Patent Publication Number: US-2023151711-A1

Title: System and method for use of a stage cementing differential valve tool

Description:
BACKGROUND 
     A completed well  1 , as illustrated in  FIG.  1   , includes a casing profile  2  within a wellbore  3  extending from a surface  4  into subterranean formations  5 . In general, there may be many layers of subterranean formations  5  below the surface  4 . The casing profile  2  includes multiple casing strings, such as a conductor casing  6 , a surface casing  7 , an intermediate casing  8 , and a production casing  9 . The conductor casing  6  may be a large-diameter casing that protects shallow formations from contamination by drilling fluid and helps prevent washouts involving unconsolidated topsoils and sediments. The surface casing  7 , the second string, has a smaller diameter than the conductor casing  6 , maintains borehole integrity and prevents contamination of shallow groundwater by hydrocarbons, subterranean brines and drilling fluids. The intermediate casing  8 , the third string, has a smaller diameter than the surface casing  7 , isolates hydrocarbon-bearing, abnormally pressured, fractured and lost circulation zones, providing well control as engineers drill deeper. Multiple strings of the intermediate casing  8  may be required to reach the target producing zone. The production casing  9 , or liner, is the last and smallest tubular element in the completed well  1 . The production casing  9  isolates the zones above and within the production zone and withstands all of the anticipated loads throughout the well&#39;s life. Additionally, the production casing  9  may be perforated  10  to allow hydrocarbons to flow into the production casing  9 . 
     Furthermore, each casing string  6 - 9  undergoes a cement operation. Typically, a well section is drilled; then a casing string (e.g., the conductor casing  6 , the surface casing  7 , the intermediate casing  8 , or the production casing  9 ) is lowered into the wellbore  3  and then cemented. In a cement operation, a slurry  11  of cement, cement additives and water is pumped into the wellbore  3  down through the casing string ( 6 - 9 ) and into an annulus around the casing string ( 6 - 9 ) or in the open hole below the casing string ( 6 - 9 ). In some cases, the cement slurry  11  is introduced into the annulus without pumping the cement slurry  11  around the bottom end of the casing string ( 6 - 9 ). To achieve this, a stage cementing tool, installed at various depths along the casing string ( 6 - 9 ), may be used to introduce the cement slurry  11  directly into the annulus along a length of the casing string ( 6 - 9 ). Cement slurry  11  supports and protects well casings and helps achieve zonal isolation while protecting the surrounding environment. However, conventional stage cementing tools may have poor cement displacement and zonal isolation leading to potential long term sustained casing pressure as well as an inability to fix annular pressure issues. 
     SUMMARY OF DISCLOSURE 
     This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. 
     In one aspect, embodiments disclosed herein relate to a stage cementing differential valve tool that includes a body extending from a first end to a second end. The body may include one or more ports that may be configured to circulate a cement slurry, an external sleeve may be slidably coupled to an outer surface to the body, and an internal sleeve assembly may be slidably coupled to an inner surface to the body. The external sleeve and the internal sleeve assembly may be configured to open and close the one or more ports. The stage cementing differential valve tool may also include a sealing element extending from the outer surface of the body that is configured to swell in a downhole fluid environment and a plug having shoulders with break-off points that is configured to actuate the internal sleeve assembly. 
     In another aspect, embodiments disclosed herein relate to a system that may include a tubular string within a wellbore, the tubular string includes a plurality of tubular joints joined end-to-end; a float shoe installed at a bottom end of the tubular string and configured to circulate a cement slurry during a first stage of cementing; and one or more stage cementing differential valve tools installed at various depths in the tubular string and configured to circulate the cement slurry during a second stage of cementing. The one or more stage cementing differential valve tools may include a body extending from a first end to a second end. The body may include one or more ports that are configured to circulate the cement slurry into an annulus between the tubular string and the wellbore; an external sleeve slidably coupled to an outer surface to the body; and an internal sleeve assembly slidably coupled to an inner surface to the body. The external sleeve and the internal sleeve assembly may be configured to open and close the one or more ports. The one or more stage cementing differential valve tools may also include a sealing element extending from the outer surface of the body that is configured to swell in a downhole fluid environment and seal against the wellbore; and a plug having shoulders with break-off points that is configured to actuate the internal sleeve assembly. 
     In yet another aspect, embodiments disclosed herein relate to a method that may include lowering a tubular string including one or more stage cementing differential valve tools into a wellbore; performing a first stage of cementing by circulate a cement slurry through a float shoe at a bottom end of the tubular string and into an annulus between the tubular string and the wellbore; dropping a first plug to isolate the float shoe and stop the first stage of cementing; and performing a second stage of cementing using the one or more stage cementing differential valve tools. The method may also include activating an internal sleeve and an external sleeve of the one or more stage cementing differential valve tools to an open position to fluid couple a bore of the one or more stage cementing differential valve tools to the annulus via one or more ports; and circulating a cement slurry through the one or more ports and into the annulus. The method may further include shearing a second plug and conducting further well operations. 
     Other aspects and advantages of the invention will be apparent from the following description and the appended claims. 
    
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
       The following is a brief description of the accompanying drawings. In the drawings, identical reference numbers identify similar elements or acts. The sizes and relative positions of elements in the drawings are not necessarily drawn to scale. For example, the shapes of various elements and angles are not necessarily drawn to scale, and some of these elements may be arbitrarily enlarged and positioned to improve drawing legibility. Further, shapes of the elements as drawn are not necessarily intended to convey any information regarding the actual shape of the elements and have been solely selected for ease of recognition in the drawing. 
         FIG.  1    is a schematic diagram of a completion well system in accordance with prior art. 
         FIG.  2    illustrates a cross-sectional view of a stage cementing differential valve according to one or more embodiments of the present disclosure. 
         FIG.  3    illustrates a cross-sectional view of a first plug according to one or more embodiments of the present disclosure. 
         FIG.  4    illustrates a cross-sectional view of a second plug according to one or more embodiments of the present disclosure. 
         FIGS.  5 A- 5 F  illustrated a cross-sectional view of a system using the stage cementing differential valve tool as described in  FIG.  2    to conduct a multi-stage cementing operations according to one or more embodiments of the present disclosure. 
         FIGS.  6 A- 6 G  illustrated a cross-sectional view of a system using the stage cementing differential valve tool as described in  FIG.  2    to conduct a multi-stage cementing operations according to one or more embodiments of the present disclosure. 
         FIG.  7    illustrates a flowchart for utilization of the stage cementing differential valve tool as described in  FIG.  2    according to one or more embodiments of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     Embodiments of the present disclosure are described below in detail with reference to the accompanying figures. However, one skilled in the relevant art will recognize that implementations and embodiments may be practiced without one or more of these specific details, or with other methods, components, materials, and so forth. For the sake of continuity, and in the interest of conciseness, same or similar reference characters may be used for same or similar objects in multiple figures. As used herein, the term “coupled” or “coupled to” or “connected” or “connected to” “attached” or “attached to” may indicate establishing either a direct or indirect connection, and is not limited to either unless expressly referenced as such. 
     Embodiments disclosed herein are described with terms designating orientation in reference to a vertical wellbore, but any terms designating orientation should not be deemed to limit the scope of the disclosure. For example, embodiments of the disclosure may be made with reference to a horizontal wellbore. It is to be further understood that the various embodiments described herein may be used in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in other environments, such as land or sub-sea, without departing from the scope of the present disclosure. It is to be further understood that the various embodiments described herein may be used in various stages of a well (land and/or offshore), such as rig site preparation, drilling, completion, abandonment etc., and in other environments, such as work-over rigs, fracking installation, well-testing installation, oil and gas production installation, without departing from the scope of the present disclosure. The embodiments are described merely as examples of useful applications, which are not limited to any specific details of the embodiments herein. 
     Additionally, embodiments disclosed herein are described with terms designating in reference to a tubular, but any terms designating should not be deemed to limit the scope of the disclosure. For example, a tubular string is made up of numerous tubular pipes joined end-to-end, and each of the tubular pipes might be about twenty to forty feet in length. Further, the tubular pipes are hollow and thus provide a continuous channel of communication between the surface and the bottom of the wellbore, down through which a suitable fluid can be introduced to any region required within the well. It is to be further understood that the various embodiments described herein may be used with various types of tubulars, including but not limited to casing or liners, without departing from the scope of the present disclosure. A casing generally refers to a large-diameter pipe that is lowered into an openhole and cemented in place. 
     Further, embodiments disclosed herein are described with terms designating in reference to a cement operation, but any terms designating should not be deemed to limit the scope of the disclosure. Cement operations may be conducted to cement the tubular string within a wellbore. For example, a cement operation may refer to an operation of pumping a cement slurry downhole to cement the tubular string to a wellbore. As used herein, cement slurry may refer to a fluid made from a mixture of cement, cement additives and water. Additionally, cement operations may include various stages of cementing. For example, a first stage of cementing may refer to an initial pumping stage where the cement slurry is pumped down into a bore of the tubular string; next the cement slurry exits at a bottom of the tubular string and into an annulus between the tubular string and the wellbore; then the cement slurry flows upward on an outer surface of the tubular string to fill the annulus to a required depth; and lastly, the cement slurry is settled to cement the tubular string within the wellbore. A second stage of cementing may refer to a stage where the cement slurry is pumped down into the bore of the tubular string and into the annulus, via a stage cementing differential valve tool, without having to exit the bottom of the tubular string. While only a first and second stage of cementing are described, any number of stages of cementing may be used without departing the scope of the disclosure. 
     In one or more embodiments, the present disclosure may be directed to systems and methods for using a stage cementing differential valve tool for cementing operations within a wellbore, either having tubulars or open hole. More specifically, embodiments disclosed herein are directed to a stage cementing differential valve tool having an external sleeve and an internal sleeve assembly slidably opening and closing one or more ports to circulate a cement slurry. Additionally, a plug of the stage cementing differential valve tool may be used to actuate the internal sleeve assembly by having shoulders of the plug include break-off points to shear on the internal sleeve assembly. Further, the stage cementing differential valve tool may also include a sealing element to seal against a wellbore. In some embodiments, the stage cementing differential valve tool is installed at predetermined depths as a tubular string is deployed in the wellbore. Overall, the stage cementing differential valve tool as described herein may reduce product engineering efforts, reduction of assembly time, reduce hardware cost, and reduce weight and envelope. The one or more embodiments of a method of using the stage cementing differential valve tool results in improved cement slurry displacement and circulation within an annulus, minimized cement slurry loss in the wellbore, reduced casing pressure, and reduction in operational costs associated with conventional cementing operations. 
     As shown in  FIG.  2   , in one or embodiments, a stage cementing differential valve tool  100  includes a body  101  that extends from a first end  102  to a second end  103 . Both the first end  102  and the second end  103  are connection ends to couple the stage cementing differential valve tool  100  to a tubular. For example, the first end  102  may be a threaded male connection  102   a  and the second end  103  may be a threaded female connection  103   a  such that the stage cementing differential valve tool  100  may be threadedly-coupled to tubulars at both the first end  102  and the second end  103 . The threaded male connection  102   a  and the threaded female connection  103   a  may have any suitable type of threads to allow for a connection to the tubular string at any depth or type of tubular string (e.g., the conductor casing, the surface casing, the intermediate casing, or the production casing). Further, a length L of the body  101  may be measured from a bottom shoulder  102   b  of the first end  102  to a top shoulder  103   b  of the second end  103 . The length L may be 10 to 20 feet. It is further envisioned that the body  101  may have a same burst, collapse, and tri-axial rating as the tubular string at which the stage cementing differential valve tool  100  is installed at. 
     In one or more embodiments, the body  101  includes an outer surface  101   a  and inner surface  101   b . The outer surface  101   a  defines an outer diameter OD of the stage cementing differential valve tool  100  and the inner surface  101   b  defines a bore  104  having an inner diameter ID of the stage cementing differential valve tool  100 . The cement slurry flows through the bore  104  and the outer surface  101   a  faces a wellbore. The difference between the outer diameter OD and the inner diameter ID is a thickness T of the stage cementing differential valve tool  100  and corresponds to an adjacent tubular in the tubular string. 
     Still referring to  FIG.  2   , the stage cementing differential valve tool  100  includes a sealing element  105  radially extending from the outer surface  101   a . The sealing element  105  surrounds a circumference of the outer surface  101   a . For example, the sealing element  105  may be a packer that swells outwardly from the outer surface  101   a  to seal against the wellbore to stop the cement slurry from flowing in an annulus below or above the stage cementing differential valve tool  100  based on a particular stage of cementing operations. In some embodiments, the sealing element  105  may have an in-situ mechanism consisting of a chamber  105   a  filled with a fluid to start a swelling of the sealing element  105  when activated. The chamber  105   a  may be activated by being ruptured to expose the sealing element  105  to the fluid to start the swelling of the sealing element  105 . The rupturing of the chamber  105   a  containing the fluid may be activated by a plug that is dropped, or by a hydraulic action, or by a combination thereof. It is further envisioned that the sealing element  105  may also be swelled by wellbore fluids (e.g., oil or water) once exposed to the wellbore fluids. In such a case, a delayed swelling mechanism (of a minimum defined interval) may be used to activate the swelling of the sealing element  105 . The sealing element  105 , once swelled and sealed against the wellbore, may withstand a range of differential pressures (e.g. 2,000 psi, 5,000 psi, 10,000 psi etc.) depending on a depth at which the stage cementing differential valve tool  100  is to be set downhole. 
     In one or more embodiments, one or more ports  106  are circumferentially provided around the body  101  above the sealing element  105 . The one or more ports  106  are openings that extend from the inner surface  101   b  to the outer surface  101   a  to fluidly couple the bore  104  to an annulus between the outer surface  101   a  and the wellbore. By fluidly coupling the bore  104  to the annulus, a cement slurry can flow from the bore  104  through the one or more ports  106  and into the annulus. The one or more ports  106  may have a shape and size (e.g., diamond, oval, circular, star, etc.), that has a flow area equal to or greater than a flow area of a conventional float shoe. 
     Still referring to  FIG.  2   , in one or more embodiments, an external sleeve  107  is slidably coupled to the outer surface  101   a  above the sealing element  105 . The external sleeve  107  extends radially outward from the outer surface  101   a . For example, the external sleeve  107  may be worn over the outer surface  101   a  in a no-go configuration that may limit an axially movement of the external sleeve  107  between slight raised shoulders above and below the external sleeve  107 . 
     As shown in  FIG.  2   , when the stage cementing differential valve tool  100  is deployed downhole, the external sleeve  107  will be in a closed position. In the closed position, the external sleeve  107  covers the one or more ports  106  to fluidly separate the bore  104  from the annulus. For example, the external sleeve  107  covers the opening of the one or more ports  106  on the outer surface  101   a . It is further envisioned that a system of seal stacks or metal-to-metal seal may be provided between the external sleeve  107  and the outer surface  101   a  to prevent leaks when the external sleeve  107  is in the closed position. Upon activation, the external sleeve  107  will shift to an open position. Activation of the external sleeve  107  can only occur after the sealing element  105  has sealed against the wellbore. In the open position, the external sleeve  107  will move downward to no longer  107  cover the opening of the one or more ports  106  on the outer surface  101   a  and fluidly couple the bore  104  to the annulus. 
     In one or more embodiments, the stage cementing differential valve tool  100  includes an internal sleeve  108  slidably coupled to the inner surface  101   b  above the sealing element  105 . For example, a top and bottom of the internal sleeve  108  has a no-go configuration to delimit an axial movement of the internal sleeve  108 . The top of the internal sleeve  108  may be a leading edge  107   a  capable of shearing any debris above the internal sleeve  108 . The bottom of the internal sleeve  108  may be a latch-ratchet system  110  coupled to a helical spring system (i.e., spring  111 ) below to provide a required recoil energy to close the internal sleeve  108 . The internal sleeve  108  is able to be move or be slidably displaced within the axial movement interval defined by the no-go configuration. The internal sleeve  108  is flush against the inner surface  101   b  to form an effective inner diameter eID (i.e., tubular drift ID) which is equal to an inner diameter of the adjacent tubulars of the corresponding tubular string. For example, the internal sleeve  108  may be telescopic with rotational capabilities in a floating arrangement flush against the inner surface  101   b  (i.e., the inner diameter of the tool). With the internal sleeve  108  flush against the inner surface  101   b , there is no loss of tubular inner diameter in the corresponding tubular string. 
     Additionally, a seal stack assembly  109  may be provided at an upper end of the internal sleeve  108  to seal the internal sleeve  108  to the inner surface  101   b . The seal stack assembly  109  includes a plurality of seals, such as metal-to-metal seals, stacked on top of each other and spaced apart from each other. Further, the internal sleeve  108  is designed with the leading edge  107   a  above the seal stack assembly  109 . The leading edge  107   a  can shear any debris above the internal sleeve  108  when moving from the closed position to the open position. The shearing force of the leading edge  107   a  may be derived from a potential energy of a spring  111  below the internal sleeve  108 . It is further envisioned that an interface between the internal sleeve  108  and the inner surface  101   b  may be bronze or copper plating or galvanizing to avoid corrosion and erosion. 
     As shown by  FIG.  2   , in one or more embodiments, a latch-ratchet system  110  couples the internal sleeve  108  to the spring  111  below the internal sleeve  108 . The latch-ratchet system  110  may activate the internal sleeve  108  by having a force applied to the top of the internal sleeve  108  to expose or retract the internal sleeve  108 . For example, a surface force is provided by an applied pressure of a certain magnitude (e.g. 2,000 psi-5,000 psi) to activate the internal sleeve  108  via the latch-ratchet system  110 . The spring  111  may be a helical spring  111 . The spring  111  aids in moving the internal sleeve  108  from a closed position to an open position or vice versa. In the closed position, the internal sleeve  108  covers the opening of the one or more ports  106  on the inner surface  101   b . In the open position, the internal sleeve  108  shifts to open the opening of the one or more ports  106  on the inner surface  101   b  to fluidly couple the bore  104  to an annulus. It is further envisioned that the internal sleeve  108  may be telescopic to have multiple sections designed to slide into one another or non-telescopic to have a fixed length. 
     In some embodiments, a shoulder  112  is provided on the inner surface  101   b  above the internal sleeve  109 . The shoulder  112  protrudes radially inward from the inner surface  101   b  such that a top surface of the shoulder  112  may be a landing surface for a plug (see  FIG.  4   ). Additionally, the shoulder  112  may be used as an anti-rotation device with in-built pawls to prevent the plug (see  FIG.  4   ) from spinning or rotating once it is dropped/pumped into place. 
     Now referring to  FIG.  3   , in one or more embodiments, an example first plug  113  is illustrated. The first plug  113  may be a shut-off plug for use after a first stage of cementing is completed. The first plug  113  has an outer diameter OD 2  that is less than the effective inner diameter (see eID in  FIG.  2   ) of the stage cementing differential valve tool (see  100  in  FIG.  2   ). This allows the first plug  113  to travel/traverse through the stage cementing differential valve tool (see  100  in  FIG.  2   ) and land in a float shoe or collar to end the first stage of cementing. 
     Now referring to  FIG.  4   , in one or more embodiments, an example second plug  114  is illustrated. The second plug  114  is used to activate the external sleeve (see  107  in  FIG.  2   ) and the internal sleeve (see  109  in  FIG.  2   ) of the stage cementing differential valve tool (see  100  in  FIG.  2   ). The second plug  114  may have an outer surface  115  that is tapered from a first end  114   a  to a second end  114   b . For example, the first end  114   a  is a bottom end with a width W 1  that is less than a width W 2  of the second end  114   b  that is a top end. In one or more embodiments, the second plug  114  may be provided with a shoulder  116  at the second end  114   b . The shoulder  116  includes one or more break off points  117  to land on the shoulder of the inner surface of the tool body  101  (see  112  in  FIG.  2   ) and that shears under an applied weight, such as weight applied by a drill bit. Both the width W 1  and the width W 2  may be less than the effective inner diameter (see eID in  FIG.  2   ) of the stage cementing differential valve tool (see  100  in  FIG.  2   ) to allow for the second plug  114  to freely pass across the internal sleeve (see  109  in  FIG.  2   ) once the one or more break off points  117  are sheared. This avoids the need for any drilling operation in a corresponding cement stage that would cause damage to the internal sleeve (see  109  in  FIG.  2   ) and compromise the internal sleeve (see  109  in  FIG.  2   ) integrity. The second plug  114  may be made out of a brittle composite material such that the one or more break off points  117  may shear and the second plug  114  can be shattered by weight applied from a bottom hole assembly (BHA). 
     In reference to  FIGS.  5 A- 5 F and  6 A- 6 G , in one or more embodiments, examples of the stage cementing differential valve tool  100  as described in  FIG.  2    being used to conduct multi-stage cementing operations are illustrated. For example, the stage cementing differential valve tool  100  aids in conducting a first stage of cementing (i.e., the cement slurry entering a annulus through a bottom end of a tubular string) and a second stage of cementing (i.e., the cement slurry entering the annulus through the stage cementing differential valve tool  100 ).  FIGS.  5 A- 5 F  illustrate one embodiment where the stage cementing differential valve tool  100  is deployed downhole with the internal sleeve  108  in the open position while  FIGS.  6 A- 6 G  illustrate another embodiment where the stage cementing differential valve tool  100  is deployed downhole with the internal sleeve  108  in the closed position. 
     Turning to  FIG.  5 A , a tubular string  500  (e.g., the conductor casing, the surface casing, the intermediate casing, or the production casing) is lowered into a wellbore  501  from a surface  509 . The tubular string  500  includes a various tubulars  502  connected end to end. One or more stage cementing differential valve tools  100 , as described in  FIG.  2   , may be installed between at various depths between the various tubulars  502 . 
     As shown in  FIG.  5 A , the internal sleeve  108  of the stage cementing differential valve tool  100  will be in the open position when being run in hole. For example, the latch-ratchet system  110  is activated at surface to move the internal sleeve  108  into the open position by moving the telescoping components of the internal sleeve  108  within each other. Additionally, the external sleeve  107  will initially be in the closed position. 
     At a lower most end  503  of the tubular string  500 , a float shoe or collar  504  is provided. A check valve  505  in the float shoe  504  prevents reverse flow of the cement slurry from a lower annulus  506  into the tubular string  500  or a flow of wellbore fluids into the tubular string  500  as the tubular string  500  is run into the wellbore  501 . The float shoe  504  may also provide a guide to keep the tubular string  500  centered in the wellbore  501  to minimize hitting rock ledges or washouts. 
     Still referring to  FIG.  5 A , in a first step, the sealing element  105  is swelled to seal against the wellbore  501  such that a first stage of cementing may be conducted. For example, the chamber  105   a  may be ruptured to expose the sealing element  105  to the fluid to start the swelling of the sealing element  105 . The sealing element  105  will swell and expand radially outward from the stage cementing differential valve tool  100  to seal against the wellbore  501 . 
     In the first stage of cementing, with the sealing element  105  sealed against the wellbore, the cement slurry is pumped down (see block arrows) the tubular string  500  to flow through the various tubulars  502  and the stage cementing differential valve tool  100  and exit the float shoe  504 . After exiting the float shoe  504 , the cement slurry flow upwards (see curved block arrows) into the lower annulus  506  below the sealing element  105 . In this step, the cement slurry will cement the tubular string  500  below the sealing element  105 . 
     Now referring to  FIG.  5 B , after the first stage of cementing is completed, the first plug  113  as described in  FIG.  3    is deployed downhole to land in the float shoe  504 . The first plug  113  isolates the float shoe  504  and plugs the lower most end  503  of the tubular string  500 . At the surface  509 , pressure is bled off to check and confirm that the float shoe  504  is holding pressure to not allow the cement slurry to pass through. 
     In one or more embodiments, with the plug  113  deployed and the float shoe  504  holding pressure, an annular blowout preventer  510  at the surface is closed. Once the annular blowout preventer  510  is closed, pressure is applied in an upper annulus  507  above the sealing element  105  via side-outlet valves (now shown) of the annular blowout preventer  510 . The pressure in the upper annulus  507  builds up to activate the external sleeve  107  of the stage cementing differential valve tool  100  from the close position to the open position. For example, a pressure between 2000 to 5000 psi may be used to activate the external sleeve  107 . It is further envisioned that a slight raised shoulder of the outer surface  101   a  may delimit a downward movement of the external sleeve  107  after being moved to the open position. To determine if the external sleeve  107  is the open position, surface readings will indicate an ability to circulate fluids without pumping such that a flow path has been exposed via the one or more ports  106 . 
     Now referring to  FIG.  5 C , with the external sleeve  107  and the internal sleeve  108  in the open position, the annular blowout preventer  510  is opened and the cement slurry  508  is pumped into the tubular string  500  to perform a second stage of cementing. For example, the cement slurry  508  travel through the bore  104  of the stage cementing differential valve tool  100  and flows out through (see curved block arrows) the one or more ports  106  of the stage cementing differential valve tool  100 . From the one or more ports  106 , the cement slurry  508  enters the upper annulus  507  to cement the various tubulars  502  above the sealing element  105 . 
     In the next step, as shown by  FIG.  5 D , with the annular blowout preventer  510  opened, the second plug  114  is deployed as described in  FIG.  4   . The shoulder  116  of the second plug  114  lands the shoulder  112  of the stage cementing differential valve tool  100 . After the second plug  114  engages in the shoulder  112  of the stage cementing differential valve tool  100 , a slight pressure spike will be observed at the surface  509 . Once the slight pressure spike is observed, the annular blowout preventer  510  is closed to increase the pressure on the internal sleeve  109 . 
     Now referring to  FIG.  5 E , in the next step, the increased pressure actives the latch-ratchet system  110  such that the spring  111  in a compressed state beneath the internal sleeve  108  will cause the internal sleeve  108  to move upward into the close position. For example, the telescoping components of the internal sleeve  108  may extend out from each other. To confirm that the internal sleeve  108  has moved to the close position and sealed the one or more ports  106 , the annular blowout preventer  510  will be opened. After opening the annular blowout preventer  510 , fluids will be attempted to circulate. If return fluids are observed from the upper annulus  507 , the one or more ports  106  are not fully closed. If the one or more ports  106  are not fully closed, a remedial cement operation is conducted. In the remedial cement operation, the one or more break off points  117  of the second plug  114  remains intact after the second plug  114  has been dislodged or shear-off. The second plug  114  is dropped and re-landed on the shoulder  112  to repeat the steps of increasing pressure to active the spring  111  to move the internal sleeve  108  to the closed position. However, if no return fluids are observed from the upper annulus  507 , and there is a sharp pressure increase when circulation is attempted, the one or more ports  106  are confirmed as fully closed by the internal sleeve  108  and the second stage of cementing is completed. 
     As shown in  FIG.  5 F , after completing the second stage of cementing, a bottom hole assembly  511  attached to a drill string  512  is run downhole through the tubular string  500 . A drill bit  513  attached at lowest most point to the bottom hole assembly  511  applies pressure on the second plug  114  to shear off the one or more break off points  117  off the shoulder  116 . After shearing, the second plug  114  will fall further down in the stage cementing differential valve tool  100  and the drill bit  513  may drill through the second plug  114 . 
     Referring now to  FIGS.  6 A- 6 G , another embodiment of a system using the stage cementing differential valve tool  100  as described in  FIG.  2    to conduct a multi-stage cementing operations according to embodiments herein is illustrated, where like numerals represent like parts. The embodiment of  FIGS.  6 A- 6 G  is similar to that of the embodiment of  FIGS.  5 A- 5 F . However, instead of the internal sleeve  108  being in the open position when the stage cementing differential valve tool  100  is run in hole, the internal sleeve  108  in the closed position. For example, as shown in  FIG.  6 A , in the first step, the telescoping components of the internal sleeve  108  are extended out of each other to cover the one or more ports  106 . 
     In  FIG.  6 A , in the first step, the sealing element  105  is swelled to seal against the wellbore such that a first stage of cementing may be conducted. In the first stage of cementing with both the external sleeve  107  and the internal sleeve  108  in the closed position, the cement slurry is pumped down (see block arrows) the tubular string  500  to flow through the various tubulars  502  and the stage cementing differential valve tool  100  and exit the float shoe  504 . After exiting the float shoe  504 , the cement slurry flow upwards (see curved block arrows) into the lower annulus  506  below the sealing element  105 . In this step, the cement slurry will cement the tubular string  500  below the sealing element  105 . 
     Now referring to  FIG.  6 B , after the first stage of cementing is completed, the first plug  113  as described in  FIG.  3    is deployed downhole to land in the float shoe  504 . The first plug  113  isolates the float shoe  504  and plugs the lower most end  503  of the tubular string  500 . At the surface  509 , pressure is bled off to check and confirm that the float shoe  504  is holding pressure to not allow the cement slurry to pass through. 
     In one or more embodiments, with the annular blowout preventer  510  opened, the second plug  114  is deployed as described in  FIG.  4   . The shoulder  116  of the second plug  114  lands the shoulder  112  of the stage cementing differential valve tool  100 . Once the second plug  114  is engaged with the shoulder  116 , one or more pump strokes from a rig or cement unit pump at the surface result in a pressure increase observed at the surface  509 . A further increase of the pressure to a pre-determined value will initiate an anti-rotational lock-ratchet system. The anti-rotational lock-ratchet system may be a hollow rotation disc or shaft that is integrated with pawls of the shoulder  112 . Additionally, the anti-rotational lock-ratchet system may be linked to the chamber  105   a . This in turn will rupture the chamber  105   a  within the sealing element  105  either mechanically, hydraulically, or both. The chamber  105   a  will be located between the internal sleeve  108  and the one or more ports  106 . In some embodiments, the chamber  105   a  may be located between the internal sleeve  108  and the one or more ports  106 . Once ruptured, the chamber  105   a  will leak out a swell fluid to contact the sealing element  105  to trigger a swell action. 
     As shown in  FIG.  6 C , the sealing element  105  swells against the wellbore  501 . The swell fluid may be designed to have a heavier density than the surrounding fluid such that the swell fluid is able to self-gravitate downwards and circumferentially to the sealing element  105 . Typically, this process will be activated after the completion of the first or preceding stage cementing operation. The sealing element  105  will only need a fraction of the swell fluid in its immediate environment to trigger the swelling action. In operation, a waiting time of 30 to 90 minutes is needed to allow the sealing element  105  swell and can be customized on a case-by-case basis. 
     Still referring to  FIG.  6 C , in one or more embodiments, the swell packer waiting time is complete, a further increase in pressure to a higher pre-determined value will activate the latch-ratchet system  110  to move the internal sleeve  108  in the downward direction to the open position to compress the spring  111  and expose the one or more ports  106 . Additionally, with the one or more ports  106  exposed, any remaining swell fluid may be expunged into the upper annulus  508 , and onto the sealing element  105 . The internal sleeve  108  may be maintained or locked in the open position by the latch-ratchet system  110 , similar to a ball pen system. 
     Now referring to  FIG.  6 D , with the external sleeve  107  and the internal sleeve  108  in the open position, the annular blowout preventer  510  is opened and the cement slurry  508  is pumped into the tubular string  500  to perform a second stage of cementing. For example, the cement slurry  508  travel through the bore  104  of the stage cementing differential valve tool  100  and flows out through (see curved block arrows) the one or more ports  106  of the stage cementing differential valve tool  100 . From the one or more ports  106 , the cement slurry  508  enters the upper annulus  507  to cement the various tubulars  502  above the sealing element  105 . 
     In the next step, as shown by  FIG.  6 E , upon completion of the second stage of cementing, and confirmation of pure or contaminated cement at surface  509  as per the displacement schedule, the annular blowout preventers  510  will be closed. Pressure will then be increased to a pre-determined value via a cement unit pump at the surface  509 . 
     As shown by  FIG.  6 E , in the next step, the increased pressure actives the latch-ratchet system  110  to release the internal sleeve  108  from the locking mechanism. With the internal sleeve  108  released from the locking mechanism, a potential energy stored in the compressed spring  111  (located below the internal sleeve  108 ) will shift the internal sleeve  108  upward to the close position to cover the one or more ports  106 . For example, the telescoping components of the internal sleeve  108  may extend out from each other. To confirm that the internal sleeve  108  has moved to the close position and sealed the one or more ports  106 , the annular blowout preventer  510  will be opened. After opening the annular blowout preventer  510 , fluids will be attempted to circulate. If return fluids are observed from the upper annulus  507 , the one or more ports  106  are not fully closed. If the one or more ports  106  are not fully closed, a remedial cement operation is conducted. In the remedial cement operation, the one or more break off points  117  of the second plug  114  remains intact after the second plug  114  has been dislodged or shear-off. The second plug  114  is dropped and re-landed on the shoulder  112  to repeat the steps of increasing pressure to active the spring  111  to move the internal sleeve  108  to the closed position. However, if no return fluids are observed from the upper annulus  507 , and there is a sharp pressure increase when circulation is attempted, the one or more ports  106  are confirmed as fully closed by the internal sleeve  108  and the second stage of cementing is completed. 
     As shown in  FIG.  6 G , after completing the second stage of cementing, a bottom hole assembly  511  attached to a drill string  512  is run downhole through the tubular string  500 . A drill bit  513  attached at lowest most point to the bottom hole assembly  511  applies pressure on the second plug  114  to shear off the one or more break off points  117  off the shoulder  116 . After shearing, the second plug  114  will fall further down in the stage cementing differential valve tool  100  and the drill bit  513  may drill through the second plug  114 . 
     Referring to  FIG.  7    illustrates a flowchart for utilization of the stage cementing differential valve tool  100  to conduct a multi-stage cementing operations. One or more steps in  FIG.  7    may be performed by one or more components (for example, the computing system coupled to a controller in communication with the stage cementing differential valve tool  100 ) as described in  FIGS.  2 - 6 G . For example, a non-transitory computer readable medium may store instructions on a memory coupled to a processor such that the instructions include functionality for operating the stage cementing differential valve tool  100 . 
     In step  700 , the tubular string including the one or more stage cementing differential valve tools is lowered into the wellbore. The one or more stage cementing differential valve tools is installed at pre-determined depths as the tubular string is being run in hole. In one or more embodiments, the internal sleeve of the one or more stage cementing differential valve tools may be actuated at the surface such that the internal sleeve is in the open position while being run in hole. In the open position, the internal sleeve moves downward and compresses the spring to expose the opening of the one or more ports on the inner surface of the body of the one or more stage cementing differential valve tools. The outer sleeve of the one or more stage cementing differential valve tools is in the close position while being run in hole. In the closed position, the outer sleeve covers the opening of the one or more ports on the outer surface of the body of the one or more stage cementing differential valve tools. In another embodiment, both the internal sleeve and the outer sleeve of the one or more stage cementing differential valve tools may be in closed position while being run in hole. 
     In step  701 , with the tubular string in the wellbore, the first stage of cementing is performed. For example, the cement slurry is pumped down through the tubular string and is circulated to the annulus between the tubular string and the wellbore via the float shoe at the bottom of the tubular string. 
     In step  702 , a first plug is dropped down the tubular string to land within and isolate the float shoe to complete the first stage of cementing. The outer diameter of the first plug is less than the effective inner diameter of the one or more stage cementing differential valve tools to allow the first plug to travel through the one or more stage cementing differential valve tools without resistance and shut off the float shoe. The first plug is bumped and bleed off the check valve such the float shoe holds pressure. 
     In step  703 , with the first stage of cementing completed, the second stage of cementing is performed using the one or more stage cementing differential valve tools. 
     In one or more embodiments, to start the second stage of cementing, the sealing element expands radially outward to seal against the wellbore. For example, the chamber is ruptured to leak a swell fluid to onto the sealing element to swell the sealing element. Additionally, the annular blowout preventer is closed to apply pressure in the annulus via side-outlet valves. This increased pressure activates the external sleeve to move downward from the close position to the open position. In the open position, the opening of the one or more ports on the outer surface are exposed. Additionally, with the external sleeve in the open position and if the internal sleeve was run in hole in the open position, the one or more ports fluidly coupled the bore of the one or more stage cementing differential valve tools to the annulus above the sealing element. 
     In another embodiments, if both the internal sleeve and the external sleeve are in the close position when the one or more stage cementing differential valve tools is run in hole, to start the second stage of cementing, the second plug is deployed to land on the shoulder on the inner surface. Once the second plug is landed, a pressure is increased to initiate an anti-rotational lock-ratchet system to rupture the chamber to leak a swell fluid to onto the sealing element to swell the sealing element. After swelling the sealing element, a further increase in pressure to a higher pre-determined value will activate the latch-ratchet system to move the internal sleeve in the downward direction to the open position and compress the spring below the internal sleeve. In the open position, the internal sleeve exposes the opening of the one or more ports on the inner surface. Additionally, the annular blowout preventer is closed to apply pressure in the annulus to activate the external sleeve to move downward from the close position to the open position. With the one or more ports exposed on both the inner surface and outer surface, any remnant fast-swell fluid to be expunged via into the annulus, and onto the sealing element. 
     In step  704 , the cement slurry is pumped down into the bore of the one or more stage cementing differential valve tools and through the one or more ports to enter to the annulus above the sealing element. The cement slurry may be pumped for a pre-determined time to cement the tubular string above the sealing element. 
     In step  705 , upon the completion of the second stage of cementing, the internal sleeve is moved to the closed position to close the one or more ports. 
     In one or more embodiments, to move the internal sleeve to the closed position, the second plug may be deployed to land on the shoulder. After the second plug lands on the shoulder, a slight pressure spike will be observed. Additionally, the annular blowout preventer is then closed to further increase the pressure to a pre-determined value that will activate the anti-rotational lock-ratchet mechanism. With the increased pressure, the latch-ratchet system releases the internal sleeve so that a potential energy of the compressed spring moves the internal sleeve upward to the close position. 
     In another embodiments, to move the internal sleeve to the closed position with the second plug already deployed, the annular blowout preventers may be closed. Pressure will then be increased to a pre-determined value via the cement unit pump. This pressure increase will activate the latch-ratchet system to release the internal sleeve from the lock mechanism. With the internal sleeve released from the lock mechanism, the potential energy stored in the compressed springs (located below the internal sliding sleeve) will shift the internal sliding sleeve upward to the close position. 
     In step  706 , the internal sleeve is confirmed to be in the close position to seal the one or more ports. To confirm the internal sleeve is the close position, the annular blowout preventer is opened, and fluids are attempted to be circulated through the one or more ports. If no fluid returns are observed from the annulus, and there is a sharp pressure increase when circulation is attempted, it is confirmed the one or more ports are fully closed as designed by the internal sleeve being in the close position and the method moves to step  707 . In step  707 , the second plug is sheared to clear the bore and allow for further well operations to be conducted. However, if fluid returns are observed from the annulus, this implies that the one or more ports are not fully closed, and thus, the internal sleeve is not in the close position. If the one or more ports are not fully closed, the method moves to step  708 . 
     In step  708 , remedial cement operations are conducted to fully close the one or more ports. For example, the second plug is landing above the internal sleeve on the shoulder. Next, a pressure may be increased above the internal sleeve increasing pump strokes to further active the latch-ratchet system and push the internal sleeve upward. From step  708 , the method may restart at step  706  until the internal sleeve in the closed position for the method to reach step  707 . 
     In addition to the benefits described, the stage cementing differential valve tool disclosed herein may improve an overall efficiency and performance of cementing operation in a wellbore while reducing cost. Additionally, the stage cementing differential valve tool may have improved flow in circulation or displacement ports to ensure better fluids (e.g., cement slurry) displacement efficiency, uniform and circumferential cement placement in an annulus, and perform remedial cement squeeze operations with ease. Further, the stage cementing differential valve tool may provide further advantages such as reducing the possibility of sustained casing pressure based on a combination of better slurry placement and effect of the well packers in forming a barrier to flow as well as reducing the risk associated with partial closure of the differential valve collar post stage cementing. 
     While the method and apparatus have been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope as disclosed. Accordingly, the scope should be limited only by the attached claims.