Key information

Title: A downhole tool with inflatable elements and a valve, and a method of using the downhole tool
Application number: 20241030
Case type: National
Status: 01.06.2026 Patent meddelt (B1)
Filed: 14.10.2024
Effective date: 14.10.2024
Publicly available: 15.04.2026
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: 01.06.2026
Patent number: 349865
Expiry date: 14.10.2044

Abstract and drawing

Disclaimer: This text has been machine-scanned and may contain errors – please refer to "Publications" for legally binding content.

A downhole tool (1) for well interventions is disclosed. The downhole tool (1) comprises a mandrel (10) comprising an inner bore (11) and at least one flow opening (12) for fluid communication between the inner bore (11) and a region outside the downhole tool (1). The downhole tool (1) also comprises a first flow guide assembly (20) comprising one or more radially expandable barrier member(s) (21) arranged around the mandrel (10). The one or more radially expandable barrier member(s) (21) are configurable between a radially unexpanded state and a radially expanded state. Furthermore, the downhole tool (1) comprises a pressure regulator (40) configured to allow fluid communication between the inner bore (11) and the region outside the downhole tool (1), via the at least one flow opening (12), when fluid pressure in the inner bore (11) reaches a threshold pressure.

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Date

Date	Doc. No.	Process	Case number	In/Out	Journal description	To/from
01.06.2026	09-01	Saksbehandling	20241030(349865)	UT	PT Registreringsbrev nasjonal patent (15) (PT20241030)
20.03.2026	08-01	Saksbehandling	20241030	UT	Intention to grant	ACAPO ONSAGERS AS
27.11.2025	07-06	Saksbehandling	20241030	INN	P29687NO00_Norwegian claims 1281362	ACAPO ONSAGERS AS
27.11.2025	07-05	Saksbehandling	20241030	INN	P29687NO00 - Amended specification (marked copy) 1281359	ACAPO ONSAGERS AS
27.11.2025	07-04	Saksbehandling	20241030	INN	P29687NO00 - Amended specification (clean copy) 1281357	ACAPO ONSAGERS AS
27.11.2025	07-03	Saksbehandling	20241030	INN	Letter_to_NIPO_Nov_17,_2025_request for postponment 1281365	ACAPO ONSAGERS AS
27.11.2025	07-02	Saksbehandling	20241030	INN	Letter_to_NIPO_Nov_17,_2025_1278641 1281364	ACAPO ONSAGERS AS
27.11.2025	07-01	Saksbehandling	20241030	INN	Korrespondanse (Hovedbrev inn)	ACAPO ONSAGERS AS
06.11.2025	06-01	Saksbehandling	20241030	UT	Substantive examination	ACAPO ONSAGERS AS
06.08.2025	04-03	Saksbehandling	20241030	INN	P29687NO00 reply	ACAPO ONSAGERS AS
06.08.2025	04-02	Saksbehandling	20241030	INN	P29687NO00 amended description and claims	ACAPO ONSAGERS AS
06.08.2025	04-01	Saksbehandling	20241030	INN	Korrespondanse (Hovedbrev inn)	ACAPO ONSAGERS AS
12.05.2025	03-02	Saksbehandling	20241030	UT	PT report 12:57:45
12.05.2025	03-01	Saksbehandling	20241030	UT	Substantive examination	ACAPO ONSAGERS AS
15.10.2024	02-01	Saksbehandling	20241030	UT	Informasjon til oppfinner	Arve Byberg
14.10.2024	01-04	Saksbehandling	20241030	INN	P29687NO00 FINAL patent specification 1192269	ACAPO ONSAGERS AS
14.10.2024	01-03	Saksbehandling	20241030	INN	P29687NO00 Final drawings 1192244	ACAPO ONSAGERS AS
14.10.2024	01-02	Saksbehandling	20241030	INN	Archer Oiltools AS 1173591	ACAPO ONSAGERS AS
14.10.2024	01-01	Saksbehandling	20241030	INN	Søknadsskjema Patent	ACAPO ONSAGERS AS
	05-02	Saksbehandling	20241030	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

349865

A DOWNHOLE TOOL WITH INFLATABLE ELEMENTS AND A VALVE,

AND A METHOD OF USING THE DOWNHOLE TOOL

TECHNICAL FIELD

5 The present invention relates to the oil and gas industry and in particular to a downhole tool for use 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 a method of using the downhole tool.

BACKGROUND

Well tools of various designs are used to perform well interventions of various types. A plug and abandonment (P&A) operation is carried out when a wellbore is no longer to be used, for example as it is no longer economically producing oil 15 and/or gas, or for other reasons. The P&A of a well is typically done in line with regulatory requirements, e.g. regulations set by national governments. It involves sealing the well by setting a plug in a region of the well so that there is no flow of fluid to the surface and so that there is no migration of formation fluid. This may be done temporarily or permanently.

A common requirement during P&A operations is to have a plug set inside an inner casing string and a further plug set in the annulus between the inner casing string and the surrounding rock formation. This can provide a so-called rock-to-rock barrier.

Prior to setting a plug it is known to carry out perforation and washing operations, such as to prepare the well for setting plugs in the annulus. Such operations may be used in various other well interventions. In a perforation operation the casing, liner or production tubing of the well is perforated by use of dedicated perforating tools.

30 The perforated section can then be washed by application of fluid under pressure.

Debris resulting from the perforation and washing operations is then removed from the well before a barrier material (typically cement) is placed by pumping it through the perforations into the annulus and into any open regions outside of the well pipe. Such operations are typically referred to as perforate, wash and cement (PWC) 35 operations.

Archer Oiltools markets a number of products for use in relation to P&A operations, including the various products in the StrongholdRTM range of systems. These systems allow for “one-trip” perforation, washing, cleaning and/or cementing

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operations in order to provide safer and more economical P&A. These one-trip methods can replace traditional P&A techniques that required up to three runs. In an example of such a combined operation a tool string with a washing tool (washing module) comprising two (or four) opposite packing assemblies is passed down the 5 well pipe and the two opposite packing assemblies are placed on opposite sides of the perforations in the well pipe. Fluid is pumped down through the tool string and out through radial ports between the two packing assemblies. The packing assemblies then prevent the liquid from flowing up or down along the tool string and the liquid will thus have to flow through the perforations in the well pipe.

In the prior art, the packing assemblies typically comprise cup elements positioned such that their concave side faces the radial ports of the washing tool. Thus, when fluid is pumped through the radial ports, the cups are forced into sealing engagement with the surrounding well pipe such that the fluid may be guided 15 through the perforations and into the annulus during washing and/or cementing.

In order to function properly, such cup elements must cover virtually the entire internal cross-sectional area of the well pipe. Because of this, the cup elements are vulnerable to wear and tear as the tool is transported down to the section(s) of the 20 well where PWC operations are to be carried out. If the cup elements become worn before reaching the target section, they may not be able to perform their function adequately, and the resulting PWC operation may be compromised. Operations may then have to be interrupted and repeated, which may be time-consuming and costly. Worse still, the resulting cement plug may not meet the requirements, which can 25 lead to environmental consequences. Another problem may arise where the well contains restrictions or obstructions that result in smaller cross-sectional areas above the section of the well where PWC operations are to be carried out. This may be the case for a production tubing which may contain downhole valves and other devices that may restrict the inner cross-sectional area, or it may also be due to 30 scale and other deposits on an internal well pipe wall.

US 2764244 discloses a well tool using inflatable packing means together with additional packing means. The additional packing means have a plurality of packing rings of compressible and resilient material, with these rings being

35 expandable responsive to sliding movement of slidable sleeves.

US 4279306 discloses a well washing tool that aims to eliminate the problems associated with cup type packer tools. This tool includes compressible type packer assemblies that are actuated by a predetermined pressure and a valve assembly that 40 is responsive to a higher predetermined pressure to unblock ports and permit fluid communication to the exterior of the tool.

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Thus, there is a need to improve downhole tools and methods available to use during well interventions such as P&A operations.

SUMMARY OF THE INVENTION

Viewed from a first aspect, the present invention provides a downhole tool for well interventions, the downhole tool comprising:

a mandrel comprising:

- an inner bore and at least one flow opening for fluid communication between 10 the inner bore and a region outside the downhole tool;

a first flow guide assembly comprising:

- one or more radially expandable barrier member(s) arranged around the mandrel and configurable between a radially unexpanded state and a radially expanded state;

15 wherein the one or more barrier member(s) each define an annulus around the mandrel, and wherein each annulus is in fluid communication with the inner bore for urging the one or more barrier member(s) toward the radially expanded state as fluid pressure in the inner bore is increased, and wherein the mandrel comprises a pressure coupling opening for supplying 20 fluid under pressure to the annulus(es) defined by the one or more barrier member(s), such that as fluid pressure is increased in the inner bore, fluid under pressure enters the annulus(es) via the pressure coupling openings and consequently inflates the barrier member(s); and

characterized in that:

25 - the annulus(es) are defined around the mandrel,

- 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 in order to ensure a minimum activation pressure of the barrier member(s) before the fluid 30 communication is allowed.

The mandrel may be a tubular mandrel, e.g. a hollow cylinder. The inner bore may thus be the inner volume of the hollow cylinder. The mandrel may form a part of the tubing of the downhole tool and/or a part of the tubing of a well string to which 35 the downhole tool is connected. The inner bore may be a through-going bore, i.e.

such that both axial ends of the mandrel are open or give access to the inner volume. Alternatively, one of the axial ends may be blocked, or closed, so that the volume can only be accessed from one axial end. The mandrel may be comprised of a single, uniform part. Alternatively, the mandrel may comprise several parts that 40 are connected together to form the mandrel.

349865

Each axial end of the mandrel may comprise a connection. The connection may be for connecting the downhole tool to another downhole tool, or to a suitable conveyance means, as discussed further below. The connections may be threaded connections as known in the art.

In certain embodiments, the first flow guide assembly may comprise two radially expandable barrier members. Each of the two barrier members may be arranged around the mandrel and configurable between a radially unexpanded state and a radially expanded state. The two barrier members may be located adjacent to each 10 other, e.g. axially adjacent to each other on the mandrel. The distance between the barrier members may be less than 2 meters, e.g. between 0,2 – 1 meter.

The one or more barrier member(s) may be able to selectively cycle between the radially unexpanded state and the radially expanded state. That means, the barrier 15 member(s) may be reconfigurable between the radially unexpanded state and the radially expanded state repeatedly, e.g. while the downhole tool is deployed in a wellbore.

In the radially expanded state, an outer diameter of the one or more barrier

20 member(s) may equal the inner diameter of a wellbore when the downhole tool is deployed in a wellbore. As such, the full circumference of the barrier member(s) may be in contact with the internal circumference of the wellbore and the barrier member(s) may thus provide a sealing function. However, this need not be the case. In the radially expanded state, the outer diameter of the barrier member(s) may also 25 be less than the inner diameter of the wellbore. As such, the full circumference of the barrier member(s) may not be in contact with the internal circumference of the wellbore. Even if there is not full contact between the barrier member(s) and the internal diameter of the wellbore, e.g. such that a certain leak of fluid across the barrier member(s) is allowed, the barrier member(s) may still provide sufficient 30 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 “flow restricting capability” may be interchangeably used to refer to the function of the barrier member(s) in the expanded state, either when it is fully sealing or when it allows some leakage 35 across, as discussed above.

The one or more barrier member(s) define an annulus, or an annular region, around the mandrel. For example, if the first flow guide assembly comprises one barrier member, then the barrier member may define one annulus around the mandrel. If the 40 first flow guide assembly comprises two barrier members, then the two barrier members may define one annulus each around the mandrel.

349865

The first flow guide assembly may be said to be “inactivated”, or to be in an “inactivated state”, when the one or more barrier member(s) are in the radially unexpanded state. Furthermore, the first flow guide assembly may be said to be “activated”, or to be in an “activated state”, when the one or more barrier

5 member(s) are in the radially expanded state. Thus, configuring the barrier member(s) from the radially unexpanded state to the radially expanded state may be referred to as “activating” the first flow guide assembly and/or “activating” the downhole tool. Furthermore, configuring the barrier member(s) from the radially expanded state to the radially unexpanded state may be referred to as “deactivating” 10 the first flow guide assembly 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 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.

15 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 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 assembly has a reduced radial extent and thus may have a radially outermost part of the flow guide assembly moved inward toward a center of the downhole tool. Preferably the radial extent of the flow guide assembly can be reduced to be no more than the radial 25 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 assembly 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 50% thereof. For example, for a well tool required to pass through a restriction of around 3 inches (about 7.6 cm) 30 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.

35 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.

When the first flow guide assembly, and thus the downhole tool, is in the activated 40 state, the downhole tool may provide a barrier, or a sealing function, in the wellbore, e.g. by preventing fluid flow across the one or more barrier member(s), or by sufficiently preventing fluid flow across the one or more barrier member(s), as

349865

discussed above (i.e. providing sufficient sealing / flow restricting capabilities). Thus, fluid may be sufficiently prevented from flowing between a location above the barrier member(s) and a location below the barrier member(s) in the wellbore, e.g. to perform operations such as integrity testing, fracturing, washing and/or 5 cementing.

The downhole tool may be deployed in the wellbore by a suitable conveyance 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 10 intermediate tool between the downhole tool and the tubing, e.g. through one of the connections of the mandrel. Thus, fluid under pressure may be supplied from surface through the tubing in order to activate the downhole tool. The intermediate 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 15 relevant well operation.

As discussed above, the mandrel comprises at least one flow opening for fluid communication between the inner bore and a region outside the downhole tool. The flow opening may be a radial flow opening formed in the mandrel, such that fluid 20 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.

25 In certain embodiments, the downhole tool may comprise a second flow guide assembly. The at least one flow opening may then be located axially between the first flow guide assembly and the second flow guide assembly. Thus, the flow opening may allow fluid communication between the inner bore of the mandrel and a region outside the downhole tool between the first and second flow guide

30 assemblies. 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 guide assemblies. The distance between the first and second flow guide assemblies may be less than 3 meters, e.g between 0,3 – 2 meters.

Alternatively, the distance between the first and second flow guide assemblies may 35 be between 5-25 diameters of the mandrel, between 5-20 diameters of the mandrel, between 10-15 diameters of the mandrel, e.g. 12 diameters of the mandrel. If the distance between the flow guide assemblies becomes too large, it may affect the performance of the downhole tool, e.g. when used for washing operations as will be discussed further below. For example, as the distance between the flow guide 40 assemblies 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.

349865

The region in the wellbore may be defined, at least in part, by the mandrel, the first and second flow guide assemblies and the surrounding wellbore in which the downhole tool is deployed. The wellbore may comprise a tubing in which the 5 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 mandrel, the first and second flow guide assemblies and the surrounding tubing in which the downhole tool is deployed.

10 The second flow guide assembly may be equal, or similar, to the first flow guide assembly. I.e., the second flow guide assembly may comprise any of the features described herein in relation to the first flow guide assembly. For example, the second flow guide assembly may comprise two radially expandable barrier members. Furthermore, the second flow guide assembly may be activated and/or 15 deactivated synchronously, or simultaneously, with the first flow guide assembly.

As such, “activating” the downhole tool may imply activating both the first and second flow guide assemblies, e.g. at the same time. Similarly, “deactivating” the downhole tool may imply deactivating both the first and the second flow guide assemblies, e.g. at the same time.

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 barrier members provide a sealing function. The section of the wellbore may be the region 25 in the wellbore as described above. As such, the first and second flow guide assemblies may allow for the section of the wellbore to be selectively enclosed by activation and deactivation of the first and second flow guide assemblies.

In some embodiments, the well intervention may be carried out as part of a plug and 30 abandonment (P&A) operation. For example, the well intervention may be a socalled 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.

35 Typically, cement is used as a plugging material. The tool may therefore generally 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 tubing by forcing fluid conveyed from surface through the perforations in the tubing 349865

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. 5 Where 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 comprise more than two perforated tubing strings and thus the tool may be

10 configured for washing all the accessible annuli.

It will be appreciated that the flow guide assemblies 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 15 this way, the 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 barrier members against the wellbore is set at a first, higher, level to increase the 20 integrity of the seal provided by the first and second flow guide assemblies (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 barrier members against the wellbore is set at a second, lower, level to reduce an anchoring force provided by the first and second flow guide assemblies (e.g. for dynamic operations when the 25 downhole tool may move within the wellbore whilst fluid is still enclosed at increased pressure in the section of the well between the first and second flow guide assemblies). This may lower friction and reduce wear on the barrier members during dynamic operations.

30 Therefore, the downhole tool may be suitable for carrying out dynamic washing and/or cementing operations. As such, the downhole tool may be a dynamic washing and/or cementing tool. The tool may thus be configured to move in the wellbore while activated (i.e. when the barrier members are in the radially expanded state) and while conveying fluids to the region outside the downhole tool between 35 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 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 40 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 349865

above. The conveyed fluid is thus forced through the perforations formed in the tubing and into the surrounding annulus (or annuli).

During a washing operation, the fluid may remove, or wash away, any debris 5 present in the annulus. Such debris may comprise old, hardened cement from a cementing operation performed during the construction phase of the well, and/or different consolidated solids particles, such as from cuttings or particles present in drilling fluids. The fluid and any debris that has come loose, may further be transported into the tubing bore above the downhole tool (i.e. above the uppermost 10 flow guide assembly) via the perforations and then back to surface. In this way, the downhole tool may be configured to wash the surrounding annulus, or annuli, as the downhole tool is moved along the perforated section of the wellbore. The downhole tool may similarly be configured to wash the surrounding annulus while lowered, or moved downwards, along the perforated section.

During a cementing operation, the tool may be used in a similar manner to convey cement to the perforated section of the wellbore as the tool is pulled upwards along the perforated section. In this way, the downhole tool may be configured to form a plug in the perforated section of the wellbore. As explained above, the term

20 “cementing operation” is used as cement is commonly used as the plugging material. However, the downhole tool may convey any other suitable plugging material for forming a plug in the wellbore.

It will be appreciated that the selectively activatable flow guide assemblies may 25 provide additional benefits to the downhole tool. The downhole tool may pass (particularly narrow) restrictions in the wellbore that would otherwise not have been possible to pass (with e.g. passively collapsible flow guides or “always active” flow guides such as swab cups). This may be an issue e.g. when the downhole tool is deployed in a production tubing which may contain downhole valves, e.g. flapper 30 valves, and other devices that may restrict the inner cross-sectional area of the tubing. It may also be an issue if there is scale or other deposits on the internal tubing wall. A further advantage of being able to configure the flow guide assemblies in the deactivated state while running into the hole is that excessive wear or damage, which may be caused by the barrier members being dragged against a 35 tubing of the wellbore and/or against different restrictions in the wellbore, will be reduced or even avoided. As such, wear and tear that could otherwise compromise the functionality of the downhole tool is reduced, or even avoided. This may ensure that subsequent washing and/or cementing operations are carried out in a satisfactory manner, which may be crucial for establishing a satisfactory

40 barrier/plug during e.g. a P&A operation.

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In certain embodiments, as discussed above, the first flow guide assembly and the second flow guide assembly may each comprise two radially expandable barrier members. In some embodiments, each flow guide assembly may even comprise more than two radially expandable barrier members. Having two or more barrier 5 members may provide additional contingency, e.g. in case a barrier member is damaged or otherwise worn-out during washing and/or cementing. The additional barrier member may thus make the tool less affected in case of any damage and provide added benefit in addition to the flow guide assemblies being selectively activatable. With this said, it may not always be beneficial to have two or more 10 barrier members for each flow guide assembly. For example, additional barrier members may lead to increased friction during dynamic operations and therefore more force may be needed in order to move the downhole tool in the wellbore while it is activated. Therefore, while additional barrier members may be beneficial in certain circumstances, it may not always be feasible. This may depend, among other 15 things, on the available pulling force on the surface.

In embodiments where the first flow guide assembly and the second flow guide assembly each comprise two or more radially expandable barrier members, the distance between adjacent barrier members of each flow guide assembly may be less 20 than 2 meters, e.g. between 0,2 – 1 meter. In general, it may be desirable to have the barrier members as close to each other as possible to reduce the length of the tool. Additionally, if e.g. one of the barrier members closest to the at least one flow opening were to fail, then the increase in distance between functional barrier members in the first and second flow guide assemblies would be as small as

25 possible, which may be desirable for e.g. washing operations as discussed above.

The mandrel comprises a pressure coupling opening for supplying fluid under pressure to the annulus(es) defined by the one or more barrier member(s). For example, if the flow guide assembly comprises one barrier member, then the 30 mandrel may comprise a pressure coupling opening for supplying fluid under pressure to the annulus defined by the barrier member. If the first flow guide assembly comprises two barrier members, then mandrel may comprise a pressure coupling opening for each of the two annuluses defined by the two barrier members. The inner bore may communicate with each annulus via a respective pressure 35 coupling opening, i.e. with each barrier member having an annulus with a corresponding pressure coupling opening in the mandrel. As fluid pressure is increased in the inner bore, fluid under pressure enters the annulus(es) via the pressure coupling openings and consequently inflates the barrier member(s). As such, the barrier member(s) are urged toward the radially expanded state by

40 inflation of the barrier member(s). The annulus(es) may be formed, at least in part, between an internal surface of the respective barrier member(s) and an external surface of the mandrel. Thus, each barrier member(s) may be shaped as a sleeve

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around the mandrel. Preferably, the annulus(es) are fluid-tight against the surroundings, i.e. against the region outside the downhole tool. The pressure coupling opening may be a radial opening in the mandrel, providing direct radial connection between the inner bore and the annulus(es) defined by the barrier 5 member(s). The pressure coupling opening may be provided by one or more fluid paths for supplying fluid to each annulus defined by the one or more barrier member(s).

The barrier member(s) may each comprise an elastomer. The elastomer may be a 10 vulcanized elastomer, e.g. a vulcanized rubber. Additionally, or alternatively, the elastomer may be a fiber reinforced elastomer. Additionally, or alternatively, the elastomer may be metal reinforced, e.g. steel reinforced.

The barrier member(s) may each comprise one single piece. Alternatively, the 15 barrier member(s) may each be segmented. For example, the barrier member(s) may each comprise of two or more elements.

Having inflatable barrier member(s) may offer certain advantages. It may provide a balanced pressure, or force distribution, on the barrier member(s) and may thus 20 provide a larger axial engagement area between the barrier member(s) and the surrounding wellbore wall. It may also provide more force to the barrier member(s) for the same pressure, which may allow for thicker barrier member(s) to be used. For example, if the barrier member(s) comprise an elastomer, it allows for a thicker elastomer element to be used. The combination of a longer axial engagement area 25 and a thicker elastomer element provides redundancy, as the internal pressure may continue to inflate the barrier member(s) and compensate for the elastomer being worn down. This makes the barrier member(s) less vulnerable to wear and tear during dynamic operations, where the barrier member(s) may be moved along the rough inner surface of a perforated tubing. Therefore, the downhole tool may 30 provide sufficient sealing capabilities during dynamic operations (e.g. during washing or cementing as discussed above) over a longer period of time.

For each of the one or more barrier member(s), a first end of the barrier member may be movable with respect to a second end of the barrier member. For example, a 35 sliding end may move towards a fixed end as the barrier member(s) deform outward, e.g. during inflation of the barrier member(s). Alternatively, a sliding end may move relative to another sliding end as the barrier member(s) deform outward . For example, the sliding ends may move toward each other as the barrier member(s) deform outward.

The first end of each barrier member may be attached to a respective first support member and the second end of each barrier member may be attached to a respective 349865

second support member. For example, if the flow guide assembly comprises one barrier member, the first end of the barrier member may be attached to a first support member and the second end of the barrier member may be attached to a second support member. If the flow guide assembly comprises two barrier members, 5 then the first end of each of the two barrier members may be attached to a respective first support member and the second end of each of the two barrier member may be attached to a respective second support member.

The first support member(s) may be axially movable with respect to the mandrel. 10 Additionally or alternatively, the first support member(s) may be rotationally movable with respect to the mandrel. Furthermore, the first support member(s) may be arranged around a portion of the mandrel. The second support member(s) may be axially movable with respect to the mandrel. Additionally or alternatively, the second support member(s) may be rotationally movable with respect to the mandrel.

15 Furthermore, the second support member(s) may be arranged around a portion of the mandrel. The first support member(s) and the second support member(s) may move axially toward each other as the barrier member(s) deform outward, e.g. during inflation of the barrier member(s).

20 The downhole tool may comprise axial stoppers for determining a maximum axial distance between the first support member(s) and the second support member(s). Furthermore, the axial stoppers may keep the barrier member(s) and the first and second support member(s) around a specific portion of the mandrel. For example, the axial stoppers may hold the barrier member(s) and the first and second support 25 member(s) within a specific axial portion on the outer surface of the mandrel. The first support member(s) and the second support member(s) may be prevented from moving past the axial stoppers but may be allowed to move between the axial stoppers. For example, the first support member(s) and the second support member(s) may be prevented from moving axially away from each other past the 30 axial stoppers, e.g. by coming into contact with the axial stoppers, but may be allowed to move axially toward each other or away from each other between the axial stoppers, e.g. when the downhole tool is activated and deactivated.

The second support member(s) may be axially fixed with respect to the mandrel. 35 Furthermore, the second support member(s) may be fixed around a portion of the mandrel. Thus, the first support member(s) may move toward the second support member(s) as the barrier member(s) deform outward, e.g. during inflation of the barrier member(s).

40 Each of the first and second support members may be shaped as a ring, or a sleeve, around the mandrel.

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Having one or both ends of the barrier member(s) movable relative to each other may facilitate expansion of the barrier member(s). For example, it may allow the barrier member(s) to radially expand without being excessively stretched or torn. This may preserve the characteristics of the barrier member(s) over a longer period 5 of time and thus improve the durability of the barrier member(s). For example, if the barrier member(s) comprise an elastomer, the characteristics of the elastomer may be preserved over a longer period of time.

The first and second ends of each barrier member may be attached to the respective 10 first and second support members by means of vulcanized bonding. The first and second support members may comprise steel to which the barrier member(s) are vulcanized. The vulcanized bonding forms a more resilient and robust connection.

In some embodiments where the downhole tool comprises a second flow guide 15 assembly, the flow guide assemblies may be mirrored across the at least one flow opening. For example, when each flow guide assembly comprises one barrier member each, the fixed end of each barrier member may be axially closest to the at least one flow opening and the sliding end of each barrier member may be axially furthest away form the at least one flow opening. Also, when each flow guide 20 assembly comprises two barrier members, the fixed end of each barrier member may be axially closest to the at least one flow opening and the sliding end of each barrier member may be axially furthest away form the at least one flow opening.

When pressure is decreased, e.g. released, in the inner bore of the mandrel, the 25 barrier member(s) may retract to the radially unexpanded state. Preferably, this is achieved by the barrier member(s) themselves, i.e. by that the barrier member(s) return to their initial state without an external force being applied, such as by means of the resilient nature of the barrier member(s). For example, elastomers, or rubbers, tend to have such characteristics. However, in certain embodiments a spring may be 30 added to bias the barrier member(s) back to the radially unexpanded state when pressure in the inner bore is decreased, to thereby deactivate the downhole tool. The spring may for example be positioned inside the barrier member(s), or in the annulus(es) formed by the barrier member(s).

35 Optionally, the downhole tool may comprise a centralizer assembly configurable between a radially unexpanded state and a radially expanded state. Similar to the barrier member, the centralizer assembly may be urged toward the radially expanded state as fluid pressure in the inner bore is increased. Furthermore, the centralizer assembly may be able to selectively cycle between the radially

40 unexpanded state and the radially expanded state. That means, the centralizer assembly may be reconfigurable between the radially unexpanded state and the

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radially expanded state repeatedly, e.g. while the downhole tool is deployed in a wellbore.

The centralizer assembly may comprise a first plurality of mechanical linkages 5 pivotally moveable with respect to the mandrel and distributed around a portion of the mandrel. Each mechanical linkage may be activatable between a radially unexpanded state and a radially expanded state as discussed above. Each mechanical linkage may comprise a first link and a second link that are pivotally connected. Furthermore, the first link may be pivotally connected to a first support 10 member which is fixed to the mandrel, and the second link may be pivotally connected to a second support member which is axially movable relative to the mandrel. As such, when the second support member moves toward the first support member, the mechanical linkages expand radially outwards. The second support member may comprise a piston, or be attached to a piston, that is activated by fluid 15 pressure, e.g. as fluid pressure in the inner bore increases. The piston may be axially movable relative to the mandrel. One or more springs may be used to bias, or urge, the centralizer assembly back to the radially unexpanded state. The springs may e.g. be located between the first and second support member so as to bias the first support member away from the second support member.

The centralizer assembly may be located adjacent to the flow guide assembly. The flow guide assembly may be located between the centralizer assembly and the flow opening. In an embodiment where the downhole tool comprises two flow guide assemblies, the downhole tool may also comprise two centralizer assemblies, each 25 located adjacent to each respective flow guide assembly. Alternatively, the downhole tool may comprise one centralizer assembly located adjacent to one of the flow guide assemblies. When one or more centralizer assemblies are present in the downhole tool, the terms “activating” and “deactivating” the downhole tool may also comprise the activation and deactivation of the centralizer assembl ies.

The downhole tool comprises 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. The threshold pressure may be configured such that the barrier 35 member(s) are in the radially expanded state before fluid communication between the inner bore and the region outside the downhole tool is allowed. As such, the pressure regulator may allow the downhole tool to activate before fluid can be conveyed to the wellbore, or in other words, activated before fluid communication to the wellbore is established. The pressure regulator may thus have an open 40 configuration in which it allows fluid communication to the wellbore, and a closed configuration in which it prevents fluid communication to the wellbore.

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The pressure regulator allows control of the fluid pressure in the inner bore of the mandrel and thus control of the fluid pressure inside the downhole tool. As such, the force at which the barrier member(s) are pushed towards, or against, the surrounding wellbore may be accurately controlled. In this way, the force on the 5 barrier member(s) may be balanced between a pressure high enough for the barrier member(s) to provide a proper flow restricting function and a pressure sufficiently low to avoid unnecessary wear on the barrier member(s). This may significantly improve the downhole tool’s performance, especially during dynamic operations such as washing, as the tool may then be able to provide sufficient sealing

10 capabilities over a longer period of time.

The pressure regulator ensures a minimum activation pressure of the barrier member(s). This may allow the barrier member(s) to provide sufficient sealing capabilities even if the required, or desired, washing pressure is low. This again 15 may contribute to better performance of the downhole tool, e.g. better washing of the tubing annulus, in a wider range of applications.

If fluid communication to the wellbore is allowed before the flow guide assemblies are activated (i.e. before the barrier member(s) are in their radially expanded state), 20 a pressure spike may occur when the downhole tool activates. In certain situations, the pressure spike may be high enough to damage the tool or cause other unwanted effects. The pressure regulator may thus also prevent these potential issues.

The pressure regulator may be able to selectively cycle between the open

25 configuration and the closed configuration. That means, the pressure regulator may be reconfigurable between the open configuration and the closed configuration repeatedly, e.g. while the downhole tool is deployed in a wellbore. The pressure regulator will be in the open configuration when fluid pressure in the inner bore is equal to or higher than the threshold pressure, and in the closed configuration when 30 fluid pressure in the inner bore is lower than the threshold pressure.

In some embodiments, the pressure regulator may comprise a pressure valve selectively configurable between the closed configuration and the open configuration, as discussed above.

The pressure regulator may comprise a sleeve which is configured for axial displacement with respect to the mandrel between a closed position and an open position. In this way, the sleeve may be operated for configuring the pressure regulator between the closed configuration and the open configuration, respectively.

The pressure regulator may comprise a regulator housing arranged around a portion of the mandrel. The regulator housing may comprise a pressure chamber and one or 349865

more ports for allowing fluid communication between the pressure chamber and the region outside the downhole tool. Furthermore, the pressure chamber may be in fluid communication with the inner bore of the mandrel through the at least one flow opening in the mandrel.

The sleeve may be arranged in the regulator housing such that it allows communication between the pressure chamber and the region outside the downhole tool in the open position and prevents communication between the pressure chamber and the region outside the downhole tool in the closed position. A first axial end of 10 the sleeve may face the pressure chamber such that fluid pressure in the inner bore is transferable to the sleeve. A second axial end of the sleeve may face, or engage with, a biasing mechanism disposed in the regulator housing. As fluid pressure in the inner bore is increased, the sleeve is urged toward its open position, while the biasing mechanism urges the sleeve toward its closed position. As such, a biasing 15 force of the biasing mechanism must be overcome for the sleeve to translate to the open position, to thereby allow fluid communication between the inner bore and the region outside the downhole tool. The threshold pressure may thus be determined by the biasing force of the biasing mechanism, i.e. the pressure required to move the sleeve to the open position and thus the pressure regulator to the open

20 configuration.

The biasing mechanism may be a spring type biasing mechanism, a hydraulic type biasing mechanism, or any other suitable biasing mechanism for urging the sleeve toward the closed position. The biasing force, and by extension the threshold 25 pressure, may be adjusted by adjusting the biasing force of the biasing mechanism.

The biasing force may be adjusted on a surface location prior to deploying the downhole tool in a wellbore, or it may be adjusted while the tool is deployed in the wellbore, e.g. using electrical signal communication. In this way, the threshold pressure may be accurately adjusted and determined based on the parameters of a 30 specific operation, e.g. based on required flow rates and well pressures.

Alternatively, the biasing force may be adjusted by changing out a biasing element of the biasing mechanism. For example, if the biasing mechanism is a spring type biasing mechanism, a spring may be selected to provide the required biasing force, and thus the required threshold pressure, for a certain operation.

Viewed from a second aspect, the present invention provides a method of using the downhole tool discussed above for the first aspect and may include any of the further optional features mentioned above. The method comprises:

- deploying the downhole tool in a wellbore;

40 - activating the downhole tool by configuring the barrier member(s) in the radially expanded state; and

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- conveying fluid to the wellbore by increasing fluid pressure in the inner bore to at least the threshold pressure.

The method may comprise a step of cycling the barrier member(s) between the 5 radially unexpanded state and the radially expanded state, e.g. in a step after the downhole tool has been deployed in the wellbore. For example, the one or more barrier member(s) may be configured from the radially unexpanded state to the radially expanded state and then back to the radially unexpanded state. Hence, the method may comprise a step of deactivating the downhole tool by configuring the 10 barrier member(s) in the radially expanded state.

According to the first aspect, the downhole tool may be configured such that the one or more barrier member(s) are urged toward the radially expanded state as fluid pressure in the inner bore is increased. Hence, the method may comprise activating 15 the downhole tool by increasing fluid pressure in the inner bore such that the one or more barrier member(s) are urged toward the radially expanded state. Furthermore, the method may comprise a step of deactivating the downhole tool by decreasing fluid pressure in the inner bore. Thus, the method may comprise activating and deactivating the downhole tool via changes in pressure within the inner bore of the 20 mandrel.

The level of force on the barrier member(s) may be varied by control of the pressure within the inner bore. The method may include adapting the level of force according to the nature of a well intervention, the nature of the fluid and/or the characteristics 25 of the wellbore.

According to the first aspect, the one or more barrier member(s) may each define an annulus around the mandrel. Furthermore, each annulus may be in fluid communication with the inner bore for urging the respective barrier member toward 30 the radially expanded state as fluid pressure in the inner bore is increased. Hence, the step of activating the downhole tool may comprise increasing fluid pressure in the inner bore such that the one or more barrier member(s) are urged toward the radially expanded state as a result of an increase in fluid pressure in the annulus.

35 The method may comprise configuring the threshold pressure such that the downhole tool is activated before allowing fluid communication between the inner bore and the wellbore. The threshold pressure may be configured, or adjusted, at a surface location in a step prior to deploying to downhole tool in the wellbore.

Alternatively, the threshold pressure may be configured, or adjusted, in a step after 40 the downhole tool has been deployed in the wellbore.

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The method may comprise activating the downhole tool prior to conveying fluid to the wellbore. For example, the method may comprise a step of increasing fluid pressure in the inner bore until the downhole tool activates and then a step of further increasing fluid pressure in the inner bore at least to the threshold pressure 5 to convey fluid to the wellbore.

The method may comprise moving the downhole tool in an uphole direction or in a downhole direction with respect to the wellbore while the downhole tool is activated and while conveying fluid to the wellbore.

It will be appreciated that that the flow guide assembly(ies) 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 downhole tool may be configured to adapt the level of force 15 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 barrier members against the wellbore is set at a first, higher, level to increase the integrity of the seal provided by the first and second flow guide 20 assemblies (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 barrier members against the wellbore is set at a second, lower, level to reduce an anchoring force provided by the first and second flow guide assemblies (e.g. for dynamic operations when the downhole tool may move within the wellbore whilst fluid is 25 still enclosed at increased pressure in the section of the well between the first and second flow guide assemblies). This may lower friction and reduce wear on the barrier members during dynamic operations.

Viewed from the second aspect, the present invention may provide a method for use 30 in a well intervention, i.e., according to the second aspect, the present invention may provide a method of using the downhole tool of the first aspect for a well intervention. 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 socalled perf, wash and cement (PWC) operation. As such, the wellbore may comprise 35 a perforated tubing, such as a perforated casing, liner or production tubing, and the downhole tool may be suitable for carrying out a washing operation and/or a plugging operation. Thus, the present invention according to the second aspect may provide a method for washing and/or plugging a wellbore. Typically, cement is used as a plugging material. The invention according to the third aspect may therefore 40 generally be referred to as a method for washing and/or cementing without any restriction being implied in terms of the plugging material used. Thus, the term

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“cement” will be used herein without excluding any other suitable plugging materials.

The method may comprise a step of deploying the downhole tool in the wellbore 5 while the downhole tool is deactivated. The method may comprise a step of positioning the downhole tool in an area about a perforated section of the wellbore while the downhole tool is deactivated. The method may further comprise a step of activating the downhole tool and positioning the downhole tool such that at least one perforation of the perforated tubing is located between the first flow guide 10 assembly and the second flow guide assembly.

The method may comprise a step of washing the perforated section by pulling the activated downhole tool upwards along the perforated section while conveying fluid to the wellbore. If sufficient washing is not achieved in one washing step, the 15 method may further comprise a step of deactivating the downhole tool and then repositioning the downhole tool at the bottom of the perforated section before repeating the washing step. The washing step may be repeated as many times as necessary in order to achieve sufficient washing of the perforated section.

20 Alternatively, the method may comprise a step of washing the perforated section by moving the activated downhole tool downward along the perforated section while conveying fluid to the wellbore. Washing the perforated section by pulling and lowering the downhole tool may also be combined, such that the perforated section may be washed both while the downhole tool is moved upward and downward along 25 the perforated section.

The method may comprise a step of forming a plug in the perforated section by pulling the activated downhole tool upwards along the perforated section while conveying a plugging material to the wellbore. The plugging material may be any 30 plugging material suitable for plugging a wellbore. Typically, cement is used. Thus, the method may comprise a step of cementing the perforated section. Preferably, the step of forming a plug in the perforated section is performed after the step of washing the perforated section. This is in order to achieve a uniform plug of plugging material in the perforated section.

LIST 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:

Figure 1A shows a longitudinal section of a downhole tool, where the downhole tool is in an inactivated state.

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Figure 1B shows a close-up of a portion of the downhole tool as shown in Figure 1A, the portion including a pressure regulator.

5 Figure 2A shows a longitudinal section of the downhole tool, where the downhole tool is in an activated state while the pressure regulator is in a closed position.

Figure 2B shows a close-up of a portion of the downhole tool as shown in Figure 2A, the portion including the pressure regulator.

Figure 3A shows another longitudinal section of the downhole tool, where the downhole tool is in the activated state while the pressure regulator is in an open position.

15 Figure 3B shows a close-up of a portion of the downhole tool as shown in Figure 5A, the portion including the pressure regulator.

DESCRIPTION OF EXAMPLES

20 Figure 1A shows a downhole tool 1. The downhole tool 1 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.

The downhole tool 1 comprises a cylindrical mandrel 10 comprising an inner 25 through-going bore 11. When the downhole tool 1 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 end, or the upper end, and the right-hand side of the figure (when viewed in the orientation of the reference numbers) would be the down-hole end, or the lower end.

The mandrel 10 comprises an upper connection 16 for connecting the downhole tool 1 to a suitable conveyance means (not shown), either directly or via another downhole tool. The suitable conveyance means allows fluid to be conveyed to the downhole tool 1 and can e.g. be a coiled tubing string or a drill pipe string. In the 35 present example, the connection 16 is depicted as a threaded box connection which is configured to receive a corresponding threaded pin connection, as is well known in the art.

At an opposite end to the connection 16, the mandrel 10 is connected to an end 40 piece 17. The end piece 17 comprises a ball seat 18 and axial flow openings 19.

Fluid may flow between the inner bore 11 and the outside of the downhole tool 1 through the axial flow openings 19. In other examples, the mandrel may comprise a 349865

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.

5 The downhole tool 1 comprises an upper flow guide assembly 20 and a lower flow guide assembly 20’ arranged around the mandrel 10. The upper flow guide assembly 20 and the lower flow guide assembly 20’ may also be referred to as the first flow guide assembly and the second flow guide assembly, respectively. The upper and lower flow guide assemblies 20,20’ are axially spaced apart along the mandrel 10 10 and are positioned on each side of a flow opening 12. The flow opening is in the form of a radial flow port 12 formed in the mandrel 10. The radial flow port 12 allows fluid communication between the inner bore 11 of the mandrel 10 and an area outside the downhole tool 1 via a pressure regulator 40. The pressure regulator 40 will be described in more detail below. Although only one radial flow port 12 is 15 depicted, the mandrel 10 may comprise additional radial flow ports that allow fluid communication between the inner bore 11 and the area outside the downhole tool 1 via the pressure regulator 40.

Features of the upper flow guide assembly 20 are also found in the lower flow guide 20 assembly 20’, and are provided with corresponding reference numerals with the addition of an apostrophe. For example, element 21 of the upper flow guide assembly 20 becomes corresponding element 21’ when found in the lower flow guide assembly 20’. As such, elements provided below with two reference numerals, one without an apostrophe and one with, are corresponding elements in 25 the upper flow guide assembly 20 and the lower flow guide assembly 20’ respectively. While the features and elements of the upper flow guide assembly 20 have corresponding features and elements in the lower flow guide assembly 20’, the orientation of the upper and lower flow guide assemblies 20,20’ differ, such that the upper and lower flow guide assemblies 20,20’ are symmetric about an axis of the 30 downhole tool 1. As can be seen in figure 1A, the upper and lower flow guide assemblies 20,20’ are mirrored across the pressure regulator 40.

Each flow guide assembly 20,20’ comprises two barrier members in the form of sleeve-shaped elastomer elements 21,21’, which are positioned around the mandrel 35 10. The sleeve-shaped elastomer elements 21,21’ form, or define, annuluses 28,28’ around the mandrel 10. The annuluses 28,28’ may be referred to as annular regions. The annuluses 28,28’ lie between the respective barrier members 21,21’ and the mandrel. The annuluses 28,28’ are thus at least partly defined by an inner surface of the elastomer elements 21,21’ and an outer surface of the mandrel 10. In the present 40 example, the sleeve-shaped elastomer elements 21,21’ are each made of a vulcanized elastomer.

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The elastomer elements 21,21’ are each attached to a first support member 23,23’ at one axial end and attached to a second support member 27,27’ at the other axial end. Both the first support members 23,23’ and the second support members 27,27’ are axially and rotationally movable relative to the mandrel 10. In the present 5 example, the elastomer elements 21,21’ are attached to the first support members 23,23’ and to the second support members 23,23’, by means of vulcanized bonding.

In the depicted example, the second support members 27,27’ have the shape of a ring and the first support members 23,23’ have the shape of a sleeve. In another 10 example, the first support members 23,23’ may be shaped as a ring such as the second support members 27,27’.

Ring-shaped axial stoppers are fixed to the mandrel 10 to determine a maximum distance between the first support members 23,23’ and the second support members 15 27,27’. That is, the first support members 23,23’ and the second support members 27,27’ are prevented from moving past the axial stoppers but are allowed to move between the axial stoppers when the downhole tool 1 is activated and deactivated, as will be discussed below.

20 The lower flow guide assembly 20’ comprises three axial stoppers. Two of the axial stoppers are indicated by reference number 24’. The third axial stopper is not indicated by a reference number but is positioned adjacent to the uppermost second support member 27’ (i.e. the second support member 27’ closest to the pressure regulator 40) between the uppermost second support member 27’ and the pressure 25 regulator 40. The third axial stopper is more visible in figures 2A and 3A.

The upper flow guide assembly 20 comprises two axial stoppers. One of the axial stoppers is indicated by reference number 24. The second axial stopper is not indicated by a reference number but is positioned adjacent to the lowermost second 30 support member 27 (i.e. the second support member 27 closest to the pressure regulator 40) between the lowermost second support member 27 and the pressure regulator 40. The second axial stopper is more visible in figures 2A and 3A. As is apparent, the upper flow guide assembly 20 comprises one axial stopper less than the lower flow guide assembly 20’. This is because, in the depicted example, a 35 shoulder 25 of the upper connection 16 acts as a stopper for the uppermost first support member 23.

A pressure coupling opening, in the form of a second radial flow port 13,13’, is formed in the mandrel 10 in the area where each sleeve-shaped elastomer element 40 21,21’ is positioned around the mandrel 10. The second radial flow ports 13,13’ allows fluid communication between the inner bore 11 of the mandrel 10 and the annuluses 28,28’. Although only one second radial flow port 13,13’ is depicted for

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each annulus 28,28’, the mandrel 10 may comprise additional second radial flow ports 13,13’ in the area where the sleeve-shaped elastomer elements 21,21’ are positioned around the mandrel 10.

5 The pressure regulator 40 is shown enlarged in figure 1B. The pressure regulator 40 comprises a regulator housing 41 arranged around the mandrel 10 in an area between the upper and lower flow guide assemblies 20,20’. A pressure chamber 42 is defined by the regulator housing 41, the outer surface of the mandrel 10, and a first axial end 44a of a valve sleeve 44 arranged inside the regulator housing 41. 10 The regulator housing 41 is arranged around the mandrel 10 so that the radial flow port 12 allows fluid communication between the inner bore 11 of the mandrel 10 and the pressure chamber 42.

The valve sleeve 44 can move axially between a closed position and an open 15 position to thereby close and open the pressure regulator 40. In the closed position, the valve sleeve 44 prevents communication between the inner bore 11 of the mandrel 10 and the region outside the downhole tool 1, by blocking, or covering, flow ports 43 formed in the regulator housing 41. In the open position, the valve sleeve 44 is moved axially such that it no longer blocks the flow ports 43. As such, 20 a fluid path is formed between the pressure chamber 42 and the flow ports 43, and thus between the inner bore 11 of the mandrel 10 and the region outside the downhole tool 1. In figure 1B, the valve sleeve 44 is in the closed position.

A second chamber 48 is defined by the regulator housing 41, the outer surface of 25 the mandrel 10, and a second axial end 44b of the valve sleeve 44. A biasing mechanism in the form of a spring 45 is positioned inside the second chamber 48. The spring 45 urges the valve sleeve 44 toward its closed position. Furthermore, the regulator housing comprises an opening 46 which allows the second chamber 48 to be filled or emptied of fluid as the valve sleeve 44 moves axially. The opening 46 30 may in some examples comprise a filter to prevent debris from entering the second chamber 48, as debris may block the valve sleeve 44 or otherwise restrict the movement of the valve sleeve 44.

A retainer 47 is attached inside the regulator housing 41 to keep the spring 45 in 35 place inside the regulator housing 41, and also to preload the spring 45. The retainer 47 can be removed in order to change the spring 45, e.g. to change to a spring with a different biasing force. The retainer 47 also comprises openings to allow the second chamber 48 to be filled or emptied of fluid as the valve sleeve 44 moves axially.

As fluid pressure in the inner bore 11 of the mandrel 10 is increased, the valve sleeve 44 is urged toward its open position (i.e., toward the right in figures 1A and

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1B when viewed in the orientation of the reference numbers), while the spring 45 urges the valve sleeve 45 toward its closed position (i.e., toward the left in figures 1A and 1B when viewed in the orientation of the reference numbers). As such, for the valve sleeve 44 to move to the open position, a force acting on the valve sleeve 5 44 from the fluid exceeds a biasing force acting on the valve sleeve 44 from the spring 45. In this way, the biasing force of the spring 45 determines a threshold pressure that must be reached before fluid communication can be established between the inner bore 11 and the area outside the downhole tool 1.

10 In figures 1A and 1B, the downhole tool 1 is in a deactivated state. In the deactivated state, the elastomer elements 21,21’ of the flow guide assemblies 20,20’ are radially retracted. Radially retracted may also be referred to as radially unexpanded.

15 In figures 2A and 2B, the downhole tool 1 is in an activated state. In the activated state, the elastomer elements 21,21’ of the flow guide assemblies 20,20’ are radially expanded.

To configure the downhole tool 1 in the activated state, a ball 50 is dropped and 20 landed in the ball seat 18 of the end piece 17. When the ball 50 has landed in the ball seat 18, it blocks the inner bore 11 of the mandrel 10 and prevents fluid to flow from the inner bore 11 to the outside of the downhole tool 1 through the axial flow openings 19. 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 11 can be 25 increased to activate the tool.

As pressure is increased in the inner bore, fluid enters the annuluses 28,28’ through the second radial ports 13,13’. As fluid enters the annuluses 28,28’ it applies a force to the inside of the elastomer elements 21,21’, thereby causing them to inflate and 30 expand radially outwards. Thus, it can be said that the elastomer elements 21,21’ are urged toward the radially expanded state by action of an internal force. As is apparent in figure 2A, the first support members 23,23’ and the second support members 27,27’ have moved axially toward each other. By having movable support members, the elastomer elements 21,21’ may expand radially without being

35 excessively stretched or torn. This may preserve the characteristics of the elastomer elements 21,21’ over a longer period of time and thus improve the durability of the elastomer elements 21,21’.

Having inflatable elastomer elements 21,21’ may offer certain advantages. It can 40 provide a balanced pressure, or force distribution, on the elastomer elements 21,21’ and may thus provide a larger axial engagement area between the elastomer elements 21,21’ and the surrounding wellbore wall. It may also provide more force

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to the elastomer elements 21,21’ for the same pressure, which may allow for thicker elastomer elements 21,21’ to be used. The combination of a longer axial engagement area and thicker elastomer elements 21,21’ provides redundancy, as the internal pressure in the elastomer elements 21,21’ may continue to inflate and 5 compensate for the elastomers being worn down. This makes the elastomer elements 21,21’ less vulnerable to wear and tear during dynamic washing and cementing operations, where the elastomer elements 21,21’ can be moved along the rough inner surface of a perforated casing.

10 The pressure regulator 40 is configured to allow the downhole tool 1 to activate before allowing fluid to be conveyed to the region outside the downhole tool 1. In other words, the biasing force of the spring 45, and thus the threshold pressure, is configured such that the elastomer elements 21,21’ of the flow guide assemblies 20,20’ move to the radially expanded state before the valve sleeve 44 moves to the 15 open position. This is achieved by configuring the threshold pressure higher than the activating pressure, i.e. the pressure required for the elastomer elements 21,21’ to radially expand. As is apparent, the biasing force, and thus the threshold pressure, can be adjusted by selecting a spring 45 with a certain biasing force and/or by adjusting the preload force provided by the retainer 47. The latter may e.g. be 20 done by positioning the retainer 47 closer to or further away from the valve sleeve 44 when attaching the retainer 47.

In figure 2A, the fluid pressure in the inner bore 11 is below the threshold pressure and thus the pressure regulator 40 is in the closed position. An enlarged view of the 25 closed pressure regulator is shown in figure 2B.

In figure 3A, the fluid pressure in the inner bore 11 is above the threshold pressure so that the pressure regulator 40 is in the open position. Figure 3B shows an enlarged view of the open pressure regulator 40. As is apparent, the valve sleeve 44 30 has moved axially to the right in the figure compared to figure 4B (when seen in the orientation of the reference numbers) due to the fluid pressure overcoming the biasing force of the spring 45. Since the valve sleeve 44 no longer blocks the flow ports 43, fluid can flow from the inner bore 11 of the mandrel 10 to the region outside the downhole tool 1 via the pressure chamber 42 and the flow ports 43. 35

According to the above, the pressure regulator 40 allows control of the fluid pressure in the inner bore 11 of the mandrel 10 and thus control of the fluid pressure inside the downhole tool 1. As such, the force at which the elastomer elements 21,21’ are pushed toward, or against, the surrounding wellbore may be accurately 40 controlled. In this way, the force on the elastomer elements 21,21’ may be balanced between a pressure high enough for the elastomer elements 21,21’ to provide sufficient sealing capabilities and a pressure sufficiently low to avoid unnecessary

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wear on the elastomer elements 21,21’ during dynamic operations, such as dynamic washing and cementing operations as will be discussed below. This may significantly improve the downhole tool’s 1 performance and also increase the longevity of the elastomer elements 21,21’.

To deactivate the downhole tool 1, the fluid pressure in the inner bore 11 is decreased. This may be achieved by reducing the flow rate (e.g. provided by a mud pump on surface) or by stopping the fluid flow completely. The elastomer elements 21,21’ will then return to their initial, retracted state by means of the resilient nature 10 of the elastomer elements 21,21’, i.e. when the counterforce from the elastomer elements 21,21’ is greater than the force of the fluid pressure.

The downhole tool 1 may be activated and deactivated as many times as desired during a single trip in a wellbore. As such, the downhole tool 1 may be run into 15 (and out of) the wellbore in the deactivated state. An advantage of this is that the downhole tool 1 then can pass narrow restrictions, or obstructions, that otherwise would not be possible to pass (e.g. for washing/cementing tools with “always active” swab cups, which are common in the art). Additionally, wear on the elastomer elements 21,21’ is reduced as unnecessary contact between the elastomer 20 elements 21,21’ and the surrounding casing (or production tubing) is avoided. This again may improve the downhole tool’s performance and increase the longevity of the elastomer elements 21,21’.

For the downhole tool 1 of figures 1A-3B, the upper and lower flow guide

25 assemblies 20,20’ each comprise two elastomer elements 21,21’. Having two elastomer elements 21,21’ provides additional contingency, e.g. in case an elastomer element 21,21’ is damaged or otherwise worn-out during washing and/or cementing. The additional elastomer element 21,21’ may thus make the tool less affected in case of any damage and provide added benefit in addition to the flow 30 guide assemblies being selectively activatable, as discussed above. With this said, it may not always be beneficial to have two elastomer elements 21,21’ for each flow guide assembly 20,20’. For example, additional elastomer elements 21,21’ may lead to increased friction during dynamic operations and therefore more force may be needed in order to move the downhole tool 1 in the wellbore while it is activated.

35 Therefore, while two elastomer elements 21,21’ may be beneficial in certain circumstances, it may not always be feasible. This may depend, among other things, on the available pulling force on the surface. Thus, in other examples, the upper and lower flow guide assemblies 20,20’ may each comprise one elastomer element 21,21’.

In an example method, the downhole tool 1 is used for a washing and cementing operation in conjunction with a PWC operation. A PWC operation may be

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performed in conjunction with a P&A operation. The downhole tool 1 is deployed in a wellbore and lowered down to a perforated section of a casing that is to be washed and then cemented in order to plug the wellbore. The downhole tool 1 is deployed and lowered down to the perforated section in the deactivated state to be able to 5 pass any restrictions and to reduce wear as discussed above.

The perforated section may e.g. be at least 50-100 meters long. The length of the perforated section (and hence the length of the plug) may be determined by local/national requirements. The perforations may have been made in the same trip 10 in the wellbore, e.g. by a mechanical perforator tool comprised in the tool string.

Alternatively, the perforations may have been made during an earlier trip in the wellbore, e.g. by explosive charges, as is known in the art.

The downhole tool 1 is positioned at a lower end of the perforated section and the 15 ball 50 is dropped in order to seal off the axial flow openings 19. Then, to initiate the washing step, fluid flow is started to activate the downhole tool 1 and to open the pressure regulator 40. The fluid may e.g. be a washing fluid. The downhole tool 1 is pulled upward along the perforated section while conveying the washing fluid through the pressure regulator 40. As the radially expanded elastomer elements 20 21,21’ restrict upward and downward flow inside the casing, the washing fluid is forced through the perforations in the casing and into the surrounding annulus. From there, the washing fluid flows back into the casing through perforations above the downhole tool (i.e. above the upper flow guide assembly 20) and up to the surface. In this way, the washing fluid can wash away any debris and unwanted 25 solids particles present in the annulus and transport the washed away debris and solids particles to the surface in order to clean the well.

When the downhole tool 1 reaches an upper area of the perforated section, fluid flow is stopped such that the downhole tool can deactivate. Then, the downhole tool 30 1 is lowered back to the bottom of the perforated section. If the perforated section (i.e. the annulus of the perforated section) is sufficiently cleaned, then the wellbore may be cemented next. If not, then another washing step can be performed, as just described. Sufficient cleaning may be determined based on different parameters, e.g. the circulating pressure (often called “stand pipe” pressure).

To initiate the cementing step, fluid flow is again started to activate the downhole tool 1 and to open the pressure regulator 40. Similar to the washing step, the downhole tool 1 is pulled upward along the perforated section while conveying cement through the pressure regulator 40. As the radially expanded elastomer 40 elements 21,21’ restrict upward and downward flow inside the casing, the cement is forced through the perforations in the casing and into the surrounding annulus, thus ensuring that the annulus is completely filled with cement along the perforated

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section. This may be referred to as a “pump and pull” method. When the downhole tool 1 reaches the top of the perforated section, the whole section, including the inside of the casing and the annulus around the casing will be filled with cement. When the cement eventually hardens, a solid plug will be formed in the wellbore. 5 The previous washing step(s) ensures that a uniform cement plug is formed, and thus that the plug provides the necessary integrity.

After the cementing step is complete, the downhole tool 1 can be deactivated and retrieved to the surface by the following steps; After the downhole tool 1 has been 10 pulled above the perforated section and positioned inside a blank portion of the casing, i.e. a portion of the casing without perforations, then fluid pressure in the inner bore may be further increased by continuing fluid flow (or by reinitiating fluid flow if fluid flow was stopped). Since the casing is not perforated in this section, fluid can no longer escape the area between the elastomer elements 21,21’ and the 15 casing, and thus the fluid pressure inside the inner bore 11 can continue to increase.

When the pressure reaches a certain threshold, the ball seat 18 shears out so that the ball 50 drops down into the end piece 17. When located inside the end piece 18, the ball 50 is not able to fully cover the axial flow openings 19. Thus, the fluid pressu re inside the inner bore 11 is released and the downhole tool 1 deactivates. Thereafter, 20 the downhole tool 1 may be retrieved to the surface in the deactivated state.

The above-described method may comprise additional steps to those described above. For example, a spacer fluid may be displaced ahead of the cement in order to aid the removal of wellbore fluid as the cement is displaced through the wellbore.

25 This may be performed in a separate step, between the washing and cementing step, while pulling the downhole tool upwards along the perforated section. Known steps, or operations, in the state of the art may also be included.

Claims

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CLAIMS

1. A downhole tool (1) for well interventions, the downhole tool (1) comprising:

a mandrel (10) comprising:

5 - an inner bore (11) and at least one flow opening (12) for fluid communication between the inner bore (11) and a region outside the downhole tool (1);

a first flow guide assembly (20) comprising:

- one or more radially expandable barrier member(s) (21) arranged 10 around the mandrel (10) and configurable between a radially unexpanded state and a radially expanded state;

wherein the one or more barrier member(s) (21, 21’) each define an annulus (28, 28’), and wherein each annulus (28, 28’) is in fluid communication with the inner bore (11) for urging the one or 15 more barrier member(s) (21, 21’) toward the radially expanded state as fluid pressure in the inner bore (11) is increased, and wherein the mandrel (10) comprises a pressure coupling opening (13, 13’) for supplying fluid under pressure to the annulus(es) (28, 28’) defined by the one or more barrier member(s) (21, 21’), such that as fluid 20 pressure is increased in the inner bore, fluid under pressure enters the annulus(es) via the pressure coupling openings and consequently inflates the barrier member(s); and

characterized in that:

- the annulus(es) (28, 28’) are defined around the mandrel (10);

25 - a pressure regulator (40) configured to allow fluid communication between the inner bore (11) and the region outside the downhole tool (1), via the at least one flow opening (12), when fluid pressure in the inner bore (11) reaches a threshold pressure in order to ensure a minimum activation pressure of the barrier member(s) before the fluid communication is allowed.

2. The downhole tool (1) according to claim 1, wherein the downhole tool (1) comprises a second flow guide assembly (20’), and wherein the at least one flow opening (12) is located axially between the first flow guide assembly (20) and the second flow guide assembly (20’).

3. The downhole tool (1) according to claim 2, wherein the second flow guide assembly (20’) comprises two radially expandable barrier members (21’).

4. The downhole tool (1) according to claim 1, 2 or 3, wherein the first flow 40 guide assembly (20) comprises two radially expandable barrier members

(21).

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5. The downhole tool (1) according to any preceding claim, wherein the barrier member(s) (21, 21’) are able to selectively cycle between the radially unexpanded state and the radially expanded state.

6. The downhole tool (1) according to any preceding claim, wherein the one or more barrier member(s) (21, 21’) each comprise an elastomer.

7. The downhole tool (1) according to claim 6, wherein the one or more barrier 10 member(s) (21, 21’) each comprise a vulcanized elastomer.

8. The downhole tool (1) according to any preceding claim, wherein for each of the one or more barrier member(s) (21, 21’) a first end of the barrier member(s) (21, 21’) is moveable with respect to a second end of the barrier 15 member(s) (21, 21’).

9. The downhole tool (1) according to claim 8, wherein the first end of each of the one or more barrier member(s) (21, 21’) is attached to a respective first support member (23, 23’) and the second end of each of the one or more 20 barrier member(s) (21, 21’) is attached to a respective second support member (27, 27’), and wherein the first support member(s) (23, 23’) are axially movable with respect to the mandrel (10) and the second support member(s) (27, 27’) are axially fixed with respect to the mandrel (10).

25 10. The downhole tool (1) according to claim 9, wherein the first and second ends of the one or more barrier member(s) (21, 21’) are attached to the first support member(s) (23, 23’) and the second support member(s) (27, 27’) by means of vulcanized bonding.

30 11. The downhole tool (1) according to any preceding claim, wherein the threshold pressure is configured such that the one or more barrier member(s) (21, 21’) are in the radially expanded state before fluid communication between the inner bore (11) and the region outside the downhole tool (1) is allowed.

12. The downhole tool (1) according to any preceding claim, wherein the pressure regulator (40) comprises a pressure valve.

13. The downhole tool (1) according to any preceding claim, wherein the 40 pressure regulator (40) has a closed configuration and an open configuration, wherein the pressure regulator (40) is configured to prevent fluid communication between the inner bore (11) and the region outside the

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downhole tool (1) in the closed configuration, wherein the pressure regulator (40) is configured to allow communication between the inner bore (11) and the region outside the downhole tool (1) in the open configuration, and wherein the pressure regulator (40 is able to selectively cycle between the 5 closed configuration and the open configuration.

14. The downhole tool (1) according to claim 16, wherein the pressure regulator (40) comprises a sleeve (44) configured for axial displacement with respect to the mandrel (10) between a closed position and an open position for 10 configuring the pressure regulator (40) between the closed configuration and the open configuration, respectively.

15. The downhole tool (1) according to claim 17, wherein the pressure regulator (40) comprises a pressure chamber (42), wherein the pressure chamber (42) 15 is in fluid communication with the inner bore (11) through the at least one flow opening (12), and wherein the pressure regulator (40) comprises one or more ports (43) configured to allow fluid communication between the pressure chamber (42) and the region outside the downhole tool (1) when the sleeve (44) is in the open position, thereby allowing fluid communication 20 between the inner bore (11) and the region outside the downhole tool (1).

16. A method of using a downhole tool (1) according to any preceding claim, the method comprising:

- deploying the downhole tool (1) in a wellbore;

25 - activating the downhole tool (1) by configuring the one or more barrier member(s) (21, 21’) in the radially expanded state; and - conveying fluid to the wellbore by increasing fluid pressure in the inner bore (11) to at least the threshold pressure.

30 17. The method according to claim 16, wherein the one or more barrier member(s) (21, 21’) are cycled between the radially unexpanded state and the radially expanded state.

18. The method according to claim 16 or 17, comprising configuring the

35 threshold pressure such that the downhole tool (1) is activated before allowing fluid communication between the inner bore (11) and the wellbore.

19. The method according to any of claims 16 to 18, comprising moving the downhole tool (1) in an uphole direction or in a downhole direction with 40 respect to the wellbore while the downhole tool (1) is activated and while conveying fluid to the wellbore.

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20. The method according to claims 16 to 19, wherein the wellbore comprises a perforated tubing and wherein the method comprises positioning the downhole tool (1) such that at least one perforation of the perforated tubing is located between the first flow guide assembly (20) and the second flow 5 guide assembly (20’).

PATENTKRAV

1. Nedihullsverktøy (1) for brønnintervensjoner,

der nedihullsverktøyet (1) omfatter:

5 en mandril (10) som omfatter:

- en indre boring (11) og minst én strømningsåpning (12) for fluid kommunikasjon mellom den indre boringen (11) og en region på utsiden av nedihullsverktøyet (1),

et første strømningslederoppsett (20) som omfatter:

10 - ett eller flere radialt ekspanderingsbare barriereelementer (21) som er anbrakt rundt mandrilen (10) og som er konfigurerbare mellom en radialt ikke-ekspandert tilstand og en radialt ekspandert tilstand, der det ene eller de flere barriereelementene (21, 21’) hvert definerer en annulus (28, 28’), og der annulusen (28, 28’) er i fluid kommunikasjon med den indre boringen 15 (11) for å tvinge det ene eller de flere barriereelementene (21, 21’) mot den radialt ekspanderte tilstanden etter som fluidtrykk i den indre boringen (11) blir økt, og der mandrilen (10) omfatter en trykkoblingsåpning (13, 13’) for å levere fluid under trykk til annulusen(e) (28, 28’) som er definert ved det ene eller de flere barriereelementene (21, 21’), slik at fluid under trykk kommer 20 inn i annulusen(e) via trykkoblingsåpningene og dermed fyller opp barriereelementet/-elementene, og

karakterisert ved at

- annulusen(e) (28, 28’) er definert rundt mandrilen (10),

- en trykkregulator (40) er konfigurert for å tillate fluid kommunikasjon 25 mellom den indre boringen (11) og regionen på utsiden av nedihullsverktøyet (1), via den minst ene strømningsåpningen (12), når fluidtrykk i den indre boringen (11) når et terskeltrykk for å kunne et minimalt aktiveringstrykk for barriereelementet/-elementene før fluidkommunikasjonen er tillatt.

2. Nedihullsverktøy (1) ifølge krav 1,

der nedihullsverktøyet (1) omfatter et andre strømningslederoppsett (20’) og der minst én strømningsåpning (12) er lokalisert aksialt mellom det første strømningslederoppsettet (20) og det andre strømningslederoppsettet (20’).

3. Nedihullsverktøy (1) ifølge krav 2,

der det andre strømningslederoppsettet (20’) omfatter to radialt ekspanderbare barriereelementer (21’).

10 4. Nedihullsverktøy (1) ifølge krav 1, 2 eller 3,

der det første strømningslederoppsettet (20) omfatter to radialt ekspanderingsbare barriereelementer (21).

5. Nedihullsverktøy (1) ifølge ethvert foregående krav,

15 der barriereelementet/-elementene (21, 21’) selektivt er i stand til å veksle mellom den radialt ikke-ekspanderte tilstanden og den radialt ekspanderte tilstanden.

6. Nedihullsverktøy (1) ifølge ethvert foregående krav,

der det ene eller de flere barriereelementene (21, 21’) hvert omfatter en elastomer.

7. Nedihullsverktøy (1) ifølge krav 6,

der det ene eller de flere barriereelementene (21, 21’) hvert omfatter en vulkanisert elastomer.

25 8. Nedihullsverktøy (1) ifølge ethvert foregående krav,

der det for hvert av det ene eller de flere barriereelementene (21, 21’) er slik at en første ende av barriereelementet/-elementene (21, 21’) er bevegelig med hensyn på en andre ende av barriereelementet/-elementene (21, 21’).

9. Nedihullsverktøy (1) ifølge krav 8,

der den første enden av det ene eller de flere barriereelementene (21, 21’) er festet til et respektivt første støtteelement (23, 23’) og den andre enden av hvert av det ene 5 eller de flere barriereelementene (21, 21’) er festet til et respektivt andre støtteelement (27, 27’), og der det første støtteelementet/-elementene (23, 23’) er aksialt bevegelig med hensyn på mandrilen (10) og det andre støtteelementet/ -elementene (27, 27’) er aksialt festet med hensyn på mandrilen (10).

10 10. Nedihullsverktøy (1) ifølge krav 9,

der den første og den andre enden av det ene eller de flere barriereelementene (21, 21’) er festet til det første støtteelementet/-elementene (23, 23’) og det andre støtteelementet/-elementene (27, 27’) ved hjelp av vulkanisert binding.

15 11. Nedihullsverktøy (1) ifølge ethvert foregående krav,

der terskeltrykket er konfigurert slik at det ene eller de flere barriereelementene (21, 21’) foreligger i den radialt ekspanderte tilstanden før fluid kommunikasjon mellom den indre boringen (1) og regionen på utsiden av nedihullsverktøyet (1) er tillatt.

20 12. Nedihullsverktøy (1) ifølge ethvert foregående krav,

der trykkregulatoren (40) omfatter en trykkventil.

13. Nedihullsverktøy (1) ifølge ethvert foregående krav,

der trykkregulatoren (40) har en lukket konfigurasjon og en åpen konfigurasjon, der 25 trykkregulatoren (40) er konfigurert for å hindre fluid kommunikasjon mellom den indre boringen (11) og regionen på utsiden av nedihullsverktøyet (1) i den lukkede konfigurasjonen, der trykkregulatoren (40) er konfigurert for å tillate kommunikasjon mellom den indre boringen (11) og regionen på utsiden av nedihullsverktøyet (1) i den åpne konfigurasjonen, og der trykkregulatoren (40) er i

stand til selektivt å veksle mellom den lukkede konfigurasjonen og den åpne konfigurasjonen.

14. Nedihullsverktøy (1) ifølge krav 16,

5 der trykkregulatoren (40) omfatter en hylse (44) som er konfigurert for aksial forskyvning med hensyn på mandrilen (10) mellom en lukket posisjon og en åpen posisjon for å konfigurere trykkregulatoren (40) mellom henholdsvis den lukkede konfigurasjonen og den åpne konfigurasjonen.

10 15. Nedihullsverktøy (1) ifølge krav 17,

der trykkregulatoren (40) omfatter et trykkammer (42), der trykkammeret (42) er i fluid kontakt med den indre boringen (11) gjennom den minst ene strømningsåpningen (12), og der trykkregulatoren (40) omfatter én eller flere porter (43) som er konfigurert for å tillate fluid kommunikasjon mellom trykkammeret 15 (42) og regionen på utsiden av nedihullsverktøyet (1) når hylsen (44) er i den åpne posisjonen, for derved å tillate fluid kommunikasjon mellom den indre boringen (11) og regionen på utsiden av nedihullsverktøyet (1).

16. Fremgangsmåte for anvendelse av et nedihullsverktøy (1) ifølge ethvert 20 foregående krav,

der fremgangsmåten omfatter:

- utplassere nedihullsverktøyet (1) i et brønnhull,

- aktivere nedihullsverktøyet (1) ved å konfigurere det ene eller de flere barriereelementene (21, 21’) i den radialt ekspanderte tilstanden, og

25 - befordre fluid til brønnhullet ved å øke fluidtrykk i den indre boringen (11) til i det minste terskeltrykket.

17. Fremgangsmåte ifølge krav 16,

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der det ene eller de flere barriereelementene (21, 21’) blir vekslet mellom den radialt ikke-ekspanderte tilstanden og den radialt ekspanderte tilstanden.

18. Fremgangsmåte ifølge krav 16 eller 17,

5 som omfatter å konfigurere terskeltrykket slik at nedihullsverktøyet (1) blir aktivert før det tillates fluid kommunikasjon mellom den indre boringen (11) og brønnhullet.

19. Fremgangsmåte ifølge ethvert av kravene 16 til 18,

som omfatter å flytte nedihullsverktøyet (1) i en retning oppover i hullet eller i en 10 retning nedover i hullet med hensyn på brønnhullet mens nedihullsverktøyet (1) blir aktivert og mens fluid befordres til brønnhullet.

20. Fremgangsmåte ifølge kravene 16 til 19, der brønnhullet omfatter et perforert rør og der fremgangsmåten omfatter å posisjonere nedihullsverktøyet (1) slik at 15 minst én perforering av det perforerte røret er lokalisert mellom det første strømningslederoppsettet (20) og det andre strømningslederoppsettet (20’).

Drawings

Priority

No priority

Patent classes

IPC classes

E21B 37/00

E21B 33/124

E21B 33/127

E21B 33/13

E21B 34/08

CPC classes

E21B 37/00

E21B 33/124

E21B 33/127

E21B 33/13

E21B 34/08

Citations

US 2764244 A (A)

US 4279306 A (A)

Applicants, owners and inventors

Owners

ARCHER OILTOOLS AS

Postboks 8037

4068 STAVANGER

NO (STAVANGER Municipality, Rogaland county)

Org. number: 968145843

Inventors

Arve Byberg

Kolleholen 12

4353 KLEPP STASJON

NO (KLEPP Municipality, Rogaland county)

Agent

ACAPO ONSAGERS AS

Edvard Griegs vei 1

5059 BERGEN

NO (BERGEN Municipality, Vestland county)

Org. number: 932214636

Reference: P29687NO00

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Payment history

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No administrative limitation

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Only events from 2024.03.04 and onwards are shown.

A downhole tool with inflatable elements and a valve, and a method of using the downhole tool

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Abstract and drawing

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Description, claims and drawings

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