhole device; and

Figure 9 shows an expanded cross-sectional view of a sealing section between a second piston assembly, extension tube and an outer body of an apparatus for controlling a downhole device.

Detailed Description

An apparatus 100 for controlling a downhole device is shown in cross-sectional view in Figures 1 , 2 and 3. The downhole device may be used to drill a bore-hole such as for an oil, gas or water well. The apparatus 100 comprises an outer body 10. As shown in the Figures, the outer body 10 may be formed of one or more components attached together. Alternatively, the outer body 10 may be a single integral component. The outer body 10 may comprise box and pin connections at its respective ends. These box and pin connections allow the outer body 10 to be quickly and easily connected to a string for a well. The string typically comprises a number of tubular devices connected end to end either side of the apparatus 100. In use, the right-hand side of the apparatus 100 as shown in Figures 1 , 2 and 3 is typically furthest down the bore-hole, with the left hand side nearer the surface. That means that the right hand side may be described as “downhole”. A component which is “downhole” of another component is therefore further towards the right hand side of these Figures. Being “downhole” means that a component is further down the bore-hole. However, alternative arrangements may also be used.

The outer body 10 defines a central cavity 11 which extends along a longitudinal axis of the outer body 10. This central cavity may be bounded by an inner wall of the outer body 10. That is, the outer body 10 may be generally a hollow cylinder with an inner wall defining the central cavity 11 . The longitudinal axis can be defined from a first end to a second end of the elongate outer body 10. Particularly, the longitudinal axis aligns in use with the drill string. A number of further components are arranged within this central cavity 11 to allow for operation of the apparatus 100 to control the downhole device. The outer body 10 may include an orifice 12 which vents to the bore hole.

The outer body 10 may further comprise a plug device 16 which is used to introduce a fluid into the apparatus 100. The plug device 16 may be provided to fill the defined hydraulic reservoir with the hydraulic fluid. The plug device 16 may be provided at any suitable location to allow filling of the defined hydraulic reservoir.

The apparatus 100 further comprises a first piston assembly 20, also known as an upper piston 20. This first piston assembly 20 is mounted within the central cavity 11 such that it is moveable in the longitudinal direction along the longitudinal axis. The first piston assembly 20 acts to switch the downhole device between an at-rest mode, a drilling mode and a circulation mode (also known as states or configurations). That is, the downhole device is switched between these different modes. As depicted in the Figures, the first piston assembly 20 can be formed of multiple components 22, 24. For example, there may be an upper piston body 22 and a lower guidance tube 24, such as a MAP tube 24, which collectively define the first piston assembly 20. Alternatively, the first piston assembly 20 may be formed as a single component. The first piston assembly 20 may comprise a control slot 25 (or orientational track) and the outer body 10 may comprise a control pin 14 which is received in and engages this control slot 25. To enhance the clarity of the schematic Figures 1 to 3, the control slot 25 is not shown. Instead, the control slot 25 is first shown in Figure 5. Particularly, the control slot 25 may be formed on the lower guidance tube 24. Movement of the control slot 25 relative to the control pin 14 affects the longitudinal movement and rotation of the first piston assembly 20 and thereby acts to switch the downhole device between the at-rest mode, the drilling mode and the circulation mode. That is, as the first piston assembly 20 moves in the longitudinal direction, the engagement of the control slot 25 and control pin 14 will direct the movement of the first piston assembly 20 so as to control the downhole device by directing its movement. Of course, in alternative arrangements the control slot 25 may be on the outer body 10 and the control pin 14 may be on the first piston assembly 20.

A specific example of a control slot 25 and control pin 14 which may be used in the present disclosure are explained in detail in WO 2013/079929 A2 and WO 2014/184551 A2, the entire contents of which are incorporated herein by reference.

Figures 5A and 5B show a schematic of control slots 25 which may be used. In these Figures, the control slot 25 has effectively been unrolled from the outer cylindrical surface of the first piston assembly 20.

Alternatively, the control slot 25 may take the form of a J-slot such as described above.

In specific examples such as shown in Figure 5A, the control slot 25 has first loops 25D wherein the control pin 14 is moveable between different configurations of the downhole device, and second loops 25E spaced with respect to the first loops 25D. The control pin 14 may be moveable in the second loops 25E between different configurations of the downhole device. At least one of the loops 25D, 25E may have a transition portion for switching the control pin 14 between the first loop 25D and the second loops 25E. In this sense, the control pin 14 may be cycleable between the different configurations within each one of the first and second loops 25D, 25E without switching between the first and second loops 25D, 25E.

Each of the first loops 25D may have a first axial portion 25A at one end, and each of the second loops 25E may have a second axial portion 25B at the same end. The second axial portion 25B may have a length different from that of the first axial portion 25A. Alternatively, the second axial portion 25B may have the same length as the first axial portion 25A. movement of the first piston assembly 20 may be limited by contact with the first alignment sub 60, such as one or more protrusions 64 as discussed below.

The control slot 25 may have alternating first and second loops 25D, 25E spaced circumferentially around the body. Of course, there may be a plurality of first loops 25D or a plurality of second loops 25E provided adjacent one another. Each of the first loops 25D and second loops 25E may have a rest end axial portion 25F at an opposite end. Each axial portion may be blind ended.

In further examples such as shown in Figure 5B, the control slot 25 may have at least one loop 25D having an axial portion 25A, wherein the pin is moveable between different configurations of the downhole device, and at least one elongated axial track 25C arranged in an axial direction of the outer body 10 and having a length in the axial direction longer than the axial portion 25A. The control pin 14 may be moveable in the at least one elongated axial track 25C between different configurations which correspond to configurations of the downhole device. Each of the at least one elongated axial track 25C may be connected to one of the at least one loop 25D via a deviate branch track, which is configured to track the control pin 14 from one of the at least one elongated axial track into one of the at least one loop 25D. The control pin 14 may be switchable between each of the at least one elongated track 25C and one of the at least one loop 25D and cycleable between the different configurations within each one of the at least one loops 25D without switching from said loop 25D to an adjacent elongated axial track 25C. The control slot 25 may have no separate, dedicate return path for returning the pin from the deviate branch track to the elongated axial track 25C. Each of the loops 25D may have a rest end axial portion 25F at an opposite end. Each axial portion may be blind ended.

Of course, any of the slots and tracks described above may be open ended depending on the machining requirements. Operation of the control slot 25 is described further below with reference to Figures 1 B, 2B and 3B.

Figures 5 and 6 show how the first piston assembly 20 may be formed from the lower guidance tube 24 and upper piston body 22. One or more metal lugs or flanges 21 A are formed on the upper piston body 22. These correspond to one or more recesses 21 B formed on the lower guidance tube 24. Of course, the lugs 21 A may be formed on the lower guidance tube 24 and the recesses 21 B on the upper piston body 22 in an alternative arrangement. These lugs 21 A and recesses 21 B are brought into engagement via connecting the lower guidance tube 24 and upper piston body 22 in the longitudinal direction. This engagement locks the lower guidance tube 24 and upper piston body 22 together rotationally. In other examples the first piston assembly 20 may be formed as a single part. This may be generally integrally formed. This single part first piston assembly may include sections corresponding to the lower guidance tube 24 and upper piston body 22.

The first piston assembly 20 may comprise an upper piston body 22 and a lower guidance tube 24, the upper piston body 22 connected to the lower guidance tube 24, wherein the lower guidance tube 24 comprises the control slot or the pin. In other arrangements, the first piston assembly 20 may be a single piece or component.

The apparatus 100 may further comprise an annular seal 23 between the upper piston body 22 and the lower guidance tube 24. This seals against fluid leakage between the upper piston body 22 and lower guidance tube 24.

The annular seal 23 may be an elastomeric O-ring 23. The elastomeric O-ring 23 is compressed in assembly for a reliable seal between the upper piston body 22 and the lower guidance tube 24.

The annular seal 23 may further comprise a non-elastomeric back-up ring 23A adjacent the elastomeric O-ring 23. These help ensure hydraulic integrity for the annular seal 23.

An annular seal 23, such an elastomeric O-ring 23, may be provided between the upper piston body 22 and the lower guidance tube 24. Particularly, the O-ring 23 may be provided on an outer surface of the lower guidance tube 24 for sealing against an inner surface of the upper piston body 22, or vice-versa. Particularly, the O-ring 23 may be located within a machined recess on the respective component. The elastomeric O-ring may further comprise one or more non-elastomeric back-up rings 23A. In particular examples, there may be a non-elastomeric back-up ring 23A either side of the elastomeric O-ring 23. When the upper piston body 22 and lower guidance tube 24 are engaged, the O-ring 23 is compressed or energised to thereby provide a hydraulic seal between the upper piston body 22 and lower guidance tube 24.

In order to hold the upper piston body 22 and lower guidance tube 24 in this assembly, one or more retaining elements 25 such as spring pins 25 may be inserted into corresponding holes and grooves in the upper piston body 22 and lower guidance tube 24. These spring pins 25 are sized to tightly fit in their respective holes to prevent respective movement of the upper piston body 22 and lower guidance tube 24.

While this describes one way of connecting the upper piston body 22 and lower guidance tube 24 to form the first piston assembly 20, it is appreciated that any other suitable method may be used - including forming the first piston assembly 20 as a single integral piece.

The first piston assembly 20 includes a number of bores which are selectively blocked based upon the operation state of the downhole device. Three positions for the first piston assembly 20 are shown in Figures 1 , 2 and 3. Particularly, there is a drilling bore 28 and a circulation bore 26. The drilling bore 28 extends from an outer surface of the first piston assembly 20 into a central bore 27 of the first piston assembly 20. The circulation bore 26 forms a pathway between two points on the outer surface of the first piston assembly.

Figure 1 shows the first piston assembly 20 in the at rest, or idle mode or state. A close-up view of this state is also shown in Figure 1 A. The first piston assembly 20 seals against the inner surface of the outer body 10 at a contact point 29 as shown in Figure 1 A.

Figure 2 shows the first piston assembly 20 in the drilling mode or state. In this drilling mode state, the first piston assembly 20 is moved along the longitudinal axis such that it no longer contacts against the inner surface of the outer body 10 at the contact point 29. Particularly, the first piston assembly 20 is moved from left to right as shown in Figures 1 and 2. In the drilling mode, fluid is able to flow through the drilling bore 28 into the central bore of the first piston assembly 20. As can be seen, the fluid can flow all the way through the apparatus as there are corresponding cavities in the other components (discussed below) to allow fluid to flow therethrough. The drilling mode state of Figure 2 may be used when the downhole device is operated in a drilling operation. Figure 3 shows the first piston assembly 20 in the circulation mode or state. In this state, the first piston assembly 20 is further moved in the longitudinal direction, and due to the interaction between the control pin 14 and control slot 25, also rotated. Particularly, the first piston assembly 20 is further moved from left to right as shown in Figures 1 , 2 and 3. As a result, the drilling bore 28 may be sealed such that fluid cannot enter. The circulation bore 26 is not sealed and is aligned with and in fluid communication with an orifice 12 in the outer body 10 of the apparatus 100. The orifice 12 connects the central bore 27 of the first piston assembly 20 with the surrounding area of the well bore. A close-up view of this orifice 12 is shown in Figure 8. In Figure 8 the first piston assembly 20 is in an at rest state (Figure 1) so the circulation bore 26 is not aligned with or in fluid communication with the orifice 12. In the at rest state the fluid is able to flow through the circulation bore 26 and into a void in the outer body 10 rom where it flows into the drilling bore 28. This continues until the pressure generated by the flow passes through the components below the assembly 100. The first piston 20 will move when this pressure exceeds the resistance of biasing members 40 and 50 (discussed below).

As can be seen in Figure 8, first and second seal assemblies 18 are provided either side of the orifice 12 to fluidly seal an inner surface of the outer body 10 against the first piston assembly 20 to prevent fluid ingress via the orifice when the first piston assembly 20 is not in the circulation state. Figure 8 also shows a bearing strip 19 which acts to support the first piston assembly 20.

The at rest, drilling and circulation states can be cycled through by applying a pressure differential to the apparatus 100. This pressure differential then causes the first piston assembly 20 to move and the engagement between the control pin 14 and control slot 25 then acts to adjust the movement of the first piston assembly 20 to determine which state is the result. Such operation is described, for example, in WO 2013/079929 A2 and WO 2014/184551 A2, the entire contents of which are incorporated herein by reference.

Particularly, the apparatus 100 may be driven between the rest mode, drilling mode and circulation mode based on a pressure differential between a pressure inside of the apparatus 100 to a pressure outside of the apparatus 100. This is controlled by causing a pressure drop outside of the apparatus 100. If the pressure differential is greater than a first threshold value this will result in the first piston assembly 20 moving from the rest mode to the drilling mode or circulation mode. In order to achieve this pressure differential, the drill string may consist of a lower bottomhole assembly (BHA). The bottomhole assembly can be activated to cause a pressure loss outside of the apparatus 100 in order to achieve the required pressure differential.

Particularly, there may be one or more pumps which can be operated to generate a flow of fluid which leads to a pressure drop. With a flowrate above a certain value, there will be a loss in the total pressure of the fluid such as to result in a pressure differential above the first threshold value.

If the pressure outside of the apparatus 100 then increases such that the pressure differential is less than second threshold value, the first piston assembly 20 may move back from the drilling mode or circulation mode to the rest mode. The first threshold value and second threshold value may be the same or may be different. The first threshold value and the second threshold value depend on a strength of biasing force provided by a first biasing member 40 and second biasing member 50 as discussed below. In practice, the pressure may be increased by switching off the pumps thereby leading to an equalisation of the pressure.

A first biasing member 40, such as a spring 40, is provided in the central cavity 11 of the outer body 10. The first biasing member 40 acts on the first piston assembly 20. Particularly, the first biasing member 40 acts to bias the first piston assembly 20 in a first direction along the longitudinal axis. This first direction may correspond to biasing the first piston assembly 20 away from the circulation mode of Figure 3. This first direction may correspond to biasing the first piston assembly 20 toward the rest mode of Figure 1 . That is, this first direction may correspond to biasing the first piston assembly 20 to the left of Figures 1 to 3. This first direction may also correspond to biasing the first piston assembly 20 away from the drilling mode towards the circulation mode.

A first alignment sub 60 may be provided to help align the first piston assembly 20 within the apparatus 100. For example, the first alignment sub 60 may extend along the longitudinal axis and receive at least a portion of the first piston assembly 20 therein as shown in the Figures. The first alignment sub 60 and/or first piston assembly 20 may include one or more protrusions such as fingers which contact the other component to thereby control and/or limit movement of the first piston assembly 20. Figure 7 shows an expanded cross-sectional view of the first piston assembly 20 being received by the first alignment sub 60. As can be seen, the first piston assembly 20 may include a seal assembly 29 to fluidly seal with the first alignment sub 60.

The first piston assembly 20 may further include a wiper assembly 29A which acts to further prevent fluid and debris ingress past the seal assembly 29 as the first piston assembly 20 moves within the first alignment sub 60. The first biasing member 40 may generally surround at least a portion of the first alignment sub 60.

The apparatus 100 further comprises a first seal which seals between an inner wall of the central cavity 11 of the outer body 10 and the first piston assembly. For example, this may be the right-most seal assembly 18 shown in Figure 8. Of course, the seal may be provided at any suitable location. Since the first piston assembly 20 includes the central bore 27, the first seal may further comprise the seal assembly 29 between the first piston assembly 20 and the first alignment sub 60.

The apparatus 100 further comprises a second piston assembly 30, also known as a lower piston 30. This second piston assembly 30 is arranged within the central cavity 11 of the outer body 10. The second piston assembly 30 is spaced from the first piston assembly 20. Particularly, the second piston assembly 30 may be spaced from the first piston assembly 20 in a second direction along the longitudinal axis which is opposite the first direction. That is, the second direction is opposite the direction of bias of the first biasing member 40. In use, this means that the second piston assembly 30 is downhole of the first piston assembly 20. In Figures 1 to 3, the second direction is to the right.

The second piston assembly 30 is biased by a second biasing member 50 arranged in the central cavity 11 of the outer body 10. The second biasing member 50 acts to bias the second piston assembly 30 in the first direction along the longitudinal axis. That is, in the same direction that the first biasing member 40 acts to bias the first piston assembly 20.

The second piston assembly 30 may be supported in the central cavity 11 of the outer body 10 by an extension tube 80. The second biasing member 50 may surround at least a portion of this extension tube 80. The second piston assembly 30 may slide along the extension tube 80. The extension tube 80 includes a central bore 87 to allow fluid flow therethrough to the drilling bore 26. The apparatus 100 further includes a second seal which seals between the inner wall of the central cavity 11 of the outer body 10 and the second piston assembly 30. The second seal may include a seal assembly 38 between the outer body 10 and the second piston assembly 30. The second seal may further comprise a seal assembly 39 between the second piston assembly 30 and the extension tube 80.

In this sense, the first seal of the first piston assembly 20 and the second seal of the second piston assembly 30 define a volume therebetween which is bounded by the inner wall of the central cavity 11 of the outer body 10. In practice, this defines a sealed hydraulic reservoir. This sealed hydraulic reservoir may be a single space. This hydraulic reservoir is filled, in use, with a hydraulic fluid. As a result, movement of the first piston assembly 20 drives the hydraulic fluid which in turn drives movement of the second piston assembly 30.

The first piston assembly may comprise the first seal, and/or the second piston assembly may comprise the second seal.

In certain embodiments such as shown in Figures 1 to 3, the central cavity 11 may be separated into a primary cavity 11 A and a secondary cavity 11 B with a fluid flow pathway 70 therebetween. The primary cavity 11 A may receive the first piston assembly 20 and the secondary cavity 11 B may receive the second piston assembly 30. In such an arrangement, the bound space and hence the sealed hydraulic reservoir may span across the primary and secondary cavities and the flow pathway therebetween. In certain examples, the first alignment sub 60 may define the first and second cavities by separating the central cavity 11 in two. In such examples, the flow pathway 70 may be formed through the first alignment sub 60 such as shown in Figure 4. A flow restrictor nozzle 72 may be provided in the flow pathway 70. Such a flow restrictor nozzle 72 may act to effectively restrict the flow of the hydraulic fluid through the flow pathway 70 and thereby dampen the apparatus 100. This damping can ensure smooth motion of the first piston assembly 20 and second piston assembly 30. The flow restrictor nozzle 72 also acts to determine the speed at which the apparatus 100 moves between the rest mode and drilling mode or circulation mode.

The hydraulic fluid may be any suitable hydraulic fluid such as a non-Newtonian fluid. For example, the hydraulic fluid may be mineral oil based. Of course, any hydraulic fluid may be used and selected for the particular performance requirements. In further examples, the hydraulic fluid may be a Newtonian fluid, such as a silicone oil.

In particular embodiments, the first biasing member 40 may provide a weaker biasing force than the second biasing member 50. This may be achieved, for example, by selecting particular spring constants in embodiments where the biasing members 40, 50 are springs.

As this defined hydraulic reservoir is fully sealed, external drilling fluid (mud) cannot enter the central cavity 11 . This also allows for lost-circulation material to be easily pumped through the apparatus 100 in the circulation mode. Such lost-circulation material may be pumped into the bore hole when drilling fluids are being lost. It acts to pack the walls of the bore hole and thereby reduce lost drilling fluids. Exemplary lost-circulation material may include fibrous materials (cedar bark, shredded cane stalks, mineral fibre and hair), flaky materials (mica flakes and pieces of plastic or cellophane sheeting) and/or granular materials (ground and sized limestone or marble, wood, nut hulls, Formica, corncobs and cotton hulls). Again, the sealed nature of the hydraulic reservoir means that this lost- circulation material does not enter these working parts of the apparatus 100 and therefore does not affect its use. The second biasing member 50 and second piston 30 may be exposed to this material, such as through ports 17 formed in the outer body 10. The ports 17 may take any suitable form, including slots and/or filter plugs. The external pressure may be communicated to the apparatus 100 via these ports 17.

Figure 1 shows the apparatus 100, particularly the first piston assembly 20, in a rest mode. The pressure differential between the internal pressure and the external pressure is less than the second threshold value. The first piston assembly 20 is driven towards this position by the first biasing member 40 and contacts an end stop. The second piston assembly 30 is also driven towards this position by the second biasing member 50. The second piston assembly 30 may be offset from a mechanical end stop in this position. This offset can be achieved by filling the hydraulic reservoir with a volume of hydraulic fluid which prevents the second piston assembly 30 from being able to contact a mechanical end stop.

In use, considering the movement from Figure 1 to Figure 2, the first piston assembly 20 moves in the second direction (to the right) against the biasing force of the first biasing member 40. An operator may, for example, run the pumps as discussed above. Once the pressure differential is greater than the first threshold, the first piston assembly 20 will begin to move in the second direction.

As the first piston assembly 20 moves it displaces the hydraulic fluid to drive the hydraulic fluid to the right. This hydraulic fluid then moves through the flow pathway 70 (if present) to then act on the second piston assembly 30. As a result, the second piston assembly 30 moves in the second direction (to the right) against the biasing force of the second biasing member 50.

Once the first piston assembly 20 has moved a predetermined amount, the drilling bore 28 is uncovered as shown in Figures 2 and 2A to allow a flow of drilling fluid therethrough. The first piston assembly 20 contacts against a first protrusion 64 of the first alignment sub 60. This first protrusion 64 acts as a mechanical end stop for the first piston assembly 20 in the drilling mode. The first protrusion 64 may, for example, be a finger.

As noted above, the first piston assembly 20 may comprise a control slot 25. Movement of the apparatus 100 between the rest mode and the drilling mode is explained with reference to the control slot 25 and Figures 1 to 3B.

Figures 1 B, 2B, 3B shows the first piston assembly 20 with the first biasing member 40 omitted for ease of viewing. The control slot 25 is shown. The control slot 25 shown in these Figures is generally similar to the one shown in Figure 5A. There may be minor changes to the precise shape without deviating from the underlying function. Of course, one or more of the axial portions 25A, 25B, 25F may or may not be blind-ended. The control pin 14 is shown in the rest end axial portion 25F of the control slot 25 in Figure 1 B. This is the apparatus 100 in the rest mode. As the pumps are turned on and the pressure differential increases, the first piston assembly 20 moves as described above. As the first piston assembly 20 moves, contact between the control slot 25 and control pin 14 guides its movement.

The control pin 14 ends up in the first axial portion 25A, which is shorter than the second axial portion 25B, as shown in Figure 2B. This first axial portion 25A corresponds to the drilling mode of the apparatus 100. As can be seen, the first piston assembly 20 contacts against the first protrusion 64 of the first alignment sub 60. The first protrusion 64 may include one or more tangs as shown. These may produce a generally castellated profile. This can act to resist angular displacement due to vibration or other drilling forces.

To move back in the opposite direction from Figure 2 to Figure 1 , the operator turns off the pumps to thereby reduce the pressure differential on the apparatus 100. The biasing forces of the first biasing member 40 and the second biasing member 50 then return the first piston assembly 20 and second piston assembly 30 back to the at-rest positions of Figure 1 . The hydraulic fluid may also assist in this movement as the movement of the second piston assembly 30 in the first direction (to the left) will drive corresponding movement in the first piston assembly 20.

As the first piston assembly 20 moves back to the rest position, the control pin 14 will move along the control slot 25 back to the original rest end axial portion 25F as shown in Figure 1 B. In this sense, the apparatus 100 remains in a loop between the rest mode and the drilling mode without entering the circulation mode.

In order to change the apparatus 100 to enter the circulation mode, movement of the first piston assembly 20 must be effected that uses the control slot 25 and control pin 14 to rotate the first piston assembly. This is described in detail in WO 2013/079929 A2 and WO 2014/184551 A2, the entire contents of which are incorporated herein by reference.

In brief, the pressure differential to drive the first piston assembly 20 is triggered. Then the pumps are turned off to move the first piston assembly 20 back towards the rest mode. After a prescribed time the pressure differential is restored while the first piston assembly 20 is between the drilling mode and the rest mode. This then drives movement of the first piston assembly back in the second direction and the interaction of the control slot 25 and control pin 14 causes rotation of the first piston assembly 20.

The result of this rotation is shown in Figure 3B. The first piston assembly 20 is driven in the second direction after this rotation and as a result the control pin 14 is now in the second axial portion 25B. This second axial portion 25B corresponds to the circulation mode.

As a result of the rotation, the first piston assembly 20 no longer contacts the first protrusion 64 of the first alignment sub 60. Instead, the first piston assembly contacts a second mechanical stop 65 as shown in Figures 3 and 3A. This allows the first piston assembly 20 to be in different axial positions for the drilling mode and circulation mode.

In the circulation mode, as shown in Figures 3 and 3A, the circulation bore 26 is now aligned with the orifice 12 which vents to the bore hole. This allows a flow of mud from the apparatus 100 to the bore hole. This means that mud through the apparatus 100 bypasses the bottomhole assembly and hence a standpipe pressure will be significantly lower.

The apparatus 100 can then be cycled between the circulation mode and rest mode in the same manner as discussed above in relation to the drilling mode and rest mode. In order to switch back to the drilling mode the same process as above is carried out.

In general terms, a method of controlling a downhole device in an oil, gas or water well can be described including the steps of: providing an apparatus 100 as described above. The first piston assembly 20 is then moved along the longitudinal axis to switch the downhole device between an at-rest mode, a drilling mode and a circulation mode. As a result, the first piston assembly 20 acts on the hydraulic fluid to drive movement of the second piston assembly 30. For completeness it is noted that this method occurs when the defined hydraulic reservoir has been filled with a suitable hydraulic fluid.