Patent Application
20210040816
The present invention relates to a well tool device for opening and closing a fluid bore in a well. In particular, the present invention relates to a well tool device having a temporary open state, a temporary closed state and a permanent open state.
In different types of well operations, it is a need for well tool devices having a valve function, i.e. the well tool device needs to be reconfigured between an open state and a closed state.
Typically, the closed state is used for pressure testing purposes to ensure that the well integrity is intact. The open state is typically during production, to allow hydrocarbon fluids to be transported from the well to the topside of the well. During the installation of the completion string or tubing, it is preferred that the tubing is open, so well fluid can flow into the tubing during the lowering of the tubing into the well.
When the tubing is landed in the well head and the pressure control equipment is installed above the tubing/well head, it is desired to replace the heavy well fluid with a lighter completion fluid before the production packer is installed. In such a case, completion fluid is pumped down into the tubing and return fluid is received through the annulus. Again, during such operations, the tubing must be open.
In some operations, the open state is also used for pressure testing purposes.
One such known well tool device is the Inter Remote Shutter Valve (IRSV), marketed by Interwell. The IRSV is initially closed and may be connected to the lower part of the completion string. When the completion string is installed, the completion string above the IRSV may be pressure tested to ensure that the production tubing is properly installed. After testing, the IRSV is opened by crushing a glass disc within the IRSV. When open, it is possible to test the production packer outside of the completion string before production starts.
The IRSV may also be used in other well tools, such as plugs (for example the Interwell ME plug, the Interwell HPHT plug etc).
The IRSV is described in the “Product Sheet: Inter Remote Shatter Valve (IRSV)” Rev. 4.0 dated 27 Sep. 2016.
U.S. Pat. No. 9,194,205, in the name of TCO AS, describes a device for a system for conducting tests of a well, pipe or the like. In the device, a plug of a removable material is inserted in a pipe through a well to carry out said tests. The device is characterized in that the wall parts of the pipe comprise channel borings that set up fluid connections between the well space and the well space above and below, respectively, the plug, and that it comprises a closing body that can close the fluid connection permanently. The channel boring is preferably defined by an axial hollow space/chamber in which a piston is arranged, said piston can be readjusted by an axial movement from a first position where there is fluid connection through the channel and a second position where the connection is permanently closed and cannot be reopened.
US 2011/0000663, in the name of TCO AS, describes a device for removal of a plug which is used in a well, a pipe, or the like for carrying out tests, and it is characterized by an element which, with an applied forced, is arranged to penetrate into the plug material so that this is crushed, said element is arranged to be supplied said force from an above lying element. The element is preferably a ring the lower end of which is arranged to be forced in a radial direction into the plug element at axial driving of a hydraulic pressure piston. Furthermore, the element is integrated into the plug.
It is also known to use ball valves in the lower end of the completion string, for testing of the production tubing and the production packer. However, if the ball valve fails, it is needed to mill out the ball valve or to remove the completion string. None of these operations are desired. Moreover, such valves often have a increased outer diameter or a reduced inner diameter. An increased outer diameter will make it difficult to insert the completion string, while a reduced inner diameter will reduce the flow rate capacity of the completion.
WO 2012066282 A2 discloses a valve assembly which is configured to be coupled to a tubing string. It comprises a housing defining a housing flow path for communicating with the tubing string, and a barrier member located in the housing and configurable between a normally-closed position in which the barrier member restricts access through the housing flow path, and an open position in which access is permitted through the housing flow path. The valve assembly also comprises a bypass arrangement reconfigurable between an open state in which the bypass arrangement defines a bypass flow path that communicates with the housing flow path on opposite sides of the barrier member to permit fluid to bypass the barrier member and thereby fill the tubing string. One object of the present invention is to add functionality to the IRSV above. One such added functionality is to provide the IRSV with an initial open state. Hence, it is achieved that it is not necessary to fill fluid into the completion when adding new pipe sections to the completion string.
One object of the invention is to achieve a well tool device where the inner diameter is not substantially reduced or where the outer diameter of the device is not substantially increased. Accordingly, the object is that the outer diameter of the well tool device is equal to or substantially equal to the outer diameter of the completion string the device is connected to, and that the inner diameter of the well tool device is equal to or substantially equal to the inner diameter of the completion string the device is connected to. In this case, the outer diameter of the well tool device should be equal to or less than the outer diameter of for example the safety valve, which has an outer diameter typically somewhat larger than the outer diameter of the tubing segments.
To save time and resources, the completion string is run into the drilling fluid. After the installation of the completion string, the drilling fluid is circulated out and replaced by a completion fluid before the production packer is set. The object of the invention is to provide a circulation valve with an initial open state, an intermediate closed state and a final open state.
In some wells with a low reservoir pressure, a light weight fluid is often circulated into the completion string before the well is opened for production, as this light weight fluid will contribute to production flowing out from the reservoir. Also in such a case it is preferred to have an initial open completion string.
Another object of the invention is that it should be connectable to the upper part of the completion string, adjacent to, but below, the tubing hanger. Here, the well tool device serves the function of a second, upper barrier of the well, assuming that a first, lower barrier also is present in the well. The first barrier can be a prior art barrier, such as a plug set in the completion string, or it may be another well tool device according to the present invention.
In the present description, the term “upper” and “lower” are used. Here, the part referred to as “upper” is relatively closer to the top of the well than the part referred to as “lower”, i.e. the part referred to as “lower” is closer to the bottom of the well, irrespective of the well being a horizontal well, a vertical well or an inclining well.
The present invention relates to a well tool device comprising a housing having an axial through bore, where the well tool device is comprising:
where the axial fluid passage is closed when the well tool device is in a subsequent state;
where:
Hence, in the initial or first state, the fluid flow between the first and second locations are allowed only via the axial fluid passage. In the intermediate or second state, fluid flow between the first and second locations are prevented. In the final or third state, the frangible disc is broken, and fluid flow is allowed through the bores. In the final state, the axial fluid passage is still closed.
The disc supporting device is supporting the frangible disc in relation to the sleeve section until the disc supporting device released from the sleeve section. Preferably, the disc supporting device is connected to the sleeve section in the initial state and in the intermediate state, while the disc supporting device is released from the sleeve section in the final state.
In one aspect, the sleeve section is moved axially upwards in relation to the housing from the initial state to the intermediate state. Alternatively, the sleeve section is moved axially downwards in relation to the housing from the initial state to the intermediate state.
In one aspect, the well tool device comprises a sleeve locking system for preventing relative axial displacement between the housing and the sleeve section when the well tool device is in the intermediate state.
Hence, the well tool device cannot return from its intermediate state to its initial state again.
In one aspect, the sleeve locking system comprises:
The pre-tensioned locking device can be a pre-tensioned locking ring, a spring-biased locking pin, a ratchet ring, etc.
The pre-tensioned locking device can be a pre-compressed locking ring or a so-called snap ring, which in the initial state is provided in the second recess. When the recesses are aligned with each other in the intermediate state, the locking ring expands partially into the first recess and hence prevents relative axial movement between the housing and the sleeve section. Alternatively, the pre-tensioned locking device is a pre-expanded locking ring, which in the initial state is provided in the first recess. When the recesses are aligned with each other in the intermediate state, the locking ring retracts partially into the second recess and hence prevents relative axial movement between the housing and the sleeve section,
The well tool device may comprise an upper connection interface and/or a lower connection interface for connection to a completion pipe, production tubing etc. In the initial state, fluids above and/or below the well tool device can be exchanged via the axial fluid passage. In the intermediate state, pressure testing can be performed. In the third state, the well tool device allows full production through the bores.
In one aspect, the well tool device is comprising a first actuating system for moving the sleeve section axially in relation to the housing from the initial state to the intermediate state.
In one embodiment, the axially displaceable sleeve section is releasably connected to the housing in the first state. This connection could be provided by a shear pin etc., which are sheared off at a predetermined load.
Alternatively, it is possible to move the sleeve section axially by means of controlling the fluid rate through the axial fluid passage. If an upwardly directed fluid flow rate is increased to a certain level determined by the cross-sectional area of the passage, an increase in the pressure below the frangible disc will occur. This increased pressure could be used to move the sleeve section axially in relation to the housing from the initial state to the intermediate state.
In one aspect, the first actuating system comprises:
where a second side of the piston is connected to the sleeve section;
where the valve is preventing fluid flow between the bore and the first side of the piston in the initial state;
where the valve is allowing fluid flow between the bore and the first side of the piston in the intermediate state, thereby causing linear movement of the piston within the piston cylinder and hence axial movement of the sleeve section.
The second side of the piston can be connected to the sleeve section by means of a piston rod provided at least partially within the piston cylinder. Alternatively, a further piston can be provided in the fluid cylinder or in fluid communication with the fluid cylinder, where the further piston is connected to the sleeve section. Here, the linear movement of the piston will cause the linear movement of the further piston and hence the sleeve section.
The fluid actuating system is preferably located in compartments provided in the housing, i.e. radially between the bore and the outer surface of the housing.
The valve control system may comprise an electric actuator for controlling the valve. The electric actuator can control the valve to open at a predetermined time by using a timer, at a signal detected by a sensor, for example a signal in the form of hydraulic pulses detected by a pressure sensor, electromagnetic signals detected by an antenna etc.
In the initial state, the pressure within the fluid cylinder is lower or substantially lower than the expected well pressure in the well. Typically, the pressure within the fluid cylinder will have a so-called atmospheric pressure in the initial state. This so-called atmospheric pressure is achieved by ensuring that the well tool device is in the initial state, and then open and close a pressure-sealed entry into the fluid cylinder topside before the well operation starts, or during manufacturing. Hence, the so-called atmospheric pressure typically corresponds to the air pressure surrounding the well tool device at the time when the fluid cylinder becomes closed. It should be noted that the atmospheric pressure typically varies dependent on the height above sea level. When the well tool device is lowered into an oil and/or gas well, the fluid pressure in the well will be substantially higher than the pressure in the fluid cylinder, which will cause the piston to move linearly inside the piston cylinder when the valve 52 is opened. Hence, variations in the so-called atmospheric pressure is neglectable with respect to the fluid pressure in the well.
In one aspect, the housing comprises a first stop profile within the bore and the sleeve section comprises a second stop profile on its outer surface, where the second stop profile is engaged with the first stop profile in the intermediate state.
In one aspect, the well tool device is comprising a second actuating system for releasing the releasable connection device, thereby causing a release of the disc supporting device from the sleeve section.
In one aspect, the disintegration device is fixed to the sleeve section within the bore of the sleeve section on the same side of the frangible disc as the disc supporting device. When the releasable connection device has been released by the second actuating system, relative movement between the frangible disc and the sleeve section is possible in one direction, as such movement is no longer prevented by the disc supporting device. Hence, the well tool device is configured to be brought from the intermediate or second state to the final state by means of two steps:
First, the releasable connection device is actuated to release the disc supporting device.
Second, the frangible disc is configured to be pushed axially relative to the sleeve section towards the disintegration device.
The second step can be performed by increasing the fluid pressure on one side of the frangible disc. Preferably, the disintegration device and the disc supporting device are located below the frangible disc. Hence, the frangible disc is pushed downwardly towards the disintegration device by increasing the fluid pressure above the frangible disc.
In one aspect, the second actuating system comprises:
where a second side of the piston is connected to the releasable connection device;
where the valve is preventing fluid flow between the bore and the first side of the piston in the initial state and intermediate state;
where the valve is allowing fluid flow between the bore and the first side of the piston to initiate the final state, thereby causing linear movement of the piston within the piston cylinder and hence release of the releasable connection device.
In one aspect, the second actuating system and the releasable connection device are provided on opposite sides of the frangible disc.
In one aspect, a piston rod is in one end connected to the second side of the piston, and is in a second end provided in contact with an actuating rod of the releasable connection device.
In one aspect, the actuating rod is provided in an axial bore provided in the sleeve section.
The second actuating system is similar to, or identical to, the first actuating system. If both actuating systems are actuated by a number of pressure cycles, the first actuating system must be designed to actuate the valve after fewer pressure cycles than the second actuating system, to ensure correct operation of the tool.
Embodiments of the invention will now be described in detail, with reference to the enclosed drawings, where:
It is now referred to
A well tool device I is generally referred to with reference number 1. In
The well tool device 1 comprises an outer housing 10 with an axial through bore 11. The well tool device 1 comprises an upper connection interface 13a and a lower connection interface 13b for connection to a completion pipe, production tubing etc. These connection interfaces 13a, 13b may be threaded connection interfaces, or other types of connection interfaces. The axial through bore 11 has a diameter D11 which is typically equal to the inner diameter of the completion pipe, production tubing etc.
A longitudinal central axis II of the well tool device 1 is indicated in
One section 11a of the axial through bore 11 has a larger diameter D11a than the diameter D11. This section 11a forms a compartment for a sleeve section 20. The sleeve section 20 is axially displaceable relative to the housing 10. The sleeve section 20 comprises an axial through bore 21 aligned with the axial through bore 11 of the housing 10. The axial displacement of the sleeve section 20 is limited by the length of the section 11a of the bore 11. In
In addition, the axial displacement of the sleeve section 20 is limited by a sleeve locking system 4, which will be described more in detail below.
The axial through bore 21 has an inner diameter D21 which is equal to the diameter D11 of the bore 11. Hence, the sleeve section 20 itself does not limit fluid flow through the well tool device 1 substantially.
The well tool device 1 further comprises a fluid flow preventing frangible disc 30 provided in the bore 21 in sealing engagement with the sleeve section 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. These chamfered upper and lower edges are supported in a so-called seat in the sleeve section 20. In
As shown in
The axially displaceable sleeve section 20 can be releasably connected to the housing 10 in the first state S1. This connection could be provided by a shear pin (not shown), which are sheared off at a predetermined load.
Devices 40, 41 and 42
In the present embodiment, the well tool device 1 comprises a disc supporting device 41 for supporting the frangible disc 30 in relation to the sleeve section 20. The upper chamfered edge of the disc 30 and the side surface of the disc 30 are supported by the sleeve section 20, while the lower chamfered edge of the disc 30 is supported by the upper supporting surface 41a of the disc supporting device 41. Hence, when the disc supporting device 41 is removed, nothing prevents the disc 30 from being pushed axially downwards in relation to the sleeve section 20. When comparing
The disc supporting device 41 is releasably connected inside the sleeve section 20 by means of a releasable connection device 42. The releasable connection device 42 is a cycle actuated mechanism described in prior art EP297892613.
The well tool device 1 further comprises a disintegration device 40 for disintegration of the frangible disc 30. The disintegration device 40 is fixed to the sleeve section 20, within the bore 21 and is located at a short distance below the frangible disc 30. The disintegration device 40 is provided at a distance below frangible disc 30 which is shorter than the distance D41. Hence, when the disc supporting device 41 is released from the sleeve section 20, the disc 30 may be pushed downwardly into contact with the disintegration device 40, thereby causing disintegration of the disc 30.
Axial Fluid Passage 2
In
In
Hence, in the initial state S1 of
First Actuating System 50 and Second Actuating System
The well tool device 1 comprises a first actuating system 50 and a second actuating system 60, shown in
The first actuating system 50 comprises a valve control system 51 for controlling a valve 52. The first actuating system 50 further comprises a piston 54 axially displaceable within a piston cylinder 55. A first, lower, side of the piston 54 is faced towards the valve 52, while a second, upper, side of the piston 54 is faced towards the sleeve section 20.
A first fluid line 53a is provided between the bore 11 and the valve 52. A second fluid line 53b is provided between the valve 52 and the lower part of the piston 54. Hence, the first side of the piston 54 is provided in fluid communication with the valve 52. The second side of the piston 54 is connected to the sleeve section 20 by means of a rod 56.
The valve 54 can be controlled to be in two different positions, a first position in which the valve 54 is preventing fluid flow between the first and second fluid lines 53a, 53b and a second position in which the valve 54 is allowing fluid flow between the first and second fluid lines 53a, 53b.
The second actuating system 60 comprises a valve control system 61 for controlling a valve 62. The second actuating system 60 further comprises a piston 64 axially displaceable within a piston cylinder 65. A first, upper, side of the piston 64 is faced towards the valve 62, while a second, lower, side of the piston 64 is faced towards the sleeve section 20.
A first fluid line 63a is provided between the bore 11 and the valve 62. A second fluid line 63b is provided between the valve 62 and the lower part of the piston 64. Hence, the first side of the piston 64 is provided in fluid communication with the valve 62. The second side of the piston 64 is connected to a piston rod 66. The piston rod 66 is used to release the connection device 42. In
The valve 64 can be controlled to be in two different positions, a first position in which the valve 64 is preventing fluid flow between the first and second fluid lines 63a, 63b and a second position in which the valve 64 is allowing fluid flow between the first and second fluid lines 63a, 63b.
The valve control system 51 may comprise an electric actuator for controlling the valve 52. The electric actuator can control the valve 52 to open at a predetermined time by using a timer, at a signal detected by a sensor, for example a signal in the form of hydraulic pulses detected by a pressure sensor, electromagnetic signals detected by an antenna etc. In the present embodiment, pressure pulses are detected by the valve control system 51 via openings 59 to the bore 11. In similar way, the valve control system 61 of the second actuating system 60 detects pressure pulses via openings 69 to the bore 11.
It should be noted that the number of pulses needed for the valve control system 51 to actuate the valve 52 is different than the number of pulses needed to actuate the valve 62, as the first actuating system 50 should be actuated before the second actuating system 60.
It should also be noted that the pressure within the fluid cylinders 55, 65 on the second side of the pistons 54, 64, i.e. on the upper side of piston 54 and on the lower side of piston 64, is lower or substantially lower than the expected well pressure in the well. Such a lower or substantially lower pressure can be a so-called atmospheric pressure as discussed in the introduction above.
The Sleeve Locking System 4
The sleeve locking system 4 mentioned above will now be described with reference to
In
Operation of the Well Tool Device
The operation of the well tool device 1 will now be described.
In the initial state S1 of
When desired, the well tool device 1 can be actuated to its intermediate state S2. In the present embodiment, this is done by changing the pressure in bore 11 in a predetermined pattern, such as by cycling the pressure a predetermined number of times. This will actuate the valve control system 51 of the first actuating system 50, causing the valve 52 to rotate and allowing the fluid in the bore 11 to enter the piston cylinder 55 on the first side of the piston 54, which again will cause the piston 54 to push the sleeve section 20 upwardly by means of the piston rod 56.
The sleeve section 20 will move upwardly until the second stop profile 26 contacts or engages the first stop profile 16, as indicated by the distance D36. When the sleeve section 20 is in this position, the first and second recesses 14, 24 are axially aligned with each other, and the sleeve locking system 4 provides that the sleeve section 20 is axially locked to the housing 10. The well tool device 1 is now in the intermediate state. It should be noted that it is not possible to move the sleeve section 20 downwardly again, as the sleeve locking system 4 will prevent such movement.
As shown in
In this intermediate state, the actuating rod 43 is moved together with the sleeve section 20 to a position where the actuating rod 43 is in contact with the piston rod 66 of the second actuating system 60.
In this intermediate state, the completion string or tubing string above the well tool device can be pressure tested.
When desired, the well tool device 1 can be actuated to its final state S3. In the present embodiment, this is done in two substeps. The first substep is to change the pressure in bore 11 (above the disc 30) in a predetermined pattern, such as by cycling the pressure a predetermined number of times. This will actuate the valve control system 61 of the second actuating system 60, causing the valve 62 to rotate and allowing the fluid in the bore 11 to enter the piston cylinder 65 on the first side of the piston 64, which again will cause the piston 64 to push the actuating rod 43 downwardly by means of the piston rod 66
This will again release the releasable connection device 42, causing that the disc supporting device 41 becomes released from the sleeve section 20.
The second substep is to increase the pressure above the disc 30, in order to push the disc 30 downwardly towards the disintegration device 40. As the disc supporting device 41 is released, the disc supporting device 41 will be pushed downwardly with the disc 30.
As the disc 30 comes into contact with the disintegration device 40, the disc will disintegrate as shown in
In
In the description above, the sleeve section 20 is moved upwardly from the first state S1 to the intermediate and closed state S2. This is an advantage, as in this closed state, the first stop profile 16 of the housing in contact with the second stop profile 26 of the sleeve, where it is relatively easy to dimension these profiles to withstand the expected well pressure. If the sleeve section 20 was to move downwardly from the initial to the closed state, the locking mechanism for locking the sleeve section in the closed state must be dimensioned and tested to handle the expected well pressure—which may be difficult to obtain.
Another advantage is that if there is a failure in the first actuating system 50, it will still be possible to close the well tool device 1. This can be performed by increasing the pressure in the entire well, i.e. increasing the pressure above and below the disc 30 (typically increasing the pressure towards the production packer). Then, the pressure can be bled off from the top side, causing the pressure to be higher below the disc 30 than above the disc 30. This pressure difference over the axial fluid passage 2 will then be so large that the sleeve section 20 will be pushed upwardly by means of the differential pressure over the axial fluid passage 2.
It should be noted that in case the well tool device 1 is intended to be provided in the bottom end of a completion pipe, the lower connection interface 13b may be used for connection to a mule shoe or a wireline re-entry guide.
The enlarged section 11a of the bore 11 is not essential for the present invention. The axial displacement of the sleeve section 20 can be limited by other types of stops causing an engagement between the sleeve section 20 and the housing 10. However, without the enlarged section 11a, it is assumed that the diameter D21 of the sleeve section 20 would have to be substantially smaller than the diameter D11 of the bore 11.
The pistons 54, 64 are described above to be mechanically connected to the sleeve section 20 and the actuating rod 43 respectively. It should be noted that a further piston can be provided in the fluid cylinder or in fluid communication with the fluid cylinder, where the further piston is connected to the sleeve section 20. In such a case, the pistons 54, 64 can be considered to be hydraulically connected to the sleeve section 20 and the actuating rod 43 respectively.
| Number | Date | Country | Kind |
|---|---|---|---|
| 20180579 | Apr 2018 | NO | national |
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/EP2019/058665 | 4/5/2019 | WO | 00 |
