Key information

Title: Downhole tool including radially expandable barrier member and a method of using the downhole tool
Application number: 20241028
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: 349866
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, 101) for well interventions is disclosed. The downhole tool (1, 101) comprises a mandrel (10) comprising an inner bore (11) and a first flow guide assembly (20). The first flow guide assembly (20) comprises a radially expandable barrier member (21) and a piston assembly (22). The radially expandable barrier member (21) is arranged around the mandrel (10) and configurable between a radially unexpanded state and a radially expanded state. Furthermore, the barrier member (21) defines an annulus (28) around the mandrel (10) and the annulus (28) is in fluid communication with the inner bore (11) of the mandrel (10) for urging the barrier member (21) toward the radially expanded state as fluid pressure in the inner bore (11) is increased. The piston assembly (22) is in fluid communication with the inner bore (11) and comprises a piston (23) arranged for urging the barrier member (21) toward the radially expanded state as fluid pressure in the inner bore (11) is increased. A method of using the downhole tool (1, 101) is also disclosed.

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Date

Date	Doc. No.	Process	Case number	In/Out	Journal description	To/from
01.06.2026	09-01	Saksbehandling	20241028(349866)	UT	PT Registreringsbrev nasjonal patent (15) (PT20241028)
20.03.2026	08-01	Saksbehandling	20241028	UT	Intention to grant	ACAPO ONSAGERS AS
13.11.2025	07-05	Saksbehandling	20241028	INN	P29686NO00 Norwegian claims	ACAPO ONSAGERS AS
13.11.2025	07-04	Saksbehandling	20241028	INN	P29686NO00 - Amended specification for publication (marked copy) 1277605	ACAPO ONSAGERS AS
13.11.2025	07-03	Saksbehandling	20241028	INN	P29686NO00 - Amended specification for publication (clean copy) 1277603	ACAPO ONSAGERS AS
13.11.2025	07-02	Saksbehandling	20241028	INN	Letter_to_NIPO_Nov_11,_2025_1277249 1277604	ACAPO ONSAGERS AS
13.11.2025	07-01	Saksbehandling	20241028	INN	Korrespondanse (Hovedbrev inn)	ACAPO ONSAGERS AS
30.10.2025	06-01	Saksbehandling	20241028	UT	Substantive examination	ACAPO ONSAGERS AS
30.07.2025	04-04	Saksbehandling	20241028	INN	P29686NO00 request for postponement of grant	ACAPO ONSAGERS AS
30.07.2025	04-03	Saksbehandling	20241028	INN	P29686NO00 - reply to OA	ACAPO ONSAGERS AS
30.07.2025	04-02	Saksbehandling	20241028	INN	P29686NO00 - proposed amendments for 1OA	ACAPO ONSAGERS AS
30.07.2025	04-01	Saksbehandling	20241028	INN	Korrespondanse (Hovedbrev inn)	ACAPO ONSAGERS AS
12.05.2025	03-02	Saksbehandling	20241028	UT	PT report 12:51:43
12.05.2025	03-01	Saksbehandling	20241028	UT	Substantive examination	ACAPO ONSAGERS AS
15.10.2024	02-01	Saksbehandling	20241028	UT	Informasjon til oppfinner	Arve Byberg
14.10.2024	01-04	Saksbehandling	20241028	INN	P29686NO00 FINAL patent specification - to be filed 1192267	ACAPO ONSAGERS AS
14.10.2024	01-03	Saksbehandling	20241028	INN	P29686NO00 Final drawings 1191909	ACAPO ONSAGERS AS
14.10.2024	01-02	Saksbehandling	20241028	INN	Archer Oiltools AS 1173591	ACAPO ONSAGERS AS
14.10.2024	01-01	Saksbehandling	20241028	INN	Søknadsskjema Patent	ACAPO ONSAGERS AS
	05-02	Saksbehandling	20241028	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

349866

DOWNHOLE TOOL INCLUDING RADIALLY EXPANDABLE BARRIER

MEMBER,

AND A METHOD OF USING THE DOWNHOLE TOOL

5 TECHNICAL FIELD

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 10 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 15 no longer to be used, for example as it is no longer economically producing oil 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 20 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 25 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 30 or production tubing of the well is perforated by use of dedicated perforating tools.

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.

35 Such operations are typically referred to as perforate, wash and cement (PWC) 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

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systems allow for “one-trip” perforation, washing, cleaning and/or cementing 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 5 module) comprising two (or four) opposite packing assemblies is passed down the 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 10 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

15 engagement with the surrounding well pipe such that the fluid may be guided 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 20 vulnerable to wear and tear as the tool is transported down to the section(s) of the 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.

25 Worse still, the resulting cement plug may not meet the requirements, which can 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 30 devices that may restrict the inner cross-sectional area, or it may also be due to 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 35 packing rings of compressible and resilient material, with these rings being expandable responsive to sliding movement of slidable sleeves.

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

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SUMMARY OF THE INVENTION

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

5 a mandrel comprising an inner bore; and

a first flow guide assembly comprising:

- a radially expandable barrier member arranged around the mandrel and configurable between a radially unexpanded state and a radially expanded state, wherein the barrier member defines an annulus around the mandrel, and wherein the 10 annulus is in fluid communication with the inner bore for urging the barrier member toward the radially expanded state as fluid pressure in the inner bore is increased, and

- a piston assembly in fluid communication with the inner bore, and wherein the piston assembly comprises a piston arranged for urging the barrier member 15 toward the radially expanded state as fluid pressure in the inner bore is increased.

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 the 20 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 are 25 connected together to form the mandrel.

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 30 connections as known in the art.

In some embodiments, the first flow guide assembly may comprise two or more radially expandable barrier members. Each barrier member may be arranged around the mandrel and configurable between a radially unexpanded state and a radially 35 expanded state. Furthermore, each barrier member may define an annulus around the mandrel, wherein each annulus may be in fluid communication with the inner bore for urging the respective barrier members toward the radially expanded state as fluid pressure in the inner bore is increased. The two or more barrier members may be located adjacent to each other, e.g. axially adjacent to each other on the mandrel.

40 Each of the two or more barrier members may comprise any feature described in relation to the barrier member discussed herein.

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The barrier member may be able to selectively cycle between the radially unexpanded state and the radially expanded state. That means, the barrier member 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 barrier member 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 may be in contact with the internal circumference of the wellbore and the barrier member may thus provide a 10 sealing function. However, this need not be the case. In the radially expanded state, the outer diameter of the barrier member may also be less than the inner diameter of the wellbore. As such, the full circumference of the barrier member may not be in contact with the internal circumference of the wellbore. Even if there is not full contact between the barrier member and the internal diameter of the wellbore, e.g.

15 such that a certain leak of fluid across the barrier member is allowed, the barrier member may still provide sufficient sealing capabilities, or flow restricting capabilities, in order to carry out relevant well operations, as discussed further below. In the following, terms such as “sealing”, “sealing function”, “sealing capability” or “flow restricting capability” may be interchangeably used to refer to 20 the function of the barrier member in the expanded state, either when it is fully sealing or when it allows some leakage across, as discussed above.

The first flow guide assembly may be said to be “inactivated”, or to be in an “inactivated state”, when the barrier member is in the radially unexpanded state. 25 Furthermore, the first flow guide assembly may be said to be “activated”, or to be in an “activated state”, when the barrier member is in the radially expanded state. Thus, configuring the barrier member 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 30 barrier member from the radially expanded state to the radially unexpanded state may be referred to as “deactivating” 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 35 may be run into the wellbore in the deactivated state and then activated when the downhole tool is at a desired location in the well. Furthermore, the downhole tool may be deactivated, moved to a different location in the well, and then reactivated. The steps of deactivating, moving and reactivating the downhole tool may be repeated as many times as desired during a single trip in a wellbore. The downhole 40 tool may be deactivated before it is retrieved back to surface.

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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 5 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) 10 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.

15 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 20 state, the downhole tool may provide a barrier, or a sealing function, in the wellbore, e.g. by preventing fluid flow across the barrier member, or by sufficiently preventing fluid flow across the barrier member, as 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 and a location 25 below the barrier member in the wellbore, e.g. to perform operations such as integrity testing, fracturing, washing and/or cementing.

The downhole tool may be deployed in the wellbore by a suitable conveyance means. The conveyance means may be a tubing, such as a coiled tubing or a drill 30 pipe string. The downhole tool may be connected directly to the tubing, or to an intermediate tool between the downhole tool and the tubing, e.g. through one of the connections of the 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

35 measurement/logging tool or any other downhole tool necessary to carry out a relevant well operation.

In certain embodiments, the mandrel comprises at least one flow opening for fluid communication between the inner bore and a region outside the downhole tool. The 40 at least one flow opening may be a radial flow opening formed in the mandrel, such that fluid may flow radially between the inner bore and the region outside the downhole tool. When the downhole tool is deployed in a wellbore, the region

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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.

In certain embodiments, the downhole tool may comprise a second flow guide 5 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 assemblies. When the downhole tool is deployed in a wellbore, fluid may thus be 10 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 be between 5-25 diameters of the mandrel, between 5-20 diameters of the mandrel, 15 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 assemblies increases, the speed with which the fluid passes, or exits, the

20 perforations in the casing decreases for the same flow rate since the total flow area through the casing increases. This may reduce the washing effect.

The region in the wellbore may be defined, at least in part, by the mandrel, the first and second flow guide assemblies and the surrounding wellbore in which the 25 downhole tool is deployed. The wellbore may comprise a tubing in which the downhole tool is deployed. The tubing may e.g. be a casing, a liner or a production tubing. Thus, the region in the wellbore may be defined, at least in part, by the mandrel, the first and second flow guide assemblies and the surrounding tubing in which the downhole tool is deployed.

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. Furthermore, the second flow guide assembly may be activated and/or deactivated synchronously, or 35 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

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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 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 5 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 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 10 casing, a liner or a production tubing) may be a perforated tubing, and the downhole tool may be suitable for carrying out a washing operation and/or a plugging operation. Thus, the downhole tool may be a washing and/or a plugging tool.

Typically, cement is used as a plugging material. The tool may therefore generally be referred to as a washing and/or cementing tool without any restriction being 15 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 20 tubing by forcing fluid conveyed from surface through the perforations in the tubing and into the annulus. This may be achieved when the downhole tool is in the activated state. The annulus may be formed between two strings of tubing, e.g. between two casings, or between a production tubing and a surrounding casing. The annulus may also be formed between a tubing and a surrounding rock formation. 25 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

30 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 35 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 configuration in which the force exerted by the barrier members against the wellbore is set at a first, higher, level to increase 40 the 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 configuration in which the force exerted by the barrier members against

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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 still enclosed at increased pressure in the section of the well between the first and second flow guide 5 assemblies). This may lower friction and reduce wear on the barrier members during dynamic operations.

Therefore, the downhole tool may be suitable for carrying out dynamic washing and/or cementing operations. As such, the downhole tool may be a dynamic

10 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 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 15 may e.g. be at least 30 meters long, at least 50 meters long, e.g. about 100 meters long. The tool may be configured to be activated at the bottom of the perforated section and then pulled upwards along the perforated section while conveying fluids. As the flow guide assemblies are activated, a section of the wellbore around the downhole tool is enclosed such that pressure is allowed to increase, as discussed 20 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 present in the annulus. Such debris may comprise old, hardened cement from a 25 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 flow guide assembly) via the perforations and then back to surface. In this way, the 30 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.

35 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 “cementing operation” is used as cement is commonly used as the plugging

40 material. However, the downhole tool may convey any other suitable plugging material for forming a plug in the wellbore.

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It will be appreciated that the selectively activatable flow guide assemblies may 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 5 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 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 10 state while running into the hole is that excessive wear or damage, which may be caused by the barrier members being dragged against a 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 15 washing and/or cementing operations are carried out in a satisfactory manner, which may be crucial for establishing a satisfactory barrier/plug during e.g. a P&A operation.

The mandrel may comprise at least one pressure coupling opening for supplying 20 fluid under pressure to the annulus defined by the barrier member. The inner bore may thus communicate with the annulus through the at least one pressure coupling opening. In this way, as fluid pressure is increased in the inner bore, fluid under pressure may enter the annulus via the pressure coupling opening and consequently inflate the barrier member. As such, the barrier member is urged toward the radially 25 expanded state by inflation of the barrier member. The annulus may be formed, at least in part, between an internal surface of the barrier member and an external surface of the mandrel. Thus, the barrier member may be shaped as a sleeve around the mandrel. Preferably, the annulus is fluid-tight against the surroundings, i.e. against the region outside the downhole tool. The pressure coupling opening may be 30 a radial opening in the mandrel, providing direct radial connection between the inner bore and the annulus defined by the barrier member.

The barrier member may comprise an elastomer. The elastomer may be a vulcanized elastomer, e.g. a vulcanized rubber. Additionally, or alternatively, the elastomer 35 may be a fiber reinforced elastomer. Additionally, or alternatively, the elastomer may be metal reinforced, e.g. steel reinforced.

The piston may be axially movable with respect to the mandrel in order to urge the barrier member toward the radially expanded state. The piston may e.g. push a 40 sliding end of the barrier member toward a fixed end so that the barrier member deforms outward, such as via buckling. A first end of the barrier member may thus be moveable with respect to a second end of the barrier member.

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The combined action of the piston and the inflatable barrier member may provide certain advantages, especially during dynamic operations. The piston generates an axial force that compresses, or buckles, the barrier member toward the surrounding 5 wellbore wall. The inflation of the barrier member, on the other hand, provides a radial force to the barrier member that urges the barrier member toward the surrounding wellbore wall. The combined effect provides a balanced pressure, or force distribution on the barrier member and provides a larger axial engagement area between the barrier member and the surrounding wellbore wall. Furthermore, it 10 allows for a thicker barrier member to be used. For example, if the barrier member comprises an elastomer, it allows a thicker elastomer element to be used. The combination of a longer axial engagement area and a thicker elastomer element provides redundancy, as the internal pressure in the barrier member may continue to inflate and compensate for the elastomer being worn down. This makes the barrier 15 members less vulnerable to wear and tear during dynamic operations, where the barrier members may be moved along the rough inner surface of a perforated tubing. In other words, the downhole tool may provide sufficient sealing capabilities during dynamic operations (e.g. during washing or cementing as discussed above) over a longer period of time.

The first end of the barrier member may be attached to the piston and the second end of the barrier member may be attached to a support member. The support member may be arranged around a portion of the mandrel. The support member may be prevented from moving axially past a certain point in a direction away from the 25 piston, e.g. by means of an axial stopper. The axial stopper may be fixed to the mandrel and the support member may be prevented from moving past the axial stopper by coming into contact with the axial stopper.

The support member may be axially fixed with respect to the mandrel. Furthermore, 30 the support member may be fixed around a portion of the mandrel.

The first and second ends of the barrier member may be attached to the piston and the support member, respectively, by means of vulcanized bonding. The piston and the support member may comprise steel to which the barrier member is vulcanized.

35 The vulcanized bonding forms a more resilient and robust connection.

In some embodiments where the downhole tool comprises a second flow guide assembly, the flow guide assemblies may be mirrored across the at least one flow opening. For example, the fixed end of each barrier member may be axially closest 40 to the at least one flow opening and the sliding end of each barrier member may be axially furthest away from the at least one flow opening. In some embodiments, the support member to which each barrier member is attached may be axially closest to

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the at least one flow opening and the piston to which each barrier member is attached may be axially furthest away from the at least one flow opening.

The piston assembly may comprise a piston housing. The piston housing may be 5 arranged around a portion of the mandrel, adjacent to the barrier member. A first axial end of the piston may face a pressure chamber of the piston housing and a second axial end of the piston may be attached to the first end of the barrier member, as discussed above. Furthermore, the mandrel may comprise a second pressure coupling opening for supplying fluid under pressure to the pressure

10 chamber of the piston housing. In this way, fluid pressure in the inner bore is transferable to the piston. The second pressure coupling opening may be a radial opening in the mandrel, providing direct radial connection between the inner bore and the pressure chamber of the piston housing.

15 In an alternative embodiment, the piston may be activated in a different manner, e.g. by a sleeve located in the internal bore of the mandrel that is configured to translate axially to activate/move the piston. The sleeve may comprise a ball seat and be axially transferable by internal pressure in the inner bore of the mandrel after a ball is landed in the ball seat. In the case of two flow guide assemblies, one sleeve 20 comprising one ball seat may be used to activate both pistons.

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

Optionally, the downhole tool may comprise a centralizer assembly configurable between a radially unexpanded state and a radially expanded state. Similar to the 35 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 unexpanded state and the radially expanded state. That means, the centralizer assembly may be reconfigurable between the radially unexpanded state and the 40 radially expanded state repeatedly, e.g. while the downhole tool is deployed in a wellbore.

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The centralizer assembly may comprise a first plurality of mechanical linkages 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

5 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 member which may be 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 10 member, the mechanical linkages expand radially outwards. The second support member may comprise a piston, or be attached to a piston, that is activated in similar fashion to that discussed above in relation to the barrier member. That is, the centralizer assembly may comprise a piston assembly comprising any of the features of the piston assembly discussed above. One or more springs may be used to bias, 15 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. When 20 the downhole tool comprises a flow opening, 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, as discussed above, the downhole tool may also comprise two centralizer assemblies, each located adjacent to each respective flow guide assembly. Alternatively, the downhole tool 25 may comprise one centralizer assembly located adjacent to one of the flow guide assemblies.

The centralizer assembly may be configured to centralize the downhole tool in the wellbore before the barrier member is in the radially expanded state. This may align 30 the downhole tool in the wellbore and contribute to a uniform expansion of the barrier member. The centralizer assembly may be configured to expand before the barrier member, e.g. by configuring the downhole tool such that the centralizer assembly is urged toward the radially expanded state at a lower pressure than the barrier member. E.g., when the centralizer assembly comprises a piston, the piston 35 of the centralizer assembly may activate at a lower pressure compared to the piston associated with the barrier member. The activation pressure may e.g. be adjusted by adjusting the biasing force of the spring(s). 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 40 of the centralizer assembly.

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The downhole tool may comprise a pressure regulator configured to allow fluid communication between the inner bore and the region outside the downhole tool, via the at least one flow opening, when fluid pressure in the inner bore reaches a threshold pressure. The threshold pressure may be configured such that the barrier 5 member (and also the centralizer assembly/assemblies if present) is 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 10 pressure regulator may thus have an open configuration in which it allows fluid communication to the wellbore, and a closed configuration in which it prevents fluid communication to the wellbore.

The pressure regulator allows control of the fluid pressure in the inner bore of the 15 mandrel and thus control of the fluid pressure inside the downhole tool. As such, the force at which the barrier member is pushed towards, or against, the surrounding wellbore may be accurately controlled. In this way, the force on the barrier member may be balanced between a pressure high enough for the barrier member to provide a proper flow restricting function and a pressure sufficiently low to avoid

20 unnecessary wear on the barrier member. 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 capabilities over a longer period of time.

25 The pressure regulator may ensure a minimum activation pressure of the barrier member. This may allow the barrier member to provide sufficient sealing capabilities even if the required, or desired, washing pressure is low. This again 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 members are in their radially expanded state), 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 35 effects. The pressure regulator may thus also prevent these potential issues.

The pressure regulator may be able to selectively cycle between the open configuration and the closed configuration. That means, the pressure regulator may be reconfigurable between the open configuration and the closed configuration 40 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

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equal to or higher than the threshold pressure, and in the closed configuration when fluid pressure in the inner bore is lower than the threshold pressure.

In some embodiments, the pressure regulator may comprise a pressure valve 5 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 10 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 15 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.

20 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 the sleeve may face the pressure chamber such that fluid pressure in the inner bore 25 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 force of the biasing mechanism must be overcome for the sleeve to translate to the 30 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 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 pressure, may be adjusted by adjusting the biasing force of the biasing mechanism.

40 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

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pressure may be accurately adjusted and determined based on the parameters of a 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 5 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 10 further optional features mentioned above. The method comprises:

- deploying the downhole tool in a wellbore; and

- activating the downhole tool by increasing fluid pressure in the inner bore such that the barrier member is urged toward the radially expanded state as a result of:

15 a) an increase in fluid pressure in the annulus; and

b) the action of the piston on the barrier member in response to the increased fluid pressure in the inner bore.

Thus, the method may comprise activating the downhole tool via changes in

20 pressure within the inner bore of the mandrel and the level of force on the barrier member 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 of the wellbore.

25 The method may comprise conveying fluid to the wellbore through the at least one flow opening.

The method may comprise cycling the barrier members between the radially unexpanded state and the radially expanded state, by increasing and decreasing fluid 30 pressure in the inner bore.

The downhole tool may comprise a pressure regulator configured to allow fluid communication between the inner bore and the wellbore when fluid pressure in the inner bore reaches a threshold pressure. The pressure regulator may be the pressure 35 regulator discussed above for the first aspect and may include any of the optional features of the pressure regulator discussed above. 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 40 prior to deploying to downhole tool in the wellbore. Alternatively, the threshold pressure may be adjusted after 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. The method may further 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 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 this way, the downhole tool may be configured to adapt the level of force 10 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 configuration 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 15 flow guide assemblies (e.g. for static operations when the downhole tool is stationary in the well), and a second activated configuration 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 20 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.

In some embodiments, the well intervention may be carried out as part of a plug and 25 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 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 third aspect may 30 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 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 “cement” will be used herein without excluding any other suitable plugging

35 materials.

The method may comprise a step of deploying the downhole tool in the wellbore 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 40 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 barrier members.

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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 5 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.

10 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 15 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 20 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.

The downhole tool according to the third aspect may include any of the features of the downhole tool discussed above for the first aspect, both alone or in combination, and may also include any of the optional features mentioned above in relation to the first aspect. In context of the method of the third aspect the downhole tool need not 30 comprise the piston assembly and thus may include other features as discussed above without the piston assembly. Alternatively, the annulus defined by the barrier member need not be in fluid communication with the inner bore, and thus may include other features as discussed above without the annulus being in fluid communication with the inner bore.

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 first downhole tool, where the first downhole tool is in an inactivated state.

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Figures 1B and 1C show a portion of the first downhole tool as shown in Figure 1A, the portion including an upper flow guide assembly and an upper centralizer assembly. Figure 1B shows a longitudinal section and figure 1C shows a side view 5 of the portion.

Figure 2A shows a longitudinal section of the first downhole tool, where the first downhole tool is in an activated state.

10 Figures 2B and 2C show a portion of the first downhole tool as shown in Figure 2A, the portion including an upper flow guide assembly and an upper centralizer assembly of the first downhole tool. Figure 2B shows a longitudinal section and figure 2C shows a side view.

15 Figure 3A shows a longitudinal section of a second downhole tool, where the downhole tool is in an inactivated state.

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

Figure 4A shows a longitudinal section of the second downhole tool, where the second downhole tool is in an activated state while the pressure regulator is in a closed position.

25 Figure 4B shows a close-up of a portion of the second downhole tool as shown in Figure 4A, the portion including the pressure regulator.

Figure 5A shows another longitudinal section of the second downhole tool, where the downhole tool is in the activated state while the pressure regulator is in an open 30 position.

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

35 DESCRIPTION OF EXAMPLES

Figure 1A shows a first downhole tool 1. The first 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 40 first downhole tool 1 will be referred to as the downhole tool 1 hereafter.

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The downhole tool 1 comprises a cylindrical mandrel 10 comprising an inner 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 5 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

10 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 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 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 20 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.

The downhole tool 1 comprises an upper flow guide assembly 20 and a lower flow 25 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 and are positioned on each side of a flow opening. The flow opening is in the form 30 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 mandrel 10. The area outside the mandrel 10 is also an area outside of the downhole tool 1, in this example. Although only one radial flow port 12 is depicted, the mandrel 10 may comprise additional radial flow ports between the 35 upper and lower flow guide assemblies 20,20’.

The upper flow guide assembly 20 is illustrated in figures 1B and 1C, with figure 1B showing an enlarged longitudinal section of a portion of the downhole tool 1 and figure 1C showing a side view of the same portion. Features of the upper flow guide 40 assembly 20 described below are also found in the lower flow guide 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 349866

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 the upper flow guide assembly 20 and the lower flow guide assembly 20’ respectively. While the features 5 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 downhole tool 1. As can be seen in figure 1A the figure, the upper and lower flow guide assemblies are

10 mirrored across the radial flow port 12.

Each flow guide assembly 20,20’ comprises a barrier member in the form of a sleeve-shaped elastomer element 21,21’, which is positioned around the mandrel 10. As such, the sleeve-shaped elastomer element 21,21’ forms, or defines, an annulus 15 28,28’ around the mandrel 10. The annulus 28,28’ may be referred to as an annular region. The annulus 28,28’ lies between the barrier member and the mandrel. The annulus 28,28’ is thus at least partly defined by an inner surface of the elastomer element 21,21’ and an outer surface of the mandrel 10. In the present example, the sleeve-shaped elastomer element 21,21’ is made of a vulcanized elastomer.

The elastomer element 21,21’ is attached to a support member 27,27’ at one axial end and attached to a piston 23,23’ at the other axial end. In the present example, the elastomer element 21,21’ is attached to the support member 27,27’ and to the piston 23,23’, by means of vulcanized bonding.

In the depicted example the support member 27,27’ is a steel ring arranged around the mandrel 10. The support member 27,27’ is not fixed to the mandrel . However, an axial stopper (not indicated by a reference number) prevents the support member 27,27’ from moving axially past a certain point in a direction away from the piston 30 23,23’. Or put differently, the axial stopper prevents the support member 27,27’ from moving axially past a certain point toward the radial flow port 12. That is, the support member 27,27’ is prevented from moving past the axial stopper by coming into contact with the axial stopper. The axial stopper is ring-shaped and fixed to the mandrel adjacent to the support member 27,27’ between the support member 27,27’ 35 and the radial flow port 12.

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 the sleeve-shaped elastomer element 21,21’ is positioned around the mandrel 10. The second radial flow port 13,13’ 40 allows fluid communication between the inner bore 11 of the mandrel 10 and the annulus 28,28’. Although only one second radial flow port 13,13’ is depicted, the mandrel 10 may comprise additional second radial flow ports 13,13’ in the area

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where the sleeve-shaped elastomer element 21,21’ is positioned around the mandrel 10.

Each of the upper and lower flow guide assemblies 20,20’ further comprises a 5 piston assembly 22,22’. The mentioned piston 23,23’ to which the elastomer element 21,21’ is attached, forms part of the piston assembly 22,22’. The piston assembly 22,22’ further comprises a piston housing 24,24’ arranged around the mandrel 10 adjacent to the elastomer element 21,21’. A first axial end 23a,23a’ of the piston 23,23’ is arranged inside the piston housing 24,24’ and a second axial end 10 23b,23b’ of the piston 23,23’ is attached to the elastomer element 21,21’, as described above.

A pressure chamber 25,25’ is defined by the piston housing 24,24’, the outer surface of the mandrel 10 and the first axial end 23a,23a’of the piston 23,23’. The 15 piston housing 24,24’ further comprises an opening 26,26’ between a second chamber 29,29’ and the region outside the downhole tool 1. The opening 26,26’ allows the second chamber 29,29’, which is opposite the pressure chamber 25,25’ relative to the first axial end 23a,23a’ of the piston 23,23’, to be filled or emptied of fluid as the piston 23,23’ moves. In other words, the second chamber 29,29’ 20 communicates with the region outside the downhole tool 1 through the opening 26,26’. When the downhole tool 1 is deployed in a wellbore, the fluid may be a wellbore fluid, such as a drilling fluid. The opening 26,26’ may in some embodiments comprise a filter to prevent debris from entering the second chamber 29,29’ as debris may block the piston 23,23’ or restrict the movement of the piston 25 23,23’.

A second pressure coupling opening, in the form of a third radial flow port 14,14’, is formed in the mandrel 10 to allow fluid communication between the inner bore 11 of the mandrel 10 and the pressure chamber 25,25’. Although only one third radial 30 flow port 14,14’ is depicted, the mandrel 10 may comprise additional third radial flow ports 14,14’ to allow fluid communication between the inner bore 11 of the mandrel 10 and the pressure chamber 25,25’.

Still referring to figure 1A, the downhole tool 1 comprises an upper centralizer 35 assembly 30 and a lower centralizer assembly 30’. The upper centralizer assembly 30 is positioned uphole of the upper flow guide assembly 20, and the lower centralizer assembly 30’ is positioned down-hole of the lower flow guide assembly 20’. The upper centralizer assembly 30 is also shown in figures 1B and 1C.

40 The centralizer assembly 30,30’ comprises a plurality mechanical linkages 70, each mechanical linkage comprising a first link 31,31’ and a second link 32,32’ pivotally connected by a hinged connection 35,35’. The number of mechanical linkages 70

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per centralizer assembly 30,30’ may e.g. be three, although only two are shown in figures 1A-1C. For each of the mechanical linkages 70, the first link 31,31’ is attached to a piston 33,33’, and the second link 32,32’ is attached to a fixed support ring 34,34’. Each first link 31,31’ and each second link 32,32’ is pivotally attached 5 to the piston 33,33’ and the fixed support ring 34,34’, respectively, by a hinged connection. The fixed support ring 34,34’ is axially and rotationally fixed relative to the mandrel 10.

A plurality of springs 80 (only illustrated in figure 1C) are attached between the 10 fixed support ring 34,34’ and the piston 33,33’, next to the mechanical linkages 70.

The springs 80 provide a biasing force that urges the piston 33,33’ axially away from the fixed support ring 34,34’.

The centralizer assembly 30,30’ further comprises a piston housing 37,37’ arranged 15 around the mandrel 10. A first axial end 33a,33a’ of the piston 33,33’ is arranged inside the piston housing 37,37’ and a second axial end 33b,33b’ of the piston 33,33’ is connected to the first links 31,31’, as discussed above.

A pressure chamber 36,36’ is defined by the piston housing 37,37’, the outer 20 surface of the mandrel 10 and the first axial end 33a,33a’ of the piston 33,33’. The piston housing 37,37’ comprises an opening 39,39’ which allows a second chamber 38,38’ opposite the pressure chamber 36,36’ to be filled or emptied of fluid as the piston 33,33’ moves. Similar to the piston assembly 22,22’ of the upper and lower flow guide assemblies 20,20’, in some examples the opening 39,39’ may comprise a 25 filter to prevent debris from entering the second chamber 38,38, as debris may block the piston 33,33’ or restrict the movement of the piston 33,33’.

A third pressure coupling opening, in the form of a fourth radial flow port 15,15’, is formed in the mandrel 10 to allow fluid communication between the inner bore 11 30 of the mandrel 10 and the pressure chamber 36,36’. Although only one fourth radial flow port 15,15’ is depicted, the mandrel 10 may comprise additional fourth radial flow ports 15,15’ to allow fluid communication between the inner bore 11 of the mandrel 10 and the pressure chamber 36,36’.

35 In figures 1A-1C, 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’ and the mechanical linkages 70 of the centralizer assemblies 30,30’ are radially retracted. Radially retracted may also be referred to as radially unexpanded.

40 In figures 2A, 2B and 2C, 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’ and the mechanical linkages 70 of the centralizer assemblies 30,30’ are radially

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expanded. Figure 2A shows the downhole tool 1 in its entirety, while figures 2B and 2C show the portion of the downhole tool 1 including the upper flow guide assembly 20 and the upper centralizer assembly 30 in a section and side view, respectively.

To configure the downhole tool 1 in the activated state, a ball 50 is dropped and 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 10 openings 19. Thus, the only source of communication to the wellbore is through the radial flow port 12. 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 increased to activate the tool.

15 As pressure is increased in the inner bore, fluid enters the annulus 28,28’ through the second radial port 13,13’. As fluid enters the annulus 28,28’ it applies a force to the inside of the elastomer element 21,21’, thereby causing it to inflate and expand radially outwards. Thus, it can be said that the elastomer element 21,21’ is urged toward the radially expanded state by action of an internal force. Additionally, when 20 fluid enters the piston chamber 25,25’ through the third radial port 14,14’, the piston 23,23’ is pushed toward the support member 27,27’ , thereby compressing the elastomer element 21,21’. Thus, it can be said that the elastomer element 21,21’ is urged toward the radially expanded state by action of the piston 23,23’. As is apparent in figures 2A and 2B, the piston 23 has moved toward the support member 25 27 and the pressure chamber 25 has thus expanded. As such, the elastomer element 21,21’ is expanded radially both by inflation and by means of the piston 23,23’.

The piston 23,23’ generates an axial force that compresses, or buckles, the elastomer element 21,21’, causing it to expand radially outwardly. In use, the 30 elastomer element 21,21’ therefore expands toward the surrounding wellbore wall.

The inflation of the elastomer element 21,21’, on the other hand, provides a radial force that urges the elastomer element 21,21’ outwardly, and in use toward the surrounding wellbore wall. The combined effect can provide a balanced pressure, or force distribution on the elastomer element 21,21’ and may provide a larger axial 35 engagement area between the elastomer element 21,21’ and the surrounding wellbore wall. It also allows for a thicker elastomer element 21,21’ to be used. The combination of a longer axial engagement area and a thicker elastomer element 21,21’ provides redundancy, as the internal pressure in the elastomer element 21,21’ may continue to inflate and compensate for the elastomer being worn down. This 40 makes the elastomer element 21,21’ less vulnerable to wear and tear during dynamic washing and cementing operations, where the elastomer element 21,21’ is moved along the rough inner surface of a perforated casing.

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The centralizer assembly 30,30’ is activated as fluid under pressure enters the pressure chamber 36,36’ and pushes the piston 33,33’ toward the fixed support ring 34,34’. As the piston 33,33’ moves, the mechanical linkages 70 are caused to rotate 5 outward towards the surrounding casing (the casing not illustrated). This is facilitated by the hinged connection 35,35’ between the first link 31,31’ and the second link 32,32’ and the respective hinged connections to the piston 33,33’ and the fixed support ring 34,34’. As is apparent in figures 2A and 2B, the piston 33 has moved toward the fixed support ring 34 and the pressure chamber 36 has thus 10 expanded.

The downhole tool 1 may be configured such that the centralizer assemblies 30,30’ activates before the flow guide assemblies 20,20’. Centralizing and aligning the downhole tool 1 in the wellbore prior to expanding the elastomer elements 21,21’ 15 may provide substantially uniform expansion of the elastomer elements 21,21’. This may further enhance the downhole tool’s 1 performance and longevity.

The biasing force of the springs 80 may be determined to enable the centralizer assemblies 30,30’ to activate before the flow guide assemblies 20,20’. I.e., the 20 springs 80 may be chosen such that the force (and thus the pressure) to activate the centralizer assemblies 30,30’ is less than the force (and thus the pressure) to activate the flow guide assemblies 20,20’.

To deactivate the downhole tool 1, the fluid pressure in the inner bore 11 is

25 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 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. Furthermore, the 30 springs 80 of the centralizer assemblies 20,20’ will push the pistons 33,33’ axially away from their respective fixed support rings 34,34’ causing the mechanical linkages 70 to radially retract.

The downhole tool 1 may be activated and deactivated as many times as desired 35 during a single trip in a wellbore. As such, the downhole tool 1 may be run into (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

40 elastomer elements 21,21’ is reduced as unnecessary contact between the elastomer elements 21,21’ and the surrounding casing (or production tubing) is avoided. This

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again will ensure the downhole tool’s performance and increase the longevity of the elastomer elements 21,21’.

Figure 3A shows an example of a second downhole tool 101. The second downhole 5 tool 101 has the same features as the first downhole tool 1 depicted in figures 1A-2C, and additionally comprises a pressure regulator 40. The features of the second downhole tool 101 that are also found in the first downhole tool 1 are labelled with the same reference numerals, and are not described again for conciseness. The second downhole tool 101 is referred to as the downhole tool 101 below.

The pressure regulator 40 is shown enlarged in figure 3B. 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 15 first axial end 44a of a valve sleeve 44 arranged inside the regulator housing 41.

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.

20 The valve sleeve 44 can move axially between a closed position and an open 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 101, by blocking, or covering, flow ports 43 formed in the regulator housing 41. In the open position, the valve 25 sleeve 44 is moved axially such that it no longer blocks the flow ports 43. As such, 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 101. In figures 3A and 3B, the valve sleeve 44 is in the closed position.

A second chamber 48 is defined by the regulator housing 41, the outer surface of 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 35 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 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 place inside the regulator housing 41, and also to preload the spring 45. The retainer 349866

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 3A and 3B), while the spring 45 urges the valve sleeve 45 toward its closed position (i.e., toward the left in figures 3A and 3B). As such, for the valve sleeve 44 to move to 10 the open position, a force acting on the valve sleeve 44 from the fluid exceeds a biasing force acting on the valve sleeve 44 from the spring 4. 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 101.

In the example embodiment, 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’ and the mechanical linkages of the centralizer assemblies 30,30’ moves to the radially expanded state before the valve sleeve 44 moves to the 20 open position. In other words, the pressure regulator 40 is configured to allow the downhole tool 101 to activate before allowing fluid to be conveyed to a surrounding wellbore. This is achieved by configuring the threshold pressure higher than the activating pressure, i.e. the pressure required for the flow guide assemblies 20,20’ and the centralizer assemblies 30,30’ to radially expand. As is apparent, the biasing 25 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 done by positioning the retainer 47 closer to or further away from the valve sleeve 44 when attaching the retainer 47.

30 In figures 3A and 3B, the downhole tool 101 is in the inactivated state and the pressure regulator is closed.

In figure 4A, the downhole tool 101 is in the activated state, i.e. the flow guide assemblies 20,20’ and the centralizer assemblies 30,30’ are radially expanded . This 35 is achieved by dropping a ball 50 and increasing the fluid pressure in the inner bore 11, as explained in conjunction with figures 2A-2C. However, in figure 4A, 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 closed pressure regulator is shown in figure 4B.

In figure 5A, the fluid pressure in the inner bore is above threshold pressure so that the pressure regulator 40 is in the open position. Figure 5B shows a more detailed

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view of the open pressure regulator 40. As is apparent, the valve sleeve 44 has moved axially to the right in the figure compared to figure 4B 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

5 mandrel 10 to the region outside the downhole tool 101 via the radial flow port 12, the pressure chamber 42 and the flow ports 43.

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 10 inside the downhole tool 101. As such, the force at which the elastomer elements 21,21’ are pushed toward, or against, the surrounding wellbore may be accurately 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 15 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 performance and also increase the longevity of the elastomer elements 21,21’.

20 In an example method, the first downhole tool 1 or the second downhole tool 101 is used for a washing and cementing operation in conjunction with a PWC operation. A PWC operation may be performed in conjunction with a P&A operation. The chosen downhole tool 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 25 wellbore. The downhole tool is deployed and lowered down to the perforated section in the deactivated state to be able to 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 30 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 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 is positioned at a lower end of the perforated section and the 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. The fluid may e.g. be a washing fluid. The downhole tool is pulled upward along the perforated section 40 while conveying the washing fluid through the radial flow port 12. As the radially expanded elastomer elements 21,21’ restrict upward and downward flow inside the casing, the washing fluid is forced through the perforations in the casing and into

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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 solids particles present in the annulus and transport the 5 washed away debris and solids particles to the surface in order to clean the well.

When the downhole tool reaches an upper area of the perforated section, fluid flow is stopped such that the downhole tool 1 can deactivate. Then, the downhole tool is lowered back to the bottom of the perforated section. If the perforated section (i.e.

10 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).

15 To initiate the cementing step, fluid flow is again started to activate the downhole tool. Similar to the washing step, the downhole tool is pulled upward along the perforated section while conveying cement through the radial flow port 12. As the radially expanded elastomer elements 21,21’ restricts upward and downward flow inside the casing, the cement is forced through the perforations in the casing and 20 into the surrounding annulus, thus ensuring that the annulus is completely filled with cement along the perforated section. This may be referred to as a “pump and pull” method. When the downhole tool 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 25 formed in the wellbore. 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 can be deactivated and retrieved to the surface by the following steps; After the downhole tool has been 30 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 35 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 17, the ball 50 is not able to fully cover the axial flow openings 19. Thus, the fluid pressure inside the inner bore 11 is released and the downhole tool deactivates. Thereafter, 40 the downhole tool may be retrieved to the surface in the deactivated state.

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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. This may be performed in a separate step, between the washing and cementing step, 5 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, 101) for well interventions, the downhole tool (1, 101) comprising:

5 a mandrel (10) comprising an inner bore (11); and

a first flow guide assembly (20) comprising:

- a radially expandable barrier member (21) arranged around the mandrel (10) and configurable between a radially unexpanded state and a radially expanded state, wherein the barrier member (21) defines an annulus 10 (28) around the mandrel (10), and wherein the annulus (28) is in fluid communication with the inner bore (11) for urging the barrier member (21) toward the radially expanded state as fluid pressure in the inner bore (11) is increased, and

- a piston assembly (22) in fluid communication with the inner bore, 15 and wherein the piston assembly (22) comprises a piston (23) arranged for urging the barrier member (21) toward the radially expanded state as fluid pressure in the inner bore (11) is increased.

2. The downhole tool according (1, 101) to claim 1, wherein the barrier 20 member (21) is able to selectively cycle between the radially unexpanded state and the radially expanded state.

3. The downhole tool (1, 101) according to claim 1 or 2, wherein the mandrel (10) comprises at least one flow opening (12) for fluid communication 25 between the inner bore (11) and a region outside the downhole tool (1, 101).

4. The downhole tool (1, 101) according to claim 3, wherein the downhole tool (1, 101) comprises a second flow guide assembly (20’), and wherein the at least one flow opening (12) is located axially between the first flow guide 30 assembly (20) and the second flow guide assembly (20’).

5. The downhole tool (1, 101) according to any preceding claim, wherein the mandrel (10) comprises at least one pressure coupling opening (13, 13’) for supplying fluid under pressure to the annulus (28, 28’) defined by the barrier 35 member (21, 21’), and wherein the inner bore (11) communicates with the annulus (28, 28’) through the at least one pressure coupling opening (13, 13’).

6. The downhole tool (1, 101) according to any preceding claim, wherein the 40 barrier member (21, 21’) comprises an elastomer.

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7. The downhole tool (1, 101) according to claim 6, wherein the barrier member (21, 21’) comprises a vulcanized elastomer.

8. The downhole tool (1, 101) according to any preceding claim, wherein the 5 piston (23, 23’) is axially movable with respect to the mandrel (10) to urge the barrier member (21, 21’) toward the radially expanded state.

9. The downhole tool (1, 101) according to claim 8, wherein a first end of the barrier member is moveable with respect to a second end of the barrier 10 member.

10. The downhole tool (1, 101) according to claim 9, wherein the first end of the barrier member (21, 21’) is attached to the piston (23, 23’) and the second end of the barrier member (21, 21’) is attached to a support member (27, 15 27’), and wherein the support member (27, 27’) is axially fixed with respect to the mandrel (10).

11. The downhole tool (1, 101) according to claim 10, wherein the first and second end of the barrier member (21, 21’) are attached to the piston (23, 20 23’) and the support member (27, 27’), respectively, by means of vulcanized bonding.

12. The downhole tool (1, 101) according to any preceding claim, comprising a centralizer assembly (30, 30’), wherein the centralizer assembly (30, 30’) is 25 configurable between a radially unexpanded state and a radially expanded state.

13. The downhole tool (1, 101) according to any preceding claim, comprising a pressure regulator (40) configured to allow fluid communication between the 30 inner bore (11) and the region outside the downhole tool (1, 101), via the at least one flow opening (12), when fluid pressure in the inner bore (11) reaches a threshold pressure.

14. The downhole tool (1, 101) according to claim 13, wherein the threshold 35 pressure is configured such that the barrier member (21, 21’) is in the radially expanded state before fluid communication between the inner bore (11) and the region outside the downhole tool (1, 101) is allowed.

15. The downhole tool (1, 101) according to claim 13 or 14, wherein the

40 pressure regulator (40) comprises a pressure valve.

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16. The downhole tool (1, 101) according to any of claims 13 to 15, wherein the pressure regulator (40) has a closed configuration and an open configuration, wherein the pressure regulator (40) is configured to prevent communication between the inner bore (11) and the region outside the downhole tool (1, 5 101) 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, 101) in the open configuration, and wherein the pressure regulator (40) is able to selectively cycle between the closed configuration and the open configuration.

17. The downhole tool (1, 101) 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 configuring the pressure regulator (40) between the closed configuration 15 and the open configuration, respectively.

18. The downhole tool (1, 101) according to claim 17, wherein the pressure regulator (40) comprises a pressure chamber (42), wherein the pressure chamber (42) is in fluid communication with the inner bore (11) through the 20 at least one flow opening (12), and wherein the pressure regulator (40)

comprises one or more ports (43) configured to allow communication between the pressure chamber (42) and the region outside the downhole tool (1, 101) when the sleeve (44) is in the open position, thereby allowing communication between the inner bore (11) and the region outside the 25 downhole tool (1, 101).

19. The downhole tool (1, 101) according to claims 13 to 18, wherein the threshold pressure is configured such that both the barrier member (21, 21’) and the centralizer assembly (30, 30’) are in the radially expanded state 30 before communication between the inner bore (11) and the region outside the downhole tool (1, 101) is allowed.

20. The downhole tool (1, 101) according to claims 13 to 18, wherein the pressure regulator ensures a minimum activation pressure of the barrier 35 member.

21. A method of using a downhole tool (1, 101) according to any preceding claim, the method comprising:

- deploying the downhole tool (1, 101) in a wellbore; and 40 - activating the downhole tool (1, 101) by increasing fluid pressure in the inner bore (11) such that the barrier member (21, 21’) is urged toward the radially expanded state as a result of:

a) an increase in fluid pressure in the annulus (28, 28’); and

b) the action of the piston (23, 23’) on the barrier member (21, 21’) in response to the increased fluid pressure in the inner bore (11).

22. The method according to claim 21, wherein the barrier members (21, 21’) are cycled between the radially unexpanded state and the radially expanded state.

10 23. The method according to claim 21 or 22, wherein the downhole tool (1, 101) comprises a pressure regulator (40) configured to allow fluid communication between the inner bore (11) and the wellbore when fluid pressure in the inner bore (11) reaches a threshold pressure, wherein the method comprises configuring the threshold pressure such that the downhole tool (1, 101) is 15 activated before allowing fluid communication between the inner bore (11) and the wellbore; and activating the downhole tool (1, 101) prior to conveying fluid to the wellbore.

24. The method according to claim 21, 22 or 23, comprising moving the

20 downhole tool (1, 101) in an uphole direction or in a downhole direction with respect to the wellbore while the downhole tool (1, 101) is activated and while conveying fluid to the wellbore.

25. The method according to any of claims 21 to 24, wherein the wellbore 25 comprises a perforated tubing and wherein the method comprises positioning the downhole tool (1, 101) such that at least one perforation of the perforated tubing is located between the barrier members (21, 21’).

PATENTKRAV

1. Nedihullsverktøy (1, 101) for brønnintervensjoner,

der nedihullsverktøyet (1, 101) omfatter:

5 et kjernerør (10) som omfatter en indre boring (11), og

et første strømningsføringsoppsett (20) som omfatter:

- et radialt ekspanderingsbart barriereelement (21) som er anbrakt rundt kjernerøret (10) og som er konfigurerbar mellom en radialt ikke-ekspandert tilstand og en radialt ekspandert tilstand, der barriereelementet (21) definerer 10 en annulus (28) rundt kjernerøret (10), og der annulusen (28) er i fluid kommunikasjon med den indre boringen (11) for å tvinge barriereelementet (21) mot den radialt ekspanderte tilstanden når fluidtrykket i den indre boringen (11) blir økt, og

- et stempeloppsett (22) i fluid kommunikasjon med den indre boringen, og 15 der stempeloppsettet (22) omfatter et stempel (23) som er anbrakt for å tvinge barriereelementet (21) mot den radialt ekspanderte tilstanden ettersom fluidtrykket i den indre boringen (11) blir økt.

2. Nedihullsverktøy (1, 101) ifølge krav 1,

20 der barriereelementet (21) er i stand til selektivt å veksle mellom den radialt ikkeekspanderte tilstanden og den radialt ekspanderte tilstanden.

3. Nedihullsverktøy (1, 101) ifølge krav 1 eller 2,

der kjernerøret (10) omfatter minst én strømningsåpning (12) for fluid

25 kommunikasjon mellom den indre boringen (11) og en region på utsiden av nedihullsverktøyet (1, 101).

4. Nedihullsverktøy (1, 101) ifølge krav 3,

der nedihullsverktøyet (1, 101) omfatter et andre strømningsføringsoppsett (20’), og der minst én strømningsåpning (12) er lokalisert aksialt mellom det første strømningsføringsoppsettet (20) og det andre strømningsføringsoppsettet (20’).

5 5. Nedihullsverktøy (1, 101) ifølge ethvert foregående krav,

der kjernerøret (10) omfatter minst én trykkoblingsåpning (13, 13’) for å levere fluid under trykk til annulusen (28, 28’) definert ved barriereelementet (21, 21’), og der den indre boringen (11) kommuniserer med annnulusen (28, 28’) gjennom den minst ene trykkoblingsåpningen (13, 13’).

6. Nedihullsverktøy (1, 101) ifølge ethvert foregående krav,

der barriereelementet (21, 21’) omfatter en elastomer.

7. Nedihullsverktøy (1, 101) ifølge krav 6,

15 der barriereelementet (21, 21’) omfatter en vulkanisert elastomer.

8. Nedihullsverktøy (1, 101) ifølge ethvert foregående krav,

der stempelet (23. 23’) er aksialt bevegelig med hensyn på kjernerøret (10) for å tvinge barriereelementet (21, 21’) mot den radialt ekspanderte tilstanden.

9. Nedihullsverktøy (1, 101) ifølge krav 8,

der en første ende av barriereelementet er bevegelig med hensyn på en andre ende av barriereelementet.

25 10. Nedihullsverktøy (1, 101) ifølge krav 9,

der den første enden av barriereelementet (21, 21’) er festet til stempelet (23, 23’) og den andre enden av barriereelementet (21, 21’) er festet til et støtteelement (27,

27’), og der støtteelementet (27, 27’) er aksialt festet med hensyn på kjernerøret (10).

11. Nedihullsverktøy (1, 101) ifølge krav 10,

5 der den første og den andre enden av barriereelementet (21, 21’) henholdsvis er festet til stemplet (23. 23’) og støtteelementet (27, 27’) ved hjelp av vulkanisert binding.

12. Nedihullsverktøy (1, 101) ifølge ethvert foregående krav,

10 som omfatter et sentraliseringsoppsett (30, 30’), der sentraliseringsoppsettet (30, 30’) kan konfigureres mellom en radialt ikke-ekspandert tilstand og en radialt ekspandert tilstand.

13. Nedihullsverktøy (1, 101) ifølge ethvert foregående krav,

15 som omfatter en trykkregulator (40) som er konfigurert for å tillate fluid kommunikasjon mellom den indre boringen (11) og regionen på utsiden av nedihullsverktøyet (1, 101), via den minst ene strømningsåpningen (12), når fluidtrykk i den indre boringen (11) når et terskeltrykk.

20 14. Nedihullsverktøy (1, 101) ifølge krav 13,

der terskeltrykket er konfigurert slik at barriereelementet 821, 2|1’) er i den radialt ekspanderte tilstanden før fluidkommunikasjon mellom den indre boringen (11) og regionen på utsiden av nedihullsverktøyet (1, 101) er tillatt.

25 15. Nedihullsverktøy (1, 101) ifølge krav 13 eller 14,

der trykkregulatoren (40) omfatter en rykkventil.

16. Nedihullsverktøy (1, 101) ifølge ethvert av kravene 13 til 15,

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der trykkregulatoren (40) har en lukket konfigurasjon og en åpen konfigurasjon, der trykkregulatoren (40) er konfigurert for å forhindre kommunikasjon mellom den indre boringen (11) og regionen på utsiden av nedihullsverktøyet (1, 101) i den lukkede konfigurasjonen, der trykkregulatoren (40) er konfigurert for tillate

5 kommunikasjon mellom den indre boringen (11) og regionen på utsiden av nedihullsverktøyet (1, 101) i den åpne konfigurasjonen, og der trykkregulatoren (40) er i stand til selektivt å veksle mellom den lukkede konfigurasjonen og den åpne konfigurasjonen.

10 17. Nedihullsverktøy (1, 101) ifølge krav 16,

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

18. Nedihullsverktøy (1, 101) ifølge krav 17,

der trykkregulatoren (40) omfatter et trykkammer (42), der trykkammeret (42) er i fluid kommunikasjon med den indre boringen (11) gjennom den minst ene strømningsåpningen (12), og der trykkregulatoren (40) omfatter én eller flere porter 20 (43) som er konfigurert for å tillate kommunikasjon mellom trykkammeret (42) og regionen på utsiden av nedihullsverktøyet (1, 101) når hylsen (44) er i den åpne posisjonen, for derved å tillate kommunikasjon mellom den indre boringen (11) og regionen på utsiden av nedihullsverktøyet (1, 101).

25 19. Nedihullsverktøy (1, 101) ifølge kravene 13 til 18,

der terskeltrykket er konfigurert slik at både barriereelementet (21, 21’) og sentraliseringsoppsettet (30, 30’) foreligger i den radialt ekspanderte tilstanden før kommunikasjon mellom den indre boringen (11) og regionen på utsiden av nedihullsverktøyet (1, 101) er tillatt.

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20. Nedihullsverktøy (1, 101) ifølge kravene 13 til 18,

der trykkregulatoren garanterer et minste aktiveringstrykk for barriereelementet.

21. Fremgangsmåte for å benytte et nedihullsverktøy (1, 101) ifølge ethvert 5 foregående krav,

der fremgangsmåten omfatter:

- utplassere nedihullsverktøyet (1, 101) i et brønnhull, og

- aktivere nedihullsverktøyet (1, 101) ved å øke fluidtrykk i den indre boringen (11) slik at barriereelementet (21, 21’) blir tvunget mot den radialt 10 ekspanderte tilstanden som et resultat av:

a) en økning i fluidtrykk i annulusen (28, 28’), og

b) virkningen av stemplet (23, 23’) på barriereelementet (21, 21’) som respons på økningen i fluidtrykk i den indre boringen.

15 22. Fremgangsmåte ifølge krav 21,

der barriereelementene (21, 21’) blir vekslet mellom den radialt ikke-ekspanderte tilstanden og den radialt ekspanderte tilstanden.

23. Fremgangsmåte ifølge krav 21 eller 22,

20 der nedihullsverktøyet (1, 101) omfatter en trykkregulator (40) som er konfigurert for å tillate fluid kommunikasjon mellom den indre boringen (11) og brønnhullet når fluidtrykk i den indre boringen (11) når et terskeltrykk, der fremgangsmåten omfatter å konfigurere terskeltrykket slik at nedihullsverktøyet (1, 101) blir aktivert før det tillates fluidkommunikasjon mellom den indre boringen (11) og brønnhullet, 25 og aktivering av nedihullsverktøyet (1, 101) før befordring av fluid til brønnhullet.

24. Fremgangsmåte ifølge krav 21, 22 eller 23,

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som omfatter å bevege nedihullsverktøyet (1, 101) i en retning oppover i hullet eller en retning nedover i hullet med hensyn på brønnhullet mens nedihullsverktøyet (1, 101) blir aktivert og befordre fluid til brønnhullet.

5 25. Fremgangsmåte ifølge ethvert av kravene 21 til 24,

der brønnhullet omfatter et perforert rør og der fremgangsmåten omfatter å posisjonere nedihullsverktøyet (1, 101) slik at minst én perforering i det perforerte røret er lokalisert mellom barriereelementene (21, 21’).

Drawings

Priority

No priority

Patent classes

IPC classes

E21B 37/00

E21B 33/124

E21B 33/127

E21B 33/128

E21B 33/13

CPC classes

E21B 37/00

E21B 33/124

E21B 33/127

E21B 33/128

E21B 33/13

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: P29686NO00

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Payment history

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No oppositions or appeals

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No administrative limitation

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No liens or licenses registered

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Only events from 2024.03.04 and onwards are shown.

Downhole tool including radially expandable barrier member 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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