EP3530873B1 - Device adapted to be run on a tubing string into a wellbore - Google Patents
Device adapted to be run on a tubing string into a wellbore Download PDFInfo
- Publication number
- EP3530873B1 EP3530873B1 EP18157788.3A EP18157788A EP3530873B1 EP 3530873 B1 EP3530873 B1 EP 3530873B1 EP 18157788 A EP18157788 A EP 18157788A EP 3530873 B1 EP3530873 B1 EP 3530873B1
- Authority
- EP
- European Patent Office
- Prior art keywords
- tubing string
- inlet
- fluid
- wellbore
- string
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
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Links
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- 238000004519 manufacturing process Methods 0.000 description 22
- 238000004891 communication Methods 0.000 description 10
- 238000013459 approach Methods 0.000 description 8
- 239000000463 material Substances 0.000 description 8
- 238000007789 sealing Methods 0.000 description 7
- 230000009477 glass transition Effects 0.000 description 5
- 238000009434 installation Methods 0.000 description 4
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- 239000004568 cement Substances 0.000 description 3
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- 239000004215 Carbon black (E152) Substances 0.000 description 2
- 230000003213 activating effect Effects 0.000 description 2
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- 230000015572 biosynthetic process Effects 0.000 description 1
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- 238000005381 potential energy Methods 0.000 description 1
- 230000000750 progressive effect Effects 0.000 description 1
- 238000005086 pumping Methods 0.000 description 1
Images
Classifications
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B34/00—Valve arrangements for boreholes or wells
- E21B34/06—Valve arrangements for boreholes or wells in wells
- E21B34/14—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
- E21B34/142—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools unsupported or free-falling elements, e.g. balls, plugs, darts or pistons
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/12—Packers; Plugs
- E21B33/128—Packers; Plugs with a member expanded radially by axial pressure
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B34/00—Valve arrangements for boreholes or wells
- E21B34/06—Valve arrangements for boreholes or wells in wells
- E21B34/063—Valve or closure with destructible element, e.g. frangible disc
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
- E21B2200/06—Sleeve valves
Definitions
- the present invention relates to a system comprising an actuating body and a device adapted to be run on a tubing string into a wellbore.
- the present invention also relates to a tubing string comprising said system.
- the present invention relates to a method of running a tubing string to an intended depth in a wellbore having wellbore fluid inside.
- a known approach involves running the tubing string into the wellbore at a speed low enough that the surging fluid does not cause harm to the components on the tubing string.
- a production packer may include a packer element formed by such a material.
- the material shows rubber-like characteristics, and at temperatures below the glass transition temperature it presents rigid characteristics.
- the material can exhibit a rigid form in zones of the wellbore, typically upper regions, in which the temperature is below the glass transition temperature, and the tubing string may thus be moved more quickly to its destination. And in zones of the wellbore in which the temperature is above the glass transition temperature, the material is more flexible and thus allows a sealing operation to occur.
- Another known approach involves running only open tubing strings. It is expected that the fluid inside the wellbore can flow to the interior of the tubing string during the trip, such as through a free end of the tubing string.
- this approach requires carrying out additional tasks in order to remove the well fluids from the inside of the tubing string. For example, when installing a production packer it is often necessary to increase the pressure inside the tubing string so that the production packer expands and forms a seal against a surrounding surface.
- the following tasks can be carried out: pump the well fluids out of the tubing string into the wellbore and upwards through the annular space surrounding the tubing string; close the tubing string using a cement plug, which involves waiting for the cement to solidify; increase the pressure inside the tubing string until the production packer is set in place; and remove the cement plug.
- a lengthy procedure is required for this approach in order to compensate for the string having been run open into the wellbore.
- Document GB 2 125 470 A discloses a tool for use downhole in a borehole for carrying out a backsurging method.
- Backsurging has the purpose of more thoroughly cleaning out some of the perforations and unplug some perforations which may be clogged with debris. This solution is focused on backsurging a well with the control valve being located as close as possible to the perforations.
- downhole and uphole are used herein to refer to the sense of placement or movement along a wellbore trajectory with respect to an entrance of the wellbore, "downhole” signifying away from and “uphole” signifying toward the entrance to the wellbore.
- the term “downhole” can refer to a part of a string which due to the wellbore trajectory may travel upward or at the same elevation, or which due to the wellbore trajectory has the same elevation or a higher elevation than another part of the string.
- uphole can refer to a part of the string which due to the wellbore trajectory may travel downward or at the same elevation, or which due to the wellbore trajectory has the same elevation or a lower elevation than another part of the string.
- apparatus 1 includes an expandable device in the form of a production packer 10, mounted on a production string 5.
- the production string 5 is being run into a wellbore 2 to install the production packer 10 in a desired location in the wellbore 2.
- the string 5 is being immerged or moved downwards as indicated by arrow A in a vertical section of a wellbore 2 so that it may be installed at a location further downhole.
- the production packer 10 is moved progressively further into the wellbore 2 as the string 5 is extended from topsides, e.g. from a rig or platform, for instance by adding sections to the string 5 using topsides equipment on a rig or platform.
- the production packer 10 is provided on a tubular body 11 which is incorporated into the string 5.
- the packer 10 has annular sealing elements 12 mounted on the tubular body 11, the sealing elements 12 extend circumferentially around the body 11.
- the sealing elements 12 are arranged so that they are expandable from a collapsed condition to an expanded condition in which the sealing elements 12 are urged radially into contact with a surrounding wall 3 of the wellbore 2 and form a fluid-tight, annular seal in the annulus 6 between the wall 3 and the tubing string 5.
- the packer 10 is in the collapsed condition, to facilitate run-in, and a small gap 8 is present between an outer surface of the packer 10 and the wall 3 of the wellbore 2.
- the packer 10 can then be expanded by appropriate activation, achieved for example by hydraulic pressure applied from the surface.
- the string 5 On a downhole side of the packer 10, the string 5 has an inlet 22 providing fluid communication into an interior 51 of the string 5.
- wellbore fluid downhole of the leading end 9 of the string 5 is displaced.
- the wellbore fluid will then typically travel along the wellbore 2 toward the surface, since the wellbore fluid will seek to escape on a pathway of least resistance toward a region of low pressure.
- Wellbore fluid downhole of the packer 10 is received in the interior 51 the string 5 through the inlet 22 and has a fluid communication path, indicated by arrows C, from an outside of the string 5, through the inlet 51, and along the inside of the string 5 toward the surface or other topsides receiver.
- a further fluid communication path, indicated by arrows B is provided for wellbore fluid along the string 5 through the annulus 6 and the gap 8, toward the surface (or other topsides receiver).
- the provision of the inlet 22 provides a path for wellbore fluid to flow along the inside of the string 5 by entering through the inlet 22, as well as on the outside, where the fluid can flow along the outside of the string 5 and pass around the outside of packer 10 through the gap 8.
- the need to allow displaced fluid to escape during the immersion is shared between the internal and external paths.
- this may facilitate reducing the impact of displacement fluids on the packer 10 during immersion and/or allow the packer 10 to be immerged at higher speeds than in typical prior art solutions.
- the velocity of the fluid allowed to pass on the outside of the packer may be reduced, which may in turn also decrease the drag forces on the packer.
- the reduction of the drag forces may have an advantage that the packer may be moved at higher speeds in the wellbore without swabbing the surrounding surface of the wellbore wall.
- the string 5 includes a flow sub 20 connected on the downhole side of the packer 10.
- the flow sub 20 also has a tubular body 23.
- the inlet 22 is provided on the flow sub 20 and comprises an aperture penetrating through the wall 21 of the tubular body 23.
- the flow sub 20 includes a close mechanism 40 for closing the inlet 22.
- An example of the close mechanism is described further below with reference to Figures 3A to 3C .
- the inlet When the inlet is open, fluid communication through the aperture is obtained, and the internal pathway (arrows B) is obtained.
- a sleeve 42 When the inlet 22 is closed, a sleeve 42 is arranged to cover the aperture to prevent fluid communication therethrough.
- the flow sub 20 is run-in/immerged as seen in Figure 2 with the inlet open to provide the desired fluid communication through an internal pathway.
- the flow sub 20 also has a destructible barrier 60, e.g. rupture body such as a glass burst disc, in a main bore of the tubular body 23.
- the destructible barrier 60 is mounted to the tubular body 23 toward a downhole end.
- the destructible barrier 60 can be destroyed by applying pressure in the fluid contained inside the tubing string 5 such that the disc yields and breaks. Destroying the barrier 60 opens up the main bore 23 for allowing production to take place and reservoir hydrocarbon fluid to travel through the inside of the string 5, through the bore of the tubular body 23 and tubular body 11 and toward the surface.
- Figure 2 shows a vertical section of a wellbore where relative positions along the string can be described by terms “above” and “below", it will be appreciated that a wellbore can in general have sections which may be horizontal, vertical, or inclined, and even show a curvature.
- the inlet 22 provides fluid communication with the interior of the tubing string so that the fluid in the wellbore in front of the packer 10 can enter the interior of the tubing string 5 when the packer 10 is moving towards a bottom of the wellbore.
- the inlet 22 is capable of letting fluid into the tubing string 5 that would otherwise flow through the gap 8 in the annular space surrounding the packer 10 and thus increase the drag forces created thereupon.
- the string 5 is run in with the inlet 22 in open configuration as shown in Figure 2 until the desired location for installation is reached. Once in location, the inlet 22 is closed, for allowing the packer 10 then to be expanded.
- the flow sub 20 is in an open configuration where the inlet 22 is open and provides fluid communication through the aperture 24 in the wall of the tubular body 23, during run-in as described above in relation to Figure 2 .
- the flow sub 20 has first and second end portions 25a, 25b connected at either end to the tubular body 23.
- the first and second end portions 25a, 25c are adapted to allow connection to adjacent sections in the string 5.
- the sleeve 42 is housed on an inside of the tubular body 23, and can be activated to slide relative to the tubular body 23, along the longitudinal axis L toward a downhole end 31.
- the sleeve 42 has a seat 35 for receiving a ball dropped into the tubing string 5 from topsides for activating the sleeve 42.
- a spring 46 is arranged on an inside of the tubular body in an annular slot 47 formed between an inner wall 48 of the tubular body 23 and spring retainer 49.
- the spring 46 acts between abutment surfaces 26, 27 on the end portion 25a and the sleeve 42 respectively, so as to be arranged to exert an axial force on the sleeve 42 in the longitudinal direction.
- the spring 46 is in compression in Figure 3A so as to exert a push force against the sleeve 42 toward the downhole end 31.
- the spring 46 is provided so that the sleeve closes spontaneously.
- the sleeve 42 is held in fixed position relative to the body 23, against the force of the spring 46, by way of shear pins 61.
- the shear pins 61 are provided to fasten the sleeve 42 in the open position, as shown in Figure 3A .
- Each shear pin 61 protrudes radially inward from the wall of the tubular body 23 and has an end which is received in a formation in an outer surface of the sleeve 42, so that the pin 61 locks the sleeve 42 with respect to the tubular body 23.
- the shear pins 61 can therefore prevent the sleeve 42 from closing the inlet 22 during run in.
- this arrangement Since the spring 46 is in a compressed state, this arrangement stores potential energy in the spring 46 that may be released for the purpose of closing the sleeve when the shear pins are broken off.
- the sleeve 42 is activated by dropping a ball 55 from a top end of the tubing string 5 such that it passes downhole through an inside of the tubing string 5.
- the ball 55 may be driven by applied fluid pressure behind the ball 55 to urge it along the tubing string 5 toward the location of the seat 35. Fluid in the tubing string 5 ahead of the ball 55 may exit through the aperture 24 to prevent "hydraulic lock".
- the ball 55 passes down the internal bore 52 and lands on the seat 35 where it comes to rest and forms a fluid tight seal against the seat 35.
- the activation of the sleeve is initiated when the object lands on the seat in the tubing string.
- Figures 3B and 3C show the progressive movement of the sleeve 42 into the fully closed configuration as shown in Figure 3C , after the shear pins 61 are broken.
- the inlet 22 is totally obstructed by the sleeve 42, and no fluid communication is possible between the inside and the outside of the tubing string 5.
- the spring 46 increases in extension from Figure 3A to 3C .
- the ball 55 is made of material that is fluid-dissolvable.
- the ball 55 is used initially to close the inlet 22 as described above, but after a time it dissolves in the presence of the fluid inside the tubing string 5 such that it is removed. Removal of the ball is useful because the bore 57 can then be opened up for allowing hydrocarbon production or other operations to be performed.
- the spring 46 alone urges the sleeve 42 to remain in position and keeps the inlet 22 closed, e.g. while production takes place.
- other objects e.g. other drop objects such as darts or the like, may be delivered through the inside of the tubing string and utilised to activate the sleeve 42.
- Such objects may or may not be dissolvable.
- the sleeve may be closed in many ways, and using a spring and shear pins as described above is only way of doing it.
- electronic means may be provided to activate the sleeve in reaction to the landing of the object on the seat; the compressed spring may be replaced by any other solution that would push the sleeve to the closed position, such as a compressed fluid; instead of the spring, the space in the tubing string that is closed by the object on the seat may be used as a pressure chamber to push the sleeve to the closed position; or the shear pins may be replaced by a locking mechanism activated electronically.
- An advantage of the approach described with reference to Figures 3A to 3C using a spring and shear pins, is that it can be simple to implement.
- Figure 4A firstly illustrates the inlet 22 in closed configuration as a result of closing the sleeve as explained in relation to Figures 3A-3C .
- the ball 55 is deployed in the tubing string 5, which in turn activates the sleeve 42 and closes the inlet 22.
- the tubing string 5 is now extended so that the packer 10 is at the position in the wellbore at which it will be expanded to form a seal against the surrounding surface of the wellbore wall.
- Figure 4B illustrates the production packer being expanded and tested.
- the pressure of fluid contained inside the tubing string in the region 57 is increased to hydraulically operate packer so that the sealing elements 12 expand and are brought into contact with the wall of the wellbore.
- the ball 55 remains on the seat 35 while the pressure in the region 57 is increased as required.
- the ball 55 may be removed before activating the packer 10, e.g. by letting it dissolve, and the region 57 may be pressured up to activate the packer directly against a rupture body 60
- test is carried out by filling the tubing string with a dense fluid, such as heavy mud, and checking if the seal of the packer 10 holds the tubing string 5 in place against the wellbore wall.
- Another test may be carried out by filling or pressurising the annulus 6 above the packer 10 and checking if there any leakage across the seal.
- the region 57 of the interior of the tubing string 5 (uphole of the ball 55 or rupture body 60 and up to the top end of the string), provides in effect a chamber for containing fluid that can be pressurised from topsides equipment, e.g. by pumping a fluid into the tubing at the top of the wellbore.
- the chamber can facilitate both expanding the packer 10 by increasing the pressure inside the tubing string 5, and carrying out at least one test for making sure that the seal of the packer 10 is well formed, for example in accordance with a standard for the certification of well barriers.
- the ball 55 is composed of dissolvable material, at some point in time the object will disintegrate. Such disintegration may take place before the expandable device is expanded, after the expansion, or after the tests. In the end, the tubing string needs to be made ready for production.
- the rupture body 60 needs to be removed using a suitable method, such as by pressurising the fluid in the region 57 beyond the pre-designed rupture limits.
- Figure 4C illustrates a final state, in which the ball 55 is not present because it has been dissolved, and the rupture body 60 is not present because it has been removed.
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Description
- The present invention relates to a system comprising an actuating body and a device adapted to be run on a tubing string into a wellbore. The present invention also relates to a tubing string comprising said system. Also, the present invention relates to a method of running a tubing string to an intended depth in a wellbore having wellbore fluid inside.
- In petroleum production, a usual task in the completion of a well is running a closed tubing string until a certain depth in the bore of the well. This task may be useful for various purposes, such as the installation of a production component.
- Carrying out this task can be complex. On the one hand, since the operation costs are proportional to the duration of the trip, it is normally desired that the tubing string reaches the intended depth as quickly as possible. On the other hand, a high velocity of insertion can result in damage being caused to the tubing string. This scenario is strongly undesired, as it represents an additional cost for the completion of the well, which typically is a significant cost. Thus, it is wished that the tubing string runs as quickly as possible into the wellbore, but at the same time that the tubing string does not get damaged because of the trip to the intended depth.
- During the trip, there is a phenomenon in particular that can cause problems to the closed tubing string: the creation of a surge of fluid towards the head of the well. Normally, the wellbore contains fluid inside during the completion phase. The submersion of the closed tubing string in that fluid displaces an amount of the second that is equal to the submerged volume. Consequently, the displaced fluid flows towards the head of the well through the available spaces, such as the annular space formed around the tubing string. This motion of the surging fluid can reach high velocities and be a cause of damage to the components that are on the tubing string. For example, it is possible that, due to the swabbing caused by the surging fluid, a packer element detaches from its respective packer device.
- Thus, it can be challenging to run a tubing string into a wellbore without that motion resulting in a surging fluid capable of damaging the tubing string.
- A known approach involves running the tubing string into the wellbore at a speed low enough that the surging fluid does not cause harm to the components on the tubing string.
- This approach significantly increases the cost of the operation, as it requires more time in order to perform the trip.
- Another known approach is to equip the components on the tubing string with stronger parts that can withstand the high velocities of the surging fluid. Some solutions in this respect include parts with different physical properties based on their glass transition temperature. For example, a production packer may include a packer element formed by such a material. In this case, at temperatures above the glass transition temperature the material shows rubber-like characteristics, and at temperatures below the glass transition temperature it presents rigid characteristics. The material can exhibit a rigid form in zones of the wellbore, typically upper regions, in which the temperature is below the glass transition temperature, and the tubing string may thus be moved more quickly to its destination. And in zones of the wellbore in which the temperature is above the glass transition temperature, the material is more flexible and thus allows a sealing operation to occur. This approach can allow the expandable device to be moved in certain parts of a well, and it does not put in jeopardy the steps required for the installation task to the same extent. However, it can be technically challenging to provide an expandable device with a suitable temperature-based material. For example, since the flexibility of the material of the expandable device may depend on the temperature in the wellbore, the temperature may need to be monitored when moving the expandable device along the well.
- Another known approach involves running only open tubing strings. It is expected that the fluid inside the wellbore can flow to the interior of the tubing string during the trip, such as through a free end of the tubing string. However, this approach requires carrying out additional tasks in order to remove the well fluids from the inside of the tubing string. For example, when installing a production packer it is often necessary to increase the pressure inside the tubing string so that the production packer expands and forms a seal against a surrounding surface. In order to install the production packer while having well fluids inside the tubing string, the following tasks can be carried out: pump the well fluids out of the tubing string into the wellbore and upwards through the annular space surrounding the tubing string; close the tubing string using a cement plug, which involves waiting for the cement to solidify; increase the pressure inside the tubing string until the production packer is set in place; and remove the cement plug. In sum, a lengthy procedure is required for this approach in order to compensate for the string having been run open into the wellbore.
- Document
US 5 181 569 A discloses a pressure operated valve in which there is a sleeve valve controlling flow between outside and inside the valve. Pressure on a ball sealingly engaging the sleeve operates the sleeve valve from open to latched closed to disconnect position and expends the sleeve valve from the housing. This solution is focused on dealing with time consumption and operation expenses drawbacks related to running tubing from surface into a well to install or expend a sealing plug from a packer, especially if long lengths of tubing must be run to reach a packer set deep in a well. -
Document GB 2 125 470 A - Document
US 2 695 066 A discloses a hydraulically actuated well tool, more particularly a well packer adapted to be anchored in a well bore as a result of subjecting the tool to fluid pressure. This solution is focused on allowing upward flow of fluid through a tool, during lowering of the tool in the well bore, by initially preventing the back pressure valve from seating. - The present invention will now be disclosed. The invention is set out in the appended set of claims.
- The terms "downhole" and "uphole" are used herein to refer to the sense of placement or movement along a wellbore trajectory with respect to an entrance of the wellbore, "downhole" signifying away from and "uphole" signifying toward the entrance to the wellbore. Hence in the case of a deviating horizontal or inverted section of a wellbore, the term "downhole" can refer to a part of a string which due to the wellbore trajectory may travel upward or at the same elevation, or which due to the wellbore trajectory has the same elevation or a higher elevation than another part of the string. Conversely, the term "uphole" can refer to a part of the string which due to the wellbore trajectory may travel downward or at the same elevation, or which due to the wellbore trajectory has the same elevation or a lower elevation than another part of the string.
- The invention will now be described, by way of example only, with reference to the accompanying drawings, in which:
- Figure 1
- is a schematic representation of an expandable device during deployment, according to the prior art;
- Figure 2
- is a part-sectional representation of an apparatus according to an embodiment of the present invention, where an expandable device is being installed;
- Figures 3A to 3C
- are part-sectional representations of an apparatus according to another embodiment of the invention, at different stages of a process through which a valve is closed; and
- Figures 4A to 4C
- are part-sectional representations of an apparatus at different stages of use to install an expandable device in a wellbore, according to another embodiment of the invention.
- Turning first to look at
Figure 2 ,apparatus 1 includes an expandable device in the form of aproduction packer 10, mounted on aproduction string 5. Theproduction string 5 is being run into awellbore 2 to install theproduction packer 10 in a desired location in thewellbore 2. Thestring 5 is being immerged or moved downwards as indicated by arrow A in a vertical section of awellbore 2 so that it may be installed at a location further downhole. Theproduction packer 10 is moved progressively further into thewellbore 2 as thestring 5 is extended from topsides, e.g. from a rig or platform, for instance by adding sections to thestring 5 using topsides equipment on a rig or platform. - The
production packer 10 is provided on atubular body 11 which is incorporated into thestring 5. Thepacker 10 hasannular sealing elements 12 mounted on thetubular body 11, thesealing elements 12 extend circumferentially around thebody 11. Thesealing elements 12 are arranged so that they are expandable from a collapsed condition to an expanded condition in which thesealing elements 12 are urged radially into contact with a surroundingwall 3 of thewellbore 2 and form a fluid-tight, annular seal in theannulus 6 between thewall 3 and thetubing string 5. - In
Figure 2 , thepacker 10 is in the collapsed condition, to facilitate run-in, and asmall gap 8 is present between an outer surface of thepacker 10 and thewall 3 of thewellbore 2. Once the intended location for installation of thepacker 10 is reached, thepacker 10 can then be expanded by appropriate activation, achieved for example by hydraulic pressure applied from the surface. - On a downhole side of the
packer 10, thestring 5 has aninlet 22 providing fluid communication into an interior 51 of thestring 5. As thestring 5 is immerged/moved into thewellbore 6, wellbore fluid downhole of theleading end 9 of thestring 5 is displaced. The wellbore fluid will then typically travel along thewellbore 2 toward the surface, since the wellbore fluid will seek to escape on a pathway of least resistance toward a region of low pressure. Wellbore fluid downhole of thepacker 10 is received in the interior 51 thestring 5 through theinlet 22 and has a fluid communication path, indicated by arrows C, from an outside of thestring 5, through theinlet 51, and along the inside of thestring 5 toward the surface or other topsides receiver. A further fluid communication path, indicated by arrows B, is provided for wellbore fluid along thestring 5 through theannulus 6 and thegap 8, toward the surface (or other topsides receiver). - Thus, it can be appreciated that the provision of the
inlet 22 provides a path for wellbore fluid to flow along the inside of thestring 5 by entering through theinlet 22, as well as on the outside, where the fluid can flow along the outside of thestring 5 and pass around the outside ofpacker 10 through thegap 8. - By way of the
apparatus 1 inFigure 2 , the need to allow displaced fluid to escape during the immersion is shared between the internal and external paths. Advantageously, this may facilitate reducing the impact of displacement fluids on thepacker 10 during immersion and/or allow thepacker 10 to be immerged at higher speeds than in typical prior art solutions. More specifically, the velocity of the fluid allowed to pass on the outside of the packer may be reduced, which may in turn also decrease the drag forces on the packer. The reduction of the drag forces may have an advantage that the packer may be moved at higher speeds in the wellbore without swabbing the surrounding surface of the wellbore wall. - Referring now to the
Figure 2 example in further detail, it can be seen that thestring 5 includes aflow sub 20 connected on the downhole side of thepacker 10. Theflow sub 20 also has atubular body 23. Theinlet 22 is provided on theflow sub 20 and comprises an aperture penetrating through thewall 21 of thetubular body 23. - The
flow sub 20 includes aclose mechanism 40 for closing theinlet 22. An example of the close mechanism is described further below with reference toFigures 3A to 3C . When the inlet is open, fluid communication through the aperture is obtained, and the internal pathway (arrows B) is obtained. When theinlet 22 is closed, asleeve 42 is arranged to cover the aperture to prevent fluid communication therethrough. Theflow sub 20 is run-in/immerged as seen inFigure 2 with the inlet open to provide the desired fluid communication through an internal pathway. - In the configuration exemplified in
Figure 2 , theflow sub 20 also has adestructible barrier 60, e.g. rupture body such as a glass burst disc, in a main bore of thetubular body 23. Thedestructible barrier 60 is mounted to thetubular body 23 toward a downhole end. At an appropriate stage during the completion of the well, thedestructible barrier 60 can be destroyed by applying pressure in the fluid contained inside thetubing string 5 such that the disc yields and breaks. Destroying thebarrier 60 opens up themain bore 23 for allowing production to take place and reservoir hydrocarbon fluid to travel through the inside of thestring 5, through the bore of thetubular body 23 andtubular body 11 and toward the surface. - Although
Figure 2 shows a vertical section of a wellbore where relative positions along the string can be described by terms "above" and "below", it will be appreciated that a wellbore can in general have sections which may be horizontal, vertical, or inclined, and even show a curvature. In all cases, theinlet 22 provides fluid communication with the interior of the tubing string so that the fluid in the wellbore in front of thepacker 10 can enter the interior of thetubing string 5 when thepacker 10 is moving towards a bottom of the wellbore. By way of theinlet 22 being disposed in front of thepacker 10, theinlet 22 is capable of letting fluid into thetubing string 5 that would otherwise flow through thegap 8 in the annular space surrounding thepacker 10 and thus increase the drag forces created thereupon. - The
string 5 is run in with theinlet 22 in open configuration as shown inFigure 2 until the desired location for installation is reached. Once in location, theinlet 22 is closed, for allowing thepacker 10 then to be expanded. - Before closing the inlet, the fluid inside the
tubing string 5 is typically driven out through the inlet back to the wellbore due to practical reasons. - With reference additionally to
Figures 3A to 3C , theclose mechanism 40 and process of closing theinlet 22 will be described further. - In
Figure 3A , theflow sub 20 is in an open configuration where theinlet 22 is open and provides fluid communication through theaperture 24 in the wall of thetubular body 23, during run-in as described above in relation toFigure 2 . - The
flow sub 20 has first andsecond end portions tubular body 23. The first andsecond end portions 25a, 25c are adapted to allow connection to adjacent sections in thestring 5. Thesleeve 42 is housed on an inside of thetubular body 23, and can be activated to slide relative to thetubular body 23, along the longitudinal axis L toward adownhole end 31. Thesleeve 42 has aseat 35 for receiving a ball dropped into thetubing string 5 from topsides for activating thesleeve 42. - A
spring 46 is arranged on an inside of the tubular body in anannular slot 47 formed between aninner wall 48 of thetubular body 23 andspring retainer 49. Thespring 46 acts between abutment surfaces 26, 27 on theend portion 25a and thesleeve 42 respectively, so as to be arranged to exert an axial force on thesleeve 42 in the longitudinal direction. Thespring 46 is in compression inFigure 3A so as to exert a push force against thesleeve 42 toward thedownhole end 31. - The
spring 46 is provided so that the sleeve closes spontaneously. - In
Figure 3A , thesleeve 42 is held in fixed position relative to thebody 23, against the force of thespring 46, by way of shear pins 61. The shear pins 61 are provided to fasten thesleeve 42 in the open position, as shown inFigure 3A . Eachshear pin 61 protrudes radially inward from the wall of thetubular body 23 and has an end which is received in a formation in an outer surface of thesleeve 42, so that thepin 61 locks thesleeve 42 with respect to thetubular body 23. The shear pins 61 can therefore prevent thesleeve 42 from closing theinlet 22 during run in. - Since the
spring 46 is in a compressed state, this arrangement stores potential energy in thespring 46 that may be released for the purpose of closing the sleeve when the shear pins are broken off. - In order to close the
inlet 22, thesleeve 42 is activated by dropping aball 55 from a top end of thetubing string 5 such that it passes downhole through an inside of thetubing string 5. Theball 55 may be driven by applied fluid pressure behind theball 55 to urge it along thetubing string 5 toward the location of theseat 35. Fluid in thetubing string 5 ahead of theball 55 may exit through theaperture 24 to prevent "hydraulic lock". Theball 55 passes down theinternal bore 52 and lands on theseat 35 where it comes to rest and forms a fluid tight seal against theseat 35. The activation of the sleeve is initiated when the object lands on the seat in the tubing string. - Pressure inside the
tubing string 5 in theregion 57 is applied and exerts a force against theball 55 such that shear pins 61 are sheared off and break. This frees thesleeve 42 and thesleeve 42 moves along thetubular body 23 to a closed position in which thesleeve 42 blocks theinlet 22 and prevents fluid communication through theinlet 22 into the interior of thetubing string 5. Thesleeve 42 is urged along thetubular body 23 by the applied force and the force of thespring 46. -
Figures 3B and 3C show the progressive movement of thesleeve 42 into the fully closed configuration as shown inFigure 3C , after the shear pins 61 are broken. InFigure 3C , theinlet 22 is totally obstructed by thesleeve 42, and no fluid communication is possible between the inside and the outside of thetubing string 5. It can be noted that thespring 46 increases in extension fromFigure 3A to 3C . - In this example, the
ball 55 is made of material that is fluid-dissolvable. Theball 55 is used initially to close theinlet 22 as described above, but after a time it dissolves in the presence of the fluid inside thetubing string 5 such that it is removed. Removal of the ball is useful because thebore 57 can then be opened up for allowing hydrocarbon production or other operations to be performed. When theball 55 has dissolved and is no longer seated on theseat 35, thespring 46 alone urges thesleeve 42 to remain in position and keeps theinlet 22 closed, e.g. while production takes place. - In other embodiments, other objects, e.g. other drop objects such as darts or the like, may be delivered through the inside of the tubing string and utilised to activate the
sleeve 42. Such objects may or may not be dissolvable. - It can also be appreciated that different close mechanism s may be employed in other embodiments to close the
inlet 22. In sleeve-based mechanisms, the sleeve may be closed in many ways, and using a spring and shear pins as described above is only way of doing it. For example, electronic means may be provided to activate the sleeve in reaction to the landing of the object on the seat; the compressed spring may be replaced by any other solution that would push the sleeve to the closed position, such as a compressed fluid; instead of the spring, the space in the tubing string that is closed by the object on the seat may be used as a pressure chamber to push the sleeve to the closed position; or the shear pins may be replaced by a locking mechanism activated electronically. An advantage of the approach described with reference toFigures 3A to 3C , using a spring and shear pins, is that it can be simple to implement. - Turning then to
Figures 4A to 4C , further stages of use are depicted through which theproduction packer 10 is expanded and tested, and thetubing string 5 is prepared for production. -
Figure 4A firstly illustrates theinlet 22 in closed configuration as a result of closing the sleeve as explained in relation toFigures 3A-3C . Theball 55 is deployed in thetubing string 5, which in turn activates thesleeve 42 and closes theinlet 22. Thetubing string 5 is now extended so that thepacker 10 is at the position in the wellbore at which it will be expanded to form a seal against the surrounding surface of the wellbore wall. -
Figure 4B illustrates the production packer being expanded and tested. The pressure of fluid contained inside the tubing string in theregion 57 is increased to hydraulically operate packer so that the sealingelements 12 expand and are brought into contact with the wall of the wellbore. In this example, theball 55 remains on theseat 35 while the pressure in theregion 57 is increased as required. However, in an alternative variant, theball 55 may be removed before activating thepacker 10, e.g. by letting it dissolve, and theregion 57 may be pressured up to activate the packer directly against arupture body 60 - Various tests are performed for checking the integrity of the seal provided by the
packer 10. One test may be carried out by filling the tubing string with a dense fluid, such as heavy mud, and checking if the seal of thepacker 10 holds thetubing string 5 in place against the wellbore wall. Another test may be carried out by filling or pressurising theannulus 6 above thepacker 10 and checking if there any leakage across the seal. - When these tests are completed, the
ball 55 is dissolved and therupture body 60 is broken by pressuring the fluid in theregion 57 as necessary, and thebore 52 for production of oil and gas is opened up as indicated inFigure 4C . - It can be appreciated that the
region 57 of the interior of the tubing string 5 (uphole of theball 55 or rupturebody 60 and up to the top end of the string), provides in effect a chamber for containing fluid that can be pressurised from topsides equipment, e.g. by pumping a fluid into the tubing at the top of the wellbore. The chamber can facilitate both expanding thepacker 10 by increasing the pressure inside thetubing string 5, and carrying out at least one test for making sure that the seal of thepacker 10 is well formed, for example in accordance with a standard for the certification of well barriers. - If the
ball 55 is composed of dissolvable material, at some point in time the object will disintegrate. Such disintegration may take place before the expandable device is expanded, after the expansion, or after the tests. In the end, the tubing string needs to be made ready for production. For this purpose, therupture body 60 needs to be removed using a suitable method, such as by pressurising the fluid in theregion 57 beyond the pre-designed rupture limits. -
Figure 4C illustrates a final state, in which theball 55 is not present because it has been dissolved, and therupture body 60 is not present because it has been removed. - The invention may have some or all of the following advantages:
- reduction of the time and cost necessary for installing a packer or other expandable device in a wellbore;
- reduced drag forces created on packer elements when it is translated along a wellbore;
- ability to move the packer into position along a wellbore at higher speed;
- simple solution with relatively few components; and
- improvements in moving a packer along a wellbore without jeopardising the ability to expand the packer, test the seal formed, and preparing the tubing string for production.
Claims (10)
- A system (1) comprising:- a device (20) adapted to be run on a tubing string (5) into a wellbore (2); and- an actuating body (55),wherein the device (20) comprises:- a tubular body (11, 23) adapted to form a portion of the tubing string,- at least one inlet (22) for enabling the entry of a fluid into the tubing string (5), wherein the at least one inlet is at least one aperture (24) in a wall of the tubular body (11, 23);- a close mechanism (40) for closing the at least one inlet (22), wherein the close mechanism (40) comprises a movable member (42) that is movable from a first position, whereby fluid can be received from an outside of the tubing string (5) into the tubing string (5) through the at least one inlet (22), to a second position for closing the at least one inlet (22); and- a catcher (35) coupled to the movable member (42),wherein, in a configuration for immerging the tubing string (5) in a fluid inside the wellbore (2), the movable member (42) is in the first position and the at least one inlet (22) is open for letting the fluid enter the tubing string (5),wherein the close mechanism (40) is operable to close by means of the actuating body (55),wherein the movable member (42) is movable from the first position to the second position by a force exerted by the actuating body (55), the actuating body (55) being received in the catcher (35),wherein the catcher (35) receives the actuating body (55) in an internal bore of the device (20) andwherein the actuating body is an object (55) inserted into a top end of the tubing string (5),wherein the object (55) is fluid-dissolvable, such that, when the device has been run on a tubing string into a wellbore in the configuration for immerging the tubing string (5), and when the object has been received in the catcher and the movable member (42) has been moved from the first position to the second position, the object dissolves after a time in the presence of the fluid that has entered into the tubing string (5) through the at least one inlet (22),characterized in that the device comprises a destructible barrier positioned downhole in relation to the at least one inlet,wherein the destructible barrier isolates the interior of the tubing string for allowing fluid in the isolated interior of the tubing string to be pressurised when the at least one inlet is closed.
- A system according to claim 1, wherein the destructible barrier is arranged to be destroyed by applying pressure in the isolated interior of the tubing string, so that a bore opens inside the tubing string.
- A system according to any of the claims 1 to 2, wherein the movable member is a sliding sleeve.
- A system according to any of the claims 1 to 3, wherein the object is a ball, and the catcher is a seat for receiving the ball.
- A system according to any of the claims 1 to 4, wherein the device comprises at least one retaining device for retaining the movable member in an open position in the immerging configuration.
- A system according to claim 5, wherein the close mechanism comprises at least one biasing means for closing the movable member spontaneously when the at least one retaining device is sheared so as to free the movable member.
- A tubing string comprising a system as described in any of the preceding claims.
- A tubing string according to claim 7, comprising at least one expandable device,
wherein the device of the system is mounted downhole in relation to the at least one expandable device. - A method of running a tubing string (5) to an intended depth in a wellbore (2) having wellbore fluid inside, characterised in that the tubing string (5) is in accordance with any of the claims 7 or 8, and wherein the method comprises the following steps:- providing the device (20) on the tubing string (5), the device (20) being in the immerging configuration;- extending the tubing string (5) until it reaches the intended depth; and- deploying the object (55) into the interior of the tubing string (5), by inserting the object (55) into the top end of the tubing string (5), so that the close mechanism (40) of the device (20) is operated to close the at least one inlet (22) of the device (20).
- A method according to claim 9, the method comprising applying pressure to fluid in the interior of the string to perform:when the tubing string (5) is in accordance with claim 8:- expanding an expandable device provided on the tubing string so as to form a seal against a surrounding surface; and- performing at least one test for testing the seal formed by the expandable device, and/orwhen the tubing string (5) of claim 7 or 8 comprises a system as described in claim 2:- destroying the destructible barrier member so that the bore opens in the interior of the string.
Priority Applications (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
EP18157788.3A EP3530873B1 (en) | 2018-02-21 | 2018-02-21 | Device adapted to be run on a tubing string into a wellbore |
PCT/NO2019/050039 WO2019164406A1 (en) | 2018-02-21 | 2019-02-20 | Device adapted to be run on a tubing string into a wellbore |
Applications Claiming Priority (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
EP18157788.3A EP3530873B1 (en) | 2018-02-21 | 2018-02-21 | Device adapted to be run on a tubing string into a wellbore |
Publications (2)
Publication Number | Publication Date |
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EP3530873A1 EP3530873A1 (en) | 2019-08-28 |
EP3530873B1 true EP3530873B1 (en) | 2023-10-11 |
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Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
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EP18157788.3A Active EP3530873B1 (en) | 2018-02-21 | 2018-02-21 | Device adapted to be run on a tubing string into a wellbore |
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EP (1) | EP3530873B1 (en) |
WO (1) | WO2019164406A1 (en) |
Citations (1)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
WO2015073001A1 (en) * | 2013-11-14 | 2015-05-21 | Schlumberger Canada Limited | System and methodology for using a degradable object in tubing |
Family Cites Families (7)
Publication number | Priority date | Publication date | Assignee | Title |
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US2695066A (en) * | 1949-10-18 | 1954-11-23 | Baker Oil Tools Inc | Hydraulically actuated well tool |
US4529038A (en) * | 1982-08-19 | 1985-07-16 | Geo Vann, Inc. | Differential vent and bar actuated circulating valve and method |
US5181569A (en) * | 1992-03-23 | 1993-01-26 | Otis Engineering Corporation | Pressure operated valve |
US5810084A (en) * | 1996-02-22 | 1998-09-22 | Halliburton Energy Services, Inc. | Gravel pack apparatus |
US5775428A (en) * | 1996-11-20 | 1998-07-07 | Baker Hughes Incorporated | Whipstock-setting apparatus |
US6769490B2 (en) * | 2002-07-01 | 2004-08-03 | Allamon Interests | Downhole surge reduction method and apparatus |
US20100032167A1 (en) * | 2008-08-08 | 2010-02-11 | Adam Mark K | Method for Making Wellbore that Maintains a Minimum Drift |
-
2018
- 2018-02-21 EP EP18157788.3A patent/EP3530873B1/en active Active
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2019
- 2019-02-20 WO PCT/NO2019/050039 patent/WO2019164406A1/en active Application Filing
Patent Citations (1)
Publication number | Priority date | Publication date | Assignee | Title |
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WO2015073001A1 (en) * | 2013-11-14 | 2015-05-21 | Schlumberger Canada Limited | System and methodology for using a degradable object in tubing |
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WO2019164406A1 (en) | 2019-08-29 |
EP3530873A1 (en) | 2019-08-28 |
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