Key information

Title: FUNDAMENT TOOL
Application number: 20241032
Case type: National
Status: 26.05.2026 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: 26.05.2026
Patent number: 349843
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.

There is provided a downhole tool (100) for setting in a wellbore (400). The downhole tool comprising a mandrel (106), a radially expandable centralizer assembly (130) arranged around a first portion (132) of the mandrel (106), a piston assembly (120), and a radially expandable barrier element (160) arranged around a second portion (162) of the mandrel (106). The piston assembly (120) comprises a piston (128) arranged such the centralizer assembly (130) is configurable between an unexpanded state and a radially expanded state by axial movement of the piston (128) with respect to the mandrel (106) and configurable between an unexpanded state and a radially expanded state. The downhole tool (100) is arranged such that a first end (164) of the barrier element (160) is moveable with respect to a second end (166) of the barrier element (160) by axial movement of the mandrel (106).

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Date

Date	Doc. No.	Process	Case number	In/Out	Journal description	To/from
26.05.2026	09-01	Saksbehandling	20241032(349843)	UT	PT Registreringsbrev nasjonal patent (15) (PT20241032)
13.03.2026	08-01	Saksbehandling	20241032	UT	Intention to grant	ACAPO ONSAGERS AS
01.10.2025	07-05	Saksbehandling	20241032	INN	Patent_specification_Sep_30,_2025_1265397	ACAPO ONSAGERS AS
01.10.2025	07-04	Saksbehandling	20241032	INN	P29668NO00 - Amended specification with description and claims (marked copy) 1264508	ACAPO ONSAGERS AS
01.10.2025	07-03	Saksbehandling	20241032	INN	P29668NO00 - Amended specification with description and claims (clean copy) 1265794	ACAPO ONSAGERS AS
01.10.2025	07-02	Saksbehandling	20241032	INN	Letter_to_NIPO_Sep_26,_2025_1264349	ACAPO ONSAGERS AS
01.10.2025	07-01	Saksbehandling	20241032	INN	Korrespondanse (Hovedbrev inn)	ACAPO ONSAGERS AS
10.09.2025	06-01	Saksbehandling	20241032	UT	Substantive examination	ACAPO ONSAGERS AS
19.06.2025	04-05	Saksbehandling	20241032	INN	P29668NO00 request postponement of the grant	ACAPO ONSAGERS AS
19.06.2025	04-04	Saksbehandling	20241032	INN	P29668NO00 Reply 19 Jun 2025	ACAPO ONSAGERS AS
19.06.2025	04-03	Saksbehandling	20241032	INN	P29668NO00 - amended claims (TC)	ACAPO ONSAGERS AS
19.06.2025	04-02	Saksbehandling	20241032	INN	P29668NO00 - amended claims (clean)	ACAPO ONSAGERS AS
19.06.2025	04-01	Saksbehandling	20241032	INN	Korrespondanse (Hovedbrev inn)	ACAPO ONSAGERS AS
29.04.2025	03-02	Saksbehandling	20241032	UT	PT report 12:02:51
29.04.2025	03-01	Saksbehandling	20241032	UT	Substantive Examination	ACAPO ONSAGERS AS
15.10.2024	02-01	Saksbehandling	20241032	UT	Informasjon til oppfinner	Arve Byberg
14.10.2024	01-04	Saksbehandling	20241032	INN	P29668NO00 Figures	ACAPO ONSAGERS AS
14.10.2024	01-03	Saksbehandling	20241032	INN	P29668NO00 Description claims abstract	ACAPO ONSAGERS AS
14.10.2024	01-02	Saksbehandling	20241032	INN	Archer Oiltools AS	ACAPO ONSAGERS AS
14.10.2024	01-01	Saksbehandling	20241032	INN	Søknadsskjema Patent	ACAPO ONSAGERS AS
	05-02	Saksbehandling	20241032	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

349843

FUNDAMENT TOOL

Field of Invention

The present invention relates to a downhole tool for setting in a wellbore. In particular, the downhole tool is for use in a well-plugging process in which a well-5 plug such as a cement well-plug is fabricated on the downhole tool. The present invention also relates to a method of fabricating a well plug using the downhole tool.

Background

Well plugging is the process of fabricating a well plug in a wellbore. A well plug 10 typically seals the wellbore. This can be critical for isolating different sections of a wellbore for example to prevent the crossflow of fluids between geological formations, and / or to ensure that no hydrocarbons or other fluids escape into the environment. Well plugs are particularly important during well abandonment, maintenance, and interventions, where secure sealing is essential to prevent leaks 15 and maintain environmental safety.

There are a number of known techniques for plugging a well. Many of these involve fabricating a cement well plug by pumping cement slurry in such a way that the cement is placed at a designated depth in the wellbore where the cement can then set to form the well plug. Many jurisdictions have strict requirements governing 20 well plugs. For example, to establish an acceptable cement plug, it is often a requirement that a certain continuous length of solid / uniform hardened cement is provided.

Commonly, so-called “bridge plugs” are used as cement bases or fundaments to ensure that the bottom of the cement plug is at the desired depth and to ensure that 25 the usually heavier cement does not flow downwards in the wellbore and mix with other fluids (typically drilling fluids or completion fluids / brine) during construction of the cement plug.

In plugging processes utilising bridge plugs, the bridge plug must be positioned in the desired location of the wellbore prior to fabricating the cement portion of the 30 plug. Therefore, the diameter of the bridge plug relative to the minimum diameter of the wellbore is an important consideration to ensure that the bridge plug can be run through the wellbore to the desired location. In view of this, bridge plugs are adjustable between a run-in state and an activated state. A maximum diameter of the bridge plug is reduced in the run-in state relative to a maximum diameter of the 35 bridge plug in the activated state. Usually, the difference in maximum diameter of the plug between the two states is relatively small. In uniform wellbores, this is not a problem. The diameter of the plug need only be reduced slightly for the plug to be 349843

small enough in diameter to run through the wellbore. The diameter can then be increased slightly when the plug is in position in order to seal the wellbore.

However, some wellbores have regions with reduced diameters, bends, joints and / or other restrictions and constrictions. This can complicate and / or limit the useful 5 deployment of bridge plugs. The run-in diameter of the bridge plug must be smaller than the smallest diameter constriction in the wellbore from surface to desired location. The bridge plug can only be useful in a plugging operation if the difference between the minimum diameter of the wellbore and the diameter of the wellbore at the desired location is less than the change in maximum diameter of the 10 bridge plug between the run-in and activated state. There are bridge plugs on the market that attempt to address this issue by providing relatively large diameter differences between the run-in and activated state, so-called “high expansion bridge plugs”. However, such bridge plugs are usually complicated and expensive. This is particularly a problem because bridge plugs are generally designed to isolate the 15 wellbore and thus be able to withstand high pressure differentials. Designing a high expansion bridge plug that is able to isolate the wellbore requires complicated and expensive expansion mechanisms.

NO 20220465 A1 relates to a downhole plug system that employs a plug for sealing off a central bore of a well, a plug mandrel, an anchor mechanism and packer 20 assembly. The system is provided with the plug mandrel and lock ring comprising a ratchet mechanism that prevents the lock ring from sliding upwards on a plug mandrel. A running tool is provided with a mandrel with a central bore, a piston sleeve slidably arranged on the running tool mandrel with a uphole facing piston area on an inside, and one or more upper ports arranged to provide fluid

25 communication between the central bore and the piston area. A tear bolt is arranged to initially connect the plug to the running tool to tear at a predetermined tension. The piston sleeve is arranged so that a differential pressure between the central bore and a annulus will force the piston sleeve to slide downwardly on the running tool mandrel, moving the lock ring downwardly and forcing the at least one set of slips 30 downwardly and onto the at least one ramp and radially outwardly to engage a wall in the well, the downwards movement and force of the lock ring is transferred through the anchor mechanism so that the compressor ring is moved axially downwardly compressing the packer element axially between the compressor ring and the stop ring.

35 There is a need for a tool for wellbore plugging process that addresses at least some of these issues. For example, there is a need for such a tool that is less complicated and less expensive. There is also a need for a tool that is flexible and can be used in non-uniform and complicated wellbores, for example with relatively large variations in diameter from the surface to the desired location of the well plug.

349843

Summary of Invention

The present invention is defined by the appended claims and in the following.

In a first aspect, there is provided a downhole tool for setting in a wellbore. In embodiments, the downhole tool is for supporting a filler material, such as cement, 5 uphole of the tool. In embodiments, the downhole tool is for use during a holeplugging process.

The downhole tool comprises a mandrel. In embodiments, the mandrel is tubular. In embodiments, the mandrel extends substantially axially.

The downhole tool comprises a radially expandable centralizer assembly. The 10 radially expandable centralizer assembly is arranged around a first portion of the mandrel.

The downhole tool comprises a piston assembly. The piston assembly comprises a piston, operatively connected to a first end of the centralizer assembly. The piston is arranged such the centralizer assembly is configurable between an unexpanded state 15 and a radially expanded state. This is achieved by axial movement of the piston with respect to the mandrel.

The downhole tool comprises a radially expandable barrier element. The barrier element is arranged around a second portion of the mandrel. The barrier element is configurable between an unexpanded state and a radially expanded state.

20 The downhole tool is arranged such that a first end of the barrier element is moveable with respect to a second end of the barrier element by axial movement of the mandrel. The first end is moveable axially with respect to the second end, such that a distance between the first end and the second end of the barrier element is changed by axial movement of the mandrel and such that axial movement of the 25 mandrel configures the barrier element between the unexpanded state and the radially expanded state.

The downhole tool and / or the barrier element may be arranged such that the barrier element is configurable between the unexpanded state and the radially expanded state as a result of either or both of: a mechanical action on the barrier element and 30 inflation of the barrier element. Therefore, in some embodiments, the barrier element may be inflatable. In some embodiments, the barrier element is a bulk element such as a bulk elastomer element. The barrier element may comprise a vulcanized elastomer. In some embodiment, the barrier element is deformable.

In some embodiments, the barrier element defines an annulus around the mandrel.

35 The annulus may be in fluidic communication with an inner bore of the mandrel such that pressure within the inner bore of the mandrel is transferable to the

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annulus. Advantageously, this may be such that increased pressure in the inner bore causes the barrier element to inflate. The barrier element may be arranged to radially expand as it is caused to inflate.

An advantage of embodiments comprising an inflatable barrier element comprising 5 an annulus in fluidic communication with the inner bore is that the piston can be activated at the same time as inflating the barrier element. As explained in more detail below, the piston assembly may be arranged such that increased pressure in the inner bore of the mandrel is transferable to the piston. In such cases, an increase in pressure in the inner bore of the mandrel may advantageously simultaneously 10 move the piston (axially) and inflate the barrier element. However, in some embodiments, the pressure required to move the piston to properly expand the centralizer assembly may be lower than the pressure required to properly inflate the barrier element. So, as the pressure in the inner bore of the mandrel is increased, it may be that the centralizer assembly reaches its radially expanded state prior to the 15 barrier element reaching its respective radially expanded state. In some embodiments, the barrier element is configurable in the radially expanded state at least in part by increasing the pressure in the inner bore of the mandrel to inflate the barrier element.

In some embodiments, the downhole tool is arranged such that configuring the 20 barrier element between the unexpanded state and the radially expanded state comprises axial movement of the mandrel. The downhole tool and / or the barrier element may be arranged such that said axial movement of the mandrel has a mechanical action on the barrier element. The downhole tool and / or the barrier element may be arranged such that axial movement of mandrel may cause a change, 25 such as a reduction, in a distance or separation between the first end and the second end of the barrier element. In some embodiments, this may have the effect of compressing the barrier element and so causing radial expansion of the barrier element. As explained in more detail below, the downhole being arranged such that axial movement of the mandrel causes mechanical action on the barrier element may 30 be advantageous because this can be the same movement that is used to disengage the tool. In some embodiments, the downhole tool is arranged such that the barrier elementis configurable in the radially expanded state at least in part by axial movement of the mandrel.

It may be particularly advantageous for the downhole tool to be arranged such that 35 the barrier element is configurable between the unexpanded state and the radially expanded state as a result of a combination of mechanical action and inflation. This can reduce the operational requirements of either the mechanical action or the inflation. For example, the inventors have found that, if the tool is arranged such that the barrier element is configurable to the radially expanded state based solely 40 on mechanical action (e.g. pulling on the mandrel), then relatively very high forces

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may be required to compress the barrier element to achieve sufficient radial expansion. However, inflating the barrier element in combination with mechanical action may reduce the force required of the mechanical action to a more manageable level.

5 In some embodiments, the tool is arranged such that axial movement of the mandrel (to radially expand the barrier element) is achieved by pulling on the tool / mandrel in and axial direction (e.g. from an uphole end of the tool). Alternatively, or additionally, the piston assembly may be arranged to drive axial movement of the mandrel with respect to the piston (to radially expand the barrier element). The 10 piston assembly may be arranged to drive said axial movement of the mandrel with respect to the piston after configuring the centralizer assembly into the radially expanded state and while the tool is received in a wellbore. The axial movement of the mandrel may be in an uphole direction.

The downhole tool, once set in a wellbore, may be for supporting a filler material.

15 The filler material may be cement. The downhole tool may be for use in a holeplugging process, in particular a hole-plugging process in which a cement plug is formed. The filler material may be retained substantially uphole of the downhole tool during a hole-plugging process. In other words, the downhole tool may act as a foundation or base on which cement may rest (e.g. during a cement displacement 20 process). The tool, when set in a wellbore and activated (in other words, when in use), may be configured to prevent cement (or cement slurry) from flowing downhole, past the tool. The cement (or cement slurry) may then set and plug the wellbore at the point in the wellbore that the tool is deployed. The tool provides support for a cement column or plug formed uphole of the plug. For this reason, the 25 downhole tool may be referred to as a “fundament tool” herein.

It may be the barrier element, in the radially expanded state, which retains the filler material uphole of the downhole tool. The barrier element may also be referred to as a barrier member. The barrier member or element may be configured to retain, restrain, prevent, hinder or otherwise impede the flow of filler material (such as 30 cement slurry) downhole of the barrier element. The barrier element may also be referred to as a barrier element. As used herein, “seal” may refer to the barrier element preventing the flow of cement slurry downhole of the barrier or barrier element when in the radially expanded state. The barrier element need not provide a fluid-tight seal such as air-tight seal in the wellbore.

35 The downhole tool according to the present invention is particularly advantageous for deployment in wellbores where there is a relatively small minimum size of tool that can be deployed (e.g. because of a relatively small wellbore diameter and / or because of other constrictions or restrictions in the wellbore between the surface and the intended deployment position of the tool). The downhole tool can be

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deployed while the centralizer assembly and the barrier element are both in their respective unexpanded states. In these states, an overall diameter of the tool is considerably reduced meaning the tool can pass constrictions or restrictions in the wellbore on transit to the intended position of the tool in the wellbore. Then, once 5 the downhole tool is in position, the centralizer assembly and the barrier element can be radially expanded to centralize the tool and provide a barrier for cement slurry, as described above.

The combination of the centralizer assembly being configurable into the radially expanded state by axial movement of a piston and the barrier element being

10 configurable into the radially expanded state by axial movement of the mandrel is particularly advantageous. These mechanisms of activation can be provided in simple and space efficient manners. Activation of each mechanism is straightforward and does not require complicated or expensive apparatus e.g. comprising a relatively large number of moving parts. For example, the piston 15 provides a simple means for expanding the centraliser assembly. The axial movement of the mandrel can simply be achieved by axial movement of the downhole tool (after the centralizer has been expanded). These mechanisms are not complicated to manufacture or deploy and are relatively inexpensive. The centralizer assembly and barrier element together provide a relatively large range of 20 expansion and are flexible in that they can be set at various diameters. Thus, the same tool can be used to plug different diameters of wellbore.

The downhole tool according to the present invention, when set and activated in the wellbore, may not provide a seal that is capable of withstanding the typical pressure differentials that well plugs are designed to withstand. For example, the downhole 25 tool (set in the wellbore and activated) may be configured to maintain a pressure differential in the wellbore of less than 7 Megapascals, optionally less than 5 Megapascals, optionally less than 3.5 Megapascals. This is not enough to isolate the wellbore. Instead, the downhole tool (when set in the wellbore and activated) may be merely configured to substantially prevent the flow of filler material (e.g.

30 cement) downhole of the tool through the wellbore. The inventors have recognised that this enables a greater freedom in the design of the tool such that the simple mechanisms used to expand the centralizer assembly and the barrier element of the present invention can be implemented even if this means that the tool is not suitable for isolating the wellbore. In particular, the force needed to activate the barrier 35 element can be relatively low (because there is no need for the barrier element to maintain a high pressure differential). This, in turn, reduces the force needed to set the centralizer assembly. Therefore, simple and inexpensive mechanisms can be used to activate the centralizer assembly and barrier element. For example, a piston with a low surface area (which is implicit given the small tool diameter) can be used 40 to activate the centralizer assembly.

349843

A maximum diameter of the barrier element in the radially expanded state may be at least 50% larger than a maximum diameter of the barrier element in the unexpanded state. A maximum diameter of the barrier element in the radially expanded state may be at least 75% larger than a maximum diameter of the barrier element in the 5 unexpanded state. A maximum diameter of the barrier element in the radially expanded state may be at least 100% larger than a maximum diameter of the barrier element in the unexpanded state.

As used herein, the diameter of a component or feature refers to its diameter in a cross-section taken perpendicular to the longitudinal axis of the tool (i.e. a plane 10 where the longitudinal axis of the tool is the normal). The maximum diameter refers to the largest diameter of the component along the axial length of the respective component. The maximum diameter may be the diameter that is most critical for considerations of a) whether the component will fit in the wellbore as the tool is run through the wellbore and b) whether the component will provide a suitable barrier 15 and / or contact the wellbore in an activated state.

In some embodiments, the downhole tool is for use in a well-plugging process employing one or more ball-drop valves. In particular, in some embodiments, the mandrel comprises an inner bore and the downhole tool comprises a ball seat of a ball drop valve, the ball seat being downhole of the piston assembly. The ball seat 20 may be referred to as a landing seat. The ball seat may be configured to receive a ball that seals the ball drop valve mechanism.

In some embodiments, the piston assembly may be activated such that the piston moves from the first position to the second position when a ball is received in the ball seat.

25 The drop seat valve mechanism may be arranged to seal the mandrel. This seal may be maintained if a net pressure is applied by fluid in the mandrel on the ball in a downhole direction. If a net pressure is applied by fluid in the mandrel on the ball in an uphole direction then the seal may be broken. Thus, the fact that the downhole tool employs a ball drop valve mechanism to activate the piston further

30 demonstrates that the tool is not suitable for isolating a wellbore (as discussed above).

As used herein, the terms “downhole tool”, “fundament tool”, and “tool” have been used interchangeably unless stated otherwise.

As used herein, the downhole tool being “activated” or “in an activated state” may 35 mean that the radially expandable centralizer assembly and the radially expandable barrier element are in their respective radially expanded states. Activation of the downhole tool may comprise using the piston assembly to reconfigure the expandable centralizer assembly from the unexpanded state to the radially expanded 349843

state and then moving the mandrel axially to reconfigure the radially expandable barrier element from the unexpanded state to the radially expanded state. If this is done while the downhole tool is positioned within a well bore then the centralizer assembly, in its radially expanded state, may centralize the tool within the wellbore 5 and secure or fix the tool to the wellbore while the radially expandable barrier element, in its radially expanded state, may provide a seal that prevents the flow of cement (or cement slurry) downhole - beyond the tool.

As used herein, the downhole tool being an “un-activated state” or a “run-in” state may mean that the barrier element and centralizer assembly are both in respective 10 un-expanded states.

The downhole tool may extend substantially along a longitudinal axis. The longitudinal axis may pass through a centre of the fundament tool and so may be referred to as a central axis. The longitudinal axis may extend along the length of the fundament tool. In use of the tool, the longitudinal axis may extend parallel to a 15 central axis of the wellbore.

As used herein, “axial” movement or expansion of a component or components of the fundament tool may refer to movement or expansion of said component or components along the longitudinal (or central) axis. Thus, axial movement may refer to movement along the length of the tool.

20 As used herein, “uphole” may generally refer to a direction towards the surface or entrance of the wellbore. An “uphole” direction may be a direction point towards the surface or entrance of the wellbore. A first component being described as being “uphole” of a second component may mean that the first component is closer to the surface than the second component. In the context of the fundament tool, “uphole” 25 may be used to describe position or direction when the fundament tool is received in the wellbore as intended. Thus, if a first component of the fundament tool would be closer to the surface than a second component of the fundament tool when the fundament tool is received in the wellbore as intended, the first component may be described as being uphole of the second component. This may be the case even at 30 times when the fundament tool is not actually received in the wellbore (for example, when the fundament tool is being transported to the site of the wellbore).

Conversely, as used herein, “downhole” may generally refer to a direction away from the surface or entrance of the wellbore and so deeper underground. A “downhole” direction may be a direction point away from the surface or entrance of 35 the wellbore and so deeper into the ground. A first component being described as being “downhole” of a second component may mean that the first component is deeper underground than the second component. In the context of the fundament tool, “downhole” may be used to describe position or direction when the fundament tool is received in the wellbore as intended. Thus, if a first component of the

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fundament tool would be deeper underground to than a second component of the fundament tool when the fundament tool is received in the wellbore as intended, the first component may be described as being downhole of the second component. This may be the case even at times when the fundament tool is not actually received in 5 the wellbore (for example, when the fundament tool is being transported to the site of the wellbore).

The uphole direction and the downhole direction may be substantially parallel to the longitudinal axis of the fundament tool and / or a longitudinal axis of the wellbore in which the fundament tool is to be received. Movement along the uphole or 10 downhole directions may be described as axial movement.

As used herein, a “radial” direction may refer to a direction that is orthogonal to the axial (or longitudinal) direction described above. Thus, radial movement may refer to movement perpendicular to the length of the tool.

As used herein, a “radial expansion” of a component may mean that a dimension of 15 at least a portion of said component increases in a radial direction. For example, a radius, a diameter, or a cross-sectional area of at least a portion of the component may increase as a result of radial expansion of the component. The dimension may be measured in a first plane that is perpendicular to the axial / longitudinal direction. The first plane may define a cross-section through the respective

20 component.

As used herein, a radially expandable element (such as the centralizer assembly and the barrier element) may have at least an unexpanded state and a radially expanded state. A dimension (such as a radius, a diameter, or a cross-sectional area) of at least a portion of said element may be larger in the radially expanded state than in the 25 unexpanded state.

The second portion of the mandrel is different to the first portion of the mandrel in embodiments. In some embodiments, the first portion of the mandrel is uphole of the second portion of the mandrel.

The downhole tool may be for use in a tubular of a wellbore. The tubular may be a 30 casing (e.g. a tube placed in an open bore as part of the process of developing the bore) or tubing (e.g. a tube such as a metal tube such as a steel tube placed in the casing for production).

In some embodiments, the centralizer assembly, in the radially expanded state, is arranged to contact an inner surface of the wellbore when the fundament tool is 35 received in the wellbore. This may mean that one or more portions of the centralizer assembly contact the inner surface of the wellbore. The centralizer assembly may be arranged to bear against the inner surface of wellbore when in the radially expanded 349843

state and received in the wellbore. The centralizer assembly may be arranged to anchor the centralizer assembly in place within the wellbore, or with respect to the wellbore, and to centralize the fundament tool within the wellbore.

In some embodiments, the radially expandable barrier element is arranged to be 5 configurable between the unexpanded state and the radially expanded state while the fundament tool is received in the wellbore and the centralizer assembly is in the radially expanded state. In some embodiments, the radially expandable barrier element is arranged to be configurable between the unexpanded state and the radially expanded state only while the fundament tool is received in the wellbore 10 and the centralizer assembly is in the radially expanded state. This may be such that the centralizer assembly is anchored in place within the wellbore. The mandrel may be moveable with respect to the centralizer assembly. Thus, once the centralizer assembly is anchored in place, axial movement of the mandrel may cause movement of the mandrel with respect to the centralizer assembly. The tool may be arranged 15 such that this relative axial movement between the mandrel and the centralizer assembly can be employed to configure or reconfigure the barrier element between its unexpanded state and radially expanded state. For example, at least a first end of the barrier element may be operatively connected to a portion of the centralizer assembly such, when the centralizer assembly is anchored in place within the 20 wellbore, that the first end of the barrier element is also anchored in place within the wellbore and is moveable with respect to the mandrel.

In some embodiments, the centralizer assembly is arranged to be axially moveable in the wellbore when the centralizer assembly is in the unexpanded state . In some embodiments, the centralizer assembly is arranged to be fixed or secured in position 25 with respect to the wellbore when the centralizer assembly is in the expanded state .

This may be such that the centralizer assembly is anchored in place within the wellbore (when the downhole tool is received in the wellbore).

In some embodiments, the piston is operatively connected to a first end of the centralizer assembly.

30 In some embodiments, the downhole tool further comprises a biasing mechanism.

The biasing mechanism may be arranged to bear against a second end of the centralizer assembly. Thus, the piston may be operatively connected to an opposing end of the centralizer assembly to the end of the centralizer that the biasing mechanism bears against. The piston may be arranged to act in an opposing

35 direction to the biasing mechanism. For example, the piston assembly may be arranged such that axial movement of the piston in a down-hole direction configures the centralizer assembly from the unexpanded state to a radially expanded state . In this example, the biasing mechanism may be arranged to bear against the second end of the centralizer in an up-hole direction.

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In some embodiments, the downhole tool further comprises a first ratchet mechanism. The first ratchet mechanism may be arranged to allow movement of the piston with respect to the mandrel in a first direction. The first direction may be the same direction that the piston is arranged to move (axially) to configure the

5 centralizer assembly from the unexpanded state to a radially expanded state . The first direction may be a downhole direction.

The first ratchet mechanism may be arranged to restrict movement of the piston with respect to the mandrel in a second direction, opposite to the first direction. This may be to prevent movement of the piston (and so the first end of the

10 centralizer assembly) in the second direction. This may prevent the centralizer assembly from returning to an unexpanded state after is has been activated. This may mean that, when hydraulic pressure in the piston housing falls, the piston remains substantially stationary in the second direction. The second direction may be the opposite direction to the direction that the piston is arranged to move 15 (axially) to configure the centralizer assembly from the unexpanded state to a radially expanded state. The second direction may be an uphole direction.

There is a particular synergistic advantage to providing the first ratchet mechanism in combination with the biasing mechanism. As the skilled reader will appreciate, a ratchet mechanism may provide a stepped motion (e.g. as the result of comprising a 20 cog comprising teeth such that each tooth corresponds to a step of the motion). The ratchet mechanism may prevent reversible movement at each step of the motion. Between steps, however, a small amount of reverse movement (in the second direction) may be allowed until a discrete step is reached. This could mean that, when the piston stops urging the centralizer assembly into the expanded state, the 25 piston / centralizer may fall back slightly. This fall back may mean that the centralizer assembly loosens in the wellbore and so reduces the contact force between the centralizer assembly and the wellbore. The biasing mechanism may advantageously mitigate this because the biasing mechanism may urge the second end of the centralizer assembly in an up-hole direction which at least partially 30 compensates for the above-described loosening. This may increase the flexibility of the tool as it can be used with any sized wellbore. It does not matter if the size of the wellbore does not match exactly to one of the steps in the first ratchet mechanism.

In some embodiments, the downhole tool further comprises a second ratchet 35 mechanism arranged to allow movement of the mandrel with respect to the first end of the of the barrier element in the second direction. The tool (e.g. the second ratchet mechanism) may also be arranged to allow movement of the mandrel with respect to the piston, but not the piston housing, in the second direction. The second ratchet mechanism may be arranged to restrict movement of the mandrel with 40 respect to the first end of the barrier element in the first direction.

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In some embodiments, the downhole tool further comprises a connector. The connector may be at an up-hole end of the downhole tool. The connector may be for connecting the downhole tool to a conveyance means comprising a drill pipe or coiled tubing or to another downhole tool or to a work string. The connector may be 5 engaged to the mandrel by a retention device. The retention device may be arranged such that the connector is disengageable from the mandrel by overcoming the retention device. An advantage of providing such a retention device may be that the tool can be disengaged from the conveyance means, other downhole tool or work string by pulling the conveyance means, other downhole tool or work string axially.

10 In some embodiments, the retention device comprises a shear pin or shear screw, The shear pin or shear screw may be arranged to shear when a force equal to or exceeding a first threshold force is applied thereto.

In some embodiments, the barrier element, in the radially expanded state, is arranged to contact and / or bear against an inner surface of the wellbore when the 15 fundament tool is received in the wellbore. In some embodiments, the barrier element, in the radially expanded state, is arranged to contact and / or bear against an inner surface of the wellbore substantially continuously around a perimeter of a first portion of the barrier element. This may be such that the barrier element provides a barrier around the perimeter of the wellbore to retain cement slurry 20 uphole of the tool, when the tool is in use and as described previously.

In some embodiments, the barrier element is configurable from the unexpanded state to the expanded state by axial movement of the mandrel in an uphole direction.

In some embodiments, an axial distance between the first end and the second end of the barrier element is reduced in the expanded state of the barrier element relative to 25 the unexpanded state. In other words, the barrier element may be axially compressed when activated causing the barrier element to radially expand.

In some embodiments, the first end of the barrier element is moveable with respect to the mandrel. In some embodiments, the second end of the barrier element is nonmoveable with respect to the mandrel. For example, the second end may be directly 30 or indirectly rigidly connected to the mandrel. Thus, the downhole tool may be arranged such that axial movement of the mandrel is transferred to axial movement of the second end of the barrier element to axially compress the barrier element with respect to the first end (which does not move with the mandrel).

In some embodiments, the downhole tool is arranged such that the axial movement 35 of the mandrel (that activates the barrier element) is achieved, at least in part, as a result of an axial force applied or appliable at an uphole end of the tool. For example, as described above, an axial force may be appliable to the connector (when present). The axial force may be appliable in an uphole direction. The axial

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force may be appliable by a conveyance means connected to the connector. The axial force may be appliable to the mandrel.

Embodiments comprising a disengageable connector (as described above), and where the barrier element is activatable by applying an axial force on the mandrel, 5 may be advantageous because a single axial movement of the conveyance means can activate the barrier element and also disengage the downhole tool. The axial movement may initially cause axial movement of the mandrel. Provided the centralizer assembly has already been activated, this axial movement may configure the barrier element between the unexpanded state and a radially expanded state. By 10 continuing the axial movement and applying a force great enough to overcome the retention device (of the connector), the tool will be disengaged.

In some embodiments, the downhole hole tool may be arranged such that the axial movement of the mandrel is achieved, at least in part, as a result of an axial force applied or appliable to the mandrel by the piston assembly. The axial movement of 15 the mandrel may be caused by relative motion of the piston body with respect to the piston. This may be while the piston is substantially stationary with respect to the centralizer assembly. In other words, the piston assembly may be arranged to axially compress the barrier element (in addition to activating the centralizer assembly).

20 In some embodiments, the piston assembly may be arranged to drive axial movement of the mandrel when / after the centralizer assembly has been activated. The tool may be arranged such that axial movement of the piston with respect to the mandrel configures the centralizer assembly between the unexpanded state and the radially expanded state, as described above. When the tool is received in a well 25 bore, the centralizer assembly, in the radially expanded state, may contact (an inner surface of) the well bore. At this point, further axial movement (e.g. downhole axial movement) of the piston with respect to the centralizer assembly may be prevented (because the centralizer assembly is anchored to the wellbore and can move no further). However, as pressure inside the cavity of the piston body is increased (e.g.

30 by increasing pressure in the inner bore of the mandrel), the piston assembly may then be arranged to cause further axial movement of the mandrel with respect to the piston. This may be because the increased pressure in the cavity causes the piston body to move with respect to the piston while the piston is substantially stationary with respect to the centralizer assembly. The piston body is secured (or non-35 moveable with respect) to the mandrel. Therefore, motion of the piston body causes motion of the mandrel with respect to the piston. The motion of the piston body (and mandrel) may be uphole with respect to the piston. The tool is arranged such that the (uphole) movement of the mandrel has the effect of compressing the barrier element.

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In some embodiments, the movement of the mandrel (and subsequent axial compression of the barrier element) may be driven completely by the piston assembly. It may be advantageous to provide a piston assembly which is able to both activate the centralizer assembly and the barrier element.

5 In some embodiments, the movement of the mandrel (and subsequent axial compression of the barrier element) may be driven by a combination of the piston assembly and an axial force applied or appliable to the mandrel at an uphole end of the tool (e.g. pulling the tool by the connector) as described above. This may reduce the design requirements of the piston assembly relative to embodiments where the 10 compression of the barrier element is driven solely by the piston. For example, the operating pressure of the piston assembly may be lowered and / or the stroke length of the piston assembly may be reduced.

In some embodiments, the first end of the barrier element is operatively connected to the centralizer assembly. For example, there may be a mechanical linkage 15 between the first end of the barrier element the centralizer assembly. The operative connection may be such that, when the fundament tool is received in the wellbore and in the radially expanded position, the first end of the barrier element is fixed in position relative to the wellbore by the centralizer assembly (which is also anchored to the wellbore).

20 In some embodiments, the barrier element is a packer element. In some embodiments, the barrier element comprises an elastomer. In some embodiments, the barrier element is elastically deformable. This mean that the barrier element can be reversible between the unexpanded and radially expanded states. In some embodiments, the barrier element may be plastically deformable.

25 In some embodiments, the piston assembly is arranged such that the piston is moveable from a first (axial) position with respect to the mandrel to a second (axial) position (different to the first position). Movement of the piston from the first position to the second position may configure the centralizer assembly from the unexpanded state to the radially expanded state.

30 In some embodiments, the piston assembly comprises a piston body or piston housing. The piston body may define a cavity in which the piston is at least partially received. The piston body is in fluidic communication with an inner bore of the mandrel. Thus, pressure within the inner bore of the mandrel may be transferable to the piston. The pressure in the inner bore of the mandrel may therefore be used to 35 control or activate the piston assembly. An increase in pressure in the inner bore of the mandrel may cause the piston to move towards (or into) the second position. This increase in pressure may be achieved following a ball-drop event in which a ball is dropped through the inner bore to be received in the above-described ball seat.

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In some embodiments, the piston assembly is arranged such that the piston is moveable from a first position with respect to the mandrel to a second position with respect to the mandrel and is arranged such that movement of the piston from the first position to the second position configures the centralizer assembly from the 5 unexpanded state to the radially expanded state, and the piston assembly is arranged such that the piston moves into the second position when the pressure within the inner bore of the mandrel is at or above a threshold pressure. The threshold pressure may be 2 Megapascals or greater, optionally 3 Megapascals or greater, optionally 5 Megapascals or greater.

10 In some embodiments, the piston body is fixed or non-moveable with respect to at least the first portion of the mandrel.

In some embodiments, the centralizer assembly comprises a first plurality of mechanical linkages. Each of the first plurality of mechanical linkages may be pivotally moveable with respect to the mandrel. The first plurality of mechanical 15 linkages may be distributed (optionally, substantially equidistantly) around the first portion of the mandrel. Each of the first plurality of mechanical linkage may be actuatable between a non-expanded state and a radially expanded state as the centraliser assembly configured between the non-expanded state and the radially expanded state.

20 In some embodiments, each mechanical linkage comprises a slip for contacting the wellbore when the centraliser assembly is in the radially expanded state. This may anchor the centraliser assembly in position within the wellbore.

In some embodiments, each slip may be positioned substantially at a pivot point of mechanical linkage. In some embodiments, each mechanical linkage (of the first 25 plurality of mechanical linkages) comprises a first portion (e.g. a first arm portion) and a second portion e.g. a second arm portion) moveably connected to the first portion. Said connection may form the pivot point of the mechanical linkage. Each slip may be formed on at least one of the portions of the respective mechanical linkage.

30 In some embodiments, the centralizer assembly comprises a first collar and a second collar. Each of the first and second collars may be arranged around the first portion of the mandrel. The first collar may be uphole of the second collar. Each of the first plurality of mechanical linkages may extend between the first and second collars. At least the first collar may be axially moveable with respect to the mandrel and may 35 be operatively connected to the piston such that the centralizer assembly is arranged to be configurable between the non-expanded state and the radially expanded state when axial movement of the piston causes axial movement of the first collar. The first collar may form the first end of the centralizer assembly described previously.

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In some embodiments, the centralizer assembly comprises a second plurality of mechanical linkages. Each of the second plurality of mechanical linkages may be pivotally moveable with respect to the mandrel. Each of the second plurality of mechanical linkages may be distributed (optionally, substantially equidistantly) 5 around the first portion of the mandrel. The second plurality of mechanical linkages may be downhole of the first plurality of mechanical linkages. Each mechanical linkage of the second plurality of mechanical linkages may be actuatable between a non-expanded state and a radially expanded state.

The second plurality of mechanical linkages may each comprise first and second 10 (arm) portions connected to, and moveable above, a pivot point. In other words, each of the second plurality of mechanical linkages may have a similar form to each of the first plurality of mechanical linkages. In some embodiments, each of the second plurality of mechanical linkages may not comprise a slip. In other words, only the first plurality of mechanical linkages may comprise slips. Only providing 15 the first plurality of mechanical linkages with slips may reduce the risk of the centralizer assembly becoming wedged in the wellbore. This feature is particularly synergistic with the biasing mechanism described previously. Said biasing mechanism may be operatively connected to the second plurality of mechanical linkages and urge in an uphole direction. Because the second (or bottom) plurality 20 of mechanical linkages do not comprise slip, this allows them to be pushed uphole to ensure contact with the casing. In some embodiments, however, each of the second plurality of mechanical linkages may comprise a slip. This may be in addition to the first plurality of mechanical linkages comprising a slip. In such embodiments, the centralizer assembly may provide an increased anchoring effect 25 when radially expanded within a well bore. This may be advantageous when the downhole tool requires relatively large axial forces on the mandrel to activate the barrier element, for example.

In some embodiments, the centralizer assembly comprises a third collar. The third collar may be arranged around the first portion of the mandrel. Each of the second 30 plurality of mechanical linkages may extend between the second and third collars.

The biasing mechanism may be arranged to bear against the third collar and urge the collar in an uphole direction.

In a second aspect, there is provided a method of plugging a wellbore. The method comprises the step of positioning a downhole tool in a wellbore.

The downhole tool comprises a radially expandable centralizer assembly arranged around a first portion of a mandrel; a piston assembly comprising a piston operatively connected to a first end of the centralizer assembly and arranged such that the centralizer assembly is configurable between an unexpanded state and a 40 radially expanded state by axial movement of the piston with respect to the mandrel; 349843

and a radially expandable barrier element arranged around a second portion of the mandrel and configurable between an unexpanded state and a radially expanded state;

wherein the downhole tool is arranged such that a first end of the barrier element is 5 moveable with respect to a second end of the barrier element by axial movement of the mandrel such that a distance between the first end and the second end of the barrier element is changed by axial movement of the mandrel and such that axial movement of the mandrel configures the barrier element between the unexpanded state and the radially expanded state.

The method comprises the step of configuring the centralizer assembly from an unexpanded state to a radially expanded state by axially moving the piston with respect to the mandrel.

15 The method comprises the step of configuring the barrier element from an unexpanded state to a radially expanded state of the mandrel such that a first end of the barrier element is moved axially with respect to a second end of the barrier element by axial movement of the mandrel to reduce a distance between the first end and the second end of the barrier element.

The step of configuring the barrier element from the unexpanded state to the radially expanded state may comprise one or both of: axial movement of the mandrel and inflation of the barrier element. The axial movement of the mandrel may comprise pulling of the mandrel in an uphole direction. The inflation of the 25 barrier element may comprise increasing pressure in the inner bore. The barrier element may define an annular around the mandrel. The annulus may be in fluidic communication with an inner bore of the mandrel such that the increased pressure in the inner bore may be transferred to the annulus. This may cause the inflation of the annulus.

The step of positioning a downhole tool in the wellbore may comprise positioning a downhole tool as described in the first aspect in the wellbore.

The method may comprise performing the step of configuring the centralizer from 35 the unexpanded state to the radially expanded state before the step of configuring the barrier element from the unexpanded state to the radially expanded state.

In some embodiments, the method comprises the step of providing a slurry cement uphole of the downhole tool. This may be after the steps of positioning the

40 downhole tool and configuring the centralizer assembly and the barrier element in their respective expanded states.

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In some embodiments, the mandrel of the downhole tool is connected to a conveyance means by a retention device of a connector of the downhole tool during the step of positioning the downhole tool. In some embodiments, the method comprises the step of applying an axial force to the mandrel in an uphole direction 5 to overcome the retention device. This may be the same motion or movement of the mandrel that configures the centralizer assembly in the radially expanded state.

Features and / or advantages described in relation to the first aspect may be applicable to the second aspect, and vice versa.

Short description of the drawings

In the following description this invention will be further explained by way of exemplary embodiments shown in the drawings:

Figure 1 is a perspective view of a downhole tool for setting in a wellbore according to the present invention;

15 Figure 2 is a cross-sectional view of the downhole tool of Figure 1;

Figure 3 is a flow diagram of a well-plugging method using the downhole tool of Figure 1;

Figure 4 is a schematic of the downhole tool of Figure 1 positioned in a wellbore;

Figure 5 is a schematic view of the downhole tool in the wellbore after a centralizer 20 assembly of the tool has been activated and so radially expanded;

Figure 6 is a schematic view of the downhole tool in the wellbore after a barrier element of the tool has been activated and so radially expanded;

Figure 7 is a schematic view of the downhole tool in the wellbore after the tool has been disengaged from a conveyance means;

25 Figure 8 is a schematic view of the downhole tool set and activated in the wellbore and after a cement well-plug has been fabricated atop the tool;

Figure 9 is cross-sectional view of a downhole tool according to the present invention in which a piston assembly and centralizer assembly of the tool has been partially activated;

30 Figure 10 is cross-sectional view of the downhole tool of Figure 9 in which the piston assembly and centralizer assembly have been completely activated;

Figure 11 is a cross-sectional view of the downhole tool of Figure 9 in which a barrier element has been activated;

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Figure 12 is a cross-sectional view of the downhole tool of Figure 9 after a connector for connecting the downhole tool to a conveyance means has been disengaged from the tool;

Figure 13 is cross-sectional view of the downhole tool of Figure 9 which has both 5 the centralizer assembly and barrier element activated in a wellbore having a smaller diameter than in Figures 10 to 12;

Figure 14 is a cross-sectional close-up view of first and second ratchet mechanisms of the tool;

Figure 15 is a cross-sectional view of another example of a downhole tool according 10 to the present invention, the tool comprising a piston assembly with an increased stroke length;

Figure 16 is a cross-sectional view of another example of a downhole tool according to the present invention, the tool comprising an inflatable barrier element;

Figure 17 is a cross-sectional view of the downhole tool of Figure 16 in which the 15 barrier element has been inflated; and

Figure 18 is a flow diagram of a well-plugging method using the downhole tool of Figure 16.

Detailed description of the invention

Figures 1 and 2 show an example downhole tool 100 for use in a hole-plugging 20 process according to the present invention. Figure 1 is a perspective view of the tool 100. Figure 2 is a cross-sectional view of the tool 100. The downhole tool 100 can be referred to as a fundament and is for setting in wellbore and then supporting a column of cement slurry uphole of the tool as part of a process of forming a cement well plug.

25 The downhole tool 100 extends longitudinally from an uphole end 102 to a downhole end 104. The downhole tool 100 comprises a tubular mandrel 106 which defines an inner bore 108 through which fluid can flow. An uphole end of the mandrel 106 is connected to a connector 110 by a retention device. In this example, the retention device comprises a shear pin 112. The connector 110 is for connecting 30 to a conveyance means such as a drill pipe or coiled tubing or to another downhole tool. The downhole end of the mandrel 106 comprises a ball seat 114 of a ball drop valve. The seat 114 provides a restriction (i.e. a portion of reduced diameter relative to the rest of the inner bore 108). In use, the downhole tool 100 is intended to be lowered into a wellbore such that the downhole end 104 is received in the wellbore 35 first. Thus, the downhole end 104 of the tool 100 will generally be lower in the wellbore than the uphole end 102.

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As shown in Figures 1 and 2, the downhole tool 100 comprises a piston assembly 120. The piston assembly 120 comprises a piston body 122 or housing which defines or encloses a cavity 124. The cavity 124 is in fluidic communication with the inner bore 108 of the mandrel 106. This is achieved in this example because an 5 opening 126 is provided in the mandrel 106 arranged such that fluid can flow from the inner bore 108 to the cavity 124. The piston assembly 120 further comprises a piston 128.

The downhole tool 100 comprises a centralizer assembly 130 arranged around a first portion 132 of the mandrel 106. The centralizer assembly 130 in this example 10 comprises a first, second and third collar 140, 142, 144 each surrounding different parts of the first portion 132 of the mandrel 106. The first collar 140 is uphole of the second collar 142 which, in turn, is uphole of the third collar 144.

In this example, a first plurality of mechanical linkages 134 are distributed equidistantly around the first portion 132 of the mandrel 106. Each mechanical 15 linkage 134 connects the first collar 140 to the second collar 142. In this example, the first plurality of mechanical linkages comprises three separate mechanical linkages 134. Two of the mechanical linkages 134 are visible in Figure 1; only one of the mechanical linkages 134 is visible in Figure 2. Each mechanical linkage 134 comprises a first arm portion 136 and a second arm portion 138 rotatably connected 20 to one another at a pivot point 139. Each first arm portion 136 is connected to the first collar 140 and each second arm portion 138 is connected to the second collar 142. Each mechanical linkage 134 of the first plurality comprises a slip 146 formed on at least one of the arm portions of the respective mechanical linkage and positioned substantially at the pivot point 139. The slip 146 is more clearly visibly 25 in Figure 9 and has the form of a plurality of teeth provided on an outer surface of the mechanical linkage.

In this example, the centralizer assembly 130 further comprises a second plurality of mechanical linkages 154 distributed equidistantly around the first portion 132 of the mandrel 106. The second plurality of mechanical linkages 154 are provided 30 downhole of the first plurality of mechanical linkages 134. Each mechanical linkage 154 of the second plurality connects the second collar 142 to the third collar 144. In this example, the second plurality of mechanical linkages comprises three separate mechanical linkages 154. Two of the mechanical linkages 154 are visible in Figure 1; only one of the mechanical linkages 154 is visible in Figure 2. Each mechanical 35 linkage 154 comprises a first arm portion 156 and a second arm portion 158 rotatably connected to one another at a pivot point 159. Each first arm portion 156 is connected to the second collar 142 and each second arm portion 158 is connected to the third collar 144. A difference between the first plurality of mechanical linkages 134 and a second plurality of mechanical linkages 154 is that the second 40 plurality of mechanical linkages 154 does not comprise slips.

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In some examples, the centralizer assembly 130 may only comprise the first plurality of mechanical linkages 134. In such examples, the centralizer assembly 130 may not comprise the third collar 144.

The downhole tool 100 further comprises a connector 170 between the piston 5 assembly 120 and the centralizer assembly 130. Specially, the connector 170 provides an operative connection between the piston 128 and the first collar 140. In this way, axial motion of the piston 128 is transferrable to the first collar 140 via the connector 170.

In the example of Figure 1 and 2, the downhole tool 100 comprises a biasing 10 mechanism which, in this example, comprises a spring 161. The spring 161 is arranged to bear against the third collar 144 of the centralizer assembly 130 so as to generally urge the third collar 144 in an uphole direction.

The downhole tool 100 comprises a barrier element 160. The barrier element 160 comprises a first end 164 and a second end 166 opposite to the first end 164. The 15 first end 164 is uphole of the second end 166. The barrier element 160 in this example comprises a bulk elastomer material and extends around a second portion 162 of the mandrel 106. The barrier element 160 is deformable. Specifically, in this example, the barrier element 160 is elastically deformable. The second portion 162 of the mandrel 106 is downhole relative to the first portion 132. The barrier element 20 160 surrounds the second portion 162 of the mandrel 106 but is not secured to it.

However, the second end 166 does abut a collar 168 that is secured to the mandrel 106. The collar 168 is non-moveable with respect to mandrel 106. Therefore, downhole movement of the second end 166 of the barrier element 160 with respect to the mandrel 106 is prevented by the collar 186

25 Each of the connector 110, the piston body 122, collar 168 and seat 114 is nonmoveable with respect to the mandrel 106. In other words, each of these features is directly or indirectly rigidly secured to the mandrel so as to be non-moveable.

Therefore, (axial) movement of the mandrel is transferrable to these features.

The piston 128, connector 170, centralizer assembly 130, spring 161 and barrier 30 element 160 are all moveable relative to mandrel 106 in at least one direction (except the second end of the barrier element 160 is fixed at one end by the collar 168, as described above). In effect, there are two significant points that are fixed to the mandrel, the piston body 122 and the collar 168. The features between these points (the piston 128, connector 170, centralizer assembly 130, spring 161 and 35 barrier element 160) are moveable in at least one direction. As will be described in more detail below, this allows for axial compression of the centralizer assembly 130 (by activating the piston assembly 120) and for axial compression of the barrier element 160 (by pulling the mandrel in an uphole direction after activation of the piston assembly). Said axial compression causes radial expansion of the centralizer

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assembly 130 and the barrier element 160 to centralize the tool 100 and provide a barrier in the wellbore upon which a cement well plug can be fabricated.

In this example, a sleeve 190 surrounds a portion of the mandrel 106. The sleeve is axially slidable on the mandrel 106 in at least one direction. The centralizer 130 and 5 spring 161 are mounted on the sleeve 190. It may still be said that the centralizer assembly 130 is provided around the mandrel 106 even though the sleeve 190 is between the mandrel 106 and the centralizer assembly 130.

In this example, the downhole tool 100 further comprises a first ratchet mechanism 192 and a second ratchet mechanism 194. The first and second ratchet mechanisms 10 192, 194 are shown more clearly in Figure 14. Each of the first and second ratchet mechanism 192, 194 are arranged to allow relative motion between two components in only one axial direction. The skilled reader will be familiar with such ratchet mechanisms. Often, a ratchet mechanism will achieve the unidirectional motion using angle teeth arranged in such a way that the angled teeth can slide with respect 15 to a secondary cog or tooth in a first direction but not a second direction. In this example, the ratchet mechanisms are provided as follows.

Each of the ratchet mechanisms 192, 194 comprises a first member on the respective first component and a second member on the respective second component. In this example, the first member comprises, or is in the form of, a 20 spiral groove formed on a surface of the respective component. The spiral groove comprises an angled surface and individual spirals effectively form a series of teeth. In this example, the second member is a split ring which is arranged to engage the spiral groove. The split ring comprises one or more grooves arranged to correspond to the shape of the spiral groove. The grooves of the split ring are arranged to 25 receive and / or engage the spiral groove in this example. The grooves of the split ring are arranged to receive and engage the spiral groove around one or more full rotations of the spiral groove. The grooves of the split ring are angled such that the split ring can slide or jump axially between rotations of the spiral in one direction but not in the opposing direction. The split in the split ring effectively allows the 30 split ring to jump from rotation to rotation in the moveable direction. However, the angled nature of the grooves on the split ring and the spiral groove are arranged to lock together when the split ring is moved in the opposite direction.

The reason for providing a spiral groove is that this is simpler to manufacture than a series of discrete teeth. The split in the split ring means that the split ring is

35 somewhat deformable such that the split ring will widen and so jump from rotation to rotation.

The first ratchet mechanism 192 is arranged to allow for axial movement of the first collar 140 of the centralizer assembly 130 with respect to the sleeve 190 in a first direction but prevent that relative axial movement in a second direction opposite to

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the first direction. Specifically, in this example, the first ratchet mechanism 192 is arranged to allow for movement of the first collar 140 with respect to the sleeve 190 in a downhole direction but not an uphole direction. In this example, the sleeve 190 comprises the spiral groove 192a and a split ring 192b is provided around the sleeve 5 190 and abutting the first collar 140 of the centralizer. The first ratchet mechanism 192 in this example is arranged such that the split ring 192b can move relative to the spiral groove 192a (and the mandrel 106 and sleeve 190) in a downhole direction but not in an uphole direction. As the split ring 192b abuts the first collar 140, the split ring 192b also prevents movement of the first collar 140 with respect 10 to the mandrel 106 and sleeve 190 in an uphole direction.

The second ratchet mechanism 194 is arranged to allow for axial movement of the piston 128 with respect to the mandrel 106 in a first direction but prevent that relative axial movement in a second direction opposite to the first direction.

Specifically, in this example, the second ratchet mechanism 194 is arranged to 15 allow for movement of the piston 194 with respect to the mandrel 106 in a downhole direction but not an uphole direction. In this example, the mandrel 106 comprises the spiral groove 194a and a split ring 194b is provided around the sleeve 190 and is engaged to the piston 128. The second ratchet mechanism 194 in this example is arranged such that the split ring 194b can move relative to the spiral 20 groove 194a (and the mandrel 106) in a downhole direction but not in an uphole direction. As the split ring 194b is engaged to the piston 128, the split ring 194b also prevents movement of the piston 128 with respect to the mandrel 106 in an uphole direction.

A well plugging method using the downhole tool 100 will now be described. The 25 steps of the method are represented by the flow chart of Figure 3. Individual steps of the method are illustrated in a series of schematic and / more detailed drawings of the downhole tool 100 in use and in various stages of activation.

Step 302 of the method comprises positioning the downhole tool 100 in a wellbore 400. This is shown schematically in Figure 4. In Figure 4, the downhole tool 100 is 30 attached to a conveyance means 402 and has been lowered into position within the wellbore 400. The position is the desired position for a well plug to be fabricated. In step 302 of the method, the downhole tool 100 is configured as shown in Figures 1 and 2.

Step 304a of the method comprises dropping a ball 502 down the conveyance means 35 402. The ball 502 comes to rest in the seat 114 of the tool 100. In other words, step 304 of the method comprises closing the ball drop valve. During use of the tool 100, fluid is pumped through the inner bore of the mandrel 106. The closing of the ball drop valve results in an increase in the pressure in the inner bore 108. Step 304a may optionally also comprise increasing the pressure under which the fluid is

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pumped (e.g. using a controller at the surface). By closing the ball drop valve and, optionally, increasing pump pressure, the pressure in the inner bore 108 of the mandrel 106 exceeds an activation pressure of the piston assembly 120. This triggers step 304b of the method.

5 In step 304b of the method, the piston assembly 120 is activated. The increased pressure in the inner bore 108 of the mandrel 106 is transferred as an increased pressure in the piston body 122 (because the cavity defined by the piston body 122 is in fluidic communication with the inner bore 108 of the mandrel). This increased pressure urges the piston 128 to move axially from the position of the piston shown 10 in Figure 1 (referred to herein as the first position of the piston) in a downhole direction. The axial motion of piston 128 is transferred to the centralizer assembly 130 which causes axial movement of the first collar 140 (and second collar 142). Said axial movement actuates the first and second plurality of mechanical linkages 134, 154 such that the first and second arm portions move about pivot points 139, 15 159. The effect of this is that first and second plurality of mechanical linkages expand outwards such that the centralizer assembly 130 radially expands.

The first (and second) collars 140,142 of the centralizer 130 are moved in a downhole direction with respect to the mandrel 106 and the sleeve 190 during step 304b. As described above, the first ratchet mechanism 194 allows for this relative 20 motion but prevents relative motion of the first ratchet mechanism 194 in the opposite direction. Similarly, the piston 128 is moving in a downhole direction with respect to the mandrel 106. As described above, the second ratchet mechanism 194 allows for this relative motion but prevents relative motion of the second ratchet mechanism 194 in the opposite direction. In other words, in this example, the piston 25 128 is allowed to move from the first position in a downhole direction by second ratchet mechanism 194. The first (and second) collars 140, 142 which are moved axially by the piston 128 are also allowed to move in a downhole direction, this time by the first ratchet mechanism 192. However, a reverse movement of both the first (and second) collars and the piston with respect to the mandrel is prevented by 30 the first and second ratchet mechanisms 192, 194 respectively. The advantage of this is that the piston 128 and first collar 140 will remain in their desired or activated position even if fluid pressure in the inner bore 106 drops after activation of the piston assembly 120. Thus, the centralizer assembly 130 can be locked into an activated position. If a reversible piston mechanism is required, then the first and 35 / or second ratchet mechanisms 192, 194 may be provided with an override which releases or disengages the second ratchet mechanism 194 to allow for reversible motion (such that the piston 128 can return to the first position, for example).

Figure 9 shows the piston assembly 120 part-way through activation. Figure 10 shows the piston assembly 120 fully activated. In Figure 10, the piston 128 is in a 40 second axial position which is a fully extend position. In the second position, the

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piston has been full pushed out of the piston body 122. Thus, in Figure 10, the centralizer assembly 130 is in a full radially expanded state. In Figure 9, the piston 128 is in a position part-way between the first position and the second position and the centralizer assembly 130 is not quite as radially expanded as in Figure 10.

5 When the centralizer assembly 130 is radially expanded, the first and second plurality of mechanical linkages contact the inner surface 420 of a wellbore 400. This is shown schematically in Figure 5. The activation of the piston is represented by double-headed arrow in Figure 5. This results in the axial length of the centralizer assembly 130 being reduced but expanding radially such that the

10 mechanical linkages contact the inner surface 420 of the wellbore 400 substantially at the pivot points 139. Because the mechanical linkages are distributed around the mandrel 106, and the mechanical linkages each expands by substantially the same amount, the radial expansion and contact has the effect of centralizing the tool 100 in the wellbore 400. The first plurality of mechanical linkages 134 comprise slips 15 146. When the slips 146 contact the inner surface 420 they have the effect of anchoring the centralizer assembly 130 in a fixed position within the wellbore 400 (axially).

Note that Figures 5 and 9 show the ball 502 in the seat 114.

Step 306a of the method comprises axial movement of the mandrel 106 in an uphole 20 direction. This can be achieved by pulling on the conveyance means 402. Step 306a is performed after step 304b. Therefore, when step 306a is performed, the centralizer assembly 130 has been activated and is anchored in place within the wellbore 400. The first ratchet mechanism 192 prevents uphole relative motion of the first collar 140 with respect to the sleeve 190 when the mandrel 106 is pulled 25 uphole. Thus, the sleeve 190 is also anchored in place with respect to the wellbore 400 (by the combination of the first ratchet mechanism 190 and the centralizer 130). It should be noted that axial movement of the mandrel 106 in an uphole direction is possible however because there is nothing preventing axial movement of the mandrel 106 with respect to the sleeve 190 in an uphole direction. Although the 30 piston 128 cannot move relative to the first collar 140, the second ratchet mechanism 194 allows the mandrel 106 to move uphole relative to the piston 128. This is because an uphole movement of the mandrel 106 relative to the piston 128 is equivalent to a downhole movement of the piston 128 relative to the mandrel and, as described above, this is movement that the second ratchet mechanism 194 is 35 arranged to allow.

When the mandrel 106 is moved in an uphole direction, the barrier element 160 is axially compressed between the centralizer assembly 130 (anchored in place with respect to the wellbore 400) and collar 168 (which is fixed to the mandrel 106 and so moves in an uphole direction). Thus, the axial distance between the centralizer

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assembly 130 and the collar 168 is reduced as a result of the uphole movement of the mandrel 106.

The second ratchet mechanism 194 (in combination with the activated centralizer assembly 130) advantageously prevents a reversal of the uphole motion of the 5 mandrel 106. This means that, even when an uphole force on the mandrel 106 is no longer applied, the barrier element 160 remains activated.

Figure 6 shows schematically the downhole tool 100 received in the wellbore 400 after step 306a has been performed. The upward arrow in Figure 6 represents the uphole axial movement that the conveyance means 402 and mandrel 106 have 10 undergone in this step of the method. Figure 11 shows a more detailed view of the downhole tool 100 after step 306a has been performed. These figures show how the axial compression of the barrier element 160 results radial expansion of the barrier element 160. As is more clearly shown in Figure 6, the radial expansion of the barrier element 160 substantially fills the wellbore 400 across its cross-section so as 15 to serve as an effective barrier. However, barrier element 160 does not form a fluid -tight seal and is not suitable for isolating the wellbore 400 on its own (i.e. is not suitable for maintaining high differential pressures), at least in this example.

Because the piston body 122 is non-moveable with respect to the mandrel 106, but the piston 128 is, the axial movement of the mandrel 106 has resulted in movement 20 of the piston 128 with respect to the piston body. In particular, as most clearly shown in Figure 11, the piston 128 has been left behind as the piston body 122 has moved in an up-hole direction such that there is now a separation between the piston 122 and the piston body 128 which was not present in Figure 10.

Step 306b of the method comprises continuing the axial movement of the mandrel 25 106 in an uphole direction to disengage the tool 100 from the conveyance means 402. This can be achieved by continuing to pull on the conveyance means 402. This pulling force will work against the anchor point(s) between the centralizer assembly and the wellbore 400. If enough force is applied, the shear pin of the retention device 112 is overcome (e.g. shears). The shear pin is what secures the connector 30 170 to the mandrel 106. Thus, when the shear pin is overcome, the connector 170 is disengaged from the mandrel 106. This step is shown schematically in Figure 7. The upward arrow represents the uphole movement of the conveyance means 402. A high enough uphole force has been applied that the shear pin has bene overcome. The conveyance means 402 remains connected to the retention device 112 and has 35 moved upwards. The rest of the tool 100 remains in the wellbore 400. The tool 100 is centralized within the wellbore by the radially expanded centralizer and is acting to block the wellbore 400 as a result of the radially expanded barrier element 160.

Figure 12 shows a more detailed view of the tool 100 that is left downhole 400 following step 306b.

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Because steps 306a and 306b both involve axial movement of the mandrel 106 in an uphole direction, these steps can be provided as a single method step. In particular, a single uphole motion is all that is needed to achieve both a) activation of the barrier element 160 (into an expanded state) and b) disengagement of the tool from 5 the conveyance means 402.

Step 308 of the method comprises fabricating a cement well plug 800 in wellbore 400 and is illustrated in Figure 8. Said fabrication comprises providing a cement slurry in the wellbore 400. The tool 100 acts to prevent the flow of the cement slurry downhole and so retains the cement in the desired position. Step 308 of the 10 method further comprises allowing the cement to set to form a well plug. Any method of fabricating a cement well plug 800 that is suitable for providing a slurry atop the tool 100 while the tool 100 is set in the wellbore can be used.

The downhole tool 100, in the non-activated state shown in Figure 1, has a relatively small minimum diameter (when the centralizer assembly 130 and the 15 barrier element 160 are both in the unexpanded states shown in Figure 1). This advantageously allows for the downhole tool 100 to be deployed in wellbores that have a relatively small wellbore diameter and / or because of bends, turns, constrictions or restrictions in the wellbore 400 between the surface and the intended deployment position of the tool. An example of a restriction is a downhole 20 valve such as a flapper valve.

Once the downhole tool 100 is in the deployed position, the tool 100 can be activated, as described in the method of Figure 3. This radially expands the centralizer assembly 130 and the barrier element 160 to centralizer the tool 100 and provide a barrier for cement slurry in the wellbore 400, respectively. The particular 25 mechanisms for radially expanding the centralizer assembly 130 and the barrier element 160 described in this example are advantageous because they allow for a high degree of expansion of the tool 100 (i.e. the difference between the unexpanded and radially expanded states is relatively large). Furthermore, the described mechanisms are simple to manufacture and simple to activate. For 30 example, the centralizer assembly 130 is simply activated by increasing the pressure in the mandrel 106. The barrier element 160 is simply activated by pulling on the mandrel 106 in an uphole direction, which is conveniently the same motion that is needed to disengage the tool. Furthermore, the inventors have recognised that there is no need for the tool 100 to isolate the wellbore 400 (i.e. retain very high

35 differential pressures). For example, the downhole tool 100 in this example is configured to maintain a differential pressure in the wellbore of less than 7 Megapascals. The inventors have recognised that this allows the simple abovedescribed mechanisms to be used, which might not be suitable if the tool were required to isolate the wellbore.

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Another advantage of the downhole tool 100 is that the tool is flexible and can accommodate different wellbore 400 diameters. For example, Figure 11 shows the tool 100 set in a wellbore 400 having a 5-inch (127 millimetre) diameter. However, the tool 100 can equally be set in a wellbore having 3-inch (76.2 millimetre) 5 diameter without adaptation. This is shown in Figure 13. Note how the centralizer assembly 130 and barrier element 160 are radially expanded to a lesser extent in Figure 13 than in Figure 12, for example. This is achievable because both the piston mechanism and the barrier element activation mechanism can flexibly radially expand the centralizer assembly and the barrier element until contact is made with 10 the wellbore 400. The first and second ratchet mechanism 190, 192 can dynamically lock the tool in positions such that the centralizer assembly 130 and barrier element 160 remain in a suitable activated position to either centralizer the tool or provide a barrier even after the tool has been disengaged from the conveyance means 402.

There are a discrete number of positions in which the split ring is properly engaged 15 to the spiralled grooves of the respective first ratchet mechanism 192. The distance between these positions is determined by the pitch of the spiralled groove(s).

Ideally, the tool 100 will be activated in a wellbore having a diameter such that the centralizer assembly 130 contacts the wellbore when the first ratchet mechanism 192 is in one of the discrete positions. If the first ratchet mechanism 192 is between 20 discrete positions when the centralizer assembly 130 contacts the wellbore then there is a risk that, when fluid pressure is reduced in the inner bore 108, the first ratchet mechanism will fall back to the previous discrete position. This may mean a small uphole movement of the piston 128 and a loosening of the centralizer assembly 130, reducing the effectiveness of the centralizer assembly 130 to anchor 25 the tool 100 in the desired position. The spring 161 counteracts this effect because the spring urges the centralizer assembly 130 from the opposite end to the piston 128 but in an uphole direction. Therefore, any loosening of the centralizer assembly 130 caused by uphole movement of the piston 128 (as the first ratchet mechanism settles to a discrete position) is compensated for by the spring 161. Thus, by 30 providing the spring 161 further improves the flexibility of the tool as the tool can be used in a continuous range of diameters of wellbore, despite the discrete nature of the first ratchet mechanism 192.

The downhole tool 100 comprises a second retention device comprising second shear pins 912. The second retention device can be overcome if the tool 100 is 35 accidentally activated or activated incorrectly.

The second retention device secures the collar 168 to the mandrel 106. In particular, the collar 168 is maintained axially in position with respect to the mandrel 106 by the second shear pins 912 (labelled in Figure 2). The second shear pins 900 can withstand a greater force than the (first) shear pin 112.

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If the tool 100 is accidentally activated or activated incorrectly, and the connector 110 is still connected to the tool 100, then the first step to correct this is to pull on the connector 110 to overcome the (first) retention device and first shear pin 112. This disengages the connector 110 from the mandrel 106 as described previously. If 5 the connector 110 has already been disengaged then this step can be skipped.

The next step is to lower a grapple tool into the wellbore to grasp the uphole end of the mandrel 106. Next, the grapple tool is used to pull the mandrel 106 in an uphole direction with a suitably high force to overcome the second retention device and so shear the second shear pins 912. This releases tension in the system, and it is then 10 possible to remove the tool 100 form the wellbore 400.

In the above described examples, the barrier element 160 is activated by pulling on the mandrel 106. Figure 15 shows an example of a downhole tool according to the present invention in which the barrier element 160 is instead activated by the piston 15 assembly. Many of the features of the tool of Figure 15 are the same as previously described and so the same reference numerals have been repeated. This includes (but not exclusively) the connector 110, the centralizer assembly 130, the barrier element 160, the spring 161, the collar 168, and the connector 170. However, the piston assembly is different.

As in previous examples, the piston assembly 1520 of Figure 15 comprises a piston body 1522 defining a cavity 1524 and a piston 1528. However, the stroke length of the piston assembly 1520 is longer than in previous examples. As such, the piston 1528 is longer, as is the cavity 1524 defined by the piston body 1522 (which 25 receives the piston). This increased stroke length enables the piston assembly 1520 to activate (i.e. axially compress and radially expand) the barrier element 160. This will now be described in more detail below in the context of using the tool of Figure 15 in a well plugging process.

30 Steps 302 to 304b and 308 of the method described previously are the same for the tool of Figure 15 as was described previously. However, step 306a and b are modified.

Step 306a still comprises axial movement of the mandrel 106 in an uphole direction.

35 However, in this example, this axial movement is achieved by increasing the pressure in the mandrel 106 above the pressure in step 304a. Step 306a is performed after step 304b. Therefore, when step 306a is performed, the centralizer assembly 130 has been activated and is anchored in place within the wellbore 400. While the increased pressure in the inner bore forces the piston 1528 to push against the 40 centralizer assembly 130, the anchored nature of the centralizer assembly 130 prevents downhole motion of the piston 1528. In other words, the piston 1528

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remains substantially stationary with respect to the centralizer assembly 130. The piston body 1522 experiences an equal and opposite force to the piston 1528. This has the effect of pushing the piston body 1522 in an uphole direction. Provided the force is large enough, the piston body 1522 will be driven to move in the uphole 5 direction (with respect to the piston 1528). As the piston body 1522 is secured to the mandrel 106, uphole motion of the piston body 1522 will be translated to uphole motion of the mandrel 106. The collar 168 is also secured to the mandrel 106 and so will move in an uphole direction too. This has the effect of axially compressing the barrier element 160 between the collar 168 and the spring 161 / centralizer assembly 10 130 such that the barrier element 160 is radially expanded to fill the well bore.

It should be appreciated that the longer stroke length of the piston assembly 1528 relative to previous examples enables the axial motion of the mandrel 106 to be driven by the piston. In previous examples, piston 128 was substantially fully extended after the centralizer assembly 130 had been activated and so further 15 extension of the piston 128 from the piston body 124 (needed to activate the barrier element 160) was not possible.

Step 306b can be performed by applying an uphole axial force on the tool to disengage the connector in a similar fashion to what was described previously.

In some examples, step 306a may comprise a combination of: increasing the 20 pressure in the mandrel 106 above the pressure in step 304a as described in relation to Figure 15; and pulling on the mandrel in an uphole direction as described originally in relation to Figure 3.

In all of the above described examples, the downhole tool is arranged such that the barrier element 160 is configurable from an unexpanded state to a radially expanded 25 state is a result of mechanical action (i.e. caused by pulling in an uphole direction).

In other examples, the barrier element 160 may alternatively or additionally be inflatable and the downhole tool is arranged such that the barrier element 160 is configurable from an unexpanded state to a radially expanded state at least in part as a result of inflation of the barrier element 160. This will now be described in 30 relation to the downhole tool 1600 shown in Figures 16 and 17, and the method of the flow diagram of Figure 18.

Figures 16 and 17 are both cross-sectional views of the tool 1600. Figure 16 shows the tool with the barrier element 160 in an unexpanded state. Figure 17 shows the tool with the barrier element 160 in an expanded state. Additionally, in Figure 17 35 the centralizer assembly 130 has been activated (i.e. radially expanded), as driven by the piston assembly.

Many of the features of the downhole tool 1600 of Figure 16 are the same as in previous examples and like features are numbered accordingly. The main

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differences are that the downhole tool 1600 of Figure 16 additionally comprises one or more radial ports 1602 or openings in the mandrel 106 and the barrier element 160 defines an annulus 1604 around the mandrel. The annulus 1604 of the barrier element 160 is in fluidic communication with the inner bore 108 of the mandrel 106 5 via the one or more radial ports 1602.

A well plugging method using the downhole tool 1600 will now be described in conjunction with the method of Figure 18.

Many of the steps of the method of Figure 18 are similar to the corresponding steps of the method Figure 3. However, steps 304b and 306b are a little different.

10 Step 1702 of method comprises positioning the downhole tool 100 in a wellbore.

Step 1702a of the method comprises dropping a ball 502 such that the ball 502 comes to rest in the seat 114 of the tool 1600 (note Figures 16 and 17 already show the ball 502 in place). Step 1704a may optionally also comprise increasing the pressure under which the fluid is pumped (e.g. using a controller at the surface). By 15 closing the ball drop valve and, optionally, increasing pump pressure, the pressure in the inner bore 108 of the mandrel 106 increases.

Step 1704b of the method is triggered by the increased pressure in the inner bore 108 of the mandrel 106. As in step 304b, step 1704b comprises the increased pressure activating the piston assembly 120. The increased pressure in the inner 20 bore 108 of the mandrel 106 is transferred as an increased pressure in the piston body 122 (because the cavity defined by the piston body 122 is in fluidic communication with the inner bore 108 of the mandrel). This increased pressure urges the piston 128 to move axially in a downhole direction. The axial motion of piston 128 is transferred to the centralizer assembly 130 which causes axial

25 movement of the first collar 140 (and second collar 142). The effect of this is that first and second plurality of mechanical linkages expand outwards such that the centralizer assembly 130 radially expands and contacts the wellbore to act as an anchor.

Additionally, step 1704b comprises inflating the barrier element 160. The increased 30 pressure in the inner bore 108 of the mandrel 106 is transferred as an increased pressure in the annulus 1704 of the barrier element 160. This causes inflation of the annulus 1704 and so inflation of, and radial expansion of, the barrier element 160.

Step 1706a of the method comprises axial movement of the mandrel 106 in an uphole direction. This is performed while the pressure is increased (and so while the 35 barrier element 160 is inflated). In this example, this uphole movement causes axial compression of the barrier element 160 is the barrier element 160 is squeezed between the centralizer assembly 130 and collar 168. In other words, the first and second ends 164,166 of the barrier element 160 are brought together. This may

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cause further radial expansion of the barrier element 160 and bring the barrier element 160 into a fully radially expanded state. The second ratchet mechanism 194 (in combination with the activated centralizer assembly 130) advantageously prevents a reversal of the uphole motion of the mandrel 106.

5 Thus, in this example, expansion of the barrier element 160 from the unexpanded state to the radially expanded state involves two actions. A first action is the inflation of step 1704b and a second action is the mechanical action of step 1706a. Compared to step 306a of the method of Figure 3, a lower pulling force may be used in step 1706a of the method to activate the barrier element. This is because the 10 barrier element 160 is already inflated and so is partially expanded.

Step 1706b of the method comprises continuing the axial movement of the mandrel 106 in an uphole direction to disengage the tool 100 from the conveyance means 402.

In an alternative example, the increased pressure 1704b may be enough to fully 15 activate / expand / inflate the barrier element 160. So, there may be no need to further compress the barrier element in step 1706a. In such examples, the uphole axial movement of the mandrel may still be used to disengage the tool 100.

Claims

CLAIMS

1. A downhole tool (100) for setting in a wellbore (400), the downhole tool comprising:

a mandrel (106);

5 a radially expandable centralizer assembly (130) arranged around a first portion (132) of the mandrel (106);

a piston assembly (120) comprising a piston (128) operatively connected to a first end of the centralizer assembly and arranged such that the centralizer assembly (130) is configurable between an unexpanded state and a radially expanded state by 10 axial movement of the piston (128) with respect to the mandrel (106);

a radially expandable barrier element (160) arranged around a second portion (162) of the mandrel (106) and configurable between an unexpanded state and a radially expanded state; and characterized in that

the downhole tool (100) is arranged such that a first end (164) of the barrier element 15 (160) is moveable with respect to a second end (166) of the barrier element (160) by axial movement of the mandrel (106) such that a distance between the first end (164) and the second end (166) of the barrier element (160) is changed by axial movement of the mandrel (106) and such that axial movement of the mandrel (106) configures the barrier element (160) between the unexpanded state and the radially 20 expanded state.

2. The downhole tool (100) of claim 1, wherein the barrier element (160) defines an annulus (1604) around the mandrel, the annulus (1604) being in fluidic communication with an inner bore (108) of the mandrel (106) such that pressure within the inner bore (108) of the mandrel (106) is transferable to the annulus.

25 3. The downhole tool (100) of claim 2, wherein the downhole tool is arranged such that the barrier element (160) is configurable in the radially expanded state at least in part by increasing the pressure in the inner bore (108) of the mandrel (106) to inflate the barrier element (160).

4. The downhole tool (100) of any one of the preceding claims, wherein the 30 downhole tool is arranged such that the barrier element (160) is configurable in the radially expanded state at least in part by axial movement of the mandrel.

5. The downhole tool (100) of any one of the preceding claims, wherein the mandrel (106) comprises an inner bore (108) and the downhole tool (100) comprises a ball seat (114), the ball seat (114) being downhole of the piston assembly (120) 35 and arranged to receive a ball (502).

6. The downhole tool (100) of any one of the preceding claims, wherein the centralizer assembly (130), in the radially expanded state, is arranged to contact an inner surface (420) of the wellbore (400) when the tool (100) is received in the wellbore (400); and wherein the radially expandable barrier element (160) is 5 arranged to be configurable between the unexpanded state and a radially expanded state while the tool (100) is received in the wellbore (400) and the centralizer assembly (130) is in the radially expanded state.

7. The downhole tool (100) of any one of the preceding claims, wherein the downhole tool (100) further comprises a biasing mechanism (161) arranged to bear 10 against a second end of the centralizer assembly (130).

8. The downhole tool (100) of claim 7, wherein the piston assembly (120) is arranged such that axial movement of the piston (128) relative to the mandrel (106) in a downhole direction configures the centralizer assembly (130) from the unexpanded state to a radially expanded state; and the biasing mechanism (161) is 15 arranged to bear against the second end of the centralizer assembly (130) in an uphole direction.

9. The downhole tool (100) of any one of the preceding claims, comprising a first ratchet mechanism (192) arranged to allow movement of the piston (128) with respect to the mandrel (106) in a first direction and to restrict movement of the 20 piston (128) with respect to the mandrel (106) in a second direction, opposite to the first direction.

10. The downhole tool (100) of any one of the preceding claims, comprising a connector (110) engaged to the mandrel by a retention device arranged such that the 25 connector (110) is disengageable from the mandrel (106) by overcoming the retention device.

11. The downhole tool (100) of claim 10, wherein the retention device comprises a shear pin (112) or shear screw.

12. The downhole tool (100) of any one of the preceding claims, wherein the 30 piston assembly (120) comprises a piston body (122) defining a cavity (124) in which the piston (128) is at least partially received, and wherein the piston body (122) is in fluidic communication with an inner bore (108) of the mandrel (106) such that pressure within the inner bore (108) of the mandrel (106) is transferable to the piston (120).

35 13. The downhole tool (100) of claim 12, wherein the piston assembly (120) is arranged such that the piston (128) is moveable from a first position with respect to the mandrel (106) to a second position with respect to the mandrel (106) and is arranged such that movement of the piston (128) from the first position to the second position configures the centralizer assembly (160) from the unexpanded state to the radially expanded state; wherein the piston assembly (120) is arranged such that the piston (128) is urged into the second position when the pressure within the inner bore (108) of the mandrel (106) is at or above a threshold pressure.

5 14. The downhole tool (100) of any one of the preceding claims, wherein the centralizer assembly (130) comprises a first plurality of mechanical linkages (134) pivotally moveable with respect to the mandrel (106) and distributed around the first portion (132) of the mandrel (106), each mechanical linkage (134) being actuatable between a non-expanded state and a radially expanded state.

10 15. The downhole tool (100) of claim 14, wherein each mechanical linkage (134) comprises a slip (146) for contacting the wellbore (400) when the centraliser assembly (130) is in the radially expanded state.

16. The downhole tool (100) of claim 14 or 15, wherein the centralizer assembly (130) comprises a second plurality of mechanical linkages (154) pivotally moveable 15 with respect to the mandrel and distributed around the first portion (132) of the mandrel (106), each of the second plurality of mechanical linkage (154) being actuatable between a non-expanded state and a radially expanded state.

17. The downhole tool (100) of claim 16 when dependent on claim 15, wherein only the first plurality of mechanical linkages (134) comprises slips (146).

20 18. A method of plugging a wellbore, the method comprising the steps of:

positioning the downhole tool (100) as defined in any one of the preceding claims in a wellbore (400);

configuring the centralizer assembly (130) from an unexpanded state to a 25 radially expanded state by axially moving the piston (120) with respect to the mandrel (106); and characterized by

configuring the barrier element (160) from an unexpanded state to a radially expanded state such that a first end (164) of the barrier element (160) is moved axially with respect to a second end (166) of the barrier element (160) by axial 30 movement of the mandrel (106) to reduce a distance between the first end and the second end of the barrier element (160).

19. The method of claim 18, comprising the step of providing a slurry cement uphole of the downhole tool (100) after the steps of positioning the downhole tool (100) and configuring the centralizer assembly (130) and the barrier element (160) 35 in their respective radially expanded states.

20. The method of claim 18 or 19, wherein, during the step of positioning the downhole tool (100), the mandrel (106) of the downhole tool (100) is connected to a conveyance means (402) by a retention device of a connector (110) of the downhole tool (100), and the method comprises the step of applying an axial force to the 5 mandrel (106) in an uphole direction to overcome the retention device.

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PATENTKRAV

1. Nedihullsverktøy (100) for setting i et brønnhull (400),

der nedihullsverktøyet omfatter:

et kjernerør (106),

5 et radialt ekspanderbart sentraliseringsoppsett (130) som er anbrakt rundt en første del (132) av kjernerøret (106),

et stempeloppsett (120) som omfatter et stempel (128) som er operativt forbundet med en første ende av sentraliseringsoppsettet og anbrakt slik at sentraliseringsoppsettet (130) kan konfigureres mellom en ikke-ekspandert tilstand 10 og en radialt ekspandert tilstand ved aksial bevegelse av stempelet (128) med hensyn på kjernerøret (106),

et radialt ekspanderingsbart barriereelement (160) anbrakt rundt en andre del (162) av kjernerøret (106) og som kan konfigureres mellom en ikke-ekspandert tilstand og en radialt ekspandert tilstand, og karakterisert ved at

15 der nedihullsverktøyet (100) er anbrakt slik at en første ende (164) av barriereelementet (160) er bevegelig med hensyn på en andre ende (166) av barriereelementet (160) med aksial bevegelse av kjernerøret (106) slik at en avstand mellom den første enden (164) og den andre enden (166) av barriereelementet (160) blir endret ved aksial bevegelse av kjernerøret (106) og slik at aksial bevegelse av 20 kjernerøret (106) konfigurerer barriereelementet (160) mellom den ikke-ekspandert tilstanden og den radialt ekspanderte tilstanden.

2. Nedihullsverktøy (100) ifølge krav 1,

der barriereelementet (160) definerer en annulus (1604) rundt kjernerøret, der 25 annulusen (1604) er i fluid kommunikasjon med en indre boring (108) i kjernerøret (106) slik at trykk inne i den indre boringen (108) i kjernerøret (106) kan overføres til annulusen.

3. Nedihullsverktøy (100) ifølge krav 2,

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der nedihullsverktøyet er anbrakt slik at barriereelementet (160) kan konfigureres i den radialt ekspanderte tilstanden i det minste delvis ved å øke trykket i den indre boringen (108) i kjernerøret (106) for å blåse opp barriereelementet (160).

5 4. Nedihullsverktøy (100) ifølge ethvert av de foregående krav,

der nedihullsverktøyet er anbrakt slik at barriereelementet (160) kan konfigureres i den radialt ekspanderte tilstanden i det minste delvis ved aksial bevegelse av kjernerøret.

10 5. Nedihullsverktøy (100) ifølge ethvert av de foregående krav,

der kjernerøret (106) omfatter en indre boring (108) og nedihullsverktøyet (100) omfatter et kulesete (114), der kulesetet (114) foreligger nedihulls for stempeloppsettet (120) og er anbrakt for å motta en kule (502).

15 6. Nedihullsverktøy (100) ifølge ethvert av de foregående krav,

der sentraliseringsoppsettet (130), i den radialt ekspanderte tilstanden, er anbrakt for å kontakte en indre overflate (420) av brønnhullet (400) når verktøyet (100) blir mottatt i brønnhullet (400), og der det radialt ekspanderingsbare barriereelementet (160) er anbrakt for å kunne bli konfigurert mellom den ikke-ekspanderte tilstanden 20 og en radialt ekspandert tilstand mens verktøyet (100) blir mottatt i brønnhullet (400) og sentraliseringsoppsettet (130) er i den radialt ekspanderte tilstanden.

7. Nedihullsverktøy (100) ifølge ethvert av de foregående krav,

der nedihullsverktøyet (100) videre omfatter en belastningsmekanisme (161) som er 25 anbrakt for å ligge an mot en andre ende av sentraliseringsoppsettet (130).

8. Nedihullsverktøy (100) ifølge krav 7,

der stempeloppsettet (120) er anbrakt slik at aksial bevegelse av stempelet (128) relativt kjernerøret (106) i en nedihullsretning konfigurerer sentraliseringsoppsettet 349843

(130) fra den ikke-ekspanderte tilstanden til en radialt ekspandert tilstand, og belastningsmekanismen (161) er anbrakt for å ligge an mot den andre enden av sentraliseringsoppsettet (130) i en oppihullsretning.

5 9. Nedihullsverktøy (100) ifølge ethvert av de foregående krav,

som omfatter en første sperrehakemekanisme (192) som er anbrakt for å tillate bevegelse av stempelet (128) med hensyn på kjernerøret (106) i en første retning og begrense bevegelse av stempelet (128) med hensyn på kjernerøret (106) i en andre retning, motsatt av den første retningen.

10. Nedihullsverktøy (100) ifølge ethvert av de foregående krav,

som omfatter et koblingselement (110) som er engasjert til kjernerøret med en tilbakeholderinnretning som er anbrakt slik at koblingselementet (110) kan frigjøres fra kjernerøret (106) ved å overvinne tilbakeholderinnretningen.

11. Nedihullsverktøy (100) ifølge krav 10,

der tilbakeholderinnretningen omfatter en skjæretapp (112) eller skjæreskrue.

12. Nedihullsverktøy (100) ifølge ethvert av de foregående krav,

20 der stempeloppsettet (120) omfatter et stempellegeme (122) som definerer et hulrom (124) som stempelet (128) i det minste delvis mottas i, og der stempellegemet (122) er i fluid kommunikasjon med en indre boring (108) av kjernerøret (106) slik at trykk inne i den indre boringen (108) av kjernerøret (106) kan overføres til stempelet (120).

13. Nedihullsverktøy (100) ifølge krav 12,

der stempeloppsettet (120) er anbrakt slik at stempelet (128) er bevegelig fra en første posisjon med hensyn på kjernerøret (106) til en andre posisjon med hensyn på kjernerøret (106) og er anbrakt slik at bevegelse av stempelet (128) fra den første

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posisjonen til den andre posisjonen konfigurerer sentraliseringsoppsettet (160) fra den ikke-ekspanderte tilstanden til den radialt ekspanderte tilstanden , der stempeloppsettet (120) er anbrakt slik at stempelet (128) blir tvunget inn i den andre posisjonen når trykket inne i den indre boringen (108) i kjernerøret (106) er på eller 5 over et terskeltrykk.

14. Nedihullsverktøy (100) ifølge ethvert av de foregående krav,

der sentraliseringsoppsettet (130) omfatter et første flertall av mekaniske sammenkoblinger (134) som er dreibart bevegelige med hensyn på kjernerøret (106) 10 og fordelt rundt den første delen (132) av kjernerøret (106), der hver mekanisk sammenkobling (134) kan aktueres mellom en ikke-ekspandert tilstand og en radialt ekspandert tilstand.

15. Nedihullsverktøy (100) ifølge krav 14,

15 der hver mekanisk sammenkobling (134) omfatter en slipp (146) for å kontakte brønnhullet (400) når sentraliseringsoppsettet (130) er i den radialt ekspanderte tilstanden.

16. Nedihullsverktøy (100) ifølge krav 14 eller 15,

20 der sentraliseringsoppsettet (130) omfatter et andre flertall av mekaniske sammenkoblinger (154) som er dreibart bevegelige med hensyn på kjernerøret og fordelt rundt den første delen (132) av kjernerøret (106), der hver av det andre flertallet av mekaniske sammenkoblinger (154) kan aktueres mellom en ikkeekspandert tilstand og en radialt ekspandert tilstand.

17. Nedihullsverktøy (100) ifølge krav 16 når det er avhengig av krav 15,

der kun det første flertallet av mekaniske sammenkoblinger (134) omfatter slipper (146).

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18. Fremgangsmåte for å plugge et brønnhull,

der fremgangsmåten omfatter trinnene med å:

posisjonere nedihullsverktøyet (100) som definert i ethvert av de foregående krav i et brønnhull (400),

5 konfigurere sentraliseringsoppsettet (130) fra en ikke-ekspandert tilstand til en radialt ekspandert tilstand ved aksialt å bevege stempelet (120) med hensyn på kjernerøret (106), og karakterisert ved at

konfigurere barriereelementet (160) fra en ikke-ekspandert tilstand til en radialt ekspandert tilstand slik at en første ende (164) av barriereelementet (160) 10 blir beveget aksialt med hensyn på en andre ende (166) av barriereelementet (160) ved aksial bevegelse av kjernerøret (106) for å redusere en avstand mellom den første enden og den andre enden av barriereelementet (160).

19. Fremgangsmåte ifølge krav 18,

15 som omfatter trinnet med å tilveiebringe en oppslemmingssement opphulls for nedihullsverktøyet (100) etter trinnene med å posisjonere nedihullsverktøyet (100) og konfigurere sentraliseringsoppsettet (130) og barriereelementet (160) i deres respektive radialt ekspanderte tilstander.

20 20. Fremgangsmåte ifølge krav 18 eller 19,

der, i trinnet med posisjonering av nedihullsverktøyet (100), kjernerøret (106) til nedihullsverktøyet (100) er koblet til et befordringsmiddel (402) med en tilbakeholderinnretning på et koblingselement (110) på nedihullsverktøyet (100), og fremgangsmåten omfatter trinnet med å påføre en aksial kraft på kjernerøret (106) i 25 en opphullsretning for å overvinne tilbakeholderinnretningen.

Drawings

Priority

No priority

Patent classes

IPC classes

E21B 33/134

E21B 33/127

E21B 33/128

E21B 33/16

E21B 17/10

CPC classes

E21B 33/134

E21B 33/127

E21B 33/128

E21B 33/16

E21B 17/1021

Citations

NO 20220465 A1 (A1)

US 4627491 A (A)

US 5311939 A (A)

US 6915845 B2 (B2)

US 2006090905 A1 (A1)

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: P29668NO00

Status history

Payment history

Oppositions and appeals

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Administrative limitation

No administrative limitation

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Only events from 2024.03.04 and onwards are shown.