Key information

Title
A SEALING ASSEMBLY FOR USE IN A DOWNHOLE TOOL, A DOWNHOLE TOOL AND A METHOD FOR USING THE DOWNHOLE TOOL
Application number
20241071
Case type
National
Status
15.06.2026 Patent meddelt (B1)
Filed
28.10.2024
Effective date
28.10.2024
Publicly available
29.04.2026
Next annual fee due
31.10.2027
Applicant
Archer Oiltools AS (NO)
Owner
Archer Oiltools AS (NO)
Inventor
Arve Byberg (NO)
Agent
ACAPO ONSAGERS AS (NO)
Granted
15.06.2026
Patent number
349916
Expiry date
28.10.2044

Abstract and drawing

Disclaimer: This text has been machine-scanned and may contain errors – please refer to "Publications" for legally binding content.
A sealing assembly for use in a downhole tool for well interventions is proposed, the sealing assembly comprising a sealing element arranged configured to be disposable on a tubular body, the sealing element being radially expandable and configurable between a radially unexpanded state and a radially expanded state to form a seal against an inner surface of the wellbore. The sealing assembly comprises a protective structure arranged at an outer circumference of the sealing element, wherein the protective structure has a higher abrasion resistance than the at least one sealing element.

Publications

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Documents

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Date
 Date Doc. No. Process Case number In/Out Journal description To/from
 16.06.2026 13-01 Saksbehandling 20241071(349916) UT PT Registreringsbrev nasjonal patent (15) (PT20241071)
10.04.2026 12-01 Saksbehandling 20241071 UT Intention to grant ACAPO ONSAGERS AS
 20.01.2026 11-06 Saksbehandling 20241071 INN P29748NO00_postponment request ACAPO ONSAGERS AS
 20.01.2026 11-05 Saksbehandling 20241071 INN P29748NO00_Amended description for publication (marked copy) ACAPO ONSAGERS AS
 20.01.2026 11-04 Saksbehandling 20241071 INN P29748NO00_Amended description for publication (clean copy) ACAPO ONSAGERS AS
 20.01.2026 11-03 Saksbehandling 20241071 INN P29748NO00 Reply ACAPO ONSAGERS AS
 20.01.2026 11-02 Saksbehandling 20241071 INN P29748NO00 Norwegian claims ACAPO ONSAGERS AS
 20.01.2026 11-01 Saksbehandling 20241071 INN Korrespondanse (Hovedbrev inn) ACAPO ONSAGERS AS
 08.01.2026 10-01 Saksbehandling 20241071 UT Substantive examination ACAPO ONSAGERS AS
 07.11.2025 09-03 Saksbehandling 20241071 INN P29748PC00 - PCT Figures 1270304 ACAPO ONSAGERS AS
 07.11.2025 09-02 Saksbehandling 20241071 INN P29748NO00 accompanying letter ACAPO ONSAGERS AS
 07.11.2025 09-01 Saksbehandling 20241071 INN Korrespondanse (Hovedbrev inn) ACAPO ONSAGERS AS
 06.10.2025 08-04 Saksbehandling 20241071 INN P29748NO00 response ACAPO ONSAGERS AS
 06.10.2025 08-03 Saksbehandling 20241071 INN P29748NO00 amended claims WC ACAPO ONSAGERS AS
 06.10.2025 08-02 Saksbehandling 20241071 INN P29748NO00 amended claims CC ACAPO ONSAGERS AS
 06.10.2025 08-01 Saksbehandling 20241071 INN Korrespondanse (Hovedbrev inn) ACAPO ONSAGERS AS
 05.09.2025 07-02 Saksbehandling 20241071 UT PT report 09:13:47
05.09.2025 07-01 Saksbehandling 20241071 UT Substantive examination ACAPO ONSAGERS AS
 05.06.2025 05-04 Saksbehandling 20241071 INN P29748NO00 Response to Office Action ACAPO ONSAGERS AS
 05.06.2025 05-03 Saksbehandling 20241071 INN P29748NO00 amended claims - clean ACAPO ONSAGERS AS
 05.06.2025 05-02 Saksbehandling 20241071 INN P29748NO00 amended claims - annotated ACAPO ONSAGERS AS
 05.06.2025 05-01 Saksbehandling 20241071 INN Korrespondanse (Hovedbrev inn) ACAPO ONSAGERS AS
 13.05.2025 04-02 Saksbehandling 20241071 UT PT report 09:45:03
13.05.2025 04-01 Saksbehandling 20241071 UT Substantive examination ACAPO ONSAGERS AS
 14.04.2025 03-02 Saksbehandling 20241071 INN P29748NO00 request expedited processing ACAPO ONSAGERS AS
 14.04.2025 03-01 Saksbehandling 20241071 INN Korrespondanse (Hovedbrev inn) ACAPO ONSAGERS AS
 28.10.2024 02-01 Saksbehandling 20241071 UT Infobrev til oppfinner ACAPO ONSAGERS AS
 28.10.2024 01-04 Saksbehandling 20241071 INN P29748NO00 Figures ACAPO ONSAGERS AS
 28.10.2024 01-03 Saksbehandling 20241071 INN P29748NO00 Description claims abstract ACAPO ONSAGERS AS
 28.10.2024 01-02 Saksbehandling 20241071 INN Archer Oiltools AS ACAPO ONSAGERS AS
 28.10.2024 01-01 Saksbehandling 20241071 INN Søknadsskjema Patent ACAPO ONSAGERS AS
 06-02 Saksbehandling 20241071 INN Korrespondanse (Hovedbrev inn) ACAPO ONSAGERS AS

Description, claims and drawings

Disclaimer: This text has been machine-scanned and may contain errors – please refer to "Publications" for legally binding content. Description
3499161A SEALING ASSEMBLY FOR USE IN A DOWNHOLE TOOL, A DOWNHOLE TOOL AND A METHOD FOR USING THE DOWNHOLE TOOLTECHNICAL FIELD5 The present invention relates to the oil and gas industry and in particular to a sealing assembly for use in a downhole tool, which is usable during a well intervention such as a plug and abandonment operation. In particular, the well intervention may involve a perforate, wash and cement operation. The invention also relates to the downhole tool and a method for using the downhole tool.10BACKGROUND OF THE INVENTIONThe efficacy of downhole tools utilized in well interventions, such as washing and cementing operations, hinges upon the integrity of, besides others, their sealing elements. These components serve to guarantee the proper isolation of wellbore 15 sections for the planned operation. These sealing elements are vulnerable to wear and tear, as they need to be transported down to the section(s) of the well where operations are to be carried out. Sealing cups or other sealing elements may wear out quickly during an axial motion in the well.US2221775A relates to a swab, washing tool and a packing assembly for the 20 washing tool. The swab includes a mandrel, sets of perforations, cup members fixed to periphery of the mandrel and expandable rubber packaging sleeve retained by the cups. Protection wires are provided along the outside of the packages, and a shield member receive and retains the ends of the wires. A packaging assembly for the swab and washing tool is also described. The packaging assembly includes support, 25 pair of spaced cups, several protective wires with their ends sealed for sling in shields and resilient packaging disposed in the cups and protected by the wire members and shield. The shield also includes a corrugated frusto-conical ring to receive the ends of the wires in the corrugations.It is therefore evident that there is a need for more durable sealing technologies that 30 can withstand the challenges abrasive wellbore conditions, and high-pressure or high-temperature environments. In order to extend the operational life of these components, reduce downtime, and enhance the efficiency of downhole washing and cementing operations, improvements in sealing material durability and mechanical design are required.35SUMMARY OF THE INVENTION 3499162In a first aspect, the present invention provides a sealing assembly for use in a downhole tool for well interventions, the sealing assembly comprising a sealing element arranged configured to be disposable on a tubular body, the sealing element being radially expandable and configurable between a radially unexpanded state and 5 a radially expanded state to form a seal against an inner surface of the wellbore. The sealing assembly comprises a protective structure arranged in an outer circumference of the sealing element, wherein the protective structure has a higher abrasion resistance than the at least one sealing element. The sealing assembly comprises a first support member and a second support member, wherein the sealing 10 element is arranged between the first support member and the second support member in an axial direction, and wherein the first support member and the second support member are axially movable relative to each other.The tubular body may be a tubular mandrel, e.g. a hollow cylinder, of the downhole tool. The tubular body may comprise an inner bore extending through the tubular 15 body. The expandable sealing element may be configured to expand when the fluid pressure within the inner more is increased. The tubular body may form a part of a tubing of the downhole tool and/or a part of the tubing of a well string to which the downhole tool is connected.By disposing the expandable sealing element on the tubular body, a seal against an 20 inner surface of the wellbore can selectively be created. In the radially expanded state, an outer diameter of the sealing element may be substantially equal the inner diameter of the wellbore when the downhole tool is deployed in the wellbore. Then, the protective structure arranged at an outer circumference of the sealing element comes into contact with the wellbore.25 The term “at an outer circumference of the sealing element”, when the sealing element may be a hollow-cylindrical body, refers to a spatial arrangement in which the protective structure is positioned at or near the exterior surface of the sealing element, specifically along its radial periphery. This configuration implies that the protective structure is distributed around the circumference of the sealing element, 30 either directly aligned with its outermost surface or in close proximity to it. The protective structure may be fully or partly embedded in the sealing element.In cases where the protective structure is “flush with the outer circumference”, it is situated such that the external surfaces of the protective structure are level with or form a continuous surface with the outer boundary of the sealing element. This 35 indicates that the protective structure does not extend beyond the outermost contour of the sealing element. Alternatively, the protective structure may protrude slightly over the outer circumference of the sealing element, meaning that the outer surfaces of the protective structure extends beyond the boundary of the sealing element by a small amount, creating an elevation relative to the cylindrical surface of the sealing 3499163element. Conversely, the phrase may also encompass a scenario in which the protective structure may be positioned beneath the outer surface of the sealing element, covered by a thin layer of the material of the sealing element, thus remaining within the material but still near the outer circumference. Preferably, the 5 protective structure lies within a range of -5% to 5% of the outer circumference of the sealing element.The term “abrasion resistance” is to be understood such that under conditions involving friction, wear, or mechanical interaction with wellbore surfaces, the protective structure is more capable of withstanding material loss or surface 10 degradation than the sealing element. The abrasion resistance refers to the ability of a material to resist being worn away or eroded when it comes into contact with another object or material through sliding, rubbing, or other forms of mechanical action.In this context, the comparison between the protective structure and the sealing 15 element suggests that the protective structure is composed of a material or has properties that enable it to endure such abrasive forces for a longer period or with less deterioration than the sealing element. This difference in performance could be attributed to factors such as the hardness, toughness, or surface treatment of the materials in question, all of which influence the rate at which material is removed 20 from their surfaces under abrasive conditions. Consequently, the protective structure will retain its structural integrity and functional properties longer than the sealing element when both are subjected to the same abrasive forces.Thus, the term “wherein the protective structure has a higher abrasion resistance than the sealing element” reflects a measurable disparity in the durability of the 25 materials in resisting wear, with the protective structure being more resistant to material loss. Preferably, the protective structure comprises a metal material such as a metal alloy, a steel, stainless steel, or an aluminium alloy. The protective structure may comprise high performance polymers, such as PE with particularly high molecular weight, aramid, ceramic materials (e.g. ceramic composites) or 30 another durable material that can withstand the harsh conditions of the wellbore.The sealing element has a lower abrasion resistance than the protective structure may comprise an elastomer material, e.g. a rubber material, such as a vulcanized elastomer. The elastomer may be a fiber reinforced elastomer.Due to its integration, the protective structure may provide the main contact 35 between the sealing assembly and the wellbore and then absorbs the majority of the abrasive effects from outside. Consequently, the protective structure mechanically shields the sealing element from damage and wear induced by a motion inside the wellbore. 3499164The term “selectively expandable” refers to its ability to be radially expanded to a radially expanded state when needed to provide a seal against the inner surface of the wellbore. However, this also implies that the sealing element may return to an initial, radially unexpanded state when the seal is not needed. In some examples the 5 sealing element returns to its unexpanded state due to elasticity of the sealing element.The sealing element may be able to selectively cycle between the radially unexpanded state and the radially expanded state. That means, the sealing element may be reconfigurable between the radially unexpanded state and the radially 10 expanded state repeatedly, e.g. while the downhole tool is deployed in a wellbore.In the radially expanded state, the outer diameter of the sealing element may, at least in sections, be less than the inner diameter of the wellbore. As such, the full circumference of the sealing element may not be in contact with the inner surface of the wellbore. Even if there is no full contact between the sealing element and the 15 inner surface of the wellbore, e.g. such that a certain leak of fluid across the sealing element is allowed, the sealing element may still provide sufficient sealing capabilities, or flow restricting capabilities, in order to carry out relevant well operations, as discussed further below.In the following, terms such as “sealing”, “sealing function”, “sealing capability” or 20 “flow restricting capability” may be interchangeably used to refer to the function of the sealing element in the expanded state, either when it is fully sealing or when it allows some leakage across, as discussed above.The sealing assembly is designed for use in a downhole tool for well interventions. The sealing assembly may be an active component of a flow guide that is capable of 25 selectively enclosing a region of the well at the downhole tool by actuation of the flow guide, i.e. the sealing assembly or the sealing assemblies included therein. For this, at least one sealing assembly is disposed on a tubular body of the downhole tool, such as a tubular mandrel. The sealing element of each sealing assembly may each define an annulus, or an annular region, around the tubular body.30 For example, if the flow guide assembly comprises one sealing assembly, then the associated sealing element may define one annulus around the tubular body. If the flow guide assembly comprises two sealing assemblies, then the associated two sealing elements may define one annulus each around the tubular body. Each annulus may be in fluid communication with the inner bore for urging the respective 35 sealing element towards the radially expanded state as fluid pressure in the inner bore is increased.The flow guide may be said to be “inactivated”, or to be in an “inactivated state”, when the associated sealing element(s) is/are in the radially unexpanded state. 3499165Furthermore, the flow guide may be said to be “activated”, or to be in an “activated state”, when the at associated sealing element(s) is/are in the radially expanded state. Thus, configuring the respective sealing element from the radially unexpanded state to the radially expanded state may be referred to as “activating” 5 the flow guide and/or “activating” the downhole tool. Furthermore, configuring the respective sealing element from the radially expanded state to the radially unexpanded state may be referred to as “deactivating” the flow guide and/or “deactivating” the downhole tool. Accordingly, the downhole tool may be able to selectively cycle between the activated state and the inactivated state, or put 10 differently, able to activate and deactivate repeatedly. As such, the downhole tool may be run into the wellbore in the deactivated state and then activated when the downhole tool is at a desired location in the well. Furthermore, the downhole tool may be deactivated, moved to a different location in the well, and then reactivated. The steps of deactivating, moving and reactivating the downhole tool may be 15 repeated as many times as desired during a single trip in a wellbore. The downhole tool may be deactivated before it is retrieved back to surface.The inactivated state is a configuration in which the flow guide, i.e. the sealing assembly or the sealing assemblies included therein, has a reduced radial extent and thus may have a radially outermost part of the flow guide moved inward toward a 20 center of the downhole tool. Preferably the radial extent of the flow guide can be reduced to be no more than the radial extent of other parts of the downhole tool. For example, the inactivated state may have a diameter of 40-70% of the activated state in which the flow guide may contact the casing of the well. Optionally, the inactivated state may have a diameter of 45-55% of the activated state, e.g. about 25 50% thereof. For example, for a downhole tool required to pass through a restriction of around 3 inches (about 7.6 cm) or 4 inches (about 10.2 cm) in diameter then the stowed configuration may be less than the restriction size whilst the deployed configuration may be perhaps 6-8 inches (about 15.2-20.3 cm), e.g. about twice the diameter of the stowed configuration.30 Activating the downhole tool may be achieved by increasing fluid pressure in the inner bore, and deactivating the downhole tool may be achieved by decreasing, e.g. releasing, fluid pressure in the inner bore. The axial movement of the downhole tool may result in a sliding or rubbing of the sealing assembly at the inner surface of the well. The sealing element of the sealing assembly is protected from mechanical 35 wear and tear through the protective structure as explained above.The protective structure may comprise a plurality of elongated flexible elements. The flexible elements may be provided in the form of rods or wires that can be flexed perpendicularly to their longitudinal axis. The flexible elements may be arranged to be parallel to a longitudinal axis of the sealing element in the40 unexpanded state. They may be regularly or irregularly staggered in the outer 3499166circumference of the sealing element. In an unexpanded state of the sealing element, the flexible elements may be arranged in a circumferentially equidistant manner, i.e. consecutive flexible elements have the same distance to each other in a circumferential direction. The flexible elements allow to follow the general shape of 5 the sealing element, while maintaining their location in the outer circumference of the sealing element. The flexible elements may comprise a cross-sectional surface that is constant along their extension. They may be placed in a constant radial distance to a central axis of the sealing element in an unexpanded state. A radial outermost part of the flexible elements may come into contact with the inner surface 10 of the wellbore, thus protecting the sealing element from wear and tear.The support members may be configured to be placeable onto the tubular body mentioned above. By their relative axial motion a controlled expansion of the sealing element can be supported. When expanding the sealing element, at least one of the support members could axially move to compensate the radial expansion of 15 the sealing element, with which an axial contraction is induced. The support members may be arranged in direct contact with axial ends of the sealing element. Preferably, the sealing element is sandwiched between the first support member and the second support member. The sealing element may be attached to at least one of the support members. It may depend on the material of the sealing element how this 20 is done. For example, the sealing element may be vulcanized to the respective support member. One of the support members may be axially fixable to the tubular body.The sealing element may be a hollow-cylindrical element comprising an elastomer. The elastomer may be a vulcanized elastomer, e.g. a vulcanized rubber. The25 elastomer may include natural and synthetic rubber materials. Additionally, or alternatively, the elastomer may be a fiber reinforced elastomer. Additionally, or alternatively, the elastomer may be metal reinforced, e.g. steel reinforced , elastomer. Elastomers are commonly used in sealing applications due to their flexibility and resilience to accommodate a wide range of wellbore conditions, 30 including temperature and pressure variations.A radial outer side of the protective structure may be substantially flush with a radial outer surface of the sealing element or may radially protrude over it. The term “substantially” is to be understood that a small material layer of the sealing element may be present radially outside of the protective structure. This may be caused by 35 the manufacturing process, e.g. when the protective structure is vulcanized into the sealing element. The remaining material layer radially outside the protective structure may, however, be insignificant and the remaining amount of material may correspond to a maximum of 1% to 2% of the outer diameter of the sealing element. This remaining material layer may be worn away the first time the downhole tool 40 with the included sealing assembly is used. This placement of the protective 3499167structure ensures that it provides adequate coverage and protection for the sealing element. Depending on the size or distribution of the protective structure on the outer surface of the sealing element, the exposure of the sealing element to the abrasive surface of the wellbore can be reduced, minimized, or completely5 prevented.The elongated flexible elements may be steel wires. The steel wires may be attached to the support members and/or to the sealing element, as exemplarily described further below. The steel wires provide a robust protection to the sealing element. They may extend over the whole length of the sealing element. Due to their design, 10 they allow to bend and thus follow the deformation of the at sealing element when being expanded. Also, they provide a mechanical reinforcement of the sealing element, thereby enhancing the overall strength and durability of the sealing assembly. The steel wires may have a diameter of a few millimeters, e.g. 2, 3, 4, 5 or 6 mm. Their diameter may, however, be chosen to be smaller or larger,15 depending on the overall size of the sealing element and other parameters.Ends of the flexible elements may be inserted into recesses of the first support member and the second support member. The recesses of one of the support members may be directly opposed to the recesses of the other one of the support members. The recesses may comprise an opening extension parallel to a central axis 20 of the at least one sealing element. When the flexible elements are attached to the sealing element, opposite ends of the steel wires do not need to be attached to the support members. They may merely be inserted into a pair of two opposed recesses. When the sealing element is expanded, the flexible elements follow the expansion motion by bulging out or buckling, carried by the at least one sealing element and 25 supported by the recesses in contact with the ends of the flexible elements.The flexible elements may be attached to the first support member and the second support member. This may be accomplished by welding, gluing, clamping, screwing or through other attachment processes. When the flexible elements are attached to the support members, they may rest on the outer surface of the sealing element, 30 without any further attachment thereto.The flexible elements may be vulcanized into the material of the sealing element. Thus, the flexible elements are held by the sealing element and follow the radial expansion and contraction of the sealing element. An additional attachment of the flexible elements to the support members may not be required to hold them in the 35 sealing assembly reliably.The first support member and the second support members may be rotatably held on the tubular body. In other words, the first support member and the second support member are not rotationally fixed. This reduces mechanical constraints on the sealing element, allowing for smoother operation and reduced wear. In addition, it 3499168reduces the manufacturing effort, as the support members may simply be placed , pushed or plugged onto the tubular body.The first and second support members may be secured by a collar, a ring or another mechanical stopper that prevents the support members from leaving a predetermined 5 section of the tubular body. Thereby, it may be ensured that the support members remain in correct positions during operation, maintaining the integrity of the sealing assembly. The collar may be integral to the tubular body. Alternatively, the mechanical stopper may be provided in the form of a separate, dedicated component that may be placed on the tubular body and be secured thereto, e.g. by a mechanical 10 fastening element, by welding or the like.It is also proposed a downhole tool for well interventions, comprising a tubular body with an inner bore and at least one flow opening for fluid communication between the inner bore and a region outside the downhole tool, and at least one sealing assembly according to the above disposed on the tubular body. The sealing 15 assembly may thus be part of a downhole tool.The tubular body may be a tubular mandrel with an inner bore and at least one flow opening for fluid communication between the inner bore and a region outside the downhole tool. The inner bore may extend through the tubular body. The tubular body may form a part of a tubing of the downhole tool and/or a part of the tubing of 20 a well string to which the downhole tool is connected. The inner bore may be a through-going bore, i.e. such that both axial ends of the tubular body are open or give access to an inner volume of the tubular body. Alternatively, one of the axial ends may be blocked, or closed, so that the volume can only be accessed from one axial end. The tubular body may be a single, uniform part or may comprise several 25 parts that are connected together to form the tubular body. In addition, each axial end of the tubular body may comprise a connection element for connecting the downhole tool to another downhole tool, or to a suitable conveyance means, as discussed further below. The connection elements may be threaded connections as known in the art.30 As explained further above, the sealing assembly may be an active component of a flow guide of the downhole tool. The downhole tool may comprise at least one flow guide. For example, the downhole tool comprises two individual flow guides. In certain embodiments, the flow guide may comprise two sealing assemblies, wherein each of the two sealing elements may be disposed on the tubular body. The sealing 35 elements of the sealing assemblies are configurable between a radially unexpanded state and a radially expanded state. The two sealing assemblies may be located adjacent to each other, e.g. axially adjacent to each other on the tubular body. The distance between the sealing assemblies may be less than 2 meters, e.g. between 0,2 - 1 meter. 3499169The downhole tool may comprise a pressure regulator configured to allow fluid communication between the inner bore and the region outside the downhole tool, via the at least one flow opening, when fluid pressure in the inner bore reaches a threshold pressure.5 When the flow guide, and thus the downhole tool, is in the activated state, the downhole tool may provide a barrier, or a sealing function, in the wellbore, e.g. by preventing fluid flow across the respective radially expanded sealing element, or by sufficiently preventing fluid flow across the respective sealing element, as discussed above (i.e. providing sufficient sealing / flow restricting capabilities). Thus, fluid 10 may be sufficiently prevented from flowing between a location above the respective sealing element and a location below the respective sealing element in the wellbore, e.g. to perform operations such as integrity testing, fracturing, washing and/or cementing.The downhole tool may be deployed in the wellbore by a suitable conveyance 15 means. The conveyance means may be a tubing, such as a coiled tubing or a drill pipe string. The downhole tool may be connected directly to the tubing, or, to an intermediate tool between the downhole tool and the tubing, e.g. through one of the connections of the tubular body. Thus, fluid under pressure may be supplied from surface through the tubing in order to activate the downhole tool. The intermediate 20 tool may e.g. be a perforating tool, such as a mechanical perforating tool, a measurement/logging tool or any other downhole tool necessary to carry out a relevant well operation.As discussed above, the tubular body may comprise at least one flow opening for fluid communication between the inner bore and a region outside the downhole tool.25 The flow opening may be a radial flow opening formed in the tubular body, such that fluid may flow radially between the inner bore and the region outside the downhole tool. When the downhole tool is deployed in a wellbore, the region outside the downhole tool may be a region in the wellbore. As such, the downhole tool may be used for conveying, or supplying, fluid to the wellbore.30 The downhole tool may comprise a first flow guide and a second flow guide, wherein the at least one flow opening may be located axially between the first flow guide and the second flow guide. The second flow guide may be equal, or similar, to the first flow guide. Thus, the flow opening may allow fluid communication between the inner bore of the tubular body and a region outside the downhole tool 35 between the first and second flow guides. When the downhole tool is deployed in a wellbore, fluid may thus be supplied through, or via, the flow opening to a region in the wellbore between the first and second flow guides. The distance between the first and second flow guides may be less than 3 meters, e.g. between 0,3 - 2 meters. Alternatively, the distance between the first and second flow guides may be 34991610between 5-25 diameters of the tubular body, between 5-20 diameters of the tubular body, between 10-15 diameters of the tubular body, e.g. 12 diameters of the tubular body. If the distance between the flow guides becomes too large, it may affect the performance of the downhole tool, e.g. when used for washing operations as will be 5 discussed further below. For example, as the distance between the flow guides increases, the speed with which the fluid passes, or exits, the perforations in the casing decreases for the same flow rate since the total flow area through the casing increases. This may reduce the washing effect.The region in the wellbore may be defined, at least in part, by the tubular body, the 10 first and second flow guides and the surrounding wellbore in which the downhole tool is deployed. The wellbore may comprise a tubing in which the downhole tool is deployed. The tubing may e.g. be a casing, a liner or a production tubing. Thus, the region in the wellbore may be defined, at least in part, by the tubular body, the first and second flow guides and the surrounding tubing in which the downhole tool is 15 deployed.When the downhole tool is activated, it may enclose a section of the wellbore around the downhole tool in order to allow for increased pressure in that section of the wellbore during supply of fluid by the downhole tool, e.g. by that the sealing elements provide a sealing function. The section of the wellbore may be the region 20 in the wellbore as described above. As such, the first and second flow guides may allow for the section of the wellbore to be selectively enclosed by activation and deactivation of the first and second flow guides.In some embodiments, the well intervention may be carried out as part of a plug and abandonment (P&A) operation. For example, the well intervention may be a so-25 called perf, wash and cement (PWC) operation. As such, the tubing (i.e., e.g. a casing, a liner or a production tubing) may be a perforated tubing, and the downhole tool may be suitable for carrying out a washing operation and/or a plugging operation. Thus, the downhole tool may be a washing and/or a plugging tool.Typically, cement is used as a plugging material. The tool may therefore generally 30 be referred to as a washing and/or cementing tool without any restriction being implied in terms of the plugging material the downhole tool is configured to convey. The term “cement” will be used herein without excluding any other suitable plugging materials.The tool may be configured for washing and/or cementing an annulus outside the 35 tubing by forcing fluid conveyed from surface through the perforations in the tubing and into the annulus. This may be achieved when the downhole tool is in the activated state. The annulus may be formed between two strings of tubing, e.g. between two casings, or between a production tubing and a surrounding casing. The annulus may also be formed between a tubing and a surrounding rock formation. 34991611Where the wellbore comprises two tubing strings and thus two annuli at the same depth/location in the well, i.e. because one tubing string is surrounding the other, then both tubing strings may be perforated. In that situation, the downhole tool may be configured for washing and/or cementing both annuli. The wellbore may also 5 comprise more than two perforated tubing strings and thus the tool may be configured for washing all the accessible annuli.It will be appreciated that the flow guides may be activated with different levels of force, e.g. by adjusting the fluid pressure in the inner bore. This may be achieved by regulating a pump pressure of a surface pump, such as a mud pump. In this way, the 10 downhole tool may be configured to adapt the level of force according to the nature of the well intervention, the nature of the fluid to be contained between the flow guide assemblies and/or the characteristics of the wellbore. In this way, the downhole tool may have a first activated state in which the force exerted by the sealing element(s) against the wellbore is set at a first, higher, level to increase the 15 integrity of the seal provided by the first and second flow guides (e.g. for static operations when the downhole tool is stationary in the well), and a second activated state in which the force exerted by the sealing element(s) against the wellbore is set at a second, lower, level to reduce an anchoring force provided by the first and second flow guides (e.g. for dynamic operations when the downhole tool may move 20 within the wellbore whilst fluid is still enclosed at increased pressure in the section of the well between the first and second flow guides). This may lower friction and reduce wear on the sealing elements during dynamic operations.Therefore, the downhole tool may be suitable for carrying out dynamic washing and/or cementing operations. As such, the downhole tool may be a dynamic25 washing and/or cementing tool. The tool may thus be configured to move in the wellbore while activated (i.e. when the sealing elements are in the radially expanded state) and while conveying fluids to the region outside the downhole tool between the first and second flow guide assemblies. In this way, the downhole tool may be used to wash and cement a perforated section of a wellbore. The perforated section 30 may e.g. be at least 30 meters long, at least 50 meters long, e.g. about 100 meters long. The tool may be configured to be activated at the bottom of the perforated section and then pulled upwards along the perforated section while conveying fluids. As the flow guide assemblies are activated, a section of the wellbore around the downhole tool is enclosed such that pressure is allowed to increase, as discussed 35 above. The conveyed fluid is thus forced through the perforations formed in the tubing and into the surrounding annulus (or annuli). The sealing element(s) of the downhole tool is/are protected from excessive wear and tear through the protective structure particularly during the dynamic washing and/or cementing operations. It will be appreciated that, due to the selectively expandable sealing element(s), the 40 downhole tool may pass narrow restrictions in the wellbore that would otherwise 34991612not have been possible to pass with common devices. When passing these restrictions, the protective structure protects the sealing element(s), too.As indicated above, the downhole tool may comprise an activation mechanism configured to selectively feed a pressurized fluid into a gap between the tubular 5 body and the sealing element to selectively expand the sealing element.The downhole tool may be configured for use in plug and abandonment operations. The downhole tool may preferably be configured to perform a perforate, wash, and cement operation.As explained above, the downhole tool may comprise at least one flow guide, 10 wherein the respective flow guide comprises one or more of the at least one sealing assembly.The downhole tool may comprise a first flow guide and a second flow guide.One or both of the first flow guide and the second flow guide may comprise two sealing assemblies.15 The at least one sealing assembly may be able to selectively cycle between the radially unexpanded state and the radially expanded state.Each sealing element defines an annulus around the tubular body, and wherein each annulus is in fluid communication with the inner bore for urging the at least one sealing element toward the radially expanded state as fluid pressure in the inner 20 bore is increased.The tubular body may comprise a pressure coupling opening for supplying fluid under pressure to the annulus(es) defined by the sealing element(s).If the first and second support members as described above are used, one of the support members may be axially fixed to the tubular body.25 The threshold pressure mentioned above may be configured such that the sealing element is in the radially expanded state before fluid communication between the inner bore and the region outside the downhole tool is allowed.The pressure regulator may comprise a pressure valve.The pressure regulator may have a closed configuration and an open configuration, 30 wherein the pressure regulator may be configured to prevent fluid communication between the inner bore and the region outside the downhole tool in the closed configuration, wherein the pressure regulator may be configured to allow communication between the inner bore and the region outside the downhole tool in 34991613the open configuration, and wherein the pressure regulator may be able to selectively cycle between the closed configuration and the open configuration.The pressure regulator may comprise a sleeve configured for axial displacement with respect to the tubular body between a closed position and an open position for 5 configuring the pressure regulator between the closed configuration and the open configuration, respectively.The pressure regulator may comprise a pressure chamber, wherein the pressure chamber may be in fluid communication with the inner bore through the at least one flow opening, and wherein the pressure regulator may comprises one or more ports 10 configured to allow fluid communication between the pressure chamber and the region outside the downhole tool when the sleeve is in the open position, thereby allowing fluid communication between the inner bore and the region outside the downhole tool.It is further proposed a method of using a downhole tool according to the above, the 15 method comprising deploying the downhole tool in a wellbore, activating the downhole tool by bringing the sealing element of the at least one sealing assembly in the radially expanded state, and conveying fluid to the wellbore by increasing fluid pressure in the inner bore to at least a threshold pressure.The downhole tool may be a tool as described in the applicant’s co-pending20 application NO20241031, which is hereby incorporated by reference. The downhole tool may comprise an upper sealing assembly and a lower sealing assembly for enclosing a section of the well in order to allow for increased pressure in that section of the well during supply of fluid by the downhole tool. The sealing assemblies comprise retractable sealing elements providing activatable flow guides 25 for allowing for the region of the well at the downhole tool to be selectively enclosed by actuation of the activatable flow guides. The activatable flow guides may be configured to move between at least one deployed configuration and at least one stowed configuration in which at least one deployed configuration allows for the activatable flow guides to form a pressure containing barrier around the30 downhole tool and the at least one stowed configuration is a configuration in which the activatable flow guides have a reduced radial extent. The activatable flow guides may be configured to have a first deployed configuration in which the force exerted by the activatable flow guides against a casing of the well is set at a first, higher, level to increase the integrity of the seal provided by the upper and lower 35 sealing assemblies for static operations when the downhole tool is stationary in the well, and a second deployed configuration in which the force exerted by the activatable flow guides against the casing of the well is set at a second, lower, level to reduce an anchoring force provided by the upper and lower sealing assemblies for dynamic operations when the downhole tool may move within the well whilst fluid 34991614is still enclosed at increased pressure in the section of the well between the upper sealing assembly and lower sealing assembly.The activatable flow guides may be configured to be actuated via changes in pressure within a tubing of the downhole tool and wherein the downhole tool may 5 be configured to vary the level of force exerted by the activatable flow guides by control of the pressure within the tubing.The downhole tool may be configured to adapt the level of force exerted by the activatable flow guides according to the nature of the well intervention, the status of the downhole tool, the nature of the fluid to be contained between the activatable 10 flow guides and/or the characteristics of the casing.The upper and lower sealing assemblies may be above and below one or more fluid outlets for the supply of fluid at the downhole tool.The downhole tool may comprise a pressure regulator configured to allow fluid communication between an inner bore of a tubing of the downhole tool and the 15 region outside the downhole tool, via the fluid outlet(s), when fluid pressure in the inner bore reaches a threshold pressure; wherein the threshold pressure may be configured such that the activatable flow guides are in a deployed state before fluid communication between the inner bore and the region outside the downhole tool is allowed.20 The activatable flow guides may be active elements capable of controlled movement and do not rely on forces external to the downhole tool to move them.The downhole tool may comprise an actuation mechanism for actuation of the activatable flow guides.As stated above, the activatable flow guides may comprise deployable elastomer 25 elements and/or retractable cups.The downhole tool may comprise tubing with an inner bore and at least one fluid outlet for fluid communication between the inner bore and a region outside the tubing; wherein the upper and lower sealing assemblies may include activatable flow guides including a radially expandable barrier member arranged around the 30 tubing and configurable between a radially unexpanded state as the stowed configuration and radially expanded states as the deployed configurations.Each of the activatable flow guides may comprise a pair of barrier members located adjacent to one another.The barrier member may define an annulus around the tubing, wherein the annulus 35 is in fluid communication with the inner bore for allowing increased fluid pressure 34991615in the inner bore to urge the barrier member toward the radially expanded state as fluid pressure in the inner bore is increased.The barrier member may comprise a vulcanized elastomer.It is additionally proposed a method for use during a well intervention, the method 5 using a downhole tool comprising an upper sealing assembly and a lower sealing assembly for enclosing a section of the well in order to allow for increased pressure in that section of the well during supply of fluid by the downhole tool, wherein the sealing assemblies may comprise retractable elements providing activatable flow guides for allowing for the region of the well at the downhole tool to be selectively 10 enclosed by actuation of the activatable flow guides, and wherein the activatable flow guides may be configured to move between at least one deployed configuration and at least one stowed configuration in which at least one deployed configuration allows for the activatable flow guides to form a pressure containing barrier around the downhole tool and the at least one stowed configuration is a configuration in 15 which the activatable flow guides have a reduced radial extent; wherein the activatable flow guides may be useable in a first deployed configuration in which the force exerted by the activatable flow guides against a casing of the well is set at a first, higher, level to increase the integrity of the seal provided by the upper and lower sealing assemblies, and useable in a second deployed configuration in which 20 the force exerted by the activatable flow guides against the casing of the well is set at a second, lower, level to reduce an anchoring force provided by the upper and lower sealing assemblies; and wherein the method may include using the second deployed configuration for one or more dynamic operations including movement of the downhole tool in the well whilst fluid is still enclosed at increased pressure in 25 the section of the well between the upper sealing assembly and lower sealing assembly.The sealing assemblies may be configured in the stowed configuration while running the downhole tool into and out of the well and configured in the deployed configuration when the downhole tool is at a position in the well where a well 30 intervention operation is to be performed.The second deployed configuration may allow for dynamic operations such as washing or cementing whilst the downhole tool is moving along the well.The method may comprise using the first deployed configuration, with a higher level of force against the casing, for one or more static operations when the35 downhole tool is held stationary in the well.The method may comprise actuating the activatable flow guides via changes in pressure within a tubing of the downhole tool and varying the level of force varied by control of the pressure within the tubing. 34991616The method may comprise adapting the level of force in the first deployed configuration and/or the second deployed configuration according to the nature of the well intervention, the status of the downhole tool, the nature of the fluid to be contained between the activatable flow guides and/or the characteristics of the 5 casing.The method may comprise supplying fluid at the downhole tool using one or more radial holes or other fluid pathways located in between the upper and lower sealing assemblies.The method may comprise using a pressure regulator configured to allow fluid 10 communication between an inner bore of tubing of the downhole tool and the well when fluid pressure in the inner bore reaches a threshold pressure; wherein the threshold pressure is configured such that the activatable flow guides are activated before the pressure regulator allows fluid communication between the inner bore and the well.15 The method may comprise the use of a downhole tool as described above.BRIEF DESCRIPTION OF FIGURES:Certain embodiments of the present invention will now be described by way of example only and with reference to the accompanying drawings in which:20 Fig. 1a shows a first exemplary embodiment of a sealing assembly in a lateral view in an inactivated state.Fig. 1b shows the sealing assembly of Fig. 1a in a lateral sectional view in an inactivated state.Fig. 1c shows the sealing assembly of Fig. 1a in a lateral sectional view without 25 elastomer in an inactivated state.Fig. 1d shows the sealing assembly of Fig. 1a in a perspective transparent view in an inactivated state.Fig. 2a shows a second exemplary embodiment of a sealing assembly in a lateral view in an inactivated state.30 Fig. 2b shows the sealing assembly of Fig. 2a in a lateral sectional view in an inactivated state.Fig. 2c shows the sealing assembly of Fig. 2a in a lateral sectional view without elastomer in an inactivated state. 34991617Fig. 2d shows the sealing assembly of Fig. 2a in a perspective transparent view in an inactivated state.Figs. 2e and 2f show two sectional views of the sealing assembly of Fig. 2a.Fig. 3 shows a part of a downhole tool using the sealing assembly.5DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS:Fig. 1a shows a first exemplary embodiment of a sealing assembly 2 for a downhole tool for well interventions. The sealing assembly 2 comprises a sleeve-shaped sealing element 4 made of an elastomeric material. The sealing element 4 may 10 preferably be made of a vulcanized elastomeric material. The sleeve shape may be understood as a hollow-cylindrical shape. The sealing element 4 may be disposed on a tubular body, which may be a tubular mandrel, which is not shown in this figure. The sealing element 4 is selectively expandable radially outwards to form a seal against an inner surface of a wellbore when deployed within the wellbore.15 The sealing assembly 2 comprises a first support member 6 and a second support member 8. Exemplarily, the second support member 8 is fixable to the tubular body and the first support member 6 is movable. In the present example, the sealing element 4 is attached to both support members 6 and 8 through vulcanized bonding. In the depicted example, the fixable second support member 8 has the shape of a 20 ring and is axially fixable. The first support member 6 has the shape of a sleeve and is configured to be axially movable relative to the tubular body. However, the first support member 6 may also comprise a ring shape.On an axial end section 12 of the first support member 6 that is directed towards the sealing element 4, the first support member 6 has a series of recesses 10. The 25 recesses 10 circumferentially extend around the end section 12 and protrude radially into a circumferential surface of the end section 12. They are distributed in a circumferentially equidistant manner. An axial end section 14 of the second support member 8 has a mirrored arrangement of recesses 10 and faces to the axial end section 12 of the first support member 6.30 As depicted in Fig. 1b, a protective structure 16 having a plurality of flexible elements exemplarily provided in the form of steel wires 18. It is to be understood that another protective structure and/or another material may be used. The protective structure 16 shall have a higher abrasion resistance than the elastomer of the sealing element 4.35 The steel wires are exemplarily integrated into an outer circumference 20 of the sealing element 4. Exemplary, the steel wires 18 are vulcanized into the sealing 34991618element 4 and axially protrude over the sealing element 4 to reach into the recesses 10 of both support members 6 and 8. The steel wires 18 are arranged to be parallel to a longitudinal axis 22 of the sealing assembly 2 and are distributed over the outer circumference 20 in a circumferentially equidistant manner. The protective structure 5 16 serves to mechanically protect the sealing element 4 from excessive abrasion during a well intervention.In Fig. 1c, the sealing assembly 2 is shown with the elastomeric material from the sealing element 4 being eliminated in the view. Here, the arrangement of the steel wires 18 axially extending from between the support members 6 and 8 is10 demonstrated. The steel wires 18 span a cylindrical surface between the support members 6 and 8.In Fig. 1d, the sealing assembly 2 is shown in a perspective and transparent view. It comprises a hollow center 24 that allows to place the sealing assembly onto a tubular body, such as a mandrel, which is shown in Fig. 3 further below.15 Figs. 2a to 2f show a modified sealing assembly 25 with a first support member 26 and a second support member 28 that have a slightly modified design. Here, the support members 28 comprise recesses 30 that do not extend through an outer circumferential surface of the support members 26 and 28 in the radial direction, but exemplarily extend from annular end faces 32 and 34 into the respective support 20 member 26 and 28 to receive the ends of the steel wires 18. The recesses 30 are exemplarily formed as blind holes. The sealing element 4 may be bonded to the support members 26 and 28 in the same manner as in the previous figures.In Fig. 2e, the recesses 30 are shown in a front view.Fig. 2f shows the sealing element 4 with the protective structure 16 being25 vulcanized into the outer circumference 20 of the sealing element 4.Fig. 3 shows a part of an exemplary downhole tool 36 in a lateral sectional view. The downhole tool 36 may be referred to as a washing tool, or a washing and cementing tool, and may be used for dynamic washing and/or cementing operations, e.g. in conjunction with PWC operations.30 The downhole tool 36 comprises a tubular mandrel 38 comprising an inner throughgoing bore 40. When the downhole tool 36 is deployed in a wellbore, the left-hand side of the figure (when viewed in the orientation of the reference numbers) would be the up-hole direction, i.e. towards the upper end, and the right-hand side of the figure (when viewed in the orientation of the reference numbers) would be the 35 down-hole end, or the lower end.The mandrel 38 comprises an upper connection (not shown) for connecting the downhole tool 36 to a suitable conveyance means (not shown), either directly or via 34991619another downhole tool. The suitable conveyance means allows fluid to be conveyed to the downhole tool 36 and can e.g. be a coiled tubing string or a drill pipe string. At an opposite end to the connection, the mandrel 36 is connected to an end piece 42. The end piece 42 exemplarily comprises a ball seat 44 and axial flow openings 5 46. Fluid may flow between the inner bore 40 and the outside of the downhole tool 36 through the axial flow openings 46. In other examples, the mandrel 38 may comprise a lower connection, instead of an end piece. The lower connection may be a threaded pin connection. Thus, the downhole tool may be connected to another downhole tool through the lower connection.10 The downhole tool 36 comprises flow guide 48, which may also be referred to as lower flow guide assembly. The flow guide 48 comprises two sealing assemblies 2 and is exemplarily arranged around the mandrel 38.As implied by the term “lower flow guide assembly”, the downhole tool 36 may comprise an upper flow guide assembly, too, which may be designed similar to the 15 flow guide 48. If two flow guides 48 are used on the downhole tool 36, they may be referred to as first flow guide and second flow guide. The first and second flow guides may be axially spaced apart along the mandrel 38 and may be positioned on each side of a flow opening 50. The illustration of Fig. 3 focuses on the flow guide 48 beneath the flow opening 50.20 The flow opening 50 is provided in the form of a radial flow port formed in the mandrel 38. The radial flow port 38 allows fluid communication between the inner bore 40 of the mandrel 38 and an area outside the downhole tool 36 via a pressure regulator (not shown). Although only one radial flow port 50 is shown, the mandrel 38 may comprise additional radial flow ports that allow fluid communication 25 between the inner bore 40 and the area outside the downhole tool 36 via the pressure regulator.To configure the downhole tool 36 in the activated state, a ball 52 is dropped and landed in the ball seat 44 of the end piece 42. When the ball 52 has landed in the ball seat 44, it blocks the inner bore 40 of the mandrel 38 and prevents fluid to flow 30 from the inner bore 40 to the outside of the downhole tool 36 through the axial flow openings 46. Now, by establishing fluid flow and then increasing the flow rate (e.g. by a mud pump on the surface), the fluid pressure in the inner bore 40 can be increased to activate the tool.As pressure is increased in the inner bore 40, fluid enters annuluses 54 between the 35 mandrel 38 and the sealing elements 4 through radial ports 56 formed in the mandrel 38 in the area where each sleeve-shaped sealing element 4 is positioned around the mandrel 38. As fluid enters the annuluses 54 it applies a force to the inside of the elastomer elements 4, thereby causing them to inflate and expand 34991620radially outwards. Thus, it can be said that the elastomer elements 4 are urged toward the radially expanded state by action of an internal force.During the expansion of the sealing elements 4, the first support members 6 and the second support members 8 have moved axially toward each other. By having 5 movable support members 6 and 8, the sealing elements 4 may expand radially without being excessively stretched or torn. This may preserve the characteristics of the sealing elements 4 over a longer period of time and thus improve the durability of the sealing elements 4. Excessive motion of the support members 6 and 8 is prevented by stoppers 58 arranged on the mandrel 38. The second support member 8 10 of the upper sealing assembly 2 may be fixed to the mandrel 38 and thus only the first support member 6 of the upper sealing assembly 2 can move in an axial direction. Both support members 6 and 8 of the lower sealing assembly 2 may be axially movable and be stopped by the stoppers 58.The protective structure 16 arranged at the outer circumference 20 of the sealing 15 elements 4 follow the expansion motion of the sealing elements 4 and provide a main contact with a wellbore. 34991621REFERENCE NUMERALS2 sealing assembly4 sealing element6 first support member 5 8 second support member 10 recess12 end section14 end section16 protective structure 10 18 steel wire20 outer circumference 22 longitudinal axis24 hollow center25 sealing assembly15 26 first support member 28 second support member 30 recess32 annular end face34 annular end face20 36 downhole tool38 mandrel40 inner bore42 end piece44 ball seat25 46 axial flow opening48 flow guide 3499162250 flow opening 52 ball54 annulus 56 radial port 5 58 stopper
Claims
34991623CLAIMS1. A sealing assembly (2, 25) for use in a downhole tool (36) for well interventions, the sealing assembly (2, 25) comprising a sealing element (4) 5 configured to be disposable on a tubular body (38), the sealing element (4) being selectively expandable radially outwards to form a seal against an inner surface of the wellbore,wherein the sealing assembly (2, 25) comprises a protective structure (16) arranged at an outer circumference of the sealing element (4),10 wherein the protective structure (16) has a higher abrasion resistance than the sealing element (4),wherein the sealing assembly (2, 25) comprises a first support member (26) and a second support member (28),wherein the sealing element (4) is arranged between the first support member 15 (26) and the second support member (28) in an axial direction, and characterized in that the first support member (26) and the second support member (28) are axially movable relative to each other.2. The sealing assembly (2, 25) according to claim 1,20 wherein the protective structure (16) comprises plurality of elongated flexible elements (18).3. The sealing assembly (2, 25) according to claim 2,wherein ends of the flexible elements (18) are inserted into recesses (10, 30) 25 of the first support member (26) and the second support member (28).4. The sealing assembly (2, 25) according to claim 3,wherein the flexible elements (18) are attached to the first support member (26) and the second support member (28).305. The sealing assembly (2, 25) according to any of the preceding claims, wherein the sealing element (4) is a hollow-cylindrical element comprising an elastomer.35 6. The sealing assembly (2, 25) according to any of the preceding claims,wherein a radial outer side of the protective structure (16) is substantially flush with a radial outer surface of the sealing element (4) or radially protrudes over it.349916247. The sealing assembly (2, 25) according to claim 2, 3 or 4,wherein the flexible elements (18) are steel wires (18).8. The sealing assembly (2, 25) according to any of claims 2, 3, 4 or 7, 5 wherein the flexible elements (18) are vulcanized into the material of the sealing element (4).9. The sealing assembly (2, 25) according to any of the preceding claims, wherein the first support member (26) and the second support member (28) 10 are rotatably held on the tubular body (38).10. The sealing assembly (2, 25) according to any of the preceding claims, wherein the first support member (26) and the second support member (28) are secured by a collar, a ring or another mechanical stopper (58) that prevents the 15 support members (26, 28) from leaving a predetermined section of the tubular body (38).11. A downhole tool (36) for well interventions, comprising:- a tubular body (38) with an inner bore and at least one flow opening for fluid 20 communication between the inner bore and a region outside the downhole tool (36), and- at least one sealing assembly (2, 25) according to any of the preceding claims disposed on the tubular body (38).25 12. The downhole tool (36) according to claim 11, comprising an activation mechanism configured to selectively feed a pressurized fluid into a gap (54) between the tubular body (38) and the sealing element (4) to selectively expand the sealing element (4).30 13. The downhole tool (36) according to claim 11 or 12, wherein the downhole tool (36) is configured for use in a plug and abandonment operation.14. A method of using a downhole tool (36) according to any of claims 11 to 13, the method comprising:35 - deploying the downhole tool (36) in a wellbore,- activating the downhole tool (36) by bringing the sealing element (4) of the at least one sealing assembly (2, 25) in the radially expanded state, and - conveying fluid to the wellbore by increasing fluid pressure in the inner bore to at least a threshold pressure.4034991625PATENTKRAV1. En tetningssammenstilling (2, 25) for bruk i et nedihullsverktøy (36) for brønnintervensjoner, hvor tetningssammenstillingen (2, 25) omfatter et tetningselement (4) konfigurert til å være anordnet på et rørformet legeme (38), 5 hvor tetningselementet (4) er selektivt ekspanderbart radielt utover for å danne en tetning mot en indre overflate av brønnhullet,hvor tetningssammenstillingen (2, 25) omfatter en beskyttelsesstruktur (16) anordnet ved en ytre omkrets av tetningselementet (4), hvor beskyttelsesstrukturen (16) har en høyere slitasjemotstand enn tetningselementet (4),10 hvor tetningssammenstillingen (2, 25) omfatter et første støtteelement (26) og et andre støtteelement (28),hvor tetningselementet (4) er anordnet mellom det første støtteelementet (26) og det andre støtteelementet (28) i en aksial retning, ogkarakterisert ved at det første støtteelementet (26) og det andre støtteelementet (28) 15 er aksielt bevegelige i forhold til hverandre.2. Tetningssammenstillingen (2, 25) ifølge krav 1, hvor beskyttelsesstrukturen (16) omfatter et flertall av langstrakte fleksible elementer (18).3. Tetningssammenstillingen (2, 25) ifølge krav 2, hvor ender av de fleksible elementene (18) er innført i fordypninger (10, 30) i det første støtteelementet (26) 20 og det andre støtteelementet (28).4. Tetningssammenstillingen (2, 25) ifølge krav 3, hvor de fleksible elementene (18) er festet til det første støtteelementet (26) og det andre støtteelementet (28).5. Tetningssammenstillingen (2, 25) ifølge et av de foregående krav, hvor tetningselementet (4) er et hul-sylindrisk element omfattende et elastomer.25 6. Tetningssammenstillingen (2, 25) ifølge et av de foregående krav, hvor en radial ytre side av beskyttelsesstrukturen (16) er i det vesentlige i flukt med en radial ytre overflate av tetningselementet (4) eller stikker radielt ut over den.7. Tetningssammenstillingen (2, 25) ifølge krav 2, 3 eller 4, hvor de fleksible elementene (18) er ståltråder (18).30 8. Tetningssammenstillingen (2, 25) ifølge et av kravene 2, 3, 4 eller 7, hvor de fleksible elementene (18) er vulkanisert inn i materialet til tetningselementet (4).9. Tetningssammenstillingen (2, 25) ifølge et av de foregående krav, hvor det første støtteelementet (26) og det andre støtteelementet (28) er roterbart holdt på det rørformede legemet (38).3499162610. Tetningssammenstillingen (2, 25) ifølge et av de foregående krav, hvor det første støtteelementet (26) og det andre støtteelementet (28) er sikret av en krage, en ring eller en annen mekanisk stopper (58) som forhindrer støtteelementene (26, 28) fra å forlate en forhåndsbestemt seksjon av det rørformede legemet (38).5 11. Et nedihullsverktøy (36) for brønnintervensjoner, omfattende:et rørformet legeme (38) med en indre boring og minst én strømningsåpning for fluidkommunikasjon mellom den indre boringen og et område utenfor nedihullsverktøyet (36), ogminst én tetningssammenstilling (2, 25) ifølge et av de foregående krav anordnet på 10 det rørformede legemet (38).12. Nedihullsverktøyet (36) ifølge krav 11, omfattende en aktiveringsmekanisme konfigurert til selektivt å tilføre et trykksatt fluid inn i et gap (54) mellom det rørformede legemet (38) og tetningselementet (4) for selektivt å ekspandere tetningselementet (4).15 13. Nedihullsverktøyet (36) ifølge krav 11 eller 12, hvor nedihullsverktøyet (36) er konfigurert for bruk i en plugge- og avslutningsoperasjon.14. En fremgangsmåte for bruk av et nedihullsverktøy (36) ifølge et av kravene 11 til 13, hvor fremgangsmåten omfatter:å utplassere nedihullsverktøyet (36) i et brønnhull,20 å aktivere nedihullsverktøyet (36) ved å bringe tetningselementet (4) til den minst ene tetningssammenstillingen (2, 25) i den radielt ekspanderte tilstanden, ogå føre fluid til brønnhullet ved å øke fluidtrykket i den indre boringen til minst et terskeltrykk.
Drawings

Priority

No priority

Patent classes

IPC classesE21B 33/12CPC classesE21B 33/1208

Citations

US 2017/0022780 A1 (A1)GB 2357787 A (A)CN 203531829 U (U)US 2221775 A (A)US 2764244 A (A)US 4886117 A (A)

Applicants, owners and inventors

Owners
Archer Oiltools AS
Postboks 8037 4068 STAVANGER NO (STAVANGER Municipality, Rogaland county)Org. number: 968145843Inventors
Arve Byberg
Kolleholen 12 4353 KLEPP STASJON NO (KLEPP Municipality, Rogaland county)

Agent

ACAPO ONSAGERS AS
ACAPO ONSAGERS AS

Org. number: 932214636

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Open in The Brønnøysund Register Centre
Edvard Griegs vei 1 5059 BERGEN NO (BERGEN Municipality, Vestland county)
Org. number: 932214636
Reference: P29748NO00

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