Patent Publication Number: US-11396787-B2

Title: Downhole tool with ball-in-place setting assembly and asymmetric sleeve

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims priority to U.S. Provisional Patent Application No. 62/804,046, filed on Feb. 11, 2019, the entirety of which is incorporated herein by reference. 
    
    
     BACKGROUND 
     There are various methods by which openings are created in a production liner for injecting fluid into a formation. In a “plug and perf” frac job, the production liner is made up from standard lengths of casing. Initially, the liner does not have any openings through its sidewalls. The liner is installed in the wellbore, either in an open bore using packers or by cementing the liner in place, and the liner walls are then perforated. The perforations are typically created by perforation guns that discharge shaped charges through the liner and, if present, adjacent cement. 
     Before or after the perforations are formed, a plug may be deployed and set into position in the liner. Some plugs include a sleeve that is expanded radially-outward into contact with the inner surface of the liner, such that the sleeve is held in place with the liner. Then, after the perforations are formed, a ball may be dropped into the wellbore so as to engage a valve seat formed in the plug. Once having received the ball, the plug thus directs fluid pumped into the wellbore outwards, through the perforations, and into the formation. 
     SUMMARY 
     A downhole tool system is disclosed. The downhole tool system includes a downhole tool. The downhole tool includes a body having a bore formed axially-therethrough. An inner surface of the body defines an asymmetric shoulder. The downhole tool also includes an upper cone configured to be received within the bore of the body from an upper axial end of the body. The upper cone is configured to move within the body in a first direction from the upper axial end toward the shoulder in response to actuation by a setting assembly, which forces at least a portion of the body radially-outward. 
     In another embodiment, the downhole tool system includes a downhole tool and a setting assembly. The downhole tool includes a body having a bore formed axially-therethrough. An inner surface of the body defines an asymmetric shoulder. The downhole tool also includes an upper cone configured to be received within the bore of the body from an upper axial end of the body. The downhole tool also includes a lower cone configured to be received within the bore of the body from a lower axial end of the body. The setting assembly is configured to move the upper and lower cones toward one another in the body. The setting assembly includes a first impediment configured to be received within a first seat in the upper cone. 
     A method for actuating a downhole tool system is also disclosed. The method includes running the downhole tool system into a wellbore. The downhole tool system includes a setting assembly and a downhole tool. The downhole tool includes a body having a bore formed axially-therethrough. An inner surface of the body defines an asymmetric shoulder. The downhole tool also includes an upper cone configured to be received within the bore of the body from an upper axial end of the body. The downhole tool also includes a lower cone configured to be received within the bore of the body from a lower axial end of the body. The method also includes exerting opposing axial forces on the upper cone and the lower cone with the setting assembly, which causes the upper cone and the lower cone to move toward the shoulder, thereby causing the body to expand radially-outward. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The present disclosure may best be understood by referring to the following description and accompanying drawings that are used to illustrate embodiments of the invention. In the drawings: 
         FIG. 1  illustrates a side, cross-sectional view of an asymmetric downhole tool system, including a downhole tool and a setting assembly, in a run-in configuration, according to an embodiment. 
         FIG. 2A  illustrates a side, cross-sectional view of the downhole tool in a first set configuration, according to an embodiment. 
         FIG. 2B  illustrates a side-cross sectional view of the downhole tool in a second set configuration, according to an embodiment. 
         FIG. 2C  illustrates a side, cross-sectional view of a body of the downhole tool in the first set configuration and cones of the downhole tool in the second set configuration, according to an embodiment. 
         FIG. 3  illustrates a flowchart of a method for actuating the downhole tool system, according to an embodiment. 
         FIG. 4  illustrates a quarter-sectional, perspective view of another asymmetric downhole tool system, including a downhole tool and a ball-in-place setting assembly, in a run-in configuration, according to an embodiment. 
         FIG. 5  illustrates a side, cross-sectional view of the downhole tool system of  FIG. 4  in the run-in configuration, according to an embodiment. 
         FIG. 6  illustrates a flowchart of a method for actuating the downhole tool system of  FIG. 4 , according to an embodiment. 
         FIG. 7  illustrates a side, cross-sectional view of the downhole tool system of  FIG. 4 , in a first set configuration, according to an embodiment. 
         FIG. 8  illustrates a side, cross-sectional view of a portion of the downhole tool of  FIG. 4  in a second set configuration, after the setting assembly has been disconnected and removed, according to an embodiment. 
     
    
    
     DETAILED DESCRIPTION 
     The following disclosure describes several embodiments for implementing different features, structures, or functions of the invention. Embodiments of components, arrangements, and configurations are described below to simplify the present disclosure; however, these embodiments are provided merely as examples and are not intended to limit the scope of the invention. Additionally, the present disclosure may repeat reference characters (e.g., numerals) and/or letters in the various embodiments and across the Figures provided herein. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed in the Figures. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact. Finally, the embodiments presented below may be combined in any combination of ways, e.g., any element from one exemplary embodiment may be used in any other exemplary embodiment, without departing from the scope of the disclosure. 
     Additionally, certain terms are used throughout the following description and claims to refer to particular components. As one skilled in the art will appreciate, various entities may refer to the same component by different names, and as such, the naming convention for the elements described herein is not intended to limit the scope of the invention, unless otherwise specifically defined herein. Further, the naming convention used herein is not intended to distinguish between components that differ in name but not function. Additionally, in the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to.” All numerical values in this disclosure may be exact or approximate values unless otherwise specifically stated. Accordingly, various embodiments of the disclosure may deviate from the numbers, values, and ranges disclosed herein without departing from the intended scope. In addition, unless otherwise provided herein, “or” statements are intended to be non-exclusive; for example, the statement “A or B” should be considered to mean “A, B, or both A and B.” 
       FIG. 1  illustrates a side, cross-sectional view of a downhole tool system  100  having a downhole tool  110  and a setting assembly  180 , according to an embodiment. The downhole tool  110  may be or include a plug (e.g., a frac plug). As shown, the downhole tool  110  may include an annular body  120  with a bore formed axially therethrough. The body  120  may have an inner surface  122  and an outer surface  124 . The body  120  may also have a first (e.g., upper) axial end  126  and a second (e.g., lower) axial end  128 . As described in greater detail below, the inner surface  122  may define an asymmetric shoulder  130 . The setting assembly  180  may include an inner rod  182  and an outer sleeve  184 . 
     Referring now to  FIG. 2A , the inner surface  122  of the body  120  may define a first, upper, tapered portion  140 . The first, upper, tapered portion  140  may extend from the upper axial end  126  of the body  120  toward the shoulder  130 . Thus, as shown, an inner diameter  132  of the body  120  may decrease in the first, upper, tapered portion  140  in a direction  134  proceeding from the upper axial end  126  toward the shoulder  130 . As a result, a radial thickness (e.g., between the inner surface  122  and the outer diameter surface  124  of the body  120 ) may increase in the first, upper, tapered portion  140  proceeding in the direction  134 . The first, upper, tapered portion  140  may be oriented at an angle from about 1 degree to about 10 degrees, about 1 degree to about 7 degrees, or about 1 degree to about 5 degrees with respect to a central longitudinal axis  101  through the body  120 . For example, the first, upper, tapered portion  140  may be oriented at an angle of about 3 degrees with respect to the central longitudinal axis  101 . 
     The inner surface  122  may also define a second, upper, tapered portion  142 . In at least one embodiment, the second, upper, tapered portion  142  may at least partially define an axial face of the shoulder  130 . The second, upper, tapered portion  142  may extend from the first, upper, tapered portion  140  toward the shoulder  130  (or the lower axial end  128  of the body  120 ). Thus, as shown, the inner diameter  132  of the body  120  may decrease in the second, upper, tapered portion  142  proceeding in the direction  134 . As a result, the radial thickness may increase in the second, upper, tapered portion  142  proceeding in the direction  134 . The second, upper, tapered portion  142  may be oriented at a different (e.g., larger) angle than the first, upper, tapered portion  140 . For example, the second, upper, tapered portion  142  may be oriented at an angle from about 3 degrees to about 20 degrees, about 5 degrees to about 15 degrees, or about 8 degrees to about 12 degrees with respect to the central longitudinal axis  101  through the body  120 . For example, the second, upper, tapered portion  142  may be oriented at an angle of about 10 degrees with respect to the central longitudinal axis  101 . 
     The inner surface  122  may also define a third, upper, tapered portion  144 . In at least one embodiment, the third, upper, tapered portion  144  may also and/or instead at least partially define the axial face of the shoulder  130 . For example, the third, upper, tapered portion  144  may serve as a stop surface of the shoulder  130 . The third, upper, tapered portion  144  may extend from the second, upper, tapered portion  142  toward the shoulder  130  (or the lower axial end  128  of the body  120 ). Thus, as shown, the inner diameter  132  of the body  120  may decrease in the third, upper, tapered portion  144  proceeding in the direction  134 . As a result, the radial thickness may increase in the third, upper, tapered portion  144  proceeding in the direction. The third, upper, tapered portion  144  may be oriented at a different (e.g., larger) angle than the first, upper, tapered portion  140  and/or the second, upper, tapered portion  142 . For example, the third, upper, tapered portion  144  may be oriented at an angle from about 15 degrees to about 75 degrees, about 20 degrees to about 60 degrees, or about 25 degrees to about 40 degrees with respect to the central longitudinal axis  101  through the body  120 . For example, the third, upper, tapered portion  144  may be oriented at an angle of about 45 degrees with respect to the central longitudinal axis  101 . 
     The inner surface  122  may also define a fourth, lower, tapered portion  146 . The fourth, lower, tapered portion  146  may extend from the lower axial end  128  of the body  120  toward the shoulder  130 . Thus, as shown, an inner diameter  132  of the body  120  may decrease in the fourth, lower, tapered portion  146  proceeding in a direction  136  (e.g., opposite to the direction  134 ). As a result, the radial thickness may increase in the fourth, lower, tapered portion  146  proceeding in the direction  136 . The fourth, lower, tapered portion  146  may be oriented at an angle from about 1 degree to about 10 degrees, about 1 degree to about 7 degrees, or about 1 degree to about 5 degrees with respect to the central longitudinal axis  101  through the body  120 . For example, the fourth, lower, tapered portion  146  may be oriented at an angle of about 3 degrees with respect to the central longitudinal axis  101 . 
     The inner surface  122  may define also a fifth, lower, tapered portion  148 . In at least one embodiment, the fifth, lower, tapered portion  148  may at least partially define an opposing axial face of the shoulder  130  (from the second, upper, tapered portion  142  and/or the third, upper, tapered portion  144 ). The fifth, lower, tapered portion  148  may extend from the fourth, lower, tapered portion  146  toward the shoulder  130  (and/or the upper axial end  126  of the body  120 ). Thus, as shown, the inner diameter  132  of the body  120  may decrease in the fifth, lower, tapered portion  148  proceeding in the direction  136 . As a result, the radial thickness may increase in the fifth, lower, tapered portion  148  proceeding in the direction  136 . The fifth, lower, tapered portion  148  may be oriented at a different (e.g., larger) angle than the fourth, lower, tapered portion  146 . For example, the fifth, lower, tapered portion  148  may be orientated at an angle from about 15 degrees to about 75 degrees, about 20 degrees to about 60 degrees, or about 25 degrees to about 40 degrees with respect to the central longitudinal axis  101  through the body  120 . For example, the fifth, lower, tapered portion  148  may be oriented at an angle of about 45 degrees with respect to the central longitudinal axis  101 . 
     A flat surface  131  may also at least partially define the shoulder  130 . The flat surface  131  may extend between the third, upper, tapered portion  144  and the fifth, lower, tapered portion  148 . The flat surface  131  may be substantially parallel with the central longitudinal axis  101 . In some embodiments, the flat surface  131  may be oriented at an angle to the central longitudinal axis  101 , may be substituted with a curved surface, or may be omitted, e.g., such that the third, upper, tapered portion  144  meets with the fifth, lower, tapered surface  148  at an edge (e.g., a point, in cross-section). 
     Thus, as may be seen, the shoulder  130 , which may be at least partially defined by the second, upper, tapered portion  142 , the third, upper, tapered portion  144 , the fifth, lower, tapered portion  148 , or a combination thereof, may be asymmetric. The shoulder  130  may be asymmetric with respect to a plane  138  that extends through the shoulder  130  and is perpendicular to the central longitudinal axis  101 . Further, the body  120  may be asymmetric, at least because the shoulder  130  (e.g., the radially-innermost extent thereof) may be closer to the lower axial end  128  than the upper axial end  126 . 
     The downhole tool  100  may further include upper and lower cones  150 ,  152 . The upper cone  150  may be received into the upper axial end  126  of the body  120 , and the lower cone  152  may be received in the lower axial end  128  of the body  120 . The upper and lower cones  150 ,  152  may each have a bore formed axially-therethrough, through which the rod  182  (see  FIG. 1 ) may extend. As described below, the upper and lower cones  150 ,  152  may be adducted together to force the body  120  radially-outward and into engagement with a surrounding tubular (e.g., a liner or casing). The upper end of the upper cone  150  may define a valve seat  151 , which may be configured to catch and at least partially form a seal with a ball or another obstructing impediment. 
       FIG. 3  illustrates a flowchart of a method  300  for actuating the downhole tool system  100 , according to an embodiment. The method  300  may include running the downhole tool system  100  into a wellbore, as at  302 . 
     The method  300  may also include exerting opposing axial forces on the downhole tool  110  with the setting assembly  180 , as at  304 . More particularly, the outer sleeve  184  may exert a downward (e.g., pushing) force on the upper cone  150 , and the rod  182  may exert an upward (e.g., pulling) force on the lower cone  152 . This may cause the cones  150 ,  152  to move axially-toward each other within the body  120 . In other words, an axial distance between the cones  150 ,  152  may decrease. 
     The force exerted by the outer sleeve  184  may cause the upper cone  150  to move within the first, upper, tapered portion  140  and/or the second, upper, tapered portion  142  of the body  120 , which may force an upper portion of the body  120  to radially-outward (e.g., deforming or otherwise expanding the upper portion of the body  120 ). Similarly, the force exerted by the rod  182  may cause the lower cone  152  to move within the fourth, lower, tapered portion  146  and/or the fifth, lower, tapered portion  148  of the body  120 , which may force (e.g., deform or otherwise expand) a lower portion the body  120  radially-outward In at least one embodiment, some portions of the body  120  may be forced outwards more or less than others. For example, the portions of the body  120  that are axially-aligned with the cones  150 ,  152  may be forced radially-outward farther than the portions of the body  120  that are not axially-aligned with the cones  150 ,  152 . For example, an intermediate (e.g., middle) portion of the body  120  may be forced to move radially-outward less than the portions on either side thereof that are axially-aligned with the cones  150 ,  152 . 
     When the force(s) exerted by the rod  182  and/or the outer sleeve  184  reach or exceed a predetermined setting force, the setting assembly  180  may disengage from the downhole tool  110  and be pulled back to the surface. In one embodiment, this may include the rod  182  disengaging from the lower cone  152 . As shown, the lower cone  152  may have teeth  153  that engage corresponding teeth  183  of the rod  182 , and the teeth  153  and/or  183  may break or yield, allowing the rod  182  to separate from and be pulled upward through the body  120  and the cones  150 ,  152 . For example, the teeth  153  of the lower cone  152  may be made of a softer material (e.g., magnesium) than the teeth  183  of the rod  182 , allowing the teeth  153  to break or yield before the teeth  183 . In another example, a portion of another component that couples the setting assembly  180  (e.g., the rod  182 ) to the downhole tool  110  (e.g., the lower cone  152 ) may break or yield, allowing the rod  182  to separate from and be pulled upward through the body  120  and the cones  150 ,  152 . The predetermined setting force may be selected such that the upper cone  150  is left positioned within the first, upper, tapered portion  140  or the second, upper, tapered portion  142  (but not in the third, upper, tapered portion  144 ), and the lower cone  152  is left positioned within the fourth, lower, tapered portion  146  (but not the fifth, lower, tapered portion  148 ). 
     The method  300  may also include introducing an impediment (e.g., a ball)  190  into the upper cone  150 , as at  306 . This is shown in  FIG. 2B . The ball  190  may be introduced from the surface and be pumped down through the wellbore (e.g., by a pump at the surface). Alternatively, the ball  190  may be run into the wellbore together with the downhole tool system  100 . For example, the ball  190  may be coupled to or positioned within the downhole tool system  100  when the downhole tool system  100  is run into the wellbore. The ball  190  may be received into the seat  151  of the upper cone  150 . 
     The method  300  may also include increasing a pressure of a fluid in the wellbore, as at  308 . The pressure may be increased between the surface and the ball  190  by the pump at the surface. Increasing the pressure may exert a downhole force on the upper cone  150  and the ball  190  (e.g., toward the shoulder  130 ). The force from the pressure/ball  190  may be greater than the force previously exerted by the outer sleeve  184 , and may thus cause the upper cone  150  to move farther toward the shoulder  130 . For example, the force from the pressure/ball  190  may cause the upper cone  150  to move from the first, upper, tapered portion  140  at least partially into (or into contact with) the second, upper, tapered portion  142 , which, by virtue of having a larger taper angle than the first, upper, tapered portion  140 , requires a larger force for the upper cone  150  to move therein. As the upper cone  150  is moved farther into the body  120  under force of the pressure/ball  190 , more of the body  120  may be forced radially-outward as the upper cone  150  moves into the second, upper, tapered portion  142 . In some embodiments, the upper cone  150  may not travel all the way to the third, upper, tapered portion  144 ; however, in other embodiments, the upper cone  150  may be pressed into engagement with the third, upper, tapered portion  144 . The third, upper, tapered portion  144  may thus act as a stop that prevents further axial movement of the upper cone  150 . 
     Before, during, or after reaching the second and/or third, upper, tapered, portion  142 ,  144 , the downhole tool  110  is set in the wellbore against the surrounding tubular, and the ball  190  is in the seat  151 , which prevents fluid from flowing (e.g., downward) through the downhole tool  110  and ball  190 . The subterranean formation may then be fractured above the downhole tool  110 . 
       FIG. 2C  illustrates a side, cross-sectional view of the downhole tool  110  with the body  120  in the first set configuration (from  FIG. 2A ) and the cones  150 ,  152  in the second set configuration (from  FIG. 2B ), according to an embodiment. Thus, the cones  150 ,  152  are shown overlapping/superimposing the body  120 . As will be appreciated, this is a configuration that cannot actually happen, but  FIG. 2C  is provided to illustrate how the movement of the cones  150 ,  152  will force the body  120  radially-outward. 
       FIG. 4  illustrates a quarter-sectional, perspective view of another downhole tool system  400  in a first (e.g., run-in) configuration, according to an embodiment.  FIG. 5  illustrates a side, cross-sectional view of the downhole tool system  400  in the run-in configuration, according to an embodiment. The downhole tool system  400  may include a downhole tool  410  and a setting assembly  480 . The downhole tool  410  may be or include a plug (e.g., a frac plug). As shown, the downhole tool  410  may include an annular body  420  with a bore formed axially-therethrough. In at least one embodiment, the body  420  may be similar to (or the same as) the body  120  discussed above. For example, the body  420  may include an asymmetric shoulder  430 . The body  420  may also include one or more of the tapered portions  140 ,  142 ,  144 ,  146 ,  148  from  FIGS. 1-3 , although they are not labeled in  FIGS. 4 and 5 . 
     The downhole tool  410  may further include upper and lower cones  450 ,  452 . The upper cone  450  may be received into an upper axial end  426  of the body  420 , and the lower cone  452  may be received in a lower axial end  428  of the body  420 . The upper and lower cones  450 ,  452  may each have one or more bores formed axially-therethrough. As shown, the upper and lower cones  450 ,  452  may each include two bores  456 A,  456 B,  458 A,  458 B formed axially-therethrough, which may be circumferentially-offset from one another around the central longitudinal axis  401  (e.g., by 180 degrees). As described below, the upper and lower cones  450 ,  452  may be adducted together to force the body  420  radially-outward and into engagement with a surrounding tubular (e.g., liner or casing). The upper end of the upper cone  450  may define one or more seats (two are shown:  451 A,  451 B). The seats  451 A,  451 B may define at least a portion of the bores formed through the upper cone  450 . 
     The setting assembly  480  may include two or more inner rods (two are shown:  482 A,  482 B) and an outer sleeve  484 . The first rod  482 A may extend through the first bore  456 A in the upper cone  450  and the first bore  458 A in the lower cone  452 , and the second rod  482 B may extend through the second bore  456 B in the upper cone  450  and the second bore  458 B in the lower cone  452 . The rods  482 A,  482 B may be coupled to (or otherwise held in place with respect to) the downhole tool  410  using any of the configurations described above with respect to  FIGS. 1-3 . As shown, the rods  482 A,  482 B may be coupled to (or otherwise held in place with respect to) the lower cone  452  by shear members (nuts or caps)  453 . The shear members  453  may be positioned at least partially between the rods  482 A,  482 B and the lower cone  452  and be configured to shear or break to release the setting assembly  480  (e.g., the rods  482 A,  482 B) from the downhole tool  410  (e.g., the lower cone  452 ) when exposed to a predetermined setting force. 
     One or more impediments (two are shown:  490 A,  490 B) may be positioned at least partially within the downhole tool system  400  when the downhole tool system  400  is run into a wellbore. More particularly, the impediments  490 A,  490 B may be positioned at least partially within the outer sleeve  484  of the setting assembly  480  when the downhole tool system  400  is run into the wellbore. As shown, the impediments  490 A,  490 B may be circumferentially-offset from one another (e.g., by 180 degrees) and/or circumferentially between the rods  482 A,  482 B around the central longitudinal axis  401 . Further, the impediments  490 A,  490 B may be positioned above the upper cone  450 . 
     In an embodiment, the impediments  490 A,  490 B may be spherical balls. The balls  490 A,  490 B may be sized and shaped to fit within the seats  451 A,  451 B in the upper cone  450 . The upper cone  450  may include a central divider  454 , which may have a pointed or otherwise narrowed or radiused upper end, so as to direct the balls  490 A,  490 B into the seats  451 A,  451 B. Although two seats  451 A,  451 B and two balls  490 A,  490 B are shown, in other embodiments, additional balls may be provided within the downhole tool system  400  to provide a redundancy in the event that the balls  490 A,  490 B do not properly move into the seats  451 A,  451 B. 
       FIG. 6  illustrates a flowchart of a method  600  for actuating the downhole tool system  400 , according to an embodiment. The method  600  may include running the downhole tool system  400  into a wellbore, as at  602 . 
     The method  600  may also include exerting opposing axial forces on the downhole tool  410  with the setting assembly  480 , as at  604 . More particularly, the outer sleeve  484  may exert a downward (e.g., pushing) force on the upper cone  450 , and the rods  482 A,  482 B may exert an upward (e.g., pulling) force on the lower cone  452 . This may cause the cones  450 ,  452  to move axially-toward each other within the body  420 . In other words, an axial distance between the cones  450 ,  452  may decrease. 
     The force exerted by the outer sleeve  484  may cause the upper cone  450  to move within the body  420 , as described above with respect to  FIGS. 1-3 , which may force the body  420  radially-outward. Thus, the upper cone  450  may be positioned in the first, upper, tapered portion and/or the second, upper, tapered portion when the predetermined setting force is reached, as described above. Similarly, the force exerted by the rods  482 A,  482 B may cause the lower cone  452  to move within the body  420 , as described above with respect to  FIGS. 1-3 , which may force (e.g., deform or otherwise expand) the body  420  radially-outward. This is shown in  FIG. 7 . 
     When the force(s) exerted by the rods  482 A,  482 B and/or the outer sleeve  484  reach or exceed the predetermined setting force, the setting assembly  480  may disengage from the downhole tool  410  and be pulled back to the surface. In the example shown, in response to the predetermined setting force being reached or exceeded, the shear member(s)  453  may shear or break, allowing the rods  482 A,  482 B to separate from and be pulled upward through the body  420  and the cones  450 ,  452 . 
     Once the rods  482 A,  482 B are removed from the bores in the upper cone  450 , the balls  490 A,  490 B may be free to move into the seats  451 A,  451 B. This is shown in  FIG. 8 . The balls  490 A,  490 B may move into the seats  451 A,  451 B substantially simultaneously (e.g., within 5 seconds or less from one another) and/or be positioned within the seats  451 A,  451 B substantially simultaneously. When the downhole tool system  400  is in a substantially vertical portion of the wellbore, the balls  490 A,  490 B may descend into the seats  451 A,  451 A due to gravity. In another example, when the downhole tool system  400  is in a substantially horizontal portion of the wellbore, the pump at the surface may cause fluid to flow (e.g., downward) through the wellbore, which may carry the balls  490 A,  490 B into the seats  451 A,  451 B. Because the balls  490 A,  490 B are run into the wellbore with the downhole tool system  400 , and thus only need to move a short distance to reach the seats  451 A,  451 B, only a minimal amount of fluid needs to be pumped to carry the balls  490 A,  490 B to the seats  451 A,  451 B. The short distance may be from about 1 cm to about 100 cm, about 5 cm to about 75 cm, or about 10 cm to about 50 cm. As will be appreciated, the aforementioned minimal amount of fluid is significantly less than the amount of fluid needed to pump a ball down from the surface, as is done for conventional tools. The amount of time that the pump is run is thus also significantly less. 
     The method  600  may also include increasing a pressure of a fluid in the wellbore, as at  606 . The pressure may be increased between the surface and the balls  490 A,  490 B by the pump at the surface. For example, the pump may start running to move the balls  490 A,  490 B into the seats  451 A,  451 B, and then continue running to increase the pressure. Increasing the pressure may exert a (e.g., downward) force on the upper cone  450  (e.g., toward the shoulder  430 ). The force from the pressure/balls  490 A,  490 B may be greater than the force previously exerted by the outer sleeve  484 , and may thus cause the upper cone  450  to move farther toward the shoulder  430 , as described above with respect to  FIGS. 1-3 . As will be appreciated, the body  420  may be forced even farther radially-outward when the upper cone  450  moves farther toward the shoulder  430 . 
     At this point, the downhole tool  410  is set in the wellbore against the surrounding tubular, and the balls  490 A,  490 B are in the seats  451 A,  451 B, which prevents fluid from flowing (e.g., downward) through the downhole tool  410 . The subterranean formation may then be fractured above the downhole tool  410 . Any of the components of the downhole tool systems  100 ,  400  (e.g., cones, bodies, obstruction members, etc.) may be made from a dissolvable material such as magnesium. 
     As used herein, the terms “inner” and “outer”; “up” and “down”; “upper” and “lower”; “upward” and “downward”; “above” and “below”; “inward” and “outward”; “uphole” and “downhole”; and other like terms as used herein refer to relative positions to one another and are not intended to denote a particular direction or spatial orientation. The terms “couple,” “coupled,” “connect,” “connection,” “connected,” “in connection with,” and “connecting” refer to “in direct connection with” or “in connection with via one or more intermediate elements or members.” 
     The foregoing has outlined features of several embodiments so that those skilled in the art may better understand the present disclosure. Those skilled in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions, and alterations herein without departing from the spirit and scope of the present disclosure.