Patent Abstract:
An apparatus for reducing pressure surges in a wellbore comprising a body having a bore therethrough, the bore providing a fluid path for wellbore fluid between a first and second end of the body, at least one fluid path permitting the wellbore fluid to pass between the bore and an annular area formed between an outer surface of the body and the walls of a wellbore therearound, and a number of closure mechanisms whereby the at least one fluid path is selectively closable to the flow of fluid.

Full Description:
BACKGROUND OF THE INVENTION  
         [0001]    1. Field of the Invention  
           [0002]    The present invention generally relates to an apparatus and a method for reducing downhole surge pressure while running a liner into a wellbore. More particularly, the invention relates to an apparatus and a method for reducing surge pressure by opening and closing ports to allow fluid and mud flow to flow within an annulus between the wellbore and a circulation tool.  
           [0003]    2. Description of the Related Art  
           [0004]    For a long time, the oil-well industry has been aware of the problem created when lowering a liner string at a relatively rapid speed in drilling fluid. This rapid lowering of the liner string results in a corresponding increase or surge in the pressure generated by the drilling fluid below the liner string. A liner string being lowered in to a wellbore can be analogized to a tight fitting plunger being pushed in to a tubular housing. Although there is a small annular clearance between the liner and the wellbore, the fluid bypass rate is limited. The faster the liner is lowered, the more fluid builds up below it due to the limited bypass and this creates an increased pressure or surge below the liner as it is lowered in to the wellbore. Of particular concern is surge related damage due to exposed formation below the liner string.  
           [0005]    This surge pressure has been problematic to the oil-well industry in that it has many detrimental effects. Some of these detrimental effects are 1) lost volume of drilling fluid; it is not unheard of to lose 50,000 or more barrels of fluid while running the liner, wherein present costs are $40 to $400,a barrel depending on its mixture, 2) resultant weakening and/or fracturing of the formation when this surge pressure in the borehole exceeds the formation fracture pressure, particularly in highly permeable formations, 3) loss of cement to the formation during the cementing of the liner in the borehole due to the weakened and, possibly, fractured formations which result from the surge pressure on those formations, and 4) differential sticking of the drill string or liner being run into a formation during oil-well operations, that is, when the surge pressure in the borehole is higher than the formation fracture pressure, the loss of drilling fluid to the formation allows the drill string or liner to be pulled against the permeable formation downhole thereby sticking the drill string or liner to the permeable formation.  
           [0006]    This surge pressure problem is further exasperated when running tight clearance liners or other apparatus in the existing casing. For example, clearances between a typical liner&#39;s Outer Diameter (O.D.) and a casing&#39;s Inner Diameter (I.D.) are ½″ to ¼″. The reduced annular area in these tight clearance liner runs results in correspondingly higher surge pressures and heightened concerns over their resulting detrimental effects.  
           [0007]    Typically, surge pressures are minimized by decreasing the running speed of the drill string or liner downhole to maintain the surge pressures at acceptable levels. An acceptable level is a level at least where the drilling fluid pressure, including the surge pressure, is at least less than the formation fracture pressure. The problem with decreasing running speed is that more time is required to complete the liner placement. That is economically disadvantageous in today&#39;s environment where drilling rig rates can be as high as $300,000.00 per day.  
           [0008]    U.S. Pat. No. 5,960,881, discloses a downhole surge pressure reduction system to reduce the pressure buildup while running in liners. The surge reduction device disclosed therein is located immediately above the top of the liner. Plugging of the float valve at the lower end of the liner can, render the surge pressure reduction system of the &#39;881 patent ineffective.  
           [0009]    U.S. Pat. No. 2,947,363, proposes a fill-up valve for well strings that includes a movable sleeve in a housing. As taught by the &#39;363 patent, after a predetermined amount of fluid has been admitted, a ball is dropped on the sleeve and pressure applied to move the sleeve downwardly to misalign the ports to a closed port position. Fingers on the sleeve are stated to interlock with teeth to stop upward movement of the sleeve. While the ball could be moved up the housing by an upward flow of pressurized fluid, the ball cannot be blown or forced downwardly through the sleeve. Therefore, this fill-up valve does not provide full opening for inner drill string work to be accomplished at a depth below the fill-up valve.  
           [0010]    U.S. Pat. No. 3,376,935, proposes a well string that is partially filled with fluid during a portion of its descent into a well and, thereafter, selectively closed against the entry of further fluid while descent of the well string continues (&#39;935 patent, col. 1, ins 25 to 47). As best shown in FIGS.  3  to  5  of the &#39;935 patent, a ball seats on a ball seat to move the sleeve downwardly to a closed port position. Upon a predetermined pressure the seat deforms, as shown in FIG. 5, to allow the ball to pivot the flapper valve downwardly and pass out of the housing  3  (&#39;935 patent, col. 6, Ins 32 to 60). The flapper check valve prevents flow of fluid (e.g. drilling fluid) up through the housing (&#39;935 patent, col. 4, ins 60 to 73), whether or not the sleeve is in the open port position (FIG. 3) or the closed port position (FIGS. 2, 4 and  5 ). Additionally, as best shown in FIGS. 1 and 2, the inside diameter of the sleeve is less than the inside diameter of the drill string or pipe interior, thereby creating a restriction in the string. While this tool allows movement of fluids from the annulus, adjacent the ports of the tool, to flow up the drill string, the surge pressure created by apparatus uses, below the tool, is not alleviated.  
           [0011]    U.S. Pat. No. 4,893,678, proposes a multiple-set downhole tool and method of use of the tool. While confirming the oil-well industry desire for “full bore” opening in downhole equipment, the &#39;678 patent proposes the use of a ball to move a sleeve to misalign a port in the sleeve and a passage in the housing. Additionally, while the ball can even be “blown out,” the stated purpose of the apparatus in the &#39;678 patent is to activate a tool, and more particularly, to inflate an elastomeric packer (&#39;678 patent, col. 1, ins 20 to 25 and col. 3, in 14 to col. 4, In 42), not to reduce surge pressure while running a drill string with a casing liner packer or other apparatus downhole.  
           [0012]    A Model “E” “Hydro-Trip Pressure Sub” No. 799-28, distributed by Baker Oil Tools, a Baker Hughes company of Houston, Tex., is installable on a string below a hydraulically actuated tool, such as a hydrostatic packer to provide a method of applying the tubing pressure required to actuate the tool. To set a hydrostatic packer, a ball is circulated through the tubing and packer to the seat in the “Hydro-Trip Pressure Sub,” and sufficient tubing pressure is applied to actuate the setting mechanism in the packer. After the packer is set, a pressure increase to approximately 2,500 psi shears screws to allow the ball seat to move down until fingers snap back into a groove. The sub then has a full opening, and the ball passes on down the tubing.  
           [0013]    U.S. Pat. No. 5,244,044, proposes a similar catcher sub using a ball to operate pressure operated well tools in the conduit above the catcher sub. However, neither the Baker nor the &#39;044 tool provides for reduction of surge pressure by diverting fluid flow into the annulus between the drill string and casing.  
         SUMMARY OF THE INVENTION  
         [0014]    The present invention relates to a downhole surge pressure reduction system for use in the oil-well industry. Typically, the tool that is the subject of the invention is disposed at an upper end of a string of tubulars or liner to be cemented in a wellbore. Installed below the tool is typically a liner hanger running tool that temporarily holds the liner string in the wellbore prior to cementing.  
           [0015]    More specifically, this invention relates to an apparatus and a method for reducing surge pressure while running tubulars into a wellbore. In one embodiment, the invention provides a means of pre-selecting a desired hydrostatic wellbore pressure at which a rupture disc will burst causing wellbore fluid to activate a piston that will seal a number of bypass ports. With the piston activated, the tool is effectively closed, and the circulation tool may proceed with cementing or other needed processes.  
           [0016]    Alternatively, the tool may be closed by shearing a breakable plug. Shearing of the breakable plug allows fluid to activate the piston in the same manner as if a rupture disc had burst. Both the rupture disc and the breakable plug, or knock-off plug, are forms of frangible members.  
           [0017]    In other embodiments, the tool comprises numerous closure members for sealing the circulation or bypass ports. Particularly, these closure members may consist of a breakable piston sleeve or a sleeve lowered or dropped from the surface. Also required is a closing mechanism that consists of the closure member as well as the equipment required to orient and place the closure member. As envisioned, the tool may be closable by more than one method. Thus, it is one object of this invention to provide a tool capable of reducing pressure surges in a wellbore wherein the tool itself is selectively closable. 
       
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0018]    So that the manner in which the above recited features of the present invention are attained and can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to the embodiments thereof which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.  
         [0019]    [0019]FIG. 1 is an elevation view of the present invention schematically showing the circulation tool described herein located within a representative borehole.  
         [0020]    [0020]FIG. 2 is a partial section view of a single operation tool, envisioned in one embodiment of this invention, prior to make-up. As shown, the threaded sleeve is in an open position allowing an operator access to the rupture disc, not shown, and a knock-off pin, or break plug. Also visible are the bypass ports in an open position.  
         [0021]    [0021]FIG. 3 is a partial section view of a single operation tool, envisioned in one embodiment of this invention, after to make-up. This view is also representative of the tool in use downhole prior to rupturing of the disc, and actuation of the piston. Also visible are the bypass ports in an open position.  
         [0022]    [0022]FIG. 4 is a partial section view of a single operation tool, envisioned in one embodiment of this invention, after the rupture disc has blown, and the showing the piston in its downward position closing off the bypass ports.  
         [0023]    [0023]FIG. 5 is a partial section view of a single operation tool, envisioned in one embodiment of this invention, with a shear bar used to shear the knock-off pin as an alternative method to allow fluid flow into the cavity.  
         [0024]    [0024]FIG. 6 is a partial section view of an electrically operated single operation tool, a separate embodiment of the present invention.  
         [0025]    [0025]FIG. 7 is a partial section view of the electrically operated single operation tool, after the heating coil has melted or burned the wire. As shown, the small piston or plug that was held being in place and sealing the hydrostatic pressure chamber from the lower atmospheric chamber has lowered and thus allowed the wellbore fluid a pathway to enter the lower atmospheric chamber.  
         [0026]    [0026]FIG. 8 is a partial section view of the tool showing an alternative non-hydraulic method of closing the bypass ports. In this view, the bypass ports are mechanically closed by way of a bridge sleeve that has been lowered from the surface by means of a running tool.  
         [0027]    [0027]FIG. 9 is a partial section view of the previous tool showing the bridge plug in position and the bypass ports closed.  
         [0028]    [0028]FIG. 10 is a partial section view of another embodiment of the present invention, in this case, showing another alternative non-hydraulic method of closing the bypass ports. In this embodiment, the piston sleeve consists of an upper body and a lower body connected by means of a shear pin. As visible on the lower piston body is a recess or undercut that will mate with the running tool&#39;s spring loaded dogs. The running tool will shear the lower piston body away from the upper piston body and place the lower piston body in position to seal the bypass ports.  
         [0029]    [0029]FIG. 11 is a partial section view of the previous embodiment wherein the running tool has mated with the lower piston body&#39;s recesses.  
         [0030]    [0030]FIG. 12 is a partial section view of the tool showing the lower piston body sealing the bypass ports. As shown the lower piston body has upper and lower o-rings and a locking mechanism that prevents the lower piston body from moving longitudinally within the tool.  
     
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT  
       [0031]    Generally shown in FIG. 1 are some of the components of the system of the present invention. Visible are a representative rig  2 , a borehole  10 , a formation  4 , an exposed formation  14 , and, a working string  8  above the tool of the present invention  100 . Schematically, fluid flows  12  through the bore  124  of the tool  100  and out the bypass ports  122  if open.  
         [0032]    [0032]FIG. 2 is a partial section view of a single operation tool  100  prior to make-up. As shown, the tool  100  comprises a bore  124  that provides a path for wellbore fluid to flow through the interior of the tool  100 . At lower end of the tool  100  are a series of bypass ports  122  that when open, as shown, allow a portion of the fluid entering the tool  100  to be diverted into an annulus between the drill string and casing (not shown). It is this additional fluid flow around the outer diameter of the tool  100  that reduces the induced surge pressure as the tool and a string of liners are run into a wellbore full of fluid.  
         [0033]    At an upper end of the tool  100  is located a rupture disc (not shown) that can be selected to burst at a predetermined pressure correlating to a predetermined depth within the wellbore. The rupture disc, a frangible member, fails due to a pressure differential between the wellbore fluid and an upper atmospheric chamber (not shown) formed around the rupture disc when the access sleeve  114  is closed. In operation, an operator would select the depth at which he needs the circulating tool to close, and from that he could correlate the pressure at which that depth would be associated with given all the known fluid and wellbore factors. The rupture disc  120  and knock-off pin  112  can be installed, inspected, and changed on the rig floor or anytime prior to the tool  100  being lowered into the wellbore.  
         [0034]    Also at the upper end of the tool  100  is an access sleeve  114  that is threadedly connected to the tool  100  and covers a knock-off pin  112  and the rupture disc. Surrounding the pin and rupture disc are a series of upper and lower o-rings  145  that seal the upper atmospheric chamber  113  when the access sleeve  114  is in the closed position.  
         [0035]    The knock-off pin  112 , another frangible member that is also known as a break plug, is designed to be a fail-safe to the rupture disc  120 , a back-up that if needed can be sheared by a shear-bar or tube  128  (FIG. 4) or similar device, known to those in the field. In this manner the bypass ports  122  are designed to be redundantly closeable, that is closeable by more than one means.  
         [0036]    [0036]FIG. 3 is a partial section view of the single operation tool  100  after make-up. The tool is made-up by installing the pre-selected rupture disc  120  and break plug  112 , then threadedly closing the sleeve in order to form the atmospheric chamber  113 . Visible is the rupture disc  120  located adjacent to the knock-off pin  112 . In this view, the access sleeve  114  has been lowered, closed, or sealed; and, the tool is now ready to be run into a wellbore with a string of liners.  
         [0037]    The access sleeve  114  is threadedly connected to the tool  100  and allows access to the break plug  112  and rupture disc  120 . In the open position both the disc  120  and the break plug or pin  112 , can be inspected, changed, removed, etc. In the closed position the access sleeve  114  seals off the pin and disc from external pressures and only allows inner wellbore fluid to act on them. Also of significance is that the access sleeve  114 , when closed, creates the flow cavity  113 . The flow cavity  113  is the annulus between the outer edge of the rupture disc  120  and the inner wall of the access sleeve  114 . This flow cavity  113  is linked to a flow path  150  that allows the fluid to act on a piston  110  and a piston set pin  125 . To further seal the flow cavity  113  there are a series of o-rings  145 , or other similar sealants, located above and below the flow cavity  113 .  
         [0038]    In normal operation, the fluid, at a pre-set pressure would flow through the rupture disc  120  and into the flow cavity  113 . From there the fluid passes into the flow path  150  to actuate the piston  110 . Alternative to the rupture disc  120 , a shear bar  128  could be dropped from the surface and thus actuate the fluid flow through the knock-off pin  112  and into the flow cavity  113 . The piston  110  is actuated when the fluid pressure overcomes the piston set pin  125  force holding the piston  110  to the flow housing  130 . Once this preset force is overcome, the piston  110  moves downward until its shoulder  140  comes to rest against the lower sub  106 . A bumper ring  107  attached to the piston&#39;s shoulder  140  makes contact with the lower sub  106  and this ring  107  cushions and dampens the vibrations caused by the piston  110  impacting the lower sub  106 . When the shoulder  140  of the piston is sitting on the lower sub  106 , the lower portion of the piston  110  effectively seals the bypass ports  122 .  
         [0039]    After fluid enters the flow cavity  113  through either the void caused by the burst of the rupture disc  120  or by the knock-off pin&#39;s  112  interior annulus, the fluid will flow through the flow cavity  113  and into the flow path  150  to act on the top of the piston  110 . The piston  110 , when not acted upon by the wellbore fluid pressure, is held in place by a piston set pin  125  attached to a non-moving flow housing  130 . Once fluid enters the flow path  150 , the fluid pressure will cause the piston set pin  125  to shear thus releasing the piston  110  in a rapid downward motion. The piston&#39;s shoulder  140  will bottom out on a lower sub  106 , located above the bypass ports  122 . The piston  110  accordingly seals the bypass ports  122  and fluid flow is then only permitted through the bore  124  of the tool  100 .  
         [0040]    [0040]FIG. 4 is a side view of the same single operation tool after the rupture disc  120  has burst, and showing the piston  110  in its downward position sealing off the bypass ports  122 . The piston  110 , as shown, has bottomed-out and its shoulder  140  is resting on the lower sub  106 . In this position, the piston  110  effectively closes the bypass ports  122  and prevents further fluid from flowing into the annulus by way of the ports  122 .  
         [0041]    [0041]FIG. 5 shows a side view of an alternative method, or redundant manner, of operating the tool by means of a shear bar  128  used to shear the knockoff pin  112  and allow fluid flow into the flow cavity  113 . In this view the fluid has entered the flow cavity  113  by way of the inner annulus or bore of the knock-off pin  112 . From there the fluid flows and acts on the piston in the same manner as if it had burst the rupture disc  120 . The shear bar  128  is generally annular in nature.  
         [0042]    [0042]FIG. 6 is a partial section view of an electrically operated single operation tool. In this embodiment, the tool  100  is remotely shifted to a closed position due to the response of an electric signal. As with the preferred embodiment described above, this tool goes in the hole in an open position.  
         [0043]    In this embodiment, a series of ports  160  connect the bore  124  with a hydrostatic pressure chamber  175 . The hydrostatic pressure chamber  175  contains a heating coil  170  and a wire  185  holding a frangible member, in this instance, a small piston  180 . The upper surface of the small piston  180  forms the lower boundary of the hydrostatic pressure chamber  175 . As named, the hydrostatic pressure chamber  175  fills with fluid and maintains the pressure of that fluid which is the same pressure of the fluid flowing through the bore  124 . A small piston  180  along with a number of o-rings  190  seal the hydrostatic pressure chamber  175  from the lower atmospheric chamber  109 . In this manner, a pressure differential is maintained between the top surface of the small piston  180  that is exposed to the wellbore fluid and the bottom surface of the small piston that is exposed to atmospheric pressure.  
         [0044]    In operation, a signal is sent from the surface, e.g. mud pulse, pipe pinning, fiber optics, magnetically charged fluid pumped from the surface, electric wire line run internally or externally to the tool, or other method known to those in the field, that causes a battery pack (not shown) to activate the heating coil  170  which is wrapped around the wire  185  holding the small piston or plug  180 . The wire  185  holding the small piston  180  is essentially keeping the hydrostatic pressure from pushing the small piston  180  into the lower atmospheric chamber  109  before it is required.  
         [0045]    When heated, the wire  185  is weakened and eventually breaks or loosens to a point that it can no longer support the small piston  180  and the hydrostatic pressure acting upon it. Thus, the heating of the wire  185  causes the small piston  180  to enter the lower atmospheric chamber  109 , exposing the piston  110  to hydrostatic pressure. As in the preferred embodiment, the hydrostatic head overcomes the force of the piston set pin  125  and causes the piston  110  to move downward and seal the bypass ports (not shown). As an alternative, a break plug  112  is attached to the lower atmospheric chamber  109 . If the signal fails to activate the battery pack a tube or shear bar, as in FIG. 5, can be dropped from the surface closing the tool.  
         [0046]    As shown in FIG. 7, the heating coil  170  has melted or weakened the wire  185  such that the hydrostatic pressure acting upon the top surface of the small piston  180  forces the small piston  180  into the lower atmospheric chamber  109 . Wellbore fluid is then allowed to make contact with the piston  110  and in the same manner as that described above, the piston  110  is forced downward and the bypass ports (not shown) are sealed.  
         [0047]    This embodiment may also be segmented such that a series of the tool described immediately above would be connected together, thus allowing for multiple or repeatable closings and openings. A first piston would close the bypass ports in the same manner as that described above in a single signal operated device. However, a second unique operation signal could then be sent to the tool and a second piston could be operated to open a lower set of bypass ports. The lower set of bypass ports are closed when a third signal is sent from the surface to move a third piston to close the tool. Additional opening and closing segments could be mated together in order to satisfy the needs of the operators. Advantageous to this system is its repeatability, its ability to open or close the bypass fluid path more than once.  
         [0048]    In yet another embodiment, not shown, the invention allows for multiple, or repeatable, openings and closings of the bypass ports during a single run downhole. In this embodiment, the use of a ratcheted sleeve, akin to that shown in FIGS. 4 and 5A- 5 F of the &#39;331 patent, would allow the tool to be repeatedly set in either an open or closed position while downhole. U.S. Pat. Nos. 5,743,311, and 6,116,336 are herein incorporated by reference. U.S. Pat. Nos. 5,743,311, and 6,116,336, refer to milling systems that allow for the repeated openings and closing of annular ports through the use of a ratcheted sleeve assembly.  
         [0049]    When running downhole it would be advantageous to be able to close the bypass ports  122  of the tool  100  if increased flow and or fluid is required in the annulus between the drill string or tool, or liner and the casing. In this embodiment, a ratcheted sleeve and accompanying piston assembly would be configured such that an operator on the surface could increases or decreases the fluid pressure in order to set the bypass ports in an open or closed position. In this manner the closing member could be selectively positioned for the desired result.  
         [0050]    In order to accomplish the aforementioned, the tool  100 , in addition to having bypass ports  122  would incorporate a piston assembly as taught in the pre-mentioned patents. The piston assembly would comprise a hollow body with a hollow piston mounted for reciprocal up and down rotative movement therein. The hollow body having an inwardly projecting lug.  
         [0051]    The lug would project through the body into a multi-branched slot of a sleeve. A ratcheted sleeve connected to the piston having a branched slot therearound which is moveable on the lug so that the ratcheted sleeve and the piston are movable to a plurality of positions. The branch slot having a plurality of positions including a plurality of recesses and positions for setting the tool, for instance there would be at least one position for circulate, and at least one position for non-circulating. The branched slot within the ratcheted sleeve would extend around the entire sleeve for cycling the piston assembly.  
         [0052]    In this manner, an operator on the surface could run the tool  100  downhole, and if needed could close and reopen the bypass ports  122  at any time prior to reaching his intended depth. Thus this embodiment provides for a cycling, and consequently an infinite number of openings and closings of the bypass ports  122 . The operator may selectively move the closing member in a back and forth manner, opening and closing the bypass ports  122  at will.  
         [0053]    To further describe this embodiment, the piston assembly would have a top bushing threadedly connected to the piston body. A bottom bushing would be connected to a lower end of the piston body. A piston would be movably mounted in a bore of the piston body. A spring abuts an upper end of the lower bushing and pushes against (upwardly) a thrust bearing set at a bottom of the ratchet sleeve (see FIG. 3C of the &#39;0331 patent). A thrust bearing set is disposed between a top of the ratchet sleeve and the lower end of the piston (see FIG. 3B of the &#39;0331 patent). The use of thrust bearings inhibits undesirable coiling of the spring and facilitates rotation of the ratchet sleeve. The thrust bearing sets may include a typical thrust bearing sandwiched between two thrust washers.  
         [0054]    As described, this embodiment allows for multiple openings and closings of the bypass ports during a single run downhole by means of a piston assembly which is responsive to increases and decreases in fluid pressure from the surface in order to ratchet a slotted lug into set positions correlating to whether the bypass ports  122  are open or shut.  
         [0055]    [0055]FIG. 8 is a partial section view of the tool showing an alternative non-hydraulic method of closing the bypass ports  122 . In this embodiment, the bypass ports  122  are mechanically sealed by way of a bridge sleeve  500  that has been lowered from the surface by means of a running tool assembly. As a mechanical alternative, yet another alternative means, to closing the bypass ports  122  the bridge sleeve  500  may be lowered or dropped from the surface. In this manner, if the rupture disc  120  or break-plug  112  fails to either operate or close the bypass ports  122  by way of a hydraulically operated piston  110  shown in FIGS.  2 - 4 , the bridge sleeve  500  could be lowered into the wellbore via wire-line, slick-line, coiled tubing, or other suitable means. During run-in, the bridge sleeve  500  attaches onto the end of the running tool  600 . Once in position, the bridge sleeve  500  locks onto a bottom sub  650  by means of a split ring latch  510 .  
         [0056]    The bridge sleeve itself has a series of upper and lower o-rings  520  to assist in fluidly sealing the bypass ports  122 . In further description, the bridge sleeve  500  comprises an upper and lower end. At the upper end, an under-cut  610  is formed so that the running tool assembly can latch onto the bridge sleeve  500 . At the lower end of the bridge sleeve  500 , a split-ring latch  510  is present which locks into the bottom sub  650  of the tool. The split-ring latch  510  locks the bridge sleeve  500  into the bottom sub  650  of the tool and prevents the bridge sleeve  500  from moving in an upward direction once positioned. To further prevent movement of the bridge sleeve  500 , particularly in a downward direction, the bridge sleeve  500  is designed with a lip  525  that mates with an interior shoulder  502  of the piston  110 . Thus, once positioned, the bridge sleeve  500  mechanically and fluidly seals the bypass ports  122 .  
         [0057]    After lowering the bridge sleeve  500  into position, the split-ring latch  510  locks into the bottom sub  650 . The running tool assembly is then pulled-up on and the bridge sleeve  500  is released so that the running tool assembly can be retrieved from the wellbore leaving the bridge sleeve  500  attached and locked to the tool.  
         [0058]    In further description, the running tool assembly comprises at least an upper body  600 , a latching member  610 , a mid-housing  640 , and a lower body  620 . A shear pin  630  holds the mid-housing  640  and lower body  620  of the running tool assembly together. The mid-housing  640  is threadedly connected to the upper body  600 . Disposed between the upper and lower bodies is a latching member  610  that is designed to lock into the under-cut  530  of the bridge sleeve  500 . The lower body  620  is formed with a lower profile member such that upon raising the running tool assembly, the profile member will grasp the latching member  610  and release the latching member  610  from the bridge sleeve  500 .  
         [0059]    In operation, when retrieving the running tool, an upward force shears the shear pin  630  and allows the lower body  620  to move in relationship to the latching member  610 . While in movement, the lower body  620  engages the latching member  610  and the entire assembly is brought to the surface.  
         [0060]    [0060]FIG. 9 is a partial section view of the previous tool showing the bridge plug in position and the bypass ports  122  closed. As shown, the bride sleeve  500  is locked into the bottom sub  650 . The upper and lower o-rings  520  of the bridge sleeve ensure that the bridge sleeve  500  maintains a sealing relationship with the tool so that no fluid may flow through the bypass ports  122  when it&#39;s in position.  
         [0061]    [0061]FIG. 10 is a partial section view of another embodiment of the present invention showing an alternative non-hydraulic method of closing the bypass ports  122 . In this embodiment, the piston consists of an upper body  900  and a lower body, or closing sleeve,  920  connected by means of a shear pin  910 . As visible on the lower piston body  920  is a recess or undercut  915  that will mate with a key seat tool (not shown). By way of mechanical force, the key seat tool will shear the lower piston body  920  away from the upper piston body  900 .  
         [0062]    In operation, a frangible member may not operate and an alternative non-hydraulic means of closing the bypass ports  122  is needed. As described herein and above, the features of this tool  100  allow more than one means of closing the bypass ports  122 .  
         [0063]    The detachable closing sleeve  920  requires the tool to be internally modified from the previous embodiments and/or closing methods. In this design, if the tool fails to close hydraulically then the key seat tool, part of a closing mechanism, is run into the wellbore on preferably coil tubing, electric wire line, or slick line with a set down acting jar, such as a spang jar.  
         [0064]    To further describe this embodiment, the key seat tool, shown in FIG. 11, typically comprises a spring loaded set of dogs that essentially spring into a specific profile. The key seat tool latches into the undercuts  915  of the lower piston body  920 . Application of impacts from the jars shears the pin  910  and moves the lower piston body, or closing sleeve,  920  down to seal the bypass ports  122 . The closing sleeve  122  latches into the lower sub  106  by means of a detent ring  917 , and the key seat tool is then retrieved. With the key seat tool out of the hole, normal cementing operations can proceed, including the use of standard cementing darts to launch cementing plugs in the liner.  
         [0065]    To further describe the key seat tool  300 , the key seat tool comprises an upper housing  300 , a bottom housing  320 , a back plate  305 , springs  310 , and keys or dogs  315 . The upper and lower housings are threadedly connected to the back plate  305 . The back plate contains recesses or positions for springs  310 . Located and placed on top of the springs  310  are keys or dogs  315 . These keys are designed to mate with the undercut profiles of with the closing sleeve  920 .  
         [0066]    In operation, the key seat tool will latch onto the recess  915  of the closing sleeve  920  and with an application of force from the running tool, the closing sleeve  920  will separate from the upper piston body  900  and move into a sealingly position around the bypass ports  122 . The closing sleeve  920  contains upper and lower o-rings  912  to seal the bypass ports  122 . Additionally, the closing sleeve  920  also contains a detent ring  917 . The detent ring  917  remains compressed while the closing sleeve  920  is in relation with the upper piston body  900 , as shown. After the closing sleeve  920  has been separated from the upper piston body  900  via the key seat tool, the detent ring  917  will maintain contact with the lower sub  106  until it reaches an annulus. At that position, the detent ring  917  expands outwardly and locks the closing sleeve  920  into position. Once the closing sleeve  920  is locked in a sealingly position around the bypass ports  122 , the key seat tool is disengaged from the closing sleeve  920  and brought back to the surface.  
         [0067]    [0067]FIG. 11 is a partial section view of the previous embodiment wherein the key seat tool  300  has mated with the closing sleeve&#39;s  920  recesses or undercuts  915 . The tool features a spring  310  loaded set of dogs  315  that latch into the recesses or undercuts of the inner diameter profile of the closing sleeve  915 . As shown, the dogs&#39; profiles are such that when the key seat tool  300  is retrieved from the bore  124 , the dogs can disengage the closing sleeve&#39;s undercuts  915 .  
         [0068]    [0068]FIG. 12 is a partial section view of the tool showing the lower piston body or closing sleeve  920  sealing the bypass ports. As shown, the closing sleeve  920  has upper and lower o-rings  912  and a locking mechanism, a detent ring  917 , which prevents the closing sleeve from moving longitudinally within the tool. In this position the closing sleeve is covering the bypass ports and along with its upper and lower o-rings  917  a fluid seal is achieved thus allowing fluid flow only through the bore  124  of the tool.  
         [0069]    As the forgoing illustrates, the invention reduces downhole surge pressure while running a liner string into a wellbore. It achieves that result by allowing fluid which flows through the relatively large inner diameter of the liner during run-in to exit the smaller inner diameter of the run-in string and travel through the annulus between the run in string and the wellbore. More particularly, the foregoing illustrates a surge reduction tool that incorporates redundancy into the means in which the tool may be operated, as well as, incorporating repeatable openings and closings. While the foregoing is directed to the preferred embodiment of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.

Technology Classification (CPC): 4