Patent Publication Number: US-9835010-B2

Title: Toe valve

Description:
BACKGROUND 
     A toe valve may be positioned at the bottom of a cemented casing completion in a horizontal or deviated wellbore. The toe valve may include a sliding sleeve that moves from a first, closed position to a second, open position. When the sliding sleeve is in the open position, a path of fluid communication is established from a bore in the toe valve to the exterior of the toe valve for circulation. This may occur prior to treatment operations in the wellbore. 
     Once the toe valve is in the desired location in the wellbore, the integrity of the casing may be tested. This may be accomplished by increasing the pressure of the fluid in the wellbore to a first level (e.g., higher than the pressure required to hydraulically fracture the surrounding formation). Subsequent to the integrity of the casing being confirmed, the sliding sleeve may be moved from the closed position to the open position. This may be accomplished by increasing the pressure of the fluid in the wellbore to a second level. The second level is higher than the first level to avoid the sliding sleeve inadvertently moving to the open position during testing. However, because the pressure needed to open the toe valve exceeds the pressure at which the casing integrity is tested, opening the toe valve may risk damaging the casing. 
     SUMMARY 
     A downhole tool is disclosed. The downhole tool includes a body having one or more openings. A main sleeve is disposed in the body. The main sleeve is configured to move between a first position in which the main sleeve blocks fluid flow through the one or more openings and a second position in which the main sleeve allows fluid flow through the one or more openings. An actuator is disposed in the body. The actuator is configured to actuate from a first state to a second state in response to application of a first level of pressure, and to a third state in response to application of a second level of pressure. Actuating the actuator to the third state causes the main sleeve to move from the first position to the second position, and the second level of pressure is less than or equal to the first level or pressure. 
     In another embodiment, the downhole tool includes a body having an axial bore, a first radial opening, and a second radial opening. A first drive sleeve is positioned in the body. A second drive sleeve is positioned in the body and at least partially axially-offset from the first drive sleeve. The second drive sleeve prevents fluid flow through the second radial opening when the second drive sleeve is in a first position. The first drive sleeve moves the second drive sleeve from the first position to a second position in response to a first level pressure applied thereto through the first radial opening. The second drive sleeve prevents fluid flow through the second radial opening when the second drive sleeve is in the second position. The first drive sleeve moves the second drive sleeve from the second position to a third position in response to a second level of pressure being applied thereto through the first radial opening. The second level of pressure is less than or equal to the first level of pressure. 
     A method for operating a downhole tool is also disclosed. The method includes running the downhole tool into a wellbore. A pressure of a fluid in the wellbore is increased to a first level to perform a wellbore operation. The pressure of the fluid decreases after the pressure reaches the first level. The pressure of the fluid increases to a second level that is less than or equal to the first level to actuate the downhole tool and to allow fluid flow through the downhole tool. 
    
    
     
       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 cross-sectional side view of a downhole tool in a first, run-in position, according to an embodiment. 
         FIG. 2  illustrates an enlarged cross-sectional side view of a portion of the downhole tool shown in  FIG. 1  including a first ring, according to an embodiment. 
         FIG. 3  illustrates an enlarged cross-sectional side view of a portion of the downhole tool shown in  FIG. 1  including a second ring, according to an embodiment. 
         FIG. 4  illustrates a flowchart of a method for actuating the downhole tool, according to an embodiment. 
         FIG. 5  illustrates a cross-sectional side view of the downhole tool in a second position after a rupture disk ruptures and a pressure of a fluid in the bore increases, according to an embodiment. 
         FIG. 6  illustrates a cross-sectional side view of the downhole tool in a third position after the pressure of the fluid in the bore decreases, according to an embodiment. 
         FIG. 7  illustrates a cross-sectional side view of the downhole tool in a fourth position after the pressure of the fluid in the bore is increased again to create a path of fluid communication between the bore and an exterior of the downhole tool, according to an embodiment. 
         FIG. 8  illustrates a graph of pressure vs. time during the actuation of the downhole tool, 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.” 
     In general, the present disclosure provides a downhole tool, such as a toe valve, that includes a plurality of sleeves and at least one ring (e.g., a ratchet ring). The at least one ring may be configured to move in one axial direction within the downhole tool but not the opposing axial direction. Together, the sleeves and the at least one ring may cooperate to allow the downhole tool to actuate from a first position when the downhole tool is run into the wellbore to a second position when the wellbore is being pressure tested. The downhole tool may then actuate into a third position as the pressure in the wellbore decreases after the pressure testing. The downhole tool may then actuate into a fourth position when the pressure is increased again, and a path of fluid communication from a bore in the downhole tool to an exterior of the downhole tool may exist in the fourth position. The downhole tool may actuate from the third position to the fourth position in response to a pressure that is less than or equal to the pressure that causes the downhole tool to actuate from the first position to the second position. 
     Turning to the specific, illustrated embodiments,  FIG. 1  illustrates a cross-sectional side view of a downhole tool  100  in a first, run-in position, according to an embodiment. The downhole tool  100  may be any tool that is designed to be run into a wellbore and circulate a fluid in the wellbore. As shown, the downhole tool  100  may be a toe valve. The downhole tool  100  may include a body  110  having a bore  112  formed at least partially therethrough. The body  110  may be one component, or the body  110  may be two or more components coupled together. As shown, the body  110  includes a first or “upper” sub  114  and a second or “lower” sub  124 . The upper and lower subs  114 ,  124  may be spaced axially-apart from one another. The body  110  may also include a housing  128  coupled to and positioned at least partially between the upper and lower subs  114 ,  124 . 
     A seal  132 A may be positioned radially-between the upper sub  114  and the housing  128 . Another seal  132 B may be positioned radially-between the lower sub  124  and the housing  128 . The seals  132 A,  132 B may be made of a polymer or elastomer (e.g., rubber) and designed to prevent fluid flow between adjacent components. In at least one embodiment, the seals  132 A,  132 B may be O-rings. 
     The upper sub  114  may have one or more first openings  116  formed radially therethrough. The first openings  116  may have burst or rupture discs  117  positioned therein that prevent fluid flow through the first openings  116 . The burst discs  117  are configured to burst when a pressure of the fluid in the bore  112  exceeds a predetermined level to provide a path of fluid communication from the bore  112 , through the first openings  116 , and into at least a portion of an annulus  134  formed between the upper sub  114  and the housing  128 . In other embodiments, instead of or in addition to burst discs  117 , the first openings  116  may include valves, sliding sleeves, or the like to selectively allow fluid flow through the first openings  116 . 
     The upper sub  114  may also have one or more second openings  118  formed radially therethrough. The second openings  118  may provide a path of fluid communication between the bore  112  and at least a portion of the annulus  134 . The second openings  118  may be axially-offset (e.g., as proceeding along a central longitudinal axis  106  of the downhole tool  100 ) from the first openings  116 . As shown, the second openings  118  may be positioned below or downstream from the first openings  116 . 
     The housing  128  may also have one or more openings  130  formed radially therethrough. The openings  130  may be positioned between the upper and lower subs  114 ,  124 . The openings  130  may provide a path of fluid communication between the annulus  134  and an exterior of the housing  128 . As shown, the openings  130  in the housing  128  are axially-offset (e.g., below or downstream) from the second openings  118  in the upper sub  114 ; however, in other embodiments, the openings  118 ,  130  may be axially-aligned with one another. 
     One or more annular sleeves (three are shown:  140 ,  150 ,  160 ) may be positioned within the body  110 . More particularly, a first drive sleeve  140  may be positioned at least partially between the upper sub  114  and the housing  128 . Seals  132 C,  132 D may be positioned radially-between the upper sub  114  and the first drive sleeve  140  and on opposing axial sides of the first openings  116  in the upper sub  114 . 
     A second drive sleeve  150  may also be positioned at least partially between the upper sub  114  and the housing  128 . The second drive sleeve  150  may be positioned below or downstream from the first drive sleeve  140 . Seals  132 E,  132 F may be positioned radially-between the upper sub  114  and the second drive sleeve  150  and on opposing axial sides of the second openings  118  in the upper sub  114 . 
     The second drive sleeve  150  may have one or more openings  152  formed radially therethrough. The openings  152  in the second drive sleeve  150  may be axially-offset and/or circumferentially-offset from the second openings  118  in the upper sub  114  when the downhole tool  100  is in the run-in position. As such, the second drive sleeve  150  (and the seals  132 E,  132 F) may prevent fluid from flowing through the second openings  118  in the upper sub  114 . 
     A third “main” sleeve  160  may be positioned at least partially between the upper sub  114  and/or the lower sub  124  on one side and the housing  128  on the other side. The main sleeve  160  may be positioned below or downstream from the second drive sleeve  150 . The main sleeve  160  may be axially-aligned with the openings  130  in the housing  128  when the downhole tool  100  is in the run-in position. As such, the main sleeve  160  may prevent fluid from flowing through the openings  130  in the housing  128 . 
     Seals  132 G,  132 H may be positioned radially-between the main sleeve  160  and the housing  128  and on opposing axial sides of the openings  130  in the housing  128 . Similarly, additional seals  1321 ,  132 J may be positioned radially-between the main sleeve  160  on one side and the upper and/or lower subs  114 ,  124  on the other side and on opposing axial sides of the openings  130  in the housing  128 . 
     A biasing member  142  may be positioned proximate to the first drive sleeve  140 . The biasing member  142  may be a spring, a Bellville washer, or the like. The biasing member  142  may be axially-adjacent to at least a portion of the first drive sleeve  140 . As shown, the biasing member  142  is positioned radially-between the upper sub  114  and the first drive sleeve  140 . In other embodiments, the biasing member  142  may be positioned radially-between the first drive sleeve  140  and the housing  128 . The biasing member  142  may exert a force on the first drive sleeve  140  in an upstream direction  104  (e.g., to the left, as shown in  FIG. 1 ) to bias the first drive sleeve  140  into the position shown in  FIG. 1 . 
     A first ring  170  may be positioned radially-between the first and second drive sleeves  140 ,  150 . A second ring  180  may be positioned radially-between the second drive sleeve  150  and the upper sub  114 . In another embodiment, the second ring  180  may be positioned radially-between the second drive sleeve  150  and the housing  128 . The first and second rings  170 ,  180  may be ratchet rings that transfer force and/or movement from one component to another. Despite being described as “rings,” the first and second rings  170 ,  180  may not extend around for the full 360 degrees. Rather, a gap may be formed between the two ends such that the rings  170 ,  180  are substantially “C-shaped.” This may allow the cross-sectional length (e.g., diameter) of the rings  170 ,  180  to expand and collapse based at least partially upon the outer diameter of the surface that they are positioned around. 
     The first drive sleeve  140 , the biasing member  142 , the second drive sleeve  150 , the first ring  170 , the second ring  180 , or a combination thereof may function as a linear actuator  190 . The linear actuator  190  may be positioned at least partially around the upper sub  114 , the lower sub  124 , or a combination thereof. As described in greater detail below, the linear actuator  190  may actuate from a first state ( FIG. 1 ) to a second state ( FIG. 5 ) in response to a first level of pressure in the bore  112 . The linear actuator  190  may then actuate into a third state ( FIG. 7 ) in response to a second level of pressure in the bore  112 . The second level of pressure may be less than or equal to the first level of pressure. The main sleeve  160  may prevent fluid flow through the openings  130  when the linear actuator  190  is in the first and second states. The main sleeve  160  may move such that a path of fluid communication exists between the bore  112  and the exterior of the housing  128  (through the openings  130 ) when the linear actuator  190  is in the third state. The linear actuator  190  moves in a linear/axial direction. In at least some embodiments, the linear actuator  190  may thus actuate without relying on, and may potentially restrain, rotational movement of its component parts. The linear actuator  190  does not rotate as it moves. 
       FIG. 2  illustrates an enlarged cross-sectional side view of a portion of the downhole tool  100  shown in  FIG. 1  including the first ring  170 , according to an embodiment. The inner surface  210  of the first drive sleeve  140  may define a recess  212 . The outer surface  230  of the second drive sleeve  150  may also define a recess  232 . The first ring  170  may be positioned in the recesses  212 ,  232  when the downhole tool  100  is in the run-in position. 
     The upstream and downstream surfaces  214 ,  216  that define the recess  212  in the first drive sleeve  140  may be substantially perpendicular to the central longitudinal axis  106  through the body  110 . At least a portion of the upstream and downstream surfaces  172 ,  174  of the first ring  170  may also be substantially perpendicular to the central longitudinal axis  106  through the body  110 . As such, the first ring  170  may remain within the recess  212  in the first drive sleeve  140  when the first drive sleeve  140  moves in either axial direction. 
     Similarly, the downstream surface  236  that defines the recess  232  in the second drive sleeve  150  may be substantially perpendicular to the central longitudinal axis  106  through the body  110 . At least a portion of the downstream surface  174  of the first ring  170  may also be substantially perpendicular to the central longitudinal axis  106  through the body  110 . As such, the first ring  170  may remain in the recess  232  in the second drive sleeve  150  when the first drive sleeve  140  moves in the downstream direction  102  (e.g., to the right, as shown in  FIG. 2 ). 
     As shown, in at least one embodiment, the upstream surface  234  of the second drive sleeve  150  that defines the recess  232  may be sloped. More particularly, an angle between the upstream surface  234  and the central longitudinal axis  106  through the body  110  may be from about 10 degrees to about 80 degrees, about 20 degrees to about 70 degrees, or about 30 degrees to about 60 degrees. At least a portion of the upstream surface  172  of the first ring  170  may also be sloped at substantially the same angle. As such, when the first drive sleeve  140  moves in the upstream direction  104  with respect to the second drive sleeve  150 , the upstream surface  172  of the first ring  170  may slide along the upstream surface  234  of the second drive sleeve  150  until the first ring  170  is no longer positioned in the recess  232  in the second drive sleeve  150 . The first ring  170  may, however, remain within the recess in the first drive sleeve  140 . 
       FIG. 3  illustrates an enlarged cross-sectional side view of a portion of the downhole tool  100  shown in  FIG. 1  including the second ring  180 , according to an embodiment. The inner surface  310  of the second drive sleeve  150  may define a recess  312 . The outer surface  330  of the upper sub  114  may also define a recess  332 . The second ring  180  may be positioned in the recesses  312 ,  332  when the downhole tool  100  is in the run-in position. 
     The upstream and downstream surfaces  314 ,  316  that define the recess  312  in the second drive sleeve  150  may be substantially perpendicular to the central longitudinal axis  106  through the body  110 . At least a portion of the upstream and downstream surfaces  182 ,  184  of the second ring  180  may also be substantially perpendicular to the central longitudinal axis  106  through the body  110 . As such, the second ring  180  may remain within the recess  312  in the second drive sleeve  150  when the second drive sleeve  150  moves in either axial direction. 
     Similarly, the upstream surface  334  that defines the recess  332  in the upper sub  114  may be substantially perpendicular to the central longitudinal axis  106  through the body  110 . At least a portion of the upstream surface  182  of the second ring  180  may also be substantially perpendicular to the central longitudinal axis  106  through the body  110 . As such, the second ring  180  may remain in the recess  332  in the upper sub  114  when the second drive sleeve  150  moves in the upstream direction  104 . 
     As shown, in at least one embodiment, the downstream surface  336  of the upper sub  114  that defines the recess  332  may be sloped. More particularly, an angle between the downstream surface  334  and the central longitudinal axis  106  through the body  110  may be from about 10 degrees to about 80 degrees, about 20 degrees to about 70 degrees, or about 30 degrees to about 60 degrees. At least a portion of the downstream surface  184  of the second ring  180  may also be sloped at substantially the same angle. As such, when the second drive sleeve  150  moves in the downstream direction  102  with respect to the upper sub  114 , the downstream surface  184  of the second ring  180  may slide along the downstream surface of the upper sub  114  until the second ring  180  is no longer positioned in the recess  332  in the upper sub  114 . The second ring  180  may, however, remain within the recess in the second drive sleeve  150 . 
       FIG. 4  illustrates a flowchart of a method  400  for actuating the downhole tool  100 , according to an embodiment. The method  400  is shown and described with respect to  FIGS. 1 and 5-7 . The downhole tool  100  may be run into the wellbore in the run-in position, as at  402  (and as shown in  FIG. 1 , according to an embodiment). In at least one embodiment, the downhole tool  100  may be run into the wellbore until it is located proximate to the end of a horizontal or deviated portion of the wellbore (i.e., the toe of the wellbore). 
     Once located in the desired position in the wellbore, the downhole tool  100  may be actuated into a second position, as shown in  FIG. 5 . To actuate the downhole tool  100  into the second position, a pressure of the fluid in the wellbore may be increased (e.g., by a pump located at the surface) to a first level to test the integrity of the casing in the wellbore, as at  404  in  FIG. 4 . The burst discs  117  may burst as the pressure of the fluid is increased to the first level, thereby providing a path of fluid communication from the bore  112 , through the first openings  116  in the upper sub  114 , and into at least a portion of the annulus  134  formed between the upper sub  114  and the housing  128 . The pressurized fluid may exert a force on one or more piston surfaces on the inner diameter of the first drive sleeve  140 , e.g., two or more surfaces of different surface areas, such that a net force is exerted. 
     In at least one embodiment, an upstream surface  115  of the upper sub  114  that defines the annulus  134  may be sloped with respect to the central longitudinal axis  106  through the body  110 . An angle between the upstream surface  115  and the central longitudinal axis  106  through the body  110  may be from about 10 degrees to about 80 degrees, about 20 degrees to about 70 degrees, or about 30 degrees to about 60 degrees. This sloped upstream surface  115  may provide a surface area differential that enables force exerted on the first drive sleeve  140  by the pressurized fluid in the annulus  134  to exceed the opposing force exerted on the first drive sleeve  140  by the biasing member  142 . This may cause the first drive sleeve  140  to move in the downstream direction  102 . 
     The movement of the first drive sleeve  140  may cause the second drive sleeve  150  to move in the downstream direction  102  due to (e.g., direct) contact between the first and second drive sleeves  140 ,  150 . In another embodiment, the movement of the first drive sleeve  140  may cause the second drive sleeve  150  to move in the downstream direction  102  due to the engagement of the first and second drive sleeves  140 ,  150  with the first ring  170 . This movement may cause a shear mechanism (not shown), which previously held the second drive sleeve  150  in place, to break. The shear mechanism may be a pin, screw, bolt, or the like that is configured to break when exposed to a predetermined axial and/or rotational force. 
     The first ring  170  may remain positioned within the recesses  212 ,  232  ( FIG. 2 ) in the first and second drive sleeves  140 ,  150 , respectively, as the first and second drive sleeves  140 ,  150  move in the downstream direction  102 . The second ring  180  may remain positioned in the recess  312  in the second drive sleeve  150  as the first and second drive sleeves  140 ,  150  move in the downstream direction  102 . However, the second ring  180  may slide out of the recess  332  in the upper sub  114  into a second recess  342  in the upper sub  114  as the first and second drive sleeves  140 ,  150  move in the downstream direction  102 . The second recess  342  in the upper sub  114  may be positioned downstream from the first recess  332  in the upper sub  114 . The first and second drive sleeves  140 ,  150  may move in the downstream direction  102  until the first drive sleeve  140  contacts a shoulder  129  formed on the inner surface of the housing  128  (or the upper sub  114  or the lower sub  124 ), which prevents further movement in the downstream direction  102 . As such, the movement of the first and second drive sleeves  140 ,  150  may not cause the main sleeve  160  to move during the pressure testing. 
     Once the pressure testing is complete, the downhole tool  100  may be actuated into a third position, as shown in  FIG. 6 . The pressure of the fluid in the wellbore may be decreased (e.g., back to hydrostatic pressure) after the pressure reaches the first level, as at  406  in  FIG. 4 . As the pressure decreases, the force exerted on the first drive sleeve  140  in the upstream direction  104  by the biasing member  142  may overcome the opposing force exerted on the first drive sleeve  140  in the downstream direction  102  by the pressurized fluid. This may cause the first drive sleeve  140  to move in the upstream direction  104  into its initial position. 
     The second drive sleeve  150  may not move together with the first drive sleeve  140  in the upstream direction  104 . Rather, the second drive sleeve  150  may be stationary with respect to the upper sub  114  because the second ring  180  may remain positioned within the recess  312  in the second drive sleeve  150  and in the second recess  342  in the upper sub  114 . The first ring  170 , however, may move together with the first drive sleeve  140  in the upstream direction  104 . More particularly, the first ring  170  may remain positioned within the recess  212  in the first drive sleeve  140 . However, the first ring  170  may slide out of the recess  232  in the second drive sleeve  150  into a second recess  242  defined in or by the second drive sleeve  150 . The second recess  242  in the second drive sleeve  150  may be upstream from the first recess  232  in the second drive sleeve  150 . 
       FIG. 7  illustrates the downhole tool  100  in a fourth position, according to an embodiment. The pressure of the fluid in the wellbore may be increased again (e.g., by the pump at the surface) to a second level, as at  408  in  FIG. 4 . The second level may be less than or equal to the first level described above. The fluid may flow from the bore  112 , through the first openings  116  in the upper sub  114 , and into the annulus  134  again. The force exerted on the first drive sleeve  140  by the pressurized fluid in the downstream direction  102  may exceed the opposing force exerted by the biasing member  142  in the upstream direction  104 . This may cause the first drive sleeve  140  to move in the downstream direction  102  again. 
     The movement of the first drive sleeve  140  may cause the second drive sleeve  150  to move in the downstream direction  102  due to the engagement of the first and second sleeves  140 ,  150  with the first ring  170 . The first and second drive sleeves  140 ,  150  may move in the downstream direction  102  until the first drive sleeve  140  contacts the shoulder  129  formed on the inner surface of the housing  128 . At this point, the second drive sleeve  150  may be positioned farther downstream than it was when the downhole tool  100  was in the second position ( FIG. 5 ) because the first ring  170  is positioned in the second recess  242  in the second drive sleeve  150 , which is upstream from the first recess  232  in the second drive sleeve  150 . When the second drive sleeve  150  is in this position, the openings  152  in the second drive sleeve  150  may be aligned with the second openings  118  in the upper sub  114 . This establishes a path of fluid communication from the bore  112 , through the openings  118 ,  152 , and into the annulus  134 . 
     Once the pressurized fluid from the bore  112  enters the annulus  134  through the second openings  118  in the upper sub  114 , the pressurized fluid may exert a force on the main sleeve  160  in the downstream direction  102 . This force may cause a shear mechanism  162  holding the main sleeve  160  in place to break, and the main sleeve  160  may then move in the downstream direction  102 . Once the main sleeve  160  has moved in the downstream direction  102 , the main sleeve  160  may no longer obstruct the openings  130  in the housing  128 . Accordingly, a path of fluid communication may exist from the bore  112 , through the axial gap between the upper and lower subs  114 ,  124 , through the openings  130 , and to the exterior of the housing  128 . 
       FIG. 8  illustrates a graph  800  of pressure vs. time during the actuation of the downhole tool  100 , according to an embodiment. The graph  800  may represent the pressure seen at the surface (e.g., at the pump that pumps fluid into the wellbore). As may be seen, the pressure of the fluid in the bore  112  of the downhole tool  100  may increase and then level off at the first pressure (shown at  802 ) at which the casing is to be tested. The downhole tool  100  may actuate from the first position ( FIG. 1 ) to the second position ( FIG. 5 ) during the pressure testing (e.g., between T 0  and T 1 ). The pressure of the fluid may then decrease to a point  804 . The downhole tool  100  may actuate from the second position ( FIG. 5 ) to the third position ( FIG. 6 ) as the pressure decreases (e.g., between T 1  and T 2 ). The pressure of the fluid may then be increased again to a second pressure, as shown at point  806 , which may be less than or equal to the first pressure. The downhole tool  100  may actuate from the third position ( FIG. 6 ) to the fourth position ( FIG. 7 ) as the pressure increases (e.g., between T 2  and T 3 ). The pressure of the fluid may then remain at the second pressure, level off at a formation (injection) pressure, or decrease back to the hydrostatic pressure. 
     As used herein, the terms “inner” and “outer”; “up” and “down”; “upper” and “lower”; “upward” and “downward”; “above” and “below”; “inward” and “outward”; “upstream” and “downstream”; 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.