Patent Publication Number: US-10774602-B2

Title: High radial expansion anchoring tool

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     None. 
     FIELD OF USE 
     Generally, methods and apparatus are presented for anchoring or positioning a gauge or other tool in a wellbore extending through a subterranean formation. More specifically, presented are anchoring devices for use on a wireline and having relatively high radial expansion, thereby allowing anchoring of a relatively small diameter gauge or other tool in standard tubing. 
     BACKGROUND 
     Mechanical operations are typically performed in the course of drilling, maintaining, and producing subterranean hydrocarbon wells, including operations requiring anchoring, temporarily or permanently, of one or more devices or tools in a downhole tubular such as tubing, liner, casing, etc. The anchoring may be required to allow the application of axial forces to the device, such as by fluid flow or tubing string manipulation. Anchoring may also be desirable to maintain a device in a selected position within the wellbore or to allow a device to be anchored in the wellbore without suspension or support from the surface, for example. 
     To facilitate anchoring, a downhole tool is anchored at a location in a wellbore with an anchoring device. For example, many anchoring devices use slips that support large forces. However, slips have limited radial expansion with respect to the tool body. Other anchoring devices use dogs or arms that extend from a tool body into a corresponding groove feature in a downhole tubular. Such devices support large forces but require special anchoring grooves at specific locations within the tubular. 
     Wireline tools are often employed and must be anchored within tubing at selected locations. Anchoring of the wireline tool can also require significant radial expansion of the anchoring mechanisms. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a more complete understanding of the features and advantages of the present disclosure, reference is now made to the detailed description of the disclosure along with the accompanying figures in which corresponding numerals in the different figures refer to corresponding parts and in which: 
         FIG. 1  is a schematic of an exemplary well system illustrated as having an anchoring tool positioned therein according to an aspect of the disclosure; 
         FIG. 2  is an elevational view of multiple exemplary anchoring tools connected in an exemplary tool string; 
         FIG. 3  is a detail, elevational view of a portion of an exemplary anchoring tool, seen in a run-in position, according to an aspect of the disclosure; 
         FIG. 4  is a cross-sectional view of an exemplary anchoring tool seen in a run-in or radially reduced position according to an aspect of the disclosure; and 
         FIG. 5  is a cross-sectional view of an exemplary anchoring tool seen in a set or radially expanded position according to an aspect of the disclosure. These figures are discussed in conjunction, with like parts having like numbers throughout. 
     
    
    
     It should be understood by those skilled in the art that the use of directional terms such as above, below, upper, lower, upward, downward and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure. Where this is not the case and a term is being used to indicate a required orientation, the Specification will state or make such clear. 
     DETAILED DESCRIPTION 
     While the making and using of various embodiments of the present disclosure are discussed in detail below, a practitioner of the art will appreciate that the present disclosure provides applicable inventive concepts which can be embodied in a variety of specific contexts. The specific embodiments discussed herein are illustrative of specific ways to make and use the disclosure and do not limit the scope of the present disclosure. The description is often made with reference to a vertical wellbore. However, the disclosed embodiments herein can be used in horizontal, vertical, or deviated bores. 
     As used herein, the words “comprise,” “have,” “include,” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps. It should be understood that, as used herein, “first,” “second,” “third,” etc., are arbitrarily assigned, merely differentiate between two or more items, and do not indicate sequence. Furthermore, the use of the term “first” does not require a “second,” etc. The terms “uphole,” “downhole,” and the like, refer to movement or direction closer and farther, respectively, from the wellhead, irrespective of whether used in reference to a vertical, horizontal or deviated borehole. 
     The terms “upstream” and “downstream” refer to the relative position or direction in relation to fluid flow, again irrespective of the borehole orientation. Although the description may focus on a particular means for positioning tools in the wellbore, such as a tubing string, coiled tubing, or wireline, those of skill in the art will recognize where alternate means can be utilized. As used herein, “upward” and “downward” and the like are used to indicate relative position of parts, or relative direction or movement, typically in regard to the orientation of the Figures, and does not exclude similar relative position, direction or movement where the orientation in-use differs from the orientation in the Figures. 
     As used herein, “tubing,” “downhole tubular,” and the like refer to any downhole tubular member including tubing strings, work strings, series of connected pipe sections, joints, screens, blanks, cross-over tools, downhole tools, liners, casings, and the like, in or insertable into a wellbore, whether used for drilling, work-over, production, injection, completion, or other processes. 
     The present disclosure generally relates to apparatus and methods for anchoring a tool in a wellbore. The tool may be anchored within any downhole tubular, including casing, liner, internal tubing, etc., at a selected location, as well as in an open bore in some circumstances. The anchoring tool can be run-in on a wireline, slick line, coiled tubing, jointed tubing, and the like. 
     The anchoring tool can be used in conjunction with other downhole tools and systems. The anchoring tool is movable between a run-in and a set position and can be used with a running tool, setting tool, downhole power unit, or other type of actuator or power supply. The anchoring tool can be used to position or hang sensors and gauges in the wellbore, such as downhole gauge tools, as are known in the industry. Alternately, the tool can be used to provide an anchoring force to allow axial force to be applied to and operate additional downhole tools. The anchoring tool can be set to remain in position for extended periods of time, such as in a monitoring or abandoned well. The anchoring tool can also be sequentially set at various positions within the wellbore during wellbore operations. 
     The anchoring tool is designed to provide relatively significant radial expansion when moved to the set position from the run-in position. The significant radial expansion allows the tool to pass through restrictions in, for example, a tubing string or liner while in the run-in position. Upon setting, in the radially expanded and set position, the tool can be anchored in relatively larger diameter tubulars below such restrictions. The tool also enables anchoring in featureless tubing or monobore of a variety of diameters. 
     By way of example, and not by limitation, an exemplary embodiment of the disclosed tool can have a 1.5 inch outer diameter (OD) in the run-in position and expand to anchor in 2⅞ inch or 3½ inch OD tubing. For example, the tool can be run in 3½ inch, 10.2 lb/ft tubing, having an inner diameter (ID) of 2.98 inches. In such an instance, utilizing an anchoring tool having a 1.5 inch OD, the expansion ratio is approximately almost 1.99:1. In this example, the annular clearance between tool and tubular is 0.74 inches. By minimizing the OD of the anchoring tool, the flow restriction past the tool is also minimized. 
     In general, the anchoring tool functions by radially extending anchoring arms away from a tool housing until the arms contact and grippingly engage the wall of a downhole tubular. Each arm applies a radial force to the tubular surface which anchors the tool in place. As described herein below, each arm is extended radially outward through cooperation with and relative movement with respect to a wedge. The wedges support the arms while engaged with the tubular surface when the tool is in a set position. Each arm is deployed by relative movement in a first direction between the arm and its corresponding cooperating wedge. The arms are returned to a radially reduced, run-in position by relative movement in another (e.g., opposite) direction. 
     Referring generally to  FIG. 1 , one embodiment of a well system  20  is illustrated as having an anchoring assembly  24  including an anchoring tool  26 . In this embodiment, the anchoring tool  26  is connected to a well tool  28  which may have a variety of forms depending on the specific well application in which the tools are utilized. For example, well tool  28  may comprise a wireline tool for performing a variety of downhole operations. Well tool  28  also may comprise a completion tool, a tool string, a treatment tool, or a variety of other tools deployed downhole, as is known in the art. 
     In the embodiment illustrated, anchoring tool  26  and well tool  28  are deployed downhole in a wellbore  30  within a tubular  32 , which may comprise a well completion assembly, casing, production tubing, or other downhole structure. A conveyance  34 , such as a wireline, is used to deploy the anchoring tool  26  and the well tool  28  into the wellbore  30  from the surface  36 . Other conveyances, such as coiled tubing or jointed pipe, also can be used to deploy the anchoring tool. 
       FIG. 2  is an elevational view of a plurality of exemplary anchoring tools  26   a - b  connected to a running or setting tool  25 , optional locking sub  88 , and a representative well tool  28  in an exemplary tool string. As shown, multiple anchoring tools  26   a - b  can be employed on a single tool string and used to insure successful anchoring of the string. 
     The setting tool  25  includes an actuator  27  which can be of any type and is operable to cause relative axial movement between the anchoring tool arms and wedges, thereby radially expanding the arms into contact with the downhole tubular  32 . The actuator  27  of the setting tool  25  can be hydraulically, electrically, mechanically, electro-mechanically, chemically or otherwise powered. The setting tool  25  can provide linear or other force or movement. Further, the setting tool  25  can utilize one or more piston assemblies, linear actuators, such as a power screw or other type of screw-based actuator, etc. The actuator can comprise an explosive charge, a spring, a gas charge, or a combination thereof. In other embodiments the actuator  27  can comprise a slip joint disposed in the tool  26  enabling selective relative movement of the arms and wedges. By way of example, the actuator  26  can comprise a Baker Style 10 or 20 setting tool, commercially available from Baker-Hughes Oil Tools, Inc. Other setting tools are commercially available from Halliburton Energy Services, Inc., and Schlumberger Limited, for example. 
     In a preferred embodiment, a setting tool locking mechanism  31  is provided to maintain the actuator  27  in its set or stroked position after the operation or stroke of the actuator  27 . The locking mechanism  31  for locking movement of the actuator can be positioned in the setting tool  26 , a designated sub, or elsewhere. The locking mechanism  31  is preferably designed to lock the setting tool elements in the set position only after the set position has been reached. The locking mechanism  31  can be keyed to the actuator stroke length, radial movement of the anchor arms  40 , resistance force acting on the actuator  27 , etc. In a preferred embodiment, a shearing device  33 , such as a shear pin, is provided in the setting tool  25  and is sheared upon completion of an effective actuator stroke. The shear pin releases a locking element which prevents movement of the actuator  27 , relative movement of elements of the setting tool  25  and/or of the anchoring tool  26 . The locking mechanism  31  prevents accidental or premature un-setting. The locking mechanism  31  can be a collet assembly, mating profiles, ratchet assembly, snap or lock ring, or other mechanism known in the art. 
     The optional locking sub  88  houses a selectively actuable and releasable locking mechanism  86 . For example, the locking mechanism  86  can be a ratchet assembly having a release mechanism  87  such as a shear pin. The locking mechanism  86  maintains the tool  26  in a set position and, upon completion of desired operations, provides for releasing the tool  26  to an un-set or run-in position for subsequent retrieval. 
       FIG. 3  is a detail, elevational view of a portion of an exemplary anchoring tool, seen in a run-in position, according to an aspect of the disclosure.  FIG. 4  is a cross-sectional view of an exemplary anchoring tool seen in a run-in or radially reduced position according to an aspect of the disclosure.  FIG. 5  is a cross-sectional view of an exemplary anchoring tool seen in a set or radially expanded position according to an aspect of the disclosure. These figures are discussed in conjunction, with like parts having like numbers throughout. 
     The anchoring tool  26  comprises a tool housing  38  and anchor arms  40  that move relative to the housing  38  between a radially contracted run-in position and a radially expanded set position. In  FIG. 3 , a portion of one embodiment of anchoring tool  26  is illustrated as having a plurality of arms  40  positioned in the run-in position to allow movement of the anchoring tool  26  through a downhole tubular  32 , including through any restrictions therein. In the example shown, housing  38  comprises an upper body  42  and a lower body  43  which are connected and axially movable relative to one another. 
     The upper body  42  has recesses  44  sized to receive corresponding arms  40 . When the arms  40  are in a radially contracted position, they can be contained within the envelope of the tool  26  such that the arms  40  do not limit the ability of tool  26  to pass through restrictions during deployment or retrieval of the tool  26 . By way of example, the tool housing  38 , and upper and lower bodies  42  and  43 , may have a maximum OD of 1.5 inches when in the run-in position, with the arms positioned interior to the OD. 
     The arms  40  pivot between the run-in position seen in  FIG. 4  and the radially expanded or “set” position seen in  FIG. 5 . Each arm  40  has a pivot hole extending therethrough which receives a pivot pin  50 . The ends of the pivot pin  50  also engage mating holes in the upper body  42 , thereby pivotally attaching the arm  40  to the upper body  42 . The arm  40  defines a gripping or engagement surface  52  at its free end  54 . In one or more embodiments the engagement surface  52  includes one or more gripping features, such as teeth, ridges, grooves, buttons, or other surface features to assist in grippingly engaging the downhole tubular  32 . 
     In one or more embodiments, the arms  40  are held or urged toward the run-in position. For example, in a preferred embodiment, each arm  40  is biased toward the run-in position by a biasing assembly  58 , such as leaf spring  60 . The leaf spring  60  is attached, such as via screw or bolt  62 , to the upper body  42 . The free end of the leaf spring  60  engages the arm  40 , exerting a biasing force on the arm, urging it toward the run-in position. During operation, as the arm  40  rotates to a set position, the free end of the leaf spring  60  is forced to bend away from the upper body  42 . In the embodiment shown, the arm  40  defines a recess  41  sized to accept and interact with the biasing leaf spring  60 . Upon release or disengagement of the anchoring tool  26 , the arms  40  disengage from the wall of the tubular  32  and pivot back toward the run-in position, at least partially in response to the urging of the biasing spring  60 . Other biasing mechanisms can be used, including springs, coil springs, torsion springs, elastomeric materials, etc. In one or more embodiments, the biasing mechanism resides within the tool envelope, as shown. Here, the leaf spring  60  and screw  62  are housed within recesses defined in the exterior of the upper body  42 . The biasing mechanism can also be positioned radially interior to the arm  40  if desired. 
     In one or more embodiments, an additional or alternative biasing assembly  90  is provided having a shaft  92  positioned in corresponding bores  94  defined in the upper and lower bodies  42  and  43 . A biasing element  96 , such as the spring shown or similar, is positioned to exert force on the shaft  92 . The bores  94  define contact shoulders  98  for limiting movement of the shaft  92  and biasing element  96 . When the upper and lower bodies  42  and  43  are in the set position, seen in  FIG. 5 , the biasing element  96  exerts force on the shaft  92 , which in turn exerts force on the lower shoulder  98 , urging the upper and lower bodies  42  and  43  axially apart from one another and toward the run-in position. The shafts  92 , of which there are three in the embodiment seen, also serve to prevent relative rotation of the upper and lower bodies  42  and  43 , providing torsional rigidity to the tool  26 . 
     Arm  40  defines a radially inward facing surface  66 , referred to herein as the interior surface  66 . The interior surface  66  extends along the arm  40  from adjacent the pivot pin  50  to the engagement surface  52  at the free end  54  of the arm  40 . The interior surface  66 , in a preferred embodiment, defines at least an initial contact surface  68  and a cam surface  70  which interact with corresponding wedge  76  during setting of the tool  26 . 
     The lower body  43  includes wedges  76  which correspond to and cooperate with the arms  40 . The wedges  76  can be formed by the lower body  43  or can be mounted to the body, such as by bolts  78 . In this way, the wedges  76  can easily be removed and replaced. In one or more embodiments, the wedges  76  are fitted into corresponding recesses  82  defined in the exterior surface of the lower body  43 . Each wedge  76  defines a sloped contact surface  80  which contacts and forces pivotal movement of the corresponding arm  40  during setting. The wedge surface  80  also supports the arm  40  while in the set position. In one or more embodiments, the wedge surface  80  is generally planar. The wedge  76  and its contact surface  80  are preferably made of an extremely hard material to minimize flexion. Also preferably, the wedge  76  or its contact surface  80  is made of a self-lubricating material. 
     In use, the tool  26  is attached to a conveyance  34 , such as a wireline, slick line, coiled tubing, tubing string, etc., and lowered into the wellbore  30  and the tubular  32  positioned therein. The tool  26  is initially in a run-in position wherein the anchor arms  40  are retracted to a radially reduced profile. One or more biasing mechanisms operate to maintain the arms  40  in the run-in position. For example, as discussed previously, the leaf spring  60  of biasing assembly  58  can be employed to inhibit movement of the arm  40 . Alternately or additionally, the biasing assembly  90  can urge the upper and lower bodies  42  and  43  toward the run-in position. 
     The tool, having a relatively small OD, is sized to pass through restrictions which may be present in the tubular  32 , for example. The tool  26  is positioned in the wellbore  30  at a desired location. The tool  26  is then set into a set position wherein the arms  40  are in gripping engagement with the tubular  32 . Wellbore operations are then run, as desired. For example, the tool  26  can support a well tool  28 , such as a gauge tool, in the wellbore  30  to take short-term or long-term measurements. Alternately, the tool  26  can support other well tools. The conveyance  34  can be detached from the tool  26  if desired and removed to the surface. In such a case, a conveyance  34  is later lowered into the wellbore  30  to un-set and retrieve the tool  26 . Upon completion of operations, the tool  26  is retracted from its set position to its run-in position for movement to another location, such as the surface  36  or another downhole position. 
     Actuation of the anchoring tool  26  from the run-in to the radially expanded, set position is caused by moving the upper body  42  and the lower body  43  axially with respect to one another.  FIGS. 4 and 5  show the upper and lower bodies in their relative positions during run-in ( FIG. 4 ) and after setting the tool ( FIG. 5 ). As the upper and lower bodies are moved axially toward one another, so are the wedges  76  and the corresponding arms  40 . The initial contact surface  68  of the interior surface  66  of the arm  40  contacts and slides along the sloped contact surface  80  of the wedge  76  during initial movement of the arm  40  from the run-in to the set position. The initial contact surface  68  of the arm  40  is preferably generally planar, as shown. In response to contact with the contact surface  80  of the wedge  76 , arm  40  pivots outwardly at a first pivot rate and to a first maximum angle α (with respect to the longitudinal axis of the tool) and to a first maximum OD. The cam surface  70  defined on the interior surface  66  of the arm  40  subsequently contacts and slides along the contact surface  80  of the wedge  76 , resulting in a second, increased pivot rate for the arm  40  during setting, and a second greater maximum pivot angle β and second or maximum OD when the arm  40  is fully radially extended. Thus, the cam surface allows for a relatively greater radial expansion of the pivoting arm  40 , allowing the tool  26  to have a relatively greater expanded OD to run-in OD ratio. The cam surface  70  maintains contact with the wedge  76  while the arm  40  is in the set position such that the wedge  76  supports the arm  40 . In the example illustrated, the tool  26  comprises three arms  40 , however other numbers of anchoring arms can be used in alternate embodiments. The arm  40  pivots radially outward into gripping engagement with the wall of the tubular  32 . The tool  26  is then in the set position and supports itself in the wellbore  30 . 
     Relative axial movement of each of the wedges  76  away from the arms  40  causes the arms  40  to pivot back toward the radially reduced, run-in position. In one or more embodiments, a biasing assembly  58  having leaf spring  60 , biases the arms  40  towards the run-in position. Similarly, the biasing assembly  90  can force movement of the arms  40  toward the run-in position. As the upper and lower bodies  42  and  43  are moved axially apart, the arms  40  disengage the wall of the tubular  32  and return to their run-in positions. 
     Relative axial movement of the upper and lower bodies  42  and  43 , and therefore the wedges  76  and arms  40 , can be achieved by an actuator  27  Actuator  27  is coupled to the upper body  42  and/or lower body  43  to induce the desired relative axial movement. In the embodiment illustrated in  FIG. 2 , a setting tool  25  is connected to the tools  26   a - b  to operate the anchor assemblies. For example, the setting tool  25  can pull upward on one or more interior body elements, such as a core rod  85 , while pushing down on exterior body elements, such as upper and lower bodies  42  and  43 , or vice versa. The core rod  85  extends the length of the tool  26  and is fixedly attached to the lower body  43 . The core rod  85  is initially and releasably attached to the upper body  42  by a temporary holding mechanism, such as a shear pin, shear ring, etc. For example, shear pins selected to shear upon application of ten pounds of force can extend between the upper body  42  and the core rod  85 . 
     In one or more embodiments, a releasable, locking mechanism  86  is provided allowing selective and temporary locking of relative movement between the upper body  42  and the core rod  85 . When the core rod  85  is moved axially upward relative to the upper body  42  in response to actuation of the actuator  27 , thereby setting the tool  26 , the locking mechanism  86  actuates and prevents premature or accidental un-setting of the tool  26 . The locking mechanism  86  can be a collet device, mating profiles, a ratchet assembly, a snap or lock ring, or other mechanism known in the art. In one or more embodiments, the locking mechanism  86  is housed in a sub  88  attached to the upper end of the tool  26 . Alternately, the locking mechanism  86  can be housed in the anchoring tool  26  or setting tool  25 . Releasing the locking mechanism  86  can be achieved by various means, such as by forcing the core rod  85  downward or upward, removing a collet support, shearing, snapping, or forcing a temporary holding device such as a shear pin or ring, mating profiles, sliding sleeve, ratchet, etc. Releasing the locking mechanism  86  can be achieved by mechanical methods, such as manipulation of the conveyance  34  from the surface  36 , actuation of a downhole power unit, etc. 
     In one or more embodiments, the actuator  27  in the setting tool  25  pulls upward on the core rod  85 , thereby shearing shear pins attaching the upper body  42  to the core rod  85 . The lower body  43  is moved upward with the core rod  85 . In this manner, the lower body  43  is moved axially into closer proximity to the upper body  42 . Each wedge  76  positioned on the lower body  43  is moved relative to its corresponding arm  40 , with wedge contact surface  80  acting upon the interior surface  66  of the arm  40 , thereby forcing rotation of the arm  40  radially outward toward the set position. 
     The anchoring tools and methods presented herein provide a simple mechanical design utilizing pivoting arms which are not articulated, jointed, or part of a linkage assembly. The tool is consequently less likely to jam, plastically deform, or fail due to weaknesses typical to articulated assemblies. 
     The anchoring tools and methods presented herein can be used in a variety of well systems and in applications. The anchoring tool can be constructed with two anchoring arms, three anchoring arms, or a greater number of anchoring arms depending on the parameters of a given application. Additionally, the anchoring tool can be incorporated into or used in cooperation with other types of well tools. The anchoring tool can be deployed singly or with multiple anchoring tools in series. The anchoring tool can be deployed via wireline or other suitable conveyance. Furthermore, the one or more anchoring tools can be actuated via a variety of actuators, including hydraulic, electrical, electro-mechanical, explosive charge, gas charge, spring, conveyance manipulation, and other suitable actuators. 
     In one or more embodiments, the methods described here and elsewhere herein are disclosed and support method claims submitted or which may be submitted or amended at a later time. The acts listed and disclosed herein are not exclusive, not all required in all embodiments of the disclosure, can be combined in various ways and orders, repeated, omitted, etc., without departing from the spirit or the letter of the disclosure. For example, disclosed is an exemplary method of using an anchoring tool in a wellbore extending through a subterranean formation, the method comprising the steps of: 1. A method of positioning an anchoring tool in a downhole tubular positioned in a wellbore, the method comprising: running an anchoring tool into a downhole tubular, the anchoring tool in a run-in position, wherein pivot arms pivotally mounted on the tool are disposed in a radially inward position; positioning the anchoring tool at a selected location in the downhole tubular; and setting the anchoring tool in the tubular, comprising: moving an upper and lower body of the anchoring tool axially relative to one another; moving wedges positioned on the upper or lower body, axially relative to corresponding pivot arms positioned on the other of the upper or lower body; sliding a sloped contact surface defined on each wedge relative to a contact surface defined on each corresponding pivot arm; and pivoting the pivot arms, in response to the relative sliding movement of the wedge and arm contact surfaces, radially outward and into gripping engagement with the tubular. 2. The method of claim  1 , further comprising releasing the anchoring tool from the set position by pivoting the pivot arms toward the run-in position. 3. The method of claim  1  or  2 , wherein the contact surface defined on each pivot arm further comprises: an initial contact surface and a cam surface, and further comprising: sliding the initial contact surface along the wedge contact surface; and pivoting the pivot arm radially outward to a first angle with respect to a longitudinal axis of the anchoring tool. 4. The method of claim  3 , further comprising: sliding the cam surface along the wedge contact surface after pivoting the arm to the first angle; and pivoting the pivot arm radially outward to a second angle with respect to a longitudinal axis of the anchoring tool, the second angle greater than the first angle. 5. The method of claims  3 - 4 , wherein the first angle is the maximum angle achievable by relative sliding movement of the wedge contact surface along the initial contact surface of the pivot arm. 6. The method of claims  1 - 5 , wherein the pivot arms have gripping surfaces for gripping the tubular, the gripping surfaces selected from the group consisting of: teeth, ridges, grooves, and buttons. 7. The method of claims  2 - 5 , wherein releasing the anchoring tool from the set position further comprises moving the upper and lower bodies axially away from one another. 8. The method of claim  7 , wherein releasing the anchoring tool from the set position further comprises biasing the upper and lower bodies axially away from one another. 9. The method of claim  8 , wherein the biasing is performed by a spring, positioned in the upper or lower body, exerting force against a surface defined on the other of the upper or lower body. 10. The method of claim  9 , wherein the spring exerts force against a shaft movable mounted in the upper and lower bodies. 11. The method of claims  1 - 10 , further comprising biasing the pivot arms towards the run-in position. 12. The method of claim  11 , wherein the biasing is performed by springs exerting force on corresponding pivot arms and urging the pivot arms radially inwardly. 13. The method of claims  1 - 12 , further comprising, after moving the upper and lower body of the anchoring tool axially relative to one another, releasably locking the upper body and lower body relative to one another in a set position. 14. The method of claim  13 , wherein the locking is performed by a locking mechanism selected from the group consisting of: a collet device, mating profiles, a ratchet mechanism, a snap ring, and a lock ring. 15. The method of claims  1 - 12 , wherein moving the upper and lower body of the anchoring tool axially relative to one another further comprises moving a core rod positioned in the anchoring tool, the core rod attached to the lower body. 16. The method of claims  1 - 15 , wherein the pivot arms are housed in recesses defined in the upper or lower body. 17. The method of claims  1 - 16 , wherein the wedges are removable mounted in recesses defined in the upper or lower body. 18. The method of claims  1 - 17 , wherein the contact surfaces of the wedges are self-lubricating. 19. The method of claims  1 - 18 , wherein setting the anchoring tool in the tubular further comprises actuating a downhole actuator to cause relative movement of the upper and lower bodies. 20. The method of claims  1 - 19 , wherein running the anchoring tool into the downhole tubular further comprises running-in the tool on a conveyance selected from the group consisting of: wireline, slick line, coiled tubing, or jointed tubing. 
     Exemplary methods of use of the disclosure are described, with the understanding that the disclosure is determined and limited only by the claims. Those of skill in the art will recognize additional steps, different order of steps, and that not all steps need be performed to practice the disclosed methods described. 
     Persons of skill in the art will recognize various combinations and orders of the above described steps and details of the methods presented herein. While this disclosure has been described with reference to illustrative embodiments, this description is not intended to be construed in a limiting sense. Various modifications and combinations of the illustrative embodiments as well as other embodiments of the disclosure will be apparent to persons skilled in the art upon reference to the description. It is, therefore, intended that the appended claims encompass any such modifications or embodiments.