Abstract:
A method of cementing a liner in a well includes mounting a valve assembly that is biased in a closed position to a running tool assembly. The running tool assembly has a stinger inserted through the valve assembly, retaining the valve assembly in an open position. The stinger has a cement retainer releasably mounted to it. After lowering the running tool assembly into engagement with the liner string, the operator pumps a cement slurry through the stinger and the valve assembly. The operator then pumps the cement retainer down the liner string into latching engagement with a lower portion of the liner string. Afterward, the operator lifts the stinger from the valve assembly, causing the valve assembly to move to the closed position. The valve assembly blocks upward flow of fluid from the well conduit through the valve assembly in the event of leakage of the cement retainer.

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
       [0001]    This application claims priority to provisional patent application 61/307,238, filed Feb. 23, 2010. 
     
    
     FIELD OF THE DISCLOSURE 
       [0002]    This disclosure relates in general to equipment and methods for cementing liner strings within a wellbore, and particularly to equipment that is utilized when the liner string serves as the drill string. 
       BACKGROUND 
       [0003]    Oil and gas wells are conventionally drilled with drill pipe to a certain depth, then casing is run and cemented in the well. The operator may then drill the well to a greater depth with drill pipe and cement another string of casing. In this type of system, each string of casing extends to the surface wellhead assembly. 
         [0004]    In some well completions, an operator may install a liner rather than an inner string of casing. The liner is made up of joints of pipe in the same manner as casing. Also, the liner is normally cemented into the well. However, the liner does not extend back to the wellhead assembly at the surface. Instead, it is secured by a liner hanger to the last string of casing just above the lower end of the casing. The operator may later install a tieback string of casing that extends from the wellhead downward into engagement with the liner hanger assembly. 
         [0005]    When installing a liner, in most cases, the operator drills the well to the desired depth, retrieves the drill string, then assembles and lowers the liner into the well. A liner top packer may also be incorporated with the liner hanger. A cement shoe with a check valve will normally be secured to the lower end of the liner as the liner is made up. When the desired length of liner is reached, the operator attaches a liner hanger to the upper end of the liner, and attaches a running tool to the liner hanger. The operator then runs the liner into the wellbore on a string of drill pipe attached to the running tool. The operator sets the liner hanger and pumps cement through the drill pipe, down the liner and back up an annulus surrounding the liner. The cement shoe prevents backflow of cement back into the liner. The running tool may dispense a wiper retainer following the cement to wipe cement from the interior of the liner at the conclusion of the cement pumping. The operator then sets the liner top packer, if used, releases the running tool from the liner, and retrieves the drill pipe. 
         [0006]    A variety of designs exist for liner hangers. Some may be set in response to mechanical movement or manipulation of the drill pipe, including rotation. Others may be set by dropping a ball or dart into the drill string, then applying fluid pressure to the interior of the string after the ball or dart lands on a seat in the running tool. The running tool may be attached to the liner hanger or body of the running tool by threads, shear elements, or by a hydraulically actuated arrangement. 
         [0007]    In another method of installing a liner, the operator runs the liner while simultaneously drilling the wellbore. This method is similar to a related technology known as casing drilling. One technique employs a drill bit on the lower end of the liner. One option is to not retrieve the dell bit, rather cement it in place with the liner. If the well is to be drilled deeper, the drill bit would have to be a drillable type. This technique does not allow one to employ components that must be retrieved, which might include downhole steering tools, measuring while drilling instruments and retrievable drill bits. 
         [0008]    Published application US 2009/0107,675, discloses a system for retrieving the bottom hole assembly by setting the liner hanger before cementing the liner. If the liner is at the total depth desired after retrieving the bottom hole assembly, the operator then runs a cementing assembly on a running tool back into engagement with the liner hanger. The cementing assembly includes a tieback assembly that stabs into sealing engagement with an upper portion of the liner string. A packer may also be included with the cementing assembly for sealing an annulus surrounding the liner. In addition, a cement retainer carried by the cementing assembly is pumped down to a lower end of the liner and latched after cementing. The cement retainer prevents backflow of cement. 
       SUMMARY 
       [0009]    In the method disclosed herein, a valve assembly that is biased to a closed position is attached to a running tool assembly. A downward extending stinger of the running tool assembly extends through the valve assembly, holding the valve assembly in the open position. The running tool assembly and the valve assembly are placed into engagement with well conduit. The operator then performs one or more operations on the well conduit with the running tool assembly, including pumping a fluid through the stinger and the valve assembly while the valve assembly is in the open position. The operator then lifts the stinger from the valve assembly, causing the valve assembly to move to the closed position. The operator retrieves the running tool assembly from the conduit, leaving the valve assembly in engagement with the well conduit. 
         [0010]    While in the closed position after the stinger is lifted, the valve assembly blocks upward flow of a fluid from below the valve assembly. In one embodiment, the valve assembly also blocks downward flow of a fluid from above the valve assembly. 
         [0011]    In one method, the operation performed while the valve assembly is open includes pumping a cement slurry down the well conduit and back up an annulus surrounding the well conduit to cement the well conduit within a borehole. The operator may also pump a cement retainer from the running tool assembly down the well conduit into latching engagement with the well conduit near a bottom of the well conduit. The cement retainer prevents the cement slurry from flowing down the annulus and up the well conduit. After the cement retainer has latched, lifting the stinger closes the valve assembly. The closure of the valve assembly prevents the cement slurry from flowing down the annulus and up the well conduit in the event of failure of the cement retainer. 
         [0012]    After lifting the stinger, the operator may circulate a cleaning liquid through the stinger while the valve assembly is in the closed position. The valve assembly blocks downward flow of the liquid past the valve assembly into the well conduit. 
         [0013]    The operator may also mount a tieback assembly to the running tool assembly and secure the valve assembly to the tieback assembly. When lowering the running tool assembly into the well, the operator stabs the tieback assembly sealingly into the well conduit. Normally, the tieback assembly includes a packer. After cementing, the operator sets the packer above the cement slurry and within the annulus surrounding the well conduit. 
         [0014]    In one embodiment, the valve assembly includes a tubular housing having an axis. A pair of valve seats is mounted within the housing in axial alignment with each other. A flapper valve element is secured bra hinge to each of the seats for pivotal movement between open and closed positions. Each of the flapper valve elements is biased to the closed position in contact with one of the seats. One of the valve elements pivots in a first direction when moving from the closed to the open position. The other of the valve elements pivots in a second direction when moving from the closed position, such that when, both are in the closed position, fluid flow through the housing is prevented in both directions. 
         [0015]    Preferably, an annular seal interface is located axially between the valve elements for sealingly engaging a tubular stinger inserted through the seats while the valve elements are in the open position. The seats may be on opposite ends of a tubular body having an outer diameter scaled to an inner diameter of the housing. The annular seal interface may be located in a bore of the body axially between the seats. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0016]      FIGS. 1A-1C  comprise a half-sectional view of a liner string having a bottom hole assembly installed for drilling with the liner string. 
           [0017]      FIGS. 2A-2C  comprise a half-sectional view of a packer and cementing assembly for installation with the liner string after the bottom hole assembly is retrieved. 
           [0018]      FIGS. 3A-3B  comprise a half-sectional view of a running tool assembly for running the packer and cementing assembly of  FIGS. 2A-2C . 
           [0019]      FIGS. 4A-4F  comprise a half-sectional view of the running tool assembly of  FIGS. 3A-3B  positioned within the packer and cementing assembly of  FIGS. 2A-2C  and the packer and cementing assembly inserted into an upper end of the liner string. 
           [0020]      FIG. 5  is a half-sectional view of the valve assembly carried by the running tool assembly in  FIGS. 3A-3B  and  4 A- 4 F. 
       
    
    
     DETAILED DESCRIPTION 
       [0021]    Referring to  FIGS. 1A and 1C , a string of casing  11  has been previously installed and cemented in the wellbore. A liner string  13  extends down from casing string  11  to the total depth of the wellbore, but has not yet been cemented in place. The term “liner string” refers to a string of well pipe that does not extend all the way up to the wellhead; rather it will eventually be cemented in the wellbore with its upper end a short distance above the lower end of casing string  13 . The terms “casing” and “liner” may be used interchangeably. In this embodiment, liner string  13  will normally have been deployed by drilling the wellbore at the same time the liner string  13  is being lowered into the well. 
         [0022]    Referring to  FIG. 1C , a cementing retainer profile  17 , such as an annular recess, is also located near the lower end of casing string  13 . During liner drilling, a bottom hole assembly (BHA)  19  extends from the lower end of liner string  13 . BHA  19  is shown in dotted lines because it will be retrieved in this example before the cementing occurs. BHA  19  includes a drill bit  21  and normally additional equipment, such as an underreamer and optionally surveying instruments and directional drilling equipment. 
         [0023]    Liner string  13  also includes a torque or profile sub  23  ( FIG. 1B ), which is near the upper end of liner string  13  in this embodiment. Torque sub  23  has an internal profile  25 , such as vertical splines. A liner running tool  27  releasably secures an upper section of a work string, such as drill pipe  26  ( FIG. 1A ), to torque sub  23  of liner string  13  for transmitting torque to liner string  13  and supporting the weight of liner string  13 . A lower drill pipe section  28  ( FIG. 1C ) extends downward from torque sub  23  through liner string  13  and is secured to BHA  19 . Rotating drill pipe  26  ( FIG. 1A ) by a drilling rig (not shown) will cause lower drill pipe section  28  to rotate BHA  19 , applying drilling torque to drill bit  21 . Torque sub  23  also causes liner running tool  27  to rotate, which in turn rotates torque sub  23  because of its engagement with profile  25 . This results in the entire liner string  13  and BHA  19  rotating. Drilling fluid is pumped down upper drill pipe string  26 , lower drill pipe string  28  and out bit  21  of BHA  19 . Published application US 2009/0107675 describes more details of the liner drilling system illustrated in  FIGS. 1A-1C . Other systems for drilling with liner string  13  are feasible, including having the torque sub located near the lower end of liner string  13  rather than at the upper end as shown in  FIG. 1B . 
         [0024]    Referring to  FIG. 1B , liner string  13  also includes a lower polished bore receptacle  29  located above torque sub  23 . Lower polished bore receptacle  29  is a cylindrical member having a smooth bore for sealing purposes. A liner hanger  31  ( FIG. 1A ) mounts to the upper end of lower polished bore receptacle  29 . Liner hanger  31  will be placed in a set position before removing drill pipe strings  26 ,  28 , running tool  27  and BHA  19 . Liner hanger  31  may be a type that can be reset in order to retrieve BHA  19  for repair or replacement. If resettable, the operator can run BHA  19  back, re-engage running tool  27  with torque sub  23  and release liner hanger  31  to continue drilling. Alternately, liner hanger  31  may be a type that is set only once and remains set. Liner hanger  31  has slips  33  that grip the inner diameter of casing string  11  and support the weight of liner string  13  when set. At the completion of drilling, liner hanger  31  will be set near but above the lower end of casing string  11 . 
         [0025]    Once the well has been drilled to total depth and BHA  19  and running tool  27  are retrieved, liner string  13  will be in condition for cementing. Referring to  FIGS. 2A-2C , a packer and cementing assembly  35  will be lowered into engagement with liner hanger  31 , upper polished bore receptacle  29  and the upper portion of torque sub  23 .  FIGS. 2A-2C  illustrate packer and cementing assembly  35  as it would appear prior to lowering into casing  11 . Packer and cementing assembly  35  includes on its lower end a tieback seal nipple  37 , as shown in FIG.  2 C. Tieback seal nipple  37  is a tubular member having seals  41  located on its outer diameter. Seals  41  are adapted to sealingly engage the inner diameter of lower polished bore receptacle  29  ( FIG. 1B ). Tieback seal nipple  37  has an optional latch  39  on its lower end with gripping members that will engage a grooved profile in the upper end of torque sub  23 , as shown in  FIG. 4D . 
         [0026]    Referring to  FIG. 2B , a valve assembly  43  connects to the upper end of tieback seal nipple  37  in this example. Valve assembly  43  comprises a mechanism that has an open position and a closed position. In the closed position, valve assembly  43  seals against pressure from below and optionally against pressure from above. In the open position, valve assembly  43  may allow fluid to flow through in both directions. In this example, valve assembly  43  comprises an upper flapper valve element  45  and a lower flapper valve element  47 , each of which will pivot between an open position shown in  FIG. 2B  and a closed position, shown by dotted lines in  FIG. 5 . Referring to  FIG. 5 , each flapper element  45  and  47  is connected by a hinge  49  to a valve seat  50 . Although the valve seats  50  could be separate elements, in this example, one valve seat  50  comprises an upper end portion of a tubular central body  51 . The other valve seat  50  comprises a lower end portion of body  51 . Also, in this example, the upper seat  50  faces upward and the lower seat  50  faces downward. When in the closed position, as shown by the dotted lines, upper flapper  45  will seal against the upward facing seat  50 , and lower flapper  47  will seal against the downward facing seat  50 . When moving from the closed to the open position, one of the flappers  45  will pivot in one direction and the other in an opposite direction. For example, upper flapper  45  pivots upward when opening and lower flapper  47  pivots downward while opening. Upper and lower flappers  45  and  47  are biased by conventional springs (not shown) to the closed position. 
         [0027]    The positions of flappers  45 ,  47  may be reversed; flapper  47  may be biased to seal pressure from above and flapper  45  from below. In that instance flapper  47  would pivot upward to open and flapper  45  would pivot downward to open. Hinges  49  are shown to be on the same side of central body  51 , which is the left side as shown in  FIG. 5 . Alternately, hinges  49  could be on different sides of central body  51 . 
         [0028]    Central body  51  is secured within the bore of a tubular housing  53  with its outer diameter in sealing engagement with the bore of tubular housing  53 . Central body  51  preferably is rigidly attached to tubular housing  53  and may be secured within tubular housing  53  in various manners, including retainer rings, press-fitting or welding. Flappers  45  and  47  can be held in the open position by a central tubular member that will be subsequently explained. The bore of central body  51  has a seal interface for sealing against the tubular member. In this embodiment, the seal interface comprises seals  63  mounted in annular grooves in the bore of central body  51 . Valve assembly  43  is formed of a drillable material, such as aluminium. Rather than flapper valve elements, another assembly that would work for the same purpose would include upper and lower ball valves. Central body  51  includes an upper adapter  59  on its upper end and a lower adapter  61  on its lower end. Referring back to  FIG. 2B , adapters  59 ,  61  have threads that attach housing  53  into packer and cementing assembly  35  ( FIG. 2A ). 
         [0029]    Still referring to  FIG. 2A , a liner top packer  67  secures to the upper end of top adapter  59 . Liner top packer  67  may be a conventional packer for sealing between liner string  13  and the inner diameter of casing  11  ( FIG. 1A ). In this example, liner top packer  67  is set by weight although it could be rotationally or hydraulically set. Liner top packer  67  has a body  69  that is tubular and has a conical upper end  71 . Elastomeric packer elements  73  are located around body  69 . A set of slips  75  is positioned on conical upper end  71 . An inner tubular body of liner top packer  67  has an interior set of left-hand threads  78 , but other attachment devices besides left-had threads are feasible. A setting sleeve  76  surrounds the inner tubular body and engages the upper end of slips  75 . Packer  67  is shown in the unset position in  FIG. 2A . To set, a downward force on setting sleeve  76  will cause slips  75  to be expanded over conical surface  71  and will also deform packer elements  73  radially outward. Slips  75  will engage the inner diameter of casing  11  ( FIG. 1A ) to hold liner top packer  67  in the set position. 
         [0030]    An optional upper polished bore receptacle  77  may be mounted to the upper end of setting sleeve  76 . Upper polished bore receptacle  77  is utilized for sealing purposes in case of problems in sealing tieback seal nipple  37  ( FIG. 2C ) to lower polished bore receptacle  29  ( FIG. 1A ) if another packer is required for sealing to casing string  11 . Prior to cementing, packer and liner top assembly  35  of  FIGS. 2A-2C  will be lowered into engagement with torque sub  13 , lower polished bore receptacle  29  and liner hanger  31 , as shown in  FIGS. 1A and 1B . Packer and liner top assembly  35  will remain in the wellbore after cementing. 
         [0031]      FIGS. 3A and 3B  illustrate a running tool assembly  79 , most of which will be retrieved after cementing. Running tool assembly  79  includes an adapter  81  at the upper end for securing it to a work string such as a string of drill pipe. Running tool assembly  79  includes a packer setting tool  83 , which secures to the lower end of adapter  81 . Packer setting tool  83  is a type utilized for setting packer  67  ( FIG. 2A ). In this example, packer setting tool  83  is a mechanical type tool that sets in response to rotation and weight imposed by the running string. Alternately, it could be a hydraulically actuated tool. Packer setting tool  83  has a set of spring-biased dogs  85  that are biased radially outward. When running tool assembly  79  is inserted into packer and cementing assembly  35 , dogs  85  will be located within upper polished bore receptacle  77  and urged outward against the sidewall of receptacle  77 . In this initial position, dogs  85  will not transmit any downward weight. When engaging an upward facing shoulder, such as the rim of upper polished bore receptacle  77 , dogs  85  will transmit a downward force. Packer setting tool  83  may have a clutch mechanism  87  of a type conventionally utilized for setting tools for liner top packers. Clutch mechanism  87  transmits rotation when weight is imposed on it. Packer setting tool  83  has a left-hand threaded connector  89  on its lower end. Threaded connector  89  will be secured to left-hand threads  78  ( FIG. 2A ) of the inner tubular body of liner top packer  67  while being assembled at the surface. The engagement of threaded connector  89  with threads  78  connects packer and cementing assembly  35  of  FIGS. 2A-2C  to running tool assembly  79  of  FIGS. 3A and 3B . 
         [0032]    Running tool assembly  79  includes a stinger  91  that extends downward from threaded connector  89 . Stinger  91  is a tubular member that extends through valve assembly  43  and holds flapper elements  45  and  47  in the open position. Seals  63  ( FIG. 5 ) in body  51  seal against stinger  91 . Alternately, seals  63  could be located on stinger  91 . 
         [0033]    Stinger  91  has a cementing retainer or plug  93  releasably connected to its lower end. In this embodiment, cement retainer  93  is a latching type. As shown in  FIG. 3B , cementing retainer  93  has an inner body  95  that may be rigid and formed of a drillable material. An axial passage  96  extends through inner body  95  for the passage of fluid. An outer sleeve  97  is formed of elastomeric material and has circumferentially extending ribs  99 . Ribs  99  are adapted to form a seal in liner string  13 . Cement retainer  93  has an adapter  101  on its upper end that releasably secures cement retainer  93  to the lower end of stinger  91  with shear pins. Adapter  101  has an internal seat  103  that is adapted to receive a sealing object pumped down, such as a dart  107  ( FIG. 4D ). Dart  107  is a conventional pump-down member that has seals and once in sealing engagement with adapter  101 , the combination will form a seal in liner string  13 . In this embodiment, a latch  105  extends around body  95  for engaging profile  17  ( FIG. 1C ). Alternatively, cementing retainer  93  could be a non-latching type. 
         [0034]    In operation, the well will be drilled, preferably utilizing liner string  13  as the drill string. Once at total depth, liner hanger  31  ( FIG. 1A ) will be set in casing string  11  to support the weight of liner string  13 . Then the operator retrieves liner running tool  27 , drill pipe sections  26 ,  28  and bottom hole assembly  19  ( FIG. 1C ). 
         [0035]    The operator then assembles running tool assembly  79  of  FIGS. 3A and 3B  in packer and cementing assembly  35  of  FIGS. 2A-2C . When doing so, in this example, the operator will secure threaded connector  89  to threads  78  by left-hand rotation. Stinger  91  will pass through valve assembly  43 , pushing and retaining flappers  45 ,  47  in the open position. Seals  63  ( FIG. 5 ) seal around stinger  91 . Tieback seal nipple  37  will be spaced such that when lowered into casing string  11 , it will be substantially located within lower tieback receptacle  29 . Cement retainer  93  ( FIG. 3B ) will be in sealing engagement with tieback seal nipple  37 . Dart  107  will not be in position at this time. The operator secures adapter  81  to a work string, such as drill pipe  26  ( FIG. 4A ), and lowers the entire assembly. 
         [0036]    Referring to  FIG. 4F , latch  39  on the lower end of tieback seal nipple  37  will enter lower polished bore receptacle  29  and latch into an annular grooved profile formed in the upper end of torque sub  23 . As shown in  FIG. 4D , cement retainer  93  will be located within liner hanger  31 , and valve assembly  43  will be above, as shown in  FIG. 4C . Liner top packer  67  will be located within casing string  11  above liner hanger  31  as shown in  FIGS. 4B-4D . 
         [0037]    The operator at that point preferably releases the engagement of running tool assembly  79  ( FIG. 4D ) from packer and cementing assembly  35  ( FIG. 4B ). In this embodiment, the operator disengages by rotating drill pipe  26  to the right, which will unscrew threaded connector  89  from internal threads  78  ( FIG. 4B ). Once released, the operator will pull running tool assembly  79  upward a short distance with drill pipe  26 . This will cause the running tool assembly  79  to move upward relative to the packer and cementing assembly  35 , indicating to the operator that running tool assembly  79  is released from packer and cementing assembly  35 . The operator will then set back down without setting packer  67 . 
         [0038]    The operator then is free to pump cement down drill pipe  26  and the assembly shown in  FIGS. 4A-4F . The cement will flow through cement retainer  93  ( FIG. 4D ), the torque sub  23  ( FIG. 4F ) and out the bottom of liner string  13 . When the desired quantity of cement has been dispensed, the operator then drops dart  107  ( FIG. 4D ) down drill pipe  26 . Dart  107  lands in sealing engagement with adapter  101  of cement retainer  93 . Applying fluid pressure at the surface will cause the shear pin between adapter  101  and stinger  91  to release. Cement retainer  93  and dart  107  move down in unison into engagement with profile  17  ( FIG. 1C ). Once in engagement, cement retainer  93  and dart  107  form a seal in liner string  13  and are prevented from moving upward by the latching engagement. The cement in the annulus surrounding liner string  13  will be prevented from flowing back up within liner string  13  by cement retainer  93  and dart  107 . 
         [0039]    The operator will then set liner top packer  67  ( FIG. 4B ) by first pulling upward a distance sufficient for dogs  85  ( FIG. 4A ) to move above the upper end of upper polished bore receptacle  77 . Dogs  85  will then spring outward past the outer diameter of upper polished bore receptacle  77 . The amount of this upward movement is not enough to cause stinger  91  to move above valve assembly  43  ( FIG. 4C ), thus flappers  45 ,  47  remain open. The operator then lowers drill string  26  and running tool assembly  79  relative to packer and cementing assembly  35 . Dogs  85  will contact the upper end of upper polished bore receptacle  77 . The operator slacks off weight, which transmits through upper polished bore receptacle  77  to setting sleeve  76 . Setting sleeve  76  will move downward relative to packer body  69 , which causes liner top packer  67  to set. Its slips  75  will grip the inner diameter of casing  11 . Packer elements  73  will seal against the inner diameter of casing  11 . 
         [0040]    The operator then will pull drill string  26  upward again, but a distance sufficient to place the lower end of stinger  91  above valve assembly  43 . This upward movement causes stinger  91 , which previously was holding flappers  45  and  47  ( FIG. 4C ) in the open position, to move above flappers  45  and  47 . Flappers  45  and  47  will then spring to the closed position shown by the dotted lines in  FIG. 5 . This closed position prevents any upward flow of fluid in the event of cement in the annulus leaking past cement retainer  93  ( FIG. 4D ). The closure of flappers  45 ,  47  also prevents any downward flow of fluid below valve assembly  43 . The barrier created will allow the operator to circulate a cleaning fluid, such as water, downward and out the lower end of stinger  91  ( FIG. 4D ). The cleaning fluid circulates back up the annulus surrounding drill pipe  26 . Alternately, the operator could circulate the cleaning fluid down the annulus in casing  11  surrounding drill pipe  26  and back up stinger  91 . This fluid flow will clean liner top packer  67  and upper polished bore receptacle  77  of cement and debris. If cleaning is not required, valve element  43  could have a single flapper valve element, rather than two. The single flapper valve element would block upward flowing fluid in case cement retainer  93  leaks, but would not block downward flowing fluid. 
         [0041]    After cleaning, the operator is free to pull up running tool assembly  79 , except for cement retainer  93 , which remains latched at the lower end of liner sting  13 . Once running tool assembly  79  has been retrieved, and when the operator wishes to complete the well, he will lower a string with a drill bit into the casing  11 . The drill bit is employed to drill through the valve assembly  43 , which is made of easily drillable components. This disintegration of valve assembly  43  thus opens the cemented liner string  13  down to cement retainer  93  ( FIG. 3B ). If desired, the operator may wish to drill out the cement retainer  93 , which may also be formed of drillable materials. The operator then may complete the well by in a conventional manner, such as by running tubing and perforating. 
         [0042]    While only one embodiment has been shown, it should be apparent to those skilled in the art that various changes and modifications may be made.