Patent Publication Number: US-11021930-B2

Title: Diverter tool and associated methods

Description:
BACKGROUND OF THE DISCLOSURE 
     To produce hydrocarbons from a formation, a wellbore is drilled from the surface of the earth using a drillstring. After the drillstring has drilled the wellbore to a first depth, the drillstring is removed from the wellbore. Operators then run a first section or string of casing into the drilled wellbore and set the first casing in place by flowing cement into the annulus between the outer diameter of the first casing and the wall of the wellbore. 
     Once the cement is allowed to cure, operators drill a further portion of wellbore extending to a second depth below the first portion. The drillstring is removed, and a second casing string or casing section is run into the wellbore through the first casing and into the further portion of the wellbore. The second casing is sometimes termed a “liner” when it is placed below casing already within the wellbore. 
     The second casing has a smaller outer diameter than the inner diameter of the first casing so the second casing can be run through the first casing. Once an upper portion of the second casing reaches a lower portion of the first casing, the second casing is temporarily hung off of the first casing, usually by a liner hanger. Cement is then flowed into the annulus between the outer diameter of the second casing and the wellbore and allowed to cure to set the second casing within the wellbore. This process can be repeated as many time as needed to place casing sections within the wellbore to form a cased wellbore of a desired depth. 
     Once the casing sections of increasing depth are placed within the wellbore, it is often necessary or desirable to run wellbore tools into the casing. Furthermore, after setting the casing within the wellbore at the desired depth for hydrocarbon production, the hydrocarbon fluid migrates through the inner diameter of the casing to the surface of the wellbore. For this reason, it is desirable that the cased wellbore possess the largest inner diameter possible for its depth to allow for the maximum area for fluid flow during hydrocarbon production as well as to permit maximum clearance for wellbore tools through the cased wellbore. Therefore, each subsequently-run casing usually has only a slightly smaller outer diameter than the inner diameter of the previously-run casing to allow for maximum effective inner diameter over the depth of the casing within the wellbore. 
     Because of the small variance between the outer diameter of the subsequently-run casing section and the inner diameter of the previously-run casing section, little annular clearance between the casing sections may exist during run-in. The small annular clearance causes a large amount of surge pressure to be imparted on the formation below the previously-run casing when the subsequently-run casing section is lowered into the wellbore. Over-pressurizing the formation can cause damage to the formation, jeopardizing production of hydrocarbons. 
     Additionally, when running casing into the wellbore, fluid located within the wellbore tends to flow up through the inner diameter of the casing being run into the wellbore. In particular, because of the pressure exerted on the formation when running in a casing sections when little annular clearance exists, downhole fluid may flow up through the casing section to relieve the pressure within the wellbore. The velocity of this upward flow can be problematic and is exacerbated by the presence of the running string used to run each casing section into the wellbore. The running string typically has a reduced inner diameter compared to the inner diameter of the casing previously disposed within the wellbore, which causes an increase in pressure within the running string as the fluid flows upward through the running string. 
     Due to the increase in pressure experienced by the fluid flowing upward within the running string, the fluid velocity tends to increase when it flows from the less restricted inner diameter of the disposed casing to the reduced diameter of the running string. An uncontrolled flow of fluid from downhole causes fluid to flow onto the rig floor from downhole. 
     To partially alleviate the surge problem, casing sections are often run into the wellbore at reduced speeds to decrease pressure on the fluid within the wellbore caused by running in the casing. Reducing the running speed of the casings into the wellbore and cleaning up the rig floor increases the amount of time required to obtain a producing wellbore, thereby increasing the cost of the wellbore. 
     A similar problem occurs when running casing into a wellbore formed in a delicate formation, regardless of whether a previous casing exists and regardless of whether the clearance between casings is small. Running casing into a delicate formation could easily result in damage to the formation due to high downhole pressure caused by running the casing into the wellbore. 
     To prevent the problems that occur due to small clearances in the annulus between casing section and due to pressure on delicate formations, diverter tools have been developed to divert fluid into the wellbore annulus while running the casing into the wellbore. The diverter tool is typically a tubular body disposed within the running string and is attached above the running tool connected to the casing. The diverter tool is open during run-in and can be closed when it has reached casing depth. 
     Some typical diverter tools have a ball seat for engaging a ball so the tool can be closed. In order for additional tools, cement plugs, darts, and the like to pass through the tool for further operations downhole, the ball is extruded through the ball seat. Although this works, there are a number of disadvantages. The increased pressure to extrude the ball through the seat can cause the ball to cannon downhole, potentially damaging downhole components. The ball also remains downhole and could hinder further operations. Finally, the extruded seat left after passage of the ball can still provide a narrow diameter for the passage of the additional devices, cement plugs, darts, and the like used in further operations downhole. In fact, the extruded seat may damage the sealing capability of some of these devices once they pass. 
     The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above. 
     SUMMARY OF THE DISCLOSURE 
     According to the present disclosure, a diverter tool is used for reducing surge pressure when running casing into a wellbore. The tool is operable with a plug, such as ball, and comprises a housing, a sleeve, and a seat. The housing has a longitudinal bore therethrough and defines a bypass port communicating the longitudinal bore outside of the housing. The sleeve is movably disposed in the longitudinal bore and has an internal bore therethrough. The sleeve is movable in the longitudinal bore from an opened position (open relative to the bypass port) to a closed position (closed relative to the bypass port). 
     The seat is disposed in the internal bore of the sleeve and defines a seat opening permitting fluid communication therethrough. The seat is rotatable in the internal bore from an interposed condition to a stowed condition. The seat in the interposed condition is interposed in the internal bore and is configured to engage the plug in the seat opening. The seat in the interposed condition engaged with the plug moves the sleeve from the opened position to the closed position in response to applied fluid pressure in the longitudinal bore. The seat in the sleeve in the closed position rotates from the interposed condition to the stowed position and exposes the internal bore of the sleeve to the longitudinal bore of the housing. 
     The tool can comprise a lock disposed between the sleeve and the housing and locking the sleeve in the closed position. For example, the lock can comprise a snap ring disposed about the sleeve and engaging in a circumferential shoulder defined in the longitudinal bore. 
     The seat can comprise an arm connected to the seat and having a pivot point disposed in a slot. The pivot point can be moveable in the slot, permitting the arm to rotate the seat from the interposed condition to the stowed position. 
     The sleeve can define a side pocket of the internal bore in which the seat rotates in the stowed condition. 
     In a configuration, the tool can comprise a temporary fixture disposed between the sleeve and the housing and temporarily holding the sleeve in the opened position up to a first limit of the applied fluid pressure. The temporary fixture releases the sleeve to move from the opened position to the closed position in response to the first limit of the applied fluid pressure acting thereagainst. 
     In one example, the temporary fixture can comprise a biasing element biasing the sleeve to the opened position and acting against a level below the first limit of the applied fluid pressure tending to prematurely close the sleeve. 
     In another example, the temporary fixture can comprise one or more radial pins disposed in the longitudinal bore of the housing and shearably engaging the sleeve. The sleeve can define one or more transverse slots each having one of the one or more radial pins retained therein. Each of the one or more transverse slots can comprise a longitudinal slot extending therefrom in which the radial pin is movable along. The one or more transverse slots can comprise a retainer clip permitting passage of the radial pin in a first direction into the transverse slot from a proximal end the longitudinal slot and preventing passage of the radial pin in a second direction opposite the first direction. 
     In a configuration, the tool can comprise a temporary fixture disposed between the seat and the sleeve and holding the seat in the interposed condition up to a second limit of the applied fluid pressure. The temporary fixture releases the seat to move from the interposed condition to the stowed condition in response to the second limit of the applied fluid pressure limit acting thereagainst. In one example, the temporary fixture can comprise a shear ring disposed between the seat and a ledge in the internal bore. 
     In a configuration, the tool can comprise a lock locking the seat in the stowed position. In one example, the lock can comprise a biased first shoulder disposed in the internal bore of the sleeve and engaging against a second shoulder of the seat. 
     In a configuration, the tool can comprise first and second seals disposed on the sleeve. The first and second seals on the sleeve in the closed position can sealably engage in the longitudinal bore respectively upbore and downbore of the bypass port. The sleeve can comprise a cross port disposed upbore of the seat and disposed downbore of the second seal. The cross port can communicate the internal bore of the sleeve with an annulus between the sleeve and the longitudinal bore. Each of the first and second seals on the sleeve in the opened position can be sealably disengaged in the longitudinal bore and can be exposed on both sides by tubing pressure in the annulus. By contrast, each of the first and second seals on the sleeve in the closed position sealably engaging in the longitudinal bore can be exposed to a pressure differential between the tubing pressure in the annulus and a borehole pressure from the bypass port. A third seal can be disposed on the sleeve, the third seal on the sleeve when opened and closed can sealably engage in the longitudinal bore downbore of the cross port. 
     According to the present disclosure, a diverter tool is for reducing surge pressure when running casing into a wellbore. The tool is operable with a plug, such as a ball, and comprises a housing, a sleeve, a seat, a first temporary fixture, and a second temporary fixture. 
     The housing has a longitudinal bore therethrough. The housing defines a bypass port communicating the longitudinal bore outside of the housing. The sleeve is movably disposed in the longitudinal bore and has an internal bore therethrough. The sleeve is movable in the longitudinal bore from an opened position (open relative to the bypass port) to a closed position (closed relative to the bypass port). 
     The seat is disposed in the internal bore of the sleeve and defines a seat opening permitting fluid communication therethrough. The seat is rotatable in the internal bore from an interposed condition to a stowed condition. The seat in the interposed condition is interposed in the internal bore and is configured to engage the plug in the seat opening. The seat in the stowed condition exposes the internal bore of the sleeve to the longitudinal bore of the housing. 
     The first temporary fixture is disposed between the housing and the sleeve. The first temporary fixture holds the sleeve in the opened position up to a first limit of applied fluid pressure and releases the sleeve to move from the opened position to the closed position in response to the first limit acting against the seat in the interposed condition engaged with the plug. The second temporary fixture is disposed between the seat and the sleeve. The second temporary fixture holds the seat in the interposed position up to a second limit of the applied fluid pressure greater than the first limit and releases the seat to rotate from the interposed condition to the stowed position in response to the second limit acting against the seat in the interposed condition engaged with the plug. 
     According to the present disclosure, a method comprises: running casing into a wellbore with a running string having a diverter tool disposed thereon; diverting surge pressure passing uphole through the running string out of a bypass port in the diverter tool until the casing is run to depth by temporarily holding a sleeve opened relative to the bypass port inside the diverter tool; engaging a plug in a seat interposed in an interposed condition in an internal bore of the sleeve in the diverter tool; shifting the sleeve closed relative to the bypass port by applying a first limit of fluid pressure against the plug seated in the seat; and pivoting the seat with the engaged plug from the interposed condition to a stowed condition in the internal bore of the sleeve by applying a second limit of the fluid pressure against the plug seated in the seat. 
     The method can further comprise: launching the plug down the running string to the diverter tool to engage the plug in the seat; and/or pumping cement down the running string and through the diverter tool to cement the casing in the wellbore. 
     In shifting the sleeve closed, the method can comprise shearing the sleeve free to shift in the diverter tool with the first limit of the fluid pressure applied against the plug seated in the seat; sealing upbore and downbore of the bypass port respectively with first and second seals disposed on the sleeve and sealably engaged inside the diverter tool; and/or locking the sleeve closed. 
     In pivoting the seat with the engaged plug from the interposed condition to the stowed condition in the internal bore of the sleeve, the method can comprise: shearing the seat free to pivot in the sleeve with the second limit of the fluid pressure applied against the plug seated in the seat; and/or locking the seat in the stowed condition. 
     The method can further comprise, before running the casing, initially testing seals sealably engaged between the sleeve and the inside of the diverter tool by mechanically shifting the sleeve closed relative to the bypass port. The method can further comprise, after shifting the sleeve closed and before pivoting the seat, testing seals on the closed sleeve sealably engaged between the sleeve and the inside of the diverter tool. 
     The foregoing summary is not intended to summarize each potential embodiment or every aspect of the present disclosure. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  illustrates a cross-sectional view of casing attached to a running string having a diverter tool for running the casing in a wellbore. 
         FIG. 2A  illustrates a cross-sectional view of an embodiment of a diverter tool of the present disclosure. 
         FIGS. 2B-2D  illustrate details of the diverter tool in  FIG. 2A . 
         FIGS. 3A-3C  illustrate the diverter tool in various operational conditions. 
         FIG. 4  illustrates a cross-sectional view of another embodiment of a diverter tool of the present disclosure. 
         FIGS. 5A-5B  illustrates cross-sectional details of the diverter tool in  FIG. 4 . 
         FIG. 6  illustrates a perspective view of a sleeve of the diverter tool in  FIG. 4 . 
         FIGS. 7A-7B  illustrates end-sectional details of the diverter tool in  FIG. 4 . 
         FIG. 8A  illustrates a cross-sectional view of yet another embodiment of a diverter tool of the present disclosure. 
         FIGS. 8B-8C  illustrate details of the diverter tool in  FIG. 8A . 
         FIGS. 9A-9C  illustrate cross-sectional details of the diverter tool during stages of operation. 
     
    
    
     DETAILED DESCRIPTION OF THE DISCLOSURE 
     An assembly  10  in  FIG. 1  includes a rig  12  suspending a traveling block  13   a , which supports a top drive  13   b  movable vertically on a block dolly  13   d . An influent drilling fluid line supplies the top drive  13   b  with drilling fluid from a drilling fluid reservoir (not shown). A launching manifold  13   c  connects to the running string  18 , which has several pipe segments extending down into the borehole  15  formed in an earth formation  14 . 
     The running string  18  conveys casing or liner  30  into the borehole  15 . A portion of the borehole  15  already has casing  20  set therein by cement  22 . The running string  18  includes a running tool  40  and a diverter tool  50 . The running string  18  lowers the liner  30  from the rig  12  at the surface  16 . The diverter tool  50  is connected toward the end of the running string  18 , near the running tool  40  connected to the liner  30 . 
     The running tool  40  is releasably connected to an inner diameter of the casing  30  by a temporary attachment, such as a hanger. Fluid F can flow through the length of the bore of the running string  18  and through the casing  30 . During run-in of the liner  30 , the diverter tool  50  remains open with a bypass ports exposed. Surge pressure can thereby be diverted from inside the casing  30  to the borehole annulus between the running string  18  and the outer casing  20 . 
     When the required depth is reached, a drop ball from the launcher  13   c  is pumped downhole to land in a movable ball seat (not labelled) inside the diverter tool  50 . A sleeve (not labelled) in the diverter tool  50  shifts and closes the diverter tool&#39;s bypass port. A locking mechanism then locks the sleeve to seal the bypass port. 
     Pressure can then be increased to test any seals around the bypass ports in the diverter tool  50  and to shear the ball seat. Once freed, the ball seat rotates away into a stowed position inside the diverter tool  50  and locks in place. The diverter tool  50  is now closed and has an open full bore for passage of tools, cement plugs, darts, etc. Accordingly, operators can hang the liner  30  in the casing  20  and can perform cementation operations. During cementation, the diverter tool  50  allows darts (not shown) to be deployed through the tool  50 . 
       FIG. 2A  illustrates a cross-sectional view of an embodiment of a diverter tool  50 A of the present disclosure for use in running casing downhole with an assembly  10  as in  FIG. 1 .  FIGS. 2B-2D  illustrate details of the diverter tool  50 A in  FIG. 2A , and  FIGS. 3A-3C  illustrate the diverter tool  50 A in various operational conditions. 
     The diverter tool  50 A is used for reducing surge pressure when running casing or liner into a wellbore, as discussed above. The tool  50 A is operable with a plug B (e.g., a ball) and includes a housing  100 , a sleeve  110 , and a seat mechanism  130 . The plug B can be launched from surface from a ball launcher or the like, or the plug B may be deployed with the tool  50 A and may be free to float above the seat mechanism  130 . 
     During use, the sleeve  110  is temporarily held opened relative to one or more bypass ports  104  inside the diverter tool  50 A. A running string (not shown) having the diverter tool  50 A disposed thereon is used to run the casing into a wellbore. Any surge pressure passing uphole through the running string is diverted out of the bypass ports  104  in the diverter tool  50 A until the casing is run to depth. 
     The plug B is then launched down the running string to the diverter tool  50 A, and the plug B engages in a seat  132  of the seat mechanism  130  interposed in an internal bore  112  of the sleeve  110 . Fluid pressure is applied against the seated plug B in the seat  132  to overcome the temporary hold that keeps the sleeve  110  in the open position. The sleeve  110  is then shifted closed relative to the bypass ports  104  by moving the sleeve  110  in the diverter tool  50 A with the fluid pressure applied against the plug B seated in the seat  132 . 
     Once the sleeve  110  shifts, the sleeve  110  is locked in a closed position. The seat  132  then pivots with the engaged plug B from the interposed position to a stowed position in the internal bore  112  of the sleeve  110 . At this point, additional operations can be performed. For example, operators can pump cement down the running string and through the diverter tool  50 A to cement the casing in the wellbore. Any needed cement plugs, darts, and the like can pass by the stowed seat  132  in the diverter tool  50 A. 
     As shown in  FIG. 2A , the housing  100  has a longitudinal bore  102  therethrough and has first and second ends  106 ,  108  for coupling to other components, such as pipe of a running string and running tool. The one or more bypass ports  104  are defined in the housing  100  and communicate the longitudinal bore  102  outside the housing  100 . 
     The sleeve  110  is movably disposed in the longitudinal bore  102  from an opened position ( FIG. 2A ) open relative to the bypass ports  104  to a closed position ( FIGS. 3A-3C ) closed relative to the bypass ports  104 . Seals  115   a - b  between the sleeve  110  and longitudinal bore  102  seal off circumferentially above and below (upbore and downbore of) the bypass ports  104  when the sleeve  110  is closed. 
     The sleeve  110  has an internal bore  112  therethrough, and the seat mechanism  130  is disposed in the internal bore  112  of the sleeve  110 . The seat mechanism  130  includes a seat  132  with a seat opening  134  permitting fluid communication therethrough. As noted briefly above, the seat  132  is rotatable/pivotable from the interposed condition ( FIGS. 3A-3B ) to the stowed condition ( FIG. 3C ). The seat  132  in the interposed condition is interposed in the internal bore  112  and is configured to engage the plug B in the seat opening  134 . 
     A temporary connection or fixture is disposed between the housing  100  and the sleeve  110  and holds the sleeve  110  in the opened position opened relative to the bypass ports  104 . A number of temporary connections or fixtures can be used between the housing  100  and the sleeve  110 . For example, shear pin, shear ring, shear plate, biasing element, spring, and the like can be disposed between the housing  100  and the sleeve  110  to hold the sleeve  110  in the opened position. 
     As depicted here in  FIGS. 2A &amp; 3A-3C , the tool  50 A includes a biasing element  120  for this temporary connection or fixture. The biasing element  120  is disposed in an annular area between the sleeve  110  and the housing  100  and acts against a tendency of downward flow through the tool  50 A from moving the sleeve  110  open. In particular, the biasing element  120  biases the sleeve  110  to the opened position ( FIG. 2A ) opened relative to the bypass ports  104 . The biasing element  120 , which can be a spring as shown, then acts against flow levels that may prematurely close the sleeve  110  before the diverter tool  50 A runs the casing (not shown) to depth. Examples of the spring force for the biasing element  120  needed so circulation can pass through the tool  50 A without closing the diverter tool  50 A can range from about 500-lb for about 5 bpm circulation flow (mud 12.5 ppg) to over 2,100-lb. for about 10 bpm circulation flow (mud 12.5 ppg). Although the biasing element  120  is disposed toward an uphole end of the tool  50 A above the seat mechanism  130  in the sleeve  110 , the entire arrangement of the sleeve  110  and biasing element  120  can be reversed relative to the seat mechanism  130  and the bypass ports  104 . 
     To prevent vacuum lock of the sleeve  110  in the housing  100 , fluid can pass in the annulus between an upper member  114   a  of the sleeve  110  and the housing  110  by communicating through ports  116 ,  117  as shown in  FIG. 2B . As further shown in  FIG. 2C , fluid in the annulus can pass through ports  123  in a retainer  122  for the spring  120 . 
     During run-in as shown in  FIG. 2A , the diverter tool  50 A is in an opened position with the sleeve  110  shifted uphole and with the bypass ports  104  exposed to the housing&#39;s bore  102 . Fluid flow uphole through the bore  102  can be diverted out of the bypass ports  104  into the surrounding annulus, as discussed above. Meanwhile, the biasing element  120  keeps the sleeve  110  open. 
     As necessary, fluid flow can also pass downhole through the bore  102 . For example, once the conveyed casing (not shown) reaches depth, the plug (e.g., ball B) can be pumped down the running string to the housing&#39;s bore  102 . As shown in  FIG. 3A , the plug B engages the seat  132  in the interposed condition in the internal bore  112  of the sleeve  110 . Pumped fluid behind the seated plug B increased fluid pressure in the bore  102 . Pumped fluid can also act against piston areas of the sleeve  110 . 
     With continued pressure from the pumped fluid, the plug B can be partially extruded/captured in the seat&#39;s opening  134 . Eventually, the seat  132  engaged with the plug B moves the sleeve  110  from the opened position ( FIG. 2A ) toward a closed position ( FIGS. 3A-3C ). The biasing element  120  is compressed between the sleeve&#39;s upper member  114   a  and the retainer  122 . Eventually, a lock  140  engages between the sleeve  110  and the housing  100  and locks the sleeve  110  in the closed position ( FIG. 3B ). As best shown in  FIG. 2C , the lock  140  comprises a lock ring disposed external to the sleeve  110 . When the sleeve  110  is shifted, the lock ring  140  engages in an internal circumferential groove  142  defined at the bypass ports  104 . 
     The continued pressure no longer acting to shift the sleeve  100  then actuates the seat mechanism  130 . In this regard, a temporary connection or fixture between internal components of the seat mechanism  130  frees the seat  130  to rotate or pivot out of the way. Again, a number of temporary connections or fixtures between the seat  132  and the sleeve  110  can be used. 
     For example, as best shown in  FIG. 2C , a shear ring  133  disposed about the seat  132  and engaged against a ledge  119  in the internal bore of the sleeve  110  shears in response to a level of applied fluid pressure. The ring  133  may shear at a fluid pressure limit above what it takes to move the sleeve  100 . For example, the ring  133  may shear at a limit of 1600-psi or higher. By contrast, the sleeve  100  may shift closed with a fluid pressure limit of 500-psi. 
     Once freed, the seat  132  in the sleeve  110  in the closed position rotates/pivots from the interposed condition ( FIG. 3B ) to the stowed position ( FIG. 3C ) and exposes the internal bore  112  of the sleeve  110  to the longitudinal bore  102  of the housing  100 . 
     The seat mechanism  130  comprises an arm  135  with a pivot  136  movable in a turned slot  138 . As the freed seat  132  is pushed downward, the pivot  136  slides in the turned slot  138 , and the arm  135  pivots about the pivot  136  to stow the seat  132  in the stowed condition in a side pocket  118  of the sleeve  110 . As shown, the seat  132  can be heavier toward one side and/or may define a side surface area to catch passing flow to help rotate the seat  132 . This may require the seat  132  to be eccentrically located in the sleeve  110 , but this is not necessary depending on the size of the tool  50 A. 
     Once pivoted, the seat  132  can then be locked in place. For example, the arm  135  can spring past a biased shoulder  137  that then holds the seat  132  stowed. In the end, the diverter tool  50 A as shown in  FIG. 3C  provides a full bore therethrough for passage of other tools, cement plugs, darts, etc. There is no need for these additional tools, cement plugs, darts and the like used in subsequent operations to pass through a restricted ball seat. Moreover, because the plug B is stowed, there are no complications downhole that may be caused its release. 
     The seat mechanism  130  can include an alternative form in which the seat  132  is pivotably attached to the sleeve  110  with a hinge and pivots open in response to the required fluid pressure. In such a case, the plug B in the seat opening  134  remains exposed to the longitudinal bore  102  and could come loose should the plug B not be sufficiently extruded/captured in the opening  134 . Such an arrangement may benefit from an additional sleeve (not shown) slideable in the internal bore  112  to cover the exposed plug B in the seat  132  once pivoted. 
     With the sleeve  110  locked in the closed position as in  FIG. 3C , the tool  50 A can eventually be reset once retrieved at surface by accessing the lock ring  140  through the bypass ports  104  and compressing the ring  140  to release the sleeve  110  to shift open. This ability to reset the sleeve  110  open can also be used to perform a pretest of the diverter tool  50 A before it is actually run downhole to install casing. For example, operators at the surface can shift the sleeve  110  closed by mechanically overcoming the biasing element  120  so the seals and integrity of the closed tool  50 A can be pretested. Once testing is complete, the tool  50 A can then be reset open by compressing the ring  140  to release the sleeve  110  to shift open. The seat mechanism  130  would be left unsheared and unpivoted during the testing. 
       FIG. 4  illustrates a cross-sectional view of another embodiment of a diverter tool  50 B of the present disclosure.  FIGS. 5A-5B  illustrates cross-sectional details of the diverter tool  50 B in  FIG. 4 ,  FIG. 6  illustrates a perspective view of portion of a sleeve in the diverter tool  50 B in  FIG. 4 , and  FIGS. 7A-7B  illustrate end-sectional details of the diverter tool  50 B in  FIG. 4 . 
     Again, the diverter tool  50 B is used for reducing surge pressure when running casing or liner into a wellbore, as discussed above. The tool  50 B is operable with a plug (e.g., a ball) and includes a housing  100 , a sleeve  110 , and a seat mechanism  130 . The plug B can be launched from surface from a ball launcher or the like, or the plug B may be deployed with the tool  50 B and may be free to float above the seat mechanism  130 . 
     During use, the sleeve  110  is temporarily held opened relative to one or more bypass ports  104  inside the diverter tool  50 B. A running tool (not shown) having the diverter tool  50 B disposed thereon is used to run the casing into a wellbore. Any surge pressure passing uphole through the running string can be diverted out of the bypass ports  104  in the diverter tool  50 B until the casing is run to depth. A plug B (e.g., ball) is then launched down the running string to the diverter tool  50 B (or has been run in with the tool  50 B), and the plug B engages in a seat  132  of the seat mechanism  130  interposed in an internal bore  112  of the sleeve  110  in the diverter tool  50 B. The sleeve  110  is shifted closed relative to the bypass ports  104  by moving the sleeve  110  in the diverter tool  50 B with fluid pressure applied against the plug B seated in the seat  132 . 
     Once the sleeve  110  shifts, the sleeve  110  is locked closed. The seat  132  then rotates/pivots with the engaged plug B from an interposed position to a stowed position in the internal bore  112  of the sleeve  110 . At this point, additional operations can be performed. For example, operators can pump cement down the running string and through the diverter tool  50 B to cement the casing in the wellbore. Any needed cement plugs, darts, and the like can pass by the stowed seat  132  in the diverter tool  50 B. 
     As shown in  FIG. 4 , the housing  100  has a longitudinal bore  102  therethrough and has first and second ends  106 ,  108  for coupling to other components, such as pipe of a running string and running tool. The one or more bypass ports  104  are defined in the housing  100  and communicate the longitudinal bore  102  outside the housing  100 . 
     The sleeve  110  is movably disposed in the longitudinal bore  102  from an opened position ( FIG. 4 ) open relative to the bypass ports  104  to a closed position closed relative to the bypass ports  104 . Again, seals  115   a - b  between the sleeve  110  and longitudinal bore  102  seal off circumferentially above and below (upbore and downbore of) the bypass ports  104  when the sleeve  110  is closed. 
     The sleeve  110  has an internal bore  112  therethrough, and the seat mechanism  130  is disposed in the internal bore  112  of the sleeve  110 . The seat mechanism  130  includes a seat  132  with a seat opening  134  permitting fluid communication therethrough. In contrast to the previous arrangement of  FIG. 2A  in which the seat  132  is positioned downhole of the seals  115   a - b  for sealing off the ports  104 , the seat  132  for the tool  50 B of  FIG. 4  is positioned uphole of the seals  115   a - b  for sealing off the ports  104 . This means that the sleeve  110  can be shorter and that the sleeve  110  requires less shifting for the lower member  114   b  of the sleeve  110  to seal off the ports  104 . 
     As noted briefly above, the seat  132  is rotatable/pivotable from the interposed condition ( FIG. 4 ) to the stowed condition. The seat  132  in the interposed condition is interposed in the internal bore  112  and is configured to engage the dropped plug B in the seat opening  134  in a manner similar to that discussed above. 
     A temporary connection or fixture is disposed between the housing  100  and the sleeve  110  and holds the sleeve  110  in the opened position ( FIG. 4 ) opened relative to the bypass ports  104 . A number of temporary connections or fixtures between the housing  100  and the sleeve  110  can be used. In contrast to the previous embodiment, the tool  50 B does not include a biasing element. Instead, the sleeve  110  is held with a temporary connection or fixture using one or more radially arranged shear pins  160  of the housing  100  disposed in one or more external slots  150  in the sleeve  110 . The radially arranged shear pins  160  are configured to shear in response to fluid pressure applied against the ball seated in the seat  132  of the tool  50 B, as discussed below. As will be appreciated with the benefit of the present disclosure, devices other than shear pins  160  can be used for the temporary fixture. For example, shear screws, shear rings, shear plates, and the like disposed between the housing  100  and the sleeve  110  can hold the sleeve  110  in the opened position opened relative to the bypass ports  104 . 
     To prevent vacuum lock of the sleeve  110  in the housing  100 , fluid can pass in the annulus between an upper member  114   a  of the sleeve  110  and the housing  110  by communicating through upper cross ports  116 . 
     During run-in as shown in  FIG. 4 , the diverter tool  50 B is in an opened condition with the sleeve  110  shifted uphole and with the bypass ports  104  exposed to the housing&#39;s bore  102 . Fluid flow uphole through the bore  102  can be diverted out of the bypass ports  104  into the surrounding annulus, as discussed above. Meanwhile, the radial pins  160  keep the sleeve  110  open. 
     As necessary, fluid flow can also pass downhole through the bore  102 . For example, once the conveyed casing (not shown) reaches depth, a plug B (e.g., ball) is pumped down the running string to the housing&#39;s bore  102 . The plug B engages the seat  132  in the interposed condition in the internal bore  112  of the sleeve  110 . Pumped fluid behind the seated plug B increases fluid pressure in the bore  102 . Pumped fluid can also act against piston areas of the sleeve  110 . 
     Continued applied pressure eventually shears the sleeve  110  free of the radial pins  160 , and the sleeve  110  shifts down to close the bypass ports  104 . In particular, the seat  132  engaged with the dropped plug B forces the sleeve  110  in the opened position ( FIG. 4 ) toward a closed position. The radially arranged pins  160  shear and free the sleeve  110  to shift from the opened position ( FIG. 4 ) toward the closed position. Eventually, a lock  140  engages between the sleeve  110  and the housing  100  and locks the sleeve  110  in the closed position. As shown here, the lock  140  comprises a split ring disposed external to the sleeve  140  for engaging in a circumferential groove  142  defined inside the bore  102  of the housing  100 . 
     The lower member  114   b  of the sleeve  110  shoulders against the housing&#39;s downhole end  108  and seals off the ports  104  with seals  115   a - b . The continued pressure no longer acting to shift the sleeve  110  then actuates the seat mechanism  130 . A temporary fixture between internal components of the seat mechanism  130  shears free. Again, a number of temporary connections or fixtures between the seat  132  and the sleeve  110  can be used. 
     For example, as best shown in  FIG. 5A , a shear ring  133  disposed about the seat  132  and engaged against a ledge  119  in the internal bore of the sleeve  110  shears in response to a level of applied fluid pressure. Once freed, the seat  132  in the sleeve  110  in the closed position rotates from the interposed condition ( FIGS. 4 &amp; 5A ) to a stowed position and exposes the internal bore  112  of the sleeve  110  to the longitudinal bore  102  of the housing  100  in a manner similar to that discussed above. 
     Again, the seat mechanism  130  comprises an arm  135  with a pivot  136  movable in a turned slot  138 . As the freed seat  132  is pushed downward, the pivot  136  slides in the turned slot  138 , and the arm  135  pivots about the pivot  136  to stow the seat  132  in the stowed condition in a side pocket  118 . The seat  132  can then be locked in place. For example, the arm  135  can spring past a biased shoulder  137  that then holds the seat  132  stowed. 
     In the end, the diverter tool  50 B provides a full bore therethrough for passage of other tools, cement plugs, darts, etc. There is no need for these additional tools, cement plugs, darts and the like used in subsequent operations to pass through a restricted ball seat. Moreover, because the plug B is stowed, there are no complications downhole that may be caused by a released ball. 
     The seat mechanism  130  can include an alternative form in which the seat  132  is pivotably attached to the sleeve  110  with a hinge and pivots open in response to the required fluid pressure. In such a case, the plug B in the seat opening  134  remains exposed to the longitudinal bore  102  and could come loose should the plug B not be sufficiently extruded/captured in the opening  134 . Such an arrangement may benefit from an additional sleeve (not shown) slideable in the internal bore  112  to cover the exposed plug B in the seat  132  once pivoted. 
     With the sleeve  110  locked in the closed position, the tool  50 B can eventually be reset once retrieved at surface by overcoming the lock of the lock ring  140  to release the sleeve  110  to shift open. 
     To allow for initial assembly and testing of the sleeve  110  in the housing  110 , each of the shear pins  160  can be disposed in a slot  150  in the sleeve  110  that is transverse (i.e., the slots  150  extends circumferentially about the outside of the sleeve  110 ). Each transverse slot  150  can further comprise a longitudinal slot  152  extending therefrom in which the radial pin  160  is movable along. Looking at  FIG. 5B , portion of the sleeve&#39;s upper member  114   a  in the housing  100  is illustrated in side cross-section showing shear pins  160  disposed in the transverse slot  150  at the end of the longitudinal slot  152 .  FIG. 6  shows the sleeve&#39;s upper member  114   a  in an isolated perspective view, showing the transverse slot  150  having the longitudinal slot  152  extending therefrom. 
     As shown in  FIG. 7A , the transverse slot  150  includes a retainer clip  154 . During assembly steps, the retainer clip  154  permit passage of the radial pin  160  in a first (clockwise) direction into the transverse slot  150  from a proximal end the longitudinal slot  152 . With the sleeve&#39;s upper member  114   a  then configured for use as in  FIG. 7B , the retainer clip  154  prevent passage of the radial pin  160  in a second (counterclockwise) direction opposite the first direction. As shown, the radial pin  160  can be held with a retainer  162  threaded and sealed in an external aperture  105  of the housing  100 . For its part, the retainer clip  154  is held in the transverse slot  150  with a retention pin  156 . 
     With this configuration of slots  150 ,  152 , retainer clips  154 , and pins  160 , the diverter tool SOB during assembly can first be set up for internal pressure testing. To do this, the sleeve  110  is shifted in the tool SOB to an internal pressure test position. For this position, the radial pins  160  are situated in the upper ends of the longitudinal slots  152  of the sleeve&#39;s upper member  114   a  with the sleeve  110  shifted to a closed condition relative to the bypass ports  104 . Fluid pressure down the bore  102  of the housing  100  can test the pressure integrity of seals in the tool SOB, such as the seals  115   a - b  sealing between the sleeve&#39;s lower member  114   b  and the bypass ports  104 . The seat mechanism  130  remains unsheared and unpivoted in the testing. 
     After testing, the tool  50 B can then be placed in an operational condition, as shown in  FIG. 4 . To do this, the sleeve  110  is pulled upward in the housing  100  and is rotated a partial turn clockwise. When the sleeve  110  is pulled, the radial pins  160  ride along the longitudinal slots  152  and reach the retainer clips  154 , as shown in  FIG. 7A . Then, when the sleeve  110  is turned as shown in  FIG. 7B , the radial pins  160  spring past the retainer clips  154 , which then prevent the sleeve  110  from rotating counterclockwise in a manner discussed above. 
     Although less desirable in terms of machining and assembly, the arrangement of pins  160  and slots  150  between the sleeve  110  and the housing  100  can be reversed. In this case, the longitudinal bore  102  of the housing  100  can define the slots  150 , and the sleeve  110  can have the pins  160  extending radially outward for engagement in the slots. 
       FIG. 8A  illustrates a cross-sectional view of yet another embodiment of a diverter tool  50 C of the present disclosure.  FIGS. 8B-8C  illustrate details of the diverter tool  50 C in  FIG. 8A . Finally,  FIGS. 9A-9C  illustrate cross-sectional details of the diverter tool  50 C during stages of operation. 
     Again, the diverter tool  50 C is used for reducing surge pressure when running casing or liner into a wellbore, as discussed above. The tool  50 C is operable with a plug (e.g., a ball B) and includes a housing  100 , a sleeve  110 , and a seat mechanism  130 . The plug B can be launched from surface with a ball launcher or the like, or the plug B may be deployed with the tool  50 C and may be free to float above the seat mechanism  130 . Many of the features of the diverter tool  50 C are similar to those discussed above with reference to  FIGS. 4 through 7B . 
     Briefly, the sleeve  110  during use is temporarily held opened relative to one or more bypass ports  104  inside the diverter tool  50 C ( FIG. 8A ). A running tool (not shown) having the diverter tool  50 C disposed thereon is used to run the casing into a wellbore. Any surge pressure passing uphole through the running string can be diverted out of the bypass ports  104  in the diverter tool  50 C until the casing is run to depth. A plug B (e.g., ball) is then launched down the running string to the diverter tool  50 C (or has been run in with the tool  50 C), and the plug B engages in a seat  132  of the seat mechanism  130  interposed in an internal bore  112  of the sleeve  110  in the diverter tool SOB. The sleeve  110  is shifted closed relative to the bypass ports  104  by moving the sleeve  110  in the diverter tool  50 C with fluid pressure applied against the plug B seated in the seat  132  ( FIG. 9B ). 
     Once the sleeve  110  shifts, the sleeve  110  is locked closed. The seat  132  then rotates/pivots with the engaged plug B from an interposed position to a stowed position in the internal bore  112  of the sleeve  110  ( FIG. 9C ). At this point, additional operations can be performed. For example, operators can pump cement down the running string and through the diverter tool  50 C to cement the casing in the wellbore. Any needed cement plugs, darts, and the like can pass by the stowed seat  132  in the diverter tool  50 C. 
     As shown in  FIG. 8A , the housing  100  has a longitudinal bore  102  therethrough and has first and second ends  106 ,  108  for coupling to other components, such as pipe of a running string and running tool. The one or more bypass ports  104  are defined in the housing  100  and communicate the longitudinal bore  102  outside the housing  100 . 
     The sleeve  110  is movably disposed in the longitudinal bore  102  from an opened position (e.g.,  FIG. 8A ) open relative to the bypass ports  104  to a closed position (e.g.,  FIG. 9B-9C ) closed relative to the bypass ports  104 . Again, seals  115   a - b  between the sleeve  110  and longitudinal bore  102  seal off circumferentially above and below (upbore and downbore of) the bypass ports  104  when the sleeve  110  is closed. 
     The sleeve  110  has an internal bore  112  therethrough, and the seat mechanism  130  is disposed in the internal bore  112  of the sleeve  110 . The seat mechanism  130  includes a seat  132  with a seat opening  134  permitting fluid communication therethrough. In contrast to the previous arrangement of  FIG. 4 , the seat  132  is positioned downhole of the seals  115   a - b  for sealing off the ports  104 . This means that the sleeve  110  may be longer and that the sleeve  110  may require more shifting for the lower member  114   b  of the sleeve  110  to seal off the ports  104 . 
     As noted briefly above, the seat  132  is rotatable/pivotable from the interposed condition ( FIGS. 8A-8C ) to the stowed condition ( FIG. 9C ). The seat  132  in the interposed condition is interposed in the internal bore  112  and is configured to engage the plug B in the seat opening  134  in a manner similar to that discussed above. 
     A temporary connection or fixture is disposed between the housing  100  and the sleeve  110  and holds the sleeve  110  in the opened position ( FIGS. 8A-8C ) opened relative to the bypass ports  104 . A number of temporary connections or fixtures between the housing  100  and the sleeve  110  can be used. Similar to the previous embodiment, the sleeve  110  is held with a temporary connection or fixture using one or more radially arranged shear pins  160  of the housing  100  disposed in one or more external slots  150  in the sleeve  110 . The radially arranged shear pins  160  are configured to shear in response to fluid pressure applied against the ball seated in the seat  132  of the tool  50 C, as discussed below. As will be appreciated with the benefit of the present disclosure, devices other than shear pins  160  can be used for the temporary fixture. For example, shear screws, shear rings, shear plates, and the like disposed between the housing  100  and the sleeve  110  can hold the sleeve  110  in the opened position opened relative to the bypass ports  104 . 
     During run-in as shown in  FIG. 8A , the diverter tool  50 C is in an opened condition with the sleeve  110  shifted uphole and with the bypass ports  104  exposed to the housing&#39;s bore  102 . Fluid flow uphole through the bore  102  can be diverted out of the bypass ports  104  into the surrounding annulus, as discussed above. Meanwhile, the radial pins  160  keep the sleeve  110  open. To prevent vacuum lock of the sleeve  110  in the housing  100 , fluid can pass in the annulus between an upper member  114   a  of the sleeve  110  and the housing  110  by communicating through upper cross ports  116 . 
     As necessary, fluid flow can also pass downhole through the bore  102 . For example, once the conveyed casing (not shown) reaches depth, a plug B (e.g., ball) is pumped down the running string to the housing&#39;s bore  102 . The plug B engages the seat  132  in the interposed condition in the internal bore  112  of the sleeve  110 . Pumped fluid behind the seated plug B increases fluid pressure in the bore  102 . Pumped fluid can also act against piston areas of the sleeve  110 . 
     Continued applied pressure eventually shears the sleeve  110  free of the radial pins  160 , and the sleeve  110  shifts down to close the bypass ports  104 . In particular, the seat  132  engaged with the plug B forces the sleeve  110  in the opened position ( FIGS. 8A-8C ) toward a closed position ( FIG. 9B ). The radially arranged pins  160  shear and free the sleeve  110  to shift from the opened position ( FIGS. 8A-8C ) toward the closed position ( FIG. 9B ). Eventually, a lock  140  engages between the sleeve  110  and the housing  100  and locks the sleeve  110  in the closed position. As shown here, the lock  140  comprises a split ring disposed external to the sleeve  140  for engaging in a circumferential groove  142  defined inside the bore  102  of the housing  100 . 
     As shown in  FIG. 9B , the lower member  114   b  of the sleeve  110  shoulders against the housing&#39;s downhole end  108  and seals off the ports  104  with the seals  115   a - b . The continued pressure no longer acting to shift the sleeve  110  then actuates the seat mechanism  130  as shown in  FIG. 9C . A temporary fixture between internal components of the seat mechanism  130  shears free. Again, a number of temporary connections or fixtures between the seat  132  and the sleeve  110  can be used. 
     For example, as best shown in  FIGS. 8B-8C , a shear ring  133  disposed about the seat  132  and engaged against a ledge  119  in the internal bore of the sleeve  110  can shear in response to a level of applied fluid pressure. Once freed, the seat  132  in the sleeve  110  in the closed position rotates from the interposed condition ( FIG. 9B ) to a stowed position ( FIG. 9C ) and exposes the internal bore  112  of the sleeve  110  to the longitudinal bore  102  of the housing  100  in a manner similar to that discussed above. 
     Again, the seat mechanism  130  comprises an arm  135  with a pivot  136  movable in a turned slot  138 . As the freed seat  132  is pushed downward, the pivot  136  slides in the turned slot  138 , and the arm  135  pivots about the pivot  136  to stow the seat  132  in the stowed condition in a side pocket  118 . The seat  132  can then be locked in place. For example, the arm  135  can spring past a biased shoulder  137  that then holds the seat  132  stowed. 
     In the end, the diverter tool  50 C provides a full bore therethrough for passage of other tools, cement plugs, darts, etc. There is no need for these additional tools, cement plugs, darts and the like used in subsequent operations to pass through a restricted ball seat. Moreover, because the plug B is stowed, there are no complications downhole that may be caused by a released ball. 
     The seat mechanism  130  can include an alternative form in which the seat  132  is pivotably attached to the sleeve  110  with a hinge and pivots open in response to the required fluid pressure. In such a case, the plug B in the seat opening  134  remains exposed to the longitudinal bore  102  and could come loose should the plug B not be sufficiently extruded/captured in the opening  134 . Such an arrangement may benefit from an additional sleeve (not shown) slideable in the internal bore  112  to cover the exposed plug B in the seat  132  once pivoted. 
     With the sleeve  110  locked in the closed position, the tool  50 C can eventually be reset once retrieved at surface by overcoming the lock of the lock ring  140  to release the sleeve  110  to shift open. 
     To allow for initial assembly and testing of the sleeve  110  in the housing  110 , each of the shear pins  160  can be disposed in a slot  150  in the sleeve  110  that is transverse (La, the slots  150  extends circumferentially about the outside of the sleeve  110 ). Each transverse slot  150  can further comprise a longitudinal slot  152  as shown in  FIGS. 8A-8B  extending therefrom in which the radial pin  160  is movable along. Features of the transverse slots  150 , the longitudinal slots  152 , the radial pins  160 , retainers ( 162 ), retainer clips ( 154 ), retention pins ( 156 ), etc. for this tool  50 C can be similar to the features discussed above with reference to the other diverter tool  50 B as in  FIGS. 7A-7B  so that they are not repeated here. 
     As before with this configuration of slots  150 ,  152 , retainer clips ( 154 ), pins  160 , etc., this diverter tool  50 C can first be set up for internal pressure testing during assembly. To do this as shown in  FIG. 9A , the sleeve  110  is shifted in the tool  50 C to an internal pressure test position before the radial pins  160  are retained in the transverse slots  150 . For this position, the radial pins  160  are situated in the upper ends of the longitudinal slots  152  of the sleeve&#39;s upper member  114   a  with the sleeve  110  shifted to a closed condition relative to the bypass ports  104 . Fluid pressure down the bore  102  of the housing  100  can test the pressure integrity of seals in the tool  50 C, such as the seals  115   a - b  sealing between the sleeve&#39;s lower member  114   b  and the bypass ports  104 . The seat mechanism  130  remains unsheared and unpivoted in the testing. 
     After testing, the tool  50 C can then be placed in its operational condition, as shown in  FIG. 8A . To do this, the sleeve  110  is pulled upward in the housing  100  and is rotated a partial turn clockwise. When the sleeve  110  is pulled, the radial pins  160  ride along the longitudinal slots  152  and reach the retainer clips ( 154 ). Then, when the sleeve  110  is turned, the radial pins  160  spring past the retainer clips ( 154 ), which then prevent the sleeve  110  from rotating counterclockwise in a manner discussed above. 
     With the tool  50 C set in the operational condition as shown in  FIGS. 8A-8C , the upper seal  115   a  is not exposed to a pressure differential so damage to the seal  115   a  can be mitigated. The upper seal  115   a  can thereby remain ready for eventual use. In particular, the upper seal  115   a  as shown in  FIG. 8B  on the sleeve  110  is disposed at an increased section  103   a  of the housing&#39;s bore  102 . Tubing pressure in the tool  50 C entering the upper cross ports  116  on the sleeve&#39;s upper member  114   a  can reach the upper seal  115   a  and can act in the annulus between the sleeve  110  and bore  102  on one of the sides of the upper seal  115   a . Meanwhile, tubing pressure in the tool  50 C can also enter a lower cross port  113  in the sleeve  110  near the seat  130  and can reach the upper seal  115   a  to act in the annulus between the sleeve  110  and bore  102  on the seal&#39;s other side. In a similar way, the lower seal  115   b  is not exposed to a pressure differential because the tubing pressure is similarly communicated to both sides of the seal  115   b  in the annulus between the sleeve  110  and bore  102 . The lower seal  115   b  can thereby remain ready for eventual use. 
     A third seal  115   c , however, in the operational condition does engage a polished surface  103   b  of the housing&#39;s bore  102 . This third seal  115   c  can ensure that tubing pressure entering the lower cross port  113  does not leak further downhole. The lower cross port  113  can be sized so as to not become plugged with debris from operation fluids. Moreover, the lower cross port  113  could be packed with grease, or other features could be used. 
     The arrangement of the seals  115   a - c  and the lower cross port  113  allow the seals  115   a - b  to be tested during assembly as in  FIG. 9A . Also, the arrangement allows the seals  115   a - b  to be tested during the process of closing the sleeve  110 . As shown in  FIG. 9B , the plug B has been engaged in the seat  132 , and fluid pressure applied against the seated plug B has sheared the shear pins  160 . As a result, the sleeve  110  has shifted closed so that the seals  115   a - b  engage the polished bore surface  130   b  and straddle the bypass port  104 . Before shearing the seat  132  free with increased pressure, the seals  115   a - b  in  FIG. 9B  are subject to a pressure differential that allows their integrity to be determined. 
     In particular, the upper seal  115   a  engages the bore surface  103   b  above (upbore of) the bypass port  104  so that the seal  115   a  is exposed to tubing pressure communicated from the sleeve&#39;s upper cross ports  116  and is exposed to borehole pressure communicated from the housing&#39;s port  104 . The lower seal  115   b  engages the bore surface  103   b  below (downbore of) the bypass port  104  so that the seal  115   b  is exposed to tubing pressure communicated from the sleeve&#39;s lower cross port  113  and to borehole pressure communicated from the housing&#39;s port  104 . Identified leakage can indicate that the integrity of the seals  115   a - b  is compromised so that operators can take remedial actions. As is understood, knowing the integrity of the seals  115   a - b  both before deployment and during use downhole can prevent a number of disadvantageous outcomes. 
     For its part, the third seal  115   c  could conceivably fail, which may allow for leakage of tubing pressure downhole. From surface, this leakage of the third seal  115   c  may be confused as being leakage from the primary seals  115   a - b  even though the primary seals  115   a - b  are functionally normally. For this reason, additional seals could be provided as a redundancy to at least this third seal  115   c . Of course, any number of redundant seals could be used for the seals  115   a - c.    
     Eventually, with the seals  115   a - b  sealing the ports  104 , the increased fluid pressure can shear the seat  132  free to pivot from the interposed condition ( FIG. 9B ) to the stowed position ( FIG. 9C ). The tool  50 C as shown in  FIG. 9C  is now closed and provides a fullbore for passage of cementing tools and the like during further operations. 
     The foregoing description of preferred and other embodiments is not intended to limit or restrict the scope or applicability of the inventive concepts conceived of by the Applicants. It will be appreciated with the benefit of the present disclosure that features described above in accordance with any embodiment or aspect of the disclosed subject matter can be utilized, either alone or in combination, with any other described feature, in any other embodiment or aspect of the disclosed subject matter. 
     In exchange for disclosing the inventive concepts contained herein, the Applicants desire all patent rights afforded by the appended claims. Therefore, it is intended that the appended claims include all modifications and alterations to the full extent that they come within the scope of the following claims or the equivalents thereof.