NO20231334A1 - Well tool device - Google Patents

Description

Well tool device

FIELD OF THE INVENTION

The present invention relates to a well tool device with an initially open state, a closed state and a final open state.

BACKGROUND OF THE INVENTION

NO 343864 and NO 343059 describes a well tool which is integrated in a lower end of a production tubing (also referred to as a completion string). The tool has a housing having a longitudinal through bore, in which a sleeve is longitudinally displaceable relative to the housing. A frangible disc is secured inside the sleeve. The tool has three states:

1: an initial state, in which fluid is allowed to bypass the frangible disc. In this state, fluid is allowed to enter the production tubing as the production tubing is lowered into the well.

2: a closed state, in which pressure can be increased above and/or below the frangible disc for pressure testing purposes.

3: a final state, in which the frangible disc has been disintegrated, allowing fluid to flow through the tool, typically during the production phase of the well.

The Interwell IRBV tool is based on the technology of the two above publications.

One object of the present invention is to improve the above prior art tool. In particular, one object is to provide a more cost-efficient tool and/or a more robust tool.

SUMMARY OF THE INVENTION

The present invention relates to a well tool device comprising:

- a housing having a longitudinal through bore;

- a sleeve provided within the bore and being longitudinally displaceable relative to the housing, wherein the sleeve comprises a longitudinal through bore aligned with the longitudinal through bore of the housing;

- a fluid flow preventing frangible disc provided in the longitudinal through bore of the sleeve;

- a fluid passage bypassing the frangible disc when the well tool device is in an initial state, thereby allowing a fluid flow between a first location above the frangible disc and a second location below the frangible disc;

- a first actuating system for bringing the well tool device to a closed state, in which the fluid passage is closed;

- a second actuating system for bringing the well tool device to a final state, in which the frangible disc has been disintegrated, thereby allowing a fluid flow through the bore of the sleeve;

characterized in that:

the first actuating system comprises:

- a first sensor for measuring a predetermined parameter;

- a valve having a closed state in which fluid flow from the bore to a piston surface of the sleeve is prevented, and having an open state in which fluid flow from the bore to the piston surface of the sleeve is allowed;

- an actuator for moving the valve from the closed state to the open state;

- a digital signal processor configured to send an actuating signal to the actuator based on information received from the sensor.

The information received from the first sensor comprises:

- a first signal;

- a confirmation signal received a period of time after the first signal;

wherein the digital signal processor may be configured to send the actuating signal to the actuator only when both the first signal and the confirmation signal may be received from the first sensor.

The information received from the first sensor may comprise:

- a reset signal;

wherein the digital signal processor may be configured to wait for further information from the first sensor before the digital signal processor is sending the actuating signal to the actuator.

The further information may comprise both the first signal and the confirmation signal. The reset signal may be considered an abort signal. The reset signal may be considered a postpone signal. The reset signal may be a lack of a confirmation signal within a predetermined period of time.

The digital signal processor may be configured to keep the well tool device in the initial state if no signal is received by the first sensor within a predetermined period of time. Here, the well tool device is considered to be fail-safe in the initial state. The digital signal processor may be configured to move the valve from the closed state to the open state within a predetermined period of time. Here, the well tool device is considered to be fail-safe in the closed state.

The piston surface of the sleeve may be ring-shaped.

The sleeve may comprise an upper sleeve section and a lower sleeve section connected to each other, wherein the frangible disc may be provided in the longitudinal through bore of the upper sleeve section and wherein the piston surface may be provided in the lower sleeve section.

The well tool device comprises:

- a supporting sleeve for supporting the fluid flow preventing frangible disc within the sleeve;

- a radially expandable locking device engaged with a lower end of the supporting sleeve;

wherein the second actuating system may be configured to prevent radial expansion of the locking device in the initial state and the closed state; and wherein the second actuating system may be configured to allow radial expansion of the locking device in the final state.

The second actuating system may comprise an actuating rod provided radially outside of the supporting sleeve, wherein the actuating rod may comprise a sleeve compartment; wherein the actuating rod may be preventing radial expansion of the locking device in the initial state and the closed state; and wherein the sleeve compartment may be aligned radially outside of the locking device in the final state, thereby allowing radial expansion of the locking device into the sleeve compartment.

An upper end of the radially expandable locking device may be wedgingly engaged with the lower end of the supporting sleeve.

By applying a fluid pressure above the frangible disc, the supporting sleeve will be pushed downwardly against the locking device. An inclined surface of the upper end of the locking device and/or an inclined surface of the lower end of the supporting sleeve will force the radially expandable locking device radially outward, thereby allowing the supporting sleeve to move further downwards, thereby allowing the frangible disc to be brought into contact with a disintegration device, which causes disintegration of the frangible disc. The well tool device is now in the open state.

The disintegration device may comprise a number of knifes. The disintegration device may be secured to the sleeve.

The supporting sleeve may comprise an upper end. The upper end of the supporting sleeve is forming a lower disc-supporting surface for the frangible disc. The sleeve comprises an upper disc supporting surface. The upper disc-supporting surface together with the upper end form a supporting seat for the frangible disc.

The well tool device may comprise a ratchet system located between the housing and the sleeve.

The ratchet system is a system which allows relative movement between the housing and the sleeve in a first direction, while it prevents relative movement between the housing and the sleeve in a second direction, opposite of the first direction. This is achieved by means of a toothed area of the inwardly facing surface of the housing being engaged with a toothed area of the an outwardly facing surface of the sleeve and where properties of the toothed areas determine the allowed/prevented movement.

The ratchet system may comprise a ratchet ring provided between the housing and the sleeve. The ratchet ring may comprise a toothed area of the inwardly facing surface of the ratchet ring being engaged with a toothed area of an outwardly facing surface of the sleeve. In this embodiment, the ratchet ring is fixed in relation to the outer housing.

Here, the ratchet system allows upward movement of the sleeve relative to the housing, while downward movement of the sleeve relative to the housing is prevented.

The fluid passage may comprise one or more apertures provided in the sleeve above the frangible disc, one or more recesses or bores provided in the housing radially outside of the frangible disc, one or more apertures provided in the sleeve below the frangible disc and one or more apertures provided in the supporting sleeve, wherein the apertures, the recesses or bores, the apertures and the apertures are aligned with each other in the initial state to allow the fluid flow between the first location above the frangible disc and the second location below the frangible disc.

The actuator of the first actuating system may be an electrically powered actuator.

The actuator of the first actuating system may be a pyrotechnic actuator for moving the valve by ignition of a pyrotechnic material. The ignition may be initiated by the electric actuating signal sent by the digital signal processor.

The first sensor may be a pressure sensor for measuring a parameter representative of a fluid pressure in the bore.

The first sensor may be a pressure sensor for measuring a fluid pressure directly or indirectly. The first sensor may be a temperature sensor for measuring a temperature of the fluid in the bore, as the fluid temperature in the bore is a parameter representative of the fluid pressure in the bore.

The predetermined parameter measured by the first sensor may be a predetermined parameter signature. The predetermined parameter signature may be a predetermined threshold value maintained for a predetermined period of time or a number of predetermined threshold values, such as pressure cycles, during a predetermined period of time.

The predetermined parameter may be fluid circulation for a predetermined period of time.

The first sensor may be a communication sensor for measuring a communication signal.

The communication sensor may be sensor for measuring an acoustic signal propagating through the well pipe and/or through the well fluid. The communication sensor may be a pressure sensor for measuring variations in fluid pressure as a function of time. Such a fluid pressure as a function of time may be referred to as a pressure signature. The communication sensor may comprise a sensor for measuring if a fluid is circulated past the sensor and/or if fluid is not circulated past the sensor.

The first actuating system may comprise a second sensor for measuring a second predetermined parameter different from the predetermined parameter measured by the first sensor. The digital signal processor may be configured to send an actuating signal to the actuator based on information received from the first sensor and/or from the second sensor.

According to the present invention, it is achieved a well tool device which can be brought from the initial state to the closed state by means of several different parameters, such as a predetermined pressure threshold, by a number of predetermined pressure thresholds, by a pressure signature etc.

The first valve may comprise a rod, a first valve bore in which the rod is sealingly engaged and a second valve bore providing fluid communication between the bore of the housing and the piston surface of the sleeve via the first valve bore. In the closed state, the rod may prevent fluid flow between the bore and the second valve bore. In the open state, the first actuator may move the rod to a position in which fluid flow between the bore of the housing and second valve bore is allowed, thereby allowing fluid flow between the bore of the housing and the piston surface of the sleeve is allowed. By increasing the fluid pressure below the frangible disc relative to the fluid pressure above the frangible disc, the sleeve may be forced to move upwardly.

The first actuating system may comprise a rechargeable battery or a super capacitor for supplying electric power to the digital signal processor, to the first sensor and to the actuator.

The fluid flow preventing frangible disc may be provided in the longitudinal through bore of the sleeve in sealing engagement with the sleeve. The sealing engagement may be achieved by a sealing element between the frangible disc and the bore of the sleeve.

In the closed state, the sleeve is moved upwardly to a position in which there is a sealing engagement between the outer surface of the sleeve and the bore of the housing. The sealing engagement may be achieved by a sealing element between the sleeve and the bore of the housing. The aperture of the sleeve may in the closed state be located above the sealing element while the aperture of the sleeve may in the closed state be located below the sealing element.

The terms “upper”, “above”, “below” and “lower” are used herein to define parts of the well tool device, when the well tool device is used in a well. “Upper” and “above” refer to a position relatively closer to the well opening and “below“ and “lower” refer to a position relatively further away from the well opening. These terms apply both when the well has a vertical and horizontal orientation.

In addition to the above achievements, it is further achieved that the parameter required to bring the well tool device from the initial state to the closed state may be changed up until immediately before inserting the well tool device into the well. In prior art, tools must typically be returned to manufacturing location in order to perform such changes. This enables the operator to choose a parameter which do not interfere with parameters of other equipment used in the well.

DETAILED DESCRIPTION

Embodiments of the invention will be described below with reference to the enclosed drawings, in which:

Fig. 1 is a first cross section of the tool in an initial state;

Fig. 2 is a second cross section of the tool in the initial state;

Fig. 3 is an enlarged view of box H of fig. 1;

Fig. 4 is a first cross section of the tool in a closed state;

Fig. 5 is a second cross section of the tool in the closed state;

Fig. 6 is an enlarged view of box K in fig. 4;

Fig. 7 is a first cross section of the tool in a final state;

Fig. 8 is a second cross section of the tool in the final state;

Fig. 9 is an enlarged view of box O of fig. 7;

Fig. 10 is an enlarged view of box P of fig. 8;

Fig. 11 is an enlarged view of box Q of fig. 8;

Fig. 12 is a flow chart of the operation of the signal processor;

Fig. 13 and 14 show the well tool device as part of a completion string in a well.

It is now referred to fig. 1 and fig. 2. Here it is shown a well tool device 1 comprising a housing 10 with a longitudinal through bore 11. A longitudinal centre axis is indicated as a dashed line LCA. In an upper end of the housing 10 (left side of fig. 1 and 2), the housing 10 comprises an upper threaded connection interface 15. In a lower end of the housing, the well tool device 1 further comprises a lower (right side of fig. 1 and 3, the housing 10 comprises a lower threaded connection interface 16. The housing 10 typically comprises several housing sections which are assembled together.

It is now referred to fig. 13. Here, a hydrocarbon producing well W is shown schematically. The well W comprises a casing CA into which a completion string CS has been inserted. The upper connection interface 15 is connected to an upper section of the completion string CS, while the lower connection interface 16 is connected to a lower section of the completion string CS.

As shown, the well tool device 1 is connected near the lower end of the completion string. However, a packer PA may be connected to a section of the completion string CS below the well tool device 1 for the purpose of sealing an annulus outside of the completion string. This will be described further in detail below.

It is now referred to fig. 1 and 2 again. Here it is shown that the well tool device 1 further comprises a sleeve 20 provided within the bore 11. The sleeve 20 comprises a longitudinal through bore 21 aligned with the longitudinal through bore 11 of the housing 10. The sleeve 20 is longitudinally displaceable relative to the housing 10, as will be apparent from the description below. However, as shown in fig. 3, a longitudinal displacement is prevented due to an arrangement 29 connecting the sleeve 20 to the housing 10.

The sleeve 20 comprises an upper sleeve section 22 and a lower sleeve section 23 secured to each other. It should be noted that the sleeve 20 may comprise more than these sleeve sections 22, 23. In the upper sleeve section 22, an upper disc supporting surface 25 is provided. In the lower sleeve section 23, a ring-shaped piston surface 26 (fig. 3) is provided. The ring-shaped piston surface 26 is formed as a collar protruding radially from the outside of the lower sleeve section 23, thereby forming an at least partially annular fluid line FL23 outside of the lower sleeve section 23 and inside of the housing 10. The annular fluid line FL23 is extending from the piston surface 26 and down to a lower end 23b of the lower sleeve section 23. The fluid line FL23 is indicated as a dashed line in fig. 3.

The well tool device 1 further comprises a frangible disc 30 and a supporting sleeve 41 for supporting the fluid flow preventing frangible disc 30 within the sleeve 20.

As is known from prior art, the frangible disc 30 is typically made of hardened glass, and is shaped as a cylinder with chamfered upper and lower edges. The chamfered upper edge is supported by the upper disc supporting surface 25.

The supporting sleeve 41 is provided radially inside of the upper sleeve section 22 and comprises an upper end 41a having an inclined supporting surface for supporting the chamfered lower edge of the frangible disc 30. Hence, the upper end 41a of the supporting sleeve 41 is forming a lower disc-supporting surface for the frangible disc 30. The upper disc-supporting surface 25 together with the upper end 41a form a supporting seat for the frangible disc 30. The frangible disc 30 is sealingly engaged in this seat by sealing elements (such as O-rings) 35. Hence, longitudinal fluid flow through the bore 21 of the sleeve 20 is prevented. It should be noted that longitudinal forces formed by a differential fluid pressure over the frangible disc 30 will be transferred via the chamfered edges of the frangible disc 30 into the sleeve 20.

It is now referred to fig. 2. Here it is shown that relative longitudinal movement of the supporting sleeve 41 is prevented by a locking device 42 arranged between a lower end 41b of the supporting sleeve 41 and an inwardly protruding collar 28 of the sleeve 20. The locking device 42 is radially expandable. The locking device 42 has an upper end 42a with an inclining surface and the lower end 41b of the supporting sleeve has an inclining surface. These inclining surfaces are providing a wedgingly engaged with each other. By pushing the supporting sleeve 41 down towards the locking device 42, the wedging engagement between the inclined surfaces will force the radially expandable locking device 42 radially outward, thereby allowing the supporting sleeve 41 to move further downwards. This will be described further in detail below. However, it should be noted that in fig. 1 and fig.

2, radial expansion of the locking device 42 is prevented. Hence, in fig. 1 and 2, it is not possible to push the supporting sleeve 41 down.

In fig. 1, it is further shown that the well tool device 1 further comprises a fluid passage 2 bypassing the frangible disc 30. The fluid passage 2 comprise a number of apertures 2a provided in the sleeve 20 above the frangible disc 30, a number of recesses or bores 2b provided in the housing 10 radially outside of the frangible disc 30, a number of apertures 2c provided in the sleeve 20 below the frangible disc 30 and a number of apertures 2d provided in the supporting sleeve 41. The apertures 2a, the recesses or bores 2b, the apertures 2c and the apertures 2d are aligned with each other in order to allow a fluid flow FF1 (indicated as a dashed arrow in fig. 1) between a first location L1 in the bore 11 above the frangible disc 30 and a second location L2 in the bore 11 below the frangible disc 30.

The well tool device 1 further comprises a first actuating system 50 and a second actuating system 60. The first actuating system 50 is used to bring the well tool device 1 from an initial state S1 shown in fig. 1 and 2 to an closed state S2 shown in fig. 5 and 6. The second actuating system 60 is used to bring the well tool device 1 from the closed state S2 to a final state S3 shown in fig. 7 and 8.

In fig. 1, it is shown that the first actuating system 50 is located below the frangible disc 30. In fig. 1 and fig. 3, it is shown that the first actuating system 50 comprises a first sensor 51 exposed to the fluid in the bore 11. The first sensor 51 is electrically connected to a digital signal processor 52, which is configured to send an electric actuating signal to an actuator 53 based on information received from the sensor 51. The actuator 53 is connected to a valve 54 having a closed state PS1 shown in fig. 3 and an open state PS2 shown in fig. 6.

The first actuating system 50 further comprises an energy source 55, typically a rechargeable battery or a super capacitor, for supplying electric power to the digital signal processor 52, to the first sensor 51 and to the actuator 53.

In the present embodiment, the first sensor 51 is a pressure sensor for measuring a parameter representative of a fluid pressure in the bore 11. The actuator 53 is a linear pyrotechnic actuator for moving the valve 54 linearly by ignition of a pyrotechnic material, for example an actuator such as Metron DR2094 manufactured by Chemring Energetics UK. The ignition of the pyrotechnic actuator is initiated by the electric actuating signal sent by the digital signal processor 52.

As shown in fig. 3 and fig. 6, the first valve 54 comprises a rod 54a, a first valve bore 54b in which the rod 54a is sealingly engaged and a second valve bore 54c providing fluid communication between the bore 11 of the housing 10 and the piston surface 26 of the sleeve 20 via the first valve bore 54b. In fig. 3, a fluid line FL23 is indicated as a dashed line. The fluid line FL3 extends from the end of the rod 54a to the piston surface 26 of the sleeve 20.

In the initial state S1 of the well tool device 1, the first actuating system 50 is in the closed state PS1. Here, the rod 54a prevents fluid flow between the bore 11 and the second valve bore 54c. In the open state PS2, the first actuator 53 has moved the rod 54a to the position shown in fig. 6. Here, fluid flow (indicated by a dashed arrow) between the bore 11 of the housing 10 and second valve bore 54c is allowed, and hence, fluid flow between the bore 11 of the housing 10 and the piston surface 26 of the sleeve 20 is allowed.

Due to the relative small cross sectional area of the fluid passage 2 bypassing the frangible disc 30, it is possible to provide a fluid difference over the frangible disc 30. By increasing the fluid pressure below the frangible disc 30 relative to the fluid pressure above the frangible disc, the sleeve 20 will move upwardly due to the fluid pressure applied to the piston surface 26. This will bring the well tool device to the closed state S2. The upwardly directed movement of the sleeve 20 is stopped by an inwardly protruding stopper 18 of the housing 10 (shown in fig. 2 and in fig. 5), such an inwardly protruding shoulder. When the sleeve 20 meets this stopper 18, further upwardly directed movement of the sleeve 20 is prevented.

The well tool device 1 further comprises a ratchet system 70 located between the housing 10 and the sleeve 20. The ratchet system 70 is a system which allows relative movement between the housing 10 and the sleeve 20 in a first direction A, while it prevents relative movement between the housing 10 and the sleeve 20 in a second direction B, opposite of the first direction A (see arrows A and B in fig. 3 and fig. 6). The ratchet system 70 comprises a ratchet ring 71 provided between the housing 10 and the sleeve 20. The ratchet ring 71 comprise a toothed area of the inwardly facing surface of the ratchet ring 71 being engaged with a toothed area of an outwardly facing surface of the sleeve 20. In this embodiment, the ratchet ring 71 is fixed in relation to the outer housing 10. Hence, the sleeve 20 is allowed to move upwardly due to the increased pressure below the frangible disc 30 relative to the pressure above the frangible disc 30. However, if the pressure above the frangible disc 30 becomes larger than the pressure below the frangible disc 30, the sleeve 20 will not be allowed to move downwardly again.

The second actuating system 60 comprises a pressure cycle counting mechanism 61, which allows a fluid within a closed chamber to exert a force onto a piston surface when a predetermined number of pressure cycles has been detected. The pressure cycle counting mechanism 61 is here a mechanical mechanism, i.e. not electronic. The pressure cycle counting mechanism may be an activating mechanism of the type described in EP 2201214B1 (filed in the name of Vosstech AS, now a part of Interwell Norway AS).

In fig. 9a, it is shown that the second actuating system 60 comprises a bore 63 within the housing 10, and a piston rod 64 provided within the bore 63. In the lower end of the piston rod 64, sealing elements 64a in the form of O-rings are provided. The bore 63 has two sections, an upper bore section 63a having a first diameter D63a and a lower bore section 63b having a second diameter D63b. The second diameter D63b is larger than the first diameter D63a. In fig. 9a, the sealing elements 64a are sealingly engaged with the piston rod 64 and the upper bore section 63a, and hence, the fluid flow between the upper bore section 63a and the lower bore section 63b is prevented. Fig. 9a shows the piston rod 64 in the position of the initial state S1 and the closed state S2.

The second actuating system 60 further comprises a sleeve 65 provided within the housing 10. An upper end 65a of the sleeve 65 is sealingly engaged with the housing 10 by means of a sealing element 83.

The upper bore section 63a is configured to be in fluid communication with the fluid of the closed chamber of the pressure cycle counting mechanism 61. In the present embodiment, fluid is here is glycol. When the pressure cycle counting mechanism 61 has finished counting the predetermined number of pressure cycles, a valve (not shown) is opened to supply pressurized glycol to the upper bore section 63a. It should be noted that the glycol is pressurized by the fluid in the bore 11 due to the opening of the valve. This will move the piston rod 64 to the position shown in fig. 9b and hence bring the sealing elements 64a into the lower bore section 63b. Due to the enlarged diameter of the lower bore section 63b, fluid is now allowed to flow from the upper bore section 63a to the lower bore section 63b as indicated by the dashed arrow FF64. This will push the sleeve 65 downwardly and out of sealing engagement with the housing 10 as indicate in fig. 9b. Here it is shown that also fluid from the bore 11 will enter the area above the sleeve 65.

In fig. 2 and 5, the distance D2 is indicating a distance between the stopper 18 and a peripheral edge surface of the sleeve 65. In fig. 8, the same distance D2 is indicated. It is here apparent that the distance D2 is shorter in fig. 8 than in fig. 2 and 5 due to the downward movement of the sleeve 65.

It is now referred to fig. 10. Here it is shown that the second actuating system 60 comprises an actuating rod 68 provided within the housing 10 radially outside of the supporting sleeve 41. The actuating rod 68 is extending from a position above the frangible disc 30 to a position below the frangible disc 30. Hence, the actuating rod 68 may be operated by the second actuating system 60 located above the frangible disc 30. The actuating rod 68 is longitudinally displaceable relative to the housing 10. However, the actuating rod 68 is locked to the sleeve 20 by means of a shear pin 32 secured through an shear pin opening 68a in the upper end of the rod 68 and a shear pin opening 27 in the upper end of the sleeve 20.

The actuating rod 68 comprises a sleeve compartment 69 adapted to receive the above locking device 42. In the initial state S1 and in the closed state S2 the actuating rod 68 has a position which is preventing radial expansion of the locking device 42. Here, the sleeve compartment 69 is not located radially outside of the locking device 42. In the final state S3, the sleeve compartment 69 is aligned radially outside of the locking device 42 thereby allowing radial expansion of the locking device 42 into the sleeve compartment 69. This is caused by the downward movement of the sleeve 65, which engages the upper end of the rod 68 and shears the shear pin 32, causing the rod 68 to move down relative to the sleeve 20. As shown in fig. 10, the shear pin opening 68a is not aligned with the shear pin opening 27.

It is now referred to fig. 2, fig. 5 and fig. 11. Here it is shown that the well tool device 1 comprises a disintegration device 40 in the form of a number of knifes secured to the sleeve 20 below the frangible disc. The supporting sleeve 41 comprises slits 41c (shown in fig. 11) in which the knifes are located in the initial state S1 and in the closed state S2. It should be noted that the slits 41c do not prevent downward movement of the supporting sleeve 41 relative to the sleeve 20 in the final state S3, as is clearly shown in fig. 11.

Operation of the well tool device

The operation of the above well tool device 1 will now be described.

Initially, it should be noted that the well tool device 1 is assembled topside. Hence, the fluid pressure in closed compartments such as the bore 54b and the continuation of the bore 54b represented by fluid line FL23 will have a pressure of ca 1 atm. when lowered into the well W. The same applies to the lower bore section 63b, which also will have a pressure of ca 1 atm.

As described above and as shown in fig. 13, the well tool device 1 is lowered into the well W in its initial state shown in fig. 1 and 2 as part of a completion string CS. During lowering of the well tool device 1 into the well, fluid in the well is allowed to enter into the completion string CS via the fluid passage 2 bypassing the frangible disc 30 (as indicated by fluid flow FF1 in fig. 1 and 13). Hence, the completion string CS has self-filling properties.

At a desired location in the well W, the packer PA is set as shown in fig. 14 to close the annulus A between the completion string CS and the casing CA. A pressure test of the packer PA is now typically performed by increasing the pressure within the completion string CS and hence also in the well below the packer PA.

A pressure test of the completion string CS is now performed by first bringing the well tool device 1 from its initial state to its closed state shown in fig. 4, 5 and 6. This is done by applying a pressure which will be recognized by the first sensor 51 and the digital signal processor 52 of the first actuating system 50.

It should be noted that the digital signal processor 52 in an alternative embodiment may be configured to first wait for the first signal, and then wait for a confirmation signal received within a predetermined period of time after the first signal. An actuating signal is only sent to the actuator 53 when both the first signal and the confirmation signal are received by the digital signal processor 52 from the first sensor 51. It should be noted that the above signals are here both pressure thresholds. Fig. 12 illustrates a flow chart for such a function. If the confirmation signal is not received within the predetermined period of time after the first signal, the tool becomes reset, i.e. both the first signal and the confirmation signal are needed in order to send a signal to the actuator 53.

It should further be noted that in yet an alternative embodiment, the digital signal processor 52 may be configured to receive a reset signal from the first sensor 51. In this case, the digital signal processor 52 is configured to wait for further information from the first sensor 51 before the digital signal processor 52 is sending the actuating signal to the actuator 53.

According to the above, it is possible to postpone or even abort the operation of bringing the well tool device 1 from the initial state to the closed state, even if the first signal has been received by the digital signal processor.

As described above, the well tool device 1 is brought from the initial state to the closed state by sending a signal to the actuator 53, causing the valve 54 to open and by allowing a fluid pressure to push the sleeve 20 upwardly. This is shown by comparing the distance D1 (indicated as a distance between the lower end of the sleeve 20 and a reference position of the housing 10) in fig. 1 with the corresponding distance D1 in fig. 3. As shown, the distance D1 in the initial state is shorter than the distance D1 in the closed state.

It is now referred to fig. 3. The fluid pressure in fluid line 23 will push a piston 29c upwardly, forcing a locking element 29a radially inwards, thereby unlocking the sleeve 20 from the housing 10. Should there be a malfunction in this arrangement 29, it is possible to force the sleeve to closed state by shearing of shear pin 29b.

The apertures 2a, the apertures 2c and the apertures 2d are now moved up relative to the recesses or bores 2b. In fig. 4, it is shown that the apertures 2a are moved to a position above sealing elements 82, the sealing elements 82 being located outside of the sleeve 20 and inside of the housing 10, while the apertures 2c and the apertures 2d still located below the sealing elements 82. Hence, no fluid is allowed to flow between the first location L1 in the bore 11 above the frangible disc 30 and the second location L2 in the bore 11 below the frangible disc 30.

As the well tool device 1 is in its closed state S2, it is now possible to perform the pressure test of the completion string CS.

When it is desired to start hydrocarbon production from the well W, the well tool device 1 is brought from the closed state S2 to the final state S3.

This is done by applying a number of pressure cycles (i.e. first a pressure increase, then a pressure decrease) so that the second actuating system 60 together with an increased fluid pressure above the frangible disc 30 is moving the rod 68 down to a position in which the sleeve compartment 69 is aligned with the locking device 42. The locking device 42 can now be forced radially outwards and into the compartment 69 by pushing the frangible disc 30 and the supporting sleeve 41 downwardly. The frangible disc 30 will now be brought into contact with the disintegration device 40 and shatter into small glass fragments, while the supporting sleeve 41 will be pushed down to a position radially inside of the locking device 42 as shown in fig. 10. As described above, the ratchet system 70 will prevent the sleeve 20 to move down.

The well tool device 1 is now fully open, as fluid may flow up via the completion string CS and through the bore 11 and bore 21 of the well tool device 1.

Alternative embodiments

It should be noted that the first actuating system 50 may comprise more than one sensor, wherein the digital signal processor 52 is configured to use signals from these more than one sensors in order to actuate the actuator 53.

It should be noted that the sensor 51 may be a communication sensor for measuring a communication signal such as an acoustic signal propagating through the well pipe and/or through the well fluid.

LIST OF REFERENCE NUMBERS

1 well tool device

2 fluid passage

2a apertures

2b bores

2c apertures

2d apertures

10 housing

11 bore

15 upper connection interface

16 lower connection interface

20 sleeve

21 bore

22 upper sleeve section

23 lower sleeve section

23b lower end of lower sleeve section

25 upper disc-supporting surface

26 piston surface

27 shear pin opening

28 inwardly protruding collar

29 locking arrangement for locking sleeve 20 to housing 10 in initial state 29a locking element

29b shear pin

29c piston

30 fluid flow preventing frangible disc

32 shear pin

33 opening for shear pin

35 o-rings

40 disintegration device

41 supporting sleeve

41a upper end of supporting sleeve

41b lower end of supporting sleeve

41c slits of supporting sleeve

42 radially expandable locking device

42a upper end of locking device

50 first actuating system

51 first sensor

52 digital signal processor

53 first actuator

54 first valve

54a rod

54b first valve bore

54c second valve bore

55 energy source

60 second actuating system

61 pressure cycle counting mechanism

63 bore

63a upper bores section

63b lower bore section

64 piston rod

64a sealing elements 65 sleeve

65a upper end of sleeve 68 actuating rod

68a shear pin opening 69 sleeve compartment 70 ratchet system

71 ratchet ring

82 sealing elements CA casing

CS completion string D1 distance

FF1 fluid flow

FL23 fluid line

FL3 fluid line

L1 first location

L2 second location LCA dashed line

PA packer

PS1 closed state

PS2 open state

S1 initial state

S2 closed state

S3 final state

Claims (13)

1. A well tool device (1) comprising:

- a housing (10) having a longitudinal through bore (11);

- a sleeve provided within the bore (11) and being longitudinally displaceable relative to the housing (10), wherein the sleeve (20) comprises a longitudinal through bore (21) aligned with the longitudinal through bore (11) of the housing (10);

- a fluid flow preventing frangible disc (30) provided in the longitudinal through bore (21) of the sleeve (20);

- a fluid passage (2) bypassing the frangible disc (30) when the well tool device (1) is in an initial state (S1), thereby allowing a fluid flow (FF1) between a first location (Ll) above the frangible disc (30) and a second location (L2) below the frangible disc (30);

- a first actuating system (50) for bringing the well tool device (1) to a closed state (S2), in which the fluid passage (2) is closed;

- a second actuating system (60) for bringing the well tool device (2) to a final state (S3), in which the frangible disc (30) has been disintegrated, thereby allowing a fluid flow (FF2) through the bore (21) of the sleeve (20);

characterized in that:

the first actuating system (50) comprises:

- a first sensor (51) for measuring a predetermined parameter;

- a valve (54) having a closed state (PS1) in which fluid flow from the bore (11) to a piston surface (26) of the sleeve (20) is prevented, and having an open state (PS2) in which fluid flow from the bore (11) to the piston surface (26) of the sleeve (20) is allowed;

- an actuator (53) for moving the valve (54) from the closed state (PS1) to the open state (PS2);

- a digital signal processor (52) configured to send an actuating signal to the actuator (53) based on information received from the sensor (51).

2. The well tool device (1) according to claim 1, wherein the information received from the first sensor (51) comprises:

- a first signal;

- a confirmation signal received a period of time after the first signal;

wherein the digital signal processor (52) is configured to send the actuating signal to the actuator (53) only when both the first signal and the confirmation signal are received from the first sensor (51).

3. The well tool device (1) according to claim 1 or 2, wherein the information received from the first sensor (51) comprises:

- a reset signal;

wherein the digital signal processor (52) is configured to wait for further information from the first sensor (51) before the digital signal processor (52) is sending the actuating signal to the actuator (53).

4. The well tool device (1) according to any one of claims 1 - 3, wherein the piston surface (26) of the sleeve (20) is ring-shaped.

5. The well tool device (1) according to any one of claims 1 - 4, wherein the sleeve (20) comprises an upper sleeve section (22) and a lower sleeve section (23) connected to each other, wherein the frangible disc (30) is provided in the longitudinal through bore (21) of the upper sleeve section (22) and wherein the piston surface (26) is provided in the lower sleeve section (23).

6. The well tool device (1) according to any one –the above claims, wherein the well tool device (1) comprises:

- a supporting sleeve (41) for supporting the fluid flow preventing frangible disc (30) within the sleeve (20);

- a radially expandable locking device (42) engaged with a lower end (41b) of the supporting sleeve (41);

wherein the second actuating system (60) is configured to prevent radial expansion of the locking device (42) in the initial state (S1) and the closed state (S2); and wherein the second actuating system (60) is configured to allow radial expansion of the locking device (42) in the final state (S3).

7. The well tool device (1) according to claim 6, wherein the second actuating system (60) comprises an actuating rod (68) provided radially outside of the supporting sleeve (41), wherein the actuating rod (68) comprises a sleeve compartment (69); wherein the actuating rod (68) is preventing radial expansion of the locking device (42) in the initial state (S1) and the closed state (S2); and wherein the sleeve compartment (69) is aligned radially outside of the locking device (42) in the final state (S3), thereby allowing radial expansion of the locking device (42) into the sleeve compartment (69).

8. The well tool device (1) according to claim 6 or 7, wherein an upper end (42a) of the radially expandable locking device (42) is wedgingly engaged with the lower end (41b) of the supporting sleeve (41).

9. The well tool device (1) according to any one of the above claims, wherein the well tool device (1) comprises a ratchet system (70) located between the housing (10) and the sleeve (20).

10. The well tool device (1) according to any one of the above claims, wherein the actuator (53) of the first actuating system (50) is an electrically powered actuator.

11. The well tool device (1) according to any one of the above claims, wherein the first sensor (51) is a pressure sensor for measuring a parameter representative of a fluid pressure in the bore (11).

12. The well tool device (1) according to any one of the above claims, wherein the first sensor (51) is a communication sensor for measuring a communication signal.

13. The well tool device (1) according to any one of the above claims, wherein the first actuating system (50) comprises a rechargeable battery or a super capacitor for supplying electric power to the digital signal processor, to the first sensor and to the actuator.