EP3530873A1 - Dispositif adapté pour être exécuté sur une colonne de tubage dans un puits de forage - Google Patents

Dispositif adapté pour être exécuté sur une colonne de tubage dans un puits de forage Download PDF

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Publication number
EP3530873A1
EP3530873A1 EP18157788.3A EP18157788A EP3530873A1 EP 3530873 A1 EP3530873 A1 EP 3530873A1 EP 18157788 A EP18157788 A EP 18157788A EP 3530873 A1 EP3530873 A1 EP 3530873A1
Authority
EP
European Patent Office
Prior art keywords
tubing string
inlet
wellbore
string
fluid
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.)
Granted
Application number
EP18157788.3A
Other languages
German (de)
English (en)
Other versions
EP3530873B1 (fr
Inventor
Tore Sørheim
Paul David Busengdal
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Grant Prideco Inc
Original Assignee
National Oilwell Varco Norway AS
Priority date (The priority date 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 date listed.)
Filing date
Publication date
Application filed by National Oilwell Varco Norway AS filed Critical National Oilwell Varco Norway AS
Priority to EP18157788.3A priority Critical patent/EP3530873B1/fr
Priority to PCT/NO2019/050039 priority patent/WO2019164406A1/fr
Publication of EP3530873A1 publication Critical patent/EP3530873A1/fr
Application granted granted Critical
Publication of EP3530873B1 publication Critical patent/EP3530873B1/fr
Active legal-status Critical Current
Anticipated expiration legal-status Critical

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Classifications

    • 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
    • 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
    • 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
    • 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
    • E21B2200/08—Down-hole devices using materials which decompose under well-bore conditions

Definitions

  • the present invention relates to a device adapted to be run on a tubing string into a wellbore.
  • the present invention also relates to a tubing string comprising said device.
  • 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.
  • a device adapted to be run on a tubing string into a wellbore, the device comprising:
  • the device may comprise 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.
  • the destructible barrier may be arranged to be destroyed by applying pressure in the isolated interior of the tubing string, so that a bore opens inside the tubing string.
  • the device may comprise a tubular body adapted to form a portion of the tubing string, and wherein the at least one inlet is at least one aperture in a wall of the tubular body.
  • the close mechanism may comprise a movable member that is movable from a first position to a second position for closing the at least one inlet, the close mechanism being operable to close by way of an actuating body.
  • the movable member may be a sliding sleeve.
  • the movable member may be movable by a force exerted by the actuating body, the actuating body being received in a catcher coupled to the movable member, wherein the catcher receives the actuating body in an internal bore of the tubing string and wherein the actuating body is an object inserted into the tubing string.
  • the object may be a ball, and the catcher may be a seat for receiving the ball.
  • the object may be dissolvable so as to be destroyable by means of a dissolvent.
  • the device may comprise at least one retaining device for retaining the movable member in an open position in the immerging configuration.
  • the close mechanism may comprise at least one biasing means for closing the movable member spontaneously when the retaining device is sheared so as to free the movable member.
  • a tubing string comprising a device as described above.
  • the tubing string may comprise at least one expandable device, wherein the device is mounted downhole in relation to the at least one expandable device.
  • a method of running a tubing string to an intended depth in a wellbore having wellbore fluid inside wherein the tubbing string is in accordance with the invention aspect above and the device is in accordance with the device embodiment above in which the movable member may be movable by a force exerted by an actuating body, the actuating body being received in a catcher coupled to a movable member, wherein the catcher receives the actuating body in an internal bore of the tubing string and wherein the actuating body is an object inserted into the tubing string.
  • the method comprises the following steps:
  • the method is for running a tubing string comprising a device is in accordance with the device embodiment above in which the device may comprise 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.
  • the method embodiment comprises applying pressure to fluid in the interior of the string to perform any one or more of:
  • 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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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Pipe Accessories (AREA)
EP18157788.3A 2018-02-21 2018-02-21 Dispositif adapté pour être exécuté sur une colonne de tubage dans un puits de forage Active EP3530873B1 (fr)

Priority Applications (2)

Application Number Priority Date Filing Date Title
EP18157788.3A EP3530873B1 (fr) 2018-02-21 2018-02-21 Dispositif adapté pour être exécuté sur une colonne de tubage dans un puits de forage
PCT/NO2019/050039 WO2019164406A1 (fr) 2018-02-21 2019-02-20 Dispositif conçu pour être posé sur une colonne de production dans un puits de forage

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
EP18157788.3A EP3530873B1 (fr) 2018-02-21 2018-02-21 Dispositif adapté pour être exécuté sur une colonne de tubage dans un puits de forage

Publications (2)

Publication Number Publication Date
EP3530873A1 true EP3530873A1 (fr) 2019-08-28
EP3530873B1 EP3530873B1 (fr) 2023-10-11

Family

ID=61256641

Family Applications (1)

Application Number Title Priority Date Filing Date
EP18157788.3A Active EP3530873B1 (fr) 2018-02-21 2018-02-21 Dispositif adapté pour être exécuté sur une colonne de tubage dans un puits de forage

Country Status (2)

Country Link
EP (1) EP3530873B1 (fr)
WO (1) WO2019164406A1 (fr)

Citations (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US2695066A (en) * 1949-10-18 1954-11-23 Baker Oil Tools Inc Hydraulically actuated well tool
GB2125470A (en) * 1982-08-19 1984-03-07 Vann Inc Geo Differential vent and bar actuated circulating valve and method
US5181569A (en) * 1992-03-23 1993-01-26 Otis Engineering Corporation Pressure operated valve
US5775428A (en) * 1996-11-20 1998-07-07 Baker Hughes Incorporated Whipstock-setting apparatus
US5810084A (en) * 1996-02-22 1998-09-22 Halliburton Energy Services, Inc. Gravel pack apparatus
US20040000406A1 (en) * 2002-07-01 2004-01-01 Allamon Jerry P. 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

Family Cites Families (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2015073001A1 (fr) * 2013-11-14 2015-05-21 Schlumberger Canada Limited Système et méthodologie pour une utilisation d'un objet dégradable dans un tubage

Patent Citations (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US2695066A (en) * 1949-10-18 1954-11-23 Baker Oil Tools Inc Hydraulically actuated well tool
GB2125470A (en) * 1982-08-19 1984-03-07 Vann Inc Geo 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
US20040000406A1 (en) * 2002-07-01 2004-01-01 Allamon Jerry P. 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

Also Published As

Publication number Publication date
EP3530873B1 (fr) 2023-10-11
WO2019164406A1 (fr) 2019-08-29

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