Patent Publication Number: US-11661814-B1

Title: Methods and systems for fracing and casing pressuring

Description:
BACKGROUND INFORMATION 
     Field of the Disclosure 
     Examples of the present disclosure relate to a downhole tools. More specifically, embodiments are related to a frac plug with lower slips and a lower cone. In embodiments, a lower cone ramp angle may greater than or equal to a cone bevel angle and a slip inner cut angle. This geometry enables the fins of the cone to not interact with the lower slips, which may not shear the lower slips as the lower slips move over the cone. Instead, the lower slips may break due to stresses caused by the tendency of the lower slips to expand as the lower slips interact with the ramp of the lower cone. 
     Background 
     Conventionally, after cementing a well and to achieve Frac/zonal isolation for a Frac operation, a frac plug and perforations on a wireline are pushed downhole to a desired a depth. Then, a frac plug is set and perforation guns are fired above to create conduit to frac fluid. This enables the fracing fluid to be pumped. Typically, to aid in allowing the assembly of perforation and frac plug to reach the desired depth, specifically in horizontal or deviated laterals, pumping operation can be used. During the pumping operation the wireline is pumped down hole with the aid of flowing fluid. 
     These conventional frac plugs are held in place via slips and packing elements. Conventional slips, cones, and packing elements are loaded on an outer mandrel on the frac plug. Conventional cones may include fins that interface with an upper notch and webbing of a slip, this may provide more uniform slips breaking points creating a consistent gap between each slips after breakage. However, due to the angularity of conventional fins, distal ends of the conventional fins contact a proximal face of the webbing. This may cause the lower slips to shear pre-maturely instead of expanding outwards then shearing. 
     Accordingly, needs exist for systems and methods utilizing a frac plug, wherein a lower cone ramp angle is greater than or equal to a cone bevel angle and a slip inner cut angle. The relative geometry of elements of the lower cone and lower slips enables the fins of the cone to not interact with the lower slips, which may not break the lower slips as the lower slips move over the cone. Instead, the lower slips may break due to stresses caused by the tendency of the lower slips to expand as the lower slips interact with the ramp of the lower cone. 
     SUMMARY 
     Embodiments disclosed herein describe systems and methods for a frac plug. The frac plug may include a lower cone a lower slips. The frac plug may also include other elements that may be sequentially loaded on a mandrel of the frac plug. For example, the frac plug may also include a load ring, upper slips, upper cone, and a packer. 
     The lower slips may be positioned adjacent to the lower cone and the cap. The lower slips may be a device that is used to grip and hold frac plug against the casing internal diameter. The lower slips may be configured to radially expand or break based on the relative movement with the lower cone. The lower slips may include a plurality of wedges that are formed in a near circle around the mandrel. After the lower slips are deployed and radially expanded, pairs of the wedges may be retained together. In embodiments, the lower slips may include an inner surface and webbing. The inner surface may have a first angle, and be configured to interface with a ramp of the lower cone. Responsive to the inner surface of the wedges interfacing with the ramp, the lower slip may radially expand. 
     The webbing may have an inner surface that has a slip inner cut angle that is substantially the same as the first angle of the ramp of the lower cone and a cone bevel angle of a fin. In embodiments, due to the relative geometries of the inner surface of the webbing and the cone bevel angle of the fin, the inner surface of the webbing may not touch, intersect, or contact an outer surface of the fin. By eliminating the contact between the webbing and the fins, a failure point of the lower slip may be removed. Furthermore, the slip inner cut angle may increase the thickness of the webbing at a location that is further away from the distal end of the fin, which may also decrease the likelihood of wedges of the slips breaking apart from each other. 
     The cone may be positioned between the packing element and the lower slips. The cone may be configured to slide towards the cap of the frac plug to radially expand the lower slips. The cone may include a ramp and fins. The ramp may be configured to interface with the inner surface of the wedges to radially expand the lower slips. The ramp may have a lower cone ramp angle that can be any realistic angle for a lower cone, such as between 5 and 30 degrees. In embodiments, the first angle may be substantially the same as the lower cone ramp angle, which may assist in radially expanding the lower slips. 
     The fins may be configured to be positioned within the upper notches of the webbing when run in hole, and under the webbing of the lower slips when the lower slips are activated. The fins may have a cone bevel angle that may be substantially equal to or less than the lower cone ramp angle, wherein the cone bevel angle is equal to that of the slip inner cut angle. However, In other embodiments, the cone bevel angle may be slightly greater than the lower cone ramp angle. For example, the cone bevel angle may be ten degrees larger than the lower cone ramp angle. In embodiments, the outer surface of the fins and the inner surface of the webbing may be offset from each other when run in hole, and both positioned away from an outer diameter of the mandrel. Due the equal angling of the outer surface of the fins and the inner surface of the webbing, the two may not contact each other even after the cone moves towards the cap and the lower slips are activated. This may enable the wedges of the lower slips to not break due to the fins interacting with the webbing. However, the wedges may break due to hoop stresses caused by the wedges expanding as they move over the ramp of the cone. 
     Furthermore, in embodiments, even if the outer surface of the fin was to interact with the lower surface of the webbing, a fin would not initially contact an edge of the webbing. This would merely assist in radially expanding the webbing rather than shearing the webbing. 
     The cap may be positioned on a distal end of the frac plug. The cap includes a passageway, recess, and projection. The passageway may be an opening extending through the inner diameter of the cap from a proximal end to a distal end of the cap, which allows fluid to flow through the inner diameter of the frac plug. The recess may a groove, depression, etc. be positioned on the distal end of the cap, wherein the recess is cylindrical in shape. The projection may extend away from the lip in a direction along the longitudinal axis of the frac plug. The projection may have an inner diameter that is greater than that of the passageway and smaller than an outer diameter of the recess. The projection may be configured to receive a frac ball, object, etc., such that if the frac ball is positioned on the projection there is communication through passageway via the space between the frac ball and the recess. 
     In embodiments, the cap and the lower slips may form an anti-rotation mechanism. The anti-rotation mechanism may be configured to allow relative linear movement between the cap and the lower slips but restrict relative rotational movement between the cap and the groove. The anti-rotation mechanism may include projections positioned on a distal end of the lower slips and grooves positioned on a proximal end of the cap. In alternative embodiments, the projections may be positioned on a proximal end of the cap, and the grooves may be positioned on the distal end of the lower slips. 
     Embodiments may include a flapper with a weak point, wherein the flapper is configured to rotate from a position blocking an inner diameter of the frac plug to a position allowing fluid to flow around the flapper. The flapper may be mounted inside the mandrel of the frac plug. The flapper may include a removable weak point assembly that is configured to form a passageway responsive to removing the removable weak point assembly, wherein the weak point assembly extends from an upper surface of the flapper to a lower surface of the flapper. In embodiments, the flapper may be positioned closer to a proximal end of the frac plug than the load ring. By position the flapper above the elements of the frac plug, the flapper may restrict the flow of fluid through the mandrel, which may limit pre-mature setting of the frac plug. 
     These, and other, aspects of the invention will be better appreciated and understood when considered in conjunction with the following description and the accompanying drawings. The following description, while indicating various embodiments of the invention and numerous specific details thereof, is given by way of illustration and not of limitation. Many substitutions, modifications, additions or rearrangements may be made within the scope of the invention, and the invention includes all such substitutions, modifications, additions or rearrangements. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Non-limiting and non-exhaustive embodiments of the present invention are described with reference to the following figures, wherein like reference numerals refer to like parts throughout the various views unless otherwise specified. 
         FIG.  1    depicts a downhole tool, according to an embodiment. 
         FIG.  2    depicts a perspective view of lower cone and lower slips, according to an embodiment. 
         FIG.  3    depicts a first cross sectional view of downhole tool, according to an embodiment. 
         FIG.  4    depicts a second cross sectional view of downhole tool, according to an embodiment. 
         FIG.  5    depicts a lower cone, according to an embodiment. 
         FIG.  6    depicts lower slips, according to an embodiment. 
         FIG.  7    depicts one embodiment of a weak point assembly, which may be utilized within the downhole tool. 
     
    
    
     Corresponding reference characters indicate corresponding components throughout the several views of the drawings. Skilled artisans will appreciate that elements in the figures are illustrated for simplicity and clarity and have not necessarily been drawn to scale. For example, the dimensions of some of the elements in the figures may be exaggerated relative to other elements to help improve understanding of various embodiments of the present disclosure. Also, common but well-understood elements that are useful or necessary in a commercially feasible embodiment are often not depicted in order to facilitate a less obstructed view of these various embodiments of the present disclosure. 
     DETAILED DESCRIPTION 
     In the following description, numerous specific details are set forth in order to provide a thorough understanding of the present invention. It will be apparent, however, to one having ordinary skill in the art that the specific detail need not be employed to practice the present invention. In other instances, well-known materials or methods have not been described in detail in order to avoid obscuring the present invention. 
       FIG.  1    depicts a downhole tool  100 , according to an embodiment. Downhole tool  100  may be a frac plug, which may be configured to isolate a stage in a cased hole after cementing. Downhole tool  100  may enable perforating and treating each stage optimally and selectively, wherein downhole tool  100  is pumped down to a desired depth, set, the zone above may be perforated. In embodiments, downhole tool  100  may be a frac plug that is formed of any material, or a combination of materials. Downhole tool  100  may include a mandrel  105 , lower cone  110 , upper cone  120 , packing element  130 , lower slips  140 , upper slips  150 , load ring  160 , flapper  172 , and cap  180 . 
     Lower cone  110  may be positioned between packing element  130  and lower slips  140 . Lower cone  110  may be configured to engage with lower slips  140  to radially expand or break the lower slips  140 . In embodiments, lower cone  110  may be coupled to the mandrel  105  via threads  112  or other any other coupling method. Threads  112  may be positioned on an outer circumference of mandrel  105 , and may allow lower cone  110  to be coupled to mandrel  105 . The coupling of lower cone  110  and mandrel  105  may limit the longitudinal movement of lower cone  110  while downhole tool  100  is being run in hole. Specifically, threads  112  may not allow lower cone  110  to move to interface with lower slips  140  prematurely before an operation is used to activate downhole tool  100 . As such, incidental pressure changes from fluid flowing around lower cone  110  while downhole tool  100  is being pumped downhole may not be sufficient to substantially move lower cone  110  to set lower slips  140 . Responsive to performing an operation to set downhole tool  100 , such as operating a setting tool, the forces applied against threads  112  may be sufficient enough to break the coupling point, which may allow lower cone  110  to move downhole and slide under lower slips  140 , which may radially expand lower slips  140 . 
     Upper cone  120  may be positioned between the upper slips  150  and packing element  130 . Upper cone  120  may be configured to engage with upper slips  150 . When upper cone  120  engages with upper slips  150 , upper slips  150  may radially expand. In embodiments, the upper cone may be coupled to the mandrel  105  via threads  112  or any coupling mechanism, such as pins. Threads  112  may allow upper cone  120  to be coupled to mandrel  105 , which may limit the longitudinal movement of upper cone  120  while downhole tool  100  is being run in hole. In other embodiments, the threads  112  can be any coupling point including a pin that couple the upper slips  150  to the cone  120  and mandrel  122 . Specifically, coupling point  122  may not allow upper cone  120  to move to interface with upper slips  150  or packing element  130  prematurely before an operation is used to activate downhole tool  100 . As such, incidental pressure changes from fluid flowing around upper cone  120  while downhole tool  100  is being pumped downhole may not be sufficient to substantially move upper cone  120  to set upper slips  120 . Responsive to performing an operation to set downhole tool  100 , such as operating the setting tool, the forces applied against coupling point  122  may be sufficient enough to break the coupling point, which may allow upper cone  120  to move. Furthermore, upper cone  120  may be configured to allow upper slips  150  to slide over upper cone  120  to radially expand upper slips  150 . 
     Packing element  130  may be an elastomeric packing element that is configured to radially expand and seal across the annulus based on a pressure differential. An elasticity of packing element  130  may be based upon the cross sectional thickness of sealing element, which may be controlled based on the profiles of the inner diameter and outer diameter of packing element  130 . Outer diameter of packing element  130  may have a concave curvature, which increases a thickness of sealing element  150  towards the ends of the longitudinal axis of packing element  130 . By varying the thickness of the packing element  130 , cross-sectional areas of the packing element  130  may be varied. This may change a pressure differential applied to the packing element  130  at different cross sectional areas. Accordingly, as fluid is pumped within the annulus between the outer surface of the packer and casing, the curvature of the outer surface may control or create a Bernoulli Effect and the pressure differential across the Packing element  130  at different locations. As such, packing element  130  may not deploy prematurely. In embodiments, packing element  130  may be positioned between lower cone  110  and upper cone  120 , and may be configured to radially expand responsive to a distance between lower cone  110  and upper cone  120  decreasing, which may occur after threads  112  and  142  are broken. 
     Lower slips  140  and upper slips  150  may be configured to radially move outward and expand across an annulus to secure mandrel  105  to a casing, wherein the annulus is positioned between an outer diameter of mandrel  105  and the casing. Responsive to moving slips  140 ,  150  across the annulus, slips  140 ,  150  may grip the inner diameter of the casing. 
     More specifically, lower slips  140  may be positioned between lower cone  110  and cap  180 . Lower slips  140  may be configured to radially expand or break responsive to lower cone  110  moving below lower slips  140 . Responsive to performing an operation to set downhole tool  100 , such as operating the setting tool, the forces applied against threads  142  may be sufficient enough to break the threads  142 , which may allow lower slips  140  to move. In other embodiments, the lower slips  140  may expand radially lower cone  110  slides under lower slip  140 . 
     Upper slips  150  may be positioned between upper cone  120  and load ring  160 . Upper slips  150  may be configured to radially expand responsive to upper cone  120  moving below upper slips  150 . Responsive to performing an operation to set downhole tool  100 , such as operating the setting tool, the forces applied may allow upper cone  120  to move, and subsequently move upper slips  150 . 
     Load ring  160  may be an upper bound of the elements of positioned on the outer diameter of the mandrel  105 . Load ring  160  may operate as a no-go, stopper, etc. configured to limit the movement, towards a proximal end of the frac plug, of the other elements on the outer mandrel  105 . Load ring may be also used to transfer the force from the setting tool during operation to the other components of the frac plug, allowing frac plug to engage the casing ID and set inside. 
     Cap  180  may be positioned on a distal end  102  of downhole tool  100 . Cap  180  may be positioned adjacent to lower slips  140 , and limit the rotational movement and linear movement of lower slips  140 . Cap may include a passageway that extends through the inner diameter of the cap from a proximal end to a distal end of the cap  180 . The passageway may allow fluid to flow through the inner diameter of the frac plug. 
     Flapper  172  may be configured to allow the flow of fluid in one direction. The one direction may usually from distal end of the well to the proximal end of the well, while restricting the flow of fluid in the opposite direction. Flapper  172  may be made of millable material such as plastic, fiber, brass or dissolvable material. In further embodiments, Flapper  172  may be configured to have an open and closed positioned responsive to flowing fluid from a distal end of tool  100  towards a proximal end of tool  100  while the weak point assembly  170  is intact. In embodiments, flapper  172  may be mounted across an inner diameter of downhole tool  100  or on mandrel  105 . Flapper  172  may include weak point assembly  170 , wherein weak point assembly  170  may be configured to assist in controlling the flow of fluid between a positioned above flapper  172  and a location below flapper  172 . 
     Weak point assembly  170  may include a housing, disc, and shear pin or shear disc, wherein weak point assembly  170  may be any geometric shape. The housing may be configured to be positioned within a passageway in weak point assembly  170 . The housing may be a removable component within weak point assembly  170  or may be an integral component. The housing may have a hollow inner diameter extending from a first face of housing to a second face of housing. In embodiments, fluid may be configured to flow through the hollow inner diameter responsive to a disc being removed from the housing. The housing may be configured to temporarily secure the disc and shear pin. The disc may be an object that is configured to be embedded within the housing when weak point assembly  170  is intact. The disc may be configured to move downhole etc. responsive to a pressure differential applied to a shear pin being greater than a pressure threshold. The shear pin may be a device be inserted into the housing and extend through and across the disc. In embodiments, the shear pin may be exposed to shearing forces via pressure applied on the disc, wherein when the shearing forces are greater than a pressure rating of the shear pin then the shear pin may break. Responsive to the breaking, the disc may move from a positioned within the housing to a position outside of the housing. 
     In embodiments, weak point assembly  170  may be used in a fracturing procedure utilizing fracturing fluid that fractures formation after the well is cemented. In embodiments, a fracturing procedure may be any procedure associated a well after it is cemented and before the well is abandoned, such as a gun misfire, premature setting of the frac plug, formation screen out above the plug, or any other operation that utilize a frac plug that may include or cause increase in the pressure above the weak point value within the frac plug if needed. 
       FIG.  2    depicts a perspective view of lower cone  110  and lower slips  140 , according to an embodiment. Elements depicted in  FIG.  2    may be described above, and for the sake of brevity a further description of these elements may be omitted. 
     As depicted in  FIG.  2   , lower cone  110  may include a ramp surface  210  and fins  212 . Ramp surface  210  may be a sloped outer surface of lower cone  110 , and be positioned a pair of fins  212 . Ramp surface  210  may be sloped towards a central axis of downhole tool  100 . The slope of ramp surface  210  may cause a proximal end of lower cone  110  to be thicker than a distal end of lower cone  110 , wherein the slope of ramp surface  210  may be a lower cone ramp angle being between five and thirty degrees. Ramp surface  210  may have a substantially wider length than fins  212 . 
     Fins  212  may be equally spaced around the perimeter of lower cone  110 . Fins  212  may be configured to slide within and below upper notch  224  without touching the inner surface of webbing  228 . Fins  212  may have a cone bevel angle that is sloped towards the central axis of downhole tool  100 . The slope of the cone bevel angle may cause a proximal end of fin  212  to be thicker than a distal end of fin  212 . In embodiments, the cone bevel angle may be less than or equal to the lower cone ramp angle. In other embodiments, the cone bevel angle may be slightly larger than the lower cone ramp angle, such as ten percent larger. 
     Lower slips  140  may be configured to radially expand based on forces applied by ramp surface  210  interfacing with an inner surface of wedges  220  expand wedges  220 . Wedges  220  may be formed between webbings  228 , wherein webbings  228  are formed along a longitudinal axis of lower slips  140  between an upper notch  224  and lower notch  226 . Responsive to lower slips  140  sliding downward, ramp surface  210  may break lower slips  140  into pairs of wedges  220  due do radial hoop stresses. For example, if you have six wedges  220 , the wedges  220  may break into three pairs of wedges  220 . In embodiments, single wedges  220  may not be partitioned from all other wedges because fins  212  may not interact directly with an inner surface of webbing  228 . This reduces shearing forces being applied to the wedges  220  after a pair of wedges  220  has been disengaged from the other wedges  220   
     In embodiments, webbings  228  may include a slip inner cut angle, which may be less than or equal to the lower cone ramp angle, and the slip inner cut angle may be substantially equal to the cone bevel angle. In other embodiments, the slip inner cut angle may be slightly larger than the lower cone ramp angle, such as ten percent larger. The slope of the slip inner cut angle may cause a proximal end webbing  228  to be thinner than a distal end of webbing  228 . 
     In embodiments, the slip inner cut angle, the cone bevel angle, and lower cone ramp angle may all be non-zero angles that extend in the same direction. 
       FIG.  3    depicts a first cross sectional view  300  of downhole tool  100 , according to an embodiment. More specifically, the cross sectional view is aligned in a plane where ramp surface  210  intersects with an inner surface of wedge  220 . Elements depicted in  FIG.  3    may be described above, and for the sake of brevity a further description of these elements may be omitted. 
     As depicted in  FIG.  3   , the wedge angle of lower slip  140  may be substantially similar to the lower cone ramp angle  310  of ramp surface  210 . This enables ramp surface  210  to slide under wedge  220  to radially expand lower slip  140 . 
       FIG.  4    depicts a second cross sectional view  400  of downhole tool  100 , according to an embodiment. More specifically, the cross sectional view is aligned in a plane where fin  212  intersects with an inner surface of webbing  228 . Elements depicted in  FIG.  4    may be described above, and for the sake of brevity a further description of these elements may be omitted. 
     As depicted in  FIG.  4   , the cone bevel angle  410  of fin  212  may be substantially similar to that of the slip inner cut angle  420  associated with the webbing  228 . In embodiments, an outer surface of fin  212  may be offset from the inner surface of webbing  228 , at a location away from the outer diameter of mandrel  105 . Due the inner cut angle  420  and the cone bevel angle  410  being substantially similar, even as ramp surface  210  interacts with the inner surface of the wedges  220  to radially expand lower slips  140 , fin  212  nor any other element of cone  110  may interact and touch the inner surface of webbing  228 . This may enable the wedges  228  to not break due to the fins  212  interacting with the webbing  228 . However, the wedges  228  may break due to hoop stresses caused by the wedges  228  expanding as they move over the ramp  210  of the cone  110 . 
     Additionally, as depicted in  FIG.  4   , before being deployed a distal end  420  of fin  212  may be positioned under a proximal end  430  of webbing  228 . This may limit the ability of fin  212  to accidently shear an edge of webbing  228 . Further, even if there was inadvertent contact between fin  212  and the inner surface of webbing  228 , the fin  212  would assist in radially expanding webbing  228  rather than shearing webbing  228 . 
     Also, in embodiments, the outer surface  440  of webbing  228  may extend in a radial plane that is perpendicular to the central the downhole tool  100 , and inner cut angle  450  associated with webbing  228  may continually extend until the inner surface of webbing  228  and the outer surface  440  of webbing  228  intersect. Alternatively, the inner cut angle  450  may terminate in a right angle at a plane  410  orthogonal to the central axis of downhole tool  100 , which occurs before the natural intersection of the inner cut angle  450  and the outer surface  450  of webbing  228 . For example, 
       FIG.  5    depicts a lower cone  110 , according to an embodiment. Elements depicts in  FIG.  5    may be described above, and for the sake of brevity a further description of these elements may be omitted. 
     As depicted in  FIG.  5   , ramp surface  210  and an outer surface of fins  212  may have a similar angle. Furthermore, ramp surface  210  and the outer surface of fins  212  may be radially offset from each other, wherein the outer surface of ramp  210  is radially positioned further away from a central axis of lower cone  110  than the outer surface of fins  212 . 
     As further depicted in  FIG.  5   , cone  110  may include a coupling orifice  510 . Coupling orifice  510  may be configured to receive a pin, threads, or any other coupling mechanism. The coupling mechanism may be configured to be inserted through the coupling orifice  510 , which may couple cone  110  with slips  140  and the mandrel. In embodiments, coupling orifice  510  may be positioned on a ramp surface  210  of cone  110 , at a location proximate to a distal end of cone  110 . 
     Fins  212  may also include planer sidewalls  214  that extend in parallel to each other. Fins  212  may extend radially away from ramp surface  210 . Because planer sidewalls  214  extend in parallel to each other a width across an entire body, or parts of the body, of fins  214  may be substantially equal. Additionally, because the tapering of fins and ramp surface  210  is equal, the upper surface of the distal end  218  of planer sidewalls  214  and ramp surface  210  may have a same radial offset from the upper surface of proximal end  219  of planer sidewalls  214  and ramp surface  210 . 
     In embodiments, fins  212  may also include a tapered proximal end  216  that gradually increases the height of fins  212 , wherein tapered proximal ends  216  are positioned between proximal end of  219  of planer sidewalls  214  and a proximal end of cone  110 . Furthermore, planer sidewalls  214  may be positioned between tapered proximal ends  214  and the distal end of cone  110 . 
       FIG.  6    depicts lower slips  140 , according to an embodiment. Elements depicts in  FIG.  6    may be described above, and for the sake of brevity a further description of these elements may be omitted. 
     As depicted in  FIG.  6   , an inner cut angle of the inner surface of webbing  228  may be similar to that of the inner surfaces of wedges  220 . As such, a radial offset between the inner surface of webbing and the inner surfaces of wedges  220  may remain constant, which may enable the outer surface of fins  212  to not directly interact or contact the inner cut angle of webbing  228 . By having fins  212  not contact the inner surfaces of lower slips  140 , the wedges  220  may not shear and may eventually break off into pairs of wedges  220  that are still connected by webbing  228 . To this end, when lower slips  140  have radially expanded and are gripping the inner diameter of casing, pairs of wedges  220  may still be directly connected to each other. 
     As further depicted in  FIG.  6   , slips  140  may include a coupling orifice  610 . Coupling orifice  610  may be configured to receive a pin, threads, or any other coupling mechanism. The coupling mechanism may be configured to be inserted through the coupling orifice  610  and cone, which may couple cone  110  and slips  140  with the mandrel. In embodiments, coupling orifice  610  may be positioned through wedges  220 , at a location proximate to a proximal end of slips  140 . To this end, coupling mechanisms in a same radial plane may be utilized to couple slips  140 , cone  110 , and the mandrel. 
       FIG.  7    depicts one embodiment of a weak point assembly  170 , which may be utilized within the downhole tool. Weak point assembly  170  may be configured to be position on a mandrel  710 , and may include insert  720  and housing  730 . 
     Mandrel  710  may be a shaft, cylindrical, rod, etc. that is configured to form a body of downhole tool  700 . Mandrel  710  may include a profile  712  that reduces an inner diameter of mandrel  710  that limits the movement of insert  720  in a first direction. Profile  712  may be a ledge that is perpendicular to a central axis of downhole tool  100  or may be a tapered sidewall that gradually and incrementally decreases the inner diameter of mandrel  710 . In other embodiments, there may be no need to have profile  712 . 
     Insert  720  may be a tool formed of composite material, or any desired material. Insert  720  may be configured to be mounted on an inner diameter of mandrel  710  of downhole tool  700 . Insert  720  may include ledge  722 , sloped sidewall  724 , distal end  726 , and pin slots  128 . Insert  720  may be threaded, glued or pinned or fixed to mandrel  710  using any other method. In other embodiments, insert  720  may be just part of the body  710  or may be removed completely and may be replaced by a profile on body  710 . 
     Ledge  722  may decrease an inner diameter across insert  720 , which may be configured to act as a stopper, no-go, etc. to restrict the movement of an upper portion of housing  730  in a first direction, wherein the first direction may be downhole. More specifically, ledge  722  may be configured to receive a projection  742  of upper portion  740  of the housing  730 . Responsive to positioning projection  742  of upper portion  740  on ledge  722 , movement of housing  730  in the first direction may be restricted when upper portion  740  and lower portion  750  are coupled together. However, when upper portion  740  and lower portion  750  are decoupled, ledge  722  may not restrict the movement of lower portion  750  in the first direction. 
     Sloped sidewall  724  may be configured to gradually decrease the inner diameter of the insert  720 . Sloped sidewall  724  may be configured to receive lower portion  750  of housing  730  to restrict the movement of lower portion  750  in the first direction responsive to decoupling upper portion  740  and lower portion  750 . In embodiments, an angle of the sloped sidewall may correspond to the tapered sidewall of mandrel  710 . Furthermore, a seal may be formed between an outer diameter of lower portion  750  and an inner diameter of insert  720  when lower portion  750  and upper portion  740  are de-coupled. 
     The distal end  726  of the insert  720  may project away from an inner diameter of the mandrel  710  to create a lower shelf. Distal end  726  may be configured to interface with elements locking outcrops  754  of lower portion  750  to limit the movement of lower portion  750  in a second direction. In certain embodiments, tool  700  may not include an insert  720  and housing  730  may be directly mounted on mandrel  710 , wherein mandrel  710  may have a similar inner profile as that described above. 
     Pin slots  728  may be holes, slots, indentations, etc. positioned through insert that are configured to selectively receive flapper pin  737 . Specifically, pin slots  728  may have a first end that is positioned on the proximal end of insert  720  and extend towards a distal end of insert  720 . Pin slots  728  may extend in a linear path with a larger length than that of flapper pin  737 , which may allow flapper pin  737  to be free floating within pin slots  728 . The proximal end of pin slots  728  may be configured to be contained between the upper portion  740  and lower portion  750  of housing  730  when upper portion  740  and lower portion  750  are coupled together. After flapper pin  737  is disengaged from pin slots  728  it may be unlikely that flapper pin  737  can reengage with pin slots  728  down well. 
     Housing  730  may be formed of brass, composite, aluminum, cast iron or any other material that can dissolve over time due well fluid and temperature. Housing  730  may be configured to be positioned within insert  720  when run in hole, wherein elements of housing  730  may all be coupled together when run in hole. The housing  730  may include a flapper  735 , upper portion  740 , and lower portion  750 . In other embodiments, the flapper  735  and flapper pin  737  may be replaced by disc or any geometrical shape. 
     Flapper  735  may be a rotatable disc formed of brass, composite, aluminum, cast iron or any other material that can dissolve over time due well fluid and temperature. Flapper  735  may be configured to rotate from a position blocking an inner diameter of the tool  700  to a position allowing fluid to flow around flapper  735 . When flapper  735  extends across an annulus within tool, flapper  735  may be configured to be positioned on a flapper seat  158  within the lower portion of housing  730 . When flapper  735  is positioned on flapper seat  158 , whether upper portion  740  and lower portion  750  are coupled or decoupled from each other, a first area on a first side of flapper  735  may be isolated from a second area on a second side of flapper  735 . Accordingly, flapper  735 , lower portion  750 , and insert  720  may extend across an inner diameter of mandrel  710  to form a seal across a plane through mandrel  710  to isolate the first area from the second area. However, if flapper  735  is rotated to not extend across the annulus within tool  700  and/or upper portion  740  is not positioned within insert  720 , then the first area and second area may not be isolated from each other. Flapper  735  may be a free floating component that is mounted inside the housing  730  via a flapper pin  737  and insert  720 . Flapper  735  may be configured to apply forces when pressure or forces are applied to flapper  735  from above against stress points  746  within housing  130  to separate upper portion  740  and lower portion  750  of housing. 
     Flapper pin  737  may be a free floating, which enables flapper  735  to move along a linear axis confined by pin slots  728 . Flapper pin  737  configured to extend across an entirety of the diameter of housing and have ends that are configured to be inserted into pin slots  728 . When flapper pin  737  is inserted into the pin slots  728 , flapper  735  may be couple housing  730  and insert  720 . In embodiments, flapper pin  737  may be an integral portion of flapper  735  or may be removably coupled to flapper  735 , such that flapper pin  737  may slide out of flapper  735 . 
     Upper portion  740  of housing  730  may be configured to be selectively coupled to lower portion  750  of housing  730  based on a pressure applied across housing  730  and a direction of fluid flowing within tool  700 , wherein both upper portion  740  and lower portion  750  are positioned within an inner diameter of mandrel  710  when run in hole. Upper portion  140  may include projection  742  and stress points  746 . In other embodiments, upper portion  740  and lower portion  750  may be two elements connected together via stress points  746  which can be a shear screw. 
     Projection  742  may be positioned on a proximal end of upper portion  740  and project away from a central axis of housing  730  to increase an outer diameter of upper portion  740 . Projection  742  may be configured to slide onto and sit on ledge  722 . Responsive to positioning projection  742  on ledge  722 , movement of upper portion  740  in the first direction may be limited. 
     Stress points  746  may be positioned between upper portion  740  and lower portion  750  of housing  730 . Stress points  746  may be weak points where upper portion  740  becomes disconnected from lower portion  750 , wherein stress points  746  extend in parallel to a central axis of mandrel  710 , wherein stress points  746  are not coupled to mandrel  710 , insert  720  or flapper  735 . In embodiments, stress points  746  may be configured to receive a force from flapper  735  against flapper seat  758  responsive to moving the free floating flapper  735  to be positioned on flapper seat  758 . More specifically, when fluid is flowing through the inner diameter of tool  700 , flapper  735  may receive forces created by the flowing fluid/pressure. This may allow flapper  735  to seat on the lower portion  750  of the housing  730 , and cause flapper  735  to apply a pressure against the stress points  746 . When flapper  735  applies a pressure greater than a stress threshold of stress points  746 , stress points  746  may break causing upper portion  740  and lower portion  750  to become detached and separated. Then, lower portion  750  of housing may move in the first direction towards the distal end of the housing  730  with the flapper  735  and flapper pin  737 . 
     Lower portion  750  of housing  730  may be configured to be selectively coupled to upper portion  740  of housing  730 . Lower portion  750  may include seal  752 , locking outcrops  754 , and tapered sidewall  756 . Seal  752  may be configured to be positioned between an outer diameter of the lower portion  750  and an inner diameter of inset  720 . Seal  752  may not allow communication through a gap between insert  720  and housing  730  when lower portion  750  is still connected to the upper portion  750  of the housing  730 , and when flapper  735  is positioned on flapper seat  758 . Locking outcrops  754  may be positioned on the distal end of lower portion  750  below the distal end  726  of insert  720 . 
     Locking outcrops  754  may increase an outer diameter of the lower portion  750  such that a diameter of locking outcrops  754  is larger than that of distal end  726 . Due to locking outcrops  754  being larger in size than that of the outer diameter of the distal end  726  and internal diameter of the lower end of insert  720 , locking outcrops  754  may restrict the movement of lower portion  750  in a second direction relative to insert  720 , wherein the second direction is an opposite position from the first direction. This may assist in the disengaging the upper portion  740 , flapper  735  and flapper pin  737  from the lower portion  740  when there is a flow back through tool  700 . Further, by restricting lower portion  750  from moving in the second direction using locking outcrops  754  and the first direction using ledge  722 , the lower portion  750  can be milled with the frac plug as an integral piece. Hence facilitating milling operation if needed. 
     Tapered sidewall  756  may be a slanted sidewall that is configured to be positioned on slanted sidewall  724  of insert  720  after lower portion  750  is sheared from upper portion  740 . 
     Flapper seat  758  may be positioned between stress points  746  and locking outcrops  754 . Flapper seat  758  may be configured to reduce the inner diameter across lower portion  750 , such that flapper  735  may be positioned on flapper seat  758 . Responsive to flapper  735  receiving pressure above the flapper  735  in the first direction, flapper  735  may translate these forces to lower portion  730  through flapper seat  758 , which may shear stress points  746 . 
     In embodiments, upper portion  740  and lower portion  750  of housing may be coupled together via stress points  746  within the inner diameter of mandrel  110 . As such, upper portion  740 , lower portion  750 , and stress points  746  may be positioned within a same vertical plane extending through the inner diameter of mandrel  710 . This may enable upper portion  740  and lower portion  750  to be sheared along a plane that extends in parallel to a central axis of the mandrel  710 . In other embodiments, the upper portion  740  and lower portion  730  can be two separate pieces coupled together with stress point  745   
     After the shearing of upper portion  740  from lower portion  730 , flapper  735  may still be encompassed by upper portion  740  and lower portion  730  until fluid is flowed in an opposite direction that used to shear upper portion  740  from lower portion  730 . 
     Reference throughout this specification to “one embodiment”, “an embodiment”, “one example” or “an example” means that a particular feature, structure or characteristic described in connection with the embodiment or example is included in at least one embodiment of the present invention. Thus, appearances of the phrases “in one embodiment”, “in an embodiment”, “one example” or “an example” in various places throughout this specification are not necessarily all referring to the same embodiment or example. Furthermore, the particular features, structures or characteristics may be combined in any suitable combinations and/or sub-combinations in one or more embodiments or examples. In addition, it is appreciated that the figures provided herewith are for explanation purposes to persons ordinarily skilled in the art and that the drawings are not necessarily drawn to scale. 
     Although the present technology has been described in detail for the purpose of illustration based on what is currently considered to be the most practical and preferred implementations, it is to be understood that such detail is solely for that purpose and that the technology is not limited to the disclosed implementations, but, on the contrary, is intended to cover modifications and equivalent arrangements that are within the spirit and scope of the appended claims. For example, it is to be understood that the present technology contemplates that, to the extent possible, one or more features of any implementation can be combined with one or more features of any other implementation.