Patent Abstract:
A method for cementing a tubular in a wellbore in a subterranean formation, according to one or more aspects of the present disclosure, comprises connecting a circulating tool to a slip and a top drive; gripping a first tubular with the slip above the surface of the wellbore; sealingly engaging the first tubular with a seal member; fluidly connecting a wiper plug to the circulating tool; connecting the first tubular to a second tubular; and lowering the second tubular into the subterranean formation.

Full Description:
RELATED APPLICATIONS 
       [0001]    This application is a continuation of U.S. patent application Ser. No. 12/114,755, filed on May 3, 2008, (now U.S. Pat. No. 7,635,016), which is a continuation of U.S. patent application Ser. No. 11/512,601, filed on Aug. 29, 2006, now U.S. Pat. No. 7,379,698, which is a continuation of U.S. patent application Ser. No. 10/047,727, filed on Jan. 15, 2002, now U.S. Pat. No. 7,096,948, which is a continuation of U.S. patent application Ser. No. 09/837,447, filed on Apr. 17, 2001, now abandoned, which is a continuation of U.S. patent application Ser. No. 09/206,876, filed on Dec. 8, 1998, now U.S. Pat. No. 6,279,654, which is a continuation-in-part of U.S. patent application Ser. No. 08/850,496, filed on May 2, 1997, now U.S. Pat. No. 5,918,673, which is a continuation-in-part of U.S. patent application Ser. No. 08/726,112, filed on Oct. 4, 1996, now U.S. Pat. No. 5,735,348. 
         [0002]    This Application is related to U.S. patent application Ser. No. 10/052,855, filed on Jan. 15, 2002, now U.S. Pat. No. 6,595,288; and U.S. patent application Ser. No. 11/555,391, filed on Nov. 1, 2006. 
     
    
     FIELD OF THE INVENTION 
       [0003]    This invention relates generally to equipment used in the drilling and completion of subterranean wells, and more specifically to the filling and circulating of drilling fluids in a casing string as well as pumping cement into the casing to set the casing within the wellbore. 
       BACKGROUND 
       [0004]    The process of drilling subterranean wells to recover oil and gas from reservoirs consists of boring a hole in the earth down to the petroleum accumulation and installing pipe from the reservoir to the surface. Casing is a protective pipe liner within the wellbore that is cemented in place to insure a pressure-tight connection to the oil and gas reservoir. The casing is run a single joint at a time as it is lowered into the wellbore. On occasion, the casing becomes stuck and is unable to be lowered into the wellbore. When this occurs, load or weight must be added to the casing string to force the casing into the wellbore, or drilling fluid must be circulated down the inside diameter of the casing and out of the casing into the annulus in order to free the casing from the wellbore. To accomplish this, it has traditionally been the case that special rigging be installed to add axial load to the casing string or to facilitate circulating the drilling fluid. 
         [0005]    When running casing, drilling fluid is added to each section as it is run into the well. This procedure is necessary to prevent the casing from collapsing due to high pressures within the wellbore. The drilling fluid acts as a lubricant which facilitates lowering the casing within the wellbore. As each joint of casing is added to the string, drilling fluid is displaced from the wellbore. The prior art discloses hose assemblies, housings coupled to the uppermost portion of the casing, and tools suspended from the drill hook for filling the casing. These prior art devices and assemblies have been labor intensive to install, required multiple such devices for multiple casing string sizes, have not adequately minimized loss of drilling fluid, and have not been multi-purpose. Further, disengagement of the prior art devices from the inside of the casing has been problematic, resulting in damage to the tool, increased downtime, loss of drilling fluid, and injury to personnel. 
         [0006]    The normal sequence for running casing involves suspending the casing from a top drive or non-top drive (conventional rotary rig) and lowering the casing into the wellbore, filling each joint of casing with drilling fluid. The filling of each joint or stand of casing as it is run into the hole is the fill-up process. Lowering the casing into the wellbore is facilitated by alternately engaging and disengaging elevator slips and spider slips with the casing string in a stepwise fashion, facilitating the connection of an additional stand of casing to the top of the casing string as it is run into the hole. 
         [0007]    Circulation of the fluid is sometimes necessary if resistance is encountered as the casing is lowered into the wellbore, preventing the running of the casing string into the hole. This resistance to running the casing into the hole may be due to such factors as drill cuttings, mud cake, or surface tension formed or trapped within the annulus between the well bore and the outside diameter of the casing, or caving of the wellbore among other factors. In order to circulate the drilling fluid, the top of the casing must be sealed so that the casing may be pressurized with drilling fluid. Since the casing is under pressure the integrity of the seal is critical to safe operation, and to minimize the loss of expensive drilling fluid. Once the obstruction is removed the casing may be run into the hole as before. 
         [0008]    Once the casing reaches the bottom, circulating of the drilling fluid is again necessary to test the surface piping system, to condition the drilling fluid in the hole, and to flush out wall cake and cuttings from the hole. Circulating is continued until at least an amount of drilling fluid equal to the volume of the inside diameter of the casing has been displaced from the casing and wellbore. After the drilling fluid has been adequately circulated, the casing may be cemented in place. 
         [0009]    On jobs which utilize a side door elevator, the casing is simply suspended from a shoulder on the elevator by the casing collar. Thus, fill-up and circulation tools with friction fit sealing elements such as packer cups, and other elastomeric friction fit devices must repeatedly be inserted and removed because of the overall length requirements of the tool. This repeated insertion will, over time, result in the wearing of the elastomeric sealing element such that it will no longer automatically seal on insertion. An adjustable extension is disclosed, which allows the fill-up and circulation tool to be retracted to prevent the elastomeric seal from being inserted into the casing during the fill-up process. 
         [0010]    Circulation alone may be insufficient at times to free a casing string from an obstruction. The prior art discloses that the fill-up and circulation tools must be rigged down in order to install tool assemblies to attach to the rig to allow the string to be rotated and reciprocated. This process requires manual labor, inherent in which is the possibility of injury or loss of life, and results in rig downtime. The potential for injury and lost rig time is a significant monetary concern in drilling operations. To eliminate his hazard and minimize lost rig time, a method and apparatus is disclosed, which allows the fill-up and circulation tool to remain rigged up while at the same time allowing the casing to be rotated and reciprocated. 
         [0011]    After the casing has been run to the desired depth it may be cemented within the wellbore. The purpose of cementing the casing is to seal the casing to the wellbore formation. In order to cement the casing within the wellbore, the assembly to fill and circulate drilling fluid is generally removed from the drilling rig and a cementing head apparatus installed. This process is time consuming, requires significant manpower, and subjects the rig crew to potential injury when handling and installing the additional equipment flush the mud out with water prior to the cementing step. A special cementing head or plug container is installed on the top portion of the casing being held in place by the elevator. The cementing head includes connections for the discharge line of the cement pumps, and typically includes a bottom wiper plug and a top wiper plug. Since the casing and wellbore are full of drilling fluid, it is first necessary to inject a spacer fluid to segregated the drilling fluid from the cement to follow. The cementing plugs are used to wipe the inside diameter of the casing and serves to separate the drilling fluid from the cement, as the cement is carried down the casing string. Once the calculated volume of cement required to fill the annulus has been pumped, the top plug is released from the cementing head. Drilling fluid or some other suitable fluid is then pumped in behind the top plug, thus transporting both plugs and the cement contained between the plugs to an apparatus at the bottom of the casing known as a float collar. Once the bottom plug seals the bottom of the casing, the pump pressure increases, which ruptures a diaphragm in the bottom of the plug. This allows the calculated amount of cement to flow from the inside diameter of the casing to a certain level within the annulus being cemented. The annulus is the space within the wellbore between the ID of the wellbore and the OD of the casing string. When the top plug comes in contact with the bottom plug, pump pressure increases indicating that the cementing process has been completed. Once the pressure is lowered inside the casing, a special float collar check valve closes, which keeps cement from flowing from the outside diameter of the casing back into the inside diameter of the casing. 
         [0012]    The prior art discloses separate devices and assemblies for (1) filling and circulating drilling fluid, and (2) cementing operations. The prior art devices for filling and circulating drilling fluid disclose a packer tube, which requires a separate activation step once the tool is positioned within the casing. The packer tubes are known in the art to be subject to malfunction due to plugging, leaks, and the like, which lead to downtime. Since each step in the well drilling process is potentially dangerous, time consuming, labor intensive and therefore expensive, there remains a need in the art to minimize any down time. There also remains a need in the art to minimize tool change out and the installation of component pieces. 
         [0013]    Therefore, there remains a need in the drilling of subterranean wells for a tool which can be used for drilling fluid, filling and circulating, and for cementing operations. 
         [0014]    For the foregoing reasons, there is a need for a drilling fluid filling, circulating, and cementing tool which can be installed quickly during drilling operations. 
         [0015]    For the foregoing reasons, there is a need for a drilling fluid filling, circulating, and cementing tool which seals against the inside diameter of a casing having a self-energizing feature. 
         [0016]    For the foregoing reasons, there is a need for a drilling fluid filling, circulating, and cementing tool which minimizes the waste of drilling fluids and allows for the controlled depressurization of the system. 
         [0017]    For the foregoing reasons, there is a need for a drilling fluid filling, circulating, and cementing tool which may be used for every casing size. 
         [0018]    For the foregoing reasons, there is a need for a drilling fluid filling, circulating, and cementing tool which submits additional axial loads to be added to the casing string when necessary. 
         [0019]    For the foregoing reasons, there is a need for a drilling fluid filling, circulating, and cementing tool which is readily adjustable in length such that damage to the sealing element is minimized. 
         [0020]    For the foregoing reasons, there is a need for a fill-up and circulating tool which may be sealingly coupled to a casing string to allow the string to be rotated and reciprocated into the wellbore. 
       SUMMARY 
       [0021]    In view of the foregoing and other considerations, the present invention relates to wellbore drilling and completion operations. Accordingly, examples of devices, systems, and methods for forming wellbores are provided. 
         [0022]    An apparatus for cementing tubulars in a wellbore, according to one or more aspects of the present disclosure, comprises a top drive having a fluid path; a gripping member supported above the wellbore comprising radially movable gripping elements; and a wiper plug assembly fluidly connected to the fluid path. 
         [0023]    An apparatus for cementing casing in a wellbore, according to one or more aspects of the present disclosure, comprises a tubular body having a fluid flow path therethrough; a seal member connectable to the tubular body and the casing; a wiper plug connectable to the tubular body; a gripping member supported above the wellbore to grip the casing; and a top drive to move the tubular body. 
         [0024]    A method for cementing a tubular in a wellbore in a subterranean formation, according to one or more aspects of the present disclosure, comprises connecting a circulating tool to a slip and a top drive; gripping a first tubular with the slip above the surface of the wellbore; sealingly engaging the first tubular with a seal member; fluidly connecting a wiper plug to the circulating tool; connecting the first tubular to a second tubular; and lowering the second tubular into the subterranean formation. 
         [0025]    A method of cementing a casing within a wellbore formed in a formation, according to one or more aspects of the present disclosure, comprises connecting a gripping member disposed above the wellbore, a cementing assembly and a top drive, wherein the top drive and the cementing assembly are fluidly connected to a fluid path; gripping the casing with the gripping member and the top drive; sealingly engaging the casing with a seal member; moving the casing within the wellbore via the top drive; and cementing the casing within the formation while maintaining a sealing engagement of the casing. 
         [0026]    A method for cementing casing in a wellbore, according to one or more aspects of the present disclosure, comprises disposing a tubular body having a seal member from a top drive, wherein a fluid path is formed through the top drive and tubular body; detachably connecting a wiper plug to the tubular body; gripping the casing with a slip above the surface of the wellbore; fluidly sealing the casing above the surface of the wellbore with the seal member; moving the casing in the wellbore via the top drive; releasing the wiper plug from the tubular body into the casing; and cementing the casing within the wellbore. 
         [0027]    A method for cementing casing in a wellbore, according to one or more aspects of the present disclosure, comprises disposing a tubular body having a seal member from a drilling rig; detachably connecting a wiper plug to the tubular body; gripping the casing above the surface of the wellbore with a slip; sealingly engaging the casing above the surface of the wellbore with the seal member; moving the casing in the wellbore; releasing the wiper plug from the tubular body into the casing; and cementing the casing within the wellbore. 
         [0028]    The foregoing has outlined some of the features and technical advantages of the present invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter which form the subject of the claims of the invention. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0029]      FIG. 1  shows a top drive rig assembly in accordance with the present invention. 
           [0030]      FIG. 2  shows a conventional rotary rig assembly used in accordance with the present invention. 
           [0031]      FIG. 3  shows a side view of the torque sub and the adjustable extension. 
           [0032]      FIG. 3A  shows a side view of the fill up and circulating tool in the fill-up mode and configured for a top drive rig assembly. 
           [0033]      FIG. 4  shows a side view of the fill up and circulating tool in the fill-up mode and configured for a conventional rotary rig assembly. 
           [0034]      FIG. 5  shows a side view of the fill up and circulating tool in the cementing mode and configured for a top drive rig assembly. 
           [0035]      FIG. 6  shows a side view of the fill up and circulating tool configured with the push plate assembly. 
           [0036]      FIG. 7  is a partial, cross-sectional view of another embodiment of a fill up and circulating tool having a pressure relief housing. 
           [0037]      FIG. 8  is a partial, cross-sectional view of the pressure relief housing of  FIG. 7 . 
           [0038]      FIG. 9  is a partial, cross-sectional view of the pressure relief housing of  FIG. 7 . 
       
    
    
     DETAILED DESCRIPTION 
       [0039]      FIG. 1  shows a top drive drilling rig  3 .  FIG. 1  also shows the casing fill up and circulator tool  46  in the top drive configuration, which is more fully described below. Those skilled in the art will know that suspended from the traveling block  1  on a drilling rig is a hook  2 . The top drive unit  3  is suspended from the hook  2 . Pressurized fluid is delivered from the drilling fluid pumps  8  through hose  4  directly to the top drive unit  3 . A top sub box connection assembly  6  is threadedly connected at one end to the top drive pin shoulder  5  to receive the fill up and circulating tool  46 . The opposite end of the top sub box connection assembly is threadedly connected to the casing fill up and circulating tool  46 . A tool catch plate  7  may be fixed to the top sub box connection assembly  6  as a stop which will engage against the uppermost portion of the casing if the tool becomes disengaged from the top drive unit  3 . An elevator  14  is suspended from bails  3   a  and  3   b  attached to the top drive unit  3 . It should be obvious to one skilled in the art that a joint of casing  32  may be positioned under the top drive unit so as to allow the upper end of the casing to be gripped by the elevator  14 , thereby inserting the fill up and circulating tool  46  partially inside of the casing  32 . The casing  32 , suspended from the elevator  14  may then be lowered through the rotary table slips  10  on the drilling rig floor and rotary table  11  below the rig floor and into the wellbore  12 . As the casing  32  is being lowered it may be filled with drilling fluid from the fill up and circulating tool  46 , the full operation of which is more fully described below. Once the casing  32  is lowered such that the elevator  14  is almost in contact with the rotary table slips  10 , the slips  10  are then engaged against the casing  32  to hold it in position above the rig floor to receive the next joint of casing  32 . The procedure is repeated until the entire casing string has been lowered into the wellbore  12 . 
         [0040]      FIG. 2  is illustrative of a conventional drilling rig with a rotary type rig assembly with the casing circulating tool installed  46 . Those skilled in the art will know that suspended from the traveling block on a rotary type rig configuration is a hook  2 . The hook  2  includes two ears  2   a  and  2   b , located on either side of the hook  2 , and are used to suspend a pair of bails  13   a  and  13   b  and an elevator  14  below. The lower end of the bails  13   a  and  13   b  are connected to the ears  14   a  and  14   b  of the elevator  14 . The hook  2 , also suspends a guide plate  15  connected by a U-bolt  16 , which is secured to the guide plate  15  with nuts  16   a  and  16   b . The U-bolt  16  extends through apertures  15   c  and  15   d  in the guide plate  15 . The bails  13   a  and  13   b  extend through two apertures  15   a  and  15   b  in the guide plate  15  such that horizontal movement of the bails  13   a  and  13   b , the elevator  14 , and the fill up and circulating tool  46  is limited. The lock block  18  having a central axial bore is welded at one end to the bottom surface  15   e  of the guide plate  15 . The lock block  18  includes at least one aperture  18   a  extending through the wall of the lock block  18  to receive spring pin  18   b . Spring pin  18   b  is adapted to releasably extend through the lock block aperture  18   a  and to engage the channel  17   a  in the upper end of the bayonet adapter  17  on the fill-up and circulating tool  46 . The spring pin  18   b  is inserted through the aperture  18  and into the channel  17   a  to retain the bayonet adapter  18  within the lock block  18  thereby suspending the fill-up and circulating tool  46  from the guide plate  15 . To deliver fluid to the casing, the drilling fluid pump  8  is activated which discharges drilling fluid into hose  4 , and into the fill-up and circulating tool through the nozzle  17   b  on the bayonet adapter  17 , which transports the drilling fluid to the fill-up and circulating tool  46  and into the casing  32 . Alternative embodiments of the lock block and bayonet adapter are contemplated by the present invention. For example, lock block  18  comprises a cylinder with internal threads and the bayonet adapter with a male threaded end so as to be threadedly connected to the lock block. In a second alternative embodiment, lock block  18  comprises a cylinder with two apertures extending through the wall of the cylinder  180  apart with the cylinder having an outside diameter slightly smaller than the inside diameter of the lock block. The upper end of the bayonet adapter is inserted inside the lock block with the apertures in alignment. A pin would then be inserted through the apertures to retain the bayonet adapter and therefore the fill-up and circulation tool. 
         [0041]      FIG. 3  is illustrative of a torque sub  70  and a rotational sub  80 , both or either of which may be used in combination with any fill-up and circulation tool insertable within a casing string in either a top drive or conventional rotary rig configuration. The torque sub  70 , the operation and benefits of which are described above, includes three primary components, a top sub  71 , a lock sub  72  and a thread adapter  73 . The inlet of top sub  71  is threadedly connected to the top drive  3  (or rotary sub if a conventional rotary rig is used). The outlet of the top sub  71  is threadedly connected to the inlet of lock sub  72 . The outlet of lock sub  72  may then be connected directly to the fill-up and circulation tool selected, or it may be connected to the adjustable extension  80 . The outlet of top sub  71  also includes O-ring  71   a  which provides a fluid tight seal against the inlet of lock sub  72 . Disposed about the lower outer surface of the top sub  71  and the upper outer surface of the lock sub  72  is thread adapter  73 . Thread adapter  73  includes external threads  73   a , which allows the assembly to be threadedly connected to the internal threads of a casing coupling. Thus, it will be obvious to one skilled in the art that the outside diameter of the thread adapter  73  varies with the inside diameter of the particular casing and therefore casing coupling used. Extending from the inside wall of the thread adapter is a shoulder  73   b , which is in engaging contact with the outside wall on the outlet portion of the lock sub  72 . Disposed within shoulder  73   b  is an O-ring  73   c , which provides a fluid tight seal between thread adapter  73  and lock sub  72 . Extending laterally through the wall of thread adapter  73 , near its upper end, are pins  74 . In the preferred embodiment, four (4) pins  74  are located approximately 90 degrees apart. Pins  74  extend past the inside surface of the wall of thread adapter  73  and extend through a slot  71   b  in the lower end of top sub  71  such that the end of the pins  74  engage against the wall of the top sub. This fixes thread adapter  73  to top sub  71 . It will now be obvious that as the assembly is rotated by top drive  3  (or rotary sub) to thread adapter  73  into the casing coupling, the assembly rotates as a unitary structure. After thread adapter  73  and the casing coupling have been made-up, elevator  14  and spider  10  ( FIGS. 1 and 2 ) may be released allowing the entire casing string to be rotated and/or reciprocated within the wellbore. Since fill-up and circulation tool  46  is still attached, fluid circulation may be performed as well. 
         [0042]      FIG. 3  also shows the adjustable extension  80 , the benefits and general operation of which is described above. The adjustable extension  80  allows a fill-up and circulation tool of any design to be extended and retracted automatically via the top drive  3  (or a rotary sub) or manually by simply rotating the adjustable extension  80  in the desired direction. The adjustable extension  80  may be used in place of or in addition to the top sub assembly or pup piece typically used to space the particular fill-up and circulation tool out on the rig. The adjustable extension  80  includes a lower adapter  84 , an upper adapter  83 , a screw mandrel  82 , and an extension housing  81 . The inlet of the upper adapter  83  includes threads to connect to a torque sub  70 , a cement head assembly (see  FIG. 5 ), or may be connected to the top drive or rotary rig. The outlet of the upper adapter  83  is threadedly connected to the upper end of extension housing  81 . An O-ring  83   a  is disposed within the lower outer wall of the outlet of the upper adapter  80  to provide a fluid tight seal between the extension housing  81  and the upper adapter  83 . The lower end of the extension housing  81  includes a shoulder  81   a , after which threads  81   b  on the inside wall extend to the end of the extension housing  81 . Threadedly connected to the lower end of the extension housing  81  is screw mandrel  82 . The screw mandrel  82  includes threads  82   a  substantially along the length of the screw mandrel  82  so that when the extension assembly is rotated, the screw mandrel moves axially within the extension housing  81  allowing the tool to be extended or retracted as the need arises. The upper end of the screw mandrel  82  includes a flange  82   b , the lower portion of which engages against the shoulder  81   a  of the extension housing  82  to create a stop when the extension assembly  80  is fully extended. The upper portion of the flange  82   b  engages against the outlet of the upper adapter  83  to create a stop when the extension assembly  80  is fully retracted. Disposed within the outer wall of the shoulder  81   a  are O-rings  82   c , which provide a fluid tight seal between the screw mandrel  82  and the extension housing  81 . Threadedly connected to the outlet of the screw mandrel  82  is the inlet of the lower adapter  84 . Disposed within the inside wall of the inlet of the lower adapter is an O-ring  84   b , which provides a fluid tight seal between the screw mandrel  82  and lower adapter  84 . The outlet of lower adapter  84  is threadedly connected to fill-up and circulation tool  46 , the cement head assembly  47 , the torque sub  70  or other related assembly as the circumstances dictate. At least one slot  84   a  is disposed in the outer wall of the lower adapter  84 . In order to retract or extend the adjustable extension  80 , a bar or other suitable member is inserted into the slot and force is applied to the bar to extend or retract the adjustable extension  80  manually. In order to extend or retract the extension automatically, a bar or other suitable member of sufficient length to engage with the bails when rotated is inserted into the slot. Thus, it will be obvious to one skilled in the art that once the top drive  3  (or rotary sub) is activated to rotate, the bar will move along with the lower adapter  84  until the bar engages against the bail. Further rotation will cause the extension assembly  80  to be retracted or extended. 
         [0043]      FIG. 3A  shows the preferred embodiment of fill-up and circulating tool  46  in the top drive configuration and in the fill-up position. Those who are skilled in the art will know and understand that each component in the flow path includes an inlet and an outlet. The tool consists of a mandrel  19 , having a central axial bore defining a flow path  19   a  through which fluid flows through the tool. A plurality of apertures  19   c  located near the outlet of mandrel  19  allow fluid to flow through apertures  19   c  during the circulating mode of tool  46  as more fully described below. To lengthen mandrel  19  to space out the tool in any desired length on the rig, a top sub assembly may be connected to the inlet of mandrel  19 . The top sub assembly may consist of a top sub  20 , a first spacer  21 , a connector coupling  22 , a second spacer  23 , and a top collar  24  connected in series thereby extending the overall length of the tool as well as the flow path  19   a . Any number of couplings and spacers or length of spacer may be used to provide proper spacing on the top drive or conventional rotary rig configuration. Once the spacing requirements have been determined, the top sub assembly is configured with top collar  24  connected to the inlet of mandrel  19 . 
         [0044]    A spring  25  is disposed about the outer surface  19   b  of mandrel  19 . The upper end  25   a  of spring  25  is in engaging contact with and below lower surface  24   a  of top collar  24 . A sliding sleeve  26  in engaging contact with the lower end  25   b  of the spring  25  is disposed about the outer surface  19   b  of the mandrel  19 . A spring stop  25   c  is disposed within the annular space between spring  25  and outer surface  19   b  of mandrel  19 . Spring stop  25   c  is included to prevent spring  25  from being damaged from excessive compression. Spring  25  biases sliding sleeve  26  such that in the fill-up mode of tool  46 , sliding sleeve  26  covers the mandrel apertures  19   c , which results in fluid flow exclusively through the outlet of mandrel  19 . 
         [0045]    The upper end of sliding sleeve  26  includes a flange portion  26   a , the upper surface of which is in engaging contact with lower end  25   b  of spring  25 , and the lower surface of which is in engaging contact with a spacer ring  27 . The lower surface of spacer ring  27  is in engaging contact with a thimble  28 . Thimble  28  is adapted to retain the upper end  29   a  of the sealing element, packer cup  29  which may be any type of elastomeric sealing device, against and between the lower surface of thimble  28  and the outer surface of sliding sleeve  26  near the upper end  26   b . While packer cup  29  is shown as the preferred embodiment of the sealing element, any friction fit sealing device may be used, as well as other sealing devices such as inflatable packers and the like may be used in combination with the features and benefits of sliding sleeve  26  and the mandrel  19  described herein. 
         [0046]    Spacer ring  27  minimizes the potential for deflection of thimble  28  when subjected to fluid pressure forcing packer cup  29  and thimble  28  upward and outward. A lock sleeve  30  is disposed about the sliding sleeve  26  and is connected to the lower end  26   b  of sliding sleeve  26 . The upper end  30   a  of lock sleeve  30  is in engaging contact with the upper end  29   a  of packer cup  29  to further retain packer cup  29  within thimble  28  and against the outer surface  26   b  of sliding sleeve  26 . Packer cup  29  depends downward with respect to the upper end  29   a  of packer cup  29 , flaring radially outward and away from sliding sleeve  26  such that it forms a cone which defines an annular space between the inside surface of packer cup  29  and sliding sleeve  26 . The outside diameter of the lower end  29   b  of packer cup  29  is at least equal to the inside diameter of casing  32 . The lower end  29   b  is further adapted to be inserted into casing  32  and upon insertion to automatically engage with and to provide a leak tight seal against the inside diameter of casing  32 . Packer cup  29  is formed from a flexible elastomeric material such as rubber, however other materials or combination of materials are contemplated by the present invention. For example, in an alternative embodiment, the upper end  29   a  of packer cup  29  is made of steel while the lower end  29   b  is made of rubber or some other elastomer. 
         [0047]    The outlet of mandrel  19  is connected to the inlet of a lower body  31 . The lower body  31  limits the travel of sliding sleeve  26  downward. In the fill-up mode of tool  46 , spring  25  biases sliding sleeve  26  downward such that the bottom surface of the sliding sleeve  26  is in engaging contact with the top surface of lower body  31 . Lower body  31  also provides a conduit connection between mandrel  19  and mud saver valve  34 . A guide ring  33  is connected to and disposed about the outer surface of the lower body  31 . The guide ring  33  serves as a guide to center tool  46  within casing  32  as it is lowered. The outlet of lower body  31  is threadedly connected to a mud-saver valve and nozzle assembly. 
         [0048]    The mud saver valve and nozzle assembly includes a mud saver valve  34 , and a nozzle  35 . The preferred embodiment comprises a mud saver valve  34  having threads on the outer surface of the valve inlet and internal threads on the inner surface of the valve outlet. Mud saver valve  34  is connected to tool  46  by threadedly connecting the body extension  36  on mud saver valve  34  to the inlet of the outlet of the lower body  31 . In so doing, the body extension and a portion of lower body  31  define the housing and annular space for mud saver valve  34  internals. A body seal  36   a  comprising an O-ring is disposed within a channel formed in the outer surface of the upper end of the body extension  36  to seal against the inner surface of the lower body  31  outlet and the pressurized fluid from leaking at the connection. Beginning with the mud saver valve  34  internals at the outlet portion, a choke  37  is connected to a choke extension  38  for regulating the flow of fluid from tool  46 . Choke extension  38  and body extension  36  are adapted to retain a plunger spring  39  within the space defined by a portion of the inner surface of body extension  36  and the outer surface of choke extension  38 . A plunger  40  having a central axial bore is connected to the upper end of choke extension  40 . Plunger  40  includes a centrally located protruding annular ring portion  41 , which is in slidable engaging contact with the inner surface of a valve housing  42 . A plunger seal  40   a  comprising an O-ring is disposed within a channel formed in the annular ring portion  41  to provide a leak tight seal against valve housing  42 . The upper end of plunger  40  includes a plurality of apertures  40   b  to allow fluid to flow into the bore of plunger  40  and out of choke  37 . A plunger tip  40   c  is adapted to provide a fluid tight seal against plunger seat  43   a . Plunger spring  39  biases plunger  40  thereby exerting an upward force on the choke extension  38  and therefore plunger  40  so that plunger tip  40   c  engages with and provides a fluid tight seal against the plunger seat  43   a . Fluid pressure exerted on plunger tip  40   c  will cause plunger spring  39  to depress, which creates an opening allowing fluid to flow through mud saver valve  34 , through nozzle  35  and into casing  32 . The valve housing  42  is disposed between and is in engaging contact with the plunger  40  and the lower body  31 . A housing seal  42   a  comprising an O-ring is disposed within a channel formed in the outer surface of valve housing  42  to provide a leak tight seal against lower body  31 . A seat ring  43  having a central axial bore is in engaging contact with and disposed within the uppermost interior portion of lower body  31  and is in engaging contact with valve housing  43  and upper body  37 . A lower body seal  31  a comprising an O-ring is disposed within a channel formed in the lower body  31  to provide a leak tight seal against the seat ring  43 . The outlet of a centrally located bore within seat ring  43  defines the plunger seat  43   a . The plunger seat  43   a  is adapted to sealingly receive plunger tip  40   c . The seat ring  43  further includes a plurality of spring loaded check valves  44  housed within vertical cavities  43   b . An aperture  43   c  extends from each of the cavities  43   b  to provide fluid communication between the seal ring bore and cavities  43   b . When the pressure below the seat ring  43  exceeds the pressure above seat ring  43 , fluid will depressure through the check valves  44  and apertures  45  until an equilibrium pressure above and below the seat ring  43  is achieved. The check valves  44  therefore function as safety relief valves to ensure that high pressure fluid is not trapped below the tool, which could result in tool  46  being expelled uncontrollably from casing  32  as it is removed, or in an uncontrolled pressurized flow of fluid from casing  32  when the tool is removed. It will be obvious to one skilled in the art that the uncontrolled depressurization of fluid could result in significant downtime due to loss of fluid, damage to equipment, and injury to personnel. 
         [0049]    Mud saver valve  34  also functions as a check valve to actuate open when the fluid pressure reaches a set point pressure of about 300 psig, for example. As the fluid pressure increases above 300 psig, plunger  40  is depressed against spring  39  which unseats plunger  40  from plunger seat  43   a , which allows fluid to flow through tool  46  and into easing  32 . When fluid pressure falls below about 300 psig plunger spring  39  biases plunger  40  upward causing plunger tip  40   c  to seat against seat ring  43 . Thus, mud saver valve  34  retains fluid that would otherwise be drained and wasted from tool  46 . The nozzle  35  is connected to the outlet of the mud saver valve  34 . Nozzle  35  is generally conical to facilitate insertion into the casing, and includes an aperture  35   a , all of which allow fluid to escape from tool  46  in a substantially laminar flow regime. Several mud saver valve  34  and nozzle  35  configurations are contemplated by the present invention. For example, a hose can be connected between mud saver valve  34  and nozzle  35 , or a hose may be connected between lower body  31  and mud saver valve  34 . 
         [0050]    To begin the fluid filling process, fill-up and circulating tool  46  is lowered over casing  32  to be filled. Only the portion of tool  46  below packer cup  29  is inserted into casing  32 . Sealing device  29  remains above and outside of casing  32  during the fill-up process. Fill-up of fluid is accomplished by simply activating the pump  8  to fill and then deactivating the pump  8  on completion. As the fluid pressure increases within tool  46 , mud saver valve plunger  40  is unseated from plunger seat  43   a  and fluid is allowed to flow through fill-up and circulating tool  46  and into casing  32  to be filled. 
         [0051]      FIG. 4  shows the preferred embodiment of fill-up and circulating tool  46  in the rotary type configuration.  FIG. 4  shows a bayonet adapter  17  connected to the first spacer  21  in place of the top sub  20  on the top sub assembly. If the top sub assembly is not needed, the bayonet adapter  17  may be connected directly to mandrel  19 . The bayonet adapter  17  includes a fluid hose connection  17   b , adapted to connect to the fluid hose  4 , and a cylindrical post  17   c  extending from the top of the bayonet adapter  17 . The outside diameter of the post  17   c  is slightly smaller than the inside diameter of the lock block so that post  17   c  may be inserted within the bore of the lock block  18 . The outer surface of the upper end of post  17  includes channel for receiving a spring pin, which allows fill-up and circulation tool  46  to be suspended in the rotary rig configuration. 
         [0052]      FIG. 4  also shows fill-up and circulating tool  46  in the fluid circulation mode. Fill-up and circulating tool  46 , in the rotary rig configuration, is shown lowered into casing  32  such that sealing element  29  is in sealing engaging contact with the inside diameter of casing  32 . Flow of fluid from pump  8  will cause the fluid pressure to build up inside of casing  32  until the hydrostatic pressure is overcome thereby resulting in the desired circulation of fluid from inside casing  32  into the wellbore  12 . Packer cup  29  automatically engages against the inside diameter of casing  32  as it is lowered therein. Therefore, when circulating fluid is desired (e.g. when the casing is stuck in wellbore  12 ), further downward force is exerted on tool  46  by lowering the assembly from traveling block  1 . This causes spring  25  disposed about the exterior of mandrel  19  to become compressed between top collar  24  and flange portion  26   a  ( FIG. 3 ) on the sliding sleeve  26 . The downward force causes mandrel  19  to move vertically downward with respect to sliding sleeve  26  thereby exposing the lower end of mandrel  19  and apertures  19   c  formed therethrough. Pressurized fluid from the fluid pump  8  may now follow the flow path  19   a  through tool  46  as well as through the apertures  19   c  into the casing  32 . As casing string  32  is filled, the fluid pressure inside of the casing increases, which further engages packer cup  29  against the inside surface of casing  32 . When circulating is no longer necessary, pump  8  is simply stopped. This results in plunger  40  within mud saver valve  34  re-seating against plunger seat  43   a , which stops the flow of fluid through nozzle  35 . Tool  46  is then withdrawn from casing  32  by raising the assembly suspended from traveling block  1  so that the next joint of casing  32  can be picked up or to prepare tool  46  for cementing operations. 
         [0053]      FIG. 5  illustrates fill-up and circulating tool  46  in the cementing configuration. While  FIG. 5  shows the preferred embodiment of fill-up and circulating tool  46  as shown in  FIGS. 3 ,  4  and  7 - 9 , the present invention contemplates and includes fill-up and circulating tools of other embodiments. Thus, the following discussion addresses wherein fill-up and circulating tool  46  is referenced for illustrative purposes. Further, this configuration may be utilized in either the top drive rig or conventional rotary rig operations. Any fill-up and circulating tool capable of insertion into casing may be quickly and easily switched from a drilling fluid filling and circulating mode of operation to the cementing configuration as shown in  FIG. 5  by combining the selected fill-up and circulating tool with cementing head assembly  47  and wiper plug assembly  57  of the present invention. The fill-up and circulating tool, in the cementing configuration, is connected to and therefore extends the flow path from a cementing head assembly  47  to a wiper plug assembly  57 . Using fill-up and circulating tool  46  as more fully described above, the cementing configuration comprises a cementing head assembly  47  connected to first spacer  21  of the top sub assembly, and a cement wiper plug assembly  57  in place of mud saver valve  34  and nozzle  35 . Since the present invention contemplates and includes fill-up and circulating tools of various other embodiments, other means of attachment to a top drive or conventional rotary type units are contemplated as required by the particular fill-up and circulating tool used in the cementing configuration. Additionally, cementing head assembly  47  may be directly connected to fill-up and circulating tool  46 . 
         [0054]    The preferred embodiment of cement head assembly  47  includes a ball drop coupling  48 , a ball carrier assembly  49 , and a ball port  50  connecting ball drop coupling  48  to ball carrier assembly  49  providing a passageway therebetween. Ball carrier assembly  49  includes a ball carrier mandrel  50 , which houses a ball carrier  51  in slidable engagement with the interior surface of the ball carrier mandrel  50 . The lower surface of the ball carrier  51  includes a slot (not shown) within which ball stops  51   b  and  51   c  are disposed. Ball carrier  51   a  further includes a large ball seat and a small ball seat within which a large ball  52   a  and a small ball  52   b  are respectively seated. Slidably disposed between large ball seat and small ball seat within slot the ball carrier  51  is ejector  51   d . Attached to an upper surface of ball carrier  51   a  is plunger  53  which extends through an aperture in the upper end of ball carrier mandrel  51 . Disposed between a lower interior surface of ball carrier mandrel  51  and a lower surface of ball carrier  51   a  is ball spring  54 . Threadedly connected to the upper end of ball carrier mandrel  51  is a pressure housing  55 . Pressure housing  55  houses an upper end of plunger  53  and a plunger spring  56 . Plunger spring  56  is disposed between a top surface of plunger head  53   a  and an inside surface on the top of pressure housing  55 . Plunger spring  56  biases plunger  53  against the biasing force applied by ball spring  54  so that neutral position, designated by line  100 , ball carrier  51  is in a position that prevents the release of either of the balls  52   a  and  52   b  through ball port  50  and into ball drop coupling  48 . Pressure housing  55  also includes pressure ports  55   a  and  55   b  through which a pressurization fluid (either gas, e.g. air, or hydraulic fluid) is delivered into pressure housing  55 . In the preferred embodiment the fluid pressure is supplied by air. Thus, cement head assembly  47  may be actuated remotely to release the appropriate ball using fluid pressure. To release large ball  52   a , air pressure in the range of 90-120 psi is delivered to pressure port  55   a . The fluid pressure forces plunger  53  and ball carrier  51  down to a position such that the movement of ejector  51   d  within the ball carrier slot stops on contact with stop  51   b , the contact of which results in large ball  52   a  being ejected through ball port  50  and descends into ball drop coupling  48 . Pressure housing  55  may be depressurized, which allows the spring biasing forces to overcome the fluid pressure, returning ball carrier  51  to neutral position  100 . To eject small ball  52   b , air pressure is delivered to pressure port  55   b . The fluid pressure forces plunger  53  and ball carrier  51   a  upward to a position such that the movement of ejector  51   d  within the ball carrier slot stops on contact with stop  51   c  the contact of which results in small ball  52   b  being ejected through ball port  50  and descends into ball drop coupling  48 . Again, pressure housing  55  may be depressurized, which allows the spring biasing forces to overcome the fluid pressure returning ball carrier  51  to neutral position  100 . 
         [0055]    If fill-up and circulating tool  46  (of  FIG. 3A  or  4 ) is installed with cementing head assembly  47  and wiper plug assembly  57 , it is preferable to keep cement from flowing through mandrel apertures  19   c . If cement is allowed to flow through mandrel apertures  19   c , plugging of the apertures as well as erosion may occur. To prevent this, sliding sleeve  26  must be fixed in place on fill-up and circulating tool  46  of the present invention so that mandrel apertures  19   c  remain covered during the cementing operation. To accomplish this, a set screw  25   d  is disposed within each of a plurality of threaded set screw apertures  25   b  in the outer surface  19   b  of mandrel  19  near mandrel outlet. Preferably apertures  25   b  are located a minimal distance above spring stop  25   c  to fix sliding sleeve  26  in a position to cover mandrel apertures  19   c  during the cementing operations. Thus cement will not flow from mandrel  19  through mandrel apertures  19   c . It is therefore desirable for the full flow of cement to follow flow path  19   a  so as to ensure proper operation of the ball dropping function, and to prevent plugging or erosion of mandrel apertures  19   c . One who is skilled in the art will readily perceive other methods for preventing sliding sleeve  26  from moving upward to expose mandrel apertures  19   c . For example, a tubular member may be disposed about spring  25  between top collar  24  and sliding sleeve  26  to fix sliding sleeve  26  in place. 
         [0056]    After the casing string has been run, it must be cemented within wellbore  12 . After the last casing joint has been filled with drilling fluid, a volume of water or flushing fluid is pumped through the assembly and into the casing. The assembly is then removed from the casing string to be configured for the cementing mode. The fill-up and circulating tool is then uncoupled from the top drive or rotary drive unit. The cementing head assembly  47  is coupled to the inlet of the tool. In the alternative, the cementing head assembly  47  may be pre-installed with the fill-up and circulating tool for operation in both the drilling fluid and cementing mode. The next step is to connect wiper plug assembly  57  to lower body  31  on fill-up and circulating tool  46 . First, mud saver valve  34 , and nozzle  35  are removed from fill-up and circulating tool  46 . The wiper plug assembly  57  is then installed. The wiper plug assembly  57  comprises a top wiper plug  58  detachably connected to a bottom wiper plug  59 . The fill-up and circulating tool is now in the cementing configuration and is then reconnected to the top drive or rotary unit. The next step is to release bottom plug  59  from wiper plug assembly  47 . To release bottom plug  59 , the first of two tripping balls  52   a  must be released from tripping ball chamber  50 . To release tripping ball  52   a , pin  50   c  is retracted, which allows ball  52   a  to descend from tripping ball chamber  49  and through tool  46 . The first tripping ball  52   a  severs the connection between two wiper plugs  58  and  59 , which causes bottom wiper plug  59  to drop into casing string  32 . A calculated volume of cement is then pumped through the tool and assembly, which drives bottom wiper plug  59  down casing string  32 . As bottom wiper plug  59  descends the casing string, it wipes mud off the inside diameter of the casing. The cement drives bottom wiper plug  59  to engage with the float collar (not shown) at the bottom of casing  32 . After the calculated volume of cement has been pumped, a second tripping ball  52   b  is released from ball dropping pump-in tee  49 . The second tripping ball severs top plug  58  from wiper plug assembly  57  and descends into the casing string. Top plug  58  is driven down casing  32  by pumping drilling fluid or other suitable fluid through inlet port  48   b  behind top plug  58 , which also wipes the cement off the inside of casing  32 . When sufficient pressure is generated between the two wiper plugs  58  and  59 , a diaphragm in bottom wiper plug  59  is ruptured, which allows the cement between wiper plugs  58  and  59  to flow from inside casing  32  through bottom wiper plug  59  and into the annulus between casing  32  and wellbore  12 . After top plug  58  has come to rest by engaging against bottom plug  59 , the discharge pressure on pump  9  begins to increase, which indicates that casing  32  has been successfully sealed off from the annulus between casing  32  and wellbore  12 . 
         [0057]    The fill-up and circulation tool of the present invention may readily be used in a tandem configuration. The tandem configuration is used when it is desired to run two different diameter casing strings, and has the advantage of eliminating the downtime required to rig up prior art circulation tools. The tandem configuration embodiment comprises the fill-up and circulation tool as described above, however, it includes a second sliding sleeve and packer cup arrangement connected above the first sliding sleeve and packer cup wherein the diameter of the second packer cup  29  is larger than first packer cup  29 . This allows for both the larger and smaller diameter casing to be filled and circulated without re-tooling. This arrangement can also be used with other sealing elements such as inflatable packers, and devices that seal against the casing via and interference or friction fit with the casing. 
         [0058]      FIG. 6  is illustrative of a push plate assembly  60 . During casing operations, it may be necessary to apply a downward force to push casing  32  into the wellbore. This feature allows the weight of the rig assembly to be applied to the top of the casing through push plate assembly  60 . While  FIG. 6  shows the preferred embodiment of fill-up and circulating tool  46  as shown in  FIG. 3 , the present invention contemplates and includes fill-up and circulating tools of other embodiments, including but not limited to those shown in the following figures. Thus, the discussion which follows whereby fill-up and circulating tool  46  referenced is for illustrative purposes. Further, this configuration may be utilized in either the top drive rig or conventional rotary rig assemblies. The push plate assembly  60  is located between top collar  24  and top sub  20  on fill-up and circulating tool  46 , and is installed in place of the standard connector coupling  22 . The push plate assembly  60  includes a coupling  61  with a plurality of J-shaped slots  62  within outer wall  63  of coupling  61 . A rotatable plate  64  is radially disposed about coupling  61  and is adapted to be fixed about coupling  61  with plurality of pins  65 . 
         [0059]    To add load to the casing string, plate  64  must first be rotated until pin  65  is engaged within the horizontal portion of J-shaped slot  62 . This locks plate  64  within assembly  60  so that load may then be transferred to the casing string. Spider  10  is then engaged against casing  32  to hold the string in place. Elevator  14  is then released from casing  32  above the rig floor. The top drive unit  3  is then lowered by traveling block  1  until plate  64  is in contact with the top of the casing string. Elevator  14  is then attached to casing  32 , and spider  10  is released. The casing  32  is now being held only by elevator  14 . Further lowering of top drive unit  3 , adds load (the weight of the rig) to casing string, forcing the string into wellbore  12 . To disengage and release the load from the rig, spider  10  is set against casing  32  to hold the casing string. Traveling block  1  is then raised about 6 inches to pick up on top drive unit  3  enough to disengage plate  64  from the top of casing  32 . Plate  64  is then rotated so that pins  65  are aligned with the vertical portion of the 3-shaped slot  62 . Traveling block  1  is then lowered about 6 inches to push down on top drive unit  3  enough to allow elevator  14  to be released from casing string  32 . The assembly can now be positioned to receive the next joint of casing  32  to be added to the string. 
         [0060]      FIG. 7  is a partial cross-sectional view of another embodiment of fill-up and circulating tool  46  of the present invention. Tool  46  includes a mandrel  19  having a bore  19   a  formed therethrough in fluid communication between a top and bottom end, the top end being adapted for connecting to a top sub assembly for connecting to a rotary or top drive as commonly known in the art and as shown in previous embodiments. Cementing apparatus  47 ,  49  and  50  may also be connected with tool  46  of the present invention as shown in  FIG. 5 . Tool  46  further includes a thimble  28  and a sealing element  29  connected about mandrel  19  for sealing annulus between casing  32  and tool  46  when tool  46  is in the circulating or cementing mode. Tool  46  further includes a pressure relief housing  110  connected to mandrel  19  having a fluid pathway formed therethrough and in fluid connection and continuing fluid pathway  19   a  of tool  46 . Pressure relief housing  110  forms at least one lateral aperture or port  112  which provides a fluid pathway in communication with the mandrel pathway  19   a  for preventing flow from pathway  19   a  into casing  32  while allowing fluid flow from said casing  32  through aperture  112  into pathway  19   a  when pressure in casing  32  is greater then the pressure within tool  46  (pathway  19   a ). In a preferred embodiment a mud saver valve  34  and nozzle  35  are connected below pressure relief housing  110 . 
         [0061]      FIG. 8  is a cross-sectional view of pressure relief housing  110 . As shown, relief housing  110  is adapted for threadedly connecting to tool assembly  46 , however, relief housing  110  may be welded or be a unitary section of mandrel  19 . Formed laterally through housing  110  is an aperture  112  for allowing fluid to flow into flow pathway  19   a . A blocking mechanism  114  is in working connection with housing  110  to prevent fluid from flowing from pathway  19   a  through lateral aperture  112  into the casing. 
         [0062]    Blocking mechanism  114  as shown in  FIG. 8  is a back seat check valve assembly having a plug and seat  116  forming a pathway therethrough, a ball  118 , and a spring  120 . Housing section  110  forms a lip  122  adjacent the inner opening of aperture  112 . Disposed inside of aperture  112  and against lip  122  is spring  120  for biasing ball  118  away from pathway  19   a  and against plug and seat  116 . As shown in this embodiment, plug and seat  116  is threadedly connected within aperture  112  for easy removal in order to replace ball  118  and spring  120  when needed. Although plug and seat  116  is shown threadedly connected to housing section  110  other modes of connecting to may be utilized such as set screws. It is also contemplated that ball  118 , spring  120 , and plug and seat  116  be constructed as a single assembly. 
         [0063]    With reference to  FIGS. 1-8 , when the well is in a static condition and pressure inside of casing  32  is substantially equal to or less then the pressure within tool within pathway  19   a , ball  118  is seated against plug and seat  118  preventing fluid flow from inside the casing through port  112  back into housing  110 . When pressure inside casing  32  is greater then the pressure in pathway  19   a , ball  118  is unseated from plug and seat  116 , allowing fluid to enter pathway  19   a  through port  112  thereby relieving pressure within casing  32 . For example, when tool  46  is in the circulating mode, sealing element  29  is engagingly disposed within casing  32 . Fluid is pumped through tool  46  and ball  118  is seated against plug and seat  116  preventing fluid flow through port  112 . When pump  8  or  9  is shut down fluid is allowed to flow from casing  32  through port  112  into pathway  19   a  and past sealing element  29 . In this manner, pressure is equalized across sealing element  29  allowing tool  46   a  to be removed from casing  32 . 
         [0064]      FIG. 9  is a partial, cross-sectional view of another embodiment of pressure relief housing  110 . As blocking mechanism  114 , includes an elastomer member  124  for preventing fluid from pathway  19   a  through port  112  into the casing when pressure is greater in pathway  19   a  then in the casing. As shown, elastomer member  124  is an inverted packer cup disposed within pathway  19   a  and across port  112 . Member  124  is held in place by a locking ring  126  connected to the interior of housing  110 . Many versions of this embodiment are anticipated such as, inversion of a packer cup such as the one shown, an elastomeric flapper attached across port  12 , use of other deformable material which is biased across port  112  when pressure in pathway  19   a  is greater then the pressure in casing  32 . 
         [0065]    In addition it is anticipated that housing  112  as shown in  FIGS. 7-9  may include a port  112  but not have a blocking mechanism. In this embodiment, fluid may be pumped through tool  46  and through port  112 . When pumps  8  or  9  are shut off, fluid and pressure is allowed to bypass valve  34  and enter tool  46  through port  112  and relieve the pressure below sealing element  29 . 
         [0066]    Those who are skilled in the art will readily perceive how to modify the present invention still further. For example, many connections illustrated have been shown as threaded, however, it should be understood that any coupling means (threads, welding, O-ring, etc.). Which provides a leak tight connection may be used without varying from the subject matter of the invention disclosed herein. In addition, the subject matter of the present invention would not be considered limited to a particular material of construction. Therefore, many materials of construction are contemplated by the present invention including but not limited to metals, fiberglass, plastics as well as combinations and variations thereof. As many possible embodiments may be made of the present invention without departing from the scope thereof, it is to be understood that all matter herein set forth or shown in the accompanying drawings is to be interpreted as illustrative and not in a limiting sense. Accordingly, the foregoing description should also be regarded as only illustrative of the invention, whose full scope is measured by the following claims.

Technology Classification (CPC): 8