Patent Abstract:
The present invention generally relates to a plunger-type valve for use in a wellbore. The plunger-type valve is arranged to selectively allow fluid flow to enter and exit the valve in both directions. Subsequently, the plunger-type valve can be deactivated to selectively allow fluid flow in only one direction. The valve includes a body, at least one locking segment, a locking sleeve, at least one biasing member, a valve seat and a plunger.

Full Description:
BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates to a valve assembly for use in a wellbore. More particularly, the invention relates to a valve assembly that allows fluid flow to pass through the valve in either direction. More particularly still, the invention relates to a dual purpose valve assembly for controlling the fluid flow during installation of a casing in a wellbore and subsequently for use as float equipment to facilitate the injection of zonal isolation fluids. 
     2. Description of the Related Art 
     Hydrocarbon wells are conventionally formed one section at a time. Typically, a first section of wellbore is drilled in the earth to a predetermined depth. Thereafter, that section is lined with a tubular string, or casing, to prevent cave-in. After the first section of the well is completed, another section of well is drilled and subsequently lined with its own string of tubulars, comprised of casing or liner. Each time a section of wellbore is completed and a section of tubulars is installed in the wellbore, the tubular is typically anchored into the wellbore through the use of a wellbore zonal isolation fluid, like cement. Zonal isolation includes the injection of cement into an annular area formed between the exterior of the tubular string and the borehole in the earth therearound. Zonal isolation protects the integrity of the wellbore and is especially useful to prevent migration of hydrocarbons towards the surface of the well via the annulus. 
     Zonal isolation methods of string are well known in the art. Typically, the cement fluid is pumped down in the tubular and then forced up the annular area toward the surface. By using a different fluid above a column of the cement, the annulus can be completely filed with cement while the wellbore is substantially free of cement. Any cured cement remaining in the wellbore is drillable and is easily destroyed by subsequent drilling to form the next section of wellbore. 
     Float shoes and float collars facilitate the cementing of tubular strings in a wellbore. In this specification, a float shoe is a valve-containing apparatus disposed at or near the lower end of the tubular string to be cemented into in a wellbore. A float collar is a valve-containing apparatus that is installed at some predetermined location, typically above a shoe within the tubular string. In certain cases, float collars are required rather than float shoes. However, in this specification, the term float shoe and float collar will be used interchangeably. 
     The main purpose of a float shoe is to facilitate the passage of cement from the tubular to the annulus of the well while preventing the cement from returning or “u-tubing” back into the tubular due to gravity and fluid density of the liquid zonal isolation fluids. In its most basic form, the float shoe includes a one-way valve permitting fluid to flow in one direction through the valve, but preventing fluid from flowing back into the tubular from the opposite direction. The float shoes usually include a cone-shaped nose to prevent binding of the tubular string during run-in. 
     Typically, wellbores are full of fluid to protect the drilled formation of the borehole and aid in carrying out cuttings created by a drill bit. When a new string of tubulars is inserted into the wellbore, the tubulars must necessarily be filled with fluid to avoid buoyancy and equalize pressures between the inside and the outside of the tubular. For these reasons, a float shoe should have the capability to temporarily permit fluid to flow inwards from the wellbore as the tubular string is run into the wellbore and fills the tubular string with fluid. In one simple example, a springloaded, normally closed, one-way valve in a float shoe is temporarily propped in an open position during run-in of the tubular by a drillable object, which is thereafter destroyed and no longer affects the operation of the valve. 
     Other, more sophisticated solutions have been the use of a differential fill valve. The differential fill valve allows filling of the tubular and circulation by utilizing the differential pressure between the inner and the outer annulus of the tubular. Typically, the prior art differential fill valve comprises a first and second flapper valve and a sleeve. The flapper valves are bias closed by a spring. The sleeve is secured in place by shear pins and is shiftable from a first to a second position. In operation, the differential fill valve is disposed on the end of the first string of tubular then inserted into the wellbore. During run-in the sleeve is in the first position, which prevents the second flapper valve from operating. As subsequent strings of tubulars are inserted into the wellbore the first flapper valve in the differential flow valve opens and closes based upon the differential pressure, thereby allowing wellbore fluid to enter the tubular string. The volume of wellbore fluid entering the tubular string is predetermined to achieve a differential height between the wellbore fluid inside the tubular annulus and the wellbore fluid outside the tubular. The amount of fluid entering the tubular through the flapper valve is controlled by a spring selected to bias the first flapper valve closed. The process of allowing a predetermined volume to enter the tubular is what is commonly called in the industry as differentially filling the tubular. 
     After the entire string of tubulars is disposed downhole, the differential fill capability of the valve is deactivated to change the valve into a one-way check valve. Typically, deactivation is accomplished by dropping a weighted ball from the surface down the wellbore either by free-fall or pumped in by a fluid mechanism allowing the ball to land into the sleeve. At a predetermined pressure the pins that secure the sleeve in the first position shear and the sleeve is shifted axially downward to a second position. In the second position, the sleeve closes the first flapper valve and subsequently allows the second flapper valve to operate. The deactivated differential fill valve functions as a standard float valve as described in the above paragraphs. 
     There are several problems associated with the prior art devices. One problem occurs while dropping the weighted ball to deactivate the differential fill feature in a deviated wellbore (deviations greater than 30 degrees from vertical). Typically, the ball is allowed to drop free-fall or pumped into a ball seat located in a sleeve. After the ball lands in the ball seat, drilling fluid is pressurized to act against the ball seat to shift the sleeve to a second position, thereby allowing a permanent check valve mechanism to engage. The reliability of actuating balls in a deviated wellbore greater than 30 degrees decreases as the deviation increases. Additionally, actuating balls in a horizontal, or near horizontal (70 to 90 degrees) well become ineffective in performing their required function, which leads to an inoperable downhole tool. 
     Another problem associated with the prior art devices arises when the tool is no longer needed to facilitate the injection of cement and must be removed from the wellbore. Rather than de-actuate the tool and bring it to the surface of the well, the tool is typically destroyed with a rotating milling or drilling device. Generally, the tool is “drilled up” or reduced to small pieces that are either washed out of the wellbore or simply left at the bottom of the wellbore. As in the case with the prior art devices that comprise of many metallic components numerous trips in and out of the wellbore are required to replace worn out mills or drill bits. This process is time consuming and results in lost productivity time. 
     Another problem with the prior art devices is the inability to operate in high downhole pressures and temperatures. Typically, as the depth of the wellbore increases both downhole pressure and temperature also increase. The prior art devices having a flapper valve design cannot operate effectively in pressures in excess of 3,000 PSI. Additionally, the prior art devices cannot function properly in downhole temperatures in excess of 300° F. 
     There is a need for a plunger-type check valve that can operate effectively in deviated wells or nearly horizontal wells. There is a further need for a plunger-type check valve that is made of composite components, thereby minimizing milling operation time upon removal of a valve and subsequently reduce the wear and tear on the drill bit. There is yet a further need for a plunger-type check valve that can operate effectively in high downhole pressures and high temperatures. 
     SUMMARY OF THE INVENTION 
     The present invention generally relates to a plunger-type valve for use in a wellbore. In one aspect, the plunger type check valve can operate effectively in deviated or nearly horizontal wells. In another aspect, the plunger-type check valve is made out of composite components, thereby minimizing milling operation time upon removal of a valve and subsequently reduce the wear and tear on the drill bit. In yet another aspect, the plunger-type check valve can operate effectively in high downhole pressures and high temperatures. 
     The plunger-type valve is arranged to selectively allow fluid to enter and exit the valve in both directions. The invention includes a body, at least one locking segment, a locking sleeve, at least one biasing member, a valve seat, and a plunger. In one direction, fluid enters an upper end of the body of the valve and urges the plunger downward, thereby allowing the fluid to exit the bottom of the valve body. In another direction, fluid enters the bottom of the valve body and urges the seat upwards, thereby allowing the fluid to flow to the upper end of the valve body. 
     In another aspect, the plunger-type valve may be deactivated to selectively allow fluid to flow in only one direction. At a predetermined maximum flow rate, the locking sleeve and the valve seat is urged axially downward. The locking segment moves radially inward to secure the locking sleeve in a fixed position. In turn, the valve seat moves axially downward to a predetermined point in the body. In this manner, both the locking sleeve and valve seat are restricted from axial movement. Consequently, fluid may only enter the top of the valve body and exit the bottom of the valve body by urging the plunger downward. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     So that the manner in which the above recited features and advantages 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 therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. 
     FIG. 1 is a longitudinal cross-sectional view of one embodiment of a valve assembly at an end of a tubular in accordance with the present invention. 
     FIG. 2 is an enlarged cross-sectional view of the valve assembly in FIG.  1 . 
     FIG. 3 is a cross-sectional view of the valve assembly as the differential pressure moves the valve seat from the plunger to permit fluid to flow from the lower end to the upper end of the valve assembly. 
     FIG. 4 is a cross-sectional view of a valve assembly pumping fluid through the valve assembly without disengaging the differential fill feature. 
     FIG. 5 is a cross-sectional view of the valve assembly pumping fluid at a maximum flow rate to deactivate the differential fill feature. 
     FIG. 6 is a cross-sectional view of a deactivated valve assembly. 
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     FIG. 1 is a longitudinal cross-sectional view of one embodiment of the valve assembly  100  at an end of a tubular  102  in accordance with the present invention. As illustrated, the valve assembly  100  is disposed in a float shoe housing  104 . It should be noted that the valve assembly  100  may also be used in a float collar arrangement, or any other configuration in which a plunger-type check valve is required in a downhole tool. 
     Typically, the wellbore  103  contains wellbore fluid that has accumulated during the drilling operation. As the tubular  102  is inserted in the wellbore  103 , the fluid is displaced into an annulus  106  created between wellbore  103  and the tubular  102 . As it is lowered into the wellbore, the tubular  102  encounters a buoyancy force that impedes its downward movement. The force increases as the tubular is lowered further. At a predetermined differential pressure between the pressure exerted against the tubular and the internal pressure of the tubular, the valve assembly  100  allows wellbore fluid to enter an interior  108  of the tubular  102  to relieve the buoyancy forces acting on the tubular  102 . The amount of wellbore fluid entering the tubular interior  108  is determined by a pre-selected differential height  109  between the wellbore fluid in the tubular interior  108  and the wellbore fluid in the annulus  106 . The differential height  109  is density dependant, therefore, the heavier the fluid the smaller the differential height  109  and the lighter the fluid the larger the differential height  109 . The valve assembly  100  will differentially fill the tubular  102  by cycling between open and close to maintain the pre-selected differential height  109 . 
     FIG. 2 is an enlarged cross-sectional view of the valve assembly  100  of FIG.  1 . The assembly  100  includes an upper housing  105  that is threadedly connected to a lower housing  120 . A retaining housing  130  is connected to the lower housing  120  at the lower end of the valve assembly  100 . The valve assembly  100  further includes a plurality of segments  110  radially spaced apart in the upper housing  105 . The upper end of the segment  110  is captured in a groove  107  in the upper housing  105 . The groove  107  is constructed to act as a pivot point for the segments  110 . A biasing member  165  is disposed at the lower end of each segment  110  to provide a means for locking the segments  110  in one position. Preferably, the biasing member  165  is a spring device wrapped radially around segments  110  to bias the segments  110  inward. Although the biasing member  165  is illustrated as an O-ring, it should be noted that the biasing member may include a garter spring, a series of C-rings, or any other device that produces a radial force. A locking shoulder  112  is formed at the lower end of the segment  110 . 
     A locking sleeve  170  may be disposed inside the segments  110  in the upper housing  105 . The locking sleeve  170  is axially movable between a first position and a lock position and contains a passageway  185  that fluidly connects to a passageway  180  in a valve seat  160 . A surface  172  is provided at the upper end of the locking sleeve  170  that is later used to secure the locking sleeve  170  in place. At the lower end of the locking sleeve  170  is an orifice  175 . The orifice  175  has a smaller inside diameter than the inside diameter of passageway  185 . As fluid flows through the passageway  185  and enters the orifice  175 , a differential pressure is created due to the restricted flow through the smaller inside diameter of the orifice  175 . This differential pressure provides a force required to axially translate the locking sleeve  170  downward. The inside diameter of the orifice  175  is based on the fluid density and flow rate through the orifice  175 . 
     At the lower end of the locking sleeve  170  are sleeve biasing members  115 . The sleeve biasing members  115  are disposed between the locking sleeve  170  and the valve seat  160 . In the preferred embodiment, the sleeve biasing members  115  are a plurality of disk shaped members such as wave springs or wave washers. However, a sealed volume of compressible fluid/gas or semi-solid compressible material such as an electrometric material, composite or plastic may be employed, so long as it is capable of biasing the locking sleeve  170 . In the preferred embodiment, the sleeve biasing members  115  are an annular member that bias the valve seat  160  and the locking sleeve  170  in opposite directions. Additionally, the sleeve biasing members  115  provide the biasing force (or backpressure force) against the valve seat  160  to control the amount of wellbore fluid entering the valve assembly  100  while differentially filling the tubular (not shown) to maintain a pre-selected differential height. The size and thickness of the sleeve biasing members  115  are selected based upon the desired differential height and the quantity of sleeve biasing members  115  is based upon the desired stroke length of the valve seat  160 . 
     The valve seat  160  is an annular member that includes passageway  180  at the upper end and an outwardly tapered portion  162  at the lower end. In FIG. 2, the valve seat  160  is shown in a run-in position. In the run-in position a seal member  155  arranged around the valve seat  160  abuts a shoulder  122  in the lower housing  120 . The seal member  155  functions to create a fluid tight seal between the valve seat  160  and the lower housing  120 . The value seal  160  may axially move between a retracted and a final extended position inside the lower housing  120 . While differentially filling a tubular, the valve seat  160  retracts or moves upward to create a fluid passageway between the bottom of the valve assembly  100  and the passageway  180  in the valve seat  160  thereby permitting fluid to enter tubular  102  (not shown) as illustrated in FIG.  3 . 
     A plunger  150  with a plunger head  190  and a shaft portion  195  is located at the lower end of the valve seat  160 . A sealing relationship is created between the plunger head  190  of the plunger  150  and the tapered portion  162  of the valve seat  160 . A biasing member in the form of a spring  145  is disposed about the plunger shaft  195  to urge the plunger  150  upward into contact with the valve seat  160  while the sleeve biasing members  115  urge the valve seat downward, thereby creating a sealing relationship. The upper end of the spring  145  is adjacent the plunger head  190  and the lower end of the spring  145  abuts a plunger housing  125 . The plunger housing  125  is disposed in the retaining housing  130  at the lower end of the valve assembly  100 . A retainer  140  is attached to the lower end of the plunger shaft  195  by a retainer screw  135 . In the preferred embodiment, the components of the valve assembly  100  are made out of a drillable, composite material. 
     FIG. 3 is a cross-sectional view of the valve assembly  100  as it is being lowered into the wellbore. In this position, differential pressure resulting from the differential height moves the valve seat  160  away from the plunger  150  to permit fluid to enter from the lower end of the valve assembly  100 . During differential filling of the tubular, wellbore fluid enters the lower portion of the valve assembly  100  and acts against the tapered section  162  of the valve seat  160 . When the differential pressure overcomes the backpressure created by the sleeve biasing members  115  on the valve seat  160 , the sleeve biasing members  115  compress, thereby allowing the valve seat  160  to move axially upward into the retracted position. The upward movement of the valve seat  160  disengages the sealing relationship between the plunger head  190  and the valve seat  160 , thereby creating a fluid passageway around the plunger  150 . Wellbore fluid, as illustrated by arrows  205 , may now enter the lower end of assembly  100 , flow around the plunger head  190  into the passageway  180  created in the valve seat  160 , move through the orifice  175 , and exit the top of the assembly  100  through the passageway  185 . As the differential pressure decreases, the sleeve biasing members  115  return to an un-compressed state, thereby allowing the valve seat  160  to sealingly contact the plunger head  190  as illustrated in FIG.  2 . 
     FIG. 4 is a cross-sectional view of the valve assembly  100  illustrating the passage of fluid from the tubular, through the assembly and into an annular area between the tubular and a wellborn (not shown). During a completion operation of a well, the wellbore may become clogged with particulates. In this situation, the wellbore needs to be pumped with high pressure fluid to clean out the wellbore prior to inserting another section of tubular. The valve assembly  100  is designed to allow fluid to flow through the valve assembly  100  at a flow rate less than a predetermined maximum flow rate to clean out the wellbore without disengaging the differential fill feature. 
     In one embodiment, fluid enters the valve assembly  100  at the upper end of the housing  105  as illustrated by arrows  210 . As the fluid  210  flows through the passageways  185 ,  180  it acts against the plunger head  190 . When the fluid pressure on the plunger head  190  overcomes the load of the spring  145 , the plunger  150  moves downward compressing spring  145  against the plunger housing  125 . The movement of the plunger  150  disengages the sealing relationship between the plunger head  190  and the valve seat  160 , thereby opening a fluid passageway through the valve  100 . As the fluid pressures increases, the locking sleeve  170 , sleeve biasing members  115 , and the valve seat  160  move axially downward as a unit. As the fluid pressures increases further, the fluid acts on orifice  175  in the locking sleeve  170 . The force exerted by the fluid at the orifice  175  urges the locking sleeve  170  axially downward against the sleeve biasing members  115 . The force exerted on the locking sleeve  170  does not entirely overcome the biasing force of the sleeve biasing members  115 . Thus, the axial movement of locking sleeve  170  only partially exposes segments  110  at the upper end of the locking sleeve  170 . In turn, the sleeve biasing members  115  compress and act upon the valve seat  160 . The valve seat  160  moves axially downward returning to the run-in position wherein the seal member  155  abuts the shoulder in the housing. Alternatively, the locking sleeve  170  can be secured in the upper housing  105  by a shear pin (not shown), which allows the locking sleeve to be retained in the first position and avoid inadvertent movement of the locking sleeve  170  to the locked position. The shear pin is constructed to fail at a predetermined flow rate acting on the orifice  175 , thereby allowing the locking sleeve  170  to move axially downward toward the locked position. 
     FIG. 5 is a cross-sectional view of a valve assembly  100  pumping fluid at or above a maximum flow rate to deactivate the differential fill feature. The fluid, as illustrated by arrow  215 , initially enters the upper housing  105  in the valve assembly  100 . The fluid flows through the passageway  185  and acts upon the orifice  175  and exerts a force that urges the locking sleeve  170  axially downward. At the maximum flow rate, the locking sleeve  170  is urged sufficiently downward to completely expose segments  110 . Upon exposure of the segments  110 , the biasing member  165  causes the lower end of the segments  110  to move radially inward and the upper end to pivot in the groove  107 . As the segments  110  move radially inward the locking shoulder  112  wedges against surface  172  of the locking sleeve  170 , thereby preventing the locking sleeve  170  from moving axially upward in the valve assembly  100 . 
     As the locking sleeve  170  moves axially downward, it also compresses the sleeve biasing members  115  against the seat  160 . The force on the seat  160  by the sleeve biasing members  115  causes the seat  160  to move axially downward until the bottom of the seat  160  hits a stop  220  in the lower housing  120 . The fluid, as illustrated by arrow  215 , continues through the passageway  180  and acts upon the plunger head  190  of the plunger  150  thereby causing the plunger  150  to move axially downward. As the plunger  150  moves downward a fluid passageway is created through the valve assembly  100  and the spring  145  is compressed against the plunger housing  125 . The fluid flows around the plunger  150  and exits the retainer housing  130 . The locking sleeve  170  and the seat  160  are secured in a fixed position by the segments  110  at the upper end of the locking sleeve  170  and the stop  120  at the lower end of the valve seat  160 . 
     FIG. 6 is a cross-sectional view of a deactivated valve assembly  100 . As illustrated, the segments  110  are wedged against the locking sleeve  170 . The locking sleeve compresses the sleeve biasing members  115  against the valve seat  160 , securing the valve seat  160  in a final extended position. While in the final extended position the taper portion  162  of the valve seat  160  creates a sealing relationship with the plunger head  190 . 
     After the section of tubular is installed in the wellbore, the tubular is typically anchored in the wellbore through a cementing process. The valve assembly  100  is used to facilitate the passage of cement from the tubular to the annulus of the well while preventing cement from returning into the tubular due to gravity and fluid density of the cement. The valve assembly  100  acts as a standard one-way check valve allowing fluid to enter the upper housing  105  into the passageway  185  through the orifice  175  into the passageway  180  and act upon the plunger head  190 . At a predetermined flow rate, the plunger  150  moves axially downward and compresses the spring  145  disposed around the shaft  195  of the plunger  150 . The downward movement of the plunger  150  disengages the seal connection between the plunger head  190  and the valve seat  160  to create a passageway around the plunger  150 . The fluid is allowed to flow through the passageway and exit the bottom of the valve assembly  100 . After the downward flow is stopped, the plunger  150  moves axially upward due to the force of the spring  145  and the plunger head  190  creates a sealing relationship with seat  160 , thereby preventing fluid from returning into the valve assembly  100  from the wellbore. 
     In another embodiment, a mechanical device, such as a weighted ball (not shown) can be dropped and seated on a ball seat. Pressure application will then slide the locking sleeve  170  to a predetermined distance to deactivate the differential fill feature. In this embodiment, cross-ports are placed above the mechanical device to allow fluid flow pass the device and through the valve. 
     In operation, the valve assembly  100  is disposed at the lower end of a tubular  102  and then the tubular is run into a wellbore. At a predetermined differential pressure, the valve assembly  100  allows wellbore fluid to enter the tubular. The amount of wellbore fluid allowed to enter the tubular is determined by a pre-selected differential height between the wellbore fluid inside the tubular and the wellbore fluid in the annulus between the tubular and the wellbore. The valve assembly  100  will differentially fill the tubular by cycling between an open and closed position to maintain the pre-selected differential height until the entire section of tubing is disposed in the wellbore. 
     During differential filling of the tubular, fluid enters the lower portion of the valve assembly  100  and acts against the valve seat  160 . Specifically, the differential pressure overcomes the backpressure created by the sleeve biasing members  115  on the valve seat  160 , thereby allowing the valve seat  160  to move axially upward into the retracted position. The upward movement of the valve seat  160  disengages the sealing relationship between the plunger head  190  and the valve seat  160 . Wellbore fluid may now enter the lower end of assembly  100 , flow around the plunger head  190  into the passageway  180  created in the valve seat  160 , flow through the orifice  175 , and exit the top of the assembly  100  through the passageway  185 . As the differential pressure decreases, the sleeve biasing members  115  return to an un-compressed state, thereby allowing the valve seat  160  to sealingly contact the plunger head  190 . 
     During a completion operation of a well, the wellbore may become clogged with particulates. In this situation, the wellbore needs to be pumped with high pressure fluid to clean out the wellbore prior to inserting another section of tubular. The valve assembly  100  is designed to allow fluid to flow through the valve assembly  100  at a flow rate less than a predetermined maximum flow rate to clean out the wellbore. Fluid enters the valve assembly  100  at the upper end of the housing  105 . Subsequently, the fluid flows through the passageway  185  and acts against the orifice  175  in the locking sleeve  170 . The force exerted by the fluid at the orifice  175  urges the locking sleeve  170  axially downward against the sleeve biasing members  115 . The sleeve biasing members  115  compress and act upon the valve seat  160 . The valve seat  160  moves axially downward returning to the run-in position. Fluid crossing the orifice enters the passageway  180  it exerts a downward pressure on the plunger head  190 . When the fluid pressure on the plunger head overcomes the load of the spring  145 , the plunger  150  moves downward. The movement of the plunger  150  disengages the sealing relationship between the plunger head  190  and the valve seat  160 , thereby opening a fluid passageway through the valve  100 . 
     Once the section of tubular is completely placed in the wellbore, fluid is pumped at or above a maximum flow rate to deactivate the differential fill feature. The fluid, initially enters the upper housing  105  in the valve assembly  100 . The fluid flows through the passageway  185  and acts upon the orifice  175  and exerts a force that urges the locking sleeve  170  axially downward. At the maximum flow rate, the locking sleeve  170  is urged sufficiently downward to completely expose segments  110 . Upon exposure of the segments  110 , the biasing member  165  causes the lower end of the segments  110  to move radially inward and the upper ends to pivot in the groove  107 . As the segments  110  move radially inward the locking shoulder  112  wedges against surface  172  of the locking sleeve  170 , thereby preventing the locking sleeve  170  from moving axially upward in the valve assembly  100 . 
     As the locking sleeve  170  moves axially downward it also compress the sleeve biasing members  115  against the seat  160 . The force on the seat  160  by the sleeve biasing members  115  causes the seat  160  to move axially downward until the bottom of the seat  160  hits a stop  220  in the lower housing  120 . The locking sleeve  170  and the seat  160  are secured in a fixed position by the segments  110  at the upper end of the locking sleeve  170  and the stop  220  at the lower end of the valve seat  160 . 
     After the section of tubular is installed in the wellbore, the tubular is typically anchored in the wellbore through a cementing process. The valve assembly  100  is used to facilitate the passage of cement from the tubular to the annulus of the well while preventing cement from returning into the tubular due to gravity and fluid density of the cement. The valve assembly  100  acts as a standard one-way check valve allowing fluid to enter the upper housing  105  into the passageway  185  through the orifice  175  into the passageway  180  and act upon the plunger head  190 . At a predetermined flow rate, the plunger  150  moves axially downward and compresses the spring  145  disposed around the shaft  195  of the plunger  150 . The fluid is allowed to flow through the passageway and exit the bottom of the valve assembly  100 . After the downward flow is stopped, the plunger  150  moves axially upward and the plunger head  190  creates a sealing relationship with seat  160 , thereby preventing fluid from returning into the valve assembly  100  from the wellbore. 
     While the foregoing is directed to embodiments 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