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Patent Searching and Data


Title:
DOWNHOLE METHOD AND APPARATUS
Document Type and Number:
WIPO Patent Application WO/2017/137781
Kind Code:
A1
Abstract:
A method for retrofitting a deployable component which includes a tracer constituent within a wellbore comprises deploying the deployable component into the wellbore, and securing the deployable component at a location within the wellbore. In one example the tracer constituent is releasable from the deployable component when exposed to a trigger condition and detectable at a remote location to permit one or more parameters associated with the wellbore to be derived.

Inventors:
PURKIS DANIEL GEORGE (GB)
Application Number:
PCT/GB2017/050378
Publication Date:
August 17, 2017
Filing Date:
February 13, 2017
Export Citation:
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Assignee:
WELL-SENSE TECH LTD (GB)
International Classes:
E21B23/00; E21B47/09; E21B47/10
Foreign References:
US20150322751A12015-11-12
US20150361761A12015-12-17
US20100212891A12010-08-26
US5346016A1994-09-13
US5176207A1993-01-05
US4605065A1986-08-12
US20130333872A12013-12-19
Other References:
None
Attorney, Agent or Firm:
MARKS & CLERK LLP (GB)
Download PDF:
Claims:
CLAIMS:

1. A method for retrofitting a deployable component within a wellbore, wherein the deployable component comprises a tracer constituent, comprising:

deploying the deployable component into the wellbore; and

securing the deployable component at a location within the wellbore.

2. The method according to claim 1 , comprising:

deploying the deployable component into a completion pre-installed within the wellbore; and

securing the deployable component at a location within the completion.

3. The method according to claim 1 or 2, wherein the tracer constituent is releasable from the deployable component when exposed to a trigger condition and detectable at a remote location to permit one or more parameters associated with the wellbore to be derived.

4. The method according to any preceding claim, wherein the deployable component comprises at least one type of tracer constituent.

5. The method according to any preceding claim, wherein the deployable component comprises multiple types of tracer constituents.

6. The method according to any preceding claim, wherein the deployable component is securable to an inner surface of a downhole component.

7. The method according to any preceding claim, wherein the deployable component comprises a securing arrangement for permitting the deployable component to be secured within the wellbore.

8. The method according to claim 7, wherein the securing arrangement comprises a magnetic securing arrangement for permitting the deployable component to be magnetically secured within the wellbore.

9. The method according to claim 8, wherein the magnetic securing arrangement comprises at least on magnet at least partially embedded within the deployable component. 10. The method according to claim 9, wherein the deployable component comprises a corrosion inhibitor or anti-corrosion arrangement to protect the at least one magnet from corrosion.

1 1. The method according to any preceding claim, wherein at least part of the deployable component is geometrically formed to match the profile of the wellbore or wellbore component.

12. The method according to any preceding claim, comprising deploying multiple deployable components.

13. The method according to claim 12, wherein at least two deployable components are deployed to be at least one of circumferentially and axially spaced apart with the wellbore. 14. The method according to claim 12 or 13, comprising deploying a first deployable component on a high side of the wellbore and a second deployable component on a low side of the wellbore bore.

15. The method according to claim 14, wherein the first and second deployable components comprise different tracer constituents to permit an understanding to be derived concerning the composition of a multiphase flow within the wellbore.

16. The method according to any preceding claim, comprising deploying the deployable component on a deployment tool which is run into the wellbore.

17. The method according to claim 16, wherein the deployment tool is configured to carry and deploy at least one deployable component.

18. The method according to claim 16 or 17, wherein the deployment tool is configured to carry and deploy multiple deployable components.

19. The method according to any one of claims 16 to 18, comprising ejecting the deployable component from the deployment tool in response to a command signal. 20. The method according claim 19, comprising ejecting the deployable component from the deployment tool in a direction to provide a predetermined deployed position of the deployable component.

21. The method according to any one of claims 16 to 20, wherein the deployment tool comprises an ejection mechanism for ejecting a deployable component.

22. The method according to claim 21 , wherein the ejection mechanism comprises a spring mechanism and a releasable latch arranged to be activated to permit actuation of the spring mechanism.

23. The method according to claim 21 or 22, wherein the ejection mechanism comprises a damping arrangement configured to suppress ejection velocity of the deployable component. 24. The method according to any one of claims 16 to 23, comprising running the deployment tool through an ESP bypass tube.

25. The method according to any preceding claim, comprising testing the attachment of the deployable component within the wellbore to determine if a suitable attachment has been achieved.

26. The method according to claim 25, comprising testing the attachment of the deployable component using a deployment tool. 27. The method according to any preceding claim, comprising preparing an attachment surface within the wellbore using a cleaning tool prior to attachment of a deployable component.

28. The method according to any preceding claim, comprising including a detectable identifier with the deployable component.

29. The method according to any preceding claim, comprising detecting a deployable component following deployment within the wellbore. 30. The method according to any preceding claim, comprising catching a deployable component which failed to sufficiently be secured within the wellbore.

31 . The method according to claim 30, comprising identifying a deployable component which has been caught.

32. The method according to any preceding claim, comprising removing a deployable component from the wellbore.

33. The method according to any preceding claim, comprising replacing a previously installed deployable component with a further deployable component.

34. A method for use in monitoring or detecting a downhole parameter and/or condition, comprising:

deploying a component comprising a tracer constituent into a completion pre- installed within a wellbore; and

securing the component at a location within the completion.

35. A downhole tool comprising:

a tool body;

a deployable component releasably mounted on the tool body; and

a releasing arrangement for releasing the deployable component.

36. A downhole deployable component to be deployed within a pre-installed completion in a wellbore, wherein the deployable component comprises a tracer constituent.

37. A method for deploying a deployable component within a wellbore, comprising running the deployable component into a wellbore, and magnetically securing the deployable component within the wellbore.

Description:
DOWNHOLE METHOD AND APPARATUS

FIELD The present disclosure relates to a method and apparatus for use in monitoring or detecting a downhole parameter, event and/or condition. The present disclosure also relates to a method and apparatus for deploying, for example retrofitting, one or more components in a wellbore. BACKGROUND

It is highly desirable for operators in the oil and gas production industry to acquire an understanding of conditions within a well. This may be advantageous in particular well types, such as in multi-zone completions, multi-lateral wells and the like. For example, an operator may seek an understanding of the inflow contribution across different zones or laterals, or when water breakthrough has occurred and where. Such knowledge may permit an operator to react to the precise conditions to maximise well performance, for example by modifying inflow across the production zone or zones, closing zones, modifying field-wide water flooding, developing appropriate intervention schedules and the like.

Proposals have been made in the industry to deploy so called smart-well completions, which may include various sensors and the like for detecting local conditions and returning data to surface, for example via optical fibres, wires and the like, or permitting autonomous control of completion components. However, such smart completions increase costs and may suffer from reliability issues.

It is known in the art to utilise a chemical solution for downhole surveillance, for example by integrating tracer chemicals into completion infrastructure prior to deployment, such that the tracer chemicals may be produced to surface in accordance with downhole conditions. Analysis of the produced fluids and of any detected tracer chemicals may permit an understanding of downhole conditions to be developed.

Tracer chemicals may be provided in a desired form, for example as an elongate strip, and installed directly within completion components, such as screens, ICDs and the like. Thus, the tracer chemicals may become deployed as an integral part of the completion.

Tracer chemicals are known which are sensitive to a particular fluid (i.e., a trigger fluid), such as oil and water, such that the tracer chemicals may be dormant until exposed to the particular trigger fluid, following which the tracer may be released and produced to surface. Such an arrangement may permit a tracer chemical to remain dormant in the wellbore during oil production, for example, and eventually be released and detected at surface following water breakthrough.

Furthermore, multiple tracer chemicals are known, each with unique chemical signatures. This allows multiple different tracers to be installed with a completion, such that the origin of tracers once detected at surface may be determined. SUMMARY

Aspects of the present disclosure relate to methods and apparatus for use in retrofitting a deployable component within a wellbore. The deployable component may comprise a tracer constituent, such as a tracer chemical. The tracer constituent may be releasable from the deployable component and detectable at a remote location, for example at a remote downhole location, surface location or the like. Such detection of the tracer constituent may permit one or more parameters associated with the wellbore to be derived, such as identification and/or allocation of flows in the wellbore. Accordingly, the present disclosure may not require completions and/or other wellbore infrastructure to be integrated with the necessary tracer constituents prior to being run into a wellbore. Further, the capability of retrofitting a deployable component with a tracer constituent in a wellbore may allow tracers to be placed prior to desired operations that were not envisioned when the wellbore was first completed.

The tracer constituent may be releasable from the deployable component when exposed to a particular trigger condition, such as a trigger fluid. The trigger fluid may comprise at least one of oil, gas, water and the like. The tracer constituent may comprise one or more tracer chemicals provided by Resman AS and/or Tracerco Limited.

The deployable component may comprise a single type of tracer constituent. The deployable component may comprise multiple tracer constituents, for example multiple types of tracer constituent. At least two tracer constituents may be the same or substantially similar. At least two tracer constituents may be different. For example, at least two tracer constituents may be releasable from the deployable component when exposed to different trigger conditions, for example different fluids.

The deployable component may comprise a solid component. The tracer constituent may form all or part of the solid component. For example, the tracer constituent may itself comprise a solid structure which forms all or part of the deployable component. The deployable component may comprise a solid matrix material, wherein the tracer constituent is embedded within the solid matrix material.

In examples where the deployable component comprises a solid component, the tracer constituent may be released upon break-up, disintegration, dissolving etc. of the solid component.

The deployable component may comprise a container, wherein the tracer constituent may be located within the container. The tracer constituent may be provided in solid form, liquid form, gel form or the like. The container may comprise an exit for permitting release of the tracer constituent from the container. The container may comprise an inlet for permitting a fluid to enter the container, for example to activate or cause release of the tracer constituent.

The method may comprise deploying the deployable component into the wellbore, and securing the deployable component at a desired location within the wellbore. The deployable component may be securable to a downhole component, such as a downhole tubular, pipe, tool or the like. The deployable component may be securable to an inner surface of a downhole component. In some embodiments the deployable component may be securable to an outer surface of a downhole component. The deployable component may comprise a securing arrangement for permitting the deployable component to be secured within the wellbore.

The securing arrangement may comprise a magnetic securing arrangement for permitting the deployable component to be magnetically secured within the wellbore. In such an arrangement the deployable component may be magnetically secured to a metallic component within the wellbore, such as a metallic tubular, pipe, tool or the like.

The securing arrangement may comprise at least one magnet, such as a permanent magnet, electro-magnet and/or the like. At least one magnet may be attached and/or embedded within the deployable component.

At least one magnet may be arranged such that the magnetic field is directed into the tubular as much as possible with as little external (stray) magnetic field as practical. This may assist to prevent a build-up of magnetic debris around the deployable component.

At least one pot magnet may be provided. At least one channel magnet may be provided.

At least one Neodymium Iron Boron magnet may be provided. At least one Samarium Cobalt magnet may be provided.

The choice of magnet may depend on temperature and desired clamping/securing force.

The deployable component may comprise a corrosion inhibitor or anti-corrosion arrangement to protect at least one magnet from corrosion, for example by use of a plating or coating, such as nickel plating.

In one example at least one magnet may be completely embedded within the deployable component.

The deployable component, for example a securing arrangement of the deployable component, may be geometrically formed to match the profile, for example inner diameter profile, of the wellbore or wellbore component. The deployable component may be geometrically formed to provide minimal protuberance toward the wellbore centre. The method may comprise deploying a single deployable component.

The method may comprise deploying multiple deployable components. Multiple deployable components may be deployed to be located at a common axial position within a wellbore. Multiple deployable components may be deployed to be located at different circumferential positions within the wellbore. Multiple deployable components may be deployed to be axially spaced apart within a wellbore. Such an arrangement may facilitate deployable components to be located within separate production intervals or zones within the wellbore. The method may comprise deploying the deployable component using a deployment tool, such as an intervention tool.

The deployment tool may be deployed from surface. The deployment tool may be deployable on an elongate member, such as e-line, coil tubing, slick line, fibre line or the like. The deployment tool may be deployable untethered. The deployment tool may be self-propelled.

The deployment tool may be run on a low side of a deviated wellbore. In some examples the deployment tool may be centralised within a wellbore, for example by one or more centraliser components secured or provided on the deployment tool.

The deployment tool may comprise or carry at least one deployable component. The deployment tool may comprise or carry multiple deployable components. The deployment tool may be run into the wellbore, typically just beyond the deepest point that a deployable component is required. The deployment tool may be pulled or otherwise moved back until the required location is achieved.

The method may comprise ejecting or releasing a deployable component from the deployment tool. Such ejection may be achieved in response to a command signal. The command signal may originate within the deployment tool, for example from an onboard controller. In this arrangement the controller may receive data from one or more sensors, such as on-board sensors. In some examples ejection may be provided autonomously by the deployment tool, for example in accordance with depth, sensed parameters or the like. Alternatively, or additionally, the command signal may be communicated from a remote location, for example from surface.

Depending on the requirement, the deployable component may be ejected towards a high side of the wellbore, a low side of the wellbore, or another pre-determined orientation between these two.

The method may comprise deploying a first component on one side of the wellbore, for example a high side, and a second component on a different side of the wellbore bore, for example a low side. In this arrangement the first and second components may comprise different tracer constituents. This arrangement may permit an understanding to be derived concerning the composition of a multiphase flow within the wellbore, for example to detect oil flowing on the high side and/or water flowing on the low side.

The deployment tool may comprise an ejection mechanism for ejecting a deployable component. The ejection mechanism may ensure that on ejection the deployable component comes within close proximity to a wall of the wellbore at a desired orientation.

The ejection mechanism may comprise a spring mechanism, such as a mechanical spring, gas spring or the like. The ejection mechanism may comprise a pre-energised, for example compressed, spring mechanism.

The ejection mechanism may comprise a releasable latch arranged to be activated to permit actuation of the spring mechanism. The releasable latch may comprise a magnetic latch. The magnetic latch may be released by energizing an electromagnet associated with the magnetic latch. The releasable latch may comprise a solenoid.

The ejection mechanism may comprise a damping arrangement configured to suppress, limit and/or control ejection velocity of the deployable component. The damping arrangement may comprise a grease filled damper. In one example a spring mechanism may be energised, for example compressed, by injecting grease into the damper system.

The deployment tool may be deployable through reduced diameter sections of the wellbore. In one example the deployment tool may be deployable through an ESP bypass tube. The deployment tool may define a diameter of less than, for example 100mm, less than 75mm, less than 50mm or less than 25mm. In one example the deployment tool may define a diameter of around 43 mm (around 1 -1 1/16"). The deployment tool may be modular. Such an arrangement may allow several deployment components/modules to be added as required.

The method may comprise deploying more than one tracer simultaneously. The method may comprise testing the attachment of the deployable component within the wellbore, for example to determine if a suitable attachment or strength has been achieved. Such attachment testing may be provided by the deployment tool. The attachment test may be by direct pull off the pipe. The attachment test may be by shear in a desired direction, for example in an axial direction within the wellbore and/or in a circumferential direction within the wellbore.

The method may comprise preparing, for example cleaning, an attachment surface within the wellbore prior to attachment of a deployable component. The method may comprise preparing a wellbore attachment surface using a cleaning tool. The cleaning tool may be run prior to running of a deployment tool which carries the deployable component. Alternatively, the cleaning tool may be run simultaneously with a deployment tool. The cleaning tool may be run coupled to the deployment tool.

The cleaning tool may be an integral part of the deployment tool.

The cleaning tool may comprise brushes, scrapers, magnets, chemicals and/or the like. The method may comprise detecting a deployable component. In one example the method may comprise detecting a deployable component following deployment, for example following becoming secured, within a wellbore. Detecting a deployable component may be used to confirm appropriate deployment of the deployable component within the wellbore.

The deployable component may comprise a detectable identifier. In examples where multiple deployable components are provided at least two deployable components may comprise different detectable identifiers. Such an arrangement may facilitate at least two deployable components to be uniquely identifiable.

A detectable identifier may comprise a magnetic identifier. The magnetic identifier may comprise a defined arrangement of magnetic poles.

A detectable identifier may comprise a coded RFID chip.

The method may comprise detecting a deployable component using a detection tool. The detection tool may be operable to detect or read a detectable identifier of a deployable component.

The detection tool may be configured to identify a detectable identifier of a deployable component and correlates this with measured depth.

The detection tool may be deployable separately from a deployment tool. The detection tool may be deployable simultaneously with a deployment tool. The detection tool may be coupled to the deployment tool. The detection tool may be integral with the deployment tool. Such an arrangement may permit a "Deploy and Confirm" functionality to be provided.

In some embodiments a deploy and confirm log may be read and stored at a remote location, for example at surface, in real time. The method may comprise running multiple deployable components into a wellbore to provide back-up or redundancy. This may permit deployment of a back-up deployable component in the event that a "Confirm" detection cannot not registered. The method may comprise catching deployable components, for example deployable components that failed to sufficiently be attached or secured within the wellbore. The method may comprise catching deployable components in a catching arrangement, such as a basket, for example a "junk basket". The method may comprise identifying deployable components which have been caught in the catching arrangement. In one embodiment the catching arrangement may be capable of identifying caught deployable components.

The catching arrangement may be magnetic.

The method may comprise removing a deployable component from the wellbore.

The method may comprise removing a deployable component using a removal tool. The removal tool may be run independently. The removal tool may be run in combination with or as part of another tool, such as with a deployment tool, detecting tool, catching arrangement and/or the like.

In some examples the removal tool may comprise detection capabilities and/or be run with a detection tool. This may permit the removal tool to remove a desired or target deployable component.

The method may comprise scraping a deployable component from a wellbore component. A removed deployable component may be retained in a catching arrangement.

In some examples the method may comprise removing the deployable component by degaussing a magnet which originally secures the deployable component within a wellbore. The method may comprise magnetically removing a deployable component. For example, the method may comprise using a magnet or magnets on a removal tool to magnetically track a deployable component. The method may comprise crushing, shattering or otherwise physically compromising (e.g., by machining such as milling) a magnet used to secure a deployable component within a wellbore.

The method may comprise confirming the removed deployable component is captured, for example within a catching arrangement.

The method may comprise seeking to detect a deployable component which was secured at a known location. Absence of any detection may sufficiently confirm removal.

The method may comprise detecting and removing one or more discrete deployable components within a set of deployable components.

A deployment, removal and detection tool may all be run simultaneously, allowing deployable components to be removed, replaced and confirmed in a single run.

The capability of being able to replace spent deployable components with fresh ones allows the use of short life tracer constituents, higher trace concentrations, optimisation of release rates and the like. This may be of particular importance in wells where extended life monitoring is required.

An aspect of the present disclosure relates to a method for use in monitoring or detecting a downhole parameter and/or condition, comprising:

deploying a component comprising a tracer constituent into a completion pre- installed within a wellbore; and

securing the component at a location within the completion.

An aspect of the present disclosure relates to a downhole tool comprising:

a tool body;

a deployable component releasably mounted on the tool body; and a releasing arrangement for releasing the deployable component.

An aspect of the present disclosure relates to a downhole deployable component to be deployed within a pre-installed completion in a wellbore, wherein the deployable component comprise a tracer constituent.

An aspect of the present disclosure relates to a deployment tool for use in deploying a deployable component within a wellbore, wherein the deployment tool comprises an ejecting arrangement for ejecting a deployable component therefrom.

An aspect of the present disclosure relates to a downhole tool comprising a deployment tool for deploying a deployable component within a wellbore.

The downhole tool may comprise a catching arrangement.

The downhole tool may comprise a cleaning tool for cleaning or preparing a surface of a wellbore component prior to attachment of a deployable component.

The downhole tool may comprise a detection tool for detecting a deployable component.

The downhole tool may comprise a removal tool for removing a deployable component.

An aspect of the present disclosure relates to a method for deploying a deployable component within a wellbore, comprising running the deployable component into a wellbore, and magnetically securing the deployable component within the wellbore.

An aspect of the present disclosure relates to a deployable component to be deployed into a wellbore, wherein the deployable component comprises a securing arrangement for permitting the deployable component to be secured to a portion of a wellbore.

The securing arrangement may facilitate station keeping of the deployable component within the wellbore. The securing arrangement may comprise a magnetic securing arrangement, such that the deployable component may be magnetically secured within the wellbore, for example magnetically secured to a metallic surface within the wellbore. Such a metallic surface may comprise a surface of a tubular member.

An aspect of the present disclosure relates to an apparatus comprising at least one magnet for magnetically securing the apparatus within a wellbore.

Although some aspects and examples presented above relate to the deployment within or association with wellbores, other aspects and embodiments may relate to deployment within or association with any tubular structure, such as a pipeline or the like.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other aspects of the present disclosure will now be described, by way of example only, with reference to the accompanying drawings, in which:

Figures 1A and 1 B are perspective views, from above and below, respectively, of a deployable component in accordance with an example of the present disclosure;

Figures 2A to 2C are diagrammatic illustrations of the sequential operation of a deployment tool in accordance with an example of the present disclosure, in deploying a deployable component within a wellbore;

Figures 3A to 3C are diagrammatic illustrations of the sequential operation of a deployment tool in accordance with an alternative example of the present disclosure, in deploying a deployable component within a wellbore; Figures 4A to 4C are diagrammatic illustrations of the sequential operation of a deployment tool in accordance with an alternative example of the present disclosure, in deploying a deployable component within a wellbore; and Figures 5A to 5C are diagrammatic illustrations of the sequential operation of a deployment tool in accordance with an alternative example of the present disclosure, in deploying a deployable component within a wellbore. DETAILED DESCRIPTION OF THE DRAWINGS

A perspective view, from above and below respectively, of a deployable component 10 is illustrated in Figures 1A and 1 B. In the present example the deployable component 10 is for use within a wellbore associated with the oil and gas exploration and extraction industry.

The deployable component 10 is generally elongate in form and is to be deployed and located within a wellbore. The deployable component 10 comprises or is formed from a tracer constituent which is released following contact with a trigger fluid within the wellbore, such as oil and/or water. The tracer constituent, once released, may be entrained with the trigger fluid and flowed to a remote location, such as a surface location where it is detected. Such detection and optionally subsequent analysis of the tracer constituent may permit one or more parameters associated with the wellbore to be derived, such as identification and/or allocation of flows in the wellbore.

The tracer constituent may be released upon break-up, dissolving or the like of the deployable component 10.

The deployable component 10 may be termed a "tracer stick".

The tracer constituent may comprise one or more tracer chemicals provided by Resman AS and/or Tracerco Limited.

In the example illustrated a plurality of permanent pot magnets 12 are embedded in the underside of the deployable component 10, as illustrated in Figure 1A. In a modified example the magnets may be exposed from both the upper and lower sides of the deployable component 10, and further additional magnets may be provided along one or both sides and/or one or both ends of the deployable component 10. As will be described in more detail below the magnets 12 facilitate magnetic attachment of the deployable component 10 to a metallic feature within a wellbore, for example an inner surface of a wellbore tubular.

Reference is now made to Figure 2A which is a diagrammatic illustration of a deployment tool 20 in accordance with an example of the present disclosure. The deployment tool 20 may be used to deploy any type of deployable component, but in the present example is for use in deploying the deployable component 10 first shown in Figure 1A. The deployment tool 20 is arranged to be run into a wellbore tubular 22 on an elongate medium 24, which may be wireline, e-line, slickline, coiled tubing or the like. In the illustrated example the deployment tool 20 is run into a deviated or horizontal section of a wellbore tubular 22. The deployment tool 20 is located on a lower side of the wellbore, however, in alternative embodiments a centraliser may be provided such that the tool 20 may be run more centrally within the wellbore tubular 22, as desired.

The deployment tool 20 includes a pocket 26 which receives a deployable component 10, wherein the pocket 26 includes an exit opening 28 arranged on a lower or leading end 30 of the deployment tool 20. It will be recognised that the lower end 30 of the tool 20 is that end which is further from an entry point (not shown) of the wellbore tubular 22.

The deployment tool 20 includes a control module 31 which functions to activate the deployment tool 20 to eject the deployable component 10 when appropriate.

The deployment tool 20 includes an ejection mechanism 32 which includes a compression spring 34. In the arrangement of Figure 2A the compression spring 34 is compressed and thus energised, and held in this configuration via a latch 36. In the embodiment shown the ejection mechanism also includes a damping arrangement 38.

When the deployment tool 10 is at the required depth an actuation signal may be initiated to release the latch 36 of the ejection mechanism 32. This signal may be initiated in a number of ways. For example, a signal may be transmitted from surface via the elongate medium, 24, which may comprise an electrical conductor, fibre optic or the like. Upon receipt of the surface initiated signal the control module 31 may provide a control function to release the latch 36 and allow the spring 34 to extend and eject the deployable component 10, as illustrated in Figure 2B, with the damping arrangement 38 restricting the exit velocity. The actuation signal may be initiated in alternative ways. For example, the actuation signal may be initiated directly within the control module 31 in response to one or more recognised conditions. For example, the control module 31 may comprise a timer, such that the deployment component 10 is ejected after a pre-determined lapse of time. Additionally, or alternatively, the control module 31 may comprise or be in communication with one or more sensors (such as temperature sensors, pressure sensors, accelerometers etc.) such that the component 10 is ejected in response to one or more sensed conditions. For example, ejection may be initiated when a predetermined depth is achieved, when a predetermined pressure and/or temperature is detected, when the control module 31 recognises that the deployment tool 20 has been stationary for a predetermined period of time, when the control module 31 recognises that the deployment tool 20 has been moved in a predetermined sequence of movements (e.g., up/down movements) and/or the like

Once ejected, the deployable component 10 becomes magnetically secured to the inner surface of the wellbore tubular 22, as illustrated in Figure 2C. In this specific example the deployable component 10 is magnetically secured to the lower side of the wellbore tubular 22. The deployment tool 20 may then be retrieved and/or moved to a different location/orientation to deploy a further deployable component. A deployment tool 120 in accordance with an alternative example of the present disclosure is shown in Figure 3A, again shown run into a wellbore tubular 22 on an elongate medium 24. The deployment tool 120 presently illustrated is very similar to the tool 20 first shown in Figure 2A, and as such like components share like reference numerals, incremented by 100. Accordingly, the deployment tool 120 includes a pocket 126 for receiving a deployable component 10, an exit port 128, and ejection mechanism 132 and a control module 131 .

In the deployment tool 20 of Figure 2A the deployable component 10 is ejected generally along a central axis of the tool 20. However, in the present example the ejection mechanism 132, pocket 126 and exit opening 128 are obliquely aligned relative to the central axis of the tool 120, such that the deployable component 10 may be ejected along a desired trajectory, and ultimately towards a desired side of the wellbore tubular 22. In the present example the deployment tool 120 is oriented such that the deployable component 10 is ejected towards the high side to the tubular 22, as illustrated in Figure 3B, with the deployable component 10 thus becoming magnetically secured to the high side to the tubular 22 as shown in Figure 3C.

A further alternative example of a deployment tool 220 is diagrammatically illustrated in Figure 4A. The deployment tool 220 is similar to the deployment tool 20 first shown in Figure 2A and as such like features share like reference numerals, incremented by 200.

The deployment tool 220 is run into a wellbore tubular 22 on an elongate medium 24. The tool 220 includes a pocket 226 for receiving a deployable component 10, and a side exit opening 228. The tool 220 further includes an ejection mechanism 232 which includes a screw jack arrangement having a leadscrew 40 and a three-arm linkage assembly 42 having a pair of outer lifting arms 42a, 42b and a central arm 42c intermediate the lifting arms 42c. The outer lifting arms 42a, 42b are engaged with the leadscrew 40 via respective screw followers 44a, 44b. It will be understood that the leadscrew 40 has opposing directed thread portions, wherein each thread portion engages a respective follower 44a, 44b. The deployable component 10 is initially mounted on the central arm 42c.

Upon receipt or generation of a control signal an on-board control module 231 provides a control function to operate the leadscrew 40 of the ejection mechanism 42, thus causing the three-arm linkage assembly 42 to extend and move the deployable component 10 towards the inner surface of the wellbore tubular 22, as illustrated in Figure 4B. The deployable component may thus become magnetically secured within the tubular 22, with the three-arm linkage 42 again retracted by reverse operation of the leadscrew, as illustrated in Figure 4C, allowing the deployment tool 220 to be retrieved or moved to a different location or orientation to deploy a further deployable component.

A further alternative example of a deployment tool 320 is diagrammatically illustrated in Figure 5A. The deployment tool 320 is similar to the deployment tool 20 first shown in Figure 2A and as such like features share like reference numerals, incremented by 300.

The deployment tool 320 is run into a wellbore tubular 22 on an elongate medium 24. The tool 320 includes a pocket 326 for receiving a deployable component 10, and a side exit opening 328. The tool 320 further includes an ejection mechanism 332 which includes a compression spring 334 and a latch 336. In the configuration shown in Figure 5A the compressions spring 334 is compressed and energised, and held in this state by the latch 336.

The ejection mechanism 332 further includes a three-arm linkage assembly 50 having a pair of lever arms 50a, 50b which pivot about respective pivot or fulcrum points 52a, 52b. The three-arm linkage assembly 50 further includes a central arm 50c intermediate the lever arms 50a, 50b, wherein the deployable component 10 is initially mounted on the central arm 50c.

The ejection mechanism 332 further includes a rod member 54 and a pair of axially spaced engagement plates 56a, 56b fixed to the rod member 54, wherein each engagement plate 56a, 56b engages a lower end of the respective lever arms 50a, 50b.

Upon receipt or generation of a control signal an on-board control module 331 provides a control function to release the latch 336, thus causing spring 334 to extend and cause the lever arms 50a, 50b to pivot, extending the three-arm linkage assembly 50 and moving the deployable component 10 towards the inner surface of the wellbore tubular 22, as illustrated in Figure 5B. The deployable component 10 may thus become magnetically secured within the tubular 22.

Once the deployable component 10 has been deployed, the deployment tool 320 may be retrieved as illustrated in Figure 5C. The three-arm linkage assembly 50 may remain extended during retrieval of the deployment tool 320, with the spring 334 simply permitting the assembly 50 to kick-down upon engagement with any obstruction.

In some or all of the examples described above an operator may wish to deploy the deployable component in a desired orientation. For example, in the examples described the components are deployed in either the lower or high sides of the wellbore tubular. In some instances the deployment tool may include an orienting arrangement, to provide appropriate orientation of the deployment tool and thus desired placement of the deployable component. For example, the deployment tool may comprise an eccentrically weighted mandrel mounted in bearings. The mandrel may thus be gravity biased to rotate to the low side (with its centre of gravity as low as possible). Thus orientation may then provide a datum point from which the remaining features of the tool (for example an exit pocket) are oriented. It should be understood that the examples described are indeed merely exemplary and that various modifications may be made thereto without departing from the scope of the present disclosure.

While the above examples are presented as deploying a deployable component which includes a tracer constituent, any other component may be deployed and magnetically secured downhole.

Further, although the deployable components are illustrated as being deployed in wellbores, the same techniques may be used to deploy components within other tubular structures such as pipelines.

Also, while the examples described above illustrate the deployable component as being in solid or stick-form, the deployable component may be in the form of a container, wherein the tracer constituent is carried within the container. The tracer constituent may be releasable from the container.




 
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