CROSS-REFERENCE TO RELATED APPLICATION

[0001] This application claims priority to U.S. Application Serial No. 17/859,539, filed on July 7, 2022, entitled “SHIFTING SLEEVE OPERATED WITH PLUG AGAINST TWO OR MORE PLUG SEATS,” commonly assigned with this application and incorporated herein by reference in its entirety.

BACKGROUND

[0002] During well completion, it is common to introduce a cement composition into an annulus in a wellbore. For example, in a cased-hole wellbore, a cement composition can be placed into and allowed to set in the annulus between the wellbore and the casing in order to stabilize and secure the casing in the wellbore. By cementing the casing in the wellbore, fluids are prevented from flowing into the annulus. Consequently, oil or gas can be produced in a controlled manner by directing the flow of oil or gas through the casing and into the wellhead. Cement compositions can also be used in primary or secondary cementing operations, well-plugging, or squeeze cementing.

BRIEF DESCRIPTION

[0003] Reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:

[0004] FIGs. 1 and 2 illustrate a downhole tool designed, manufactured and/or operated according to one or more embodiments of the disclosure being positioned within a well system;

[0005] FIGs. 3A through 31 illustrate various different views of an inner sleeve designed, manufactured and/or operated according to one or more embodiments of the disclosure; and [0006] FIGs. 4A through 4D illustrate a set of cross-sectional drawings illustrating various different operational states for a downhole tool designed, manufactured and/or operated according to one or more embodiments of the disclosure.

DETAILED DESCRIPTION

[0007] In the drawings and descriptions that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals, respectively. The drawn figures are not necessarily to scale. Certain features of the disclosure may be shown exaggerated in scale or in somewhat schematic form and some details of certain elements may not be shown in the interest of clarity and conciseness. The present disclosure may be implemented in embodiments of different forms.

[0008] Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the disclosure, and is not intended to limit the disclosure to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed herein may be employed separately or in any suitable combination to produce desired results.

[0009] Unless otherwise specified, use of the terms “connect,” “engage,” “couple,” “attach,” or any other like term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described.

[0010] Unless otherwise specified, use of the terms “up,” “upper,” “upward,” “uphole,” “upstream,” or other like terms shall be construed as generally away from the bottom, terminal end of a well, regardless of the wellbore orientation.; likewise, use of the terms “down,” “lower,” “downward,” “downhole,” or other like terms shall be construed as generally toward the bottom, terminal end of a well, regardless of the wellbore orientation. Use of any one or more of the foregoing terms shall not be construed as denoting positions along a perfectly vertical axis. Unless otherwise specified, use of the term “subterranean formation” shall be construed as encompassing both areas below exposed earth and areas below earth covered by water such as ocean or fresh water. room The present disclosure recognizes that traditional cement operations have inherent drawbacks. The present disclosure further recognizes that reverse cementing operations were developed to overcome some of the disadvantages to traditional cement operations. For example, in traditional cementing operations, the setting time of the cement composition is longer in order for the cement slurry to travel through the casing or an inner tubing string and back up into the annulus before setting. Additionally, the amount of cement slurry that is pumped is generally greater than in reverse cementing. In reverse cementing, the cement slurry is pumped directly into the annulus instead of into the annulus via the casing string or tubing string. Accordingly, reverse cementing generally requires less of the cement slurry, faster setting times, and lower pump pressures because gravity assists the cement slurry in being placed in the annulus.

[0012] To perform reverse cementing operations successfully, the ability of holding displaced cement in place has proven to be difficult. One method of reverse cementing employs an inner tubing or drill string to prop open a check valve for the duration of reverse cementing. Once completed, retracting the tubing or drill string from the check valve allows it to close and check the further flow of cement into the casing string. The use of an inner tubing is expensive, requiring extra equipment, time, and personnel to complete the job. Thus, there is a need for improved ways to perform a reverse cementing operation that requires less time, money, and personnel. [0013] The present disclosure, based at least in part upon the above recognitions, has developed an improved inner sleeve, downhole tool, and a method for cementing in a wellbore. The inner sleeve, in at least one embodiment, may include a tubular having an uphole end, a downhole end, an inside tubular surface and an outside tubular surface. The inner sleeve, according to this embodiment, may further include two or more plug seat openings circumferentially positioned about the tubular and extending from the outside tubular surface to the inside tubular surface, the two or more plug seat openings configured to engage with two or more associated plug seats and allow the two or more associated plug seats to move between a radially retracted state and a radially extended state.

[0014] The downhole tool, in at least one embodiment, may include a valve connector housing, and an inner sleeve located at least partially within the valve connector housing. The inner sleeve, in at least one embodiment, may include a tubular having an uphole end, a downhole end, an inside tubular surface and an outside tubular surface, two or more plug seat openings circumferentially positioned about the tubular and extending from the outside tubular surface to the inside tubular surface, and two or more associated plug seats engaged with the two or more plug seat openings, the two or more associated plug seats configured to move between a radially retracted state and a radially extended state as the inner sleeve slides within the valve connector housing.

[0015] The method, in at least one embodiment, may include obtaining a casing string and a downhole tool installed therein, wherein the downhole tool includes: a body coupled to the casing string, a valve connector housing located within the body, an inner sleeve located at least partially within the valve connector housing. The inner sleeve, in at least one embodiment, may include a tubular having an uphole end, a downhole end, an inside tubular surface and an outside tubular surface, two or more plug seat openings circumferentially positioned about the tubular and extending from the outside tubular surface to the inside tubular surface, two or more associated plug seats engaged with the two or more plug seat openings, the two or more associated plug seats held in radially retracted states via the valve connector housing, a first valve located within the body and configured to open and close a fluid flow path through the valve connector housing, wherein the first valve is in a first valve open position, and a second valve located within the body and configured to open and close the fluid flow path through the valve connector housing, wherein the second valve is in a second valve closed position. The method may further include introducing the casing string and the downhole tool into a wellbore.

[0016] Turning to the figures, FIG. 1 illustrates the downhole tool 118 during introduction into a wellbore of a well system 100 — commonly known in the industry as being run-in-hole. The downhole tool 118 includes a body 120. The body 120 can be configured to fit within a casing string 115, for example, via casing box X pin connectors. The casing string 115 and the downhole tool 118 can be introduced into a wellbore that is defined by a wellbore wall 105. An annulus can be defined as the space located between the wellbore wall 105 and the outside of the casing string 115 and body 120.

[0017] The downhole tool 118 can include an inner sleeve 125 and a valve connector housing 192. The inner sleeve 125 can be releasably attached to the valve connector housing 192 by a frangible device 180. The frangible device 180 can be any device that is capable of withstanding a predetermined amount of force and capable of releasing at a force above the predetermined amount of force. The frangible device 180 can be, for example, a shear pin, a shear screw, a shear ring, a load ring, a lock ring, a pin, or a lug. There can also be more than one frangible device 180 that connects the inner sleeve 125 to the valve connector housing 192. The frangible device 180 or multiple frangible devices can be selected based on the force rating of the device, the total number of devices used, and the predetermined amount of force needed to release the device. For example, if the total force required to break or shear the frangible device is 15,000 pounds force (Ibf) and each frangible device has a rating of 5,000 Ibf, then a total of three frangible devices may be used.

[00181 The downhole tool 118 may also include a first valve 150 and a second valve 155. The first and second valves 150/155 can be flapper valves. As shown in FIG. 1, the downhole tool 118 is shown in the run-in-hole position wherein the first valve 150 is in an open position and the second valve 155 is in a closed position. In practice, drilling mud is usually introduced along with the casing string 115 and the downhole tool 118 from a wellhead in the direction DI. As shown, the first valve 150 is located above the second valve 155 at a location that is closer to the wellhead. With the first valve 150 held in the open position during run-in-hole via the inner sleeve 125, the run-in-hole fluid (e.g., a drilling mud) can flow within a fluid flow path through the body 120 in the direction DI. The second valve 155 can partially or fully open when a sufficient volume of run-in-hole fluid enters the downhole tool 118. The second valve 155 will naturally return to the closed position if pumping of the run-in-hole fluid stops. The run-in-hole fluid can then enter the annulus in the direction D2. The inner sleeve 125 can also include one or more sealing elements 145 that restrict or prevent fluid flow between the outside of the inner sleeve 125 and the inside of the valve connector housing 192.

[0019] The methods can include causing the inner sleeve 125 to shift after introduction and placement of the casing string 115 and the downhole tool 118 into the wellbore. The downhole tool 118 can include two or more plug seats 190 that are located on the inner sleeve 125 above the second valve 155. After the downhole tool 118 has been placed at the desired location within the wellbore, a plug 185 can be introduced into the casing string 1 1 and be flowed through the inner sleeve 125 of the downhole tool 118. It is to be understood that reference to a “plug” is not meant to limit the geometric shape of the plug, but rather is meant to include any device that is capable of engaging with a seat. In at least one embodiment, the plug 185 is a ball, but in other embodiments the plug 185 could be a dart, a bar, or any other shape.

[00201 Shifting of the inner sleeve 125 can be accomplished via the two or more plug seats 190 and the plug 185, for example by dropping the plug 185 from the wellhead onto the two or more plug seats 190 that are located within the downhole tool 118. The plug 185 engages with the two or more plug seats 190, and the seal created by this engagement prevents fluid communication downstream of the plug 185 and two or more plug seats 190. A pressure differential is created after the seal is created by engagement of the plug 185 with the two or more plug seats 190. The pressure differential can cause the frangible device 180 to shear, thereby releasing the inner sleeve 125 from connection with the valve connector housing 192.

[0021] Turning now to FIG. 2, the inner sleeve 125 is caused to move downward within the body 120 due to the pressure differential and shearing of the frangible device 180. A lower end of the inner sleeve 125 causes a flapper on the second valve 155 to convert from the closed position shown in FIG. 1 to an open position as shown in FIG. 2. The flapper can rotate into the open position via a hinge 175 on a second valve body 165.

[0022] The inner sleeve 125 can continue to travel in a downward direction until a sleeve shoulder 135 shoulders up against a valve connector housing shoulder 195. Continued travel of the inner sleeve 125 is prevented after the sleeve shoulder 135 engages with the valve connector housing shoulder 195. The inner sleeve 125 and the valve connector housing 192 can also include a lock ring 140. The lock ring 140 can become locked as shown in FIG. 2 after shouldering occurs. Locking of the lock ring 140 can help secure the inner sleeve 125 from further movement within the body 120, particularly back uphole toward the first valve 150.

[0023] As can also be seen in FIG. 2, the downward movement of the inner sleeve 125 can cause the first valve 150 to convert from an open position into a closed position. As the inner sleeve 125 moves downward, a flapper of the first valve 150 is no longer held open by the inner sleeve 125 and can rotate into the closed position via a hinge 170 located on a first valve body 160. A bottom portion of the inner sleeve 125 can push a flapper of the second valve 155 open and continue to travel downward into a bottom portion 198 of the downhole tool 118. The second valve 155 can be locked in the open position via the inner sleeve 125. Although shown in the figures with the first valve hinge 170 being located opposite from the second valve hinge 175, it is to be understood that the hinges 170/175 can be located on the same side of the valve connector housing 192.

[0024] The plug 185, the two or more plug seats 190, and/or the inner sleeve 125 can be configured to allow the plug 185 to disengage from the two or more plug seats 190. Thus, the methods can further include causing or allowing the plug 185 to disengage from the two or more plug seats 190, for example after the inner sleeve 125 has shouldered up, as shown in FIG. 2. The second valve 155 is maintained in the open position and prevented from closing due to the protrusion of the lower end of the inner sleeve 125 into the bottom portion 198 of the downhole tool 118. A surface indication of increased pressure can signal that the second valve 155 is in the open position and reverse cementing can commence.

[0025] The components of the downhole tool 118 can be made from a variety of components including, but not limited to, metals, metal alloys, composites, plastics, and rubbers. [0026] The methods further include introducing a cement composition 110 into an annulus located between a wall 105 of the wellbore and an outside of the casing string 115. The annulus and inside of the casing string 115 can contain a fluid. The fluid can be a run-in-hole fluid, for example, a drilling mud. The methods can include introducing a first fluid into the annulus prior to introduction of the cement composition 110. The first fluid can be a spacer fluid. A spacer fluid can help separate a drilling mud from the cement composition 110. The cement composition 110 can then be introduced into the annulus. There can also be a second, third, etc. fluid introduced into the annulus after the first fluid and before the cement composition 110. Any of the fluids can be introduced into the annulus in the direction D3 and can enter the downhole tool 118 in the direction D4. The first valve 150 can open as fluids enter the inner sleeve 125 from direction D4. With the cement composition 110 in place, it may be allowed to set to fix the casing string 115 and body 120 within the wellbore.

[0027] Turning to FIGs. 3A through 31, illustrated is an inner sleeve 300 designed manufactured and/or operated according to one or more embodiments of the disclosure. The inner sleeve 300, in the illustrated embodiment, includes a tubular 310 having an uphole end 315a, a downhole end 315b, an inside tubular surface 315c and an outside tubular surface 315d. In accordance with one embodiment of the disclosure, the inner sleeve 300 may include two or more plug seat openings 320 circumferentially positioned about the tubular 310 and extending from the outside tubular surface 315d to the inside tubular surface 315c. In accordance with this embodiment, the two or more plug seat openings 320 are configured to engage with (or actually engage with) two or more associated plug seats 330 (e.g., two or more associated locked dogs), and allow the two or more associated plug seats 330 to move between a radially retracted state (e.g., as shown in

FIG. 1) and a radially extended state (e.g., as shown in FIG. 2). [0028] Tn one or more embodiments, the two or more plug seat openings 320 are two or more T- shaped plug seat openings, such as shown in FIGs. 3A through 31. The two or more T-shaped plug seat openings, in at least one embodiment, each include a vertical portion 325a and a horizontal portion 325b. In at least one embodiment, a downhole sidewall 325c of the vertical portion 325a is not angled (e.g., perpendicular to the top surface of the horizontal portion 325b), as shown in FIG. 3F. In at least one other embodiment, the downhole sidewall 325c of the vertical portion 325a is angled downhole, as shown in FIG. 3H.

[0029] In one or more embodiments, the two or more plug seats 330 are two or more T-shaped plug seats, such as shown in FIGs. 3A through 31. The two or more T-shaped plug seats, in at least one embodiment, each include a vertical portion 335a and a horizontal portion 335b. In at least one embodiment, a downhole sidewall 335c of the vertical portion 335a is not angled (e.g., perpendicular to the top surface of the horizontal portion 335b), as shown in FIG. 3G. In at least one other embodiment, the downhole sidewall 335c of the vertical portion 335a is angled downhole, as shown in FIG. 31. It is believed that the angled vertical portion 325a of the two or more plug seat openings 320 and the angled vertical portion 335a of the two or more plug seats 330 may assist the two or more plug seats 330 to move between the radially retracted state (e.g., as shown in FIG. 1) and the radially extended state (e.g., as shown in FIG. 2). Furthermore, the two or more plug seats 330 may include a radius of curvature, for example substantially tracking the radius of curvature of the inside tubular surface 315c of the tubular 310.

[0030] Any number of plug seat openings 320 and associated plug seats 330 may be used and remain within the scope of the disclosure, so long as there are at least two of each. In at least one embodiment, three plug seat openings 320 and associated plug seats 330 are used. In yet another embodiment, such as shown in FIGs. 3A through 31, four plug seat openings 320 and associated plug seats 330 are used. Tn even yet another embodiment, six or more plug seat openings 320 and associated plug seats 330 are used. In even yet even another embodiment, from four to twenty plug seat openings 320 and associated plug seats 330 are used. In at least one embodiment, the two or more plug seat openings 320 and two or more plug seats 330 are circumferentially placed around the tubular 310 equidistance from one another.

[00311 In the illustrated embodiment, the inner sleeve 300 may additionally include a lock ring groove 340 in the outside tubular surface 315d. The inner sleeve 300 may additionally include a lock ring 345 positioned within the lock ring groove 340. In at least one embodiment, the lock ring groove 340 and lock ring 345 are positioned between the two or more plug seat openings 320 and the downhole end 315b of the tubular 310. Accordingly, the lock ring groove 340 and the lock ring 345 may be used to prevent the inner sleeve 300 from travelling back uphole (e.g., toward the first valve) after the plug seats 330 have moved from radially retracted state (e.g., as shown in FIG. 1) to the radially extended state (e.g., as shown in FIG. 2).

[0032] In the illustrated embodiment, the inner sleeve 300 may additionally include one or more seal grooves 350 in the outside tubular surface 315d. The inner sleeve 300 may additionally include one or more seals 355 positioned within the one or more seal grooves 350. In at least one embodiment, the one or more seal groove 350 and one or more seals 355 are positioned between the two or more plug seat openings 320 and the uphole end 315a of the tubular 310, and are configured to prevent fluid from entering the spacing between the inner sleeve 300 and the valve connector housing .

[0033] In one or more embodiments, the inner sleeve 300 may additionally include a fluid release port/slot 360. This fluid release port/slot 360 may allow any fluid trapped between the inner sleeve 215 and the valve connector housing to escape when/if the inner sleeve 300 is moving from the radially retracted state (e.g., as shown in FIG. 1 ) to the radially extended state (e.g., as shown in FIG. 2).

[0034] Turning to FIGs. 4A through 4D, illustrated are a set of cross-sectional drawings illustrating various different operational states for a downhole tool 400 designed, manufactured and operated according to one or more embodiments of the disclosure. The downhole tool 400 may include many of the same features as the downhole tools disclosed above. In the illustrated embodiment, the downhole tool 400 includes a valve connector housing 410, as well as an inner sleeve 420 located at least partially within the valve connector housing 410. In the illustrated embodiment, the inner sleeve 420 includes a tubular 430, two or more plug seat openings 435, and two or more associated plug seats 440 engaged with the two or more plug seat openings 435. [0035] The downhole tool 400 according to the embodiment of FIGs. 4A through 4D, additionally includes a body 450 coupled to the valve connector housing 410, the body 450 having one or more plug seat spaces 455. The downhole tool 400 additionally includes a first valve 460 and second valve 465 located within the body 450. The first valve 460 and second valve 465, in the illustrated embodiment, are configured to open and close a fluid flow path through the valve connector housing 410.

[0036] In the embodiment of FIG. 4A, the inner sleeve 420 is positioned in its run-in-hole state. Accordingly, the first valve 460 is propped open by the inner sleeve 420, while the inner sleeve 420 allows the second valve 465 to remain closed. Furthermore, the valve connector housing 410 is holding the two or more plug seats 440 in the radially retraced state.

[0037] In the embodiment of FIG. 4B, a plug 470 has been dropped within the valve connector housing 410 and the inner sleeve 420. As shown, the plug 470 engages with the two or more plug seats 440, thereby forming a seal and closing the fluid path in the inner sleeve 420. [0038] Tn the embodiment of FIG. 4C, fluid pressure has been applied to the plug 470, thereby moving the inner string 420 at least partially downhole. In the illustrated embodiment of FIG. 4C, the inner string 420 starts to open the second valve 465, while it allows the first valve 460 to start closing. At this axial position of the inner sleeve 420, the two or more plug seats 440 remain within their radially retracted state. For example, the valve connector housing 410, at this axial location of the inner sleeve 420, keeps the two or more plug seats 440 within their radially retracted state.

[0039] In the embodiment of FIG. 4D, fluid pressure continues to be applied to the plug 470, thereby moving the inner string 420 downhole to its final axial position. In the illustrated embodiment of FIG. 4D, the final axial position of the inner string 420 allows the first valve 460 to close. Furthermore, the final axial position of the inner sleeve 420 allows the two or more plug seats 440 to align with the two or more plug seat spaces 455 in the body 450. Accordingly, pressure on the plug 470 pushes the two or more plug seats 440 from their radially retracted state to their radially extended state (e.g., into the two or more plug seat spaces 455), thereby allowing the plug 470 to fall out from the inner sleeve 420.

[0040] Aspects disclosed herein include:

A. An inner sleeve, the inner sleeve including: 1) a tubular- having an uphole end, a downhole end, an inside tubular surface, and an outside tubular surface; and 2) two or more plug seat openings circumferentially positioned about the tubular and extending from the outside tubular surface to the inside tubular surface, the two or more plug seat openings configured to engage with two or more associated plug seats and allow the two or more associated plug seats to move between a radially retracted state and a radially extended state. B. A downhole tool, the downhole tool including: 1 ) a valve connector housing; and 2) an inner sleeve located at least partially within the valve connector housing, the inner sleeve including: A) a tubular having an uphole end, a downhole end, an inside tubular surface, and an outside tubular surface; bO two or more plug seat openings circumferentially positioned about the tubular and extending from the outside tubular surface to the inside tubular surface; and c) two or more associated plug seats engaged with the two or more plug seat openings, the two or more associated plug seats configured to move between a radially retracted state and a radially extended state as the inner sleeve slides within the valve connector housing.

C. A method for cementing in a wellbore, the method including: 1) obtaining a casing string and a downhole tool installed therein, wherein the downhole tool includes: a) a body coupled to the casing string; b) a valve connector housing located within the body; c) an inner sleeve located at least partially within the valve connector housing, the inner sleeve including: i) a tubular having an uphole end, a downhole end, an inside tubular surface, and an outside tubular surface; ii) two or more plug seat openings circumferentially positioned about the tubular and extending from the outside tubular surface to the inside tubular surface; and iii) two or more associated plug seats engaged with the two or more plug seat openings, the two or more associated plug seats held in radially retracted states via the valve connector housing; d) a first valve located within the body and configured to open and close a fluid flow path through the valve connector housing, wherein the first valve is in a first valve open position; and e) a second valve located within the body and configured to open and close the fluid flow path through the valve connector housing, wherein the second valve is in a second valve closed position; and 2) introducing the casing string and the downhole tool into a wellbore. [0041] Aspects A, B, and C may have one or more of the following additional elements in combination: Element 1: wherein the two or more plug seat openings are two or more T-shaped plug seat openings. Element 2: wherein the two or more T-shaped plug seat openings each include a vertical portion and a horizontal portion. Element 3: wherein a downhole sidewall of the vertical portion is angled downhole. Element 4: further including two or more associated T- shaped plug seats engaged within the two or more T-shaped plug seat openings, the two or more T-shaped plug seat openings allowing the two or more associated T-shaped plug seats to move between the radially retracted state and the radially extended state. Element 5: wherein the two or more associated T-shaped plug seats each include a vertical plug seat portion and a horizontal plug seat portion, and further wherein a second downhole sidewall of the vertical plug seat portion is angled downhole. Element 6: wherein the two or more T-shaped plug seat openings each include a vertical portion and a horizontal portion, and further including two or more associated T-shaped plug seats engaged within the two or more T-shaped plug seat openings, the two or more associated T-shaped plug seats each including a vertical plug seat portion and a horizontal plug seat portion, and further wherein the vertical plug seat portion has a radius of curvature. Element 7: further including four or more plug seat openings circumferentially positioned about the tubular and extending from the outside tubular surface to the inside tubular surface. Element 8: further including a lock ring located within a lock ring groove in the outside tubular surface, the lock ring and lock ring grove located between the two or more plug seat openings and the downhole end of the tubular. Element 9: further including one or more seals located within one or more seal grooves in the outside tubular surface, the one or more seals and one or more seal grooves located between the two or more plug seat openings and the uphole end of the tubular. Element 10: further including: a body coupled to the valve connector housing and configured to fit within a casing string; a first valve located within the body and configured to open and close a fluid flow path through the valve connector housing, wherein the first valve opens to a first valve open position in a direction towards a wellhead of the wellbore; and a second valve located within the body and configured to open and close the fluid flow path through the valve connector housing, wherein the second valve opens to a second valve open position in a direction away from the wellhead of the wellbore. Element 11: wherein the first valve is configured to be in the first valve open position and the second valve is configured to be in a second valve closed position during placement of the downhole tool in the wellbore. Element 12: wherein the body includes one or more plug seat spaces, the one or more plug seat spaces configured to allow the two or more associated plug seats to move from the radially retracted state to the radially extended state as the inner sleeve slides within the valve connector housing. Element 13: wherein the two or more plug seat openings are two or more T-shaped plug seat openings. Element 14: wherein the two or more associated plug seats are two or more associated T-shaped plug seats, and further wherein the two or more associated T-shaped plug seats each include a vertical plug seat portion and a horizontal plug seat portion, and further wherein a second downhole sidewall of the vertical plug seat portion is angled downhole. Element 15: further including introducing cement composition into an annulus located between a wall of the wellbore and an outside of the casing string after introducing the casing string and the downhole tool into the wellbore. Element 16: wherein the two or more associated plug seats held in the radially retracted state extend radially inward from the inside tubular surface, and further including introducing a plug into the casing string and the inner sleeve, wherein the plug engages with the two or more plug seats to create a seal and a pressure differential, and wherein the pressure differential causes the inner sleeve to shift downhole. Element 17: wherein the shift downhole moves the first valve to a first valve closed position and the second valve to a second valve open position. Element 18: wherein the shift downhole allows the two or more associated plug seats to encounter one or more plug seat spaces in the body and move from the radially retracted state to the radially extended state. Element 19: wherein the pressure differential against the plug moves the two or more associated plug seats from the radially retracted state to the radially extended state when they encounter the one or more plug seat spaces in the body. Element 20: wherein the move of the two or more associated plug seats from the radially retracted state to the radially extended state allows the plug to disengage from the two or more associated plug seats and leave the downhole tool. Element 21: wherein the two or more plug seat openings are two or more T-shaped plug seat openings. Element 21: wherein the two or more T-shaped plug seat openings each include a vertical portion and a horizontal portion. Element 22: wherein a downhole sidewall of the vertical portion is angled downhole. Element 23: wherein the two or more associated plug seats are two or more associated T-shaped plug seats, and further wherein the two or more associated T-shaped plug seats each include a vertical plug seat portion and a horizontal plug seat portion, and further wherein a second downhole sidewall of the vertical plug seat portion is angled downhole.

[0042] Those skilled in the ail to which this application relates will appreciate that other and further additions, deletions, substitutions, and modifications may be made to the described embodiments.