Patent Publication Number: US-11384613-B1

Title: Wellbore dart with separable and expandable tool activator

Description:
TECHNICAL FIELD 
     A wellbore dart and methods of use are provided. The wellbore dart includes a tool activator that is used to activate a component of a downhole tool. The tool activator is separable from the other components of the dart. 
    
    
     
       BRIEF DESCRIPTION OF THE FIGURES 
       The features and advantages of certain embodiments will be more readily appreciated when considered in conjunction with the accompanying figures. The figures are not to be construed as limiting any of the preferred embodiments. 
         FIG. 1  is a perspective view of a wellbore dart according to certain embodiments. 
         FIG. 2  is a longitudinal, cross-sectional view of the wellbore dart of  FIG. 1 . 
         FIG. 3  is a longitudinal, cross-sectional view of the wellbore dart after engaging with a downhole tool. 
         FIG. 4  is a longitudinal, cross-sectional view of the wellbore dart of  FIG. 3  showing separation of the tool activator from the body of the dart. 
         FIG. 5A  is a vertical, cross-sectional view of a tool activator of the wellbore dart showing a ball landing on the tool activator. 
         FIG. 5B  is a vertical, cross-sectional view of the tool activator of  FIG. 5A  showing a ball passing through the tool activator. 
         FIG. 6A  is a perspective view of a tool activator of the wellbore dart with a band as a retracting device. 
         FIG. 6B  is a horizontal, cross-sectional view of a tool activator of the wellbore dart with springs as a retracting device. 
         FIG. 6C  is a horizontal, cross-sectional view of a tool activator of the wellbore dart with a ring as a retracting device. 
         FIG. 7  is a longitudinal, cross-sectional view of the wellbore dart according to certain other embodiments. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     Oil and gas hydrocarbons are naturally occurring in some subterranean formations. In the oil and gas industry, a subterranean formation containing oil and/or gas is referred to as a reservoir. A reservoir can be located under land or offshore. Reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs). In order to produce oil or gas, a wellbore is drilled into a reservoir or adjacent to a reservoir. The oil, gas, or water produced from a reservoir is called a reservoir fluid. 
     As used herein, a “fluid” is a substance having a continuous phase that can flow and conform to the outline of its container when the substance is tested at a temperature of 71° F. (22° C.) and a pressure of one atmosphere “atm” (0.1 megapascals “MPa”). A fluid can be a liquid or gas. A homogenous fluid has only one phase, whereas a heterogeneous fluid has more than one distinct phase. 
     A well can include, without limitation, an oil, gas, or water production well, an injection well, or a geothermal well. As used herein, a “well” includes at least one wellbore. A wellbore can include vertical, inclined, and horizontal portions, and it can be straight, curved, or branched. As used herein, the term “wellbore” includes any cased, and any uncased, open-hole portion of the wellbore. A near-wellbore region is the subterranean material and rock of the subterranean formation surrounding the wellbore. As used herein, a “well” also includes the near-wellbore region. The near-wellbore region is generally considered to be the region within approximately 100 feet radially of the wellbore. As used herein, “into a subterranean formation” means and includes into any portion of the well, including into the wellbore, into the near-wellbore region via the wellbore, or into the subterranean formation via the wellbore. 
     A portion of a wellbore can be an open hole or a cased hole. In an open-hole wellbore portion, a tubing string can be placed into the wellbore. The tubing string allows fluids to be introduced into or flowed from a remote portion of the wellbore. In a cased-hole wellbore portion, a casing is placed into the wellbore that can also contain a tubing string. A wellbore can contain an annulus. Examples of an annulus include, but are not limited to: the space between the wellbore and the outside of a tubing string in an open-hole wellbore; the space between the wellbore and the outside of a casing in a cased-hole wellbore; and the space between the inside of a casing and the outside of a tubing string in a cased-hole wellbore. 
     Wellbore treatment operations can be performed in a wellbore. Treatment operations can involve placing a downhole tool at a desired location within the wellbore. The downhole tool can be used to perform a wide variety of treatment operations. A wellbore dart can be used to activate a component of a downhole tool, such as to shift a sleeve, rotate a sleeve, or block fluid flow through the tool. The wellbore dart can also be used to separate fluids within the wellbore. 
     Darts are generally composed of a body, a nose, a tool activator, and optionally one or more wiper fins (also referred to in the industry as wiper cups). The dart is pumped into the wellbore where the tool activator engages with a downhole tool and activates a component of the downhole tool. The nose can help guide the dart through a tubing string and can be weighted to assist vertical alignment of the dart within the tubing string. The nose can also seat against a component of the downhole tool to block fluid flow through the downhole tool. Wiper fins can also be included on the dart. The wiper fins can be located circumferentially around the outside of the dart body and can function to “wipe” the inside of the tubing string and separate fluids as the dart is being pumped into the wellbore. 
     One significant disadvantage to traditional darts is that the dart used to activate one downhole tool can block placement of other devices, such as darts or balls, below the dart because the body of the dart obstructs the inside of the downhole tool. In order to allow placement of other darts or balls below the dart, the dart must be removed from the wellbore. Removal of the dart can include drilling the dart or running a retrieval tool into the wellbore to pull the dart out of the wellbore. The process of removing the dart is not only time consuming, but also increases the cost of performing the wellbore operation. As such, there is a need and ongoing industry concern for improved darts that activate a downhole tool. 
     Novel darts are disclosed. The dart includes a tool activator that is separable from the body of the dart after the dart has activated a downhole tool. The dart can be used to activate a downhole tool. One of the many advantages of the novel dart is that the body of the dart does not prevent additional devices, such as darts or balls, from being introduced into the wellbore downstream of the dart after separation from the tool activator. Thus, the dart does not have to be removed from the wellbore in order for tools to be subsequently activated or balls to seat on a ball seat. 
     A wellbore dart can include: a body; and a tool activator releasably connected to the body by a frangible device, wherein the tool activator comprises: a first section; a second section; and a third section, wherein the first, second, and third sections are movable radially away from each other into an expanded position when a force is applied to an inner diameter of the tool activator. 
     The wellbore dart can further include a retracting device, wherein the retracting device is configured to move the first, second, and third sections radially towards each other from the expanded position into a retracted position when the force is removed from the inner diameter of the tool activator. 
     Methods of activating a downhole tool can include: introducing a dart into a wellbore, wherein the dart comprises: a body; and a tool activator comprising a first section; a second section; and a third section, wherein the tool activator is releasably connected to the body by a frangible device; causing or allowing the tool activator to activate the downhole tool; releasing the tool activator from connection with the body; introducing a device into the wellbore, wherein the device has an outer diameter that is greater than an inner diameter of the tool activator; causing the device to pass through the tool activator, wherein the device causes the first, second, and third sections to move radially away from each other into an expanded position as the device passes through the tool activator; and allowing the first, second, and third sections to move radially towards each other into a retracted position after the device has passed through the tool activator. 
     It is to be understood that the discussion of any of the embodiments regarding the dart or any component of the dart is intended to apply to all of the method and apparatus embodiments without the need to repeat the various embodiments throughout. 
     Turning to the Figures,  FIG. 1  is a perspective view of a wellbore dart  100 . The dart  100  can include a body  110 . The body  110  can be cylindrical in shape and have a variety of dimensions. The length of the body  110  can be selected such that a desired orientation of the dart  100  within a tubing string during introduction into a wellbore is achieved. The desired orientation can be a substantially centered longitudinal axis of the body  110  within the inside of the tubing string. In this manner, the dart  100  can maintain a substantially axial orientation within the tubing string and does not tilt off its longitudinal axis. The length of the body  110 , for example, can range from 10 inches (in.) to 30 in. 
     The outer diameter (O.D.) of the body  110  can vary and can be selected such that the dart  100  is capable of being placed in a desired location within the wellbore. Accordingly, the O.D. of the body  110  can be less than the inner diameter (ID.) of any tubing string or downhole tool that the dart  100  is meant to pass through. The O.D. of the body  110  can also be selected such that the desired orientation of the dart  100  within the tubing string during introduction into the wellbore is achieved. The O.D. of the body  110 , for example, can range from ½ in. to 4 in. 
     The body  110  can be made from materials known to those skilled in the art. Non-limiting examples of materials include metals, metal alloys, and hardened plastics, such as thermoset and thermoplastic materials. According to any of the embodiments, the body  110  is solid. According to any of the embodiments, the body can include a hollow core. According to any of the embodiments, the body  110  does not include a rupture disk. Any common bodies known to those skilled in the art can be used for the dart  100 . The body can be sized such that wipers  112  can fold up in the annular space between the O.D. of the body  110  and an I.D. of the casing or tubing through which the wellbore dart  100  passes. 
     The dart  100  can also include a nose  114 . The nose  114  can be located at a first end of the body  110 . The nose  114  can function as a guide for the dart  100  during introduction into the wellbore. A variety of noses known to those skilled in the art can be used for the dart  100 . The nose  114  can, for example, be rounded or weighted, and/or form a high-pressure seal when seated onto or within a downhole tool. The nose  114  can include a latch ring or lock ring that can secure the dart  100  in place after landing on a seat. 
     The dart  100  can also include one or more wipers  112  (also known as wiper fins or wiper cups). The wipers  112  can function to separate two different wellbore fluids and “wipe” or remove residual fluid on the inside of a tubing string. Although shown with two wipers  112  in the drawings, it is to be understood that a plurality of wipers  112  can be included on the dart  100 . The wipers  112  can extend circumferentially around the outside of the body  110 . The O.D. of the wipers  112  can be the same or different. Different sized wipers can be used to wipe different sized tubing strings. The wipers  112  can be made of commonly known materials, for example, natural or synthetic rubber or urethane elastomers that provide flexibility to the wipers. A variety of wipers  112  known to those skilled in the art can be used for the dart  100 . The geometric shape of the wipers  112  can vary. The angle at which the wipers  112  extend away from the body  110  towards the I.D. of the tubing or casing string can also vary and be selected such that the wipers engage in a wiping action on the inside of the tubing or casing string. The thickness of the wipers  112  can also vary. The shape, angle, thickness, and total number of wipers  112  can be selected to provide multiple external steps or compound angles targeted at multiple inner diameters the dart  100  must pass through. In this manner, the wipers  112  can engage with a variety of different inner diameters and function to wipe the inside of different sized tubing or casing strings. 
     The dart  100  also includes a tool activator  120 . Still with reference to  FIG. 1 , the tool activator  120  can include a first section  121 , a second section  122 , and a third section  123 . The tool activator  120  can also include a fourth section  124 , a fifth, sixth, seventh, and so on sections (not shown). As will be discussed in more detail below, the tool activator  120  preferably includes at least three sections. The tool activator  120  can be made from a variety of materials including, but not limited to, metals, metal alloys, and hardened plastics or composites. Metals and metal alloys can be selected from aluminum, steel, or cast iron. 
       FIG. 2  is a cross-sectional view of the dart  100 . As can be seen, the tool activator  120  is releasably connected to the body  110  by a frangible device  130 . The tool activator  120  is releasably connected to a second end of the body  110  opposite of the nose  114 . The frangible device  130  can be any device that is capable of withstanding a predetermined amount of force and capable of releasing at a force above the predetermined amount of force. The frangible device  130  can be, for example, a shear pin, a shear screw, a shear ring, a load ring, a lock ring, a pin, or a lug. There can also be more than one frangible device  130  that connects the tool activator  120  to the body  110 . The frangible device  130  or multiple frangible devices can be selected based on the force rating of the frangible device, the total number of frangible devices used, and the predetermined amount of force needed to release or shear the frangible device. For example, if the total force required to break or shear the frangible device is 15,000 pounds force (lb f ) and each frangible device has a rating of 5,000 lb f , then a total of three frangible devices may be used. 
     The frangible device  130  spans from a recess  131  located within an inner diameter of a section of the tool activator  120  to a recess  132  located within an outside of the body  110 . According to any of the embodiments, at least one frangible device  130  releasably connects every section  121 ,  122 ,  123 , and  124  to the body  110 . In this manner the dart  100  and each section  121 / 122 / 123 / 124  of the tool activator  120  has structural integrity until the pressure in the tubing string is sufficient to shear the frangible devices  130 . According to these embodiments, there would be a total of four frangible devices  130 , four recesses  131  (one for each of the four sections  121 / 122 / 123 / 124 ), and four recesses  132  on the body  110  that correspond to the recesses  131  on the sections  121 / 122 / 123 / 124 . It is to be understood that if the tool activator  120  includes more than four sections, then the total number of frangible devices  130  included can be greater than four. 
     As can be seen in  FIG. 2 , the tool activator  120  includes an inner diameter and an outer diameter. The I.D. can include an angled surface  125  that partially extends from a top end of the tool activator  120  towards a bottom end. The I.D. can also have a straight surface  126  that extends from where the angled surface  125  ends to the bottom end. According to any of the embodiments, the recesses  131  for housing the frangible devices  130  are located within the straight surface  126 . These embodiments can be useful when the top of the body  110  terminates at the angled surface  125 /straight surface  126  junction. This location of frangible devices can prevent premature shearing of the frangible devices. 
     The methods include introducing the dart  100  into a wellbore. The wellbore can include a tubing string and a downhole tool located within the tubing string. As shown in  FIG. 3 , the tool activator  120  can be configured to engage with a downhole tool  150 . The methods can include causing or allowing the tool activator  120  to activate the downhole tool  150 . The tool activator  120  can activate the downhole tool to cause an action to occur. Examples of the action include, but are not limited to, shifting of a sleeve of the downhole tool, rotating a sleeve of the downhole tool, or shutting off fluid flow through the downhole tool. The tool activator  120  can cause a variety of different actions to occur depending on the exact downhole tool that the tool activator  120  activates. The tool activator  120  is releasably connected to the body  110  during activation of the downhole tool  150 . 
     The methods can include releasing the tool activator  120  from connection with the body  110 . The step of releasing can include applying a pressure to the dart  100 . By way of example, after the tool activator  120  has activated the downhole tool  150 , a force can be applied to the dart  100  that shears the frangible devices  130 ; thus, separating the tool activator  120  from the body  110 . As shown in  FIG. 4 , the tool activator  120  remains engaged with the downhole tool  150  after shearing, while the body  110 , the nose  114 , and the wipers  112  can travel through the downhole tool  150 , thereby enabling fluid flow through the downhole tool  150 . The body  110 , the nose  114 , and the wipers  112  can be retained by the downhole tool  150  or retained in a separate retainer after shearing and traveling downstream of the tool activator  120 . 
     After the tool activator  120  has been released from connection with the body  110 , the methods can include introducing a device into the wellbore. The device can be, without limitation, another dart, a plug, or a ball. The device can have an O.D. that is greater than the I.D. of the tool activator  120 . Turning to  FIG. 5A , the device is depicted as a ball  160  having an O.D. greater than the I.D. of the tool activator  120 . 
     The sections  121 / 122 / 123 / 124  of the tool activator  120  are movable radially away from each other into an expanded position when a force is applied to the I.D. of the tool activator  120 . As can be seen in  FIGS. 5A and 5B , the ball  160  can land onto the tool activator  120 . Angled surfaces  125  of the sections  121 / 122 / 123 / 124  can guide or force the ball  160  into the center of the tool activator  120 . Continued application of a downward force on the ball  160 , for example via fluid pressure within the tubing string, causes the ball  160  to exert an outward force on the sections  121 / 122 / 123 / 124 . The greater or steeper the angle of the angled surfaces  125 , the more uniform spread as well as increased spread of the sections  121 / 122 / 123 / 124  that can be achieved. This outward force causes the sections  121 / 122 / 123 / 124  to expand radially away from each other into an expanded position, for example, as shown in  FIG. 5B . When the sections  121 / 122 / 123 / 124  have expanded a sufficient distance away from center, the ball  160  has enough clearance to pass through the tool activator  120 . Accordingly, causing the device to pass through the tool activator can include applying a downward pressure to the device, wherein the downward pressure forces the sections  121 / 122 / 123 / 124  to radially move away from each other into the expanded position. 
     According to any of the embodiments, the tool activator  120  includes at least three sections  121 / 122 / 123 . In this manner, radial expansion away from each other can be more easily achieved. The force that is applied to the sections  121 / 122 / 123 / 124  may need to be in more than two directions. If the tool activator  120  includes only two sections, then a sufficient radial expansion away from each other may not occur to allow the device to pass through the tool activator  120 . 
       FIG. 6A  shows a perspective view of the tool activator  120 . As can be seen, a demarcation line  129  can delineate the sections  121 / 122 / 123 / 124 . According to any of the embodiments, the tool activator  120  can include discreet sections  121 / 122 / 123 / 124  that are made by forming the tool activator  120  as a single unit and then cutting the tool activator into the desired number of sections. Alternatively, each section can be formed independently and then assembled into a completed tool activator that is then releasably connected to the body  110 . According to any of the other embodiments, the tool activator  120  can be formed as a single unit that includes three or more score lines, wherein the total number of score lines equals the total number of sections. The score lines provide a weak point whereby an applied force can break the tool activator  120  into the desired number of sections. If the tool activator  120  includes score lines, then only two frangible devices  130  that are located opposite each other may be needed because structural integrity is maintained due to the tool activator  120  being formed as a single unit. 
     The methods can include allowing the sections  121 / 122 / 123 / 124  to move radially towards each other into a retracted position after the device (e.g., the ball  160 ) has passed through the tool activator  120 . The tool activator  120  can also include a retracting device. The retracting device can be configured to cause the sections  121 / 122 / 123 / 124  to move into the retracted position after expansion. 
       FIG. 6A  depicts a band  140  as the retracting device. The band  140  can be positioned around the outside of the tool activator  120  and surround all of the sections  121 / 122 / 123 / 124 . The band  140  can have a height that is within 20% to 100% of the height of the sections  121 / 122 / 123 / 124 . The band  140  can be made from a stretchable material that then returns to its pre-stretched state after the device passes through the tool activator  120 . Materials such as natural latex rubber and expanded neoprene are suitable for this purpose. Other suitable materials for the band  140  include, but are not limited to, knitted compression cottons, polyesters, or other fibers, and thermal plastics that are stretchable. A circumferential coil spring could also be used for the band. In this manner, the band  140  can expand with the sections  121 / 122 / 123 / 124  without breaking into the expanded position during passage of the device and then move the sections  121 / 122 / 123 / 124  radially towards each other into the retracted position. 
       FIG. 6B  is a horizontal, cross-sectional view of the tool activator  120  in the expanded position and depicts a spring  141  as the retracting device. The tool activator  120  can include at least a first spring  141  that connects the first section  121  to the second section  122 , a second spring that connects the second section  122  to the third section  123 , a third spring that connects the third section  123  to the fourth section  124 , and a fourth spring that connects the fourth section  124  to the first section  121 . In other words, at least one spring  141  is located at each demarcation line  129 . There can be more than one spring  141  located at each demarcation line  129 . Both ends of each of the sections  121 / 122 / 123 / 124  can include a receiver  128  that houses an end of the spring  141 . The ends of the spring  141  can be permanently attached to the sections  121 / 122 / 123 / 124 , for example with a glue, resin, hardened plastic, or other compounds. Preferably, the receivers  128  are located within the straight surface  126  area of the sections  121 / 122 / 123 / 124 . In this manner, the springs  141  are capable to stretching with the sections  121 / 122 / 123 / 124  into the expanded position without breaking or detaching from the sections  121 / 122 / 123 / 124  and then moving the sections  121 / 122 / 123 / 124  back towards each other into the retracted position. 
       FIG. 6C  is a horizontal, cross-sectional view of the tool activator  120  in the expanded position and depicts a ring  142 , such as an O-ring, located circumferentially within the sections  121 / 122 / 123 / 124 . A middle portion of the sections  121 / 122 / 123 / 124  can include a receiving groove  127  that houses the ring  142 . The ring  142  can be made from a stretchable material, for example, those materials disclosed above for the band. Preferably, the receiving groove  127  is located within the straight surface  126  area of the sections  121 / 122 / 123 / 124 . In this manner, the ring  142  is capable to stretching with the sections  121 / 122 / 123 / 124  into the expanded position without breaking and then moving the sections  121 / 122 / 123 / 124  back towards each other into the retracted position. 
     According to certain other embodiments, the tool activator  120  does not include a retracting device. An adhesive can be applied to each demarcation line  129  to temporarily hold the sections  121 / 122 / 123 / 124  together. The adhesive can be a glue or resin, for example. The sections  121 / 122 / 123 / 124  can separate from one another when a force from the device (e.g., the ball  160 ) is applied to the tool activator  120  and this force causes the adhesive to lose its bonding ability. The sections  121 / 122 / 123 / 124  can also be temporarily held together by score lines or a band, for example a metal band, located around the outside of the sections  121 / 122 / 123 / 124 . When the force from the device is applied to the tool activator  120 , the sections  121 / 122 / 123 / 124  can separate from each other by breaking into sections at the score lines or the band breaking into two or more pieces. Frangible devices can also be used to temporarily hold the sections together. The frangible devices can be positioned on the tool activator  120  as discussed above regarding the springs  141 . When the force from the device is applied to the tool activator  120 , the sections  121 / 122 / 123 / 124  can separate from each other by shearing of the frangible devices. 
     For the embodiments in which a retracting device is not used, a retainer can be included in the tubing string or the downhole tool  150  located adjacent to the tool activator  120 . Because the sections  121 / 122 / 123 / 124  are not held together by a retracting device, the sections are susceptible to falling or flowing into the downhole tool and creating an obstruction. The retainer can be any component that prevents the sections  121 / 122 / 123 / 124  from flowing downstream within the downhole tool  150  after separating from each other. The retainer can be, without limitation, a sleeve or a pocket that retains the separated sections  121 / 122 / 123 / 124  at their location. An elastomeric sleeve can be used to contract and move the sections  121 / 122 / 123 / 124  back towards each other into the retracted position after the device passes through the tool activator  120 . 
     Turning to  FIG. 7 , the dart  100  can include a second tool activator  170 . The second tool activator  170  can be positioned around the outside of the tool activator  120 . The second tool activator  170  can have a different shape, for example a rhombus shape, from the tool activator  120 , which has a ring shape. The second tool activator  170  can be removably attached to the tool activator  120  by two or more frangible devices  134 . In practice, the second tool activator  170  can activate the downhole tool  150  to perform a first function, and then the tool activator  120  can be detached from the second tool activator  170  via shearing of the frangible devices  134 . After shearing, the second tool activator  170  can remain in place while the tool activator  120 , body  110 , and the other components of the dart  100  can move further downstream within the downhole tool  150 . The tool activator  120  can then activate the downhole tool  150  to perform a second function. After the second function has been performed, the tool activator  120  can be detached from the body  110  via shearing of the frangible devices  130 . 
     An embodiment of the present disclosure is a wellbore dart comprising: a body; and a tool activator releasably connected to the body by a frangible device, wherein the tool activator comprises: a first section; a second section; a third section, wherein the first, second, and third sections are movable radially away from each other into an expanded position when a force is applied to an inner diameter of the tool activator; and a retracting device, wherein the retracting device is configured to move the first, second, and third sections radially towards each other from the expanded position into a retracted position when the force is removed from the inner diameter of the tool activator. Optionally, the wellbore dart further comprises wherein the tool activator is made from metals, metal alloys, or hardened plastics or composites. Optionally, the wellbore dart further comprises wherein each of the first, second, and third sections comprise at least one frangible device. Optionally, the wellbore dart further comprises wherein the frangible device is selected from the group consisting of a shear pin, a shear screw, a shear ring, a load ring, a lock ring, a pin, a lug, or combinations thereof. Optionally, the wellbore dart further comprises wherein the tool activator further comprises one or more wipers located circumferentially around an outside of the body. Optionally, the wellbore dart further comprises wherein the inner diameter of the tool activator comprises an angled surface that partially extends from a top end of the tool activator towards a bottom end, and wherein the inner diameter of the tool activator further comprises a straight surface that extends from a bottom edge of the angled surface to the bottom end of the tool activator. Optionally, the wellbore dart further comprises wherein the force is applied to the inner diameter of the tool activator via a device, wherein the device is selected from another dart, a plug, or a ball, and wherein the device has an outer diameter that is greater than the inner diameter of the tool activator. Optionally, the wellbore dart further comprises wherein the tool activator is configured to allow the device to pass through the tool activator via a sufficient radial expansion of the first, second, and third sections. Optionally, the wellbore dart further comprises wherein the retracting device is a band positioned circumferentially around the outside of the first, second, and third sections. Optionally, the wellbore dart further comprises wherein the band is made from a stretchable material that returns to a pre-stretched state after the force is removed. Optionally, the wellbore dart further comprises wherein the retracting device comprises at least three springs that correspond to the first, second, and third sections, wherein at least one of the at least three springs is located between two of the sections. Optionally, the wellbore dart further comprises wherein each of the first, second, and third sections comprises a receiver that houses an end of the at least three springs. Optionally, the wellbore dart further comprises wherein the retracting device is a ring, wherein a middle portion of the first, second, and third sections comprises a receiving groove that houses the ring, and wherein the ring is made from a stretchable material that returns to a pre-stretched state after the force is removed. Optionally, the wellbore dart further comprises a second tool activator, wherein the second tool activator is positioned around the outside of the tool activator. 
     Another embodiment of the present disclosure is a wellbore dart comprising: a body; and a tool activator releasably connected to the body by a frangible device, wherein the tool activator comprises: a first section; a second section; and a third section, wherein the first, second, and third sections are movable radially away from each other into an expanded position when a force is applied to an inner diameter of the tool activator. Optionally, the wellbore dart further comprises a retainer, wherein the retainer prevents the first, second, and third sections from flowing downstream within a downhole tool after separating from each other via the force applied to the inner diameter of the tool activator. Optionally, the wellbore dart further comprises wherein the retainer is selected from a sleeve or a pocket. 
     Another embodiment of the present disclosure is a method of activating a downhole tool comprising: introducing a dart into a wellbore, wherein the dart comprises: a body; and a tool activator comprising a first section, a second section, and a third section, wherein the tool activator is releasably connected to the body by a frangible device; causing or allowing the tool activator to activate the downhole tool; releasing the tool activator from connection with the body; introducing a device into the wellbore, wherein the device has an outer diameter that is greater than an inner diameter of the tool activator; causing the device to pass through the tool activator, wherein the device causes the first, second, and third sections to move radially away from each other into an expanded position as the device passes through the tool activator; and allowing the first, second, and third sections to move radially towards each other into a retracted position after the device has passed through the tool activator. Optionally, the method further comprises wherein the body releases from the tool activator after activation of the downhole tool, and wherein after releasing, the body moves downstream within the downhole tool. Optionally, the method further comprises wherein the step of releasing comprises applying a pressure to the dart. 
     Therefore, the various embodiments are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the various embodiments may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is, therefore, evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present invention. 
     As used herein, the words “comprise,” “have,” “include,” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps. While compositions, systems, and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions, systems, and methods also can “consist essentially of” or “consist of” the various components and steps. It should also be understood that, as used herein, “first,” “second,” and “third,” are assigned arbitrarily and are merely intended to differentiate between two or more sections, wipers, springs, etc., as the case may be, and does not indicate any sequence. Furthermore, it is to be understood that the mere use of the word “first” does not require that there be any “second,” and the mere use of the word “second” does not require that there be any “third,” etc. 
     Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.