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TECHNICAL FIELD 
     This disclosure relates to securing a downhole tool at a location downhole, and more particularly to systems and methods for securing a downhole tool, such as a packer, within a well casing. 
     BACKGROUND 
     Downhole tools, such as packers, straddle packers, fracturing plugs (“frac plugs”), and bridge plugs, may be secured in place down hole to isolate one or more portions of a wellbore from one or more other portions of a wellbore. 
     SUMMARY 
     A downhole tool according to one aspect includes an elongated mandrel, a first slip assembly carried on the mandrel, and a second slip assembly carried on the mandrel. The first slip assembly may include a first slip radially extendable to grip a wall of a wellbore and a first engaging portion. The first engaging portion may be adapted to grip the mandrel against relative movement in a first axial direction and allow relative movement of the mandrel in a second axial direction. The second slip assembly may include a second slip radially extendable to grip the wall of the wellbore and a second engaging portion. The second engaging portion may be adapted to grip the mandrel against relative movement in the first axial direction and allow relative movement of the mandrel in the second axial direction. The downhole tool also includes a sealing element carried on the mandrel adapted to engage the wall of the wellbore. 
     Another aspect includes a method for diverting loading in a first direction around a sealing element of a downhole tool. The method includes applying a setting load in a first direction through a mandrel to extend a sealing element into contact with an adjacent surface and form a first gripping engagement with the adjacent surface on a first side of the sealing element indicated by the first direction and second gripping engagement with the adjacent surface on a second side of the sealing element opposite the first direction. The method also includes communicating loading through the mandrel in the first direction through the sealing element and the first gripping engagement, and communicating loading through mandrel in the second direction through the second gripping engagement and bypassing the sealing element. 
     A further aspect includes a downhole tool configurable between an unset and set configuration and adapted to provide a seal downhole. The downhole tool includes an elongated mandrel and a first slip assembly carried on the mandrel comprising a first engagement portion, a first radially expandable engagement member adapted to grip the wall of the wellbore and a first wedge adapted to expand the first radially expandable engagement member. The downhole tool also includes a second slip assembly carried on the mandrel comprising a second engagement portion, a second radially expandable engagement member adapted to grip the wall of the well bore and a second wedge adapted to expand the second radially expandable engagement member. A sealing element may be carried on the mandrel and disposed between the first slip assembly and the second slip assembly. The sealing member may be adapted to radially expand to engage a wall of a wellbore. A first load path extending through the second engagement portion and bypassing the sealing element in the set configuration to conduct loading applied to the mandrel in the first axial direction, and a second load path extending through the sealing element and the first engagement portion in the set configuration to conduct loading applied to the mandrel in the second axial direction. 
     The various aspects may include one or more of the following features. The sealing element may be positioned between the first slip assembly and the second slip assembly. The first slip assembly and the second slip assembly may cooperate to form a first load path bypassing the sealing element when the mandrel is loaded in the first axial direction and a second load path including the sealing element when the mandrel is loaded in the second axial direction. One of the first engaging portion or the second engaging portion comprises may include a wedge that grips the mandrel. At least one of the first slip assembly, the second slip assembly, or the sealing element may be adapted to be actuated fluidically. At least one of the first slip assembly, the second slip assembly, or the sealing element may be adapted to be actuated by a wireline actuation tool. At least one of the first engaging portion or the second engaging portion may be adapted to ratchet in the second axial direction relative to the mandrel. 
     The various aspects may also include one or more of the following features. The adjacent surface is an interior surface of a wellbore casing. Forming the first gripping engagement with the adjacent surface may include radially expanding a first engagement member on the first side of the sealing element to grip the adjacent surface, and forming the second gripping engagement with the adjacent surface may include radially expanding a second engagement member on the second side of the sealing element to grip the adjacent surface. Radially expanding the first engagement member may include ratcheting the first engagement member along a length of the mandrel in a second direction opposite the first direction. Radially expanding the second engagement member may include ratcheting the second engagement member along a length of the mandrel in a second direction opposite the first direction. Applying the setting load in the first direction may include fluidically applying the setting load. 
     The various aspects may further include one or more of the following features. The first slip assembly and the second slip assembly may cooperate to radially expand the sealing element. At least one of the first slip assembly or the second slip assembly may be adapted to ratchet along the mandrel in the first axial direction. At least one of the first slip assembly, the second slip assembly, or the sealing element may be adapted to be actuated fluidically. At least one of the first engagement portion or the second engagement portion may include a locking ring disposed adjacent the mandrel and operable to ratchet along the mandrel in the first axial direction. At least one of the first engagement portion or the second engagement portion may include a wedge. The downhole tool may include a housing carried on the mandrel and a channel having a substantially zero internal pressure formed between the housing and the mandrel. The first engagement portion may be adapted to grip the mandrel against relative movement in a first axial direction and allow relative movement of the mandrel in a second axial direction opposite the first axial direction. The second engagement portion may be adapted to grip the mandrel against relative movement in a first axial direction and allow relative movement of mandrel in a second axial direction opposite the first axial direction. 
     The details of one or more implementations are set forth in the accompanying drawings and the description below. Other features, objects, and advantages will be apparent from the description and drawings, and from the claims. 
    
    
     
       DESCRIPTION OF DRAWINGS 
         FIG. 1  shows a schematic of a wellbore extending from a terranean surface and having a downhole tool disposed therein. 
         FIGS. 2A-C  show an example downhole tool in the running configuration that is actuated by a wireline actuation tool and set from the top-down. 
         FIGS. 3A-C  show the example downhole tool of  FIGS. 2A-C  in the set configuration. 
         FIG. 4  shows a detail view of an example slip ring of the downhole tool shown in  FIGS. 2A-C  and  3 A-C. 
         FIG. 5  is a detail view of a locking ring system. 
         FIG. 6  is a detail view of various components of the locking ring system of  FIG. 5 . 
         FIG. 7A-D  shows an example downhole tool in the running configuration that is fluidically actuated and set from the top-down. 
         FIGS. 8A-D  shows the downhole tool of  FIGS. 7A-D  in the set configuration. 
         FIGS. 9A-D  shows an example downhole tool in a running configuration that is fluidically actuated and set from the bottom-up. 
         FIGS. 10A-C  shows the downhole tool of  FIGS. 9A-D  in the set configuration. 
     
    
    
     DETAILED DESCRIPTION 
     The present disclosure encompasses a downhole tool for isolating a portion of a wellbore. An example configuration of an application of the downhole tool is illustrated in  FIG. 1 .  FIG. 1  shows a wellbore  1  extending from a terranean surface  2 . A wellbore casing  3  extends along a least a portion of the wellbore  1 . The casing  3  may be cemented or otherwise secured into place within the wellbore  2 . A downhole system  4  extends into the wellbore  1  and includes a downhole tool  5 , for example, extending from a tubular working string, a wireline or other. The downhole tool  5  may be a sealing tool operable to seal or substantially seal against flow through an annulus  6  formed between the downhole tool  5  and the wellbore casing  3  when the downhole tool  5  is placed in a set configuration. Once set, the downhole tool  5  is operable to transmit force applied to the downhole tool  5  in one direction through the rigid components of the downhole tool, thus, bypassing a resilient sealing element  6  of the downhole tool  5 . In the opposite direction, the force is transmitted through resilient member  6  of the downhole tool  5 . 
       FIGS. 2A-C  and  3 A-C show an example downhole tool  10  that may be used as the downhole tool  5 , shown in  FIG. 1 .  FIGS. 2A-C  show a partial cross-sectional view of the downhole tool  10  in an unset or “running” configuration, and  FIGS. 3A-C  show the downhole tool  10  in a set configuration. The downhole tool  10  is maintained in the running configuration when the downhole tool  10  is being placed into a desired location within the wellbore. The set configuration represents the downhole tool  10  after being set into position within the wellbore. The downhole tool  10  shown in  FIGS. 2A-C  is a wireline-actuated tool. However, in certain instances the downhole tool may be adapted to be actuated in other manners, for example, fluidically (hydraulically and/or hydrostatically) actuated, mechanically actuated by manipulating a tubing coupled to the downhole tool and/or otherwise actuated. Examples of fluidically actuated downhole tools  10  are discussed in more detail with respect to  FIGS. 7A-D ,  8 A-D,  9 A-D, and  10 A-C. 
     The downhole tools described herein could, in some instances, be a packer. In other instances, the downhole tools could be configured as a frac plug for primarily sealing in one direction. In some instances, a frac plug may include only one expansion member, such as expansion member  260 , on one side of a resilient sealing member, such as resilient sealing member  270 . In still other instances, the downhole tools described herein could be configured as a bridge plug by blocking the internal passage of the tubular mandrel, such as tubular mandrel  20 , described below. 
     Referring again to  FIGS. 2A-C  and  3 A-C, the downhole tool  10  includes a tubular mandrel  20  that may be formed of a plurality of tubular elements coupled to each other, for example, by threaded connections, welding, or other joining technique. Alternately, the tubular mandrel  20  may be a single unitary tubular body, subject to manufacturing requirements. The downhole tool  10  may also include a tubular housing  30  circumjacent the tubular mandrel  20  and slideable relative thereto. The tubular housing  30  may also be formed from a plurality of tubular portions connected, for example, by threaded connections, welding, or other joining technique. The downhole tool  10  shown in  FIGS. 2A-C  and  3 A-C is referred to as being set from the “top-down,” because, when placing the downhole tool  10  into the set configuration, the tubular housing  30  is moved downhole and the tubular mandrel  20  is moved uphole. With reference to  FIGS. 2A-C  and  3 A-C, if the uphole location (i.e., towards the terranean surface) is considered to be on the left side of the figure, as indicated), the tubular housing  30  is moved in the direction of arrow  110  and/or the tubular mandrel  20  is moved in the direction of arrow  120  when placing the downhole tool  10  in the set configuration. Other implementations may be considered to be set from “bottom-up” (such as the downhole tool  10  shown in  FIGS. 9A-D  and  10 A-C), because, when placing the downhole tool  10  in the set configuration, the tubular housing  30  is moved uphole (i.e., to the left side of the  FIGS. 9A-D , and  10 A-C) and/or the tubular mandrel  20  is moved downhole (i.e., to the right side of  FIGS. 9A-D , and  10 A-C). 
     Near a first end portion  40  of the tubular housing  30 , a slip ring  50  is disposed between the tubular mandrel  20  and the tubular housing  30 . In some implementations, the slip ring  50  may be wedge-shaped. The slip ring  50  includes an engaging portion  60  formed of a plurality of engaging members or teeth  70 . A detail view of the slip ring  50  is shown in  FIG. 4 . According to some implementations, the teeth  70  are a plurality of asymmetrical teeth. The teeth  70  may form a saw tooth pattern and configured to permit movement of the slip ring  50  relative to the tubular mandrel  20  in one direction but prevent movement of the slip ring  50  relative to the tubular mandrel  20  in an opposite direction. The plurality of asymmetrical teeth  70  may be formed from a plurality of coaxial annular rings or one or more continuous helical threads formed on the interior surface of the slip ring  50 . As shown, the asymmetrical shape of the teeth  70  may form a saw tooth pattern having a vertical or substantially vertical side  90  and a sloped side  100 . However, the shape of the teeth  70  shown in  FIG. 4  is merely one example. Thus, the teeth  70  may have other shapes. 
     The slip ring  50  may also include one or more slits (not shown) formed at an edge of the slip ring  50 , extending through the slip ring  50  and terminating at a distance along the length of the slip ring. Alternating slits formed in the slip ring  50  may have an origin at opposite edges of the slip ring  50  and have terminating ends within the slip ring  50  near opposite ends thereof. Alternately or in addition, the slip ring  50  may include another slit extending entirely through the length of the slip ring  50  resulting in the slip ring  50  having a “C” shape in profile. The slits allow the slip ring  50  to elastically expand radially without yielding. A retaining ring  125 , shown residing in a groove  130  in the tubular housing  30 , may be included to prevent the first retaining ring  50  from being removed from downhole tool  10  during manufacturing and/or assembly and to drive the slip ring  50  along the exterior surface of the tubular mandrel  20 . 
     The configuration of the teeth  70  permits the slip ring  50  to move along the exterior surface of the tubular mandrel  20  in the direction of arrow  110 . However, movement of the slip ring  50  in the direction of arrow  120  causes the teeth to “bite” into the tubular mandrel  20  resulting in an increase in friction that resists movement. Thus, the orientation of the teeth  70  of the slip ring  50  defines the direction in which movement of the slip ring  50  is facilitated. As a general matter, the slip ring  50  is capable of moving in a direction corresponding to the side of the teeth  70  having a shallow angle (in this case, side  100 ) and resists movement in a direction corresponding to the side of the teeth  70  having a vertical or substantially vertical side (in this case, side  90 ). A shallow angle defined at an interface between the slip ring  50  and the housing  90  also contributes to the ability of the slip ring  50  to grip the tubular mandrel  20  in one direction while moving relative to the tubular mandrel  20  in the opposite direction. 
     Continuing along the downhole tool  10 , a first slip  140  is retained around the tubular mandrel  20 , sandwiching a first wedge ring  150  between the first slip  140  and the tubular mandrel  20 . The first slip  140 , wedge ring  150 , and slip ring  50  form a slip assembly  155 . Similar to the slip ring  50 , the first slip  140  includes an engaging portion  160 . As shown, the engaging portion  160  includes a plurality of engaging members or teeth  170  disposed on an exterior surface of the first slip  140 . The teeth  170  may be asymmetrical in shape. Similar to the teeth  70 , described above, the teeth  170  include a sloped side  180  and a vertical or substantially vertical side  190 . The teeth  170  provide for locking engagement with a wellbore casing when the first slip  140  is in an extended position. In the extended position, the first slip  140  resists movement of the downhole tool  10  relative to the wellbore casing in a direction corresponding to arrow  120 . The teeth  170  may be formed from a plurality of adjacent coaxial annular rings or one or more continuous helical threads. The first slip  140  also includes a plurality of longitudinal slits  200  extending from an edge of the first slip  140  and ending at a location within the first slip  140  near an opposing edge of the first slip  140 . Adjacent slits  200  extend from opposing edges of the first slip  140 . Additionally, the first slip  140  includes another slit  210  extending longitudinally through first slip  140  along an entire length thereof so that the first slip  140  forms a “C” shape in profile. Shear pins  220  may be provided on opposing sides of the slit  210  to retain the first slip  140  in position in an unset or “run” configuration prior to setting the downhole tool  10  in position within the wellbore casing. (It is noted that only one of the shear pins  220  is illustrated in  FIG. 2B  due to the partial cross-sectional view presented.) That is, the shear pins  220  temporarily fix the first slip  140  in position as the downhole tool  10  is being run into the wellbore and prior to being placed into a desired location downhole. The slits  200  and  210  facilitate outward radial expansion of the first slip  140  when the downhole tool  10  is placed in a set configuration, i.e., the downhole tool  10  is fixed within the wellbore casing. The first wedge ring  150  has a pair of wedge-shaped protrusions  230  that nest within wedge-shaped recesses  240  formed in the first slip  140 . The first wedge ring  150  may include more or fewer wedge-shaped protrusions extending into corresponding wedge-shaped recesses formed in the first slip  140 . 
     Adjacent the first slip  140  and first wedge ring  150  is a sealing assembly  250  that may be expanded into sealing engagement with the wellbore casing when the downhole tool  10  is placed in the set configuration. In some implementations the sealing assembly  250  may be a packer. As shown, the sealing assembly  250  may include expansion members  260  and a resilient sealing element  270 . The expansion members  260  are operable to eliminate or substantially reduce axial extrusion of the resilient sealing element  270 . Thus, the expansion members  260  are operable to provide a zero extrusion gap for the sealing element  270  when deployed in the set configuration. 
     The downhole tool  10  also includes a locking ring system  280  that includes a locking ring  290  disposed between a portion  32  of the tubular housing  30  and the tubular mandrel  20 . The locking ring  290  has a through-slit (not shown) extending an entire length of the locking ring  290  so that the locking ring  290  has a “C” shape in profile. The locking ring  290  may also include a plurality of slits, similar to the slits  200  described above with respect to the first slip  140 .  FIGS. 5 and 6  show an example implementation of the locking ring system  240 . 
     Referring to  FIGS. 5 and 6 , the locking ring  290  includes a plurality of coarse asymmetrical teeth  300  formed on an external surface thereof and a finer plurality of asymmetrical teeth  310  formed on an inner surface of the slip ring  240 . The teeth  290  engage mating asymmetrical teeth  320  formed on an inner surface of the portion  32  of the tubular housing  30 , and the teeth  310  engage asymmetrical teeth  330  formed on an exterior surface of the tubular mandrel  20 . Any of the teeth  300 - 330  may be formed in a manner similar to the teeth  70 ,  170  described above. For example, the teeth  300 - 330  may be formed from a plurality of coaxial annular rings formed along the locking ring  290  or, alternatively, from one or more continuous helical threads. It should be apparent that if teeth  300  or  310  are formed from one or more continuous helical thread, the mating teeth  320  or  330  would also be formed from one or more continuous helical threads. Similarly, if the teeth  300  or  310  were formed from a plurality of coaxial rings, the mating teeth  320  or  330  would also be formed from a plurality of coaxial rings. 
     In the example implementation shown, a gap  340  is formed between the mating teeth  300  and  320 , and the teeth  310  and  330  have relative sizes such that two teeth  330  fit into the space formed between adjacent teeth  310 . The implementation shown, though, represents only one possible implementation and is not meant to limit the scope of the disclosure. For example, the relative sizes of teeth  310  and  330  may be such that more or less than two teeth  330  may reside in the space formed between adjacent teeth  310 . 
     Further, the portion of the tubular mandrel  20 , the portion  32  of the tubular housing  30 , and the locking ring  290  forming the locking ring system  280  have defined rigidities so that locking ring system  280  performs a ratcheting action as the portion  32  of the tubular housing  30  and the tubular mandrel  20  move relative to each other in a defined direction. Particularly, as the tubular housing  20  moves in a direction indicated by arrow  345  and as the tubular mandrel  20  moves relative according to the direction indicated by arrow  350 , vertical or substantially vertical side  360  of teeth  320  engage vertical or substantially vertical side  370  of teeth  300 . As the portion  32  of the tubular housing  30  continues to move, the sloped portion  380  of teeth  310  slip over the sloped portion  390  of the teeth  330 , causing the locking ring  290  to expand into the gap  340  until the locking ring  290  moves the distance of one of the teeth  330 . When the locking ring  290  moves past a tooth  330 , the teeth  310  fall back into the spaces formed between adjacent teeth  330 , permitting the locking ring  290  to radially contract. On the contrary, when the portion  32  of the tubular housing  30  is moved in a direction opposite arrow  345 , sloped portion  400  of the teeth  320  engage sloped portion  410  of teeth  300  causing the vertical or substantially vertical side  420  of teeth  310  to engage the vertical or substantially vertical side  430  of teeth  330 . The interaction of sides  420  and  430  prevent the locking ring  290  from moving relative to the tubular mandrel  20 . Further, the tubular mandrel  20  is prevented from sliding relative to the locking ring  290  due to the relative rigidities of the tubular mandrel  20 , the tubular housing  30  (e.g., the portion  32 ), and the locking ring  290 . Thus, a wall thickness of the locking ring  290 , the tubular mandrel  20 , and the portion  32  of the tubular housing  30  as well as the geometry of teeth  300 - 330  are sized such that the locking ring  290  elastically deforms without yielding to permit movement of the portion  32  of the tubular housing  30  relative to the tubular mandrel  20  only in a one direction. Consequently, the locking ring system  290  is adapted to permit movement of the portion  32  of the tubular housing  30  relative to the tubular mandrel  20  in one direction, while preventing relative movement in an opposite direction. 
     Additionally, the downhole tool  10  may include pins  440  extending through openings  445  formed in the portion  32  of the tubular housing  30  and into the through-slit formed in the locking ring  290 . The pins  440  prevent rotation of the locking ring  290  relative to the portion  32  of the tubular housing  30  as the portion  32  of the tubular housing  30  and the tubular mandrel  20  move relative to each other, as described above. A rotational tendency may be present when, for example, the teeth pairs  300  and  320  and/or  310  and  330  are formed from one or more continuous helical threads. 
     The downhole tool  10  also includes a second slip  450 . The second slip  450  may be configured similar to the first slip  140  having slits  460  and  470  corresponding to slits  200  and  210 , respectively. The second slip  450  may or may not include shear pins, similar to shear pins  220 , provided on opposing sides of the slit  470 . Similar to the first slip  140 , the second slip  450  also includes an engaging portion  480  that may include a plurality of engaging members or teeth  490 . Teeth  490  may be asymmetrical in shape. Similar to teeth  170 , the teeth  490  may be formed from a series of coaxial annular rings formed on the external surface of the slip  450  or may be one or more continuous helical threads. Also, the teeth  490  are oriented in an opposite direction as the teeth  170  formed on the first slip  140 . Thus, movement of second slip  450  in the direction of arrow  110  causes the teeth  490  to “bite” into the casing of the wellbore. 
     A second wedge ring  500 , similar to the first wedge ring  150 , is disposed adjacent the tubular housing  30  and tubular mandrel  20 . The second slip  450 , second wedge ring  500 , and locking ring system  280  form a second slip assembly  505 . Similar to the first wedge ring  150 , the second wedge ring  500  includes two wedge-shaped protrusions  510  that nest in wedge-shaped recesses  520  formed in the second slip  450 . More or fewer wedge-shaped protrusions  510  and corresponding wedge-shaped recesses  520  may be used. A second end portion  530  of the tubular housing  30  is secured to the tubular mandrel  20 , such as by a threaded connection, welding, or other connection technique. Thus, the second end portion  530  of the tubular housing  30  is prevented from moving relative to the tubular mandrel  20 . 
     The tubular housing  30  and the tubular mandrel  20  are temporarily held fixed relative to each other with one or more shear pins  540  or other device, for example, until movement of the tubular housing  30  and the tubular mandrel  20  relative to each other is desired. When the relative movement is desired, a force greater than the shearing strength of the shear pins  540  is applied, causing the shear pins  540  to break and the tubular housing  30  operable to move relative to the tubular mandrel  20 . 
     In operation, a wireline actuation tool (not shown), coupled to the downhole tool  10 , is actuated. In some implementations, the wireline actuation tool may engage a profile or other geometry of the tubular mandrel  20  and a profile or other geometry of the tubular housing  30  to displace the tubular mandrel  20  and the tubular housing  30  relative to each other. As explained above, the downhole tool  10  has a top-down set configuration such that the wireline actuation tool applies a force to the tubular housing  30  in the direction of arrow  110  and a force to the tubular mandrel  20  in the direction of arrow  120 . This force exceeds the strength of the shear pins  540 , causing them to shear or otherwise break, allowing the tubular housing  30  to move relative to the tubular mandrel  20 . Because the second end portion  530  of the tubular housing  30  is fixed to the tubular mandrel  20 , as the tubular housing  30 B moves down the tubular mandrel  20 , the wedge-shaped protrusions  510  of the second wedge ring  500  force the second slip  450  to expand outwardly and engage the interior surface of the wellbore casing. As the second slip  450  is driven into the wellbore casing, the second wedge ring  500  is prevented from traveling further along the tubular mandrel  20  due to engagement of the wedge-shaped protrusions  520  with the wedge-shaped recesses of the second slip  450 . Further, the teeth of the second slip  450  are oriented so that the teeth  49  “bite” into the interior wall of the wellbore casing. 
     As the second slip  450  begins to expand and movement of the second wedge ring  500  along the tubular mandrel  20  begins to slow, the sealing assembly  250  is squeezed between opposing shoulders  550  and  560 . The expansion members  260  and the resilient sealing element  270  are expanded radially outwards so that resilient sealing element  270  also engages the interior surface of the wellbore casing to form a seal. The first slip  140  also expands radially outwardly as the first slip  140  is pushed outwardly by the wedge-shaped protrusions  230  of the first wedge ring  150 . 
     The slip ring  50  is also driven downwardly by the retaining ring  125  that is attached to the tubular housing  30 . Thus, when the tubular mandrel  20  and tubular housing  30  move relative to each other, the retaining ring  125  contacts and drives the slip ring  50  along the exterior surface of the tubular mandrel  20 . The orientation of the teeth  70  permits the slip ring  50  to travel along the tubular mandrel  20  in the direction of arrow  110  without binding. 
     In the set configuration, relative movement between the tubular housing  30  and the tubular mandrel  20  is resisted by the engagement portion  70 . That is, movement of the tubular housing  30  relative to the tubular mandrel  20  in the direction of arrow  120  causes the teeth  70  to “bite” into and engage the exterior surface of the tubular mandrel  20 . Further, relative movement between the tubular housing  30  and the tubular mandrel  20  is resisted by the first and second slips  140  and  450 . Moreover, a force in the direction of arrow  110  applied through the tubular mandrel  20  is transmitted through rigid elements of the downhole tool  10 , thereby bypassing the resilient sealing element  270 . 
     For the top-down set downhole tool  10  illustrated in  FIGS. 2A-C  and  3 A-C, a force through the tubular mandrel  20  in the direction of arrow  110  (i.e., compressive loading) bypasses the resilient sealing element  270 . The corresponding load path is shown as arrow  550  in  FIG. 3A-C . As shown, the compressive loading passes from the tubular mandrel  20 , through the locking ring system  280 , and into the second slip  450 . When a compressive load applied to the tubular mandrel  20 , the tubular mandrel  20  and the tubular housing  30  are prevented from relative movement because the slip ring  50  lockingly engages the tubular mandrel  20  via the teeth  70 . The compressive load passes through the locking ring system  280  as a result of the locking functionality of the locking ring system  280 , described above. The load is transmitted from the locking ring system  280 , into the second slip ring  450 , and into the wellbore casing. As a result, a pressure increase to the resilient sealing element  270  and the formation of gaps between the first and second slips  140  and  450  and the first wedge ring  150  and the second wedge ring  500 , respectively, or between the first slip assembly  760  or the second slip assembly  770  and adjacent portions of the tubular housing  30  are avoided. Such loading and mandrel movement may occur during load reversals imparted to the working string, such as working string  4  in  FIG. 1 , during wellbore operations. Downhole tool  10  also enjoys the benefit of significantly reduced movement of the tubular mandrel  20  when the resilient sealing element  270  experiences load and/or pressure reversals. Further, the durability of the resilient element  270  is improved due to the reduced stress and movement of the tubular mandrel  20 , which ultimately improves the long term sealability of the resilient sealing element  270 , increases resistance to tubular mandrel collapse, as well as increased resistance to wellbore casing burst. On the other hand, tensile loading, i.e., loading the tubular mandrel  20  in the direction of arrow  120  (shown as load path  560 ) passes from the tubular mandrel  20 , the second end portion  530  of the tubular housing  30 , the second slip  450 , the second wedge  500 , the sealing assembly  250 , the first wedge  150 , and through the first slip  140 . During tensile loading to the tubular mandrel  20 , the tubular mandrel  20  may move relative to the slip ring  50 . In the example shown, the movement would be uphole movement, i.e., towards the terranean surface. Once the movement uphole movement of the tubular mandrel  20  ceases, the slip ring  50  again grips the tubular mandrel  20 , preventing the tubular mandrel  20  from returning to its original position prior to the application of the tensile loading. 
     It is noted that, in wellbore operations, the most significant loading direction to the tubular mandrel  20  after setting the downhole tool  10  is generally known. Thus, the downhole tool  10  used in a particular application can be selected from one of a top-down set or bottom-up set type. An example bottom-up set type downhole tool is described below with respect to  FIGS. 9A-D  and  10 A-C. 
       FIGS. 7A-D  and  8 A-D illustrate a further implementation of the downhole tool  10  that is hydraulically actuated. The downhole tool  10  shown in  FIGS. 7A-D  and  8 A-D is configured to be set from the top-down. This downhole tool  10  also has a tubular mandrel  20  and a tubular housing  30  circumjacent the tubular mandrel  20 . The downhole tool  10  may be provided on a tubular working string for running the downhole tool  10  into position downhole in the wellbore. 
     First and second portions  600 ,  602  of the tubular housing  30  are coupled to the tubular mandrel  20  such as by a treaded connection, welding, or any other coupling technique. The first portion  600  of the tubular housing  30  includes a pressure sensitive valve  610  disposed in a port  620 . In some implementations, the pressure sensitive valve is a rupture disk. The rupture disk may be configured to rupture when the rupture disk experiences a desired pressure difference between an exterior of the downhole tool  10  and a pressure interior of the rupture disk. In some implementations, the pressure differential may be selected to be 1500 to 2000 psi greater than an expected downhole pressure. A piston member  630  of the tubular housing  30  adjacent the first portion  600  is moveable relative to the first portion  600 . As shown, the piston member  630  overlaps an end of the first portion  600 . A first seal  640  is formed between the first portion  600  and piston member  630  by one or more sealing members  650 . According to some implementations the one or more sealing members  650  may be one or more o-ring or other resilient sealing members. A second seal  660  is also formed between an interior surface of the first portion  600  and an exterior surface of the tubular mandrel  20 . The second seal  660  may be formed by one or more sealing members  670 . The sealing members  670  may be similar to or different from the sealing members  650 . A third seal  680  is formed between an interior surface of the piston member  630  and an exterior surface of the tubular mandrel  20 . The seal  680  may be formed from one or more sealing members  690 , which may be similar to or different from the sealing members  650  and/or  670 . An annular channel  672  is formed between the first portion  600  and the tubular mandrel  20  and is in communication with the port  620 . The annular channel  672  extends to an annular gap  674  bounded by the first portion  600 , the piston member  630 , and the tubular mandrel  20 . The annular channel  672  is sealed by the first, second, and third seals  640 ,  660 , and  680 . 
     An annular chamber  700  is formed between the piston member  630  and the tubular mandrel  20 . In some implementations, the annular chamber  700  has a low internal pressure. In some implementations, the annular chamber  700  has zero pressure or substantially zero pressure. The third seal  680  is formed at a first end  710  of the annular chamber  700  and a fourth seal  720  is formed at a second end  730  of the annular chamber  700 . The fourth seal  720  may be formed from one or more sealing members  740 , similar to or different from the sealing members  650 ,  670 , and/or  690 . Thus, the third and fourth seals  680  and  720  are operable to isolate the annular chamber  700 . 
     The downhole tool  10  also includes a sealing assembly  750  flanked on opposite sides by a first slip assembly  760  and a second slip assembly  770 . The sealing assembly  750  and first and second slip assemblies  760  and  770  are provided on the tubular mandrel  20 . The first and second slip assemblies  760 ,  770  are substantially the same as and operate similarly to the first and second slip assemblies  155  and  505  with the exception that, in the shown implementation, the first slip assembly  760  includes a locking ring system  780  rather than the slip ring  50 . However, according to other implementations, a slip ring similar to slip ring  50  may be used in place of the locking ring system  780 . Thus, the first slip assembly  760  includes a first slip  790 , a wedge ring  800 , and the locking ring system  780 . The second slip assembly  770  includes a second slip  810 , a second wedge ring  820 , and a locking ring system  830 . Likewise, the sealing assembly  750  may be similar to the sealing assembly  250 . Thus, the sealing assembly  750  may include a resilient sealing element  840  with expansion members  850 ,  860  on opposing sides thereof, although the expansion members  850 ,  860  may be omitted. 
     The locking ring system  780  corresponds essentially to the locking ring system  280 , illustrated in  FIGS. 2A ,  3 A,  5 , and  6 . Thus, the locking ring system  780  is adapted to allow the first slip assembly  760  to move relative to the tubular mandrel  20  in the direction of arrow  880  but not in the direction of arrow  870 . 
     In operation, the downhole tool  10  is placed into a desired position downhole. A pressure in the wellbore is increased to a pressure that causes the pressure sensitive valve  610  to open. In the implementation shown, the downhole pressure is increased to a pressure designed to rupture the rupture disk. Wellbore pressure is communicated through the pressure sensitive valve  610  into the port  620 , through the annular channel  672  and into the annular gap  674 . The wellbore pressure acts on the surface  675 . Because the pressure within the annular chamber  700  is zero or substantially zero, there is little to no resistance to the piston member  630  moving in the direction of arrow  880  relative to the tubular mandrel  20 ; consequently, the first and second slip assemblies  760  and  770  are moved relative to the tubular mandrel  20 , causing the associated slips to radially expand and engage the wellbore casing. The sealing assembly  750  is also actuated to form an annular seal within the wellbore casing. The locking ring systems  780 ,  830  of the first and second slip assemblies  760  and  770 , respectively, permit movement of the tubular housing  30  along the tubular mandrel  20  in the direction of arrow  880  but not in the direction of arrow  870 . Thus, the locking ring systems  780 ,  830  lock the first and second slip assemblies  760 ,  770  and the sealing assembly  750  into position when the downhole tool  10  is placed in the set configuration.  FIG. 8A-8D  shows the wellbore tool  10  in the set configuration. 
     A compression force applied to the tubular mandrel  20  is directed through the locking ring system  830 , through the second slip  810 , and into the wellbore casing, thereby bypassing the resilient sealing element  840  of the sealing assembly  750 , as illustrated by the load path  890 . Conversely, a tensile force applied through the tubular mandrel  20  passes through the second portion  602  of the tubular housing  30 , the second slip  810 , the second wedge  820 , the sealing assembly  750 , the first wedge  800 , and the first slip  790  into the casing wall, illustrated by load path  900 . 
       FIGS. 9A-D  and  10 A-C show another implementation of the downhole tool  10  that is fluidically actuated. The downhole tool  10  of  FIGS. 9A-D  and  10 A-C is similar to the downhole  10  of  FIGS. 7A-D  and  8 A-D except that the downhole tool  10  of  FIGS. 9A-D  and  10 A-C is set from the bottom-up. As a result, the ratcheting direction of the first and second locking ring systems  780  and  830  is reversed. One or more ports  620  is in communication with the interior  960  of the tubular mandrel  20 . In some instances, a pressure sensitive valve  610  may be disposed in the port  20 . The port  620  is in communication with annular passage  910 , which is defined between the second portion  602  of the tubular housing  30  and an end  920  of the piston member  630 . The annular passage  910  may be isolated from the exterior of the downhole tool  10  and the annular channel  700  by seals  940 ,  950 . The end  920  is sandwiched between the second portion  602  of the tubular housing  30  and the tubular mandrel  20 . The annular chamber  700  is defined between the piston member  630  and the exterior surface of the tubular mandrel  20 . 
     Thus, when fluid pressure is applied to the interior of the tubular mandrel  20 , the pressure sensitive valve  610  opens (if provided) and fluid pressure is communicated to the end  920  of the piston member  630  via the one or more ports  620  and annular passage  910 . The piston member  630  slides relative to the tubular mandrel  20  in the direction of arrow  870  (uphole towards the terranean surface), thereby placing the downhole tool  10  in the set configuration (shown in  FIGS. 10A-D ). A subsequent tensile load to the tubular mandrel  20  after the downhole tool  10  has been placed in the set configuration follows the load path  890  through the first locking ring system  780 , the first wedge  800 , the first slip  790 , and into the wellbore casing, thus avoiding the resilient sealing element  840 . A compressive load applied to the tubular mandrel  20 , on the other hand, passes through the resilient sealing element  840 , as indicated by the load path  900 , and through the second slip  810 . 
     A number of implementations have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure. For example, although not shown, implementations on a wireline or tubing string and set from the bottom-up are also within the scope of the present disclosure. Accordingly, other implementations are within the scope of the following claims.

Summary:
A downhole tool for providing a seal downhole within a wellbore for reducing loading experienced by a sealing member of the downhole tool is disclosed. The downhole tool may include a pair of directional locking members, at least one of which is operable to transfer a loading experienced by the downhole tool through rigid components of the downhole tool, thereby bypassing the sealing member.