Patent Publication Number: US-11391117-B2

Title: Annular casing packer collar stage tool for cementing operations

Description:
BACKGROUND 
     The present disclosure generally relates to multiple stage operations, and more particularly to systems and methods for performing cementing jobs with a stage tool. 
     In the drilling of deep wells, it is often desirable to cement the casing in the well bore in separate stages, beginning at the bottom of the well and working upward. During the drilling and construction of subterranean wells, casing strings are generally introduced into the wellbore. To stabilize the casing, a cement slurry is often pumped downwardly through the casing, and then upwardly into the annulus between the casing and the walls of the wellbore. One concern in this process is that, prior to the introduction of the cement slurry into the casing, the casing generally contains a drilling or some other servicing fluid that may contaminate the cement slurry. To prevent this contamination, a subterranean plug, often referred to as a cementing plug or a “bottom” plug, may be placed into the casing ahead of the cement slurry as a boundary between the two. The plug may perform other functions as well, such as wiping fluid from the inner surface of the casing as it travels through the casing, which may further reduce the risk of contamination. 
     Similarly, after the desired quantity of cement slurry is placed into the casing, a displacement fluid is commonly used to force the cement into the desired location. To prevent contamination of the cement slurry by the displacement fluid, a “top” cementing plug may be introduced at the interface between the cement slurry and the displacement fluid. This top plug also wipes cement slurry from the inner surfaces of the casing as the displacement fluid is pumped downwardly into the casing. 
     In some circumstances, a pipe string will be placed within the wellbore by a process comprising the attachment of the pipe string to a tool (often referred to as a “casing hanger and run-in tool” or a “work string”) which may be manipulated within the wellbore to suspend the pipe string in a desired sub-surface location. In addition to the pipe string, a sub-surface release cementing plug system comprising a plurality of cementing plugs may also be attached to the casing hanger and run-in tool. Such cementing plugs may be selectively released from the run-in tool at desired times during the cementing process. Additionally, a check valve, typically called a float valve, will be installed near the bottom of the pipe string to perform the first stage operation. The float valve may permit the flow of fluids through the bottom of the pipe string into the annulus, but not the reverse. A cementing plug will not pass through the float valve. 
     In conventional second stage operations, sleeves are individually shifted via plugs. Subsequently, packer elements can expand due to available hydraulic pressure from the shifting sleeves. However, this can be costly and time-consuming to drop a plug for each desired operation. For example, incorrect plugs may be inadvertently used or operator error may occur in the release/launch of the proper plug at the appropriate time. Further, rupture discs covering ports within conventional cementing tools can be prematurely actuated when there are pressure losses within the tool, thereby allowing access between the exterior and interior of the cementing tool during non-ideal conditions. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       These drawings illustrate certain aspects of some of the embodiments of the present disclosure and should not be used to limit or define the claims. 
         FIG. 1  illustrates a system configured for delivering cement slurries downhole in accordance with one or more embodiments of the present disclosure. 
         FIG. 2  illustrates a cross-sectional view of a cementing tool in a first position in accordance with one or more embodiments of the present disclosure. 
         FIG. 3  illustrates a cross-sectional view of a cementing tool in a second position in accordance with one or more embodiments of the present disclosure. 
         FIG. 4  illustrates a cross-sectional view of a cementing tool in a third position in accordance with one or more embodiments of the present disclosure. 
         FIG. 5  illustrates a cross-sectional view of a cementing tool in a fourth position in accordance with one or more embodiments of the present disclosure. 
         FIG. 6  illustrates a cross-sectional view of a cementing tool in accordance with one or more embodiments of the present disclosure. 
     
    
    
     While embodiments of this disclosure have been depicted, such embodiments do not imply a limitation on the disclosure, and no such limitation should be inferred. The subject matter disclosed is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those skilled in the pertinent art and having the benefit of this disclosure. The depicted and described embodiments of this disclosure are examples only, and not exhaustive of the scope of the disclosure. 
     DETAILED DESCRIPTION 
     The present disclosure generally relates to multiple stage operations, and more particularly to systems and methods for performing cementing jobs with a stage tool. While conventional stage tools for cementing operations may actuate the packer element to set, expand or both based on a pressure differential between the interior and exterior of the stage tool, the present disclosure contemplates a stage tool that may be configured to mechanically set, expand or both a packer element by transmitting the load after a setting plug has landed on a setting seat. Further, the disclosed stage tool may eliminate the need for rupture disks disposed about the ports of the stage tool. There may be risks of prematurely puncturing rupture disks while disposing conventional stage tools downhole. The disclosed stage tool may provide for setting a packer at a predetermined pressure with fewer seats and plug drops necessary for conventional tooling. As the seats in the disclosed stage tool shift or translate within the stage tool, there may be confirmation at the surface determined by changes in fluid pressure. The disclosed stage tool may provide cost savings in reduced equipment within the tool, reduce risk of prematurely puncturing rupture disks by eliminating the need for such use, and provides for reduced time during operations as fewer plug drops are necessary. 
       FIG. 1  shows an illustrative schematic of a system  100  that can deliver cement slurries, according to one or more embodiments. It should be noted that while  FIG. 1  generally depicts a land-based system, it is to be recognized that like systems may be operated in subsea locations as well. As depicted in  FIG. 1 , the system  100  may include a mixing tank  105 , in which a cement slurry  108  may be formulated. Again, in one or more embodiments, the mixing tank  105  may represent, or otherwise be replaced with, a transport vehicle, a shipping container or both configured to deliver or otherwise convey the cement slurry  108  to the well site. The cement slurry  108  may be conveyed via a line  110  to a wellhead  115 , where the cement slurry  108  enters a tubular  120  (for example, a casing, drill pipe, production tubing, coiled tubing, etc.). The tubular  120  may extend from the wellhead  115  into a wellbore  125  penetrating a subterranean formation  130 . Upon being ejected from the tubular  120 , the cement slurry  108  may subsequently return up the wellbore  125  in the annulus between the tubular  120  and the wellbore  125  as indicated by flow lines  135 . In one or more embodiments, the cement slurry  108  or any other suitable fluid may be reverse pumped down through the annulus and up tubular  120  back to the surface, without departing from the scope of the disclosure. A pump  140  may be configured to raise the pressure of the cement slurry  108  to a desired degree before introduction of the cement slurry  108  into tubular  120  (or the annulus). It is to be recognized that the system  100  is merely exemplary in nature and various additional components may be present that have not necessarily been depicted in  FIG. 1  in the interest of clarity. Non-limiting additional components that may be present include, but are not limited to, supply hoppers, valves, condensers, adapters, joints, gauges, sensors, compressors, pressure controllers, pressure sensors, flow rate controllers, flow rate sensors, temperature sensors, and the like. 
     One skilled in the art, with the benefit of this disclosure, may recognize the changes to the system  100  described in  FIG. 1  to provide for other cementing operations (for example, squeeze operations, reverse cementing (where the cement is introduced into an annulus between a tubular and the wellbore and returns to the wellhead through the tubular), and the like). 
     It is also to be recognized that the cement slurry  108  may also directly, indirectly or both affect the various downhole equipment and tools that may come into contact with the treatment fluids during operation. Such equipment and tools may include, but are not limited to, wellbore casing, wellbore liner, completion string, insert strings, drill string, coiled tubing, slickline, wireline, drill pipe, drill collars, mud motors, downhole motors and/or pumps, surface-mounted motors and/or pumps, centralizers, turbolizers, scratchers, floats (for example, shoes, collars, valves, etc.), wellbore projectiles (for example, wipers, plugs, darts, balls, etc.), logging tools and related telemetry equipment, actuators (for example, electromechanical devices, hydromechanical devices, etc.), sliding sleeves, production sleeves, plugs, screens, filters, flow control devices (for example, inflow control devices, autonomous inflow control devices, outflow control devices, etc.), couplings (for example, electro-hydraulic wet connect, dry connect, inductive coupler, etc.), control lines (for example, electrical, fiber optic, hydraulic, etc.), surveillance lines, drill bits and reamers, sensors or distributed sensors, downhole heat exchangers, valves and corresponding actuation devices, tool seals, packers, cement plugs, bridge plugs, and other wellbore isolation devices, or components, and the like. Any of these components may be included in the systems generally described above and depicted in  FIG. 1 . 
     Referring now to  FIGS. 2, 3, 4 and 5 , a stage tool  200  may be used for performing a cementing operation, other second stage operation or both in a multi-stage operation. Without limitations, the stage tool  200  may comprise an annular casing packer collar. The stage tool  200  may comprise a mandrel  205 . In embodiments, the mandrel  205  may be any suitable size, height, shape and any combination thereof. The mandrel  205  may be a generally tubular element constructed of steel, aluminum, composite, other materials used in oilfield operations and any combination thereof. 
     Both an opening seat  210  and a closing seat  215  may be attached to an interior surface  206  of the mandrel  205 . Such attachment may be made via any suitable fasteners. In embodiments, shear pins may be used thereby allowing selective movement of the respective elements relative to the mandrel  205 . Movement of the opening seat  210  may uncover a port  220  to provide selective communication between the interior surface  206  and an exterior surface  207  of the mandrel  205 . In embodiments, there may be a plurality of ports  220  disposed about the mandrel  205 , wherein each one of the plurality of ports  220  spans the thickness of the mandrel  205 , wherein the opening seat  210  blocks or covers the plurality of ports  220  from the interior surface  206  of the mandrel  205  in a first position (for example, a run-in position). The plurality of ports  220  may be disposed about the mandrel  205  in any suitable fashion, such as in a radial arrangement. Movement of the opening seat  210  may further allow for actuation of a packer element  225  attached to the exterior surface  207  of the mandrel  205 . Movement of the closing seat  215  may cover the plurality of ports  220  preventing communication between the interior surface  206  and the exterior surface  207  of the mandrel  205 . 
     The opening seat  210  may be constructed of any suitable materials, including, but not limited to, metals, nonmetals, polymers, composites, and/or combinations thereof. In embodiments, the opening seat  210  may be constructed of materials used in zonal isolation operations. The opening seat  210  may be disposed adjacent to the closing seat  215  in the first position. In the first position, the opening seat  210  may cover the plurality of ports  220  in the mandrel  205 . Thus, fluid communication between the interior surface  206  and the exterior surface  207  of the mandrel  205  is prevented through the plurality of ports  220  when the opening seat  210  is in the first position. The opening seat  210  may have a first end  211  coupled to an intermediate sleeve  230 , wherein the intermediate sleeve  230  is disposed about the interior surface  206  of the mandrel  205 . The intermediate sleeve  230  may translate in-line with the translation of the opening seat  210 . Without limitations, a plurality of shear pins  233  may couple the intermediate sleeve  230  to the first end  211  of the opening seat  210 . The plurality of shear pins  233  may allow the intermediate sleeve  230  to move in tandem with the opening seat  210  until the plurality of shear pins  233  are sheared. After the plurality of shear pins  233  have been sheared, the intermediate sleeve  230  may translate in relation to the opening seat  210 . In one or more embodiments, the intermediate sleeve  230  may translate in a direction parallel to further movement or translation of the opening seat  210 . 
     In embodiments, the intermediate sleeve  230  may serve to transfer movement from the opening seat  210  to a setting sleeve  235  via suitable fasteners that couple said intermediate sleeve  230  to the setting sleeve  235 . In one or more embodiments, the setting sleeve  235  may be disposed about the external surface  207  and around the mandrel  205 . Without limitations, the suitable fasteners may be a plurality of radial setting pins  240 . As illustrated, the plurality of radial setting pins  240  may be disposed in a first set of a plurality of outer channels  245  disposed about the mandrel  205 . In one or more embodiments, each one of the plurality of radial setting pins  240  may be disposed in an individual outer channel  245 , wherein each outer channel  245  spans the thickness of the mandrel  205 . The length of the first set of the plurality of outer channels  245  may limit the distance that the opening seat  210  may travel as the ends of each one of the plurality of outer channels  245  prohibit further movement of the intermediate sleeve  235 . In one or more embodiments, the setting sleeve  235  may be coupled to the intermediate sleeve  230  through the plurality of radial setting pins  240 , wherein the setting sleeve  235  is configured to translate as the intermediate sleeve  230  translates. 
     The opening seat  210  may have a second end  212  with an interior surface  213  having a conical or other shape suitable for swallowing, seating, or otherwise engaging an opening plug  300  (shown in  FIGS. 3-5 ). The opening plug  300  may have any suitable size, height, and/or shape to engage the opening seat  210 . The opening plug  300  may be a plug, ball, dart, or other device for shifting and carrying any one or more seats downward. Without limitations, the opening plug  300  may be formed of aluminum, composite, rubber, or other materials used in multiple stage zonal isolation operations. When the opening plug  300  lands in the opening seat  210 , the opening seat  210  may move from the first position to a second position by translating in an axial direction through the mandrel  205 . In the second position, the opening seat  210  may no longer cover the plurality of ports  220 . As the opening seat  210  moves, the packer element  225  may be actuated. 
     As illustrated, the packer element  225  may be attached to or disposed on the exterior surface  207  of the mandrel  102 . While a singular packer element  225  is depicted, any number of packer elements  225  may be used within the scope of the present disclosure. In one or more embodiments, the packer element  225  may be disposed between the setting sleeve  235  and a ramp  250 . The ramp  250  may be configured to expand the packer element  225  by providing an angle in relation to the exterior surface  207  of the mandrel  205 . The ramp  250  may comprise a lower centralizer  255  at a distal end  251  of the ramp  250 . The lower centralizer  255  may serve to centralize the stage tool  200  within a wellbore. 
     Once the opening plug  300  drops, the opening seat  210  may translate along the interior of the mandrel  205 . Since the setting sleeve  235  is coupled to the opening seat  210 , as the opening seat  210  translates, the setting sleeve  235  may translate accordingly. As the setting sleeve  235  translates, the packer element  225  may be compressed by the setting sleeve  235  and the ramp  250 . Such compression may cause radial expansion of the packer element  225 , allowing the packer element  225  to engage an interior surface (not shown) of the wellbore. The packer element  225  may be displaced over the ramp  250  and against a shoulder  260  of the lower centralizer  255 . In this second position, the packer element  225  may be expanded and sealed against the interior surface of the wellbore and the plurality of ports  220  may be open to allow fluid communication between the interior surface  206  and the exterior surface  207  of the mandrel  205 . As illustrated, the setting sleeve  235  may comprise one or more lock rings  236  disposed at a first end  237  of the setting sleeve  235 . The one or more lock rings  236  may be configured to be received by one or more accommodating grooves  238  disposed on the exterior surface  207  of the mandrel  205 . As the setting sleeve  235  translates and compresses the packer element  225 , the setting sleeve  235  may be locked in place as the one or more lock rings  236  are displaced into the one or more grooves  238 . In this position, the setting sleeve  235  may be inhibited from translating back to cover the plurality of ports  220 . In order to prevent further fluid communication through the plurality of ports  220 , a closing plug  500  (shown in  FIG. 5 ) may be dropped to engage the closing seat  215  to cover the plurality of ports  220 . 
     The closing seat  215  may be constructed of any suitable materials, including, but not limited to, metals, nonmetals, polymers, composites, and/or combinations thereof. In embodiments, the closing seat  215  may be constructed of materials used in zonal isolation operations. The closing seat  215  may be disposed adjacent and uphole to the opening seat  210  in a first position. In the first position (for example, a run-in position), the closing seat  215  may not cover the plurality of ports  220 . Thus, fluid communication between the interior surface  206  and the exterior surface  207  of the mandrel  205  is permitted through the plurality of ports  220  when the closing seat  215  is in the first position and the opening seat  210  is in the second position. The closing seat  215  may be coupled to a closing sleeve  265  disposed about the external surface  207  and around the mandrel  205  via suitable fasteners, wherein the closing sleeve  265  may translate as the closing seat  215  translates. Without limitations, the suitable fasteners may be a plurality of radial closing pins  270 . As illustrated, the plurality of radial closing pins  270  may be disposed in a second set of the plurality of outer channels  245  disposed about the mandrel  205 . In one or more embodiments, each one of the plurality of radial closing pins  270  may be disposed in an individual outer channel  245  of the second set, wherein each outer channel  245  spans the thickness of the mandrel  205 . The length of the second set of plurality of outer channels  245  may limit the distance that the closing seat  215  may travel as the ends of each one of the second set of plurality of outer channels  245  prohibit movement of the closing seat  215 . Further, there may be an upper centralizer  275  disposed about and/or adjacent to the closing sleeve  265  in the first position on the exterior surface  207  of the mandrel  205 . The upper centralizer  275  may serve to centralize the stage tool  200  within the wellbore. As the closing sleeve  265  translates, the closing sleeve  265  may abut the upper centralizer  275  wherein the upper centralizer  275 , the second set of plurality of outer channels  245 , or combinations thereof inhibit further translation in a certain direction. 
     The closing seat  215  may have a first end  216  with an interior surface  217  having a conical or other shape suitable for swallowing, seating, or otherwise engaging the closing plug  500  (shown in  FIG. 5 ), wherein the closing seat  215  is configured to receive the closing plug  500  at the first end  216 . The closing plug  500  may have any suitable size, height, and/or shape to engage the closing seat  215 . The closing plug  500  may be a plug, ball, dart, or other device for shifting and carrying any one or more seats downward. Without limitations, the closing plug  500  may be formed of aluminum, composite, rubber, or other materials used in multiple stage zonal isolation operations. When the closing plug  500  lands in the closing seat  215 , the closing seat  215  may move from the first position to a second position. As the closing seat  215  moves to the second position, the closing sleeve  265  may translate accordingly. When the closing seat  215  has moved to the second position, the closing sleeve  265  may cover the plurality of ports  220 , thereby inhibiting fluid communication between the interior surface  206  and the exterior surface  207  of the mandrel  205 . 
     With reference now to  FIG. 6 , another embodiment of the stage tool  200  is illustrated. As illustrated, the components of the stage tool  200  may be designed similar to the embodiment as shown in  FIGS. 2-5  except that the present embodiment may not require the plurality of shear pins  233  (referring to  FIGS. 2-5 ) to couple the intermediate sleeve  230  to the opening seat  210 . The intermediate sleeve  230  may be coupled to the opening seat  210  by any other suitable means. Alternatively, the opening seat  210  may comprise an extension of material with the plurality of radial setting pins  240  rather than the intermediate setting sleeve  230 . In one or more embodiments, as pressure is applied to the stage tool  200 , the plurality of radial setting pins  240  may shear after the packer element  225  has been actuated to expand. As the plurality of radial setting pins  240  shear, the opening seat  210  may further translate to allow fluid communication between the interior surface  206  and the exterior surface  207  of the mandrel  205  through the plurality of ports  220 . The intermediate sleeve  230  may move or translate in tandem with the opening seat  210  before, after or both the plurality of radial setting pins have sheared. 
     A method of using the stage tool  200  may involve providing the stage tool  200  as described above, running the stage tool  200  into a wellbore, providing the opening plug  300 , disposing the opening plug  300  into the opening seat  210 , providing the closing plug  500 , and placing the closing plug  500  into the closing seat  215 . The stage tool  200  may be run into the wellbore as part of a casing string (for example, tubular  120  shown on  FIG. 1 ) with each of the opening seat  210  and the closing seat  215  in a first position. Thus, the plurality of ports  220  may be covered by the opening seat  210  and not by the closing sleeve  265 . Once the stage tool  200  is in the desired location in the wellbore, the opening plug  300  may be dropped into the casing string and run in until it reaches the stage tool  200  and lands on the opening seat  210 , as illustrated in  FIG. 3 . Moving the opening plug  300  into engagement with the opening seat  210  may require application of pressure within the interior of the casing string, which may be in communication with the interior surface  206  of the mandrel  205  of the stage tool  200 . 
     Once the opening plug  300  has landed on the opening seat  210 , pressure sufficient to cause the opening seat  210  to move from the first position to the second position may be applied. This pressure may be sufficient to shear a set of shear pins holding the opening seat  210  in engagement with the interior surface  206  of the mandrel  205 , allowing the opening seat  210  and the opening plug  300  to move downward. As the opening seat  210  moves downward, the plurality of ports  220  may be uncovered, thereby allowing fluid communication between the interior surface  206  and the exterior surface  207  of the stage tool  200 . As the opening seat  210  moves downward, the packer element  225  may be compressed to expand radially to create a seal against the interior surface of the wellbore. 
     Once the packer element  225  is set, a second stage cementing operation may be performed before disposing the closing plug  500  into the wellbore (for example, a fluid may be introduced to flow through the plurality of ports  220 ). Such fluid in a second stage cementing operation may include cement or other material intended to be placed between the wellbore and the casing string, above the location of the packer element  225 . Once the fluid has been placed between the wellbore and the casing string, the plurality of ports  220  may be blocked or covered through use of the closing plug  500 . The closing plug  500  may be dropped into the casing string and pressure applied to cause the closing plug  500  to land on the closing seat  215 , as illustrated in  FIG. 5 . 
     Once the closing plug  500  has landed on the closing seat  215 , pressure sufficient to cause the closing seat  215  to move from the first position to the second position may be applied. This pressure may be sufficient to shear a set of shear pins holding the closing seat  215  in engagement with the interior surface  206  of the mandrel  205 , allowing the closing seat  215  and the closing plug  500  to move downward. As the closing seat  215  moves downward, the closing sleeve  265  may be displaced over the plurality of ports  220 , preventing further flow of the fluid therethrough. 
     Once these operations are complete, the opening plug  300 , opening seat  210 , the closing plug  500 , and/or the closing seat  215  may be drilled out. 
     An embodiment of the present disclosure is a stage tool comprising: a mandrel, an opening seat, a closing seat, a plurality of ports, a closing sleeve, and a packer element, wherein the opening seat is attached to an interior surface of the mandrel, wherein the closing seat is attached to the interior surface of the mandrel, wherein the plurality of ports is configured to allow fluid communication between the interior surface of the mandrel and an exterior surface of the mandrel, wherein the closing sleeve is disposed on the exterior surface of the mandrel and coupled to the closing seat, and wherein the packer element is disposed on the exterior surface of the mandrel. 
     In one or more embodiments described in the preceding paragraph, the stage tool further comprises an intermediate sleeve coupled to a first end of the opening seat, wherein the opening seat is configured to receive an opening plug at a second end, wherein the second end is opposite to the first end. In one or more embodiments described above, wherein the intermediate sleeve is coupled to the first end of the opening seat through a plurality of shear pins, wherein the intermediate sleeve translates in relation to the opening seat after the plurality of shear pins have been sheared. In one or more embodiments described above, wherein the intermediate sleeve translates in tandem with the opening seat. In one or more embodiments described above, the stage tool further comprises a setting sleeve, wherein the setting sleeve is coupled to the intermediate sleeve through a plurality of radial setting pins, wherein the setting sleeve is configured to translate as the intermediate sleeve translates. In one or more embodiments described above, the stage tool further comprises a ramp, wherein the packer element is disposed between the setting sleeve and the ramp, wherein the ramp comprises a lower centralizer at a distal end of the ramp. In one or more embodiments described above, wherein the closing sleeve is coupled to the closing seat via a plurality of radial closing pins. In one or more embodiments described above, the stage tool further comprises an upper centralizer, wherein the upper centralizer is disposed on the exterior surface of the mandrel about the closing sleeve. In one or more embodiments described above, wherein the closing seat is configured to receive a closing plug at a first end. In one or more embodiments described above, wherein the closing seat is adjacent to the opening seat in a first position, wherein the opening seat blocks the plurality of ports from the interior surface of the mandrel. 
     Another embodiment of the present disclosure is a method for cementing operations comprises: disposing a stage tool downhole into a wellbore, wherein the stage tool comprises: a mandrel, an opening seat, a closing seat, a plurality of ports, a closing sleeve, and a packer element, wherein the opening seat is attached to an interior surface of the mandrel, wherein the closing seat is attached to the interior surface of the mandrel, wherein the plurality of ports is configured to allow fluid communication between the interior surface of the mandrel and an exterior surface of the mandrel, wherein the closing sleeve is disposed on the exterior surface of the mandrel and coupled to the closing seat, wherein the packer element is disposed on the exterior surface of the mandrel, disposing an opening plug into the wellbore, and disposing a closing plug into the wellbore. 
     In one or more embodiments described in the preceding paragraph, wherein the opening plug lands onto the opening seat, wherein the opening seat comprises a first end and a second end, wherein the first end is coupled to an intermediate sleeve, wherein the second end is configured to receive the opening plug. In one or more embodiments described above, wherein the intermediate sleeve is coupled to the first end of the opening seat through a plurality of shear pins. In one or more embodiments described above, the method further comprises shearing the plurality of shear pins. In one or more embodiments described above, the method further comprises translating the opening seat and the intermediate sleeve, wherein the intermediate sleeve is coupled to a setting sleeve, wherein the setting sleeve is coupled to the intermediate sleeve through a plurality of radial setting pins, wherein the setting sleeve is configured to translate as the intermediate sleeve translates. In one or more embodiments described above, the method further comprises actuating the packer element to expand in a radial direction to engage the wellbore. In one or more embodiments described above, wherein the closing plug lands onto the closing seat, wherein a first end of the closing seat is configured to receive the closing plug. In one or more embodiments described above, the method further comprises translating the closing seat, wherein the closing seat is coupled to a closing sleeve, wherein the closing sleeve is coupled to the closing seat through a plurality of radial closing pins, wherein the closing sleeve is configured to translate as the closing seat translates. In one or more embodiments described above, wherein the closing sleeve blocks the plurality of ports from the exterior surface of the mandrel after being translated by the closing seat. In one or more embodiments described above, the method further comprises performing a second stage cementing operation before disposing the closing plug into the wellbore. 
     Therefore, the present disclosure is 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 present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. While numerous changes may be made by those skilled in the art, such changes are encompassed within the spirit of the subject matter defined by the appended claims. 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 disclosure. In particular, every range of values (for example, “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 as referring to the power set (the set of all subsets) of the respective range of values. The terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee.