GB2621709A

GB2621709A - Apparatus and method

Info

Publication number: GB2621709A
Application number: GB2312232.8A
Authority: GB
Inventors: Mathew Ackroyd Warren; James Rhodes Thomas; Thomas Smith Cameron
Original assignee: Oilenco Ltd
Current assignee: Oilenco Ltd
Priority date: 2022-08-10
Filing date: 2023-08-10
Publication date: 2024-02-21
Also published as: GB202211671D0; GB202312232D0

Abstract

A downhole tool for cleaning a device such as a safety valve within an oil or gas well is described. The tool comprises a jet sleeve having first and second perforated portions through which cleaning or other fluid may be jetted. The tool has a movable valve, which actuates in response to fluid pressure within the tool, and alternately permits and restricts fluid flow through the first and second perforated portions. The portions can be spaced apart to align with specific areas to be cleaned e.g. a flapper valve or other movable part subject to potential scale build up. Accordingly different sections of the device can be targeted for cleaning without requiring retrieval, reconfiguration, and redeployment of the downhole tool.

Description

I

APPARATUS AND METHOD

FIELD OF THE INVENTION

The present invention relates to apparatus and a method relating to a downhole cleaning assembly. In particular, the present invention relates to an apparatus and method for cleaning a downhole device.

BACKGROUND OF THE INVENTION

In a downhole environment, devices situated within wellbores for a period of time can develop scaling. If the devices have moving parts, the movement of these parts can be hindered by scale build-up, potentially leading to failure of the device when actuation of the moving parts is attempted. If the device is safety-critical, failure could lead to significant risks for personnel, structures, and/or the environment.

One example of such a device which may suffer from scaling issues is a side pocket mandrel, where the valve moving in and out of the pocket can become restricted due to build-up. This can lead to e.g. restriction of well fluid flow through the mandrel pocket and into the casing.

By way of a further example, downhole safety valves such as tubing retrievable subsurface safety valves (TRSSV) are critical failsafe mechanisms in the event of uncontrolled releases of reservoir fluids from an oil and/or gas well. Commonly, these valves comprise a flapper valve that is configured to open in a downhole direction, where the valve is held open under normal circumstances via a hydraulic connection to the surface. For example, the flapper can be held open by a movable flow tube that retracts when hydraulic pressure is removed, allowing the valve to close.

Scale can build up on the surfaces of a safety valve as it sits in the downhole environment. In some cases, scale can accumulate on and around critical mechanisms of the safety valve, hindering full movement of these mechanisms and resulting in full or partial failure of the valve. Any interference with the working of these safety valves in the event of a blowout or other high-risk event can result in significant safety risks and environmental damage through spillage.

To mitigate these risks, when scaling is detected the safety valve can be treated to remove the scale. This is generally done through mechanical and/or chemical treatment methods, depending on e.g. the hardness of the scale.

The use of bullheading to forcibly pump fluids from surface into a pressurised wellbore allows for, e.g., chemical fluids to be injected into the well to dissolve scale that has built up. An example of such a typical treatment method is where a chemical dissolving agent is fed into the tubing from the surface. The entire tubing volume is then filled with fluid, pressured up, and held for a period of time to allow the chemical treatment to soak into and dissolve the scale. The fluid is then returned to surface.

Alternatively, a jetting nozzle can be deployed at the end of a length of coiled tubing, through which fluid can be pumped at target locations in the completion. The pressure of the fluid as it is pumped out of the nozzle can be sufficient to remove the scale in itself, or the fluid can include a chemical washing agent (and/or abrasive/erosive particles) to enhance the removal of the scale.

A further alternative is a wireline-deployed jetting tool which can be located within a safety valve. The jetting tool may include pre-drilled holes through which fluid jets to target scale in the valve -as before, the fluid can include chemicals and/or particles to improve scale removal.

All of these known tools and methods provide limited scope for in situ adjustment to clean different locations in the same valve. Additionally, in tools with extended jetting areas such as the jetting tool having pre-drilled holes, fluid exiting the uppermost holes flows down past the holes situated lower down in the tool, impeding the effectiveness of jetting from the lower parts of the tool.

SUMMARY OF THE INVENTION

According to the present invention there is provided a downhole tool for cleaning of a device in an oil and/or gas well, the downhole tool comprising: a sleeve comprising a sleeve wall; the sleeve having at least first and second tubular sections configured to allow fluid flow through the sleeve wall; and a movable valve disposed within the sleeve; wherein the movable valve is actuatable in response to changes in fluid pressure within the downhole tool, and wherein actuation of the movable valve changes the downhole tool between first and second configurations; wherein the movable valve permits fluid flow through the first tubular section of the sleeve and restricts fluid flow through the second tubular section of the sleeve when the downhole tool is in the first configuration; and wherein the movable valve permits fluid flow through the second tubular section of the sleeve and restricts fluid flow through the first tubular section of the sleeve when the downhole tool is in the second configuration.

The downhole tool offers the advantage that different sections of the device can be targeted for treatment/cleaning in one operation, i.e. without requiring retrieval, reconfiguration, and redeployment of the tool.

Optionally the movable valve is an axially movable valve. Alternatively, the movable valve may be another form of valve such as a radial valve, or a rotary valve, or the movable valve may comprise more than one valve type.

Optionally the first and second tubular sections may be individual tubular sections that are connected by a threaded connection.

Optionally the first and second tubular sections of the sleeve each comprise a perforated portion (i.e. first and second perforated portions, respectively); each said portion optionally comprising a plurality of perforations in the wall of the sleeve. Optionally a first portion of the wall of the first tubular section of the sleeve comprises a first plurality of perforations, and a second portion of the wall of the second tubular section of the sleeve comprises a second plurality of perforations.

Optionally the perforations are in the form of substantially circular apertures through the wall of the sleeve. Optionally the perforations are substantially equally spaced from one another.

Optionally the first and/or second perforated portion(s) of the wall of the sleeve extend at least partially around the circumference of the sleeve; i.e. optionally the first and/or second plurality of perforations extends at least partially circumferentially around the first and/or second portion(s) of the wall of the sleeve, respectively.

Optionally the first and/or second perforated portion(s) of the wall of the sleeve extend around the full circumference of the sleeve; i.e. optionally the first and/or second plurality of perforations extends circumferentially around the first and/or second portion(s) of the wall of the sleeve, respectively. Optionally the first and second perforated portions of the downhole tool are axially spaced apart.

Optionally the first and second tubular sections are configured such that pressurised fluid pumped through the downhole tool from the surface may be jetted from the downhole tool through one or more of the first and second tubular sections.

Optionally the first and second tubular sections are configured such that fluid jets from the downhole tool in a substantially perpendicular direction relative to the longitudinal axis of the downhole tool. Optionally the plurality of perforations in the wall of the sleeve provide a radial jetting effect of fluid. Optionally the first and second tubular sections are configured such that fluid jets from the downhole tool in a substantially perpendicular direction relative to the flow of fluid within the downhole tool.

Optionally the axial spacing of the first and second perforated portions of the downhole tool corresponds to an axial spacing of components within the device. For example, the first perforated portion may align with an operating stroke of a flow tube within a safety valve, while the second perforated portion may align with a flapper cavity area of the valve.

Alignment of the first and second perforated portions of the downhole tool with critical components of the device offers the advantage of allowing precise targeting of the components with an appropriate treatment chemical. Advantageously, the downhole tool can provide targeted jetting of a first location within the device at a first fluid pump rate from surface; and an alternative targeted jetting of a second location within the device by simply adjusting the fluid pump rate at the surface.

Optionally the movable valve is a differential piston. Optionally the movable valve comprises a wall. Optionally the wall of the movable valve comprises at least one aperture or port extending through the wall of the movable valve and through which fluid can flow between the inner bore of the valve and the exterior of the valve.

Optionally an axis of the port is perpendicular to an axis of the movable valve.

Optionally the movable valve comprises a plurality of ports. Optionally the ports are arranged circumferentially. Optionally the ports may be larger than the apertures in the first and/or second tubular sections e.g. larger internal diameter or other dimension.

Optionally the movable valve comprises an inner bore, optionally open at one end (optionally an uphole end) and optionally closed at the opposing end (optionally a downhole end). Optionally the fluid pumped from the surface enters the movable valve through the open end of the inner bore, and optionally the only fluid pathway the fluid may follow as a result of the opposing end of the inner bore being closed is through the one or more ports in the wall of the movable valve.

Optionally there is an at least partially annular space or void formed between at least a portion of the outer circumference/wall of the downhole tool and the inner circumference/wall of the device being treated. Optionally fluid that passed through the perforated portion(s) enters into the annular space or void. Optionally the fluid within the annular space or void is not restricted in movement and flows freely through and out of the device.

Optionally the movable valve is coaxial with the sleeve of the downhole tool.

Optionally the downhole tool comprises at least one annular seal disposed around the inner circumference of the wall of the sleeve of the downhole tool. Optionally the at least one annular seal is arranged to seal against an external surface of the movable valve.

Optionally, in the first configuration, the at least one annular seal is located below (optionally in a downhole direction) the ports of the movable valve. Optionally, the at least one annular seal restricts fluid communication between the portions of the downhole tool that are disposed on opposing sides of the at least one annular seal (an alternative sealing arrangement may be used to separate two portions of the downhole tool and resist fluid communication between said portions; this sealing arrangement may be modified to suit e.g. different types of movable valve). Optionally, in the first configuration, fluid passes through the ports of the movable valve and is jetted through the first tubular section of the downhole tool. Optionally, in the first configuration, little to no fluid passes through the second tubular section of the downhole tool.

Optionally the downhole tool comprises a resilient device, for example a coil/compression spring. Optionally the resilient device is biased against movement of the movable valve in at least one direction. Optionally the resilient device is biased against movement of the movable valve in a downhole direction.

By increasing the pump rate of the fluid from the surface, fluid can enter the downhole tool at a greater velocity. Optionally, as the pump rate of the fluid is increased from the surface, fluid enters the movable valve at a greater velocity.

Optionally this creates a pressure differential.

Optionally, as the pump rate of the fluid is increased, the jetting force of the fluid entering the downhole tool increases, which in turn can result in an increase in back pressure above the movable valve. Optionally fluid pressure increases between the pump at the surface, the apertures/ports of the movable valve, and the internal wall of the perforated portion of the downhole tool with which the ports of the movable valve are aligned, relative to the pressure within the volume between the external wall of the downhole tool and the well below the downhole tool.

Optionally, changes in the pump rate of the fluid from the surface can change the configuration of the downhole tool to or from the second configuration. Optionally, there is a fluid pressure threshold at which the biasing force of the resilient device within the downhole tool can be overcome. Optionally the fluid pressure threshold may be between 1 and 8 psi, or alternatively between 3 and 6 psi; however this is not limiting and higher or lower pressure thresholds may be selected according to the tool configuration/downhole environment etc.. Optionally, when this fluid pressure threshold is reached and/or exceeded, the fluid pressure acts on the movable valve to move the valve, optionally in a downhole direction. Optionally the movement of the movable valve compresses the resilient device.

Optionally at this fluid pressure threshold the movable valve begins to move past the annular seal. Optionally, at an intermediate stage between the first and the second configurations, the one or more ports align with the annular seal, restricting fluid flow through the one or more ports, and thereby restricting fluid flow between the movable valve and the first and second tubular sections of the downhole tool. Optionally, the pressure differential increases further as a result of this restriction of fluid flow. Optionally, the increase in pressure differential may cause the movable valve to move past the annular seal, into the second configuration of the downhole tool.

Optionally, in the second configuration the one or more ports of the movable valve are disposed within the second tubular section of the downhole tool. Optionally, in the second configuration, fluid flows through the one or more ports of the movable valve and is jetted through the second tubular section of the downhole tool.

Optionally, in the second configuration, little to no fluid flows through the first tubular section of the downhole tool.

Optionally, when the fluid pump rate is reduced (optionally resulting in a reduction in the pressure differential) the movable valve returns to its initial position in the first configuration of the downhole tool. Optionally the movable valve returns due to the biasing force of the resilient device being greater than the force of the fluid pressure against the movable valve. Optionally the movable valve is configured to move between either side of the annular seal.

Optionally, the downhole tool can be cycled between the first and second configurations within the device as often as required. Optionally, the downhole tool can be changed between the first and second configurations in situ in the downhole environment, i.e. without retracting the downhole tool from the device to surface. The device can be operated throughout any of the jetting phases of the downhole tool described herein, e.g. hydraulically operated. This practice may advantageously assist in regaining full functionality of the device being cleaned by actuating the components being cleaned, e.g. for a safety valve, the flow tube and the flapper mechanisms; for a side pocket mandrel, the gas lift valve(s); and exercising the movement of said components Optionally the downhole tool comprises a sealing assembly that is disposed at a distal end of the downhole tool from the movable valve. Optionally the sealing assembly is disposed at the distal end of the second tubular section of the downhole tool. Optionally the sealing assembly is disposed on the opposite side of the second perforated portion to the movable valve.

Optionally the sealing assembly comprises a housing that is configured to connect to an end of the second tubular portion. Optionally the housing comprises a threaded female connector that connects to a corresponding threaded male connector of the second tubular portion.

Optionally the housing comprises an external recess formed around the outer circumference of the housing. Optionally an annular external seal is disposed within the external recess. Optionally the annular external seal is disposed within the annular space or void formed between the downhole tool and the device as described above. Optionally the external seal seals against the inner wall of the throughbore of the device.

Optionally the housing comprises a hollow space arranged substantially centrally within the housing e.g. a central cavity, optionally aligned with a central longitudinal axis of the downhole tool. Optionally the central cavity comprises at least a first and a second recess. Optionally the first recess contains a resilient device, for example a coil spring or other spring type.

Optionally the housing further comprises a movable internal sealing member. Optionally the internal sealing member comprises a first extension that extends into the first recess formed within the cavity. Optionally the internal sealing member comprises a second extension that extends into the second recess formed within the cavity. Optionally the second extension acts to maintain the internal sealing member in the correct orientation e.g. optionally the second extension keeps the internal sealing member centralised within the cavity.

Optionally the internal sealing member is held in a first configuration by the biasing force of the resilient device.

Optionally the first configuration of the internal sealing member is a sealing configuration. Optionally the internal sealing member comprises at least one annular seal that is configured to seal against the central cavity, optionally an internal wall or surface of the central cavity. For example, the central cavity may include a inwardly extending portion that forms a restriction in the central cavity. The inwardly extending portion may comprise at least one shoulder. Optionally the annular seal of the internal sealing member is configured to seal against the shoulder in the first configuration.

Optionally the housing comprises at least one first orifice extending into the central cavity of the housing. Optionally the at least one first orifice extends through the wall of the housing. Optionally the at least one first orifice extends from the annular space or void, through the wall of the housing, and into the central cavity. Optionally the at least one first orifice is located above the internal sealing member, e.g. optionally the at least one first orifice is located above the annular seal of the internal sealing member. Optionally the at least one first orifice is angled downward into the central cavity. Optionally the at least one first orifice comprises a first opening within the central cavity and a second opening within the void. Optionally the second opening is located at a higher point than the first opening.

Optionally, as fluid is pumped into the downhole tool, the fluid flows through the annular space or void and enters the at least one first orifice of the housing. Optionally in the first configuration of the sealing assembly the annular seal of the internal sealing member resists any further flow of the fluid within the housing.

Optionally the annular external seal resists any further flow of the fluid beyond the location of the external seal in the annular space/void.

Optionally as fluid continues to be pumped into the downhole tool a column of fluid builds up within the downhole tool. Optionally as fluid continues to be pumped into the downhole tool the fluid pressure within the housing increases.

Optionally when the fluid pressure reaches a threshold value, the biasing force of the resilient device of the sealing assembly is overcome and the internal sealing member moves within the central cavity of the housing, into a second configuration.

Optionally, the movement of the internal sealing member compresses the resilient device. Optionally, the movement of the internal sealing member within the housing disengages the at least one annular seal of the internal sealing member from the housing.

Optionally the housing comprises at least one second orifice, axially spaced apart from the at least one first orifice. Optionally the at least one second orifice extends through the wall of the housing. Optionally the at least one second orifice extends from the annular space or void, through the wall of the housing, and into the central cavity of the housing. Optionally the at least one second orifice is located below the internal sealing member, e.g. optionally the at least one second orifice is located below the annular seal of the internal sealing member. Optionally the at least one second orifice is angled downward away from/out of the cenral cavity. Optionally the at least one second orifice comprises a first opening within the cavity and a second opening within the void. Optionally the second opening is located at a lower point than the first opening.

Optionally, disengagement of the annular seal opens a fluid flowpath through the central cavity of the housing of the sealing assembly. Optionally fluid flowing through the central cavity of the housing exits the sealing assembly by bypassing, or flowing around, the internal sealing member and flowing through the at least one second orifice. Optionally the fluid then flows out of the downhole tool (for example through an aperture in a downhole end of the downhole tool). Optionally the fluid flows out of the device, for example through an opening in a downhole end of the device.

Optionally fluid pumping stops after a period of time, optionally a predetermined period of time, or optionally in response to a signal. Optionally when fluid pumping ceases, the fluid within the downhole tool drains from the downhole tool through the fluid flowpath through the sealing assembly. Optionally the fluid pressure within the sealing assembly also falls. Optionally when the fluid pressure within the sealing assembly reaches a predetermined threshold value, the biasing force of the resilient device exceeds the force of the fluid pressure. Optionally the internal sealing member returns to the first configuration from the second configuration. Optionally the annular seal of the internal sealing member again seals against the central cavity of the housing. Optionally when the internal sealing member returns to the first configuration, some fluid (optionally descaling media) remains within the downhole tool and the device. This offers the advantage of soaking the components of the device in the fluid, which may contain descaling or other cleaning media, for an extended period of time, further improving cleaning.

Optionally the downhole tool is deployed on wireline. Optionally the downhole tool is set within the device. Optionally at an end of the downhole tool, for example the top of the tool/uphole end, there may be a component or portion comprising a larger diameter than the internal diameter of the device. Optionally the component or portion allows the downhole tool to hang off at a known reference point within the device. Optionally the downhole tool is configured to interact with a no-go landing nipple on or adjacent to the device, which optionally sets the downhole tool at the desired location within the device.

According to the present invention there is further provided a method of cleaning a device in an oil and/or gas well, the method comprising: actuating an movable valve, disposed within a sleeve of a downhole tool, in response to changes in fluid pressure within the downhole tool; wherein the sleeve comprises a sleeve wall, with first and second tubular sections configured to allow fluid flow through the sleeve wall; wherein actuation of the movable valve changes the downhole tool between first and second configurations; and wherein the method further comprises the movable valve: permitting fluid flow through the first tubular section of the sleeve and restricting fluid flow through the second tubular section of the sleeve when the downhole tool is in a first configuration; and permitting fluid flow through the second tubular section of the sleeve and restricting fluid flow through the first tubular section of the sleeve when the downhole tool is in a second configuration.

Optionally the method comprises deploying the downhole tool on wireline to the target position in the oil and/or gas well. Optionally the method includes setting the downhole tool within the device.

Optionally the method includes pumping fluid from the surface into the downhole tool when the downhole tool is disposed within the device. Optionally the method includes changing the fluid pressure within the downhole tool by changing the fluid flow/pump rate at the surface. Optionally the method includes changing the downhole tool between first and second configurations by changing the fluid flow/pump rate at the surface.

Optionally the method includes restricting fluid flow between portions of the downhole tool that are disposed on opposing sides of an annular seal. Optionally the method includes flowing fluid through at least one aperture or port formed in a wall of the movable valve. Optionally the method comprises restricting fluid flow through the second tubular section of the downhole tool when the downhole tool is in the first configuration.

Optionally the method includes jetting fluid from the downhole tool through one or more of the first and section tubular sections by pumping pressurised fluid through the downhole tool from the surface. Optionally the method includes jetting fluid from the downhole tool in a substantially perpendicular direction relative to the longitudinal axis of the downhole tool. Optionally the method includes arranging pluralities of perforations in the wall of the sleeve of the downhole tool to provide a jetting effect of fluid, optionally a radial jetting effect. Optionally the method includes jetting fluid from the downhole tool in a direction that is substantially perpendicular relative to the flow of fluid within the downhole tool.

Optionally the method includes creating a pressure differential within the movable valve by increasing the pump rate of the fluid. Optionally, the method includes increasing the jetting force of the fluid passing through the downhole tool by increasing the pump rate of the fluid at the surface, and thereby increasing back pressure above the movable valve.

Optionally the method includes increasing fluid pressure between the pump at the surface, the apertures/ports of the movable valve, and the internal wall of the perforated portion of the downhole tool with which the ports of the movable valve are aligned, relative to the pressure within the volume between the external wall of the downhole tool and the well below the downhole tool.

Optionally the method includes actuating the movable valve from the first configuration, where the one or more ports of the movable valve are disposed within the first tubular section of the downhole tool, to the second configuration where the one or more ports of the movable valve are disposed within the second tubular section of the downhole tool. Optionally the method includes setting a pressure threshold which when reached and/or exceeded, moves the movable valve, optionally in a downhole direction. Optionally the method includes setting the pressure threshold such that it exceeds the biasing force of a resilient device that acts to maintain the movable valve in a first position and thereby maintain the downhole tool in the first configuration.

Optionally the fluid pressure threshold may be between 1 and 8 psi, or alternatively between 3 and 6 psi; however this is not limiting and higher or lower pressure thresholds may be selected according to the tool configuration/downhole environment etc..

Optionally the method includes moving the movable valve past the annular seal. Optionally the method includes increasing the pressure differential. Optionally the method includes increasing the pressure differential by restricting fluid flow through the one or more ports of the movable valve, optionally by aligning the one or more ports of the movable valve with the annular seal in an intermediate stage between the first and the second configurations, thereby restricting fluid flow between the movable valve and the first and second tubular sections of the downhole tool.

Optionally the method includes moving the movable valve past the annular seal, into the second configuration, by increasing the pressure differential.

Optionally the method includes moving the valve between either side of the annular seal. Optionally the method includes jetting fluid through the second tubular section of the downhole tool by flowing fluid through the one or more port of the movable valve. Optionally the method includes restricting fluid flow through the first tubular second of the downhole tool when the downhole tool is in the second configuration.

Optionally the method includes returning the downhole tool to the first configuration by reducing the fluid pump rate (optionally thereby reducing the pressure differential). Optionally the method includes reducing the fluid pump rate, thereby reducing the fluid pressure within the downhole tool below the equivalent biasing force of the resilient device. Optionally the method includes returning the movable valve to its initial position in the first configuration of the downhole tool, due to the biasing force of the resilient device being greater than the force of the fluid pressure against the movable valve.

Optionally the method includes cycling the downhole tool between the first and second configurations within the device. Optionally the method includes changing the downhole tool between first and second configurations in situ in the downhole environment, i.e. without retracting the downhole tool from the device. Optionally the method includes operating the device throughout the jetting phases of the downhole tool described herein, e.g. hydraulically operating the device. Optionally the method includes actuating the components that are being cleaned (and thereby exercising the movement of the components), e.g. where the device is a safety valve, a flow tube and a flapper mechanism; where the device is a side pocket mandrel, one or more gas lift valves; which can advantageously assist in regaining full functionality of the device.

Optionally the method includes alternately restricting and permitting fluid flow through the downhole end of the downhole tool. Optionally the method includes increasing fluid pressure within a sealing assembly disposed at the downhole end of the downhole tool, optionally by pumping fluid into the downhole tool from the surface. Optionally the sealing assembly comprises a movable internal sealing member configured to restrict fluid flow through the sealing assembly in a first configuration, and permit fluid flow through the sealing assembly in a second configuration.

Optionally as the fluid pressure increases within the sealing assembly, a biasing force of a resilient device is overcome, and the internal sealing member moves from the first, sealing, configuration, into the second, unsealed configuration. Optionally the in the second configuration fluid within the sealing assembly can flow through the sealing assembly and bypass the internal sealing member. Optionally the fluid may then drain from the downhole tool through, for example, an aperture in a downhole end of the downhole tool.

Optionally the method includes reducing fluid pressure within the sealing assembly by stopping further pumping of fluid from the surface, as fluid continues to drain from the downhole tool. Optionally the method includes returning the internal sealing member to the first configuration by reducing fluid pressure within the sealing assembly. Optionally the method includes retaining a volume of fluid (for example cleaning media, descaling media, or any other fluid) within the downhole tool and/or the device.

Optionally the method includes cycling the sealing assembly between the first and second configurations The various aspects of the present invention can be practiced alone or in combination with one or more of the other aspects, as will be appreciated by those skilled in the relevant arts. The various aspects of the invention can optionally be provided in combination with one or more of the optional features of the other aspects of the invention. Also, optional features described in relation to one aspect can typically be combined alone or together with other features in different aspects of the invention. Any subject matter described in this specification can be combined with any other subject matter in the specification to form a novel combination.

Various aspects of the invention will now be described in detail with reference to the accompanying figures. Still other aspects, features, and advantages of the present invention are readily apparent from the entire description thereof, including the figures, which illustrates a number of exemplary aspects and implementations. The invention is also capable of other and different examples and aspects, and its several details can be modified in various respects, all without departing from the scope of the present invention. Accordingly, each example herein should be understood to have broad application, and is meant to illustrate one possible way of carrying out the invention, without intending to suggest that the scope of this disclosure, including the claims, is limited to that example. Furthermore, the terminology and phraseology used herein is solely used for descriptive purposes and should not be construed as limiting in scope. Language such as "including", "comprising", "having", "containing", or "involving" and variations thereof, is intended to be broad and encompass the subject matter listed thereafter, equivalents, and additional subject matter not recited, and is not intended to exclude other additives, components, integers or steps. Likewise, the term "comprising" is considered synonymous with the terms "including" or "containing" for applicable legal purposes. Thus, throughout the specification and claims unless the context requires otherwise, the word "comprise" or variations thereof such as "comprises" or "comprising" will be understood to imply the inclusion of a stated integer or group of integers but not the exclusion of any other integer or group of integers.

Any discussion of documents, acts, materials, devices, articles and the like is included in the specification solely for the purpose of providing a context for the present invention. It is not suggested or represented that any or all of these matters formed part of the prior art base or were common general knowledge in the field relevant to the present invention.

In this disclosure, whenever a composition, an element or a group of elements is preceded with the transitional phrase "comprising", it is understood that we also contemplate the same composition, element or group of elements with transitional phrases "consisting essentially of", "consisting", "selected from the group of consisting of", "including", or "is" preceding the recitation of the composition, element or group of elements and vice versa. In this disclosure, the words "typically" or "optionally" are to be understood as being intended to indicate optional or nonessential features of the invention which are present in certain examples but which can be omitted in others without departing from the scope of the invention.

All numerical values in this disclosure are understood as being modified by "about".

All singular forms of elements, or any other components described herein are understood to include plural forms thereof and vice versa. References to directional and positional descriptions such as upper and lower and directions e.g. "up", "down" etc. are to be interpreted by a skilled reader in the context of the examples described to refer to the orientation of features shown in the drawings, and are not to be interpreted as limiting the invention to the literal interpretation of the term, but instead should be as understood by the skilled addressee. In particular, positional references in relation to the well such as "up" and similar terms will be interpreted to refer to a direction toward the point of entry of the borehole into the ground or the seabed, and "down" and similar terms will be interpreted to refer to a direction away from the point of entry, whether the well being referred to is a conventional vertical well or a deviated well.

BRIEF DESCRIPTION OF THE DRAWINGS

In the accompanying drawings: Figure 1 shows a schematic cross-sectional view of an example tubing retrievable subsurface safety valve (TRSSV) that the present invention is suitable for use with, the TRSSV in an open configuration; Figure 2 shows the TRSSV of Figure 1 in a closed configuration; Figure 3 shows a schematic view of a downhole tool in accordance with the invention; Figure 4 shows a schematic cross-sectional view of the downhole tool of Figure 3 in the first configuration; Figure 5 shows a schematic cross-sectional view of the downhole tool of Figures 3 and 4 in the second configuration; Figure 6 shows a schematic cross-sectional view of a downhole tool deployed within a TRSSV, with the downhole tool in the first configuration; Figure 7 shows a schematic close-up view of a section of Figure 6 including perforations in the first tubular section aligned with a flow tube void of the TRSSV; Figure 8 shows a schematic close-up view of a further section of Figure 6 including perforations in the second tubular section aligned with the flapper valve of the TRSSV; Figure 9 shows the downhole tool of Figure 6 with an alternative close-up view of ports in the wall of an axially movable valve, and the fluid flowpath from the ports through the perforations in the first tubular member and jetting into the flow tube void of the TRSSV; Figure 10 shows a schematic cross-sectional view of a downhole tool in accordance with the invention, where the downhole tool has been deployed within a TRSSV and is in the second configuration; Figure 11 shows a schematic close-up view of a section of Figure 10 including perforations in the first tubular section aligned with a flow tube void of the TRSSV, with the fluid flowpath now bypassing these perforations; Figure 12 shows a schematic close-up view of a further section of Figure 10 including perforations in the second tubular section aligned with the flapper of the TRSSV, with the fluid flowpath exiting the perforations and jetting into the flapper valve; Figure 13a shows a schematic cross-sectional view of a downhole tool in the first configuration in accordance with the invention; Figure 13b shows a close-up view of the indicated section of Figure 13, showing the fluid flowpath exiting ports in the axially movable valve towards perforations in the first tubular section; Figure 13c shows a close-up view of the indicated section of Figure 13a, showing the fluid flowpath from the ports through the perforations and jetting outwards; Figure 14a shows a schematic cross-sectional view of a downhole tool in the second configuration in accordance with the invention; Figure 14b shows a close-up view of the uppermost indicated section of Figure 14, showing the fluid flowpath exiting ports in the axially movable valve and travelling downwards; Figure 14c shows a close-up view of the lower indicated section of Figure 14, showing the fluid flowpath towards the perforations in the second tubular section; Figure 14d shows a close-up view of the indicated section of Figure 14b, showing the fluid flowpath through the perforations and jetting outwards; Figure 15 shows a schematic cross-sectional view of a downhole tool comprising an internal seal in a sealed configuration as fluid is pumped into the tool; Figure 16 shows a close-up view of the internal seal of Figure 15 and associated fluid flowpath in the sealed configuration; Figure 17 shows a schematic cross-sectional view of the downhole tool of Figure 15, with the internal seal in an open configuration as fluid is pumped into the tool; Figure 18 shows a close-up view of the internal seal of Figure 17 and the associated fluid flowpath in the open configuration; Figure 19 shows a schematic cross-sectional view of the downhole tool of Figure 15, with the internal seal in a sealed configuration following cessation of fluid pumping into the tool; and Figure 20 shows a close-up view of the internal seal of Figure 19 and the associated fluid flowpath following reinstatement of the internal seal.

DETAILED DESCRIPTION OF EXAMPLES OF THE INVENTION

As shown in Figures 1 and 2, a tubing retrievable subsurface safety valve (TRSSV) 1 is a downhole safety valve that is run and retrieved as part of the production tubing and operated at surface through a hydraulic control line secured to the outside of the tubing. By applying hydraulic pressure the safety valve 1 can be opened via a piston and spring arrangement that forces a tube (flow tube 8) against a flapper 5 so that it is held open. Any loss of hydraulic control line pressure will result in the automatic closure of the safety valve 1 -commonly referred to as a fail-safe device.

It is possible that due to historical scaling issues within a wellbore, for example, a TRSSV (or any similar device with moving parts that may be subject to scaling) may suffer from scale accumulation that results in the valve failing to function satisfactorily. In particular, scale can build up within critical mechanisms of the TRSSV and hinder full movement of these parts and others that rely on them.

It is desirable to be able to descale the TRSSV with chemical cleaning agents. To achieve this, jetted fluid can be targeted at different areas within the internal profile of the TRSSV by using a downhole tool in accordance with the present invention, avoiding the need for retrieval, reconfiguration and redeployment of the tool. The introduction of a pressure reactive fluid diverter system (in the form of the movable valve described above and further described below, in the following examples an axially movable valve) that responds to variation of flow rate allows jetted fluid to be targeted at more than one area within the safety valve, without the need to retrieve and redeploy the tool. This offers significant operational advantages, particularly in terms of time and costs saved through the ability to adjust the tool in situ.

Referring now to Figure 1, an example of a TRSSV 1 (with which the present invention is suitable for use) with a throughbore 2 is shown in an open configuration with the flapper valve 5 held open by the flow tube 8. In this configuration, flow tube void 9 is created by the flow tube 8 having moved downwards under hydraulic pressure to hold the flapper valve 5 open.

Figure 2 shows the TRSSV in a closed configuration, where the flow tube 8 has been retracted upwards into the flow tube void 9, and the flapper valve 5 has actuated to close off the throughbore 2 of the TRSSV 1.

Figure 3 shows a jet sleeve 100 that can be deployed downhole (e.g. on wireline), within a TRSSV 1 in this example, but the sleeve can be adjusted for jetfing/cleaning/descaling other suitable components. The jet sleeve 100 comprises a no-go profile 110 on its external surface, which engages with the no-go shoulder 10 of the TRSSV 1 shown in Figures 1 and 2.

The jet sleeve 100 further comprises at least two modular tubular sections, an upper modular section 111 and a lower modular section 112. Upper modular section 111 extends between the no-go profile 110 and an upper jetting section 120 of the jet sleeve 100. The length of the upper modular section 111 can be selected so that the distance between the no-go profile 110 and the upper jetting section 120 matches the distance between the no-go shoulder 10 of the TRSSV and the first component to be cleaned, for example flow tube void 9 (Fig.1 and 2). Each of the sections of the jet sleeve 100 can be connected together with threaded connections or other suitable means of connection.

The lower modular section 112 is located between the upper jetting section 120 and a lower jetting section 140. The length of the lower modular section 112 can also be selected to provide optimal axial spacing of the two jetting sections 120, 140 so that both jetting sections 120, 140 align with the relevant components to be cleaned, for example flow tube void 9 and flapper 5 (Fig. 1 and 2).

Both the upper and lower jetting sections 120, 140 comprise multiple apertures or perforations 122, 142 in a wall of the sections 120, 140. In the example shown, the upper and lower jetting sections comprise perforations 122, 142 around their circumference. The perforations 122, 142, can be in a generally radial pattern and are substantially equally spaced apart. Accordingly, any rotation of the jet sleeve 100, for example during deployment, has no detrimental effect on the jetting of fluid out of the upper and/or lower jetting sections 120, 140 as the upper and lower jetting sections 120, 140 permit jetting of fluid around 360° relative to the longitudinal axis of the jet sleeve 100 The jet sleeve 100 comprises an inner bore 103 which is open at the jet sleeve's 100 upper end 100U, and closed at the jet sleeve's lower end 100L. Within the inner bore 103, there is a differential piston or diverter valve 150 that is coaxial with the jet sleeve 100. The diverter valve 150 comprises an inner bore 151 into which fluid can enter via the inner bore 103 of the jet sleeve 100; the inner bore 151 is open at an upper end to receive fluid from the inner bore 103, and closed off at the opposite, lower, end.

A coil spring 153 surrounds a portion of the exterior of the diverter valve 150. The coil spring 153 is held in place between a shoulder 152 formed at the upper end of the diverter valve 150 and a first annular seal 157 that extends around a first portion of the external surface of the diverter valve 150. A second annular seal 158 extends around a second portion of the external surface of the diverter valve 150 and is axially spaced from the first annular seal 157. Both annular seals 157, 158 act to seal against the external surface of the diverter valve 150 on their inner circumference, and seal against the inner surface of the jet sleeve 100 on the seals' 157, 158 outer circumference. The second annular seal 158 restricts fluid communication between the upper and lower jetting zones 120, 140.

The diverter valve 150 comprises a plurality of ports 155 that extend through the wall of the diverter valve 150 towards the diverter valve's 150 lower end. A central axis of each port 155 is perpendicular to the longitudinal axis of the diverter valve 150. The ports 155 are shown in a circumferential arrangement around a section of the diverter valve 150. In a first configuration of the jet sleeve 100 (and of the diverter valve 150), the ports 155 are positioned above the second annular seal 158. The biasing force of the coil spring 153 acts to hold the diverter valve 150 in this position in the absence of any greater force acting against the coil spring 153. To facilitate fluid flow, the ports 155 are larger than the perforations 122, 142 in the upper and lower jetting sections 120, 140, i.e. as shown in this example the ports 155 can have a larger diameter than the perforations 122, 142.

Pressurised fluid is pumped downhole into the jet sleeve 100 from the surface.

As shown in Figures 4 and 5, fluid enters into the bore 103 at the upper end 100U of the jet sleeve 100 but cannot exit out of the inner bore 103 without following predetermined fluid pathways FP1 and FP2.

Figure 4 shows the jet sleeve 100 in the first configuration, when fluid pumped from the surface is of relatively low pressure and low flow. Fluid passes from the inner bore 103 of the jet sleeve 100 into the inner bore 151 of the diverter valve 150. Following the first fluid pathway FP1, the fluid exits the diverter valve 151 through the ports 155. The first and second annular seals 157, 158 restrict fluid communication between the portions of the jet sleeve 100 that are disposed on opposing sides of the annular seals 157, 158. As a result, fluid exiting the ports 155 enters an annular chamber 125 formed between the two annular seals 157, 158 in an axial direction, and between the inner surface of the upper jetting zone 120 of the jet sleeve 100 and the outer surface of the diverter valve 150 in a radial direction. Fluid within the chamber 125 exits the jet sleeve 100 through the perforations 122 in the upper jetting section 120. As illustrated, fluid jets through the perforations 122 in a substantially perpendicular direction relative to the longitudinal axis of the jet sleeve 100 and the direction of fluid flow within the jet sleeve 100. The arrangement of the perforations 122 provides a radial fluid jetting effect. After jetting, the fluid falls freely past the rest of the jet sleeve 100.

The fluid that is pumped downhole can include cleaning chemicals to enhance descaling/cleaning of the components of the safety valve along with the mechanical cleaning effect of the jetting fluid.

The fluid pressure can be increased at the surface to move the diverter valve 150 downwards, and the jet sleeve 100 into a second configuration, shown in Figure 5 for a high fluid pressure/high fluid flow situation. As the lower end of the diverter valve 150 is closed off, the fluid acts against the lower end of the diverter valve 150 to push it in a downwards direction, compressing the coil spring 153 and acting against the biasing force of the coil spring 153.

As the diverter valve 150 moves downwards, the ports 155 of the diverter valve 150 pass by the second annular seal 158. At an intermediate stage between the first and second configurations of the jet sleeve 100, the ports 155 of the diverter valve 150 align with the second annular seal 158, restricting fluid flow through the ports 155 (not shown). This results in increasing back pressure within the diverter valve 150 and can move the diverter valve downwards more rapidly than the initial movement that aligned the ports 155 with the second annular seal 158.

When the jet sleeve 100 is in the second configuration, the ports 155 of the diverter valve 150 are positioned below the second annular seal 158. In the second configuration, the fluid flowpath FP2 begins with fluid entering the bore 151 of the diverter valve 150 from the bore 103 of the jet sleeve 100. The fluid flows through the ports 155 and enters into the lower part of the bore 103L of the jet sleeve 100 below the diverter valve 150. The fluid then exits the lower bore 103L through the perforations 142 of the lower jetting section 140, and falls freely past the rest of the jet sleeve 100.

The alignment of the upper and lower jetting sections 120, 140 with the flow tube void 9 and the flapper 5 of the safety valve 1 results in precisely targeted fluid jetting of the components.

The diverter valve 150 can be moved between either side of the annular seal 150, and therefore the jet sleeve 100 can be moved between the first and second configurations as often as required by altering the fluid pump rate from the surface -with lower flow, the force of the coil spring 153 is greater than the pressure from the fluid and therefore the diverter valve 150 remains in its initial position; while with higher flow, the biasing force of the coil spring 153 is exceeded by the force of the fluid acting on the diverter valve 150, moving the diverter valve 150 downwards. To return the diverter valve 150 to its original position, the fluid flow can be reduced once more.

Figures 6-14d show an example of a jet sleeve 300 within a tubing retrievable subsurface safety valve (TRSSV) 200. In these figures, the numbering convention of the previously described examples of Figures 1-5 is maintained, with reference numbers increased by 200.

Figures 6-8 show the jet sleeve 300 deployed within the TRSSV 200, with the no-go profile 310 of the upper end 300U of the jet sleeve 300 engaged and hanging off the no-go shoulder 210 of the safety valve 200. The jet sleeve 300 is shown here in the first configuration.

Figure 7 shows a detail of the upper jetting section 320, with the ports 355 of the diverter valve 350, first and second annular seals 357, 358, the perforations 322 of the upper jetting section 320, and the flow tube void 209 of the safety valve 200 which is the target of the upper jetting section 320 in the examples described here.

Figure 8 shows a detail view of the lower jetting section 340, with the perforations 342 of the lower jetting section 340 aligned with the flapper 205 of the safety valve 200.

Figure 9 is another view of the jet sleeve 300 in the safety valve 200. A detail view of the upper jetting section 320 is shown, with the fluid flowpath FP3 illustrated. Fluid enters the bore 303 of the jet sleeve 300 and travels into the bore 351 of the diverter valve 350. The fluid exits the diverter valve 350 through ports 355 in the wall of the diverter valve 350 and enters an annular chamber 325 disposed between the jet sleeve 300 and the diverter valve 350. The fluid is then jetted from the perforations 322 in radial jets J1 into the flow tube void 209, and the fluid then falls freely past the rest of the jet sleeve 300.

Figures 10-12 show the jet sleeve 300 and safety valve 200 as above, with the jet sleeve 300 in the second configuration. Figure 11 shows a detail view of the upper jetting section 320, with the ports 355 now located below the annular seal 358. Fluid flow path PF4 shows the fluid entering the bore 351 of the diverter valve 350 and passing through the ports 355. The fluid then enters the lower section of the bore 303L of the jet sleeve 300 and passes through the perforations 342 in the lower jetting section 340 in radial jets J2 against the flapper 205 of the safety valve 200. Once jetted, the fluid falls past the rest of the jet sleeve 300.

Figures 13a-13c show a further view of the jet sleeve 300 in the first configuration and alternative detail views of the upper jetting section 320, with the flow path FP3 and jets J1 shown in detail in Figures 13b and 13c.

Figures 14a-14d show further views of the jet sleeve 300 in the second configuration. Figure 14b shows a detail view of a portion of the upper jetting section 320 with fluid flowpath FP4 illustrated, passing through the ports 355 of the diverter valve 350 and flowing downwards into the lower bore 303L of the jet sleeve 300. Figures 14c and 14d show detail view of the lower jetting section 340, with the fluid passing through the perforations 342 and exiting in jets J2 against the flapper of the safety valve.

Figures 15-20 show an example of a jet sleeve 500 within a tubing retrievable subsurface safety valve (TRSSV) 400 as described above. In these figures, the numbering convention of the previously described examples of Figures 6-14d is maintained, with reference numbers increased by 200 where applicable.

Figure 15 shows a jet sleeve 500 including a sealing assembly 580 comprising a movable sealing component 581 disposed within a central cavity 585 formed within a housing 583. The jet sleeve 500 is in situ within the tubing retrievable subsurface safety valve (TRSSV) 400.

As best seen in Figure 16, fluid exits the jet sleeve 500 through perforations 542 in the lower jetting section 540. The fluid that exits through the perforations 542 travels down through the void 509 formed between the inner wall of the TRSSV 400 and the outer wall of the jet sleeve 500 and follows fluid flowpath FP5.

The sealing assembly 580 is located at the distal end of the jet sleeve 500. The sealing assembly 580 comprises a first annular seal 589 that is disposed within a recess formed in the surface of the housing 583 of the sealing assembly 580. The first annular seal 589 is arranged to seal within the void 509 and restrict further passage of fluid longitudinally through the void 509.

The sealing assembly 580 comprises at least one first orifice. In this example, the sealing assembly 580 comprises a plurality of first orifices 584 radially spaced around the housing 583. The first orifices 584 are disposed above the external seal 589. The first orifices 584 extend through the wall of the housing 583 into the central cavity 585, and can be angled to direct fluid towards the central cavity 585 of the housing.

Within the central cavity 585 is the movable sealing component 581 comprising a body 581d, a collar 581c, and a second annular seal 582 disposed at least partially around the outer surface of the movable sealing component 581. The collar 581c may be threaded or otherwise attached to a portion of the body 581d of the movable sealing component 581. The collar 581c comprises a radially protruding arm with a raised edge forming a recess 581a within which the second annular seal 582 sits. The body 581d also comprises a radially protruding shoulder 581b. When the collar 581c is connected to the body 581d, the radially protruding shoulder 581b of the body 581d encloses a portion of the second annular seal 582 to hold the seal 582 in place. A portion of the seal 582 remains exposed, and in a first configuration of the movable sealing component 581, the second annular seal 582 seals against the wall of the central cavity 585.

In the first configuration, the second annular seal 582 restricts fluid passage so that fluid that enters through the first orifices 584 and cannot flow past the second annular seal 582. In the first configuration therefore, fluid flow is restricted past the first and second annular seals and fluid cannot drain from the TRSSV 400. This results in a column of media building up within the TRSSV 400. Continued pumping of fluid into the TRSSV 400 results in fluid pressure increasing within the TRSSV 400.

The movable sealing component 581 can optionally further comprise upper 591 and lower 592 extensions, each with diameters that are smaller than the widest diameter or cross section of the movable sealing component 581. The diameter of the upper extension 591 and the lower extension 592 can be the same, or can differ from each other. The upper extension 591 is disposed within an upper recess 593 in the housing 583 and can act to keep the movable sealing component 581 centralised within the central cavity 585. The lower extension 592 extends into a lower recess 594 that holds a resilient device 595, in this example a coil spring but alternative resilient devices can be used. The lower extension 592 is encircled by the resilient device 595 and is axially aligned with the coil spring 595. The resilient device 595 is biased to maintain the movable sealing component 581 in the first configuration.

When the fluid pressure reaches a threshold value within the TRSSV 400, and therefore within the central cavity 585, the biasing force of the resilient device 595 is overcome and the movable sealing component 581 moves downwards within the central cavity 585 of the housing 583, into a second configuration, shown in Figures 17 and 18. The movement of the movable sealing component 581 compresses the resilient device 595. As the movable sealing component 581 moves, the second annular seal 582 disengages from the wall of the central cavity 585.

The sealing assembly 580 comprises at least one second orifice. In this example, the sealing assembly 580 comprises a plurality of second orifices 586 radially spaced around the housing 583 and axially spaced apart from the first orifices 584. The second orifices 586 extend through the wall of the housing 583 from the void 509 and into the central cavity 585. The second orifices 586 are angled to carry fluid out of the central cavity 585 and downwards into the lower portion of the TRSSV 400 -in other words, the openings of the second orifices 586 into the central cavity 585 are higher than the openings into the void 509. The second orifices 586 are positioned below the second annular seal 582 in the central cavity 585.

When the movable sealing component 581 moves into the second configuration, a fluid flowpath FP6 opens up through the central cavity 585. Fluid that has built up within the TRSSV 400 can flow through the central cavity 585 and exit the sealing assembly 580 by flowing around the movable sealing component 581 and through the second orifices 586. The fluid can then escape from the TRSSV 400 by passing through an opening at the end of the TRSSV 400.

When fluid stops pumping from the surface -for example after a predetermined time, or in response to a signal -the fluid within the TRSSV 400 continues to drain out of the tool. Eventually the fluid pressure within the TRSSV 400 (and therefore within the sealing assembly 580) reduces back to and beyond the predetermined threshold value. As the biasing force of the resilient device 595 is stronger than the force of the fluid pressure, the movably sealing component 581 returns to the first configuration from the second configuration (Figures 19 and 20). The second annular seal 582 of the again seals against the central cavity 585 of the housing 583.

When the movable sealing component 581 returns to the first configuration, some fluid (e.g. descaling media) remains within the TRSSV 400, soaking the components of the TRSSV 400 in the fluid.

Modifications and improvements may be made to the examples hereinbefore described without departing from the scope of the invention

Claims

CLAIMS1. A downhole tool for cleaning of a device in an oil and/or gas well, the downhole tool comprising: a sleeve comprising a sleeve wall; the sleeve having at least first and second tubular sections configured to allow fluid flow through the sleeve wall; and a movable valve disposed within the sleeve; wherein the movable valve is actuatable in response to changes in fluid pressure within the downhole tool, and wherein actuation of the movable valve changes the downhole tool between first and second configurations; wherein the movable valve permits fluid flow through the first tubular section of the sleeve and restricts fluid flow through the second tubular section of the sleeve when the downhole tool is in the first configuration; and wherein the movable valve permits fluid flow through the second tubular section of the sleeve and restricts fluid flow through the first tubular section of the sleeve when the downhole tool is in the second configuration.
2. A downhole tool as claimed in claim 1, wherein the movable valve is an axially movable valve.
3. A downhole tool as claimed in claim 1 or claim 2, wherein the first tubular section of the sleeve comprises a first perforated portion, and the second tubular section of the sleeve comprises a second perforated portion.
4. A downhole tool as claimed in claim 3, wherein the first and second perforated portions extend at least partially around the circumference of the sleeve.
5. A downhole tool as claimed in claims 1-4, wherein the downhole tool comprises at least one annular seal, wherein the at least one annular seal is disposed between an inner surface of the sleeve wall and an outer surface of the movable valve.
6. A downhole tool as claimed in claim 5, wherein the movable valve comprises an inner bore defined by a wall, wherein the inner bore comprises an open end and a closed end
7. A downhole tool as claimed in claim 6, wherein the movable valve comprises a wall having at least one aperture extending through the wall and configured to permit fluid communication between the inner bore and an exterior of the movable valve.
8. A downhole tool as claimed in claim 6, wherein the wall of the movable valve comprises a plurality of apertures arranged circumferentially around the wall of the movable valve.
9. A downhole tool as claimed in claim 8, wherein in the first configuration, the at least one annular seal is located between the apertures of the movable valve and the second tubular section of the sleeve.
10. A downhole tool as claimed in 8 or claim 9, wherein in the second configuration, the at least one annular seal is located between the apertures of the movable valve and the first tubular section of the sleeve.
11. A downhole tool as claimed in claims 1-9, wherein the downhole tool comprises a resilient device configured to resist movement of the movable valve in at least one direction.
12. A downhole tool as claimed in claim 6, wherein the downhole tool comprises a resilient device biased against movement of the movable valve in at least one direction and configured to retain the downhole tool in the first configuration; wherein the inner bore of the movable valve is configured to receive fluid pumped from the surface; wherein the closed end of the inner bore of the movable valve provides a surface area for pumped fluid to act against; and wherein when the force of the pumped fluid acting against the surface area exceeds the biasing force of the resilient device, the movable valve is configured to move the downhole tool into the second configuration.
13. A downhole tool as claimed in claims 1-12, wherein the downhole tool further comprises a movable sealing assembly configured to alternately close and open a fluid flowpath through the movable sealing assembly; wherein when the fluid flowpath is closed, fluid is restricted from flowing out of the downhole tool; and wherein when the fluid flowpath is open, fluid is permitted to flow out of the downhole tool.
14. A method of cleaning a device in an oil and/or gas well, the method comprising: actuating a movable valve, disposed within a sleeve of a downhole tool, in response to changes in fluid pressure within the downhole tool; wherein the sleeve comprises a sleeve wall, with first and second tubular sections configured to allow fluid flow through the sleeve wall; wherein actuation of the movable valve changes the downhole tool between first and second configurations; and wherein the method further comprises the movable valve: permitting fluid flow through the first tubular section of the sleeve and restricting fluid flow through the second tubular section of the sleeve when the downhole tool is in a first configuration; and permitting fluid flow through the second tubular section of the sleeve and restricting fluid flow through the first tubular section of the sleeve when the downhole tool is in a second configuration.
15. A method as claimed in claim 14, wherein the movable valve is an axially movable valve.
16. A method as claimed in claim 14 or claim 15, the method including deploying the downhole tool into a wellbore from surface, and setting the downhole hole tool within a device.
17. A method as claimed in claim 16, the method further comprising pumping fluid from the surface into the downhole tool when the downhole tool is deployed and set within the device.
18. A method as claimed in claims 14-17, the method including changing the downhole tool between first and second configurations by changing a rate that fluid is pumped into the downhole tool from the surface.
19. A method as claimed in claims 14-18, including flowing fluid through at least one aperture formed in a wall of the movable valve.
20. A method as claimed in claim 14-18, wherein the downhole tool comprises at least one annular seal disposed between the sleeve and the movable valve; wherein the method includes: flowing fluid through at least one aperture formed in a wall of the movable valve; and restricting fluid flow through the second tubular section of the downhole tool when the downhole tool is in the first configuration by positioning the at least one aperture of the movable valve on a first side of the at least one annular seal, wherein the second tubular section of the downhole tool is on a second side of the at least one annular seal, opposing the first.
21. A method as claimed in claim 20, wherein the method includes restricting fluid flow through the first tubular section of the downhole tool when the downhole tool is in the second configuration by positioning the at least one aperture of the movable valve on the second side of the at least one annular seal.
22. A method as claimed in claims 14-21, the method including: pumping fluid into the downhole tool from the surface; jetting fluid from the downhole tool through at least one of the first and second tubular sections.
23. A method as claimed in claim 22, the method including jetting fluid in a substantially perpendicular direction relative to the longitudinal axis of the downhole tool through one or more perforations formed in the sleeve wall.
24. A method as claimed in claims 14-23, wherein the method includes moving the movable valve from the first configuration, where one or more apertures, formed in a wall of the movable valve, are disposed within the first tubular section of the downhole tool, to the second configuration where the one or more apertures of the movable valve are disposed within the second tubular section of the downhole tool.
25. A method as claimed in claims 14-24, wherein the method includes setting a pressure threshold of fluid pumped into the downhole tool, such that the pressure threshold exceeds the biasing force of a resilient device that acts to maintain the movable valve in a first position and thereby maintain the downhole tool in the first configuration.
26. A method as claimed in claim 25, wherein the method includes: reducing the fluid pump rate, thereby reducing the fluid pressure within the downhole tool below the equivalent biasing force of the resilient device; and returning the movable valve to its initial position in the first configuration of the downhole tool.
27. A method as claimed in claims 14-26, wherein the method includes: actuating a movable sealing assembly within the downhole tool to alternately open and close a fluid flowpath through the movable sealing assembly; wherein when the fluid flowpath is closed, fluid is restricted from flowing out of the downhole tool; and wherein when the fluid flow path is open, fluid is permitted to flow out of the downhole tool.