Trimming attachment tool and method

Abstract

A tool (234) for conditioning an inner surface in a wellbore (202) includes a jacket (238) configured to be mounted on an outer surface of a body (236). The jacket (238) includes a proximal end and a distal end, and further includes two or more portions that are detachable from each other. One or more fiber optic cables (248) extend to the distal end of the jacket and generate an annular laser beam (250) for trimming the inner surface in the wellbore (202). An associated method includes: mounting a jacket (238) on an outer surface of a body (236), where the jacket (238) includes two or more portions that are mutually detachable; extending one or more fiber optic cables (248) to a distal end of the jacket (238); deploying the body (236) and the jacket (238) into the wellbore (202); generating an annular laser beam (250) via one or more fiber optic cables (248); and trimming the inner surface in the wellbore (202) via the annular laser beam (250).

Description

Background Technology

[0001] In hydrocarbon recovery, a common problem is that tools can get stuck in the wellbore due to the presence of foreign objects and uneven surfaces. This can happen in both open-hole and cased wells and can be caused by irregular drilling, cavitation, or geomechanical issues.

[0002] Traditionally, mechanical dressing tools can be lowered into the wellbore to smooth one or more inner surfaces of casing or uncased wells, allowing virtually any tool or instrument to be run downhole without obstruction. However, this dressing process can be significantly inefficient and can be very costly due to the time and resources required, especially when ongoing operations may need to be interrupted. Summary of the Invention

[0003] This summary is provided to introduce a series of concepts that will be further described in the following detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to help limit the scope of the claimed subject matter.

[0004] In one aspect, embodiments disclosed in this specification relate to a tool for trimming the inner surface of a wellbore. The tool includes a clip configured to be mounted on the outer surface of a body. The clip includes a proximal end and a distal end, and further includes two or more mutually detachable portions. One or more fiber optic cables extend to the distal end of the clip and generate an annular laser beam for trimming the inner surface of the wellbore.

[0005] In one aspect, embodiments disclosed in this specification relate to a method comprising: mounting a jacket on an outer surface of a body, the jacket including a proximal end and a distal end, wherein the jacket includes two or more mutually detachable portions; extending one or more optical fiber cables to the distal end of the jacket; deploying the body and the jacket into a wellbore; generating a ring laser beam via the one or more optical fiber cables; and trimming an inner surface in the wellbore via the ring laser beam.

[0006] Other aspects and advantages of the claimed subject matter will become apparent from the following description and the appended claims. Attached Figure Description

[0007] Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying drawings. For consistency, similar elements in the drawings are indicated by similar reference numerals.

[0008] Figure 1 A well site with a drilling rig and wellbore is schematically shown in a cross-sectional elevation view according to one or more embodiments.

[0009] Figure 2 A wellbore with dressing tools arranged according to one or more embodiments is schematically shown in an isometric view.

[0010] Figure 3A and Figure 3B The laser trimming jacket is schematically shown in both the assembled and disassembled configurations in isometric views.

[0011] Figure 4 A flowchart of a method according to one or more embodiments is shown.

[0012] Figure 5 A computing device and related components according to one or more embodiments are schematically illustrated. Detailed Implementation

[0013] Numerous specific details are set forth in the following detailed description of embodiments of the present disclosure in order to provide a more thorough understanding of the disclosure. However, it will be apparent to those skilled in the art that the disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

[0014] Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as adjectives for elements (i.e., any noun in this application). Unless explicitly disclosed, such as by using the terms “before,” “after,” “single,” and other such terms, the use of ordinal numbers does not imply or create any particular order of elements, nor does it limit any element to a single element. Rather, the use of ordinal numbers is for the purpose of distinguishing between elements. As an example, a first element is distinct from a second element, and a first element may contain more than one element and be listed after (or before) the second element in the order of elements.

[0015] According to one or more embodiments, this specification generally envisions a dressing tool comprising a downhole tool body with an outer sleeve on the downhole tool body. The dressing tool may also house optical fibers to perform actual dressing or cutting via a high-power laser, wherein a ring beam can be generated below the tool. By using a high-power laser to dress and remove obstructing material in the wellbore, and with precise control via optical fibers, a smoother and more symmetrical wellbore can be achieved compared to conventional mechanical equipment. The outer sleeve itself can be sized or customized to reliably fit different downhole tools.

[0016] Now turn to the attached diagram for easier description. Figures 1 to 5 It is easier to refer to at that time, in the instructions Figures 1 to 5 When referring to similar or analogous parts or elements, the reference numerals may be increased in multiples of 100.

[0017] Figure 1 A well site with a drilling rig and wellbore, according to one or more embodiments, is schematically illustrated in a cross-sectional elevation view. Thus, Figure 1 A non-limiting example of well site 100 is shown. Well site 100 is described as being on land. In other examples, well site 100 may be offshore, and drilling may be carried out with or without a marine riser. Drilling operations at well site 100 may include drilling a wellbore 102 into a subsurface formation including various formations 126. Well site 100 may include more than one wellbore 102, but only one wellbore 102 is shown for illustrative purposes. To drill a new section into the wellbore 102, a drill string 112 is suspended within the wellbore 102. The drill string 112 may include one or more drill pipes connected to form a guide pipe and a bottom drill assembly (BHA) 124 disposed at the distal end of the guide pipe. BHA 124 may include a drill bit 128 to cut into the subsurface rock. BHA 124 may include measuring tools, such as measurement-while-drilling (MWD) tools or logging-while-drilling (LWD) tools (not shown), and other drilling tools not specifically shown but which will be understood by those skilled in the art.

[0018] Furthermore, the drill string 112 can be suspended in the wellbore 102 via the derrick structure 101. A top hoist 106 can be mounted on top of the derrick structure 101. A traveling block 108 can be suspended from the top hoist 106 via a cable or drill rope 103. One end of the drill rope 103 can be connected to a winch 104, which is a winding device for adjusting the length of the drill rope 103, allowing the traveling block 108 to move up or down along the derrick structure 101. The traveling block 108 may include a hook 109 on which a top drive 110 is supported. The top drive 110 is coupled to the top of the drill string 112 and is operable to rotate the drill string 112. Alternatively, the drill string 112 can be rotated via a rotary table (not shown) on the surface 114. Drilling fluid (commonly referred to as mud) can be pumped into the drill string 112 from the mud system 130. Mud can flow into the drill string 112 through the appropriate flow channel in the top drive 110, or, if a rotary table (not shown) is used, through a rotating tap.

[0019] Furthermore, as is typical according to one or more embodiments, and during drilling operations at well site 100, the drill string 112 rotates relative to the wellbore 102, and weight is applied to the drill bit 128 so that the drill bit 128 can break the rock as the drill string 112 rotates. In some cases, the drill bit 128 can be rotated independently using a drilling motor. Typically, a combination of a drilling motor and a top drive 110 (or, if a rotary table is used instead of a top drive, a rotary tap) can also be used to rotate the drill string 112, thereby rotating the drill bit 128. When cutting rock with the drill bit 128, drilling fluid or "mud" (not shown) is pumped into the drill string 112. The mud flows downward along the drill string 112 and is discharged through nozzles in the drill bit 128 to the bottom of the wellbore 102. The mud in the wellbore 102 then flows upward back to the surface 114 in the annular space between the drill string 112 and the wellbore 102, thereby carrying entrained drill cuttings to the surface 114. The mud containing drill cuttings is returned to the mud system 130 for recirculation back into the drill string 112. Typically, drill cuttings are removed from the mud before it is pumped back into the drill string 112, and the mud is reprocessed as needed.

[0020] continue Figure 1 Drilling is complete once the drill string 112, BHA 124, and drill bit 128 are removed from the wellbore 102. In some embodiments of the wellbore 102 construction, casing production can begin. A casing string 116, consisting of one or more larger-diameter fittings, is lowered into the wellbore 102 along with the drill string 112. The casing string 116 typically isolates the inner diameter of the wellbore 102 from the adjacent formation 126. Once in place, the casing string 116 is secured, and cement is typically pumped down through the internal space of the casing string 116, exiting from the bottom of the casing shoe 120 and entering the annular space between the outer diameter of the wellbore 102 and the outer diameter of the casing string 116. This secures the casing string 116 in place and creates the desired isolation between the wellbore 102 and the formation 126. At this point, drilling can begin on the next section of wellbore 102.

[0021] Figure 2 A wellbore with dressing tools arranged according to one or more embodiments is schematically shown in an isometric view. As shown, wellbore 202 is depicted as a lateral wellbore in formation 226 (e.g., sandstone), but it should be understood that dressing tools can be used in virtually any type of wellbore.

[0022] As shown in the figure, and according to one or more embodiments, the dressing tool 234 may include a tool body 236 and a laser dressing sleeve 238 disposed on the outer surface of the distal end of the body 236. As shown, the tool 234 may be deployed independently into the wellbore, or may be attached to, for example... Figure 1 124 in the text represents BHA or part of the formation of BHA.

[0023] According to one or more embodiments, the body 236 includes one or more latching devices 240 disposed on its outer surface; two such latching devices 240 are in Figure 2 The tools 234 are shown in the diagram and are axially spaced from each other. The latching device 240 can function to lock onto the inner surface of the wellbore 202 or casing, thereby securing the tool 234 at a predetermined axial position within the wellbore 202. Furthermore, a centralizer 242 can be provided to radially center the tool 234 within the wellbore 202. Here, the centralizer 242 is arranged axially adjacent to the proximal end of the laser dressing jacket 238, but can essentially be arranged along the tool 234 at any suitable axial position.

[0024] According to one or more embodiments, although various implementations are possible, the latching device 240 can essentially comprise any suitable mechanical means capable of expanding or extending and then locking or securing to the inner surface of the wellbore 202 or casing. For example, the latching device 240 may each comprise a pad or plate having a high coefficient of friction with the inner surface of the wellbore 202 or casing, and mounted on an arm typically extending radially outward from the laser dressing jacket 238 to contact the pad or plate with the inner surface of the wellbore 202 or casing. The centralizer 242, in itself, can be implemented as is commonly known in the field of hydrocarbon recovery for centering the casing prior to cementing. Thus, by way of exemplary and non-limiting example only, the centralizer 242 may include a hinged collar and a bow spring, which, through mutual contact between one or more elements of the centralizer 242 and the inner surface of the wellbore 202 or casing, ensures that the laser dressing jacket is radially centered within the wellbore 202.

[0025] According to one or more embodiments, the high-power laser source 244 can be located on the ground, for example, on a truck as shown. During operation, once the tool 234 is locked and centered within the wellbore 202, the laser energy generated by the source 244 can be routed via control unit 246 and transmitted to the tool 234 and dressing sleeve 238 via one or more fiber optic cables 248. Before the tool 234 is deployed downhole, the dressing sleeve 238 is mounted (e.g., secured or clamped) to the tool body 236 and then acts to generate a ring laser beam 250. The control unit 246, in itself, can be implemented via a physical location (e.g., a small building or other structure) containing one or more automated or manual mechanisms for controlling the access of laser energy through the fiber optic cables 248 and for controlling one or more other mechanisms described herein. Therefore, the control unit 246 can include one or more computers housed therein or located remotely (e.g., refer to...). Figure 5 The computer 582 described and shown communicates with one or more processors or user interfaces.

[0026] According to one or more embodiments, virtually any suitable laser source 244 can be used for the present purpose. By way of exemplary and non-limiting example, the vehicle-mounted laser source 244 can have a maximum power of 10.2 kW, while each fiber optic cable 248 can have a core diameter of approximately 300 micrometers. The beam generated by the light source 244 and transmitted by the cable 248 can be pumped by a multimode diode, having a beam parameter product (BPP) of approximately 14 mm × mrad and a wavelength of approximately 1070 nm.

[0027] Therefore, according to one or more embodiments, the beam 250 can be projected forward of the distal end of the tool 234, thereby allowing removal of irregularities 252 located on uneven surfaces or on such surfaces within the wellbore 202, along the downhole direction. The beam 250 can be set to any predetermined diameter relative to the wellbore 202, as desired for the current task. If the tool 234 then moves further downhole, the beam 250 continues to eliminate irregularities from the inner surface of the wellbore or casing, thereby continuing to produce a finished (or “smoothed”) hole 254.

[0028] According to one or more embodiments, in one possible operating mode, the beam 250 can be controlled to translate a given distance downhole even when the tool 234 is fixed and centered within the borehole. In another possible operating mode, the beam 250 can be controlled to remain in a fixed axial position relative to the tool 234 while the entire tool 234 is deployed downhole at a predetermined rate. Therefore, the two operating modes can operate individually or together to achieve relative translational displacement of the beam 250 relative to the borehole 202 at one or more different rates as needed. The relevant control can be implemented at or via a control unit 246, which may itself contain or communicate with a computer, for example... Figure 5 The computer shown in Figure 582.

[0029] According to one or more embodiments, Figure 3A and Figure 3B The laser trimming sleeve 238 is schematically shown in both the assembled and disassembled configurations in isometric views. Refer to these two figures for further details.

[0030] According to one or more embodiments, the laser trimming jacket 238 may be formed of two or more partial tubular portions. Thus, in this working example, two semi-tubular portions 256a and 256b are shown. Each partial tubular portion 256a / b may include a set of magnets 258 embedded at each of the two circumferential ends of each partial tubular portion 256a / b. The magnets 258 thus interact to facilitate the fixation of the two or more partial tubular portions 256a / b to each other to form the complete tubular shape of the laser trimming jacket 238. Alternatives such as clips or straps may be used instead of magnets 258, or in addition to magnets 258.

[0031] According to one or more embodiments, such as Figure 3B As shown, one or more fiber optic cables 248 can enter through the proximal end (upper end) of the jacket 238 and then, as shown, branch into multiple branch cables 260 traveling toward the distal end (lower end) of the jacket. Each branch cable 260 extends to a corresponding end 261 from which a separate laser beam is projected. Although three branch cables 260 are shown, it should be understood that they can be installed or configured in virtually any suitable number and arrangement to form a ring laser beam 250. The branch cables 260 can each be guided via one or more suitable apertures to a position corresponding to the end 261 on the outer surface of the jacket 238, or each end 261 can be embedded in the jacket 238 and exposed at the ring end face of the jacket 238. Although Figure 3B Not specifically shown, but the annular connector element can be fixed to the annular end face of the jacket 238 to receive the ends 261 of the branch cables 260, and the annular connector element can be configured to emit a separate beam of light from each end 261, thereby forming an annular beam 250. The number of branch cables 260 can be appropriately selected according to the actual application, but it should generally be understood that the number originating from the light source 244 (see [reference]) is also important. Figure 2 A higher power beam may mean fewer branch cables 260 are needed, while a lower power original beam may require a higher number of branch cables 260.

[0032] According to one or more embodiments, one or more temperature sensors 262 may be provided to measure the temperature of the dressing tool (see...). Figure 2 (234 in the text) and the current temperature at one or more locations within the wellbore. Therefore, when in the wellbore or tool (e.g., in...) Figure 2 When one or more temperatures (exceeding predetermined thresholds) are sensed within the jacket 238 or body 236 shown, a suitable feedback and shutdown mechanism can be employed to deactivate the laser beam. This feedback and shutdown mechanism can be integrated into the control unit 246, which may itself contain a computer or be connected to a computer, for example... Figure 5The computer shown in 582. Communication between one or more temperature sensors 262 and control unit 246 can be achieved via a wired or wireless connection.

[0033] According to one or more embodiments, one or more acoustic cameras 264 may be configured to capture and transmit visual images from the remote end (downhole end) of the tool to visualize downhole “targets” or other objects or obstacles, and to aid in tracking distance and speed as the tool moves downhole. Communication between the one or more acoustic cameras 264 and the control unit 246 may be achieved via a wired or wireless connection.

[0034] According to one or more embodiments, the one or more temperature sensors 262 and the one or more acoustic cameras 264 can be mounted in substantially any suitable location. In the illustrated working example, one sensor 262 and one camera 264 are mounted on the outer surface of the distal end of the laser trimming jacket 238.

[0035] Figure 4 A flowchart of the method is shown as a general overview of the steps that can be performed according to one or more embodiments described or contemplated in this disclosure. Specifically, Figure 4 A method for finishing the inner surface of a wellbore is described. Figure 4 One or more boxes in the middle can be used as follows Figure 1 To Figure 3 and Figure 5 It is performed by one or more components as described herein. Although Figure 4 The boxes in the document are presented and described in sequence, but those skilled in the art will understand that some or all of these boxes may be executed in a different order, may be combined or omitted, and may be executed in parallel. Furthermore, these boxes may be executed actively or passively.

[0036] Therefore, according to one or more embodiments, a sleeve is mounted on the outer surface of the body, the sleeve including a proximal end and a distal end, wherein the sleeve includes two or more mutually detachable portions (step 465). As an illustrative example, this may correspond to reference... Figures 2 to 3B The jacket 238, portions 25a / b, and body 236 are described and shown. One or more fiber optic cables are extended to the distal end of the jacket (step 467). As an illustrative example, this may correspond to the reference. Figure 2 and Figure 3B One or more cables 248 and branch cables 260 are described and illustrated. The body and jacket are deployed into the wellbore (step 469). A ring laser beam is generated via the one or more fiber optic cables (step 471), and the inner surface of the wellbore is trimmed via the ring laser beam (step 473). As an exemplary example, references can be used. Figures 2 to 3BThe process is described and illustrated to help understand these steps.

[0037] Figure 5 A computing device and related components according to one or more embodiments are schematically illustrated. Therefore, Figure 5 A block diagram of a computer system 582 for providing computing functions according to one or more embodiments is generally depicted, the computing functions being associated with algorithms, methods, functions, processes, flows, and programs as described in this disclosure. In this respect, the computer 582 can be connected locally or remotely to one or more components of a control unit (e.g., referred to in [reference]) via an internal or external network 594. Figure 2 Component 246 described and shown communicates.

[0038] According to one or more embodiments, the computer 582 shown is intended to cover any computing device, such as a server, desktop computer, laptop / notebook computer, wireless data port, smartphone, personal data assistant (PDA), tablet computing device, one or more processors within these devices, or any other suitable processing device, including physical or virtual instances (or both) of the computing device. Additionally, computer 582 may include a computer comprising: an input device, such as a keypad, keyboard, touchscreen, or other device capable of accepting user information; and an output device for transmitting information associated with the operation of computer 582, including digital data, visual or audio information (or a combination of information); or a GUI.

[0039] Computer 582 may function as a client, network component, server, database, or other persistent device, or any other component (or combination of roles) in a computer system for performing the subjects described in this disclosure. The illustrated computer 582 is communicatively coupled to network 594. In some embodiments, one or more components of computer 582 may be configured to operate within an environment including a cloud-based environment, a local environment, a global environment, or other environments (or combinations thereof).

[0040] At a higher level, computer 582 is an electronic computing device capable of receiving, transmitting, processing, storing, or managing data and information associated with the described subject. According to some embodiments, computer 582 may also include, or be communicatively coupled to, application servers, email servers, web servers, cache servers, streaming media data servers, business intelligence (BI) servers, or other servers (or combinations thereof).

[0041] Computer 582 may receive requests from client applications (e.g., executing on another computer 582) via network 594 and respond to the requests by processing the received requests in a suitable software application. Additionally, requests may also be sent to computer 582 from internal users (e.g., from a command console or via other suitable access methods), external or third parties, other automated applications, and any other suitable entity, individual, system, or computer.

[0042] Each component of computer 582 can communicate using system bus 583. In some embodiments, any or all components (hardware or software, or a combination of hardware and software) of computer 582 can interact with each other or with interface 584 (or a combination of both) on system bus 583 using application programming interface (API) 592 or service layer 593 (or a combination of API 592 and service layer 593). API 592 may include descriptions of routines, data structures, and object classes. API 592 may be language-independent or language-dependent and refers to a complete interface, a single function, or even a set of APIs. Service layer 593 provides software services to computer 582 or other components (whether shown or not) communicatively coupled to computer 582. The functionality of computer 582 is accessible to all service consumers using the service layer. Software services (such as those provided by service layer 593) provide reusable, defined business functions through defined interfaces. For example, the interface may be software written in JAVA, C++, or another suitable language that provides data in Extensible Markup Language (XML) format or other suitable formats. Although shown as an integrated component of computer 582, alternative implementations may show API 592 or service layer 593 as a separate component relative to other components of computer 582 or communicatively coupled to computer 582 (whether shown or not). Furthermore, any part or all of API 592 or service layer 593 may be implemented as a submodule or sub-module of another software module, enterprise application, or hardware module without departing from the scope of this disclosure.

[0043] Computer 582 includes interface 584. Although in Figure 5While shown as a single interface 584, two or more interfaces 584 may be used depending on specific needs, expectations, or a particular implementation of computer 582. Interface 584 is used by computer 582 to communicate with other systems in a distributed environment connected to network 594. Generally, interface 584 includes logic coded in software or hardware (or a combination of software and hardware) and operable to communicate with network 594. More specifically, interface 584 may include software supporting one or more communication protocols associated with the communication, enabling the hardware of network 594 or the interface to operate to transmit physical signals both inside and outside the illustrated computer 582.

[0044] Computer 582 includes at least one computer processor 585. Although in Figure 5 The computer processor 585 is shown as a single computer processor 585, but two or more processors may be used depending on specific needs, expectations, or a particular implementation of the computer 582. Generally, the computer processor 585 executes instructions and manipulates data to perform the operations of the computer 582 and any algorithms, methods, functions, procedures, flows, and programs as described in this disclosure.

[0045] Computer 582 also includes memory 586, which stores data for computer 582 or other components (or a combination of both) that can be connected to network 594. For example, memory 586 may be a database storing data consistent with this disclosure. Although in Figure 5 The memory 586 is shown as a single memory 586, but two or more memories may be used depending on specific needs, expectations, or a particular embodiment of the computer 582 and the functions described. Although the memory 586 is shown as an integrated component of the computer 582, in alternative embodiments, the memory 586 may be external to the computer 582.

[0046] Application 587 is an algorithmic software engine that provides functionality (particularly with respect to the functionality described in this disclosure) for a specific need, expectation, or according to a specific implementation of computer 582. For example, application 587 can be used as one or more components, modules, applications, etc. Furthermore, although shown as a single application 587, application 587 can be implemented as multiple applications 587 on computer 582. Additionally, although shown as integrated with computer 582, in alternative embodiments, application 587 may be located external to computer 582.

[0047] Any number of computers 582 may exist, either associated with or outside the computer system containing computer 582, with each computer 582 communicating via network 594. Furthermore, the terms "client," "user," and other suitable sets of terms may be used interchangeably where appropriate without departing from the scope of this disclosure. Moreover, this disclosure envisions a plurality of users using one computer 582, or a single user using multiple computers 582.

[0048] Although only a few exemplary embodiments have been described in detail above, those skilled in the art will readily understand that many modifications can be made to the exemplary embodiments without substantially departing from the invention. Therefore, all such modifications are intended to be included within the scope of this disclosure as defined by the appended claims.

Claims

1. A tool for finishing the inner surface of a wellbore (102, 202), the tool (234) comprising: A sleeve (238) is configured to be mounted on the outer surface of the body (236), the sleeve (238) including a proximal end and a distal end; The jacket (238) comprises two or more mutually detachable parts; and One or more fiber optic cables (248) extend to the distal end of the jacket and generate an annular laser beam (250) for trimming the inner surface of the wellbore (102, 202).

2. The tool according to claim 1, wherein, The two or more mutually detachable parts include two or more tubular portions (256a, 256b).

3. The tool according to claim 2, wherein, The two or more partial tubular portions (256a, 256b) are two partial tubular portions.

4. The tool according to claim 2 or 3 further includes a magnet (258) for fixing the tubular portions to each other.

5. The tool according to claim 4, wherein: Each of the tubular portions (256a, 256b) includes two rounded end portions; and The magnet (258) is embedded at each of the two circumferential ends of each of the said partial tubular portions (256a, 256b).

6. The tool according to any one of claims 1 to 5, wherein, One or more fiber optic cables (248) extend from the laser source (244) to the proximal end of the jacket and split into multiple branch cables (260), which extend to the distal end of the jacket and project the annular laser beam (250) from the distal end of the jacket in a downhole direction.

7. The tool according to any one of claims 1 to 6 further includes a control unit (246) that, when the tool (234) is in a fixed position, controls the annular laser beam (250) to translate downhole from the distal end of the jacket.

8. The tool according to any one of claims 1 to 7 further includes one or more temperature sensors (262) mounted on the jacket (238).

9. The tool according to claim 8 further includes a control unit (246) that disables the annular laser beam (250) when the one or more temperature sensors (262) sense that the temperature in the tool (234) or the wellbore (102, 202) is higher than a predetermined threshold.

10. The tool according to any one of claims 1 to 9, further comprising one or more acoustic cameras (264) mounted on the clip (238).

11. The tool according to any one of claims 1 to 10, further comprising one or more latching devices (240) configured to lock onto the inner surface of the wellbore (102, 202).

12. The tool according to any one of claims 1 to 11 further includes a centralizer (242) configured to radially center the tool (234) within the wellbore (102, 202).

13. A method comprising: A sleeve (238) is mounted on the outer surface of the body (236), the sleeve including a proximal end and a distal end, wherein the sleeve (238) includes two or more mutually detachable parts; Extend one or more fiber optic cables (248) to the distal end of the jacket; The main body (236) and the jacket (238) are deployed into the wellbore (102, 202); A ring laser beam (250) is generated via one or more fiber optic cables (248); and The inner surface of the wellbore (102, 202) is trimmed via the annular laser beam (250).

14. The method according to claim 13, wherein, Installing the clip (238) involves attaching the two or more mutually detachable parts to each other.

15. The method according to claim 14, wherein, The two or more mutually detachable parts include two tubular portions (256a, 256b).

16. The method according to claim 14 or 15, wherein, The attachment includes securing the mutually detachable parts to each other via a magnet (258).

17. The method according to any one of claims 13 to 16, wherein, One or more fiber optic cables (248) extend from the laser source (244) to the proximal end of the jacket and split into multiple branch cables (260), which extend to the distal end of the jacket and project the annular laser beam (250) from the distal end of the jacket in a downhole direction.

18. The method according to any one of claims 13 to 17, further comprising controlling the annular laser beam (250) to translate downhole from the distal end of the jacket when the jacket (238) and the body (236) are in a fixed position in the wellbore (102, 202).

19. The method according to any one of claims 13 to 18, further comprising: One or more temperature sensors (262) are mounted on the jacket (238); and When one or more temperature sensors (262) detect that the temperature in the jacket (238), the body (236), or the wellbore (102, 202) is higher than a predetermined threshold, the annular laser beam (250) is deactivated.

20. The method according to any one of claims 13 to 19, further comprising mounting one or more acoustic cameras (264) on the jacket (238).

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