WELLBORE DEVICES AND METHODS

Abstract

A wellbore device and method for use in downhole operations are provided. The device may comprise a deployment member packaged in a first configuration arranged to be deployed from said first configuration upon deployment of the wellbore device within a wellbore. In some examples, a tool is also provided. The first disposable member may be made of a degradable material, and optionally may be a fibre optic for providing sensing and/or data communication. The tool may be a smart tool.

Claims

1.-33. (canceled)

34. A deployable device for deployment in a wellbore, the deployable device comprising: a deployable member comprising a fibre optic, the member being stored in a first configuration prior to deployment, and arranged to deploy to a second configuration during deployment, and wherein the deployable member is configured to permit distributed sensing using the deployed fibre optic when in the second configuration.

35. The deployable device of claim 34, wherein the first configuration is a wound configuration, and wherein at least some of the deployable member is stored in the first configuration in a particular manner so as to impart or assist with linear deployment of fibre optic in the second configuration.

36. The deployable device accordingly to claim 34, wherein the device is configured such that, when deployed to a second configuration, the deployable member provides one or more coiled portions of fibre optic in the wellbore.

37. The deployable device according to claim 36, wherein the device is configured such that the coiled portions of fibre optical are provided at one or more sections along the length of the deployable member.

38. The deployable device according to claim 36, wherein at least one of: (i) the deployable member is stored in the first configuration in a particular manner so as provide the coiled portion(s) of fibre optic when deployed in the second configuration, and (ii) the device is configured to retain some of the deployable member with the device, when in the second configuration, in order to provide the coiled portion of fibre optic.

39. The deployable device according to claim 34, wherein deployable member is stored in the first configuration as a winding such that the deployable member pays out from an inner surface of the winding, when deployed.

40. The deployable device according to claim 34, wherein the device is configured to permit controlled deployment of the device in a wellbore.

41. The deployable device according to claim 40, wherein the deployable member comprises two or more different coating characteristics, configured to provide controlled deployment of the device in a wellbore.

42. The deployable device according to claim 34, wherein the deployable member is configured to permit distributed acoustic sensing using the deployed fibre optic when in the second configuration.

43. The deployable device according to claim 34, further comprising a tool for deployment in the wellbore.

44. The deployable device according to claim 43, wherein at least one of: (i) the tool comprises a drift; and (ii) the tool comprises a drift having one or more sensors configured to measure well conditions, and wherein the sensors are configured to communicate sensed conditions using the fibre optic of the deployable member.

45. The deployable device according to claim 34, wherein the device is configured to be deployed in the wellbore in a non-permanent manner.

46. The deployable device according to claim 34, wherein the device is configured to be disposable in the wellbore.

47. The deployable device according to claim 34, wherein some or all of the deployable member comprises a reinforcing and/or protective coating surrounding the fibre optic.

48. The deployable member according to claim 47, wherein the coating comprising Kevlar.

49. A distributed sensing arrangement comprising a deployable device according to claim 34, and a fibre optic module for provide distributed sensing, wherein the fibre optic module is in operative communication with the fibre optic of the deployable member.

50. A method for deploying a fibre optic in a wellbore, comprising: storing a deployable member comprise a fibre optic in a first configuration with a deployable device, and deploying the deployable device to a second configuration in the wellbore so as to deploy the deployable member and fibre optic and to permit subsequent distributed sensing using the deployed fibre optic.

51. The method according to claim 50, wherein the method comprises storing a deployable member comprise a fibre optic in a first configuration in a particular manner so as to impart or assist with linear deployment of fibre optic in the second configuration.

52. The method according to claim 50, wherein the method comprises deploying the deployable member so as to provide one or more coiled portions of fibre optic in the wellbore.

53. The method according to claim 50 comprising at least one of: (i) performing distributed sensing using the deployed fibre optic; and (ii) performing distributed acoustic sensing using the deployed fibre optic.

54. The method according to claim 53 comprising disposing of the fibre optic in the wellbore subsequent to performing distributed sensing.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0190] These and other aspects of the present invention will now be described, by way of example only, with reference to the accompanying drawings, in which:

[0191] FIG. 1 is a simplified, diagrammatic, longitudinal cross-sectional view of a wellbore device comprising a fibre optic deployable member and a drift.

[0192] FIG. 1A is a simplified, diagrammatic cross-sectional view of a friction device.

[0193] FIG. 2 is a simplified diagrammatic illustration of the wellbore device of FIG. 1 deployed within a wellbore.

[0194] FIG. 3 is a simplified, diagrammatic, longitudinal cross-sectional view of a wellbore device comprising a fibre optic deployable member and a smart drift.

[0195] FIG. 4 is a simplified, diagrammatic, longitudinal cross-sectional view of a wellbore device comprising a deployable member and a smart drift with a retrievable electronics module.

[0196] FIGS. 5a to 5d show further examples of a deployable member being deployed;

[0197] FIGS. 6a and 6b show examples of a deployable device having elements;

[0198] FIGS. 7a and 7b show further examples of a deployable member being deployed;

[0199] FIGS. 8a, 8b and 8c show further examples of a deployable member being deployed using first and second device sections;

[0200] FIGS. 9a, 9b and 9c show further examples of a deployable member being deployed having different characteristics; and

[0201] FIG. 10 shows a further example of a deployable device

DETAILED DESCRIPTION OF DRAWINGS

[0202] FIG. 1 provides a simplified, diagrammatic, longitudinal, cross-sectional view of a wellbore device generally identified by reference numeral 10.

[0203] The wellbore device 10 comprises a frame or housing 12 comprising a container 14 mounted thereon. Within the container 14 is packaged in a first configuration a deployable member 17. In this example, the deployable member 17 comprises a fibre optic line. Here, the fibre optic may be provided as a bare fibre; that is a fibre without protective coating, or the like. In other examples described below, the fibre may indeed be provided with some form of coating. In any event, the fibre optic 17 is arranged to be deployed from this first configuration upon deployment of the wellbore device 10 within a wellbore (not shown).

[0204] The wellbore device 10 further comprises a tool 16 which in the embodiment disclosed is exemplified as a drift 16, and in particular a disposable drift. It will be appreciated when considering the following description that in some examples the device 10 need not comprise a tool per se, or any tool may be different from a drift 16, or may not be disposable. Here, however, for explanation the drift 16 is mounted to the frame 12 of the wellbore device 10. The drift 16 comprises a generally cylindrical housing 19 defining a hollow interior 20 and end plates 22 for closing the hollow interior. The hollow interior 20 may be filled with any suitable material, including a readily disposable material for adding weight as may be needed. Examples of suitable materials may include natural materials such as sand, rock and rock flour and/or artificial materials such as iron filings, liquid metal, dissolving plastic beads and the like generally indicated by the shading 21. At least one of the end plates 22 may be removably mountable to the housing 19 to allow ready opening of the drift 16 so that it may be filled with a suitable disposable material to add weight to the drift 16. Different materials may be used depending on the overall desired weight. The housing 19 and the end plates 22 may be made of a disposable material such as a low cost plastic material including but not limited to a polyolefin such as polypropylene and/or polyethylene. The housing 19 and the end plates may be made of a dissolvable material such as a dissolvable plastic material which may dissolve in water and/or oil. The selection of the precise plastic material may depend upon the conditions of the well including but not limited to the type of fluid contained in the well. Hence for example, if the well contains water then a water soluble material may be used for the housing 19 and/or the end plates 22 of the drift 16. If the well contains hydrocarbons then an oil soluble material may be used for the housing 19 and/or the end plates 22 of the drift 16. Other well conditions such as the temperature and acidity of the fluid in the well may be considered in selecting a suitable dissolvable material.

[0205] It should be also understood, that although the drift 16 is shown in the embodiment of FIG. 1 having a hollow cylindrical shape filled with a weight material, that other shapes and configurations may be employed. For example, the drift 16 may be made of a solid cylinder made of a dissolvable material, or the drift 16 may be made of a solid cylinder made of an outer housing made of a slower tougher dissolvable material and an inner core made of a faster dissolvable material. Many other variations may be envisioned by a skilled person in this art after having read the present disclosure.

[0206] For example, although, the wellbore device 10 as shown in FIG. 1 is equipped with a fibre optic line, it should be understood that other types of deployable members 17 may be used. For example, the deployment member 17 may comprise one or more lines made from Vectran and/or Kevlar fibres, monofilament polymer, steel, copper, glass fibre or any other material that can be formed into a wire, thread, line or braid. Further, in some cases, the deployable member 17 may include a first line providing data and/or signal communication and a second line for providing adequate mechanical support for the wellbore device. The deployable member 17 may also be spooled around a bobbin or spool, or the like.

[0207] Various materials and or techniques may be used to control deployment or unintentional unwinding of the deployable member 17. For example, a wax, varnish, lacquer, grease or any other material with semi sticky properties may be applied on the loaded deployable member 17 to keep the deployable member 17 from deploying unintentionally. Also, for example, a friction device 30 may be operably connected close to the launch point to provide a friction force to prevent unintentional unwinding of the deployable member 17.

[0208] An example of a friction device 30 is shown in FIG. 1A. Friction device 30 comprises first and second through bores 32 and 33. Deployable member 17 is passed through bore 33. Co-operating magnets 31a and 31b (and in this example two magnets) are slidably contained within bore 32 so that they can slide and press against the deployment member 17 because of the attractive force between them. By adjusting the strength of the magnets 31a, 31b the friction applied on the deployable member 17 and/or the rate of deployment of the deployable member 17 may be controlled. The device 30 may further comprise means for securing it to the container 14 or some other fixed part of the wellbore device 10 (not shown). Although in the embodiment of FIG. 1A the magnets 31a, 31b are applied directly on the deployable member 17, it should be understood that a pad of a suitable material may also be used between the magnets 31a, 31b and the deployable member 17. While in this example, the friction device 30 has been principally described using magnetics, it will be appreciated that in other examples other friction devices 30 may be used that are otherwise configured to impede or restrict free deployment of the member 17. In some examples, any friction device 30 may co-operate with selective coatings or the like of the member so as to provide a desired effect.

[0209] The deployable member 17 may include an electrical and/or a fibre optic component to provide support for example for control, power and/or data communication as may be needed.

[0210] According to one example, the deployment member 17 may be made from a material that degrades or dissolves in the presence of wellbore fluids.

[0211] The deployment member 17 may exhibit a sufficiently high strength, thermal stability and low stretch or deformation for supporting the weight of the wellbore device 10 under the wellbore ambient temperature conditions. The deployable member 17 may exhibit a sufficiently high strength, thermal stability and low stretch or deformation for supporting the self-weight of the deployable member 17 when it is fully unspooled and suspended in a well under the wellbore ambient temperature conditions. The deployable member 17 may exhibit a sufficiently high strength, thermal stability and low stretch or deformation for supporting the flow induced forces caused by the fluid flow around and along the deployable member 17 suspended in the well as injection and/or fracturing fluids are pumped into the well.

[0212] Referring now to FIG. 2, an application of the wellbore device 10 will be described. The wellbore device 10 may be introduced within a wellbore 11. Tubular 28 is a diagrammatic simplified illustration of a wellhead region and comprises a device 24 such as a lubricator or stuffing box 24 for entering the wellbore device 10 inside the well head. Device 24 may also be a ball or dart launcher, a deployment head or any other suitable device for entering the wellbore device 10 inside the well head.

[0213] By way of an example, a first end 17a of the deployable member 17 is anchored through the lubricator 24 by a fibre optic feed through connector and is connected to a surface module 26. The other end is located in the container. The surface module 26 may be a laser range finder such as an OTDR used to measure the total length of the fibre optic by looking for light reflection from the deployed fibre optic line 17. The range finder may additionally or alternatively analyse backscatter along the length of the fibre. The point 18 at which the fibre optic transitions from being packaged (under bending stress) to being unpackaged (bending stress removed), also referred to as the launch point, may give a unique signature backscatter fingerprint. This in turn may feed into a calculation for determining an instantaneous depth and/or speed of the drift 16 as it is being deployed within the wellbore 11. The fibre optic line 17 may extend through a stress inducer element (not shown) as it is being deployed so that the induced stress may be more readily detected by the optical equipment at the surface.

[0214] The wellbore device 10 as shown in FIG. 2 may be deployed within the wellbore via gravity, however, it should be understood that other methods of deployment may be employed such as, for example, via fluid pumping or a combination thereof. Fluid pumping may be employed, for example, in deviated or horizontal wellbores. Of course, in some examples, a tractor may be used in order to assist with deployment of the member 17 in the wellbore 11.

[0215] The drift 16 may confirm clear passage to a given depth for other tools such as intervention tools that may follow. As the wellbore device 10 is being deployed into the well the fibre optic 17 is also be deployed. Using well-known optical range finding methods, an instantaneous depth and/or speed of the drift may be calculated and displayed real time at the surface.

[0216] If the well is successfully drifted the drift 16 may then be disposed within the well, for example at or near the bottom of the well where it may present little or no concern to the operations. The drift 16 may dissolve/degrade over time eliminating any concerns of having a drift at the bottom of the well.

[0217] An obstruction in the well may be indicated by the drift 16 becoming lodged in the tubing 11, for example, this may be indicated at the surface as a zero speed reading. A stuck drift that is not retrieved would typically cause an obvious blockage problem, however the present invention drift may dissolve/degrade therefore reducing and/or eliminating any blockage issues. The drift material may be selected taking into consideration the well conditions, for example, whether the well contains water, or oil, the well temperature, pressure, acidity and the like. On completion of the drift run the fibre optic 17 may be retrieved back to the surface through stuffing box 24.

[0218] Alternatively, if a disposable fibre optic line 17 is used, the fibre optic may be released and allowed to remain in the well. Such fibres that are configured to remain in the well may have applicability in relation to distributed sensing (as is further described below). In some embodiments the fibre optic may degrade over time. However, for example, when provided a relatively simply fibre (e.g. a bare fibre) such degradation may only occur after a time that the fibre 17 has been used to perform sensing. It may be that is some cases, the deployed fibre (and any associated tools or other components) is only expected to be operable for a day or less, such as 12 hours, or less, or even 6 hours or less. In other words, the device 10 may be constructed in such a manner that the survivability of the fibre, device, etc. beyond a fairly short time frame is not expected. In such a way, the device 10 can be constructed at reduced cost compared to a permanent installation.

[0219] In this case, the wellbore device 10 may be employed to drift and log the wellbore at the same time. Accordingly, a first region such as first end 17a of the fibre optic line 17 may be operably connected to a fibre optic surface module 26 comprising a light source and an interrogator. In such a way, the deployable member 17 may be usable for the purposes of distributed sensing. Suitable fibre optic modules may be used including DTS, DPS, and/or DAS modules all being commercially available from a number of suppliers. For example if a DTS module is used, the temperature of the fibre optic at all locations along its length may be measured from the surface. In some examples, no downhole electronics may be needed. Moreover, the temperature profile of the well may be logged either during deployment or during retrieval of the fibre optic.

[0220] A wellbore device 110 according to another embodiment is diagrammatically illustrated in FIG. 3. The embodiment of FIG. 3 has many features in common with the embodiment shown in FIGS. 1 and 2 and for ease of reference we will refer to similar features using the same numerals we used for the embodiment of FIG. 1 augmented by 100. Accordingly, the wellbore device 110 comprises a frame 112 comprising a container 114 within which there is packaged in a first configuration a fibre optic line 117. The fibre optic line 117 is arranged to be deployed from this configuration upon deployment of the device 110 within a wellbore (not shown).

[0221] The wellbore device 110 further comprises a smart drift 150 which is mounted to the frame 112 of the wellbore device. The smart drift 150 comprises a generally cylindrical housing 119 defining a hollow interior 120 and end plates 122 and 123 for closing the hollow interior. The hollow interior 120 may be filled with any suitable readily disposable material. Examples may include natural materials such as sand, rock, rock flour, and/or artificial materials such as iron filings, liquid metal, dissolving plastic beads and the like for adding weight as may be needed. At least one of the end plates 122 may be removably mounted to the housing 119 to allow ready opening of the smart drift 150 and filling it with a suitable disposable material.

[0222] The smart drift 150 further comprises an electronics module 152. The electronics module 152 may be protected within a heat shield arrangement 153 comprising a housing 154 and a phase change material (PCM) 156 filling a hollow space 155 defined between housing 154 and the electronics module 152. End plate 123 may be removably mounted to the housing 154 to allow filling the hollow space 155 within PCM material. End plate 123 may also serve as the upper end plate for defining the hollow interior 120 of the drift housing 119 which is filled with a disposable material 121. The electronics module 152 may be operably connected with one end 117b of the fibre optic via an opening 154a of the housing 154. The other end of the fibre optic 117 (not shown) may be connected to a surface module (not shown) in a similar manner to the embodiment described above with reference to FIG. 2. The housing 154 may be positioned within an upper portion 120a of the hollow interior 120 defined by the housing 118 of the drift 150.

[0223] The electronics module 152 may comprise or be coupled to one or more sensors as may be needed. For example, sensors may include, for example, a pressure sensor, a temperature sensor, a CCL sensor, a gamma ray sensor, an ultrasonic wall thickness sensor, a calliper gauge, a cement bond sensor and the like. Other sensors may also be used. The data gathered may be signalled or transmitted to the surface via the fibre optic 217.

[0224] The heat shield arrangement 153 may be advantageous because it may enable the use of low cost readily available consumer electronic components, and batteries. Moreover, because of the disposable nature of the wellbore device 10, the heat shield may be designed to provide adequate protection to the consumer electronics and battery for the rather short time of deployment of the wellbore tool. Typically, this may not exceed 1 hour of operation in the wellbore, and more typically may not exceed 30 minutes or 10 minutes. Any suitable PCM which can absorb an adequate amount of energy without a significant change in the temperature of the PCM may be used. According to an example, a PCM material may be or comprise wax. Any suitable wax may be used. According to an embodiment a wax having a melting point in the range of from about 40 to about 60 degrees Celsius may be used. The wax may be a petroleum based wax such as a paraffinic wax.

[0225] Data collected by the one or more sensors of the electronics module 152 may be transmitted via the fibre optic line 117 to a surface module. Any suitable method of transmitting the data via a fibre optic line may be used.

[0226] In this way all the bulk of the hardware may be kept at the surface instead of in the tool.

[0227] Any well-known method of transmitting data via a fibre optic may be used including digital and analogue methods.

[0228] According to a further example, collected data may be transmitted as an analogue signal by varying the amplitude of a light source, e.g. an LED as a function of a sensor output. This technique may be advantageous because of its simplicity and because it may be used for a number of applications. For example, this technique may be used in a method for detecting casing collars with a CCL wherein the actual value of the CCL output does not matter but rather it is the shape of the wave form that may be used to determine the location of collars. For example a spike in the wave form may indicate the existence of a collar.

[0229] The housing 154 of the electronics module and the end plate 123 may be made of a degradable material which may degrade when exposed in wellbore conditions, for example they may be made or comprise an effective amount of a dissolvable plastic material which may dissolve in water and/or oil. The selection of the precise plastic material may depend upon the conditions of the well including but not limited to the type of fluid contained in the well. So for example, if the well contains water then a water soluble material may be used for the housing 154. If the well contains hydrocarbons then an oil soluble material may be used for the housing 154. Other well conditions such as the temperature and acidity of the fluid contained in the well may be considered in selecting a suitable dissolvable material for the housing 154 and the end plate 123.

[0230] Referring now to FIG. 4, a wellbore device 210 is provided according to yet another example. Wellbore device 210 has many features in common with the wellbore device 110 of FIG. 3 and for simplicity similar features are denoted using the same numerals as for the embodiment of FIG. 3 augmented by 100. Accordingly, the wellbore device 210 comprises a deployable member 217 connected at one end thereof 217a to a retrievable electronic module 260. The retrievable electronic module 260 is operably connected to the electronics module 252 of a smart drift 250 via one or more electronic terminal connectors and/or wires 262 so that during deployment of the wellbore device 210 inside the wellbore (not shown) data collected by sensors of the electronics module 252 may be stored into a memory housed within the retrievable electronic module 260. The retrievable electronic module 260 may be in the form of an insert adapted to be removably insertable to a corresponding mating receptacle 254a formed at the top of the housing 254 of the electronics module 252. The retrievable electronic module 260 may be removed and retrieved to the surface upon full deployment of the wellbore device 210 via the deployment member 217 using a reeling mechanism at the surface (not shown). Any suitable reeling mechanism may be used.

[0231] The deployment member 217 may be any suitable deployment member, including but not limited to a fibre optic line.

[0232] The deployable member 217 may be or comprise a line made from Vectran and/or Kevlar fibres, monofilament polymer, steel, copper, glass fibre or any other material that can be formed into a wire, thread, line or braid and may be spooled around a bobbin or spool 270.

[0233] According to one example, the deployment member 217 may comprise a Kevlar line and may not transmit data in real time to the surface. Alternatively, the deployment member 217 may be or comprise a smart line such as an electrical line or a fibre optic capable of transmitting data and/or signals in a single or two way communications between a surface module (not shown) and the retrievable electronic module 260. Upon full deployment of the wellbore device 210, the wellbore device including the frame 212, the spool 270 and the whole smart drift 250 including the electronics module 252, sensors and battery may fall to the bottom of the well and be permitted to dissolve or degrade.

[0234] The electronics module 252 of the smart drift is positioned within a heat shield arrangement 253 comprising a housing 254 and a PCM at an upper part of the cavity 220a formed by the housing 219 of the smart drift 250 as described above in reference to the embodiment of FIG. 3.

[0235] The smart drift 250 may further comprise sensors 274 positioned outside of the heat shield protection. The sensors 274 may be wired back to the electronics module 252 via one or more wires 272 and a connector 273. Sensors 274 may have a higher operating temperature and hence may not need to be within the heat shield arrangement 253 that protects the electronics of the electronics module 252. Sensors 274 may be any suitable sensors. Sensors 274 may be, for example, sensing coils forming part of a casing collar locator (CCL) device. Sensors 274 may be a temperature and/or pressure sensor.

[0236] In some examples, one or more image sensors may be used with the device in any of the described examples. In some cases, such a device may be deployed in an optical pill. An example of an optical pill may have suitable visibility for the image sensors in the wellbore in order to image the wellbore wall (e.g. for inspection purposes).

[0237] FIGS. 5a-5d show a further example of a wellbore device 300 for deployment (and being deployed) in a wellbore 311. Again, the wellbore device 310 may have some or all features in common with the examples described above, as will be appreciated.

[0238] In the examples above, the wellbore devices 10, 110, 210 may be initially introduced or deployed from a lubricator, stuffing box or the like. Here, as shown in dashed lines in FIG. 5a, the device 310 may be provided together with housing 370, e.g. in a preassembled manner, for coupling with the lubricator or the like. In such a way, the housing 370 comprising the deployable device 310 may be considered may be easily connectable to the lubricator or the like, without the need to couple a deployable member 317 to the lubricator. Also, characterisation of the device 310 (e.g. the deployable member 317) may be performed prior to installation.

[0239] When ready, the device 310 may be deployed from an open or openable end of the housing 370 in order to be deployed in the wellbore 311.

[0240] Again, the deployable member 317 here is stored together with the deployable device 310, which is fixed at a region of the housing 370. In this example, a feed-through or connector 375 may be provided in order to allow the deployable member 317 to be connected to surface module (e.g. for signal and/or power communication). In some examples, a portion of the deployable member 317 may be reinforced at the connection region. In one example, a portion of reinforcing sheath is provided at the connection region, and may extend for some of the deployable member 317. In doing so, accidental detachment of the fibre from within the housing may be avoided.

[0241] The deployable member 317 again may be stored with the wellbore device 300, and be configured to deploy as the device 310 is deployed in the wellbore 311. Here, as shown in FIG. 5a, the deployable member 317 may be stored in a first configuration 318. Here, that first configuration 318 may be considered to be a bundled or wound configuration. Similarly, when deployed, the deployable member 317 may adopt a second configuration, which may be considered unwound or linear configuration. In some examples, the deployable member 317 may be wound around a spool or the like, within the deployable device 310, and configured to deploy therefrom. However, in other examplesas is the case herethe deployable member 317 can be considered to be stored as a layered winding without an inner spool (e.g. in a similar manner to that shown in FIGS. 1-3) and to pay out from the inner of the wound configuration. Storing the deployable member 317 in this manner may help provide a reduced profile for a similar length of stored deployable member 317.

[0242] In one example, in order to provide the deployable member 317 in this manner, the deployable member 317 may be initially wound around a support structure. In other words, a first inner layer may be wound around a support structure, and subsequent layers of member 317 being wound on top of those initially-laid inner layers. Subsequently the support structure may be removed so as to remain, in place, the first configuration 318. In some examples, a collapsible/retrievable support structure may be used, or otherwise a dissolvable/flowable structure may be used. It will be appreciated that depending on the forces used when laying down the member 317, residual stresses may be apparent in the wound configuration 318, which may assist in holding the windings together, even without a support structure present.

[0243] In this particular example, the deployable member 317 comprises a fibre optic line, or the like, suitable for distributed sensing. While in many examples, a fibre without coating may be employed for the deployable member 317which can help reduce weight, costs, and/or improve the length of fibre that can be stored within a certain volumein other cases a coating may be provided. Such a coating may help provide a cushioning effect against overlapping windings, and so improve robustness and reduce likelihood of fracture. By way of an example, the bare fibre may be in the order of 25 ?m or less, while with the coating it may be in the order of 325 ?m or less. Further, in some examples, the fibre (bare or otherwise) may be stored in grease, or the like, again which may help improve robustness. In some cases, the provision of grease, when deployed, may help adhere the deployable member 317 to the bore wall.

[0244] In other examples, the device 310 and in particular the deployable member may comprise a plurality of retaining elements provided along some or all the length of the member 317. Such retaining elements may be specifically configured to fix the deployable member to the wellbore. The retaining elements may comprise magnets, or other fixing means.

[0245] It will be appreciated that in certain circumstances the step of initially winding the deployable member 317 may impart on the deployable member 317 a characteristic twist or otherwise helical characteristic to the deployable member 317 when deployed from the device 310. However, in situations where the deployable member 317 may be used for distributed sensing, such characteristics may be unhelpful and may reduce the overall depth that the fibre is provided. Further, accurate relative positioning of Bragg gratings or the like together with regions of interest in the wellbore 311 may be difficult. As such, there may in some cases be a desire to avoid any such twisted or helical characteristics when the fibre 317 is being deployed.

[0246] One method that may mitigate such characteristics, or at least improve the linear deployment of the member 317, may be to impart a counter rotation of the deployable device 310 during deployment. This may be achieved using rotational elements at the deployable device 310 that interact with fluid in the well (e.g. during deployment). Consider now FIGS. 6a and 6b, which show examples of such elements 360a, 360b, which may be used to provide impart a counter rotation at the device 310. While other elements may be used, here the elements 360a are provided as fins or ribs that extend from the surface of the device 310.

[0247] Of course, additionally or alternatively, the deployable member 317 may be initially wound such that, when deployed, the member 317 is deployed linearly without twisted or helical characteristics. In order to achieve this, the member 317 may be pre-twisted when initially layered in the wound configuration 318. Put in similar words, the step of winding the member 317 may include imparting a rotation of the member 317 as the member 317 is being wound on the support structure, or the like. The extent of the rotation (or pre-twist) may be selected based on the geometry of the wound configuration 318. One way in which to store the fibre in a wound configuration having characteristics that assist with a linear second configuration may be spool or wind the fibre initially (e.g. onto a support structure) at an angle different from the angle at which the fibre is unwound from the first configuration to the second configuration. For example, the winding angle may be obliquely orientated with respect to the axis of the overall fibre winding.

[0248] Consider now FIG. 5b which shows the deployable member 310 having been deployed in the wellbore 311. Here, an essentially linear deployable member 317 has been deployed. In this case, twisted or helical characteristics may have been mitigated or avoided using the elements 360a, 360b and/or the initial pre-twist at the wound configuration. It will be appreciated that the term linear here, or in other words the absence of a helical twist, would also be true if shown in deviated wells.

[0249] Of course, in some examples an essentially linear distributed sensor (e.g. distributed acoustic, temperature and/or pressure sensor) may be helpful, but in other cases, retaining portions of the deployed member with a twist or helical arrangement, e.g. a coiled portion 319, may help improve the capabilities of the sensor at a region of interest. It will be appreciated that in some examples, due to the improved resolution/sensitivity, the coiled portion 319 may be used essentially as a point sensor. Further still, in some examples the distributed sensed signal from the remainder of the fibre may be of little or no importance compared to the coiled portion, which may be positioned at a region of interest within the wellbore.

[0250] Consider now FIGS. 5c and 5d in which a portion of the deployed member 317 comprises coiled portions 319. Here, the coiled portions 319 retain a wound characteristic (e.g. a helical characteristic). That wound characteristic may have been provided by the absence of a pre-twist, or indeed by a pre-twist in a complementary direction to the unwinding of the member 317. Similarly, the coiled portion 319 may be provided by a resilient coating or the like, configured to impart a particular structural form to the deployable member 319, when deployed.

[0251] In any event, the deployable device 310 may be configured such, when deployed, coiled portions 319 of the deployable member 310 are provided at regions of interest within the wellbore, such as regions of suspected leaks, or inlet ports, laterals, or the like. It will be appreciated that during distributed sensing, such as distributed acoustic sensing, that those coiled portions 319 may provide regions of greater data resolution or sensitivity, which may be helpful in accurately characterising sand production, well integrity (e.g. assessing leaks), flow allocation, or the like. It will be appreciated that the term coiled need not be limited to a wound coil of fibre, per se, but may be any relative bundle of fibre, of the like, which may provide improved sensor resolution/sensitivity compared to the other sections of the fibre.

[0252] It will be appreciated that in some examples, the deployable member 317 may be selectively initially wound and stored in the first configuration (e.g. with selective sections having a pre-twist) such that, when deployed in the second configuration, sections of the deployable member are essentially linear while others comprise a coiled portion 319, as will be understood.

[0253] While in FIGS. 5c and 5d, the coiled portion 319 is provided during deployment of the deployable member 317 from the deployable device 310, in other examples this need not be the case. For example, consider now FIGS. 7a and 7b. Here, the deployable member 317 is initially stored in the first configuration 318 (e.g. wound configuration) prior to deployment, as above. However, when deployed, a coiled portion 319 of the deployable member 317 (e.g. fibre optic) remains with the deployable device 310. For example, the coiled portion 319 may remain within the housing of the device 310. By way of an example, the outer most layer (or outer layers) of the wound deployable member 317 may be fixed in order to retain them in a wound configuration. It will be appreciated that a region of improved resolution may then be provided in a similar manner to that described in relation to FIGS. 5c and 5d.

[0254] In some examples, as is shown in FIGS. 8a, 8b and 8c, the deployable device 310 may comprise cascadable sections (e.g. first and second sections 310a, 310b as shown). In FIG. 8b, after the deployable member 317 has been deployed from the first section 310a, a deployable member 317 may then be deployed from the second section 310a. In each case, some of the deployable member 317 is retained within the sections as a coiled portion 319. A release mechanism may be used to cause separation of each section at a user defined time, or otherwise the second section 310b may be released after the first section has paid out, or vice versa.

[0255] In some examples, whether deploying the member 317 with coiled portions 319, or not, there may be a desire to control the rate of deployment, for example when it is expected to be passing regions of restricted passage in the wellbore 311. In such cases, and as is shown in FIGS. 9a, 9b and 9c, the deployable member may be provided with different coating characteristic at different portions of the deployable member 317.

[0256] Here, a first portion 317 of the deployable member has a first characteristic 317a, such as a first coating characteristic (or absence of a coating), while a second portion of the deployable member has a second characteristic 317b, such as a second coating characteristic (or absence of a coating). Here, the device 310 may comprise a restriction, or friction device the same as or similar to that shown in FIG. 1A. In use, different characteristics may be used to cause different deployment rates of the deployable device 310. In some examples, the deployable member 317, once deployed, may be used in a similar manner to that shown in FIG. 2 in as much as optical module can be located at surface, outside of the wellbore 311, and used to communicate signals (e.g. signals suitable for distributed sensing, such as distributed acoustic sensing) along the deployable member 317.

[0257] It will be appreciated that in the examples disclosed herein that a friction device 30 or restriction or the like may additionally or alternative be used to control deployment of the deployable member 317 when that deployable member 317 has been stored in the first configuration with some compression, or such stress, that would otherwise urge the deployable member, upon release, to pay out quickly and uncontrollably. In that regard the friction device may be largely passive, but yet still configured to control deployment of the member 317. A skilled reader will readily be able to implement such examples accordingly.

[0258] In some examples, the device 310 may be used to perform some action in the wellbore 311. It may be helpful if that action is performed at desired depth. Consider now FIG. 10 in which a further example of a deployable device 410 is shown. Here, optical equipment is located with the device 410 itself. A light source 480 is configured to communicate an optical signal into the deployable member 417. As above (see point 18 in FIG. 2), by way of measuring backscatter effects, the characteristic bend of the fibre as it changes from a wound configuration 419 to a linear configuration can be observable. As such, and by using range finding techniques, the length of fibre remaining in the device can be calculated or approximated (e.g. using a processor 482 and memory 484, configured in a known manner). When a desired depth has been reached an activation device 490 may be initiated. In some example, a friction device 495, or the like, may be used in order to provide an characteristic indication in the fibre optic when the fibre is being deployed from the device 410.

[0259] It will be appreciated the providing the light source, etc., together with the deployable device, rather than at surface, allows the device to be self-contained and complex set up, connections, or ancillary equipment may not be needed. This may result in ease of use and a reduced deployment time.

[0260] It will be appreciated that aspects of the above examples may lend themselves well to ease of deployment, ease of operation, as well as reducing costs and time, and/or improving sensing capabilities within a wellbore. In addition to collecting well data, further examples of when the above devices and methods may be used could be ease of monitoring of well conditions such as sand production, well integrity (e.g. assessing leaks), flow allocation, etc., or for use in offset seismic applications or the like. For example, during seismic surveying the deployable device may be deployed in one well and configured to sense vibrations or the like from another well.

[0261] It will further be appreciated that the above device may be deployed subsequent to previous installed completion or intervention procedures installing other sensors. Further, the device may be deployed in producing or previously producing well, or indeed injector wells. The well may have ceased production/injection (e.g. may be shut in) or may be flowing during deployment. Further, it may be the case that a pre-existing optical fibre is installed in the well, e.g. a part of the overall completion. A skilled reader will appreciate that the above described devices 10, 110, 210, 310 may be used in addition to that existing fibre, and each may be used in a calibration process or the like of the other fibre.

[0262] While the above examples have generally been described in relation to a deployable member comprising a fibre optic, it will be appreciated that in some examples a fibre optic bundle may be used. That is to say, in some examples the deployable member may comprise a plurality of fibre optics. In those examples, each of the fibres may be used for dedicated purposes (e.g. one for communicating data from a tool, and the other for performing distributed sensing). However, in other examples, each of the fibre optics may be used for the same purposes. In such examples, data from the plurality of fibres can be verified by comparison and/or a level of redundancy may be established.

[0263] The applicant hereby discloses in isolation each individual feature described herein and any combination of two or more such features, to the extent that such features or combinations are capable of being carried out based on the present specification as a whole in the light of the common general knowledge of a person skilled in the art, irrespective of whether such features or combinations of features solve any problems disclosed herein, and without limitation to the scope of the claims. The applicant indicates that aspects of the invention may consist of any such individual feature or combination of features. In view of the foregoing description it will be evident to a person skilled in the art that various modifications may be made within the scope of the invention.