Patent Application
20240418059
In a first aspect, the present invention relates to a downhole tool for perforating a downhole tubular installed in a borehole in the Earth. In another aspect, the invention relates to method for perforating a downhole tubular arranged within a borehole in the Earth.
In the operation of oil/gas wells or other cased boreholes in the Earth, it can often become necessary or beneficial to punch one or more holes through, or perforate, the casing which lines the well bore, or a production tubing within the casing. Tools have been proposed to perforate the casing, and to subsequently inject sealing material into the space between the Earth formation around the bore hole and the casing through the perforation or perforations formed therein. U.S. Pat. No. 2,381,929, for example, discloses a system in which punches are forced outwardly, and radially against the casing, by a pressurized fluid. The application of pressure is continued until the punches are forced through the casing.
U.S. Pat. No. 6,155,150 discloses a hydraulic tubing punch, wherein the punch is mounted on a sliding block, which can slide in radially outward direction from the tool to bring the punch in engagement with the casing wall. A wedge-shaped plunger is fixedly attached to a hydraulically driven piston. Both piston and the plunger can move in longitudinal direction through the tool. Instead of directly applying the pressurized fluid to the back of the sliding block, the wedge-shaped plunger pushes or pulls on the sliding block depending on whether it moves up or down in the longidinal direction in the tool. Longitudinal movement of the sliding block along the tool axis is prevented by sliding surfaces which only allow sliding movement of the sliding block in transverse direction relative to the tool axis.
In accordance with the invention there is provided downhole tool for perforating of a tubular installed in a borehole in the Earth, comprising:
In a further aspect, there is provided a method of perforating a wall of a downhole tubular arranged within a borehole in the Earth, said method comprising:
In a preferred embodiment, there is provided downhole tool for perforating of a tubular installed in a borehole in the Earth, comprising:
Activating the press device in the preferred embodiment leads to forcing the first sting in the first radially outward direction from the tool housing through a wall of the downhole tubular and forcing the second sting in the second radially outward direction from the tool housing through the wall of the downhole tubular, whereby perforating said wall of said downhole tubular in multiple locations.
These and other features, embodiments and advantages of the method, and of suitable expansion devices, are described in the accompanying claims, abstract and the following detailed description of non-limiting embodiments depicted in the accompanying drawings, in which description reference numerals are used which refer to corresponding reference numerals that are depicted in the drawings.
The drawing figures depict one or more implementations in accordance with the present teachings, by way of example only, not by way of limitation. In the figures, like reference numerals refer to the same or similar elements.
Similar reference numerals in different figures denote the same or similar objects. Objects and other features depicted in the figures and/or described in this specification, abstract and/or claims may be combined in different ways by a person skilled in the art. Unless otherwise indicated, the term longitudinal is used herein to express the direction parallel to the central longitudinal tool axis, and the term transverse is used to express any direction normal (perpendicular) to the central longitudinal tool axis.
Proposed is a downhole tool, with an elongate tool housing that extends around a central longitudinal tool axis, houses a sting, a press device, and a bending arm. The downhole tool may be run longitudinally in a bore of a downhole tubular arranged within a borehole in the Earth. The downhole tool can be used to perforate a wall of the downhole tubular.
The sting is movable in a radially outward direction, and capable of perforating the wall of the wellbore tubular. The press device acts on the sting, to force the sting in the radially outward direction upon relative movement of the press device, in longitudinal direction, with respect to the sting whereby the sting may extend outside the tool housing. The sting is mounted on a distal end of the bending arm. At its proximal end, the bending arm is secured longitudinally stationary relative to the tool housing. However, the sting and the distal end of the bending arm are movable in unison in a longitudinal-radial plane from the central longitudinal tool axis. Any axial force transmitted from the surface of the longitudinally moving wedge to the distal end and the sting is thus balanced by tension in the bending arm. The axial force does not need to be countered by any sliding surface.
In use, the tool may be lowered into a borehole through the bore of the downhole tubular, to a selected depth. At the selected depth, the tool may be kept stationary, while activating the press device acting on the sting. Thus, the sting is forced in the radially outward direction from the tool housing, into contact with the wall of the downhole tubular and subsequently perforating the wall of the downhole tubular. At least part of the sting may be subsequently retracted, and the downhole tool may then be retrieved from the downhole tubular.
Typical downhole tubulars include wellbore tubulars, such as, for example, casing, liner, or production tubing.
The method and downhole tool described herein can be used to install a functional plug in a wall of a downhole tubular (e.g. casing or production tubing). Such functional plug may for example include an orifice or nozzle, and/or a non-return valve, to be able to pass a fluid through the wall from the inside of the tubular to the surrounding and/or in the other direction. Applications for such functional plug include (gas) lift operations and injecting of an treatment fluid such as a sealant.
The method and downhole tool described herein may be used for subsequently injecting a treatment fluid in an annulus surrounding the downhole tubular.
The tool can be of modular design, having several sections (or: modules) which can be assembled to form a tool string using connectors. Shown in
The expander section 30 furthermore comprises a sting 7. The sting 7 is movable in a radially outward direction 18, away from the central longitudinal tool axis 2, from a retracted position (as shown) to an extended position (not shown), whereby the sting 7 partly extends to outside the elongate tool housing 3. A window 13 may suitably be provided in the elongate tool housing 13 to allow passage of the sting 7. A press device, comprising a wedge (here, embodied in first wedge segment 33), acts on the sting 7 to force the sting 7 in the radially outward direction 18 from the tool housing 3. The movement of the sting 7 is driven by movement of the first wedge segment 33 in longitudinal direction with respect to elongate housing 3 and the sting 7. The radially outward direction 18 is in essence transverse to the longitudinal axis 2. The sting 7 is rigidly mounted on a distal end of a bending arm 35. At a proximal end thereof, the bending arm 35 is fixed longitudinally stationary relative to the elongate tool housing 3. In the embodiment as shown, the bending arm 35 is monolithic to the base 37. This can be made by machining.
The sting 7 and the distal end of the bending arm 35 are movable in unison in a longitudinal-radial plane from the central longitudinal tool axis 2. As a result, the sting 7 can move in said radial outward direction 18, essentially without experiencing any friction in the transverse direction. The bending arm 35 effectively acts as a spring blade, which is elastically loaded as the press device forces the sting 7 in the radially outward direction 18.
The expander section 30 may comprise multiple sting-arm combinations, each with their own press device. For example, in the embodiment of
Each press device includes its own wedge segment. Two such wedge segments are shown in
An inlay 36, consisting of sheet or platelet of a wear resistant contact material, may be provided in a recess in one of the wedge segments at the abutment plane 38. The inlay 36 may be best visible in the detailed cross sectional view of
The bending arms 35,35′ are flexible, such that upon movement of the respective wedge segments 33,33′ the bending arms 35,35′ flex or pivot outward, such that each sting 7,7′ is movable in unison with the distal ends of the bending arms in a longitudinal-radial plane from the longitudinal tool axis 2. The bending arms 35,35′ may flex fully elastically, or the flexing may be assisted by a pivot. Elastic bending has the advantage that the bending arms will automatically retract when the wedge segments 33,33′ are returned to their starting positions.
With the tool ran concentrically inside a downhole tubular installed in a borehole in the Earth, the stings will first engage with the inside of the wall of the tubular and after continued forcing the wedge segments the stings will ultimately, one after the other, perforate the wall of the tubular and protrude through the tubular into the annular space surrounding the tubular.
As can also be seen in
The wedge segments 33,33′ each engage with a hydraulic piston, which may be housed within the piston section 50. The hydraulic piston can be actuated by a hydraulic fluid that is displaced by a pump, to impart the relative movement of the wedge segments, in longitudinal direction, with respect to each of the stings 7,7′. Advantageously, each of the wedge segments 33,33′ engages with a plurality of hydraulic pistons.
Focusing now on
When two wedge segments 33 and 33′ have to be actuated, the above described hydraulic pistons 54a,54b together act as a first piston engaging with the first wedge segment 33, while similar hydraulic pistons together form a second piston engaging with the second wedge segment 33′. The hydraulic fluid, which is displaced by the hydraulic pump, can be distributed over all available piston bores. Referring now to
Also visible in
Referring, again, to
The injection tube 43 and fluid channel 47 are optional. However, in case injection tube 43 and fluid channel 47 are provided, a canister may be provided for storing the treatment fluid. The canister may be in selective fluid communication with a hydraulic pump, via a selectable valve which selectively isolates the canister from the pump or opens the canister to the pump. The hydraulic fluid may push the treatment fluid from the canister to one or both of the stings 7,7′, by displacing and replacing the treatment fluid inside the canister. A piston separator may be provided within the canister to separate the treatment fluid from the hydraulic fluid and to avoid contamination of the treatment fluid by the hydraulic fluid. The pump may be the same pump as the one utilized for actuating the press device, as the pump's duty for actuating the press device will not be necessary when the sting is in its extended position.
The first canister base 67 is provided with a hydraulic fluid connector 72 for supply of pressurized hydraulic fluid from the pump, and with a treatment fluid first connector 71 and a treatment fluid second connector 71′. The latter two may respectively be fluidly connected to sockets 31 and 31′ via treatment fluid connection lines (not shown). These treatment fluid connection lines are suitably flexible, to allow for the transition of the stings 7,7′ from their respective retracted position to extended position.
The treatment fluid first connector 71 communicates via a bore 73 through the first canister base 67 to the treatment fluid first reservoir 61. Inside the first central hydraulic fluid tube 65, an inner tube 75 extends from the treatment fluid second connector 71′ to connector 76 provided in the second canister base 67′. This communicates via a bore 77 through the second canister base 67′ to the treatment fluid second reservoir 61′. The hydraulic fluid connector 72 communicates via bore 74 and the first central hydraulic fluid tube 65 to a hydraulic fluid first annulus 82 in the first canister head 66 which extends between the first central hydraulic fluid tube 65 and the first canister head 66. From there, the hydraulic fluid can pass via the hydraulic fluid first annulus 82 into the hydraulic fluid first reservoir 62. The bore 74 is suitably sealed off, for example by means of O-ring 85, from the treatment fluid first reservoir 61 to avoid contamination of the treatment fluid inside the treatment fluid first reservoir 61 with the hydraulic fluid passing through bore 74.
The hydraulic fluid first reservoir 62 is fluidly connected to the hydraulic fluid second reservoir 62′ as follows. Via bore 78 though the first canister head 66 and liner 79 a hydraulic fluid connection is established to bore 84 in the second canister base 67′ and the second central hydraulic fluid tube 65′. Bore 84 is suitably sealed off from the treatment fluid second reservoir 61′, for example with O-ring 87 or other type of seal. From the second central hydraulic fluid tube 65′, the hydraulic fluid can enter into the hydraulic fluid second reservoir 62′ via annulus 82′ extending between the second central hydraulic fluid tube 65′ and the second canister head 66′.
Both the first canister 60 and the second canister 60′ are in selective fluid communication with the hydraulic fluid pump. During use, a selectable valve selectively isolates both the first canister 60 and second canister 60′ from the pump or opens both the first canister 60 and the second canister 60′ to the pump. When selectively opened to the pump, both the hydraulic fluid first reservoir 62 and the hydraulic fluid second reservoir 62′ fill with the hydraulic fluid when the canister is opened to the pump. The first canister 60 is in fluid communication with the first sting 7 with a second treatment fluid connection line (not shown) extending between the treatment fluid first connector 71 and socket 31. The second canister 60′ is in fluid communication with the second sting 7′ with a second treatment fluid connection line (not shown) extending between the treatment fluid second connector 71′ and socket 31′. The second treatment fluid connection line bypasses the first treatment fluid connection line and the first sting 7.
An advantage of providing a dedicated canister (or dedicated set of canisters) for each of the stings, it is achieved that the treatment fluid is injected through each sting in predetermined quantities, preferably in mutually equal quantities. If multiple stings would be fed by a shared canister, imbalances may cause the treatment fluid to pass preferentially through one of the stings, thereby filling the annulus surrounding the downhole tubular less homogenously. Imbalances may be caused, for example, by one of the stings experiencing a higher flow resistance than the other. By feeding each sting from a different canister, it is believed a more controllable and homogenous distribution of the treatment fluid around the tubular can be feasible.
The treatment fluid may for example be a two-component resin, the components of which being mixed during the injection of the treatment fluid. In this case, multiple canisters may be provided for each of the stings. Alternatively, a resin may be employed which hardens in contact with a wellbore fluid, such as water. Examples are described in International publication No. WO2021/170588A1. In such cases, a single canister per string could suffice.
The valves may be controlled electrically. To activate the press device(s), three-way valve 92 is selected to open pump 91 to connector 95 and block the connection to the pressure-compensated reservoir 90. At the same time, three-way valve 93 is in opposite position, blocking the connection with the pump 91 but opening the connection to the pressure-compensated reservoir 90. This allows circulation of the hydraulic fluid from the pressure-compensated reservoir 90 to the piston bores 56a,56b and from the piston rod annuli 58a,58b back into the pressure-compensated reservoir 90. When the piston rods 53a, 53b are in their end positions, the selectable valve 94 may be opened to open the canister(s) to the pressure of the pump 91 and thereby start the injection of the treatment fluid. The stings may be restored to their retracted positions by reversing the positions of both three-way valves 92 and 93 whereby allowing circulation of the hydraulic fluid from the pressure-compensated reservoir 90 to the piston rod annuli 58a,58b and from the piston bores 56a,56b back into the pressure-compensated reservoir 90.
Many variations are possible for the hydraulic circuitry. For example, three-way valves 92 and 93 may be mechanically interlinked so that they mechanically switch in unison. Other variants may include use of a bi-directional pump.
The downhole tool may be used as follows. First, the downhole tool as described above is lowered into the borehole, through the downhole tubular, to a selected depth. Then, at the selected depth, the press device acting on the sting is activated. Thereby the sting is forced in the radially outward direction from the tool housing, through a wall of the downhole tubular, whereby perforating said wall of said downhole tubular. Subsequently, the downhole tool may be retrieved from the downhole tubular by pulling the downhole tool in upward direction through to borehole towards surface. In certain embodiments, prior to retrieving the tool, the treatment fluid may be injected from the downhole tool through the sting into an annulus surrounding the downhole tubular.
At least part of the sting may be retracted prior to retrieving. This can be done by reversing the relative movement of the press device, in longitudinal direction, with respect to the sting. A distal end of the sting, for instance the end cap 41, may stay behind in the wall of the downhole tubular after retrieving the downhole tool as a functional plug.
The present disclosure is not limited to the embodiments as described above and the appended claims. Many modifications are conceivable and features of respective embodiments may be combined. The particular embodiments disclosed above are illustrative only, as the present invention may be modified, combined and/or practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined and/or modified and all such variations are considered within the scope of the present invention as defined in the accompanying claims.
| Number | Date | Country | Kind |
|---|---|---|---|
| 21207921.4 | Nov 2021 | EP | regional |
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/EP2022/081439 | 11/10/2022 | WO |
