Patent Publication Number: US-11041354-B2

Title: Wellbore plug and abandonment

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application also claims priority to and the benefit of U.S. Provisional Application No. 62/142,326, titled “WELLBORE PLUG AND ABANDONMENT METHOD,”, filed Apr. 2, 2015, the entire disclosure of which is hereby incorporated herein by reference. 
    
    
     BACKGROUND OF THE DISCLOSURE 
     The present disclosure is related in general to wellsite equipment, such as oilfield surface equipment, downhole assemblies, coiled tubing (CT) assemblies, slickline assemblies, and the like. The present disclosure is also related to the use of laser cutting equipment and sealing materials for repairing or sealing completion tubulars and other conduits located within a wellbore and/or for repairing or sealing portions of rock formation around the wellbore. 
     Wellbores are drilled from the Earth&#39;s surface and into a subterranean formation of interest in order to extract oil, gas, and/or other hydrocarbon materials. After a wellbore is completed with production tubing or the like, hydrocarbons from the formation are produced to the surface through the production tubing. A completed well may also be subjected to treatment and/or well intervention operations, such as to adjust and/or increase the rate of production of hydrocarbons to the surface. 
     At the end of the life of a wellbore, the wellbore may undergo a plug and abandonment (P&amp;A) operation, such as to isolate portions of the wellbore and/or the entire wellbore. P&amp;A operation may involve pulling production tubing from the wellbore and installing of one or more cement plugs to block fluid from the formation surrounding the wellbore from flowing into the wellbore. 
     P&amp;A operations conventionally utilize a full drilling rig (such as a drillship, a semi-submersible rig, a jackup rig, a submersible rig, or a land rig) with associated equipment to pull the production tubing and other completion equipment from the wellbore. Such rigs are utilized because they have a pulling capacity high enough to retrieve the production tubing and completion equipment from the wellbore. However, the rigs are expensive and time-consuming to operate, and occupy a large footprint at the wellsite surface. Such aspects are endured, however, as being unavoidable if the P&amp;A operation is to successfully secure and isolate hydrocarbons and wellbore fluids from migrating to surface from subterranean zones exposed during the well construction and operation processes. 
     SUMMARY OF THE DISCLOSURE 
     This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter. 
     The present disclosure introduces a method that includes conveying a downhole tool within a wellbore, the downhole tool including a laser cutting apparatus and a sealing material. The method also includes operating the laser cutting apparatus to remove material from at least one of a subterranean formation penetrated by the wellbore, a casing secured within the wellbore, and/or a cement sheath securing the casing within the wellbore. The method also includes placing the sealing material in a void created by the material removal. 
     The present disclosure also introduces an apparatus including a downhole tool for conveyance within a wellbore. The downhole tool includes a laser cutting apparatus operable to remove material from at least one of a subterranean formation penetrated by the wellbore, a casing secured within the wellbore, and/or a cement sheath securing the casing within the wellbore. The downhole tool also includes a sealing material and a heating device operable to melt the sealing material. 
     These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the materials herein and/or practicing the principles described herein. At least some aspects of the present disclosure may be achieved via means recited in the attached claims. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The present disclosure may be understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion. 
         FIG. 1  is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure. 
         FIG. 2  is a schematic sectional view of at least a portion of an example implementation of the apparatus shown in  FIG. 1  according to one or more aspects of the present disclosure. 
         FIG. 3  is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure. 
         FIGS. 4 and 5  are schematic sectional views of the apparatus shown in  FIG. 2  during different stages of operation according to one or more aspects of the present disclosure. 
         FIG. 6  is an axial view of the apparatus shown in  FIG. 5  according to one or more aspects of the present disclosure. 
         FIGS. 7-13  are schematic sectional views of the apparatus shown in  FIG. 2  during different stages of operation according to one or more aspects of the present disclosure. 
         FIG. 14  is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact. 
       FIG. 1  is a schematic view of at least a portion of an example wellsite system  100  according to one or more aspects of the present disclosure, representing an example coiled tubing environment in which one or more apparatus described herein may be implemented, including to perform one or more methods and/or processes also described herein. However, it is to be understood that aspects of the present disclosure are also applicable to implementations in which wireline, slickline, and/or other conveyance means are utilized instead of or in addition to coiled tubing. 
       FIG. 1  depicts a wellsite surface  105  upon which various wellsite equipment is disposed proximate a wellbore  120 .  FIG. 1  also depicts a sectional view of the Earth below the wellsite surface  105  containing the wellbore  120 , as well as a tool string  110  positioned within the wellbore  120 . The wellbore  120  has a sidewall  121  and extends from the wellsite surface  105  into one or more subterranean formations  130 . When utilized in cased-hole implementations, a cement sheath  124  may secure a casing  122  within the wellbore  120 . However, one or more aspects of the present disclosure are also applicable to open-hole implementations, in which the cement sheath  124  and the casing  122  have not yet been installed in the wellbore  120 . The wellbore  120  may further include a completion/production tubular  114 , which may be disposed within the casing  122 . 
     At the wellsite surface  105 , the wellsite system  100  may comprise a control and power center  180  (referred to hereinafter as a “control center”) comprising processing and communication equipment operable to send, receive, and process electrical and/or optical control signals to control at least some aspects of operations of the wellsite system  100 . The control center  180  may also provide electrical power and communicate the control signals via electrical conductors  181 ,  182 ,  183  extending between the control center  180  and a laser source  190 , a laser generator chiller  185 , and the tool string  110  positioned within the wellbore  120 . The laser source  190  may provide energy in the form of a laser beam to at least a portion of the tool string  110 . The laser source  190  may provide the laser beam to the tool string  110  via an optical conductor  191 , which may comprise one or more fiber optic cables. 
     The electrical conductor  181  may comprise a plurality of conduits or conduit portions interconnected in series and/or in parallel between the control center  180  and the tool string  110 . For example, as depicted in the example implementation of  FIG. 1 , the electrical conductor  181  may comprise a stationary portion extending between the control center  180  and a reel  160  of coiled tubing  161 , such that the stationary portion of the electrical conductor  181  remains substantially stationary with respect to the wellsite surface  105  during conveyance of the tool string  110 . The electrical conductor  181  further comprises a moving portion extending between the reel  160  and the tool string  110  via the coiled tubing  161 , including the coiled tubing  161  spooled on the reel  160 . Thus, the moving portion of the electrical conductor  181  may rotate and otherwise move with respect to the wellsite surface  105  during the conveyance of the tool string  110 . 
     Similarly, the optical conductor  191  may comprise a plurality of conduits or conduit portions interconnected in series and/or in parallel between the laser source  190  and the tool string  110 . For example, as depicted in the example implementation of  FIG. 1 , the optical conductor  191  may comprise a stationary portion extending between the laser source  190  and the reel  160  of the coiled tubing  161 , such that the stationary portion of the optical conductor  191  remains substantially stationary with respect to the wellsite surface  105  during the conveyance of the tool string  110 . The optical conductor  191  may further comprise a moving portion extending between the reel  160  and the tool string  110  via the coiled tubing  161 , including the coiled tubing  161  spooled on the reel  160 . Thus, the moving portion of the optical conductor  191  may rotate and otherwise move with respect to the wellsite surface  105  during the conveyance of the tool string  110 . A swivel or rotary joint  163 , such as may be known in the art as a collector, provides an interface between the stationary and moving portions of the electrical and optical conductors  181 ,  191 . 
     The wellsite system  100  may further comprise a fluid source  140  from which a fluid (referred to hereinafter as a “surface fluid”) may be communicated by a fluid conduit  141  to the reel  160  of the coiled tubing  161  and/or other conduits that may be deployed into the wellbore  120 . The fluid conduit  141  may be fluidly connected with the coiled tubing  161  by, for example, a swivel or another rotating coupling (obstructed from view). The coiled tubing  161  may be operable to communicate the surface fluid received from the fluid source  140  to the tool string  110  coupled at a downhole end of the coiled tubing  161 . 
     The coiled tubing  161  may be further operable to transmit or convey therein the moving portions of the optical and/or electrical conductors  181 ,  191  from the wellsite surface  105  to the tool string  110 . The electrical and optical conductors  181 ,  191  may be disposed within an internal passage of the coiled tubing  161  inside a protective metal carrier (not shown) to insulate and protect the conductors  181 ,  191  from the surface fluid inside the coiled tubing  161 . However, the optical and/or electrical conductors  181 ,  191  may also or instead be secured externally to the coiled tubing  161  or embedded within the structure of the coiled tubing  161 . The reel  160  may be rotationally supported on the wellsite surface  105  by a stationary base  164 , such that the reel  160  may be rotated to advance and retract the coiled tubing  161 , including the electrical and optical conductors  181 ,  191 , within the wellbore  120 , such as during the conveyance of the tool string  110  within the wellbore  120 . 
     The wellsite system  100  may further comprise a support structure  170 , such as may include a coiled tubing injector  171  and/or other apparatus operable to facilitate movement of the coiled tubing  161  in the wellbore  120 . Other support structures, such as a derrick, a crane, a mast, a tripod, and/or other structures, may also or instead be included. A diverter  172 , a blow-out preventer (BOP)  173 , and/or a fluid handling system  174  may also be included as part of the wellsite system  100 . For example, during deployment, the coiled tubing  161  may be passed from the injector  171 , through the diverter  172  and the BOP  173 , and into the wellbore  120 . 
     The tool string  110  may be conveyed along the wellbore  120  via the coiled tubing  161  in conjunction with the coiled tubing injector  171 , which may be operable to apply an adjustable uphole and downhole force to the coiled tubing  161  to advance and retract the tool string  110  within the wellbore  120 . Although  FIG. 1  depicts a coiled tubing injector  171 , it is to be understood that other means operable to advance and retract the tool string  110 , such as a crane, a winch, a draw-works, a top drive, and/or other lifting device coupled to the tool string  110  via the coiled tubing  161  and/or other conveyance means (e.g., wireline, drill pipe, production tubing, etc.), may also or instead be included as part of the well site system  100 . 
     During some downhole operations, the surface fluid may be conveyed through the coiled tubing  161  and caused to exit into the wellbore  120  adjacent to the tool string  110 . For example, in the open-hole implementation, the surface fluid may be directed into an annular area between the sidewall  121  of the wellbore  120  and the tool string  110  through one or more ports or nozzles (not shown) in the coiled tubing  161  and/or the tool string  110 . However, in the cased-hole implementation, the surface fluid may be directed into an annular area between an inner surface  123  and the tool string  110  through one or more ports or nozzles in the coiled tubing  161  and/or the tool string  110 . The inner surface  123  may be an inner surface of the casing  122  or an inner surface of the completion/production tubular  114 , if disposed within the casing  122 . Thereafter, the surface fluid and/or other fluids may return in the uphole direction and out of the wellbore  120 . The diverter  172  may direct the returning fluid to the fluid handling system  174  through one or more conduits  176 . The fluid handling system  174  may be operable to clean the returning fluid and/or prevent the returning fluid from escaping into the environment. The returned fluid may then be directed to the fluid source  140  or otherwise contained for later use, treatment, and/or disposal. 
     The tool string  110  may comprise one or more modules, sensors, and/or tools  112 , hereafter collectively referred to as the tools  112 . For example, one or more of the tools  112  may be or comprise at least a portion of a monitoring tool, an acoustic tool, a density tool, a drilling tool, an electromagnetic (EM) tool, a formation testing tool, a fluid sampling tool, a formation logging tool, a formation measurement tool, a gravity tool, a magnetic resonance tool, a neutron tool, a nuclear tool, a photoelectric factor tool, a porosity tool, a reservoir characterization tool, a resistivity tool, a seismic tool, a surveying tool, a tough logging condition (TLC) tool, a plug, and/or one or more perforating guns and/or other perforating tools, among other examples within the scope of the present disclosure. 
     One or more of the tools  112  may be or comprise a casing collar locator (CCL) operable to detect ends of casing collars by sensing a magnetic irregularity caused by the relatively high mass of an end of a collar of the casing  122 . One or more of the tools  112  may also or instead be or comprise a gamma ray (GR) tool that may be utilized for depth correlation. The CCL and/or GR tools may transmit signals in real-time to wellsite surface equipment, such as the control center  180 , via the electrical conductor  181  or another communication means. The CCL and/or GR tool signals may be utilized to determine the position of the tool string  110  and/or selected portions of the tool string  110 , such as with respect to known casing collar numbers and/or positions within the wellbore  120 . Therefore, the CCL and/or GR tools may be utilized to detect and/or log the location of the tool string  110  within the wellbore  120 , such as during downhole operations described below. 
     One or more of the tools  112  may also comprise one or more sensors  113 . The sensors  113  may include inclination and/or other orientation sensors, such as accelerometers, magnetometers, gyroscopic sensors, and/or other sensors for utilization in determining the orientation of the tool string  110  relative to the wellbore  120 . The sensors  113  may also or instead include sensors for utilization in determining petrophysical and/or geophysical parameters of a portion of the formation  130  along the wellbore  120 , such as for measuring and/or detecting one or more of pressure, temperature, strain, composition, and/or electrical resistivity, among other examples within the scope of the present disclosure. The sensors  113  may also or instead include fluid sensors for utilization in detecting the presence of fluid, a certain fluid, or a type of fluid within the tool string  110  or the wellbore  120 . The sensors  113  may also or instead include fluid sensors for utilization in measuring properties and/or determining composition of fluid sampled from the wellbore  120  and/or the formation  130 , such as spectrometers, fluorescence sensors, optical fluid analyzers, density sensors, viscosity sensors, pressure sensors, and/or temperature sensors, among other examples within the scope of the present disclosure. 
     The wellsite system  100  may also include a telemetry system comprising one or more downhole telemetry tools  115  (such as may be implemented as one or more of the tools  112 ) and/or a portion of the control center  180  to facilitate communication between the tool string  110  and the control center  180 . The telemetry system may be a wired electrical telemetry system and/or an optical telemetry system, among other examples. 
     The tool string  110  may also include a downhole tool  200  operable to repair tubular members downhole, such as the casing  122  and/or the completion/production tubular  114 , which may be disposed within the casing  122 . The downhole tool  200  may be further operable to repair a portion of the cement sheath  124  securing the casing  122  within the wellbore  120 . The downhole tool  200  may also be operable to repair a portion of the subterranean formation  130  surrounding or defining the wellbore  120  in both the cased-hole and open-hole implementations. For example, the downhole tool  200  may be operable to smooth out, patch, plug, or otherwise repair holes, perforations, scrapes, deformations, and other damaged portions along the sidewall  121  in an open-hole implementation and/or the inner surface  123  in a cased-hole implementation, including damage to the completion/production tubular  114 , the casing  122 , the cement sheath  124 , and/or the formation  130  surrounding the wellbore  120 . The downhole tool  200  may comprise a laser cutting apparatus operable to direct the laser beam upon the damaged portions along the sidewall  121  and/or the inner surface  123  to remove or cut the damaged portion by forming one or more radially extending cavities or slots (referred to hereinafter as “radial slots”) along the damaged portion. The radial slots (shown in and identified in  FIGS. 5-7  with numeral  286 ) may extend through or penetrate the completion/production tubular  114 , the casing  122 , the cement sheath  124 , and/or the formation  130  a predetermined depth. 
     Although  FIG. 1  shows the tool string  110 , including the downhole tool  200 , disposed within a vertical portion of the wellbore  120  to form the radial slots extending outwardly along a substantially horizontal plane, it is to be understood that the downhole tool  200  may also be utilized to form the radial slots in a horizontal or partially deviated portion of the wellbore  120 . Accordingly, the radial slots may also be formed along a plane extending substantially vertically or diagonally with respect to the wellsite surface  105 . 
     The tool string  110  is further shown in connection with the optical conductor  191  and the electrical conductor  181 , which may extend through at least a portion of the tool string  110 , including the downhole tool  200 . The optical conductor  191  may be operable to transmit the laser beam from the laser source  190  to the downhole tool  200 , whereas the electrical conductor  181  may be operable to transmit the electrical control signals and/or the electrical power between the control center  180  and the tool string  110 , including the downhole tool  200 . 
     The electrical conductor  181  may also permit electrical communication between the several portions of the tool string  110  and may comprise various electrical connectors and/or interfaces (not shown) for electrical connection with the several portions of the tool string  110 . Although the electrical conductor  181  is depicted in  FIG. 1  as a single continuous electrical conductor, the wellsite system  100  may comprise a plurality of electrical conductors (not shown) extending along the coiled tubing  161  and/or the tool string  110 . Also, although  FIG. 1  depicts the downhole tool  200  being coupled at a downhole end of the tool string  110 , the downhole tool  200  may be coupled between the tools  112 , or further uphole in the tool string  110  with respect to the tools  112 . The tool string  110  may also comprise more than one instance of the downhole tool  200 , as well as other apparatus not explicitly described herein. 
       FIG. 2  is schematic sectional view of at least a portion of an example implementation of the downhole tool  200  shown in  FIG. 1  according to one or more aspects of the present disclosure. The following description refers to  FIGS. 1 and 2 , collectively. 
     The downhole tool  200  comprises a laser cutting apparatus  202  operable to receive a laser beam  252  from the laser source  190  and direct the laser beam  252  upon the sidewall  121  of the wellbore  120  in the open-hole implementation or the inner surface  123  of the completion/production tubular  114  or the casing  122  in the cased-hole implementation to remove the damaged portion of the sidewall  121  or the inner surface  123  designated for repair. Accordingly, the laser cutting apparatus  202  may cut one or more radial slots along the damaged portion of the sidewall  121  or the inner surface  123 , such as may extend into or through the completion/production tubular  114 , the casing  122 , the cement sheath  124 , and/or the formation  130  around the wellbore  120 . 
     The laser cutting apparatus  202  includes a housing  210 , which defines an internal space  205  and a fluid pathway  214  within the downhole tool  200 . The housing  210  may comprise a lower housing  211  and an upper housing  212 . The upper housing  212  may couple the downhole tool  200  with one of the tools  112  of the tool string  110  and/or with the coiled tubing  161 , such as may facilitate communication of the surface fluid, the electrical power, the electrical signals, and/or the laser beam  252  to the downhole tool  200 . For example, the upper housing  212  may be operable to receive therein or couple with the coiled tubing  161 , such as to permit communication of the surface fluid from the fluid source  140  to the downhole tool  200 . The upper housing  212  may be further operable to receive therein the electrical conductor  181 , such as to permit communication of the electrical power and/or signals from the control center  180  to the downhole tool  200 . The upper housing  212  may also be operable to receive therein or couple with the optical conductor  191 , such as to facilitate transmission of the laser beam  252  from the laser source  190  to the downhole tool  200 . 
     The lower housing  211  may be rotationally coupled with the upper housing  212  in a manner permitting the lower housing  211  to rotate relative to the upper housing  212 , such as about an axis of rotation  251 , which may substantially coincide with a longitudinal central axis  203  of the downhole tool  200 . The lower housing  211  may be disposed at a downhole end of the downhole tool  200 , and may comprise a bowl-shaped or other configuration having an open end  217  and a closed end  216 . The open end  217  may be rotationally engaged or otherwise coupled with the upper housing  212 , such as to permit the above-described rotation of the lower housing  211  relative to the upper housing  212 . For example, the open end  217  of the lower housing  211  may be coupled with the upper housing  212  via a sliding joint  219 . The closed end  216  of the lower housing  211  may be rounded, sloped, tapered, pointed, beveled, chamfered, and/or otherwise shaped with respect to the central axis  203  of the downhole tool  200  in a manner that may decrease friction forces between the downhole tool  200  and the sidewall  121  or the inner surface  123  and/or wellbore fluid as the tool string  110  is conveyed downhole. 
     The lower housing  211  may enclose internal components of the downhole tool  200  and/or prevent the wellbore fluid from leaking into the interior space  205 . The lower housing  211  may further comprise a window  213  that may permit transmission of the laser beam  252  from within the downhole tool  200  to a region external to the downhole tool  200 . The window  213  may include an optically transparent material, such as glass or a transparent polymer, or the window  213  may be an aperture extending through a sidewall of the lower housing  211 . The window  213  may have a substantially circular, rectangular, or other geometry, or may extend circumferentially around the entire lower housing  211 . 
     During laser cutting operations, the internal space  205  of the lower housing  211  may be filled with the surface fluid communicated through the coiled tubing  161 , such as to permit uninterrupted transmission of the laser beam  252  through the internal space  205  and/or to equalize internal pressure of the downhole tool  200  with hydrostatic wellbore pressure. However, instead of being filled with the surface fluid, the internal space  205  may be filled with gas, such as nitrogen, or may be substantially evacuated (e.g., at a vacuum), among other implementations permitting substantially uninterrupted transmission of the laser beam  252  through the internal space  205 . 
     A deflector  250  may be included within the internal space  205  to direct the laser beam  252  through the window  213  to be incident upon intended locations along the sidewall  121  or the inner surface  123 , including via rotation about the axis of rotation  251 . For example, the downhole tool  200  may comprise a motor  260  operable to rotate the deflector  250  to control the rotational or angular direction or position of the deflector  250 . The motor  260  may comprise a stator  262  and a rotor  264 . The stator  262  may be fixedly coupled with respect to the upper housing  212 , and the rotor  264  may be coupled with or otherwise carry and thus rotate the deflector  250 . For example, an intermediate member  255  may be coupled with or otherwise rotate with the rotor  264 , and the deflector  250  may be coupled or otherwise carried with the intermediate member  255 . The intermediate member  255  may comprise an optical passage or other opening permitting the laser beam  252  to pass from the optical conductor  191  to the deflector  250 . 
     The deflector  250  is or comprises a light deflecting member operable to direct the laser beam  252  emitted from the optical conductor  191  through the window  213  upon the sidewall  121  or the inner surface  123 . The deflector  250  may be or comprise a lens, a prism, a mirror, or another light deflecting member. Although depicted as a single light deflecting member, the deflector  250  may comprise two or more prisms or mirrors, or the deflector  250  may comprise a rhomboid prism, among other example implementations within the scope of the present disclosure. 
     As described above, the upper housing  212  may be operable to receive therein or couple with the coiled tubing  161  to direct the surface fluid along the fluid pathway  214  within the downhole tool  200 , as indicated in  FIG. 2  by arrows  215 . Thereafter, the surface fluid may be directed by additional fluid pathways  218  toward the intermediate member  255 , which may direct the surface fluid into the internal space  205  and/or out of the downhole tool  200 . The intermediate member  255  may comprise a fluid pathway  256  directing the surface fluid from the fluid pathway  218  into the internal space  205 . At least a portion of the intermediate member  255  may extend radially outwards through the lower housing  211 , and this or another portion of the intermediate member  255  may comprise a fluid pathway  257  directing the surface fluid from the fluid pathway  218  to outside of the lower housing  211 . The fluid pathway  257  may terminate with a fluid nozzle  240  and/or other means operable to form a stream  242  of surface fluid expelled from the fluid pathway  257 . Although the nozzle  240  is depicted in  FIG. 2  as being flush with the exterior of the lower housing  211 , the nozzle  240  may also protrude outward from the exterior of the lower housing  211 . 
     The intermediate member  255  may also operatively couple the rotor  264  and the lower housing  211 , such as may permit the motor  260  to rotate the lower housing  211 . The connection between the intermediate member  255  and the rotor  264  further permits the motor  260  to simultaneously rotate the deflector  250  and direct the nozzle  240  in the same direction. That is, the nozzle  240  and the deflector  250  may be angularly aligned, relative to rotation around the axis of rotation  251 , such that the nozzle  240  may direct the fluid stream  242  in substantially the same direction that the deflector  250  directs the laser beam  252  (e.g., within about five degrees from each other). Although the nozzle  240  is shown forming the stream  242  flowing parallel with respect to the laser beam  252 , the nozzle  240  may form the fluid stream  242  flowing diagonally with respect to the laser beam  252  or along a radial path that at least partially overlaps or coincides with a radial path of the laser beam  252 . 
     Accordingly, during or after the laser cutting operations, the fluid stream  242  may be directed into the radial slots or the fluid stream  242  may impact a portion of the completion/production tubular  114 , the casing  122 , the cement sheath  124 , and/or the formation  130  that is being cut by the laser beam  252  to flush out particles, dust, fumes, and/or other contaminants (hereafter collectively referred to as “contaminants”) formed during the laser cutting operations. The fluid stream  242  may also displace contaminants and wellbore fluid from a region generally defined by the path of the laser beam  252 , such as may aid in preventing the contaminants and wellbore fluid from diffusing or otherwise interfering with the laser beam  252 . 
     The surface fluid communicated from the fluid source  140  via the coiled tubing  161  and expelled through the nozzle  240  may be substantially transparent to the laser beam  252 . For example, the surface fluid may comprise nitrogen, water with an appropriate composition and salinity, and/or another fluid that does not deleteriously interfere with and/or alter the laser beam  252 . The fluid composition may depend on the wavelength of the laser beam  252 . For example, the spectrum of absorption of water for infrared light may have some wavelength intervals where water is substantially transparent to the laser beam  252 . Accordingly, the downhole tool  200  may be operable to emit the laser beam  252  having a wavelength that may be transmitted through the water with little or no interference. 
     During or after the laser cutting operations, a depth sensor  230  may be utilized to detect the damaged portion of the sidewall  121  or the inner surface  123  and/or monitor or otherwise determine a depth or geometry of the radial slots formed by the laser beam  252 . The depth sensor  230  may be operatively connected with the motor  260 , such as may permit the motor  260  to control the angular position of the depth sensor  230  in an intended direction. For example, the depth sensor  230  may be coupled with or otherwise carried by the intermediate member  255 . The depth sensor  230  and the deflector  250  may be angularly aligned, relative to rotation around the axis  251 , such that a sensing direction of the depth sensor  230  and the direction of the laser beam  252  deflected by the deflector  250  may be substantially similar (e.g., within about five degrees of each other). Thus, the depth sensor  230  may be operable to detect the depth of the radial slot in real-time as the radial slot is being cut by the laser beam  252 . 
     The depth sensor  230  may comprise a signal emitter operable to emit a sensor signal  232  directed toward the sidewall  121  or the inner surface  123  and/or into the radial slot. The depth sensor  230  may further comprise a signal receiver operable to receive the sensor signal  232  after the sensor signal  232  is reflected back by the sidewall  121 , the inner surface  123 , or a radially outward end of the radial slot. The depth sensor  230  may be operable to calculate or determine damage along the sidewall  121  or the inner surface  123  and/or the penetration depth of the radial slot based on a duration of travel of the sensor signal  232  between the emitter and receiver. However, a controller  220  may also or instead be utilized to determine the damage along the sidewall  121  or the inner surface  123  and/or the penetration depth of the radial slot. 
     For example, the depth sensor  230  may be in communication with the controller  220 , such as to initiate emission of the sensor signal  232  by the controller  220  and to receive the returning sensor signal  232 . Once the sensor signal  232  is transmitted and received, the controller  220  may be operable to determine the damage along the sidewall  121  or the inner surface  123  and/or penetration depth of the radial slot based on the received sensor signal  232  or based on the duration of travel of the sensor signal  232  from the emitter to the receiver, such as between a first time at which the sensor signal  232  is emitted from the depth sensor  230  and a second time at which the depth sensor  230  receives the reflected sensor signal  232 . The penetration depth through the completion/production tubular  114 , the casing  122 , the cement sheath  124 , and/or the formation  130  may be measured in real-time as the radial slot is being formed by the laser beam  252 . Although the depth sensor  230  is shown emitting the sensor signal  232  parallel with respect to the laser beam  252 , the depth sensor  230  may emit the sensor signal  232  diagonally with respect to the laser beam  252  or otherwise toward the sidewall  121  or the inner surface  123  or into the radial slot formed by the laser beam  252 . 
     The depth sensor  230  may be an acoustic sensor operable to emit an acoustic signal upon the sidewall  121  or the inner surface  123  or into the radial slot and detect a reflection of the acoustic signal. The depth sensor  230  may also be an electromagnetic sensor operable to emit an electromagnetic signal upon the sidewall  121  or the inner surface  123  or into the radial slot and detect a reflection of the electromagnetic signal. The depth sensor  230  may also be a light sensor operable to emit a light signal upon the sidewall  121  or the inner surface  123  or into the radial slot and detect a reflection of the light signal. 
     The controller  220  may be connected with the electrical conductor  181  for transmitting and/or receiving electrical signals communicated between the controller  220  and the control center  180 . The controller  220  may be operable to receive, process, and/or record the signals or information generated by and/or received from the control center  180 , the downhole tool  200 , and/or the one or more tools  112  of the tool string  110 . For example, the controller  220  may be operable to receive and process signals from the CCL and/or orientation sensor(s) described above, such as to acquire the position and/or the orientation of the downhole tool  200 . The controller  220  may be further operable to transmit the acquired position and/or orientation information to the control center  180  via the electrical conductor  181 . 
     The downhole tool  200  may also carry or otherwise comprise a sealing material  271 ,  272  which may be disposed at least partially within or around the housing  210  of the laser cutting apparatus  202  or another portion of the downhole tool  200  in a manner permitting the sealing material  271 ,  272  to remain about the housing  210  during downhole conveyance operations. For example, the sealing material  271  (which may be referred to herein as “particulate sealing material”) may be provided in a form of pellets, beads, or other solid particles, which may be operable to freely roll, flow, or otherwise move via gravity when not contained. If the particulate sealing material  271  is utilized, the sealing material  271  may be contained within a container  281 , such as may be operable to maintain the sealing material  271  at least partially within or around the housing  210  of the laser cutting apparatus  202  or another portion of the downhole tool  200 . The container  281  may comprise a hatch, a door, or another release mechanism  282  operable to release or otherwise permit the sealing material  271  to flow or move out of the container  281 , such as by way of gravity. The sealing material  271  may also be supplied from the wellsite surface  105 , such as via the coiled tubing  161 . For example, the sealing material  271  may be communicated from the wellsite surface  105  into the container  281  or the sealing material  271  may be communicated from the wellsite surface  105  and directed directly into the radial slot during sealing operations. 
     The sealing material  272  (which may be referred to herein as “non-particulate sealing material”) may also be provided in a solid state in a form of one or more rings (not shown) that are stacked or otherwise disposed about the upper housing  212 , although other arrangements are also within the scope of the present disclosure. 
     The sealing material  271 ,  272  may be a metal and/or eutectic material selected based on, for example, anticipated wellbore conditions and a well intervention operation to be performed with the downhole tool  200 . That is, the sealing material  271 ,  272  may be carried by the downhole tool in a solid state, whether bulk or particulate, having a melting temperature at which the sealing material  271 ,  272  flows in a liquid state. Such sealing material  271 ,  272  then solidifies when cooled to a temperature below the melting temperature. 
     For example, the sealing material  271 ,  272  may be a eutectic material formulated such that the melting temperature of the eutectic material is lower than the melting temperatures of each of the individual constituents. The melting temperature of the eutectic material is known as a eutectic temperature. The eutectic temperature depends on the amounts and perhaps relative orientations of its constituents. The eutectic material may comprise a bismuth-based alloy, such as may substantially comprise about 58% bismuth and about 42% tin, by weight. However, other eutectic alloys are also within the scope of the present disclosure. 
     The sealing material  271 ,  272  may be melted by heating via electrical, chemical, and/or other heating means  274  located along or adjacent the sealing material  271 ,  272 . The sealing material  271 ,  272  melts, transforming from a solid state to a liquid or melted state when heat from the heating means  274  is applied or otherwise transferred to the sealing material  271 ,  272 . When in the melted state, the sealing material  271 ,  272  may be molded or otherwise formed to perform downhole sealing operations. 
     The heating means  274  may comprise one or more electrical heating coils or other elements (not shown) disposed substantially along the length of the sealing material  271 ,  272 , whether within the upper housing  212  or between the upper housing  212  and the sealing material  271 ,  272 . The electrical power may be provided to the heating means  274  via one or more electrical conductors  181 . The tool string  110  may also comprise an internal alternator or generator (not shown) for generating heat or electrical energy to heat the sealing material  271 ,  272 . 
     The heating means  274  may also or instead comprise one or more thermites and/or other heat-generating chemical elements, such as may be disposed in solid or powder form substantially along the length of the sealing material  271 ,  272 , whether within the upper housing  212  or between the upper housing  212  and the sealing material  271 ,  272 . The heat-generating chemical elements may be activated to generate heat via chemical reaction, thus melting the sealing material  271 ,  272 . 
     The downhole tool  200  may also utilize the laser beam  252  to melt the sealing material  271 ,  272 . For example, the non-particulate sealing material  272  and the laser cutting apparatus  202  may be movable with respect to each other such that the laser beam  252  may be directed upon the sealing material  272  to heat the sealing material  272  to at least the melting temperature. In an embodiment of the downhole tool  200 , the sealing material  272  may be axially movable about the upper housing  212  such that at least a portion of the sealing material  272  may be positioned along the path of the laser beam  252  exiting the window  213  such that the laser beam  252  is directed upon the sealing material  272 . In an embodiment of the downhole tool  200 , the laser cutting apparatus  202  may be axially movable or retractable within the sealing material  272  such that the window  213  is positioned within the sealing material  272  and the laser beam  252  is directed upon the sealing material  272 . 
     Although the sealing material  271 ,  272  is shown disposed around the upper housing  212  of the laser cutting apparatus  202  and the heating means  274  is shown disposed within the upper housing  212 , it is to be understood that the sealing material  271 ,  272  and the heating means  274  may be implemented as part of another portion of the downhole tool  200 . The sealing material  271 ,  272  and the heating means  274  may also be or comprise a portion of another tool  112  coupled within the tool string. For example, the sealing material  271 ,  272  and the heating means  274  may be disposed around and within a mandrel of another tool  112  coupled uphole or downhole with respect to the laser cutting apparatus  202 . 
     A portion of the downhole tool  200  located downhole from the sealing material  271 ,  272  and/or the window  213  may comprise an outer diameter  276  that is larger than an outer diameter  204  of the rest of the downhole tool  200 , such as the housing  210 . The downhole portion of the downhole tool  200  may be or comprise a radially protruding member or spreader  280  having a surface  278  transitioning between the outer diameters  204 ,  276 . The surface  278  of the spreader  280  may be operable to urge the flowing sealing material  271 ,  272  radially outward toward the sidewall  121  or the inner surface  123 , such as to provide a path for the flowing sealing material  271 ,  272 . The outer diameter  276  of the spreader  280  may be slightly smaller than or substantially equal to an inner diameter  118  of the sidewall  121  in the open-hole implementation or the outer diameter  276  may be slightly smaller than or substantially equal to an inner diameter  119  of the inner surface  123  in the cased-hole implementation. The surface  278  may be a substantially frustoconical surface extending diagonally or axially tapered with respect to the central axis  203  of the downhole tool  200 . The surface  278  may extend circumferentially and/or substantially continuously around the lower housing  211 . 
     The spreader  280  may be fixedly disposed downhole from the sealing material  271 ,  272  and/or the window  213  or the spreader  280  may be movable between a retracted position (shown in  FIG. 4-7 ) and an expanded position (shown in  FIG. 2 ). In the retracted position, the spreader  280  comprises an outer diameter  275  that may be substantially smaller than the outer diameter  276  when the spreader  280  is in the expanded position. When in the retracted position, the outer diameter  275  of the spreader  280  may be substantially equal to the outer diameter  204  of the housing  210 . When in the expanded position, the outer diameter  276  of the spreader  280  may be slightly smaller than or substantially equal to the inner diameter  118  of the sidewall  121  or the outer diameter  276  may be slightly smaller than or substantially equal to the inner diameter  119  of the inner surface  123 . 
     The spreader  280  may comprise one or more flexible scoopers, bristles, and/or other filaments (not shown) operable to distribute or shape the melted sealing material  271 ,  272 . The spreader  280  may be substantially solid or may comprise recesses, holes, fins, and/or other heat-dissipating features (not shown) extending into or from the spreader  280 . Such features may aid in absorbing heat from the melted sealing material  271 ,  272  and/or in transferring heat from the melted sealing material  271 ,  272  to the lower housing  211  and/or surrounding environment, which may include water and/or other fluids within the wellbore  120 . 
     Although shown as being integral with the lower housing  211 , the spreader  280  may be a separate and distinct portion of the downhole tool  200  connected to the lower housing  211 . Furthermore, although the spreader  280  is shown disposed in connection with the lower housing  211 , the spreader  280  may be connected with another portion of the downhole tool  200  downhole from the sealing material  271 ,  272  and/or the window  213 . The spreader  280  may also be or comprise a portion of another tool  112  coupled within the tool string  110  downhole from the sealing material  271 ,  272  and/or the laser apparatus  202 . 
       FIG. 3  is a schematic view of at least a portion of an example implementation of an apparatus  300  according to one or more aspects of the present disclosure. The apparatus  300  may be or form a portion of the control center  180  shown in  FIG. 1  and/or the controller  220  shown in  FIG. 2 , and may thus be operable to facilitate at least a portion of a method and/or process according to one or more aspects described above. 
     The apparatus  300  is or comprises a processing system  301  that may execute example machine-readable instructions to implement at least a portion of one or more of the methods and/or processes described herein. For example, the processing system  301  may be operable to receive, store, and/or execute computer programs or coded instructions  332 , such as may cause the downhole tool  200  and/or other components of the tool string  110  and the wellsite system  100  to perform at least a portion of a method and/or process described herein. The processing system  301  may be programmed or otherwise receive the coded instructions  332  at the wellsite surface  105  prior to conveying the downhole tool  200  within the wellbore  120 . The processing system  301  may also be programmed with information related to quantity and location, and other parameters related to formation of the radial slots. The processing system  301  may also be programmed with a predefined radial slot geometry and/or the processing system  301  may be programmed to form the radial slots based on geometry of the damaged portions of the sidewall  121  and/or the side surface  123 , including the completion/production tubular  114 , the casing  122 , the cement sheath  124 , and/or the formation  130 . Based on the information and/or coded instructions  332 , the processing system  301  may be operable to control the downhole tool  200 , including activating the laser source  190  (or indicating a “ready” status therefor), rotating the motor  260  to control the angular position of the deflector  250 , the nozzle  240 , and/or the depth sensor  230 , and actuating the coiled tubing injector  171  to apply an uphole and downhole force to the coiled tubing  161  to advance and retract the downhole tool  200  within the wellbore  120 . Therefore, the processing system  301 , including the programmed information and/or coded instructions  332 , may facilitate a substantially automatic radial slot formation process, perhaps with no or minimal interaction or communication with a human operator at the wellsite surface  105 . 
     The processing system  301  may be or comprise, for example, one or more processors, controllers, special-purpose computing devices, servers, personal computers, personal digital assistant (PDA) devices, smartphones, smart glasses, tablets, internet appliances, and/or other types of computing devices. The processing system  301  may comprise a processor  312 , such as, for example, a general-purpose programmable processor. The processor  312  may comprise a local memory  314 , and may execute the coded instructions  332  present in the local memory  314  and/or another memory device. The processor  312  may execute, among other things, machine-readable instructions or programs to implement the methods and/or processes described herein. The processor  312  may be, comprise, or be implemented by one or a plurality of processors of various types suitable to the local application environment, and may include one or more of general- or special-purpose computers, microprocessors, digital signal processors (DSPs), field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), and processors based on a multi-core processor architecture, as non-limiting examples. Other processors from other families are also appropriate. 
     The processor  312  may be in communication with a main memory, such as may include a volatile memory  318  and a non-volatile memory  320 , perhaps via a bus  322  and/or other communication means. The volatile memory  318  may be, comprise, or be implemented by random access memory (RAM), static random access memory (SRAM), synchronous dynamic random access memory (SDRAM), dynamic random access memory (DRAM), RAMBUS dynamic random access memory (RDRAM) and/or other types of random access memory devices. The non-volatile memory  320  may be, comprise, or be implemented by read-only memory, flash memory and/or other types of memory devices. One or more memory controllers (not shown) may control access to the volatile memory  318  and/or the non-volatile memory  320 . 
     The processing system  301  may also comprise an interface circuit  324 . The interface circuit  324  may be, comprise, or be implemented by various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB), a third generation input/output (3GIO) interface, a wireless interface, a satellite interface, a global positioning system (GPS) and/or a cellular interface or receiver, among others. The interface circuit  324  may also comprise a graphics driver card. The interface circuit  324  may also comprise a device, such as a modem or network interface card to facilitate exchange of data with external computing devices via a network (e.g., Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, satellite, etc.). 
     One or more input devices  326  may be connected to the interface circuit  324 . The input device(s)  326  may permit a user to enter data and commands into the processor  312 . The input device(s)  326  may be, comprise, or be implemented by, for example, a keyboard, a mouse, a touchscreen, a track-pad, a trackball, an isopoint, and/or a voice recognition system, among others. 
     One or more output devices  328  may also be connected to the interface circuit  324 . The output devices  328  may be, comprise, or be implemented by, for example, display devices (e.g., a light-emitting diode (LED) display, a liquid crystal display (LCD, or a cathode ray tube (CRT) display, among others), printers, and/or speakers, among others. 
     The processing system  301  may also comprise one or more mass storage devices  330  for storing machine-readable instructions and data. Examples of such mass storage devices  330  include floppy disk drives, hard drive disks, compact disk (CD) drives, and digital versatile disk (DVD) drives, among others. The coded instructions  332  may be stored in the mass storage device  330 , the volatile memory  318 , the non-volatile memory  320 , the local memory  314 , and/or on a removable storage medium  334 , such as a CD or DVD. Thus, the modules and/or other components of the processing system  301  may be implemented in accordance with hardware (embodied in one or more chips including an integrated circuit, such as an ASIC), or may be implemented as software or firmware for execution by a processor. In the case of firmware or software, the embodiment may be provided as a computer program product including a computer readable medium or storage structure embodying computer program code (i.e., software or firmware) thereon for execution by the processor. 
       FIGS. 4-10  are sectional views of the downhole tool  200  shown in  FIG. 2  disposed in the wellbore  120  during different stages of operation according to one or more aspects of the present disclosure. The downhole tool  200  is depicted as being disposed within a cased-hole implementation of the wellbore  120 , which does not include the completion/production tubing  114 . Accordingly, the inner surface  123  in  FIGS. 4-10  comprises the inner surface of the casing  122 . The inner surface  123  and the sidewall  121  are shown having a damaged portion  284 , which extends through the casing  122 , the cement sheath  124 , and into the formation  130 . The following description refers to  FIGS. 1 and 4-10 , collectively. 
     During the laser cutting operations in which one or more damaged portions  284  are to be removed, the downhole tool  200  may be conveyed to the damaged portion  284  of the wellbore  120 . The coiled tubing injector  171  may convey the tool string  110  with the downhole tool  200  such that the window  213  of the laser cutting apparatus  202  is located at an uphole end of the damaged portion  284 , as shown in  FIG. 4 . When such position is reached, the laser source  190  may be activated to transmit the laser beam  252  to the laser cutting apparatus  202 . The laser beam  252 , directed by the deflector  250 , may then be utilized to remove or cut a portion of the casing  122 , the cement sheath  124 , and/or the formation  130  along the damaged portion  284  of the wellbore  120 . 
     As shown in  FIGS. 5 and 6 , the laser beam  252  may form one or more cavities or radial slots  286  along the damaged portion  284  of the wellbore  120 . The deflector  250  may be rotated about the axis of rotation  251  through a predetermined angle to form the radial slot  286  having an angular sector geometry along the entire damaged portion  284  or multiple damaged portions of the wellbore  120 . If the damaged portion  284  extends around the entire inner surface  123 , the deflector  250  may be rotated 360 degrees to form a continuous or substantially continuous 360-degree slot  286  along the entire damaged portion  284 , as shown in  FIG. 6 . The radial slot  286  may be formed to a depth  288 , which may be substantially the same as or greater than a depth  290  of the damaged portion  284 . If the damaged portion  284  extends axially (i.e., vertically) along the wellbore  120 , the radial slot  286  may be extended axially by causing the coiled tubing injector  171  to move the tool string  110 , including the laser cutting apparatus  202 , along the wellbore  120  in the downhole direction until the window  213  is positioned at the next portion of the damaged portion  284  that has not been removed. Once the window  213  is positioned at the intended location, the laser beam  252  may be reactivated and rotated through the intended angle to extend the radial slot  286  axially. It is to be understood that the radial slot  286  may also be formed in a continuous manner, wherein the deflector  250  is rotated through the intended angle while the laser cutting apparatus  202  is moved axially along the wellbore  120 . It is to be further understood that the radial slot  286  may be initiated at a downhole end of the damaged portion  284  and the laser cutting apparatus  202  may be moved in the uphole direction to extend the radial slot  286  axially. 
     As the laser cutting apparatus  202  is forming the radial slot  286 , the fluid source  140  may be activated to introduce the surface fluid into the downhole tool  200 , causing the fluid stream  242  to be discharged from the nozzle  240 . As described above, the fluid stream  242  may clean the radial slot  286 , such as by flushing out contaminants formed during the laser cutting operations. 
     As the laser cutting apparatus  202  is forming the radial slot  286 , the depth sensor  230  may be activated to detect the damaged portion  284  of the wellbore  120  along the inner surface  123  and/or monitor the depth  288  or geometry of the radial slot  286 . As described above, the depth sensor  230  may transmit the sensor signal  232  upon the damaged portion  284  and receive the sensor signal  232  that is reflected by the radially outward end of the damaged portion  284  to identify or determine the location, geometry, and/or depth  290  of the damaged portion  284 . The depth sensor  230  may also transmit the sensor signal  232  into the radial slot  286  and receive the sensor signal  232  that is reflected by the radially outward end of the radial slot  286  to identify or determine the geometry or depth  288  of the radial slot  286 . After the depth  288  or geometry of the radial slot  286  is known, the controller  220  may be operable to cause the motor  260  to rotate the deflector  250  based on the determined depth  288 . For example, the controller  220  may be operable to slow down the motor  260  to decrease angular velocity of the deflector  250  and, thus, decrease the angular velocity of the laser beam  252 . Such decrease may be based on the determined depth  288  to, for example, deliver a substantially constant amount of laser energy per unit length of the casing  122 , the cement sheath  124 , and/or the formation  130  being cut. 
     The coiled tubing injector  171  may move the tool string  110 , including the laser cutting apparatus  202 , along the wellbore  120  in the downhole direction until the radial slot  286  is formed along the entire axial length of the damaged portion  284 , as shown in  FIG. 7 . 
     When the damaged portion  284  of the casing  122 , the cement sheath  124 , and/or the formation  130  has been removed to form the intended radial slot  286 , a sealing operations may commence. As shown in  FIG. 8 , the axial position of the downhole tool  200  may be adjusted such that a radially outward end of the spreader  280  and/or the spreader surface  278  is located at or slightly below a downhole end of the radial slot  286 . If the spreader  280  is retractable, the spreader  280  may be actuated to its expanded position such that its outer diameter  276  is slightly smaller than or substantially equal to the inner diameter  119  of the inner surface  123 . The spreader  280  may also be actuated to its expanded position such that its outer diameter  276  is slightly smaller than or substantially equal to the inner diameter  118  of the sidewall  121 , if the downhole tool  200  is utilized in the open-hole implementation of the wellbore  120 . 
     In the implementation of the downhole tool  200  utilizing the non-particulate sealing material  272 , the sealing material  272  and/or the laser cutting apparatus  202  may be axially moved with respect to each other such that at least a portion of the sealing material  272  may be positioned along the window  213  or otherwise along the path of the laser beam  252 . As further shown in  FIG. 8 , the sealing material  272  may be axially moved in the downhole direction about the housing  210  of the laser cutting apparatus  202  such that at least a portion of the sealing material  272  may be positioned along the window  213  and, thus, along the path of the laser beam  252  exiting the window  213 . 
     Once the sealing material  272  is positioned along the window  213  or otherwise along the path of the laser beam  252 , the laser source  190  may be activated to transmit the laser beam  252  to the laser cutting apparatus  202 , as shown in  FIG. 9 . The laser beam  252 , directed by the deflector  250  at the sealing material  272 , may then increase the temperature of the sealing material  272  until it melts. The melted sealing material  273  may flow in a downhole direction and be urged radially outward by the surface  278  of the spreader  280 . The deflector  250  may rotate about the axis of rotation  251  to melt the sealing material  272  disposed around the housing  210 . As the sealing material  272  is melted, the melted sealing material  273  is urged or flows radially outward into the radial slot  286  to progressively fill the radial slot  286 . 
     As further shown in  FIG. 10 , prior to or after the radial slot  286  is filled with the melted sealing material  273 , the coiled tubing injector  171  may be activated to move the tool string  110 , including the laser cutting apparatus  202 , along the wellbore  120  in the uphole direction. As the downhole tool  200  moves uphole, the spreader  280  may further urge the melted sealing material  273  into the radial slot  286 . The spreader  280 , the housing  210 , and/or another portion of the tool string  110  that contacts the melted sealing material  273  absorbs heat from the melted sealing material  273  and shapes the melted sealing material  273  to include an inner surface  283  that is substantially continuous with the inner surface  123  of the casing  122 . If the radial slot  286  was formed in the open-hole implementation of the wellbore  120 , the downhole tool  200  will have shaped the melted sealing material  273  to form an inner surface  285  (shown in phantom lines) that is substantially continuous with the sidewall  121  of the wellbore  120 . 
     The downhole tool  200  may be moved in the uphole direction at a speed that permits the melted sealing material  273  to cool to a temperature at which the viscosity and/or other properties of the melted sealing material  273  reach an intended level of solidity to permit shaping of the melted sealing material  273  as intended. The properties of the sealing material  273  may be selected such that the sealing material  273  chemically and/or otherwise bonds with the casing  122 , the cement sheath  124 , and/or the formation  130  and/or otherwise permits the sealing material  273  to be molded and/or otherwise shaped by the spreader  280 . Accordingly, as the melted sealing material  273  cools and solidifies, the solidified sealing material  279  adheres to or remains within the radial slot  286  without further flowing downhole along the inner surface  123  of the casing  122  or otherwise deforming from the shape formed by the spreader  280 . The solidified sealing material  279  may form a patch to seal the radial slot  286  and/or may provide the inner surface  283 , which may permit subsequent downhole tool or fluid placement within the wellbore  120 . When the damaged portions  284  along the inner surface  123  are repaired or the sealing material  272  has been used up, the downhole tool  200  may then be removed from the wellbore  120 . 
     Although  FIGS. 8-10  show the sealing material  272  being melted by the laser beam  252 , the sealing material  272  may also or instead be melted by activating the heating means  274 . As described above, the heating means  274  may comprise one or more electrical heating coils or other elements (not shown) disposed substantially along the sealing material  272 . Accordingly, the electrical power may be provided from the control center  180  to the heating means  274  via the electrical conductor  181 . The heating means  274  may also or instead comprise one or more thermites and/or other heat-generating chemical elements, such as may be disposed in solid or powder form substantially along the sealing material  272 . The heat-generating chemical elements may be activated to generate heat via chemical reaction, thus melting the sealing material  272 . Once melted, the sealing material  273  may flow downhole between the housing  210  of the laser cutting apparatus  202  and the inner surface  123 . The melted sealing material  273  may then be directed or operated upon as described above. 
       FIGS. 11-13  are schematic sectional views of another example implementation of the downhole tool  200  shown in  FIGS. 2-10  according to one or more aspects of the present disclosure, and designated in  FIGS. 11-13  by reference number  201 . Unless described otherwise, the downhole tool  201  is substantially similar to the downhole tool  200  shown in  FIGS. 2-10 , including where indicated by like reference numbers. The following description refers to  FIGS. 1 and 11-13 , collectively. 
     When utilizing the downhole tool  201  during the sealing operations, the particulate sealing material  271  may be placed within the radial slot  286  without first being melted. As shown in  FIG. 11 , when the intended radial slot  286  has been formed and the spreader  280  is positioned along or slightly below the downhole end of the radial slot  286 , the release mechanism  282  may be actuated to an open position to permit the sealing material  271  to flow out of the container  281 . Gravity may then cause the sealing material  271  to axially flow in the downhole direction along the housing  210  of the laser cutting apparatus  202 . The spreader  280  may urge the sealing material  271  to flow into the radial slot  286  and prevent the sealing material  271  to flow further downhole into the wellbore  120 . 
     As shown in  FIG. 12 , once the sealing material  271  substantially fills the radial slot  286 , the release mechanism  282  by be actuated to a closed position to stop the flow of the sealing material  271 . Prior to or after the sealing material  271  substantially fills the radial slot  286 , the laser source  190  may be activated to transmit the laser beam  252  to the laser cutting apparatus  202 . The laser beam  252 , directed by the deflector  250  at the sealing material  271  within the radial slot  286 , may increase the temperature of the sealing material  271  until it melts. The deflector  250  may rotate about the axis of rotation  251  to melt the sealing material  271  disposed within the radial slot  286  around the housing  210 . Prior to or after the sealing material within the whole radial slot  286  is melted, the coiled tubing injector  171  may be activated to move the tool string  110 , including the laser cutting apparatus  202 , along the wellbore  120  in the uphole direction. 
     As the downhole tool  201  moves uphole, the spreader  280  may further urge the melted sealing material  287  into the radial slot  286 . The spreader  280 , the housing  210 , and/or another portion of the tool string  110  that contacts the melted sealing material  287  absorb heat from the melted sealing material  287  and shape the melted sealing material  287  to form the inner surface  283  that is substantially continuous with the inner surface  123  of the casing  122 , as shown in  FIG. 13 . If the radial slot  286  was formed in the open-hole implementation of the wellbore  120 , the downhole tool  201  will have shaped the melted sealing material  287  to form the inner surface  285  (shown in phantom lines) that is substantially continuous with the sidewall  121  of the wellbore  120 . 
     The downhole tool  201  may be moved in the uphole direction at a speed that permits the melted sealing material  287  to cool to a temperature at which the viscosity and/or other properties of the melted sealing material  273  reach an intended level of solidity to permit shaping of the melted sealing material  287  as intended. The properties of the sealing material may be selected such that the sealing material chemically and/or otherwise bonds with the casing  122 , the cement sheath  124 , and/or the formation  130  and/or otherwise permits the sealing material to be molded and/or otherwise shaped by the spreader  280 . Accordingly, as the melted sealing material  287  cools and solidifies, the solidified sealing material  289  adheres to or remains within the radial slot  286  without further flowing downhole along the inner surface  123  of the casing  122  or otherwise deforming from the shape formed by the spreader  280 . The solidified sealing material  289  may form the patch to seal the radial slot  286  and/or may provide the inner surface  283 , which may permit subsequent downhole tool or fluid placement within the wellbore  120 . When the damaged portions  284  along the inner surface  123  are repaired or the sealing material  271  has been used up, the downhole tool  201  may then be removed from the wellbore  120 . 
     Although  FIGS. 12 and 13  show the sealing material  271  being melted by the laser beam  252 , the sealing material  271  may also or instead be melted by activating the heating means  274 . As described above, the heating means  274  may comprise one or more electrical heating coils or other elements (not shown). Accordingly, the electrical power may be provided from the control center  180  to the heating means  274  via the electrical conductor  181 . The heating means  274  may also or instead comprise one or more thermites and/or other heat-generating chemical elements. The heat-generating chemical elements may be activated to generate heat via chemical reaction. Accordingly, when the sealing material  271  is disposed within the radial slot  286 , the downhole tool  201  may be moved axially to align the heating means  274  with the sealing material  271  within the radial slot  286 , such as may permit heat transfer between the heating means  274  and the sealing material  271  to melt the sealing material  271 . The melted sealing material  287  may then be directed or operated upon as described above. 
     Although  FIGS. 2-13  show the downhole tools  200 ,  201  operable perform both the laser cutting and sealing operations during a single trip to the damaged portion  284  of the wellbore  120 , it is to be understood that the laser cutting and sealing operations may be performed during multiple trips and/or by utilizing multiple downhole tools. For example the laser cutting operations may be performed during a first downhole trip with a laser cutting tool, which may comprise the same or similar structure as the laser cutting apparatus  202  described above with respect to the laser cutting apparatus  202 . To form the radial slot  286 , the laser cutting apparatus may perform the same or similar operations as described above. Once the intended one or more radial slots  286  are formed with the laser cutting apparatus, the sealing operations may be performed during a second downhole trip with a sealing tool. Such sealing tool may comprise a sealing material, a heating means, a mandrel, and a spreader, each comprising the same or similar structure as the sealing material  271 ,  272 , the heating means  274 , the housing  210 , and the spreader  280 , respectively, described above. To seal the radial slot  286 , the sealing tool may perform the same or similar operations as described above with respect to the downhole tools  200 ,  201 , including the sealing material  271 ,  272 , the heating means  274 , the housing  210 , and the spreader  280 . 
     The downhole tools  200 ,  201  described above may also be utilized to perform a P&amp;A operation according to one or more aspects of the present disclosure. For example, the laser cutting apparatus  202  may be operated to remove material at a selected location within the wellbore  120  and replace, seal, and/or isolate the wellbore and/or the space previously occupied by the removed material with the solidified sealing material  279 ,  289 . As described above, the removal of the existing material and replacement with the solidified sealing material  279 ,  289  may be performed in a single trip within the wellbore  120 , instead of multiple trips in and out of the wellbore  120  with different tools and/or tool strings. 
     For example,  FIG. 14  is a flow-chart diagram of at least a portion of an example implementation of a method ( 500 ) to be performed in a P&amp;A operation according to one or more aspects of the present disclosure. The following description refers to at least  FIGS. 4-14 , collectively. 
     The method ( 500 ) comprises conveying ( 510 ) the downhole tool  200  or  201  within the wellbore  120  to a location at which the P&amp;A operation will be performed. The location may be a faulty, leaking, and/or otherwise damaged portion  284  of the casing  122 , the cement sheath  124 , and/or the formation  130 , such as depicted in  FIG. 4 . The laser cutting apparatus  202  is then operated to remove ( 520 ) material from the casing  122 , the cement sheath  124 , and/or the formation  130 , such as depicted in  FIGS. 5-7 . However, the material may also or instead be removed ( 520 ) mechanically, such as via utilization of one or more cutters, underreamers, and/or other mechanical material removal means. The material may also or instead be removed ( 520 ) hydraulically, such as via utilization of one or more fluid jet devices. The material may also or instead be removed ( 520 ) via chemical reaction, such as dissolving methods. The material removal ( 520 ) may also be via combinations of two or more of such laser, mechanical, hydraulic, and/or chemical methods. 
     The method ( 500 ) may also comprise subsequently cleaning ( 530 ) the void created by the material removal ( 520 ), such as to remove dust, particulate, and/or other debris generated by or otherwise remaining after the material removal ( 520 ). For example, such cleaning ( 530 ) may comprise circulation of one or more liquid and/or gaseous fluids. Such fluids may be non-reactive to the casing  122 , the cement sheath  124 , and/or the formation  130 , such as air, nitrogen, water, brine, and/or other materials. However, such fluids may instead be at least somewhat reactive, such as an acidic solution, a surfactant, a solvent, and/or other materials. The cleaning ( 530 ) may also utilize a combination of these and other reactive and non-reactive materials that may aid in removing debris, dust, and the like. 
     The cleaning ( 530 ) may also entail pressurization of the cleaning fluid, such as fluid pressurized at the wellsite surface and pumped to the downhole tool  200 ,  201  via coiled tubing, and/or via one or more fluid jets. For example, the fluid nozzle  240  may be utilized during one or both of the material removal ( 520 ) and/or the cleaning ( 530 ). The cleaning ( 530 ) may also comprise utilizing a downhole camera, sonic device, and/or other imaging means to ensure and/or verify adequate removal ( 520 ) and/or cleaning ( 530 ) of the material from the void when the plug is to be formed. 
     The sealing material  271 ,  272  is then melted ( 540 ) and the melted sealing material  273 ,  287  is then placed ( 550 ) into at least the void created by the material removal ( 520 ), as described above. For example, as shown by comparison of  FIGS. 7 and 8 , the sealing material  271 ,  272  and/or the laser cutting apparatus  202  may be axially moved with respect to each other. Such relative movement may position at least a portion of the sealing material  271 ,  272  within the path of the laser beam  252  emitted by the laser cutting apparatus  202 , so as to utilize the laser cutting apparatus  202  to melt ( 540 ) the sealing material  271 ,  272 . However, melting ( 540 ) the sealing material  271 ,  272  may be via means other than (or in addition to) the laser cutting apparatus  202 , as described above, such as a resistive heater, a chemical heater, and/or other means. The laser beam  252  may also be utilized to energize another material/chemical carried with the downhole tool  200 ,  201  and that is reactive to the laser energy to generate sufficient heat to melt ( 540 ) the sealing material  271 ,  272 . Such reactive material/chemical may also be supplied to the tool downhole tool  200 ,  201  from the wellsite surface, such as via coiled tubing and/or other conduits. After the sealing material  273 ,  287  is melted, it is placed ( 550 ) into the void created by the material removal ( 520 ), such as via gravity-induced flow, utilization of the spreader  280 , and/or other means described above. The melted sealing material  273 ,  287  then solidifies, forming the plug of solid sealing material  279 ,  289 . 
     After placing ( 550 ) the melted sealing material  273 ,  287  in the void created by the material removal ( 520 ), the melted sealing material  273 ,  287  may be permitted to solidify around the lower housing  211  or a tool  112  coupled below the downhole tools  200 ,  201  without removing the lower housing  211  or the tool  112  before such solidification. Accordingly, the lower housing  211  or the tool  112  and the solidified sealing material  279 ,  289  may collectively form the solid plug preventing communication of wellbore fluids between portions of the wellbore  120  above and below the plug. The lower housing  211  or the tool  112  may then be decoupled or severed from the upper housing  212  or the downhole tool  200 ,  201 , to be abandoned in the wellbore  120 . However, multiple iterations of the melting ( 540 ) and material placement ( 550 ) may also be utilized to build layer upon layer of solidified sealing material  279 ,  289 , with the downhole tool  200 ,  201  being moved to slightly above the plug, so that the downhole tool  200 ,  201  may be retrieved to the surface in its entirety. 
     It is noted that a P&amp;A operation according to one or more aspects described above and/or otherwise within the scope of the present disclosure may provide a reduction in the footprint of equipment at the wellsite surface utilized for performing the P&amp;A operation. For example, the P&amp;A operation may be performed with standard coiled tubing and/or wireline surface equipment, which has a much smaller footprint at the wellsite surface compared to semi-submersible, jack up, and/or other drilling rigs. Accordingly, P&amp;A operations according to one or more aspects of the present disclosure may be performed without the burden of handling casing and/or jointed tubing, because the P&amp;A operation may be performed on a conveyance as a through-tubing operation, such as via coiled tubing and/or wireline. Such P&amp;A operations may also be performed without circulating and solids-handling surface equipment, or at least with reduced circulating and solids-handling surface equipment, compared to the large surface equipment conventionally utilized in P&amp;A operations, such as mechanical under-reaming equipment and the associated surface equipment for handling casing cuttings and other solids. Moreover, because P&amp;A operations according to one or more aspects of the present disclosure may be performed with coiled tubing, wireline, and/or other through-tubing conveyance means instead of casing and/or other jointed tubing, the well control equipment at the wellsite surface may also be much smaller compared to the well control equipment conventionally utilized for P&amp;A operations. P&amp;A operations according to one or more aspects of the present disclosure may also be performed with fewer personnel compared to conventional P&amp;A operations, due to the reduced footprint of the surface equipment, the reduction in number of surface systems and equipment, and/or other factors. 
     P&amp;A operations according to one or more aspects of the present disclosure may also be performed with greater efficiency and/or reduced time and/or cost, because less surface equipment is utilized, because casing and/or other jointed tubing is not fully removed, and/or because a P&amp;A operation performed as an intervention operation with coiled tubing and/or wireline is much quicker than an operation utilizing jointed tubing. P&amp;A operations according to one or more aspects of the present disclosure may also be performed with greater efficiency and/or reduced time and/or cost, compared to P&amp;A operations utilizing a drilling rig, because telemetry via coiled tubing and/or wireline permits multiple functions to be carried out with the downhole tool  200 ,  201  in the wellbore, without having to trip different tools in and out of the wellbore. 
     P&amp;A operations according to one or more aspects of the present disclosure may also be performed with greater efficiency and/or reduced time and/or cost because the laser cutting apparatus  202  permits precise material removal and more control of the overall process, compared to conventional P&amp;A operations in which an excessive amount of material is removed to account for uncertainty in the material removal process. P&amp;A operations according to one or more aspects of the present disclosure may also be performed with greater efficiency and/or reduced time and/or cost because the precise placement of the sealing material  279 ,  289  permits more control of the overall process, compared to conventional P&amp;A operations in which an excessive amount of replacement material is deposited downhole to account for uncertainty in the plugging process. 
     One or more aspects described above with respect to the composition and/or placement of the sealing material  279 ,  289  may be better adapted to P&amp;A operations than the cement utilized in conventional P&amp;A operations. For example, the permeability of the sealing material  279 ,  289  may be close to zero, which is orders of magnitude less than the cement utilized in conventional P&amp;A operations. The sealing material  279 ,  289  may also be less susceptible and/or not subject to corrosion, dissolution, crystal form changes (metamorphosis), electrochemical degradation, and/or other risks inherent to the cement utilized in conventional P&amp;A operations. The melted sealing material  273 ,  287  may also expand as it solidifies to form the solid sealing material  279 ,  289 , which may correct and/or provide the isolation sought by the P&amp;A operation. The solid sealing material  279 ,  289  may also permit a smaller total length (e.g., length  410  in  FIG. 13 ) of the resulting barrier while still achieving the same or better isolation relative to the much longer cement column utilized in conventional P&amp;A operations. 
     The sealing material  279 ,  289  is also denser, more ductile, and less susceptible and/or not subject to stress cracking compared to the cement utilized in conventional P&amp;A operations. For example, the sealing material  279 ,  289  may be about three times as dense as the conventional cement, which may reduce the risk of contamination of the sealing material during deployment, and/or may permit better displacement of wellbore fluids. The sealing material  279 ,  289  may also be substantially not soluble in water or hydrocarbon(s), which may also reduce the risk of contamination. 
     The melted sealing material  273 ,  288  may also not contain particles, such that it may enter small apertures without bridging, as compared to cement. The increased temperature of the melted sealing material  273 ,  288  may also permit removal and/or displacement of water and/or other solid hydrocarbons in the isolation volume. The melted sealing material  273 ,  288  may also have a low viscosity, which may permit more accurate placement in the wellbore. The sealing material of the present disclosure also has a smaller and more controllable setting time, perhaps less than 30 minutes (whereas cement curing can take several hours or days), which may aid in preventing contamination by migrating fluids during the setting process. 
     In view of the entirety of the present disclosure, including the claims and the figures, a person having ordinary skill in the art will readily recognize that the present disclosure introduces a method comprising: (A) conveying a downhole tool within a wellbore, wherein the downhole tool comprises a laser cutting apparatus and a sealing material; (B) operating the laser cutting apparatus to remove material from at least one of: (1) a subterranean formation penetrated by the wellbore; (2) a casing secured within the wellbore; and/or (3) a cement sheath securing the casing within the wellbore; and (C) placing the sealing material in a void created by the material removal. 
     Operating the laser cutting apparatus to remove the material may comprise removing portions of each of the subterranean formation, a member of the casing, and the cement sheath, such that the void completely severs the casing member into two discrete portions. 
     The method may be a plug and abandonment operation, such that placing the sealing material in the void may create a plug fluidly isolating first and second sections of the wellbore on opposing sides of the plug. In such implementations, among others within the scope of the present disclosure, the method may not comprise utilizing a drilling rig. For example, conveying the downhole tool may be via a through-tubing conveyance. Conveying the downhole tool may be via coiled tubing or wireline. 
     The method may further comprise, after the material removal but before the sealing material placement, inducing relative movement of the laser cutting apparatus and the sealing material. 
     Placing the sealing material in the void may comprise operating the downhole tool to melt the sealing material. Placing the sealing material in the void may further comprise directing the melted sealing material into the void. 
     The sealing material may be carried with the downhole tool in particulate form, and placing the sealing material in the void may comprise: directing the sealing material into the slot; and melting the sealing material within the slot. 
     The laser cutting apparatus may comprise a laser beam deflector, and operating the laser cutting apparatus for the material removal may comprise operating the laser cutting apparatus to rotate the laser beam deflector and thereby rotate a laser beam through 360 degrees to create the void as an annular space surrounding the wellbore. In such implementations, placing the sealing material in the void may comprise operating the laser cutting apparatus to direct the laser beam onto the sealing material and rotate the laser beam through 360 degrees to melt an annular portion of the sealing material. The laser beam may melt the sealing material before and/or after the sealing material is in the void. 
     The wellbore may extend from a wellsite surface, and the method may further comprise: communicating a fluid from the wellsite surface to the downhole tool via the coiled tubing; and cleaning the void with the fluid before placing the sealing material in the void. 
     The present disclosure also introduces an apparatus comprising a downhole tool for conveyance within a wellbore, wherein the downhole tool comprises: (A) a laser cutting apparatus operable to remove material from at least one of: (1) a subterranean formation penetrated by the wellbore; (2) a casing secured within the wellbore; and/or (3) a cement sheath securing the casing within the wellbore; (B) a sealing material; and (C) a heating device operable to melt the sealing material. 
     The downhole tool may be operable to form a plug comprising the sealing material in a void created by a material removal operation of the laser cutting apparatus. The plug may fluidly isolate first and second sections of the wellbore on opposing sides of the plug. The downhole tool may be operable to form the plug in the void without removing the downhole tool from the wellbore. The downhole tool may be operable to form the plug in the void without utilizing a drilling rig. 
     The sealing material may be a eutectic material having a eutectic temperature at which the eutectic material melts. 
     The sealing material may comprise a metallic composition meltable downhole via operation of the heating device. 
     The conveyance may be through-tubing conveyance. 
     The conveyance may be via coiled tubing or wireline. 
     The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure. A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same functions and/or achieving the same benefits of the embodiments introduced herein. A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure. 
     The Abstract at the end of this disclosure is provided to permit the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.