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CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    This application, pursuant to 35 U.S.C. §119, claims priority to U.S. Provisional Application No. 61/675,074, filed on Jul. 24, 2012, which is incorporated herein by reference in its entirety. 
     
    
     BACKGROUND 
       [0002]    In oil and gas exploration and development operations, it is often desirable to remove casing which has previously been set in the wellbore. Casing removal requires that the casing string first be severed, and the free end then pulled to the surface, to remove the severed portion. 
         [0003]    Conventional apparatus and techniques for extraction of well casing typically involve the use of multiple trips to move cutting and extracting equipment downhole. Thus, in removal operations a cutting device is first lowered into the wellbore to cut the casing at a desired depth after which time the cutting device is returned to the surface. A spearing device is then lowered inside the well and engaged to the free end of the casing. Once the free end of the casing is engaged, an attempt is then made to recover the casing by pulling, or, in the case where jars are used, by a combination of pulling and jarring. If these attempts to remove the casing are unsuccessful, the spear assembly is removed from the wellbore and the cutting device reattached to the tool string to sever the casing at a point above the original cut. The pulling/jarring process is then repeated until the casing is recovered. 
         [0004]    Such prior art apparatuses and techniques for retrieving well casing are time consuming and costly. This time and expense is a result of the utilization of separate cutting and extraction tools, which are typically run downhole independently. Even when casing is retrieved without the need to complete a second cut of the casing, at least two trips are necessary for a complete cutting and retrieval operation. When a significant length of casing is extracted, considerable rig time must be used to move the tools downhole to the site of the cut. Time and expense are therefore increased when multiple cuts are necessary to retrieve the casing. 
         [0005]    In certain operations, casing cutting may be required when performing slot recovery operations. During slot recovery, the object is to construct a new well with new barriers from a previously used slot while shutting off all communication with an old reservoir. Cutting and pulling casing may be restricted due to cement behind production casing or barite settling from drilling fluid in the production casing annulus. Such slot recovery operations may thus require the cutting and removal of multiple sections of casing from a wellbore. Because slot recovery operations often involve cutting a casing segment in a first trip and pulling the cut casing in a second trip, such operations are often time consuming and expensive. 
       SUMMARY OF THE CLAIMED EMBODIMENTS 
       [0006]    In one aspect, embodiments disclosed herein relate to a spearing device for use in removing casing from a wellbore. The spearing device may include: a top sub; a bottom sub; a mandrel coupled to the top sub and bottom sub and having an outer surface, at least a portion of which is corrugated. The spearing device also includes: a grapple including one or more grapple members having a correspondingly corrugated inner surface and at least a portion of an outer surface of the grapple members including wickers for engaging an interior surface of the casing, wherein the grapple is configured to (i) axially and rotationally move along the corrugated outer surface of the mandrel and (ii) expand and collapse the grapple members responsive to axial movement relative to the mandrel; a piston slidably disposed within the mandrel and operatively connected to the grapple; and a spring operative with the piston and biasing the grapple toward a collapsed position. Responsive to an increase in hydraulic pressure, the piston compresses the spring and axially moves the grapple, expanding the grapple members. Responsive to a subsequent decrease in hydraulic pressure, the spring decompresses and axially moves the grapple, collapsing the grapple members. 
         [0007]    In another aspect, embodiments disclosed herein relate to a downhole tool for cutting and removing casing from a wellbore. The tool may include: a cutting device disposed on a tool string and configured to make at least one casing cut; and, a spearing device disposed on the tool string and configured to engage and remove casing cut by the at least one cutting device from the wellbore. The spearing device may include: a top sub; a bottom sub; a mandrel coupled to the top sub and bottom sub and having an outer surface, at least a portion of which is corrugated; a grapple including one or more grapple members having a correspondingly corrugated inner surface and at least a portion of an outer surface of the grapple members including wickers for engaging an interior surface of the casing, wherein the grapple is configured to (i) axially and rotationally move along the corrugated outer surface of the mandrel and (ii) expand and collapse the grapple members responsive to axial movement relative to the mandrel; a piston slidably disposed within the mandrel and operatively coupled to the grapple; and a spring operative with the piston and biasing the grapple toward a collapsed position. Responsive to an increase in hydraulic pressure, the piston compresses the spring and axially moves the grapple, expanding the grapple members. Responsive to a subsequent decrease in hydraulic pressure, the spring decompresses and axially moves the grapple, collapsing the grapple members. 
         [0008]    In another aspect, embodiments disclosed herein relate to a method of removing casing from a wellbore. The method may include: disposing a downhole tool assembly in a wellbore, the downhole tool assembly including a first cutting device and a first spearing device. The spearing device may include: a top sub; a bottom sub; a mandrel coupled to the top sub and bottom sub and having an outer surface, at least a portion of which is corrugated; a grapple including one or more grapple members having a correspondingly corrugated inner surface and at least a portion of an outer surface of the grapple members including wickers for engaging an interior surface of the casing, wherein the grapple is configured to (i) axially and rotationally move along the corrugated outer surface of the mandrel and (ii) expand and collapse the grapple members responsive to axial movement relative to the mandrel; a piston slidably disposed within the mandrel and operatively coupled to the grapple; and a spring operative with the piston and biasing the grapple toward a collapsed position. Responsive to an increase in hydraulic pressure, the piston compresses the spring and axially moves the grapple, expanding the grapple members. Responsive to a subsequent decrease in hydraulic pressure, the spring decompresses and axially moves the grapple, collapsing the grapple members. The method may also include: activating the first cutting device; cutting a first casing segment; deactivating the first cutting device; activating the first spearing device; engaging the first spearing device with the first casing segment; removing the first casing segment from the wellbore. 
         [0009]    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 key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. 
     
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
         [0010]      FIG. 1  is a schematic representation of a downhole tool assembly according to embodiments of the present disclosure. 
           [0011]      FIGS. 2-13  are various views of spearing devices according to embodiments of the present disclosure. 
           [0012]      FIGS. 14-16  are schematic representations of downhole tool assemblies according to embodiments of the present disclosure. 
       
    
    
     DETAILED DESCRIPTION 
       [0013]    In one aspect, embodiments disclosed herein relate to methods and apparatuses for cutting and retrieving easing from a wellbore. More specifically, methods and apparatuses disclosed herein relate to removing casing from a wellbore by making multiple casing cuts, and retrieving the casing joints in a well slot recovery operation. More specifically still, methods and apparatuses disclosed herein relate to making multiple casing cuts and retrieving multiple cut casing joints from a wellbore in a single trip. 
         [0014]    The methods and apparatus disclosed herein include downhole tool assembly designs that may be used in the cutting and removing of casing segments from a wellbore. In accordance with embodiments disclosed herein, such operations, often referred to by those of ordinary skill in the art as slot recovery applications, include the use of a downhole tool capable of cutting casing segments, engaging the cut segments, freeing the segments, and then removing the segments from the wellbore in a single trip. Because multiple casing cuts may increase the efficiency of the operations, methods for activating and/or deactivating multiple downhole tools will be discussed below in detail. 
         [0015]    Referring to  FIG. 1 , a schematic representation of a fishing tool assembly  100  according to embodiments of the present disclosure is shown. Fishing tool assembly  100  includes a cutting device  101 , a spearing device  102 , and a jarring device  103 . Generally, cutting device  101  may be any type of cutting device capable of cutting cemented/uncemented casing known in the art. Spearing device  102  will be described in detail below. Jarring device  103  may include various types of jarring devices known in the art. Fishing tool assembly  100  may also include one or more additional components that may facilitate the slot recovery operation. The other components illustrated in  FIG. 1  include a jarring device  104 , a packer  105 , and a stabilizer  106 . Those of ordinary skill in the art will appreciate that, depending on the requirements of the slot recovery operation, multiple cutting devices  101 , spearing devices  102 , packers  105 , stabilizers  106 , and other components, such as jar accelerators (not shown), may be used. Such alternative configurations of downhole tool assembly  100  will be discussed in detail below. 
         [0016]    Generally, as noted above, cutting device  101  may include any type of cutting device capable of cutting casing known in the art. Such cutting devices typically include a plurality of arms  107  that may be actuated to extend from the body of the cutting device to engage casing. Typically, cutting devices include a plurality of cutting elements, teeth, or inserts disposed on the arms, such that upon actuation, the cutting elements contact the casing. Examples of cutting device actuation may include, spring loaded knives, expandable arms and/or blades with cuttings elements disposed thereon, and other cuttings devices known to those of ordinary skill in the art. As the tool string rotates, including rotation of the cutting device  101 , the cutting elements on arms  107  contact the casing and cut the casing to a depth defined by the extension of arms  107  and/or cutting elements. Thus, those of ordinary skill in the art will appreciate that a depth of cut into the casing may be controlled by limiting the extension of the arms and/or the protrusion from the arms of associated cutting elements. Depending on the thickness of the casing being cut, it may be beneficial to limit the depth of cut into the casing to, for example,  0 . 25  inches more than the casing thickness. In still other operations, it may be beneficial to decrease the depth of cut to an alternate depth, such as, for example, the thickness of the casing or a specified depth for the specific operation. Such depth of cut limits may find application in operations where sequentially smaller casing segments are disposed within the same region. Because the depth of cut may be limited, an engineer may elect to cut into a first casing segment (i.e., an inner casing segment) without cutting a second casing segment (i.e., an outer casing segment). U.S. Pat. No. 7,762,330, incorporated herein by reference to the extent not contradictory to embodiments herein, discloses examples of a cutting device  101 , a packer  105 , and a stabilizer  106  that may be used according to embodiments disclosed herein. 
         [0017]    Referring to  FIGS. 2 and 3 , a spearing device according to embodiments herein is illustrated. Spearing device  200  may include a top sub  201  and a bottom sub  202 . A mandrel  207  may be coupled to the top sub  201  and the bottom sub  202 , stationary with respect to the top and bottom subs  201 ,  202  during operation of the spearing device  200 . In some embodiments, the mandrel  207  may be threadedly connected to the top sub  201  and the bottom sub  202 , stationary with respect to the top and bottom subs  201 ,  202  during operation of the spearing device  200 . 
         [0018]    Disposed circumferentially about the mandrel  207  is a grapple  206 . Grapple  206  may include one or more axial slots  208  defining grapple members  210 . At least a portion of the exterior surface of grapple members  210  includes wickers  212 ,  216  ( FIG. 3 ) for engagement of the casing when the grapple members  210  are expanded. In some embodiments, grapple members  210  include wickers  212  biased in an upward direction to aid in lifting the casing from the wellbore. Grapple members  210  may also include wickers biased in a downward direction, minimizing slippage of the grapple relative to the casing during a jarring operation and aiding with re-cock of the jar, for example. This wicker design, when the grapple members  210  are engaged with the casing, allows application of axial force in both directions, as may be required by casing pulling, jarring operations, and jar re-cocking. 
         [0019]    A portion of the outer surface of mandrel  207  is corrugated. Similarly, a portion of the inner surface of grapple members  210  is correspondingly corrugated. The respective corrugated surfaces may include ramps (non-helical) or buttress threads (helical), for example; use of threads may advantageously provide for rotational jerking of the spearing device. The corrugated surfaces may provide for axial and rotational movement of the grapple  206  along the corrugated outer surface of the mandrel  207 . Axial movement of the grapple  206  relative to mandrel  207  results in expansion and contraction of the grapple members  210  due to the corrugated surfaces. 
         [0020]    The design of grapple  206  may depend on the type of corrugated surfaces used. For example, helical buttress threads may provide for use of a one-piece grapple  206 , where, as illustrated in  FIG. 3 , a lengthwise axial slot  230  may allow grapple  206  to flex when the grapple members are expanded. The buttress threads may also allow for ease in assembly. Where the corrugated surfaces are ramps, a multi-piece grapple  206  may be required (e.g., two half-ring sections). 
         [0021]    A piston  214  is slidably disposed within mandrel  207  and/or bottom sub  202 . Piston  214  is operatively coupled to grapple  206  via activation dogs  215 , where the respective portions of the activation dogs may push or pull on shoulder  235  of grapple  206 . Movement of piston  214  in an axial direction thus provides for expansion and contraction of grapple members  210 . A spring  211  is also provided, operative with piston  214  and biasing the grapple  206  toward a contracted or collapsed position. As illustrated, spring  211  abuts a shoulder  220  of bottom sub  202  and a shoulder  222  of piston  214 , and is in a biased, uncompressed condition. 
         [0022]    Expansion of the grapple members  210  may be provided by a hydraulic activation system. For example, fluid flow is provided to spearing device  200  via throughbore  225 . The fluid flow passes through top sub  201  and mandrel  207  and enters nozzle  260 , resulting in applied pressure to a top surface of piston  214 . The applied pressure pushes piston  214  downward, compressing spring  211 , pulling grapple  206  axially with respect to mandrel  207  via activation dogs  215 , and expanding the grapple members  210  to engage an inner surface of casing to be removed, where the engagement provides a firm grip for the tool with the casing to facilitate the retrieval of the cut casing segment from the wellbore. When the hydraulic pressure is reduced, spring  211  decompresses and moves the grapple  206  upward, retracting grapple members  210  and disengaging from the casing wall. 
         [0023]    Alternatively, the spring  211  may be positioned above the piston and biased toward a compressed condition, where activation of the piston may pull on spring  211  and deactivation of the system may result in the spring compressing, pulling on the piston and collapsing the grapple members. 
         [0024]    Spearing device  200  may also include an anti-rotation locking system  213 , which may include one or more shear dogs  217  and shear screws  218 , among other components. To avoid rotation of grapple  206  relative to mandrel  207 , a shear dog  217  may be bolted to the mandrel  207  and disposed within a longitudinal slot  230  in grapple  206 . In some embodiments, the shear dog  217  may be coupled to the mandrel  207  and disposed within a longitudinal slot  230  in grapple  206 . Shear dog  217  incorporates an intentionally weakened face which can be sheared by application of right-hand (or alternatively left-hand) rotation of mandrel  207 , such as in the event of a grapple  206  “freeze” that cannot be released by conventional application of downwards force. Anti-rotation locking system  213 , when engaged, may prevent the grapple  206  from rotating when fully engaged with the casing. In some instances, however, it may be desirable to rotate grapple  206 , such as to free the spearing device  200  from the casing or other instances as readily envisionable by one skilled in the art. Thus, when disengaged (i.e., sheared), anti-rotation locking system  213  may provide for rotation of the grapple  206 , with typically less than 360 degrees of permitted rotation. The ability to unlock the rotatability of the grapple  206  may thus provide significant advantages during casing removal operations. 
         [0025]    Referring now to  FIGS. 4-13 , a spearing device according to other embodiments herein are illustrated. Spearing device  400  may include a top sub  401 , bottom sub  402 , spring  411 , piston  414 , mandrel  407 , grapple  406  (including grapple members and wickers (not illustrated)), activation dogs  415 , throughbore  425 , and anti-rotation locking system  413 , each as described above with respect to  FIGS. 2 and 3 . 
         [0026]    Spearing device  400  further includes a nozzle assembly  460 , disposed on a proximal end of piston  414  and including a nozzle carrier  462  partially axially spaced above piston  414 , a Bellville stack  464 , and a nozzle  466 . Spearing device  400  also includes a ratchet locking assembly  470 , disposed in the central bore of the top sub  401  and coupled with the top sub  401 . In some embodiments, the ratchet locking assembly  470  is threadedly connected with the top sub  401 . Locking assembly  470  may include an outer sleeve  472 , an intermediate sleeve  474 , an inner sleeve  476 , an end cap  478 , and a ratchet mechanism  480 , among other components as will be described below. 
         [0027]    An upper end portion  477  of inner sleeve  476 , or a portion thereof, may be disposed within the intermediate sleeve  474  and may include wickers (not illustrated) on an outer surface thereof. Inner sleeve  476  extends axially through mandrel  407 , the lower end portion  479  ( FIG. 4 ) of the inner sleeve being disposed proximate nozzle assembly  460 . 
         [0028]    Ratchet mechanism  480  may be disposed between overlapping portions of the inner and intermediate sleeves  476 ,  474 . Ratchet mechanism  480  engages the wickers of the inner sleeve  476  and allows downward axial movement of inner sleeve  476  but prevents upward axial movement of inner sleeve  476 . Ratchet mechanism  480  may include a split ring  490  that includes inner ratchet teeth  492 , such as illustrated in  FIGS. 10A and 10B , retained by circumferential garter springs  491 , for engaging the corresponding wickers  493  on inner sleeve  476  ( FIG. 10C ). The wickers are lengths of thread-like members that are tapered in only one direction. Thus, engagement between ratchet rings  490  and the wickers of inner sleeve  476  allows inner sleeve  476  to move in only one direction with respect to mandrel  407 . 
         [0029]    As illustrated in  FIGS. 4-6 , the spearing device is in a non-activated state. When spearing device  400  is to be used to hold and retrieve a piece of casing, such as retrieval to the surface, it may be desired or necessary to engage the holding ratchet mechanism  480 . This is performed by bleeding pressure from the tool string and hence the bottom hole assembly, inserting a “drop ball” at surface and pumping this ball  482  through the tool string to spearing device  400 , as illustrated in  FIGS. 7-9 . Once the ball has seated within the lower end portion of the inner sleeve  476 , fluid pressure is applied to the spearing device  400 , resulting in the ball  482  and hence the ratchet mandrel (inner sleeve  476 ) being forced downwards a distance D; this applied force results in the shearing of ratchet mandrel shear screws  484  ( FIGS. 6 and 9 ). Prior to the ball drop, the spearing device may be hydraulically activated and deactivated as described above with respect to  FIGS. 2 and 3 ; shearing of shear screws  484  as a result of the ball drop activates the ratchet locking mechanism. 
         [0030]    The downward movement of ball  482  and ratchet mandrel  476  continues through the unidirectional wicker profile of the ratchet mechanism  480 , which may include retaining blocks or ratchet rings  490  retained by circumferential garter springs  491  ( FIGS. 10A-10C ) that allow radial movement sufficient to allow the ratchet mandrel  476  and corresponding ratchet retaining rings  490  with wicker profiles  492  to pass over each other and then snap back into retention position after each wicker tooth length. 
         [0031]    Once inner sleeve  476  has moved sufficiently to come into contact with the nozzle carrier  462 , this effectively blocks the nozzle  466  and thus restricts fluid flow through the tool. Continued application of static pressure pushes the ball  482 , inner sleeve  476 , and nozzle carrier  462  downwards, thereby loading the Bellville spring stack  464 , and, in turn directly mechanically pushing the piston  414  and activation dogs  415  into contact with lower lip  435  of grapple  406  and drawing it downwards along mandrel  407 , thereby radially expanding the grapple  406  into contact with the casing as per the “pressure only” activation process described earlier. In addition to this directly applied mechanical force, fluid ports  488  above the drop ball&#39;s position in the inner sleeve  476  allows fluid pressure to be applied to the upper face of the piston assembly (piston  414 , and nozzle carrier  462 ), thereby resulting in an effective activation force, matching and possibly exceeding that of the fluid set engagement described above with respect to  FIGS. 2 and 3 . 
         [0032]    The purpose of the Bellville stack  464  is to prevent mechanical lockup of ratchet mandrel  476  and nozzle carrier  462  relative to piston assembly (piston  414 , activation dogs  415 , etc.) and hence, through transmission, grapple  406  and in turn the casing. This is required in order for the ratchet release mechanism to function properly (described below). 
         [0033]    Referring now to  FIGS. 11-13 , when the spearing device  400  is to be released after “activation with ratchet” as described above (i.e., deactivated), a second, larger diameter drop ball  494  is to be “dropped” into the tool string and allowed to come into contact with the ratchet release sleeve (intermediate sleeve  474 ), as illustrated in  FIG. 13 . 
         [0034]    Upon pressurization of the tool string and in turn application of fluid pressure to second ball  494 , sufficient force is applied to the ratchet release sleeve  474  to shear the ratchet release shear screws  496  (see  FIGS. 6 and 13 ) coupling outer sleeve  472  and intermediate sleeve  474 . Once this occurs, the ratchet release sleeve  474  moves downward, bringing a release wedge profile feature  497  (integral with ratchet release sleeve  474 ) into contact with the corresponding ratchet rings/retaining blocks  490  internal wedge profiles (not shown). Continued downward travel of the ratchet release sleeve  474  forces the ratchet rings  490  to move outwards radially against the circumferential retaining garter springs  491  a distance that allows clearance between the retaining rings  490  and ratchet mandrel  476  wicker profiles. The resultant de-meshing of the wicker profile features allows free upward movement of the inner sleeve  476  causing the spring, piston, and grapple to return to the relaxed position, thereby disengaging grapple  406  from the casing, and thus releasing the casing. 
         [0035]    During casing recovery operations, varied configurations of bottom hole assemblies including the above-described components may be used. Referring back to  FIG. 1 , the operation of downhole tool assembly  100  during casing recovery operations will be described in detail. Initially, downhole tool assembly  100  is disposed in a wellbore, wherein downhole tool assembly  100  includes at least a cutting device  101 , a spearing device  102 , and a jarring device  104 . As described above, downhole tool assembly  100  may also include various other components, such as stabilizers  106 , packers  105 , and/or jarring accelerators  103 . 
         [0036]    In one embodiment, downhole tool assembly  100  is disposed in a wellbore, and lowered to a portion of the wellbore where a casing cut is desirable. When downhole tool assembly  100  reaches the preferred casing section, cutting device  101  is activated by, for example, radio frequency transmission, ball drop actuation, pressure actuation, pressure pulse from the surface to the tool, such as through measurement while drilling tools, or any other actuation method known to those of ordinary skill in the art. Activation of cutting device  101  allows for a first casing segment to be cut. After the first casing segment is cut, cutting device  101  is deactivated, and spearing device  102  is activated. Spearing device  102  is engaged with the cut casing segment, and jarring device  104  is activated, so as to free the first casing segment. Because spearing device  102  is engaged with the first casing segment, downhole tool assembly  100  may be pulled up, and the casing segment removed from the wellbore. 
         [0037]    In other embodiments, after the first casing segment is cut and spearing device  102  is engaged with the cut casing segment, cutting device  101  may be re-activated, and a second casing cut may be made. In certain embodiments, two casing cuts may be required, such that upon jarring the casing segment, the casing segment is freed. To increase the precision of the casing cuts, stabilizers  106  may be disposed on downhole tool assembly  100  to centralize cutting device  101  within the wellbore. By centralizing cutting device  101 , the individual cutters of cutting device  101  may be controlled, such that a preferred depth of cut may be maintained. Additionally, centralizing cutting device  101  may decrease the wear on the individual cutters, thereby increasing the life of cutting device  101 . 
         [0038]    Referring to  FIG. 14 , a downhole tool assembly  600  according to an alternate embodiment of the present disclosure is shown. In this embodiment, downhole tool assembly includes multiple cutting devices  601   a,    601   b,    601   c,  a spearing device  602 , and a jarring device  604 . As described with respect to  FIG. 1 , fishing tool assembly  600  may also include additional components, such as jarring accelerators  603 , packers  605 , and/or stabilizer(s)  606 . 
         [0039]    In this embodiment, fishing tool assembly  600  may be disposed in a wellbore and activated similar to the activation of downhole tool assembly  100  of  FIG. 1 . However, after a first casing segment is cut, and cutting device  601   a  is deactivated, fishing tool assembly  600  may either be raised or lowered into the wellbore to a different depth, and additional cuts may be made. For example, in one embodiment, cutting device  601   a  may be activated and deactivated so as to make a number of cuts, such as 3 or more cuts. After a number of cuts, the cutters of cutting device  601   a  may be worn such that additional cuts can not be made. However, rather than remove fishing tool assembly  600  from the wellbore so that the cutters and/or cutting device  601   a  may be replaced, cutting device  601   a  may be deactivated, and cutting device  601   b  may be activated, such that additional cuts may be made. Those of ordinary skill in the art will appreciate that the process of deactivating one of cutting devices  601   a,    601   b,  or  601   c  and activating a different cutting device  601   a,    601   b,  or  601   c  may occur in any order. For example, in certain embodiments, the lowest cutting device  601   c  may be activated first, while in other embodiments, cutting device  601   a  or  601   b  may be activated first. The order of activation of cutting devices  601   a,    601   b,  and  601   c  will depend on the requirements of the casing cutting operation, as well as the depth of the casing segments within the wellbore. 
         [0040]    Multiple cutting devices  601  may allow for multiple casing cuts to be made in a single trip of the tool string. Cutters of cutting devices  601  often wear down after two to three cuts. As such, the tool string would have to be tripped after two to three cuts. However, downhole tool assembly  600  may be capable of making multiple cuts, such as twelve or more cuts, thereby decreasing the number of trips of the tool string required to cut casing segments from the wellbore. In other embodiments, multiple cutting devices  601  may serve as redundant cutting devices, such that if one of the cutting devices  601  loses functionality or if the cutters of a first cutting device wear down prematurely, a second cutting device may be used. Those of ordinary skill in the art will appreciate that depending on the requirements of the casing cutting operation, the number of cutting devices  601  may vary. As such, bottom hole assemblies having one, two, three, four, or more cutting devices are within the scope of the present disclosure. 
         [0041]    Referring to  FIG. 15 , a downhole tool assembly  700  according to one embodiment of the present disclosure is shown. In this embodiment, downhole tool assembly  700  includes multiple cutting devices  701   a,    701   b,  and  701   c,  a spearing device  702 , and a jarring device  704 . Downhole tool assembly  700  also includes various optional components, such as a jarring accelerator  703 , packer(s)  705 , and a plurality of stabilizers  706 . 
         [0042]    In this embodiment, the configuration of stabilizers  706  may allow for near cutting device centralization during activation of any of cutting devices  701   a,    701   b,  and/or  701   c.  As illustrated, stabilizers  706  are located at least above each of cutting devices  701 . As such, as cutting devices  701  are activated, the tool string may be centralized in a location close to cutting device  701 . By increasing stabilization and thus centralization of the tool string close to the individual cutting devices, the precision of cuts made by each cutting device  701  may be increased. Those of ordinary skill in the art will appreciate that the spacing of the individual stabilizers  706  will vary based on the type and/or size of casing being cut and the parameters of the downhole tool assembly  700 . However, by decreasing the space between cuttings devices  701  and stabilizers  706 , the centralization of the individual cutting devices  701  may be increased. Additionally, in certain embodiments, it may be beneficial to have stabilizers  706  disposed along the tool string both above and below cutting devices  701 . 
         [0043]    Referring to  FIG. 16 , a downhole tool assembly  800  according to one embodiment of the present disclosure is shown. In this embodiment, downhole tool assembly  800  includes multiple cutting devices  801   a  and  801   b,  multiple spearing devices  802   a  and  802   b,  and a jarring device  804 . Downhole tool assembly  800  also includes various optional components, such as a jarring accelerator  803 , packer(s)  805 , and a plurality of stabilizers  806 . 
         [0044]    Downhole tool assembly  800  includes multiple spearing devices  802   a  and  802   b,  thereby increasing the number of cut casing segments that may be removed from the wellbore in a single trip. Downhole tool assembly  800  may thus be used in a cutting operation wherein cutting device  801   a  is activated, and a first casing segment is cut. Spearing device  802   a  may then be activated, thereby engaging spearing device  802   a  with the first casing segment, and jarring device  804  may be activated to free the cut casing segment from the wellbore. Subsequently, second cutting device  801   b  may be activated, and a second casing segment may be cut. Spearing device  802   b  may then be activated, so as to engage the cut casing segment. Jarring device  803  may then be reactivated, and the second casing segment may be freed from the wellbore. The above described method of cutting, spearing, and jarring may be repeated as many times as the cutters on individual cutting devices  801  allow. As such, multiple casing segments may be cut, speared, and removed from the wellbore in a single trip. 
         [0045]    Those of ordinary skill in the art will appreciate that the order of operation of the individual components may be varied, without departing from the scope of the present disclosure. For example, in one embodiment, cutting device  801   a  may be activated, and a first casing cut made. Cutting device  801   a  may then be deactivated, and the tool string lowered axially within the wellbore. Cutting device  801   a  may then be reactivated, and a second casing cut may be made. This process of making multiple casing cuts may be repeated for the life of the cutters on cutting device  801   a.  After the desired number of casing cuts are made, spearing device  802   a  may engage one or more of the cut casing segments, and jarring device  804  may be activated to help free the casing cuts. 
         [0046]    In other embodiments, after the plurality of casing cuts by cutting device  801   a  have been made, cutting device  801   b  may be activated, and a plurality of additional casing cuts may be made. Similar to the function of cutting device  801   a,  cutting device  801   b  may be activated and deactivated until the desired number of casing cuts has been made. After all of the casing cuts have been made by both cutting devices  801   a  and  801   b,  one or more of spearing devices  802   a  and  802   b  may be activated to engage the cut casing segments. In one embodiment, both spearing devices  802   a  and  802   b  may be activated, while in other embodiments only one of spearing devices  802   a  or  802   b  may be required to allow for the removal of the cut casing segments from the wellbore. Those of ordinary skill in the art will appreciate that it may only be necessary to engage the lowest axial spearing device, in this embodiment  802   b,  when removing the casing segments. Because the higher axial casing segments will be pulled up to the surface of the wellbore as the lowest axial casing segment is pulled upwardly, only one spearing device  802   b  may be required to remove multiple casing segments. However, in certain embodiments, it may be beneficial to engage multiple spearing devices  802  with the cut casing segments so as to increase the contact area between the spearing device  802  and the casing being removed. By increasing the surface area of the contact between the spearing device  802  and the casing, more casing may be removed from the wellbore in a single trip. 
         [0047]    Fishing tool assemblies as described above include a spearing device, or grapple, that is configured to engage drill pipe or casing. The spearing device may be internal to the cylindrical body of a cutting tool, or in other embodiments, may be a separate component of a fishing tool assembly. In such an embodiment where the spearing device is a separate component of a fishing tool assembly, the spearing device may be disposed axially upward of a cutting tool, and may engage the drill pipe or casing before, during, and/or after the cutting operation. Thus, drill pipe may be held in place during operation, and as the cutting tool assembly is removed from the wellbore, the cut section of the drill pipe may also be removed from the wellbore. 
         [0048]    Any of the above described embodiments may allow for multiple casing segments to be removed from a wellbore in a single trip. The order of operation of specific embodiments of the present disclosure may vary according to the requirements of the cutting operation. For example, in certain embodiments, multiple casing cuts may be made, followed by a single spearing and jarring. In other embodiments, multiple casing cuts may be followed by multiple spearing and jarring. Accordingly, all of the casing cuts may be made initially, followed by spearing the lowest axial cut casing segment, jarring one or more of the segments, and then removing the freed casing segments from the wellbore. Those of ordinary skill in the art will appreciate that each cut casing segment may be jarred loose separately. In other embodiments, it may be beneficial to cut a desired number of casing segments, spear the segments, and then cut additional segments. In such an embodiment, multiple spearing devices may facilitate the cutting and removal of the cut casing segments from the wellbore. 
         [0049]    Advantageously, embodiments of the present disclosure may allow for casing segments to be cut, speared, and removed from a wellbore in a single trip of the tool string. By providing multiple cutting devices that may be sequentially activated by the use of, for example, radio frequency transmission, sequentially sized ball drop actuation, pressure pulse actuation, and/or pressure thresholds, a plurality of casing segments may be cut, speared, and removed from the wellbore. Such activation may be remotely and selectively controlled from the rig floor. By removing multiple casing segments in a single trip, valuable time may be saved in slot recovery operations. Additionally, by decreasing the number of trips of the tool string to cut and recover casing segments, the cost of a slot recovery operation may be decreased. 
         [0050]    The hydraulically actuated spears disclosed herein, such as illustrated in  FIGS. 2 and 4 , may provide for a greater expansion of the grapple members, allowing an increased initial clearance, and facilitating insertion of the tool assembly within the casing. The greater expansion may also provide for use of an improved teeth (wickers) design, and for increased gripping forces, allowing a greater weight carrying capacity as compared to mechanically activated spearing devices, and facilitating removal of larger and/or more sections of casing in a single trip. For example, in the case of upward pulling, the force applied is directly transmitted from the casing to top sub  201  and in turn to mandrel  207 . This force pulls mandrel  207  upward relative to the now “stuck” grapple  206 , thereby increasing the radial expansion forces acting upon the grapple, and thus increasing the gripping force between the grapple wickers and the casing. 
         [0051]    While the disclosure includes a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments may be devised which do not depart from the scope of the present disclosure. Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Summary:
A spearing device for use in removing casing is disclosed. The spearing device includes: a top sub; a bottom sub; a mandrel, coupled to the top and bottom subs, having an outer corrugated surface; a grapple having a correspondingly corrugated inner surface and an outer surface including wickers for engaging an interior surface of the casing; a piston disposed within the mandrel and operatively coupled to the grapple; and a spring operative with the piston and biasing the grapple toward a collapsed position. The grapple: (i) axially and rotationally moves along the corrugated outer surface of the mandrel and (ii) expands and collapses responsive to axial movement relative to the mandrel. Responsive to increases in hydraulic pressure, the piston compresses the spring and axially moves and expands the grapple. Responsive to subsequent decreases in hydraulic pressure, the spring decompresses and axially moves and collapses the grapple.