Downhole Fishing

Abstract

Apparatus and methods for performing downhole fishing. The apparatus may be a downhole tool having a fishing tool operable to connect with a target component in a wellbore and a plurality of arms each independently deployable into contact with a sidewall of the wellbore to facilitate connection of the fishing tool with the target component by radially moving the fishing tool relative to the target component.

Description

BACKGROUND OF THE DISCLOSURE

Drilling operations have become increasingly expensive as the need to drill deeper, in harsher environments, and through more difficult materials has become a reality. In addition, testing and evaluation of completed and partially finished wellbores has become commonplace, such as to increase well production and return on investment. Consequently, in working with deeper and more complex wellbores, it becomes more likely that downhole tools, tool strings, tubulars, metal junk, and other downhole components may become lost and/or stuck within the wellbore. An item lost or stuck within the wellbore is known in the oil and gas industry as a “fish.”

For example, if a tool string becomes stuck within the wellbore, high tension may be applied from the wellsite surface to disconnect (e.g., via a release tool and/or a severing a designed weak point) a free portion of the tool string located uphole from a stuck portion of the tool string. After the free portion of the tool string is disconnected from the stuck portion, the free portion may be removed to the wellsite surface. A fishing tool string may then be conveyed downhole via a conveyance means (e.g., a wireline, a slickline, coiled tubing, etc.) to connect with and retrieve the stuck portion (i.e., the fish).

A fishing string typically terminates with a fishing tool operable to connect with a fish and may also include a jarring tool for jarring the fish free. The fishing tool may be configured to extend into and latch against an inner portion of the fish, or the fishing tool may be configured to extend around and latch onto an outer portion of the fish. The fishing tool may also be configured to connect with a fishing head or another coupler located on top of the fish. Tension may then be applied from a wellsite surface to the deployed fishing string to pull the fish free. However, if the applied tension is not sufficient to free the fish, tension may be stored in the form of elastic energy in the fishing tool string and the conveyance means. After sufficient amount of tension is applied, the jarring tool may be triggered to release the elastic energy and deliver an impact to dislodge the stuck fish.

Establishing and verifying a successful connection between the fishing tool and an exposed portion of the fish (e.g., the fishing head) is difficult because the precise position of the fish within the wellbore may not be known. For example, the fish may be located at a central location with respect to a sidewall of the wellbore, or the fish may be located off-center, such as against the sidewall of the wellbore. Off-center positioning may be caused by differential sticking and/or gravity, for example, and is often encountered in horizontal or otherwise deviated wells. Fishing strings deployed from the wellsite surface are typically guided by gravity, with no other means for aligning the fishing tools with the fish. Such lack of guidance can result in numerous connection attempts, which may last hours or even days until successful connection between the fishing tool and the fish is established.

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 an apparatus including a downhole tool that includes a fishing tool and multiple arms. The fishing tool is operable to connect with a target component in a wellbore. The arms are each independently deployable into contact with a sidewall of the wellbore to facilitate connection of the fishing tool with the target component by radially moving the fishing tool relative to the target component.

The present disclosure also introduces an apparatus including a downhole tool that includes a member, a fishing tool, and multiple arms. The fishing tool is coupled with the member and is operable to connect with a target component in a wellbore. The arms are each coupled with the member and are independently deployable into contact with a sidewall of the wellbore, thereby facilitating connection of the fishing tool with the target component by radially moving the fishing tool relative to the target component.

The present disclosure also introduces a method including conveying a downhole tool within a wellbore from a wellsite surface to a target component in the wellbore. The downhole tool includes a fishing tool and multiple arms. The arms are operated to move into contact with a sidewall of the wellbore to facilitate connection of the fishing tool with the target component. The method also includes connecting the fishing tool with the target component, and then retrieving the downhole tool and the target component to the wellsite surface.

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 is best 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 view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 3 is a schematic view of a portion of an example implementation of the apparatus shown in FIG. 2 according to one or more aspects of the present disclosure.

FIG. 4 is a schematic view of the apparatus shown in FIG. 3 at a different stage of operation according to one or more aspects of the present disclosure.

FIG. 5 is an axial view of the apparatus shown in FIG. 2 according to one or more aspects of the present disclosure.

FIG. 6 is an axial view of the apparatus shown in FIG. 3 at a different stage of operation according to one or more aspects of the present disclosure.

FIG. 7 is an axial view of the apparatus shown in FIG. 4 at another stage of operation according to one or more aspects of the present disclosure.

FIGS. 8-10 are axial views of example operations according to one or more aspects of the present disclosure.

FIG. 11 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.

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 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.

FIG. 1 is a schematic view of at least a portion of an example implementation of a wellsite system 100 to which one or more aspects of the present disclosure may be applicable. The wellsite system 100, which may be situated onshore or offshore, comprises a downhole tool string 110 suspended within a wellbore 102 that extends from a wellsite surface 106 into one or more subterranean formations 104. The tool string 110 may be suspended within the wellbore 102 via a conveyance means 112 operably coupled with a tensioning device 114 and/or other surface equipment 116 disposed at the wellsite surface 106. The wellbore 102 may be lined with a casing 108 secured by cement 109. However, one or more aspects of the present disclosure may be applicable to and/or readily adaptable for utilizing in an open-hole wellbore lacking the casing 108 and cement 109.

The tensioning device 114 may be operable to apply an adjustable tensile force to the tool string 110 via the conveyance means 112 to convey the tool string 110 within the wellbore 102. The tensioning device 114 may be, comprise, or form at least a portion of a crane, a winch, a drawworks, an injector, a top drive, and/or other lifting device coupled to the tool string 110 via the conveyance means 112. The conveyance means 112 may be or comprise a cable, a wireline, a slickline, an e-line, a coiled tubing, production tubing, and/or other conveyance means spooled at the wellsite surface 106, such as by or in conjunction with the tensioning device 114.

The conveyance means 112 may comprise and/or be operable in conjunction with means for communication between the tool string 110, the tensioning device 114, and/or one or more other portions of the surface equipment 116, including a surface control system 118. For example, a multi-conductor cable (generally called a wireline cable), hereinafter referred to as a conductor 120, may extend through the conveyance means 112 and at least partially within the tool string 110 and surface equipment 116. The conductor 120 may permit electrical power transfer between the surface equipment 116 and the tool string 110. The conductor 120 may also facilitate electrical and/or optical signal communication between one or more components of the surface equipment 116, including the surface control system 118, and one or more portions of the tool string 110, including a downhole control system 122. However, the conveyance means 112 may instead be a single wire cable or slickline. The wire may be covered by an insulation, with no additional conductors. The slickline may be utilized as an electrical conductor between the tool string 110 and surface equipment 116, and electrically coupled with the casing 108 utilized as the ground. There might be a contact between the tools string 110 and the casing 108 and/or surface equipment 116 as described for instance in patent U.S. Pat. No. 7,652,592 or the coupling may be capacitive coupling. In the following, such cable will be designated as a digital slickline. The digital slickline may thus facilitate electrical signal communication between the tool string 110 and the surface equipment 116 without utilizing multiple electric or other conductors, such as the conductor 120, extending between the tool string 110 and the surface equipment 116.

The tool string 110, the conveyance means 112, the tensioning device 114, the surface equipment 116, and/or other portions of the wellsite system 100 may be collectively operable to connect with and retrieve to the wellsite surface 106 a downhole tool, a tool string, a drill pipe or another tubular, metal junk, downhole equipment, and/or another target downhole component 124 that is dropped, lost, or stuck within the wellbore 102. As described above, a downhole component that is dropped, lost, or stuck within a wellbore is known in the oil and gas industry as a “fish.” Accordingly, the target downhole component 124 is referred to hereinafter as the “fish 124.”

The tool string 110 may comprise one or more downhole tools, subs, modules, and/or other apparatuses operable in wireline, coiled tubing, completion, production, and/or other operations. For example, the tool string 110 may comprise a cable head 126, a telemetry/control tool 128, a lateral positioning tool 130, and a fishing tool 132. The tool string 110 may also comprise additional subs, modules, or tools 140, 142 at various locations along the tool string 110, each of which may perform various functions while performing downhole operations within the scope of the present disclosure. For example, the tool string 110 may further comprise one or more of an acoustic tool, a density tool, a directional tool, an electromagnetic (EM) tool, a fluid power tool, a fluid sampling tool, a formation logging tool, a formation testing tool, a gravity tool, a jarring tool, a magnetic resonance tool, a mechanical interface tool, a monitoring tool, a neutron tool, a nuclear tool, a photoelectric factor tool, a porosity tool, a power module, a release tool, a reservoir characterization tool, a resistivity tool, a seismic tool, a stroker tool, and/or a surveying tool, among other examples also within the scope of the present disclosure.

Each of the cable head 126, the telemetry/control tool 128, and the lateral positioning tool 130 may be electrically connected to the conductor 120 for instance via the cable head. The conductor 120 may include various electrical and/or optical connectors or interfaces (not shown), such as may facilitate connection between the conductor 120 and the tool string 110 to permit communication between one or more of the tools 126, 128, 130, 140, 142 and one or more components of the surface equipment 116, including the surface control system 118. For example, the conductor 120 may be operable to transfer electrical power, data, and/or control signals between the surface equipment 116 and one or more of the tools 126, 128, 130, 140, 142.

The cable head 126 may be operable to connect the conveyance means 112 with the tool string 110. The telemetry/control tool 128 may facilitate communication between the tool string 110 and the surface equipment 116 and/or control of one or more portions of the tool string 110. The telemetry/control tool 128 may comprise the downhole control system 122 communicatively coupled to the surface equipment 116, including the surface control system 118, via the conductor 120. However, the telemetry/control tool 128 may instead utilize digital slickline telemetry to facilitate communication between the tool string 110 and the surface equipment 116 if the conveyance means 112 is a digital slickline.

The surface and downhole control systems 118, 122 may each comprise a processing device (e.g., a computer) and a memory operable to store programs or instructions that, when executed by the processing device, may cause the tool string 110 and/or the surface equipment 116 to perform methods, processes, and/or routines described herein. The surface and/or the downhole control systems 118, 122 may also include various electronic components, such as an interface for receiving commands from the wellsite operator. The downhole control system 122 may be operable to receive control commands from the surface control system 118 for controlling the tools 126, 128, 130, 140, 142 and other components of the tool string 110 from the wellsite surface 106. The surface and downhole control systems 118, 122 may operate independently or cooperatively to control one or more portions of the tool string 110. The surface and/or downhole control systems 118, 122 may also receive, store, and/or process measurements and other data obtained from various sensors of the tool string 110, and store and/or communicate the processed measurements and other data to the surface equipment 116 for subsequent analysis.

The tool string 110 may terminate with the fishing tool 132 configured to connect with (e.g., grab, latch, engage, etc.) the fish 124. The fishing tool 132 may be implemented as an inside grappling device (e.g., a spear) having a tapered outer profile (e.g., threads, barbs, slips, etc.) configured to be inserted into and latch against an inner profile or surface of the fish 124. The fishing tool 132 may instead be implemented as an outside grappling device (e.g., an overshot) having a bell-shaped housing with an inner profile configured to extend around (i.e., swallow) and latch onto an outer profile or surface of the fish 124.

The lateral positioning tool 130 may comprise a body 134 (e.g., a housing, a chassis, a mandrel, another rigid internal or external structural component or member, etc.) and a plurality of arms 136 each operable to deploy into contact with a sidewall 103 of the wellbore 102 to facilitate connection of the fishing tool 132 with the fish 124 by laterally (i.e., radially, transversely, perpendicularly) moving the fishing tool 132 relative to the fish 124. Each arm 136 may be operable to move radially (i.e., laterally) with respect to the body 134 and/or a central axis 111 of the tool string 110 along a plane coincident with the central axis 111 of the tool string 110. The arms 136 may be operable to move against the sidewall 103 to collectively move at least a portion of the tool string 110, including the fishing tool 132, laterally with respect to a central axis 101 of the wellbore 102 along a plane 105 coincident with a diameter 113 of the wellbore 102, as indicated by arrows 107, to facilitate connection of the fishing tool 132 with the fish 124. The plane 105 also extends laterally through the wellbore 102 and the axis 101. The arms 136 may be independently movable to collectively align the fishing tool 132 with the fish 124 to permit the fishing tool 132 to connect with the fish 124 and, thus, permit the tensioning device 114 to retrieve the tool string 110 and the fish 124 to the wellsite surface 106. Although the lateral positioning tool 130 is shown comprising two arms 136, it is to be understood that the lateral positioning tool 130 within the scope of the present disclosure may include three, four, or more arms 136, each operable to extend against the sidewall 103.

The fishing tool 132 may be directly coupled with the body 134 of the lateral positioning tool 130 or the fishing tool 132 may be indirectly coupled with the body 134 via an intermediate tool or module, such as the tool 140. Also, individually or collectively, the arms 136 may be directly coupled with the body 134 of the lateral positioning tool 130, or the arms 136 may be indirectly coupled with the body 134 via intermediate tools, modules, components, or other members, such as connectors, brackets, slides, gears, or other mechanical members.

The subs, modules, or tools 140, 142 may also include a power module operable to provide power to operate the lateral positioning tool 130 and/or other portions of the tool string 110. For example, the power module may be or comprise a hydraulic power pack, which may be operable to supply hydraulic power to the lateral positioning tool 130. The hydraulic power pack may provide a pressurized hydraulic fluid to various actuators operable to extend and retract the arms 136, as described above. The power module may also or instead be or comprise an electrical power source, such as a battery. In such implementations, the battery may provide electrical power to the various actuators operable to extend and retract the arms 136, as described above. The power module may also be omitted from the tool string 110, such as in implementations in which the hydraulic and/or electrical power is provided from the wellsite surface 106 via the conveyance means 112.

After the fishing tool 132 is aligned with the fish 124, the fishing tool 132 may be moved in a downhole direction such that the fishing tool 132 engages and connects with the fish 124. The fishing tool 132 may be moved in the downhole direction by conveying the tool string 110 in the downhole direction via the tensioning device 114 and the conveyance means 112 until the fishing tool 132 connects with the fish 124. However, the fishing tool 132 may also or instead be moved in the downhole direction via an axial positioning tool 140, which may be included in the tool string 110 uphole from the fishing tool 132 to move the fishing tool 132 in the downhole direction. The axial positioning tool 140 may be or comprise a linear actuator, such as a ram or a stroker tool, operable to move the fishing tool 132 and other tools coupled downhole from the axial positioning tool 140 axially along the wellbore 102 until the fishing tool 132 engages and connects with the fish 124. The axial positioning tool 140 may also or instead be or comprise a downhole tractor utilizing rotating drives or an inchworm principle with two or more sections alternatingly gripping the sidewall 103 and resetting to move the tool string 110 axially along the wellbore 102 until the fishing tool 132 engages and connects with the fish 124.

After the fishing tool 132 connects with the fish 124, tension may be applied by the tensioning device 114 via the conveyance means 112 to pull the fish 124 free. However, if the applied tension is not sufficient to free the fish 124, a jarring tool 142 included in the tool string 110 uphole from the fishing tool 132, may be utilized to help free the fish 124. During jarring operations, tension applied from the wellsite surface 106 may be stored in the form of elastic energy in the tool string 110 and the conveyance means 112. After sufficient tension is applied at the jarring tool 142, the jarring tool 142 may be triggered to release the elastic energy and deliver an upward or downward impact to the fishing tool 132 and the fish 124 connected with the fishing tool 132 to dislodge the stuck fish 124. After the fish 124 becomes free, the tool string 110 and the fish 124 may be retrieved to the wellsite surface 106.

FIG. 2 is a schematic side view of an example implementation of a tool string 200 according to one or more aspects of the present disclosure. The tool string 200 comprises one or more similar features of the tool string 110 described above and shown in FIG. 1, including where indicated by like reference numbers, except as described below. The tool string 200 is shown disposed within a vertical portion of the wellbore 102 and connected with the surface equipment 116 (shown in FIG. 1) via the conveyance means 112. However, it is to be understood that the tool string 200 may also be utilized within a substantially horizontal or otherwise deviated portion of the wellbore 102. The following description refers to FIGS. 1 and 2, collectively.

The tool string 200 may comprise a cable head 126, a telemetry/control tool 128 containing a downhole control system 122, a lateral positioning tool 210, an axial positioning tool 211, and a fishing tool 212. The conveyance means 112 and the tool string 200 may contain a conductor 120 extending between the surface equipment 116 and the tool string 200 to communicatively connect the wellsite equipment 116, including the surface control system 118, with the various tools 126, 128, 210, 211 of the tool string 200, including the downhole control system 122. Although not shown, the tool string 200 may comprise other tools or modules described above, including a power module and/or a jarring tool.

The tool string 200, the conveyance means 112, the tensioning device 114, the surface equipment 116 may be collectively operable to connect with and retrieve a fish 220 lost and/or stuck within the wellbore 102. The tool string 200 may terminate with the fishing tool 212 configured to connect with (e.g., grab, latch, engage, etc.) the fish 220. The fishing tool 212 may be implemented, for example, as an outside grappling device (e.g., an overshot) having a bell-shaped housing with a receptacle 222 configured to extend around (i.e., swallow) and latch onto an outer profile or surface of the fish 220. For example, the receptacle 222 may be configured to extend around and latch onto a fishing head 224 or another coupler located at a top end of the fish 220. Fishing heads, such as the fishing head 224, may be included at one or more locations within a tool string conveyed within a wellbore. If the tool string becomes stuck, a free portion of the tool string may be uncoupled from a stuck portion of the tool string exposing one of the fishing heads. After the free portion of the tool string is retrieved to a wellsite surface, a fishing tool string, such as the tool string 200, terminating with a fishing tool may be deployed into the wellbore and connected with the exposed fishing head to connect the fishing tool string with the stuck portion of the tool string. The stuck portion of the tool string may then be retrieved to the wellsite surface.

The lateral positioning tool 210 may be operable to move at least a portion of the tool string 200, including the fishing tool 212, radially with respect to the fish 220, as indicated by arrows 206, to axially align the fishing tool 212 with the fishing head 224. The lateral positioning tool 210 may comprise a body 214 and a plurality of arms 216 each operable to extend away from and retract toward the body 214 (i.e., move radially or laterally with respect to a central axis 202 of the tool string 200) against a sidewall 103 (e.g., casing 108, rock formation 104) of the wellbore 102, as indicated by arrows 204, to move the fishing tool 212 laterally (i.e., in a transverse or perpendicular direction) with respect to the longitudinal axis 101 of the wellbore 102, as indicated by arrows 206. Each arm 216 may terminate with a roller or another contact member 218 operable to roll, slide, or otherwise reduce friction between the arms 216 and the sidewall 103 of the wellbore 102. The friction reducing contact members 218 may permit the tool string 200, including the fishing tool 212, to move axially (e.g., roll, slide) along the wellbore 102, such as during searching operations utilizing the tensioning device 114 to move the fishing tool 212 axially along the wellbore 102, as described below. Although the lateral positioning tool 210 is shown comprising three arms 216, it is to be understood that the lateral positioning tool 210 within the scope of the present disclosure may include four, or more arms 216 operable to extend against the sidewall 103. Furthermore, instead of the arms 216 comprising the friction reducing contact members 218, the arms 216 may comprise friction increasing contact members 218, such as barbs or slips, which may anchor or otherwise reduce movement of at least a portion of the tool string 200 within the wellbore 102, such as during searching operations utilizing the axial positioning tool 211 to move the fishing tool 212 axially along the wellbore 102, as described below.

The lateral positioning tool 210 may further comprise a plurality of actuators 228 each operably connected with a corresponding arm 216 and operable to independently extend and retract the corresponding arm 216 to move the tool string 200 laterally within the wellbore 102. The actuators 228 may be or comprise hydraulic rams, hydraulic motors, linear electric motors, and/or rotary electric motors, among other examples. The lateral positioning tool 210 may further comprise a plurality of position sensors 230 each operable to generate a signal or information indicative of lateral position (i.e., radial position, extension) and/or velocity of a corresponding arm 216 to monitor the lateral position and/or velocity of the fishing tool 212 within the wellbore 102. Each sensor 230 may be disposed in association with the corresponding arm 216 and/or actuator 228 in a manner permitting sensing of the position and/or velocity of the arm 216. The sensors 230 may be or comprise linear encoders, linear potentiometers, capacitive sensors, inductive sensors, magnetic sensors, linear variable-differential transformers (LVDT), proximity sensors, Hall effect sensors, and/or reed switches, among other examples.

The axial positioning tool 211 may be included in the tool string 200 uphole from the fishing tool 212 to move the fishing tool 212 in downhole and uphole directions along and/or with respect to the central axes 101, 202 of the wellbore 102 and the tool string 200, as indicated by arrows 208, 209. The axial positioning tool 211 may be or comprise a linear actuator, such as a ram or a stroker tool, operable to move the fishing tool 212 axially along the wellbore 102 until the fishing tool 212 engages the fish 124.

The tool string 200 may also comprise one or more tension sensors 232 (e.g., a load cell, a strain gauge) each operable to generate a signal or information indicative of a tension imparted to or otherwise experienced by one or more portions of the tool string 200. A tension sensor 232 may be mounted within or otherwise disposed in association with the cable head 126, such as may permit the tension sensor 232 to monitor tension applied to the tool string 200 from the wellsite surface 106 by the tensioning device 114 via the conveyance means 112. A tension sensor 232 may also or instead be mounted within or otherwise disposed in association with the axial positioning tool 211, such as may permit the tension sensor 232 to monitor tension applied to the fishing tool 212 by the axial positioning tool 211 and/or by the tensioning device 114 via the conveyance means 112.

The tensioning device 114, the axial positioning tool 211, the actuators 228, the position sensors 230, and the tension sensors 232 may be communicatively connected with the surface and/or downhole control systems 118, 122 via the conductor 120. Accordingly, the axial and lateral positioning of the fishing tool 212 within the wellbore 102 may be automatically controlled by the surface and/or downhole control systems 118, 122 and/or manually controlled by the wellsite operator from the wellsite surface 106. The signals or information generated by the position sensors 230 may be telemetered and/or otherwise communicated to the surface and/or downhole control systems 118, 122 to provide position feedback to the control systems 118, 122 and/or to the wellsite operator controlling the operations of the tool string 200. Similarly, the signals or information generated by the tension sensors 232 may be telemetered and/or otherwise communicated to the surface and/or downhole control systems 118, 122 to provide tension feedback to the control systems 118, 122 and/or to the wellsite operator controlling the operations of the tool string 200, such as may be utilized to determine if the fishing tool 212 connected with the fish 220 and/or to determine if the fish 220 became free. Alternatively or additionally, other sensors may be used in the tool string for determining if the fishing is successful. A camera taking an image of the fishing head may for instance be added to the tool string and used for that purpose.

FIGS. 3 and 4 are schematic views of a portion of an example implementation of the lateral positioning tool 210 shown in FIG. 2, in different stages of operation according to one or more aspects of the present disclosure. FIG. 3 shows one of the arms 216 of the lateral positioning tool 210 in a retracted position, in which the arm 216 is disposed against the body 214 of the lateral positioning tool 210. FIG. 4 shows the arm 216 in an extended position, in which the arm 216 is disposed a predetermined or otherwise intended distance 213 away from the body 214. The following description refers to FIGS. 1-4, collectively.

The arm 216 may comprise an upper arm portion 215 and a lower arm portion 217. A lower end of the upper arm portion 215 and an upper end of the lower arm portion 217 are pivotally connected together via a connector 219 (e.g., a pivot pin) and/or other connection means. The contact member 218 (e.g., a friction-reducing contact member or a friction-increasing contact member) may be operatively connected at the pivot connection to permit or prevent axial movement of the lateral positioning tool 210 along the wellbore 102, as described herein. A lower end of the lower arm portion 217 may be pivotally connected with a lower portion of the body 214 via, for example, a pivot hole (i.e., an eye) (obstructed from view) located at or adjacent the lower portion of the body 214. The pivot hole may extend through the body 214 or be connected with the body 214 via a pivot mounting bracket 221 (e.g., a clevis or eye bracket) fixedly connected with the body 214 and comprising the pivot hole. A connector 223 (e.g., a pivot pin) may be connected with the lower end of the lower arm portion 217 and disposed within the pivot hole to pivotally connect the lower arm portion 217 with the bracket 221. An upper end of the upper arm portion 215 may be slidably connected with an upper portion of the body 214, for example, via an elongated slot 227 extending axially at or adjacent the upper portion of the body 214. The slot 227 may extend through the body or be connected with the body 214 via a mounting bracket 225 fixedly connected with the body 214 and comprising the elongated slot 227. A connector 229 (e.g., a pivot pin) may be connected with the upper end of the upper arm portion 215 and slidably disposed within the elongated slot 227 to slidably connect the upper arm portion 215 with the mounting bracket 225.

The combination of the pivoting and sliding actions of the upper and lower arm portions 215, 217 permit the arm 216 to be moved between the retracted and extended positions via a corresponding actuator 228. The actuator 228 may be disposed within or otherwise connected with the body 214 and comprise an actuating portion 231 selectively operable to extend and retract an actuated portion 233 (e.g., a rod, a shaft) out of, into, or otherwise with respect to the actuating portion 231. The actuating portion 231 may be or comprise, among other examples, a hydraulic cylinder, a hydraulic motor, or an electric motor operatively connected with the actuated portion 233, such as via a piston or a gear assembly, to permit the actuating portion 231 to selectively drive or otherwise actuate the actuated portion 233. A linking member 235 may connect the actuated portion 233 with the upper arm portion 215. For example, the linking member 235 may be connected with the connector 229 to connect the actuated portion 233 with the upper end of the upper arm portion 215. Although the actuated portion 233 and the linking member 235 are shown as distinct items, it is to be understood that the actuated portion 233 and the linking member 235 may be or comprise a single member or item operatively connecting the actuating portion 231 with the upper arm portion 215.

The actuator 228 may be selectively operable to independently extend the corresponding arm 216 a predetermined or otherwise intended distance away from the body 214 to move the tool string 200, including the fishing tool 212, to a predetermined or otherwise intended lateral position within the wellbore 102. As shown in FIG. 4, the actuating portion 231 may retract the actuated portion 233, as indicated by arrow 237, by an intended distance, thereby moving the upper end of the upper arm portion 215 along the elongated slot 227 causing the arm 216 and the contact member 218 to extend laterally, as indicated by arrow 239, to an intended lateral position. As shown in FIG. 3, the actuating portion 231 may also extend the actuated portion 233, as indicated by arrow 241, by an intended distance to laterally retract the arm 216 and the contact member 218, as indicated by arrow 243, to the retracted position or another intended lateral position.

FIGS. 5-7 are schematic axial views of the tool string 200 shown in FIG. 2, in different stages of operation according to one or more aspects of the present disclosure. The following description refers to FIGS. 1, 2, and 5-7, collectively.

FIGS. 2 and 5 show the fish 220 located along the central axis 101 of the wellbore 102. Accordingly, the actuators 228 may be operated to extend the arms 216 the same amount against the sidewall 103 to centralize the fishing tool 212 and, thus, permit the receptacle 222 to receive and latch onto the fishing head 224. However, if the fish 220 is located off-center within the wellbore 102, the arms 216 may be extended by different amounts to axially align the fishing tool 212 with the fish 220. As described above, the arms 216 may be independently movable to collectively axially align the central axis 202 of the tool string 200, including the fishing tool 212, with a central axis 226 of the fish 124, including the fishing head 224, to facilitate or otherwise permit the fishing head 224 to be received within the receptacle 222 and, thus, latch the fishing tool 212 with the fish 220. The fishing tool 212 may be substantially, but not necessarily perfectly axially aligned with the fish 220 to permit connection between the fishing tool 212 and the fish 220. The fishing tool 212 and the fish 220 may be substantially axially aligned if such alignment is sufficient to permit engagement and connection between the fishing tool 212 and the fish 220. For example, the fishing tool 212 and the fish 220 may be substantially axially aligned if such alignment is sufficient to permit tapered surfaces of the fishing tool 212 and/or fishing head 224 to guide the fishing tool 212 laterally, as indicated by the arrows 206, while the tool string 200 is moving axially toward the fish 220, as indicated by the arrow 208, until the receptacle 222 is disposed about and connected with the fishing head 224.

As shown in FIG. 6, if the fish 220 is determined or predicted to be located off-center within the wellbore 102, the actuators 228 may be operated independently to extend the corresponding arms 216 by different amounts to align the fishing tool 212 with the fish 220. For example, one arm 216 may be extended by a small amount, as indicated by arrow 234, another arm 216 may be extended by a larger amount, as indicated by arrow 236, and the last arm 216 may be extended by a largest amount, as indicated by arrow 238, to collectively move the fishing tool 212 laterally within the wellbore 102, as indicated by arrow 240, into alignment with the fish 220.

As shown in FIG. 7, if the fish 220 is determined or predicted to be located against the sidewall 103 of the wellbore 102, the actuators 228 may be operated independently to extend the corresponding arms 216 by different amounts to align the fishing tool 212 with the fish 220. For example, one arm 216 may be fully retracted or remain fully retracted and the other arms 216 may be extended into contact with the sidewall 103, as indicated by arrows 242, to collectively move the fishing tool 212 laterally against the sidewall 103, as indicated by arrow 244, into alignment with the fish 220.

FIGS. 8-10 are schematic axial views of the fishing tool 212 at different lateral positions within the wellbore 102 according to one or more aspects of the present disclosure. The following description refers to FIGS. 1-10, collectively.

The tool string 200 may be utilized to retrieve a fish 220 whose lateral position within the wellbore 102 is detected or otherwise known. As shown in FIG. 8, while the tool string 200 is being conveyed downhole toward the fish 220 or after the tool string 200 is conveyed downhole to a close proximity with the fish 220, the arms 216 of the lateral positioning tool 210 may be operated to move the fishing tool 212 laterally with respect to the fish 220 to any one of a plurality of lateral positions within the wellbore 201, as indicated by arrows 206, 246, where the fish 220 is detected or otherwise known to be located. After the fishing tool 212 is aligned with the fish 220, the fishing tool 212 may be lowered in an attempt to connect with the fish 220. The fishing tool 212 may be further lowered via the conveyance means 112 by operating the tensioning device 114 causing the tool string 200, including the fishing tool 212, to roll or slide axially in the downhole direction along the wellbore 102, as indicated by the arrow 208, with the help of the friction reducing contact members 218 until the fishing tool engages the fish 220. The fishing tool 212 may instead be further moved axially in the downhole direction via the axial positioning tool 211, as indicated by the arrow 208, while the tool string 200 is anchored against the sidewall 103 of the wellbore 102 via the friction increasing contact members 218 until the fishing tool engages the fish 220. If the connection is successful, tension may be applied to the tool string 110 by the tensioning device 114 via the conveyance means 112 to free the fish 220 and retrieve the fish 220 to the wellsite surface 106.

A successful connection between the fishing tool 212 and the fish 220, as well as whether the fish 220 was pulled free, may be verified by monitoring the tension sensors 232. For example, if the fishing tool 212 was moved downhole into engagement with the fish 220 via the conveyance means 112, the tensioning device 114 may then be operated to apply tension to the tool string 200 and the fish 220 via the conveyance means 112 in the uphole direction. A progressive increase in tension indicated by the tension sensor 232 at the cable head 126 may be indicative of a successful connection of the fishing tool 212 with the fish 220, however, a substantially steady or unchanged tension at the cable head 126 may be indicative of a failed connection. If the fishing tool 212 was moved downhole into engagement with the fish 220 via the axial positioning tool 211, the axial positioning tool 211 may be retracted in the uphole direction to apply tension to the tool string 200 and the fish 220. A progressive increase in tension indicated by the tension sensor 232 at axial positioning tool 211 may be indicative of a successful connection of the fishing tool 212 with the fish 220, however, a substantially steady or unchanged tension at the axial positioning tool 211 may be indicative of a failed connection. If the connection is determined to be successful, tension may be applied to the tool string 110 and the connected fish 220 by the tensioning device 114 via the conveyance means 112 to free and retrieve the fish 220 to the wellsite surface 106. A progressive increase in tension indicated by the tension sensor 232 at the cable head 126 or the axial positioning tool 211 followed by a sudden decrease in the tension may be indicative that the fish 220 was pulled free. As indicated above, other sensors may also be used in order to determine if the connection was successful.

The tool string 200 may also be utilized to “search” for a fish 220 whose lateral position within the wellbore 102 is predicted (i.e., estimated) or not known. As shown in FIG. 9, while the tool string 200 is being conveyed downhole toward the fish 220 or after the tool string 200 is conveyed downhole to a close proximity with the fish 220, the arms 216 of the lateral positioning tool 210 may be operated to move the fishing tool 212 to an intended lateral position 250 within the wellbore 201 where the fish 220 is predicted to be located. After the fishing tool 212 is aligned with the intended lateral position 250 of the fish 220, the fishing tool 212 may be lowered via the tensioning device 114 or the axial positioning tool 211, as indicated by the arrow 208, in an attempt to connect with the fish 220. If the connection is successful, tension may be applied to the tool string 110 and the fish 220 by the tensioning device 114 to retrieve the fish 220 to the wellsite surface 106. However, if the attempted connection failed, the fishing tool 212 may be moved uphole via the tensioning device 114 or the axial positioning tool 211 by a predetermined incremental axial distance, as indicated by the arrow 209, such as by retracting the axial positioning tool 211. Thereafter, the arms 216 of the lateral positioning tool 210 may be operated again to move the fishing tool 212 laterally, as indicated by arrows 206, by a predetermined incremental lateral distance to another lateral position within the wellbore 201 where the fish 220 is predicted to be located and connection may be attempted again. Such process may be repeated as the fishing tool 212 is moved incrementally along a predetermined lateral search path 248 until connection between the fishing tool 212 and the fish 220 is successful. As shown in FIG. 9, the intended lateral position 250 where the first attempt at connection is made may be a central position within the wellbore 102 and the search path 248 along which the subsequent connection attempts are made may be a spiral search path. However, the searching operations may be started at different lateral positions within the wellbore 102 and the search paths may comprise different geometries.

As shown in FIG. 10, the searching operations may be initiated at an intended lateral position 252 that is in close proximity to or against the sidewall 103 of the wellbore 102 where the fish 220 is predicted to be located. After the fishing tool 212 is aligned with the predicted location 252 of the fish 220, the fishing tool 212 may be lowered in an attempt to connect with the fish 220, as indicated by the arrow 208. If the connection is successful, tension may be applied to the tool string 110 and the fish 220 by the tensioning device 114 from the wellsite surface 106 to retrieve the fish 220 to the wellsite surface 106. However, if the attempted connection failed, the arms 216 of the lateral positioning tool 210 may be operated to move the fishing tool 212 laterally by a predetermined incremental lateral distance to another lateral position within the wellbore 201 and connection may be attempted again. The searching operations may be performed along an alternating (e.g., zig-zag) search path 254 until connection between the fishing tool 212 and the fish 220 is successful. The searching operations may be started along the sidewall 103, for example, if the fish 220 is stuck against the sidewall 103 due to differential pressure sticking or if gravity caused the fish 220 to move toward or into contact with the sidewall 103, such as in horizontal or otherwise deviated wellbores 102.

Various portions of the apparatus described above and shown in FIGS. 1-10, may collectively form and/or be controlled by a control system, such as may be operable to monitor, cause, and/or otherwise facilitate the methods and operations of the wellsite system 100, including the tool string 200, as described above. FIG. 11 is a schematic view of at least a portion of an example implementation of such a control system 300 according to one or more aspects of the present disclosure. The following description refers to one or more of FIGS. 1-11.

The control system 300 may comprise a controller 310, which may be in communication with various portions of the wellsite system 100, including the tensioning device 114 and the various portions of the tool string 200 described within the scope of the present disclosure. For example, the controller 310 may be in signal communication with the actuators 228 to operate the arms 216 of the fishing tool 212, the position sensors 230, the tension sensors 232, the axial positioning tool 211, the jarring tool 142, the tensioning device 114, and/or other actuators and sensors of the wellsite system 100 and the tool string 200. For clarity, these and other components in communication with the controller 310 will be collectively referred to hereinafter as “actuator and sensor equipment.” The controller 310 may be operable to receive coded instructions 332 from the wellsite operator and signals generated by the position sensors 230 and the tension sensors 232, process the coded instructions 332 and the signals, and communicate control signals to the actuators 228, the axial positioning tool 211, the jarring tool 142, and/or the tensioning device 114, to execute the coded instructions 332 to implement at least a portion of one or more example methods and/or processes described herein, and/or to implement at least a portion of one or more of the example systems described herein. The controller 310 may also or instead cause the signals generated by the position sensors 230 and the tension sensors 232 to be displayed on an output device to be viewed by the wellsite operator, such as may permit the wellsite operator to manually control the actuators 228, the axial positioning tool 211, the jarring tool 142, and/or the tensioning device 114 to implement at least a portion of one or more example methods and/or processes described herein. The controller 310 may be or comprise one or more of the surface and downhole control systems 118, 122 described above.

The controller 310 may be or comprise, for example, one or more processors, special-purpose computing devices, servers, personal computers (e.g., desktop, laptop, and/or tablet computers) personal digital assistant (PDA) devices, smartphones, internet appliances, and/or other types of computing devices. The controller 310 may comprise a processor 312, such as a general-purpose programmable processor. The processor 312 may comprise a local memory 314, and may execute coded instructions 332 present in the local memory 314 and/or another memory device. The processor 312 may execute, among other things, the machine-readable coded instructions 332 and/or other instructions and/or programs to implement the example methods and/or processes described herein. The programs stored in the local memory 314 may include program instructions or computer program code that, when executed by an associated processor, facilitate the wellsite system 100 and the tool string 200 to perform the example methods and/or processes described herein. The processor 312 may be, comprise, or be implemented by one or more processors of various types suitable to the local application environment, and may include one or more of general-purpose computers, 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. Of course, other processors from other families are also appropriate.

The processor 312 may be in communication with a main memory 317, 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), RAIVIBUS 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 non-volatile memory 320.

The controller 310 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 cellular interface, and/or a satellite interface, among others. The interface circuit 324 may also comprise a graphics driver card. The interface circuit 324 may also comprise a communication 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 of the actuator and sensor equipment may be connected with the controller 310 via the interface circuit 324, such as may facilitate communication between the actuator and sensor equipment and the controller 310.

One or more input devices 326 may also be connected to the interface circuit 324. The input devices 326 may permit the wellsite operator to enter the coded instructions 332, including control commands, operational set-points, and/or other data for use by the processor 312. The operational set-points may include, as non-limiting examples, search start positions 250, 252, search paths 248, 254, predicted axial and lateral positions of the fish 220, and tension thresholds for determining whether the fishing tool 212 is successfully connected with the fish 220 and whether the fish 220 is pulled free. The input devices 326 may be, comprise, or be implemented by a keyboard, a mouse, a touchscreen, a track-pad, a trackball, an isopoint, and/or a voice recognition system, among other examples.

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 display devices (e.g., a liquid crystal display (LCD), a light-emitting diode (LED) display, or cathode ray tube (CRT) display), printers, and/or speakers, among other examples. The controller 310 may also communicate with one or more mass storage devices 330 and/or a removable storage medium 334, such as may be or include floppy disk drives, hard drive disks, compact disk (CD) drives, digital versatile disk (DVD) drives, and/or USB and/or other flash drives, among other examples.

The coded instructions 332 may be stored in the mass storage device 330, the main memory 317, the local memory 314, and/or the removable storage medium 334. Thus, the controller 310 may be implemented in accordance with hardware (perhaps implemented in one or more chips including an integrated circuit, such as an ASIC), or may be implemented as software or firmware for execution by the processor 312. In the case of firmware or software, the implementation may be provided as a computer program product including a non-transitory, computer-readable medium or storage structure embodying computer program code (i.e., software or firmware) thereon for execution by the processor 312.

The coded instructions 332 may include program instructions or computer program code that, when executed by the processor 312, may cause the wellsite system 100, including the actuators 228, the axial positioning tool 211, the jarring tool 142, and/or the tensioning device 114, to perform methods, processes, and/or routines described herein. For example, the controller 310 may receive, process, and record the operational set-points entered by the wellsite operator and the signals generated by the sensors 230, 232. Based on the received operational set-points and the signals generated by the sensors 230, 232, the controller 310 may send signals or information to the actuators 228, the axial positioning tool 211, the jarring tool 142, and the tensioning device 114 and/or other portions of the wellsite system 100 to automatically perform and/or undergo one or more operations or routines described herein or otherwise within the scope of the present disclosure. The controller 310 may also or instead cause the signals generated by the position sensors 230 and the tension sensors 232 to be displayed on the output device 328 to be viewed by the wellsite operator, such as may permit the wellsite operator to manually control the actuators 228, the axial positioning tool 211, the jarring tool 142, and/or the tensioning device 114 to implement at least a portion of one or more example methods and/or processes described herein.

In view of the entirety of the present application, including the figures and the claims, a person having ordinary skill in the art will readily recognize that the present disclosure introduces an apparatus comprising a downhole tool comprising: a fishing tool operable to connect with a target component in a wellbore; and a plurality of arms each independently deployable into contact with a sidewall of the wellbore to facilitate connection of the fishing tool with the target component by radially moving the fishing tool relative to the target component.

The apparatus may further comprise a conveyance element extending from the downhole tool to a wellsite surface from which the wellbore extends. The downhole tool may be controllable from the wellsite surface via telemetry on the conveyance element.

The conveyance element may comprise a single wire covered by an electrical insulation, and the wire may be operable to transmit electrical signals between the downhole tool and the wellsite surface.

The arms may be collectively operable to move the fishing tool along a plane coincident with a diameter of the wellbore.

Each arm may be operable to move in a corresponding plane coincident with a central axis of the downhole tool.

Each arm may comprise a roller for selectively contacting the wellbore sidewall.

The plurality of arms may comprise three arms.

The downhole tool may comprise a plurality of actuators each associated with a corresponding one of the arms, and each actuator may be independently operable to move the corresponding arm independently with respect to the other arms.

The downhole tool may comprise a plurality of position sensors each operable to generate a signal or information indicative of a current position of a corresponding one of the arms.

The downhole tool may comprise a sensor operable to generate a signal or information indicative of connection between the fishing tool and the target component.

The apparatus may comprise a conveyance element extending between the downhole tool and the wellsite surface from which the wellbore extends. The sensor operable to generate the signal or information indicative of connection between the fishing tool and the target component may be or comprise a tension sensor operable to generate a signal or information indicative of tension applied to the downhole tool by the conveyance element.

The downhole tool may comprise a downhole power source operable to supply power for deploying the arms into contact with the sidewall of the wellbore.

The downhole tool may comprise a telemetry module operable to: transmit signals or information to the wellsite surface; and/or receive signals or information from the wellsite surface. The transmitted signals or information may be indicative of: position of each one of the arms; position of the fishing tool within the wellbore; tension applied to the downhole tool via means for conveying the downhole tool within the wellbore; and/or an image of the downhole tool. The received signals or information may be indicative of: intended position of each one of the arms; and/or intended position of the fishing tool within the wellbore.

The target component may be stuck in the wellbore.

The downhole tool may facilitate retrieval of the target component to a wellsite surface from which the wellbore extends.

The present disclosure also introduces an apparatus comprising a downhole tool comprising: a member; a fishing tool coupled with the member and operable to connect with a target component in a wellbore; and a plurality of arms each coupled with the member and independently deployable into contact with a sidewall of the wellbore to facilitate connection of the fishing tool with the target component by radially moving the fishing tool relative to the target component.

The member may be a structural component, a housing, a chassis, a body, a mandrel, and/or another rigid, internally or externally disposed component of the downhole tool.

The fishing tool may be indirectly coupled with the member via another member of the downhole tool.

Each arm may be indirectly coupled with the member via another member of the downhole tool.

The arms may be collectively coupled indirectly with the member via another member of the downhole tool.

The member may be a first member, the arms may be collectively coupled indirectly with the first member via a second member, and the first and second members may each be a structural component, a housing, a chassis, a body, a mandrel, and/or another rigid, internally or externally disposed component of the downhole tool.

The plurality of arms may collectively move the fishing tool along a plane coincident with a diameter of the wellbore to facilitate connection of the fishing tool with the target component.

Each arm may be independently deployable into contact with the sidewall of the wellbore to collectively move the fishing tool into substantial axial alignment with the target component to facilitate connection with the target component.

The fishing tool may be operable to latch onto a fishing head of the target component to connect the fishing tool with the target component.

The target component may be stuck in the wellbore.

The downhole tool may facilitate retrieval of the target component to a wellsite surface from which the wellbore extends.

The apparatus may further comprise a conveyance element extending from the downhole tool to a wellsite surface from which the wellbore extends. The downhole tool may be controllable from the wellsite surface via telemetry on the conveyance element.

The conveyance element may comprise a single wire covered by an electrical insulation, and the wire may be operable to transmit electrical signals between the downhole tool and the wellsite surface.

Each arm may be operable to move in a corresponding plane coincident with a central axis of the downhole tool.

Each arm may comprise a roller for selectively contacting the wellbore sidewall.

The plurality of arms may comprise three arms.

The downhole tool may comprise a plurality of actuators each associated with a corresponding one of the arms, and each actuator may be independently operable to move the corresponding arm independently with respect to the other arms.

The downhole tool may comprise a plurality of position sensors each operable to generate a signal or information indicative of a current position of a corresponding one of the arms.

The apparatus may comprise means for conveying the downhole tool within the wellbore, and the downhole tool may comprise a tension sensor operable to generate a signal or information indicative of tension applied to the tool string and/or the target component.

The downhole tool may comprise a sensor operable to generate a signal or information indicative of connection between the fishing tool and the target component. The tension sensor may be or comprise the sensor operable to generate the signal or information indicative of tension applied to the tool string and/or the target component.

The downhole tool may comprise a downhole power source operable to supply power for deploying the arms into contact with the sidewall of the wellbore.

The downhole tool may comprise a telemetry module operable to: transmit signals or information to the wellsite surface; and/or receive signals or information from the wellsite surface. The transmitted signals or information may be indicative of: lateral position of each one of the arms; lateral position of the fishing tool within the wellbore; tension applied to the tool string; and/or tension applied to the target component. The received signals or information may be indicative of: intended lateral position of each arm; and/or intended lateral position of the fishing tool within the wellbore.

The present disclosure also introduces a method comprising: (A) conveying a downhole tool within a wellbore from a wellsite surface to a target component in the wellbore, wherein the downhole tool comprises: (1) a fishing tool; and (2) a plurality of arms; (B) operating the arms to move into contact with a sidewall of the wellbore to facilitate connection of the fishing tool with the target component; (C) connecting the fishing tool with the target component; and (D) retrieving the downhole tool and the target component to the wellsite surface.

Facilitating connection of the fishing tool with the target component may comprise radially moving the fishing tool relative to the target component into substantial axial alignment with the target component. Connecting the fishing tool with the target component may comprise, after the fishing tool is substantially axially aligned with the target component, moving at least a portion of the downhole tool in a downhole direction until the fishing tool engages with the target component. Connecting the fishing tool with the target component may comprise, after the fishing tool is substantially axially aligned with the target component, latching the fishing tool with a fishing head of the target component.

Facilitating connection of the fishing tool with the target component may comprise moving the fishing tool to different lateral positions within the wellbore until the fishing tool is axially aligned with the target component. Connecting the fishing tool with the target component may comprise attempting to connect the fishing tool with the target component at each one of the different lateral positions within the wellbore until the fishing tool connects with the target component.

Facilitating connection of the fishing tool with the target component may comprise moving the fishing tool along a plane coincident with a diameter of the wellbore.

Conveying the downhole tool within the wellbore may be performed via a single wire covered by an electrical insulation, and operating the arms may comprise transmitting electrical control signals between the downhole tool and the wellsite surface via the wire to control movement of the arms.

Operating the arms may comprise transmitting control commands from the wellsite surface via digital slickline telemetry to operate the arms.

The downhole tool may comprise three arms, and operating the arms may comprise operating the three arms.

Operating the arms may comprise operating each one of the arms to move independently with respect to the other arms.

Operating the arms may comprise moving each one of the arms in a corresponding plane coincident with a central axis of the downhole tool.

The downhole tool may comprise a plurality of actuators each associated with a corresponding one of the arms, and operating the arms may comprise operating each one of the actuators independently of the other actuators to move the corresponding one of the arms independently with respect to the other arms.

The method may comprise: applying tension to at least a portion of the downhole tool; and monitoring the tension to determine if the fishing tool is connected with the target component, wherein a progressive increase in the tension may be indicative of connection of the fishing tool with the target component.

The method may comprise: applying tension to the downhole tool from the wellsite surface via means for conveying the downhole tool within the wellbore; and monitoring the tension to determine if the target component became free, wherein a sudden decrease in the tension may be indicative of the target component becoming free.

The downhole tool may comprise a plurality of position sensors each associated with a corresponding one of the arms, and the method may comprise monitoring position of each one of the arms utilizing the position sensors.

The method may comprise transmitting via a downhole telemetry module signals or information to the wellsite surface. The transmitted signals or information may be indicative of: lateral position of each one of the arms; lateral position of the fishing tool within the wellbore; tension applied to the tool string; and/or tension applied to the target component.

The method may comprise receiving via a downhole telemetry module signals or information from the wellsite surface. The received signals or information may be indicative of: intended lateral position of each one of the arms; and/or intended lateral position of the fishing tool within the wellbore.

The method may comprise: (A) telemetering (transmitting and/or receiving) first signals or information indicative of: (1) lateral position of each one of the arms; (2) lateral position of the fishing tool within the wellbore; (3) tension applied to the tool string; and/or (4) tension applied to the target component; and/or (B) telemetering (transmitting and/or receiving) second signals or information indicative of: (1) intended lateral position of each one of the arms; and/or (2) intended lateral position of the fishing tool within the wellbore.

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 purposes and/or achieving the same advantages 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 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.

Claims

1. An apparatus comprising:

a downhole tool comprising: a fishing tool operable to connect with a target component in a wellbore; and a plurality of arms each independently deployable into contact with a sidewall of the wellbore to facilitate connection of the fishing tool with the target component by radially moving the fishing tool relative to the target component.

2. The apparatus of claim 1 further comprising a conveyance element extending from the downhole tool to a wellsite surface from which the wellbore extends, wherein the downhole tool is controllable from the wellsite surface via telemetry on the conveyance element.

3. The apparatus of claim 2 wherein the conveyance element comprises a single wire covered by an electrical insulation, wherein the wire is operable to transmit electrical signals between the downhole tool and the wellsite surface.

4. The apparatus of claim 1 wherein the arms are collectively operable to move the fishing tool along a plane coincident with a diameter of the wellbore.

5. The apparatus of claim 1 wherein the downhole tool further comprises a plurality of actuators each associated with a corresponding one of the arms, and wherein each actuator is independently operable to move the corresponding arm independently with respect to the other arms.

6. The apparatus of claim 1 wherein the downhole tool further comprises a plurality of position sensors each operable to generate a signal or information indicative of a current position of a corresponding one of the arms.

7. The apparatus of claim 1 wherein the downhole tool further comprises a sensor operable to generate a signal or information indicative of connection between the fishing tool and the target component.

8. The apparatus of claim 7 further comprising a conveyance element extending between the downhole tool and the wellsite surface from which the wellbore extends, wherein the sensor is or comprises a tension sensor operable to generate a signal or information indicative of tension applied to the downhole tool by the conveyance element.

9. The apparatus of claim 1 wherein the downhole tool further comprises a downhole power source operable to supply power for deploying the arms into contact with the sidewall of the wellbore.

10. The apparatus of claim 1 wherein:

the downhole tool further comprises a telemetry module operable to: transmit signals or information to the wellsite surface; and/or receive signals or information from the wellsite surface;

the transmitted signals or information are indicative of: position of each one of the arms; position of the fishing tool within the wellbore; tension applied to the downhole tool via means for conveying the downhole tool within the wellbore; and/or an image of the downhole tool, and

the received signals or information are indicative of: intended position of each one of the arms; and/or intended position of the fishing tool within the wellbore.

11. A method comprising:

conveying a downhole tool within a wellbore from a wellsite surface to a target component in the wellbore, wherein the downhole tool comprises: a fishing tool; and a plurality of arms;

operating the arms to move into contact with a sidewall of the wellbore to facilitate connection of the fishing tool with the target component;

connecting the fishing tool with the target component; and

retrieving the downhole tool and the target component to the wellsite surface.

12. The method of claim 11 wherein facilitating connection of the fishing tool with the target component comprises radially moving the fishing tool relative to the target component into substantial axial alignment with the target component.

13. The method of claim 12 wherein connecting the fishing tool with the target component comprises, after the fishing tool is substantially axially aligned with the target component, moving at least a portion of the downhole tool in a downhole direction until the fishing tool engages with the target component.

14. The method of claim 11 wherein facilitating connection of the fishing tool with the target component comprises moving the fishing tool to different lateral positions within the wellbore until the fishing tool is axially aligned with the target component.

15. The method of claim 14 wherein connecting the fishing tool with the target component comprises attempting to connect the fishing tool with the target component at each one of the different lateral positions within the wellbore until the fishing tool connects with the target component.

16. The method of claim 11 wherein facilitating connection of the fishing tool with the target component comprises moving the fishing tool along a plane coincident with a diameter of the wellbore.

17. The method of claim 11 wherein conveying the downhole tool within the wellbore is performed via a single wire covered by an electrical insulation, and wherein operating the arms comprises transmitting electrical control signals between the downhole tool and the wellsite surface via the wire to control movement of the arms.

18. The method of claim 11 wherein operating the arms comprises operating each one of the arms to move independently with respect to the other arms.

19. The method of claim 11 further comprising:

applying tension to at least a portion of the downhole tool; and

monitoring the tension to determine if the fishing tool is connected with the target component.

20. The method of claim 11 further comprising:

telemetering first signals or information from downhole to surface, wherein the first signals are indicative of: lateral position of each one of the arms; lateral position of the fishing tool within the wellbore; tension applied to the tool string; and/or tension applied to the target component; and

telemetering second signals or information from surface to downhole, wherein the second signals are indicative of: intended lateral position of each one of the arms; and/or intended lateral position of the fishing tool within the wellbore.