SYSTEM AND METHOD FOR USE OF A STAGE CEMENTING DIFFERENTIAL VALVE TOOL

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'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. 5A-5F 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. 6A-6G 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 102a and the second end 103 may be a threaded female connection 103a 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 102a and the threaded female connection 103a 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 102b of the first end 102 to a top shoulder 103b 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 101a and inner surface 101b. The outer surface 101a defines an outer diameter OD of the stage cementing differential valve tool 100 and the inner surface 101b 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 101a 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 101a. The sealing element 105 surrounds a circumference of the outer surface 101a. For example, the sealing element 105 may be a packer that swells outwardly from the outer surface 101a 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 105a filled with a fluid to start a swelling of the sealing element 105 when activated. The chamber 105a 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 105a 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 101b to the outer surface 101a to fluidly couple the bore 104 to an annulus between the outer surface 101a 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 101a above the sealing element 105. The external sleeve 107 extends radially outward from the outer surface 101a. For example, the external sleeve 107 may be worn over the outer surface 101a 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 101a. 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 101a 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 101a 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 101b 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 107a 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 101b 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 101b (i.e., the inner diameter of the tool). With the internal sleeve 108 flush against the inner surface 101b, 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 101b. 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 107a above the seal stack assembly 109. The leading edge 107a 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 107a 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 101b 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 101b. In the open position, the internal sleeve 108 shifts to open the opening of the one or more ports 106 on the inner surface 101b 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 101b above the internal sleeve 109. The shoulder 112 protrudes radially inward from the inner surface 101b 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 OD2 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 114a to a second end 114b. For example, the first end 114a is a bottom end with a width W1 that is less than a width W2 of the second end 114b 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 114b. 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 W1 and the width W2 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. 5A-5F and 6A-6G, 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. 5A-5F 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. 6A-6G 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. 5A, 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. 5A, 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. 5A, 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 105a 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. 5B, 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 101a 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. 5C, 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. 5D, 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. 5E, 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. 5F, 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. 6A-6G, 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. 6A-6G is similar to that of the embodiment of FIGS. 5A-5F. 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. 6A, 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. 6A, 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. 6B, 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 105a. This in turn will rupture the chamber 105a within the sealing element 105 either mechanically, hydraulically, or both. The chamber 105a will be located between the internal sleeve 108 and the one or more ports 106. In some embodiments, the chamber 105a may be located between the internal sleeve 108 and the one or more ports 106. Once ruptured, the chamber 105a will leak out a swell fluid to contact the sealing element 105 to trigger a swell action.

As shown in FIG. 6C, 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. 6C, 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. 6D, 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. 6E, 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. 6E, 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. 6G, 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. 2-6G. 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.

SYSTEM AND METHOD FOR USE OF A STAGE CEMENTING DIFFERENTIAL VALVE TOOL

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