Patent Publication Number: US-11391113-B2

Title: Tandem cement retainer and bridge plug

Description:
CLAIM OF PRIORITY 
     This application claims priority to and is a continuation of U.S. patent application Ser. No. 16/103,447, filed on Aug. 14, 2018, the entire contents of which is hereby incorporated by reference. 
    
    
     TECHNICAL FIELD 
     This disclosure relates to a tandem cement retainer and bridge plug for remedial applications such as squeeze cementing. 
     BACKGROUND 
     Oil well cementing may include mixing a slurry of cement and water, and pumping the slurry down the wellbore casing, tubing, or drill pipe to a specified elevation or volume in the well. Primary cementing may involve casing cementation. In particular, primary cementing may be the cementing that takes place soon after the lowering of the casing into the hydrocarbon formation and may involve filling the annulus between the casing and the hydrocarbon formation with cement. Secondary cementing may include various cementing operations in which cement is pumped into a well during drilling or production phases. Secondary cementing can involve remedial cementing such as squeeze cementing. 
     SUMMARY 
     An aspect relates to a downhole tool assembly including a bridge plug and a cement retainer in tandem to be deployed into a wellbore on the same run for remedial cementing of the wellbore. 
     Another aspect relates a downhole tool assembly to be lowered into a wellbore on a single trip for secondary cementing. The assembly includes a re-settable cement retainer on an upper portion of the downhole tool assembly, a bridge plug on a lower portion of the downhole tool assembly, and a lower stinger coupling the re-settable cement retainer to the bridge plug. The bridge plug is coupled to the lower stinger via a shear pin. 
     Yet another aspect relates to a method of operating a downhole tool assembly for squeeze cementing of a wellbore having a casing. The exemplary method includes lowering, via a drill string, a lower bridge plug and an upper cement retainer coupled via a lower stinger into the wellbore on a single trip to below a wellbore zone to be squeeze cemented. The method includes setting the lower bridge plug, setting the upper cement retainer, and pressure testing to confirm isolation of a lower portion of the wellbore below the bridge plug. In some examples, the upper cement retainer is initially set against casing blank pipe below the wellbore zone to be squeezed. In addition, the method includes unsetting the upper cement retainer, repositioning the upper cement retainer to above the wellbore zone to be squeeze cemented, re-setting the upper cement retainer, introducing cement through the upper cement retainer into the wellbore zone, and allowing the cement introduced into the wellbore zone to harden. In some examples, prior to introducing the cement, the method can include pressure testing the cement retainer from annulus to confirm isolation of a upper section of the wellbore above cement retainer. Moreover, the introducing of the cement may involve pumping the cement through the upper cement retainer into the wellbore zone. 
     Yet another aspect relates to a method of operating a downhole tool assembly for remedial cementing, including coupling the downhole tool assembly to a lower end of a drill string via an upper stringer. The method includes lowering the downhole tool assembly in a collapsed mode into a wellbore on a single run via the drill string, the downhole tool assembly including a lower bridge plug and an upper cement retainer coupled via a lower stringer, wherein the upper cement retainer is mechanically re-settable. For example, the cement retainer is mechanically re-settable by rotating the string. See the non-limiting example of the drill string  110  in  FIGS. 3B-3D . Further, the method includes setting the lower bridge plug, wherein the lower bridge plug is coupled to the lower stinger via a shear pin. In one example, the lower bridge plug is mechanically set hydraulically by dropping a ball into the drill string. See the non-limiting example of the ball  304  in  FIG. 3B . 
     Yet another aspect relates to a method of operating a downhole tool assembly for squeeze cementing, including coupling the downhole tool assembly to a lower end of a drill string via an upper stringer, the upper stringer coupled via a first shear pin to a cement retainer of the downhole tool assembly. The method includes deploying into a wellbore via the drill string the downhole tool assembly to below a wellbore zone to be squeeze cemented, the downhole tool assembly having the cement retainer and a bridge plug coupled via a lower stringer, the bridge plug coupled to the lower stinger via a second shear pin. The method includes setting the bridge plug by dropping an activation ball to a ball seat of the bridge plug and pressuring the drill string to at least 1000 pounds per square inch gauge (psig). The method includes raising the drill string to pull up the lower stringer to shear the second shear pin to release the bridge plug from the lower stringer and the downhole tool assembly. The method includes setting the cement retainer by rotating the drill string in a first direction. In addition, the method includes pressure testing between the cement retainer as set and the bridge plug as set to confirm seal integrity and isolation of the wellbore below the bridge plug. 
     The details of one or more implementations are set forth in the accompanying drawings and the description below. Other features and advantages will be apparent from the description and drawings, and from the claims. 
    
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
         FIG. 1  is a diagram of a downhole tool assembly for secondary cementing. 
         FIG. 1A  is a diagram of a cement-retainer internal bypass in a closed position. 
         FIG. 1B  is a diagram of the cement-retainer internal bypass  FIG. 1A  but in the open position. 
         FIG. 2  is a diagram of the downhole tool assembly of  FIG. 1  lowered into a wellbore. 
         FIGS. 3A-3E  are diagrams of a downhole tool assembly over time as deployed in a wellbore. 
         FIG. 4  is a block flow diagram of a method of operating a downhole tool assembly for secondary cementing. 
     
    
    
     DETAILED DESCRIPTION 
     Aspects of the disclosure relate to well intervention in oil and gas production. In particular, embodiments of the present techniques may be directed to well intervention equipment and methods for remedial cementing. Features may include combining both a drillable-composite bridge plug and a drillable-composite cement retainer (or squeeze packer) in tandem in one run for remedial cementing a casing leak or for selective perforation abandonment. In examples, the remedial cementing is squeeze cementing. 
     Squeeze cementing generally is a secondary cementing which may involve applying hydraulic pressure to force or squeeze a cement slurry or sealant in contact with a formation, either in open hole or through perforations in the casing or liner. A casing leak may be repaired by squeezing cement through the leak. Squeeze cementing is sometimes employed to seal off selectively perforations intervals, plug a water producing zone, or seal a depleted open-hole, and the like. 
     Again, the cement retainer may be drillable or a drillable squeeze packer in some examples. In a particular example, the composite material for the cement retainer or bridge plug body may include woven fiberglass cloth laid up with resin mixture. Some elements of the cement retainer or bridge plug may be constructed of brass or aluminum, or both. 
     For remedial cementing, such as squeeze cementing, a lower bridge plug and an upper cement retainer may be run downhole on two separate runs. In a first trip, the lower bridge plug may be lowered into the wellbore and set below a casing leak or perforations, and pressure tested. Then, the cement retainer is deployed on a second trip and set above the casing leak or perforations. For the remedial cementing, cement is pumped/squeezed through the cement retainer into the wellbore portion/formation zone to be isolated between the upper cement retainer and the lower bridge plug. 
     In contrast, embodiments herein deploy the lower bridge plug and the upper cement retainer in tandem on a single trip (the same trip). For this single-trip tandem deployment, embodiments may be a downhole drillable tool assembly employed for squeeze cementing into a casing leak or for selective perforation abandonment. The assembly may have (1) a ball-activated lower bridge plug and (2) an upper cement retainer (mechanically re-settable) deployed in tandem into the wellbore in a single trip. Such saves rig time, by eliminating one full trip as compared to the bridge plug and cement retainer deployed separately. 
     In operation, initially the upper cement retainer and the lower bridge plug are both deployed to below the casing leak. The lower bridge plug is set to isolate a perforation or open hole underneath from the casing leak above. Then, the re-settable upper cement retainer (or squeeze packer) is set for pressure testing. Next, the upper cement retainer may be un-set, repositioned to above the casing leak zone, and re-set. Cement is pumped through an internal flow path or bypass of the cement retainer. Lastly, the internal flow path or bypass may be closed to isolate the hydrostatic column of drilling fluid from the leak zone and to maintain the cement in position until the cement sets and hardens. Thus, certain embodiments herein include setting both a temporary, ball-activated, drillable bridge plug and a separate drillable, mechanically re-settable, cement retainer (or squeeze packer) in a single trip downhole. Again, such may save rig time and cost by eliminating one full trip compare to the two trips discussed above. 
     As for the tool assembly, an upper stinger may couple the cement retainer to the drill string (work string). A lower stinger may couple the cement retainer with the lower bridge plug. The lower bridge plug, once deployed, may be activated or set hydraulically, for example, by dropping a setting ball that lands on a ball seat of the bridge plug. Then, by applying pressure in the drill string, the packer elements (seal) and slips (mechanical slips) of the bridge plug may engage the wellbore casing and thus provide a seal. As mentioned, this lower bridge plug may isolate lower perforations or the open hole underneath from a casing leak above. Once this bridge plug is set, the drill string may be pulled up, for example, to shear pins connecting the bottom of the lower stinger to the bridge plug. Such may release the bridge plug from the downhole tool assembly. As indicated, both the bridge plug toward the bottom and the cement retainer toward the top may be made of composite material that are drilled with a bit or mill after completing the cement squeeze operation. 
     After pulling up the lower stinger above the bridge plug (for example, to a few feet above the bridge plug), the upper cement retainer (re-settable) may be set, for example, by rotating the drill string in a first direction. In examples, the first direction of rotation may be right hand, or to the right or clockwise with respect to the surface. The cement retainer may be set in order to pressure test both the lower bridge plug packers (seal) and the casing in between the lower bridge plug and upper cement retainer. The pressure test may include pressuring through the working drill string and confirming that the lower wellbore is properly isolated. Then, in some implementations, by rotating the drill string in a second direction (for instance, opposite the first direction), the upper cement retainer may be unset and the drill string pulled up to reposition the upper cement retainer above, for instance, a casing leak zone. The second direction may be left hand, or to the left or counterclockwise with respect to the surface. With the upper cement retainer positioned above the casing leak, the drill string may be rotated, for example, in the first direction to re-set the upper cement retainer. Here, after re-setting the upper cement retainer, the internal bypass or flow path of the cement retainer may be in the open position for squeeze cementing. 
     In some examples, confirmation of setting of the cement retainer may be by pressuring the casing-drill pipe annulus. The pressure test may confirm that the packer element of the cement retainer is sealing against the internal surface of the casing and that the casing itself above the cement retainer ( FIG. 3D ) has no leak. The pressure test may be based on casing condition from corrosion log interpretation. In one example, the pressure test is performed at least to 500 pound per square inch gauge (psig) with the hydrostatic head of drilling fluid (kill fluid). In another example, the pressure test is performed to 1500 psig or less with water. In some instances, the pressure test may be performed per an industry standard or company policy. 
     Then, after setting of the cement retainer (and any pressure testing), the drill string may be raised to apply straight pull force. Thus, the shear pins holding the cement retainer to the upper stinger or drill string may shear. The upper stinger is pulled out of the cement retainer to close, for example, an internal bypass or flow path of the cement retainer. In examples, the internal bypass has generally not been open and not closed in the preceding steps. A purpose of the raising of the stinger and closing of the internal bypass may be to verify bypass functionality of close/open and also best practice to shear the pins before starting the remedial cementing job. Once cement slurry is mixed and ready to be pumped, the upper stinger may be lowered back into the cement retainer to re-open the internal bypass and the cement squeeze operation can be performed. Again, as should be apparent, the internal bypass would have typically already been open if the stinger earlier had remained in the cement retainer but the pins would not have been sheared and the bypass closed position functionality not confirmed. 
     The cement is then pump from the surface through the drill string and the internal bypass in the cement retainer to the wellbore zone below to be squeeze cemented. Then, after pumping the cement slurry, the upper stinger is pulled out of the cement retainer to close the bypass and isolate the hydrostatic column of the drilling fluid from above the leak zone and maintain the cement in position until the cement sets and hardens. Lastly, as indicated for embodiments, the upper cement retainer and the lower bridge plug, and the lower stinger in between, may be made of easily drillable material that can be drilled with a conventional bit or mill. 
     In general, cement retainers are typically used in cement squeeze or similar remedial treatments. As discussed, a specially profiled probe known as a stinger may be attached to the bottom of the tubing string or drill string to engage the retainer during operation. When the stinger is removed, the valve assembly of the cement retainer may isolate the wellbore below the cement retainer. The cement retainer may be a tool including slips, a ported mandrel, elastomer or rubber sealing elements, and so forth. In some implementations, the cement retainer may be set in the casing which allows cement or other fluids to be pumped through the tool, but seals against fluid movement when the tubing is released from the tool. Thus, a cement retainer may be an isolation tool set in the casing or liner that facilitates treatments to be applied to a lower interval while providing isolation from the annulus above. As mentioned, a profiled probe known as a stinger is connected to the bottom of the tubing string and inserted into the cement retainer during operation. Again, when the stinger is removed, the cement-retainer internal valve assembly will close and isolate the wellbore below the cement retainer 
     In summary, some embodiments herein include a downhole easy drillable tool assembly employed for squeeze cementing into a casing leak or for selective perforation abandonment. The assembly has (1) a ball-activated lower composite material bridge plug and (2) an upper composite material cement retainer (mechanically re-settable) deployed in tandem into the wellbore in a single trip. Such saves rig time by eliminating one full trip as compared to the bridge plug and cement retainer deployed separately. In operation, the lower bridge plug is set underneath a casing leak to isolate a perforation, open hole, or casing/liner underneath from the casing leak above. Then, the re-settable upper cement retainer is set below the casing leak for pressure testing. Next, the upper cement retainer will be unset, repositioned to above the casing leak zone, and re-set. Cement is pumped through an internal bypass of the cement retainer. Lastly, the cement stinger may be sheared and stung out from cement retainer, the internal-bypass ball valve shifting to close position under final squeeze pressure to isolate the hydrostatic column of drilling fluid from the leak zone or perforation, and to leave pressure below until the cement sets and hardens. Whereas a squeeze packer in lieu of the cement retainer may not be drillable and is pulled out to surface after the squeeze job. 
     Due to their composite-material construction, both the bridge plug and cement retainer may be easy drillable with a relatively low amount of junk generated in the drilling. Such may result in reduced rig time and reduced number of future runs for cleaning the junk, and the like. Junk may be relatively small items of non-drillable metals that fall or are left behind in the wellbore or borehole during the drilling. 
       FIG. 1  is a downhole tool assembly  100  that can be coupled to a working drill string  110  and sent downhole into a wellbore in a single trip. The assembly  100  includes a bridge plug  102  and cement retainer  104  as discrete or separate devices coupled via a lower stinger  106 . The bridge plug  102  is a lower portion of the assembly  100  below the cement retainer  104 . The cement retainer  104  is an upper portion of the assembly  100  above the bridge plug  102 . As indicated, the bridge plug  102  and cement retainer  104  (as components of the tool assembly  100 ) may be lowered in tandem into the wellbore on the same run. The coupling via the lower stinger  106  may facilitate deployment of the bridge plug  102  and cement retainer  104  on the same run. The lower stinger  106  may be a profiled probe or longitudinal coupler having a specified length. In examples, the lower stinger  106  may be coupled to the cement retainer  104  via a threaded connection or other type of connection. In contrast, the lower stinger  106  may be coupled to the bridge plug  102  via a shear pin  122 , as discussed below. 
     A bridge plug  102  may be a downhole tool that is located and set in the wellbore to isolate the lower part of the wellbore. Bridge plugs may isolate or seal the lower wellbore from production, from a treatment conducted on an upper zone, or as well control barrier for a high pressure zone underneath, and so forth. Indeed, a bridge plug may be run and set in casing to isolate a lower zone while an upper section is tested, cemented, stimulated, or produced. In general, bridge plugs in place may be permanent, retrievable, drillable, and the like. To facilitate removal by drilling, a bridge plug may be made of cast iron or composite material. In the illustrated example of  FIG. 1 , the bridge plug  102  is constructed of composite material and is drillable. In certain implementations, the bridge plug  102  may be a one-time set plug and isolate the wellbore section below. The bridge plug  102  may have a ball seat  120  and be set by a setting ball and pressure, and not have a close/open sleeve or ball. 
     A cement retainer  104  may be a sealer or isolation tool set in the casing or liner that facilitates treatments to be applied to a lower interval while providing isolation from the annulus above. The cement retainer may be a tool set temporarily or permanently in the casing or well to prevent the passage of cement, thereby forcing or routing the cement to follow another designated path. In certain embodiments discussed herein, the cement retainer  104  is ultimately set permanently and may be removed by being drilled. Again, the cement retainer  104  may be employed in squeeze cementing and other remedial cementing jobs. The cement retainer  104  generally has an internal bypass (for example, internal bypass valve  124 ) and hold-down slips (for example, mechanical slips  116 ). The bypass gives a path for cement flow through the cement retainer  104  to further downhole, and thus may be labeled as a cementing internal bypass. Indeed, the bypass can facilitate the pumping/injection of cement through the cement retainer  104  to the treatment zone, for example, having the casing leak or perforations to be cemented. Of course, the internal bypass may also allow for fluid generally, such as drilling fluid, to flow through the cement retainer. The hold-down slip assembly, such as mechanical slips  116 , may facilitate application of relatively high squeeze pressure without the cement retainer  104  unsetting or moving up the wellbore. The bypass may be closed when the remedial cementing of that zone is complete. 
     In some examples, a squeeze packer or cement retainer  104  may be a downhole permanent or drillable cement retainer set by lowering some of the weight of the tubing string  110  onto the cement retainer  104 . The weight expands the sealing element, such as seals  118 , of the cement retainer  104  to prevent flow between the tubing string  110  and the casing below the cement retainer. Again, the cement retainer  104  may be a millable cement retainer for remedial cementing such as squeeze cementing. In certain implementations, the cement retainer  104  may be employed to pressure test the section above or the section below and provide a path for pumped cement through the cement retainer to below the cement retainer. The cement retainer  104  may have a mechanical set/unset by rotation of the drill string  110 . In particular examples, the cement retainer  104  may have close/open positions by shifting a ball valve  124  via the stinger  108  and lock with a hexagonal profile, and so forth. 
     In summary, a cement retainer  104  may be drillable and for receiving pumped cement there-through, and can maintain pressure underneath while cement sets. In contrast, while a squeeze packer may be compared to a cement retainer, examples of a squeeze packer are retrievable and non-drillable, are generally not used for pumping cement there-through, and typically cannot accommodate the cement setting under pressure. Some squeeze packers can be employed to squeeze chemical treatment or acid while isolating the upper casing or wellbore from squeeze pressure 
     The drill string  110  or the assembly  100  may include an upper stinger  108  to couple the cement retainer  104  (and thus the assembly  100 ) to the drill string  110 . The stinger  108  may be a profiled probe attached to the bottom of the tubing string  110  to engage the cement retainer  104 . In the illustrated embodiment, the upper stinger  108  has a profiled portion, such as a hexagonal portion, to lock with the cement retainer  104 . In some examples, the upper stinger  108  with its hexagonal profile to apply or transmit torque via an operator rotating the string  110  for setting and un-setting the cement retainer  104 . 
     The bridge plug  102  has mechanical slips  112  and a seal  114 . The mechanical slips  112  may be wedge-shaped or other shape, and may have protrusions (for example, on the slip face) such as teeth, buttons, wickers, inserts, wedges, and the like, to engage (for example, grip) the inner wall of the casing, tubing, or liner. The mechanical slips  112  are typically radially expandable or extendable to engage (abut, grip, partially penetrate, or hook into) the inner wall of the wellbore casing to secure (lock, fix, or anchor) the bridge plug  102  in place in the wellbore. The mechanical slips  112  may longitudinally fix the bridge plug  102  in place in the wellbore. The seal  114  may be sealing elements that are packer type to prevent flow upward or downward. The seal  114  may be or include elastomer, rubber, metal, donut-shaped, seal assembly, rings, metallic rings, backup rings, lock, ratchet-lock, anchor, packing, packer seal, and so on. In operation, the seal  114  may be radially expanded against an inner surface of the casing  202  to seal the bridge plug  102  as set in place. 
     Similarly, the cement retainer  104  may have mechanical slips  116  and a seal  118 . The mechanical slips  116 , which may be the same or similar as the bridge-plug  102  mechanical slips  112 , may secure or set the cement retainer  104  in place in the casing. The seal  118 , which may be the same or similar as the bridge-plug  102  seal  114 , may seal the set cement retainer  104  in place in the casing. Again, the bridge plug  102  and cement retainer  104  may be drillable. 
     The lower bridge plug  102  of the downhole tool assembly  100  may have a ball seat  120  to receive an activation ball or setting ball to activate or set the bridge plug. Indeed, examples of the bridge plug  102  are set by a setting ball. To set the bridge plug  102  may extend the mechanical slips  112  and expand the seal  114  against the inner surface of the casing wall (to grip the casing). In the illustrated example, the bridge plug  102  has the ball seat  120 . In operation, a ball may be dropped from the surface through the drill string  110  and pumped down the drill string  110  and through the cement retainer  104  until the ball seats on the ball seat  120  in the bridge plug  102 . Once the ball is seated on the ball seat  120 , the operator can pressure the bridge plug  102  to apply pressure against the ball and ball seat. Moreover, the operator may continue to apply pressure from the surface and the pressure may beneficially act on the ball and seat  120 . In some examples, below the ball seat  120  may be a pup joint  121  connected to the bottom of bridge plug (as a guide) and a gap  123 . 
     In the illustrated embodiment of  FIG. 1 , the bridge plug  102  is coupled to the lower stringer  106  via one or more shear pins  122 . The shear pin  122  may hold the weight of the lower bridge plug but may shear with exposed greater weight. In one example, the shear pin  122  will shear when subjected to weight of at least 30 thousand pounds (klbs). 
     The cement retainer  104  may include internal bypass valve  124  which may include or be a ball that rotates, or other type of valve. If a ball is employed, the ball may be a hollow ball in having a hollow portion or port including an interior-volume space as a path for cement to flow. In some examples, the ball may be a ball valve. Such a ball valve may be full-port or full-bore in certain examples. In implementations, spring loading is provided by a spring  126  for opening and closing the bypass valve  124  by pushing with the upper cement stinger  108 . As indicated, the ball valve  124  may be or along the internal bypass. In some implementations, when the stinger  108  is inside the cement retainer  104 , the stinger  108  pushes and rotates the ball of the bypass valve  124  to an open position and compresses down the springs  126 . Such allows cement or other drilling fluids to be pumped down through the cement retainer  104  via the internal bypass. When the stinger  108  is out of the cement retainer  104 , the springs  126  pushes the bypass valve  124  ball up which will rotate back to closed position to seal the internal (bypass) conduit of the cement retainer  104 . Thus, once the stinger  108  is stung out (through a profile), the spring  126  may push the bypass valve  124  ball which rotates to close the cement retainer  104 , isolating the upper hydrostatic column from the leak zone below the cement retainer  104 . As indicated, the spring  126  is for the valve  124 . While running in hole, the internal valve  124  may be in open position to allow for dropping of the setting ball (for example,  304  in  FIG. 3 ) to pass through the cement retainer  104  to the lower bridge plug  102  and reach the ball seat  120 . 
     The cement retainer  104  may be coupled by one or more shear pins  128  to the upper stinger  108  and thus coupled to the drill string  110 . In the illustrated example, two shear pins  128  are depicted. The shear pins  128  hold the weight of the lower bridge plug  102  and the cement retainer  104 . Once the upper cement retainer  104  is set, the shear pins  128  may be sheared such as by raising the drill string  110  to decouple the cement retainer  104  from the upper stinger  108 . Such may un-sting the cement retainer  104  from the stinger  108 , for example, to close the internal bypass valve  124 . In one example, the shear pins  128  may shear at a force or weight of at least 50 klbs. 
     The cement retainer  104  may be set and remain in hole, and isolate the hydrostatic above during wait time on cement to harden, and with the cement stinger retrieved, and so on. Moreover, the cement retainer  104  may facilitate, for example, a hesitation squeeze such for when a primary squeeze cement has failed. Again, the cement retainer seal  118  may be sealing elements of packer type and with flow not allow upward or downward when the packer-type seal is expanded. 
     In summary, the cement retainer may be re-settable and with a cycling close/open ball valve  124 . A purpose or function of the ball  124  cycling close/open feature may be associated with multiple sting in/out for the cement stinger  108  during the cement job. When the internal bypass or bypass valve  124  is closed, there generally is no flow through or around the cement retainer  104 . As the cement job is completed or finished, the sting out from the cement retainer  104  closes the bypass valve  124  so that there will generally not be flow through (or around) the cement retainer  104 , with sealing facilitated by the seals  118 . In the example depiction of  FIG. 1 , the internal bypass valve  124  is in the open position. 
       FIG. 1A  is an example of the internal bypass  130  of the cement retainer  104 . The internal bypass  130  has the bypass valve  124 . The internal bypass  130  in an open position allows for cement slurry or fluids to flow from the drill string  110  above through the cement retainer  104  to below the cement retainer  104 . If desired, drilling fluids or cement can flow through the open internal bypass  130  (and thus through the cement retainer  104 ) while the cement retainer  104  is being lowered into and repositioned in the wellbore, and after the cement retainer is set in the wellbore  104 . 
     After the cement retainer  104  is set in final position, cement slurry is pumped for the squeeze cementing and flows through the internal bypass  130  to the isolation zone below the cement retainer  104 . After the squeeze cementing (through the internal bypass  130 ) is complete, the internal bypass  130  may be placed in a closed position as depicted in  FIG. 1A . 
     The bypass valve  124  includes a ball  132  having an opening  134  such as a hollow portion or port including giving a full-port ball valve. The opening  134  may be full port in the sense that the diameter of the opening  134  is generally the same at the inside diameter (ID) of the bypass conduit or stinger  108 . 
     The internal bypass  130  may have a cavity or conduit  136  as an inlet  138  to receive cement from the drill string  100  and stinger  108  above. The bypass  130  may have a cavity or conduit portion  140  as an outlet  142  for discharge of cement from the cement retainer  104  to below the cement retainer  104 . 
     The internal bypass  130  may include fixed linear gears  143  to the side that engage gears  144  coupled to the outer surface of the ball  134 . Thus, the ball  132  may rotate via rotation of the ball gears  144  along the linear gears  143 . The ball  132  may rest on the spring  126 . 
     To close the bypass valve  124  and thus close the bypass  130 , the upper stinger  108  may be raised to pull the stinger  108  out of the cement retainer  104 . This allows the spring  126  to push up the ball  132  such that the outer diameter (OD) surface  148  of the ball  132  presses against the sealing surface  150 . As the ball is  132  is pushed up by the spring  126 , the ball  132  rotates to the closed position depicted in  FIG. 1A . The closed position may be characterized as the opening  134  not aligned (not in-line) with the internal bypass  130  flow conduit including portions  136  and  140 . For the internal bypass  130  closed position depicted in  FIG. 1A , the stinger  108  is not at the inlet  138 . Instead, the stinger  108  is disengaged from the cement retainer  104  to allow the spring  126  to decompress and push the ball  132  up against the sealing seat  150  and thus to rotate the ball  132  via the gears  144  to the closed position. 
       FIG. 1B  is the example internal bypass  130  in the open position. To open the internal bypass  130 , the stinger  108  is inserted into the body  152  of the cement retainer  104  to push down the ball  132  against the spring  126 . The ball  132  rotates via the ball gears  144  engaged with the fixed side gears  143 . The spring  126  is compressed. The ball  132  rotates such that the ball opening  134  is aligned (in-line) with the internal bypass flow conduit, as indicated by reference numeral  154 . The opening  134  (hole) through the ball  132  aligns with the internal ID of the stinger  108  to pass the setting ball (see  304  of  FIG. 3B ) of the bridge plug and also to allow pumping cement through the cement retainer  104 . Lastly, it should be emphasized that other configurations of an internal bypass may be employed. Indeed, the internal bypass depicted in  FIGS. 1, 1A , and  1 B is given as only an example. 
       FIG. 2  is a wellbore  200  formed with a casing  202  into an Earth subsurface formation  204 . In examples, a cement layer (not shown) may be disposed in the annulus between the casing  202  and the formation  204 . The wellbore  200  has perforations  206  through the casing  202  into the formation  204 . The wellbore  200  may receive hydrocarbon, such as oil and gas, from the formation  204  through the perforations  206  for oil or gas production. 
     The downhole tool assembly  100  of  FIG. 1  coupled to a drill string  110  is depicted as lowered into the wellbore  200  at a desired position in the wellbore  200 . The downhole tool assembly  100  may be implemented or applied for remedial reasons such as repairing a casing  202  leak or for selective perforation abandonment, and so on. In examples of cementing a casing  202  leak, the assembly  100  may be placed downhole below the casing  202  leak. The lower bridge plug  102  and upper cement retainer  104 , in collapsed mode, may be run inside the wellbore  200  to below the perforations  206  or to a depth of good casing below a casing leak. The collapsed mode is the mechanical slips  112 ,  116  and seals  114 ,  118  not radially extended or expanded. The perforations  206  may be the perforations that are to be abandoned and therefore cemented (cement flow through the drill string shown by reference numeral  208 ). The perforations  206  may also be cemented in repair of a casing leak. 
       FIGS. 3A-3E  are a portion of a wellbore  300  over time. Demonstrated is the operation of the downhole tool assembly  100  for remedial cementing such as squeeze cementing. In some examples, the internal bypass valve  124  in the cement retainer  104  is open in  FIGS. 3A, 3B, 3C, and 3D . 
       FIG. 3A  may be similar to the operation depicted in  FIG. 2  in which the downhole tool assembly  100  is lowered and positioned into the wellbore  300 . An upper stinger  108  may couple the cement retainer  104  to the drill string  310  (work string). A lower stinger  106  may couple the cement retainer  104  with the lower bridge plug  102 . Both the bridge plug  102  toward the bottom and the cement retainer  104  toward the top may be made of composite material that are drilled with a bit or mill after completing the cement squeeze operation. 
     In  FIG. 3A , on a single trip into the wellbore  300 , the lower bridge plug  102  and upper cement retainer  104  may be in collapsed mode and run to below the perforations  206  or to a depth of good casing below a casing leak. The collapsed mode may mean that the mechanical slips  112 ,  116  and seals  114 ,  118  are not radially extended or expanded. In some examples, the collapse mode may be the initial mode of the assembly  100  in deployment into the wellbore  300  for remedial cementing such as squeeze cementing. 
     Referring to  FIGS. 3A and 3B , after the downhole tool assembly  100  being deployed in the wellbore  300  including being lowered to the desired or specified vertical location or position within the wellbore  300 , the lower bridge plug  102  may be set by dropping an activation ball  304  and pressuring up the string  110  such as to 1000 pounds per square inch gauge (psig) or greater. In response to receipt of the activation ball  304  on the ball seat  120  and the pressure, the lower bridge plug  102  may extend its mechanical slips  112  and seal  114  against the inner wall of the casing  202  to set the bridge plug  102 . The set lower bridge plug  102  may isolate lower perforations (not shown) or the open hole underneath from a casing leak above. 
     At  FIG. 3B , after the lower bridge plug  102  is set, the drill string  110  may be raised to pull up the lower stinger  106  to shear the pin  122  and release the stinger  106  from the set bridge plug  102 . Such may release the bridge plug from the downhole tool assembly  100 . The lower stinger  106  may be made of aluminum or other material for easy drillability. After pulling up the lower stinger  106  above the bridge plug  102  (for example, to a few feet above the bridge plug  102 ), the upper cement retainer (re-settable) may be set, for example, by rotating the drill string  110  in a first direction  302 . In a particular example, the first direction  302  is a right hand rotation. 
     Continuing at  FIG. 3B , with an example right-hand rotation  302  of the drill string  110 , the upper re-settable cement retainer  104  is set against the casing  202  to facilitate a pressure test. The drill string  110  rotation may extend the mechanical slips  116  and seal  118  of the upper cement retainer  104  against the inner wall of the casing  202  to set the cement retainer  104 . With the cement retainer  104  set, a pressure test may be to pressure test of the lower bridge plug  102  from the top, the upper cement retainer  104  from the bottom, and the casing  202  in between in order to confirm seal integrity and bottom-hole isolation. Thus, the pressure test may include pressuring through the working drill string  310  and confirming that the lower wellbore is properly isolated. 
     At  FIG. 3C , in some implementations, by rotating the drill string  110  in a second direction  306  (for instance, opposite the first direction  302 ), the upper cement retainer may be unset and the drill string pulled up ( FIG. 3D ) to reposition the upper cement retainer above, for instance, a casing leak zone. In the illustrated example, by left hand rotation  306  ( FIG. 3C ) of the drill string  110 , the upper, re-settable cement retainer  104  is unset ( FIG. 3C ) and the string  110  can be pulled to reposition ( FIG. 3D ) the upper cement retainer  104  above the casing leak. 
     At  FIG. 3D , the drill string  110  is so raised to reposition the cement retainer  104  above the casing leak or above the perforations  206  for cementing of casing leak or the perforations  206 . In instances with no casing leak, the perforations  206  may be cemented for selective perforation abandonment. The flow path for the cement slurry is indicated by arrows  308 . 
     By rotation in the first direction  302  (for example, right hand rotation) of the drill string  110 , the upper, re-settable cement retainer  104  is set to seal against the casing  202  and can be pressure tested by pressuring up the casing-drill pipe annulus. Indeed, in implementations, confirmation of setting of the cement retainer  104  may be achieved by pressuring the annulus between the drill string  110  (drill pipe) and the casing  202 . In examples of the pressure test, the cement retainer  104  is set above the perforations or leak zone to be cemented and without communication below the annulus during the pressure test. If the pressure test fails, such may mean that the seals  118  are not holding pressure and, therefore, the cement retainer  104  may need to be pulled out of the wellbore and replaced with a new cement retainer  104 . 
     Then at  FIGS. 3D-3E , by applying straight pull force via raising of the drill string  110 , the shear pins  128  holding the cement retainer to the upper stinger  108  or drill string  110  may shear and the upper stinger  108  pulled out of the cement retainer  104  to close, for example, an internal bypass of the cement retainer  104 . The upper stinger  108  having a hexagonal bottom end for rotational lock and torque transfer to the setting mechanism or setter of the re-settable cement retainer  104 , is pulled to shear the pins  128  and release the stinger  108  from the upper cement retainer  104 . 
     The release of the stinger  108  from the cement retainer  104  moves up the internal bypass mandrel of the cement retainer  104  to close the cementing internal bypass of the cement retainer  104 . In one example, the release of the stinger  128  allows the spring  126  to push the ball of the bypass valve  124  up and thus with the ball rotating to close the valve  124 . 
     Continuing at  FIG. 3E , once cement  310  slurry is mixed and ready to be pumped, the upper stinger  108  may be lowered back into the cement retainer  104  to push the mandrel and open the internal cementing bypass channel for the cement flow. In one example, the lowered stinger  108  as being inserted pushes the ball (of the valve  124 ) back down rotating the ball to open the internal bypass valve  124 . With the internal bypass open, the cement squeeze operation can be performed. Once the cement squeeze operation is completed, the stinger  108  is pulled out to close the internal bypass channel and isolate the hydrostatic column of the drilling fluid from the casing  202  leak zone to maintain the cement  310  in place until the cement  310  sets and hardens. 
     Lastly, in examples, the upper cement retainer  104 , lower bridge plug  102 , and lower stinger  106  in between may be constructed of drillable material and can be drilled with a conventional bit or mill. The technique may include drilling the upper cement retainer  104 , the hardened cement  310 , and the lower bridge plug  102 . 
       FIG. 4  is a method  400  of remedial cementing of a wellbore. In particular, the method  400  may be a method of operating a downhole tool assembly for squeeze cementing of a wellbore having a casing. 
     At block  402 , the method includes lowering, via a drill string, a lower bridge plug and an upper cement retainer coupled via a lower stinger into the wellbore on a single trip to below a wellbore zone to be squeeze cemented. In other words, a bridge plug and cement retainer as two discrete devices are lower into the wellbore in a single run or single trip. As indicated, the bridge plug and the cement retainer may be coupled via a stinger (lower stinger). In implementations, the bridge plug and the cement retainer (and stinger) may be components of the downhole tool assembly deployed. As discussed above, the downhole tool assembly may deployed initially in collapse mode. 
     At block  404 , the method includes setting the lower bridge plug and setting the upper cement retainer. Setting the lower bridge plug may include dropping an activation ball through the drill string and the upper cement retainer to a ball seat of the lower bridge plug and pressuring the drill string. Setting the upper cement retainer may include raising the drill string to pull up the lower stringer to shear a shear pin to release the lower bridge plug, and rotating the drill string in a first direction. 
     At block  406 , the method includes pressure testing to confirm isolation of the lower portion of the wellbore (the lower wellbore). The pressure testing may include introducing pressure through the drill string (see, for example,  FIG. 3B ) to pressure test the upper cement retainer from below, the lower bridge plug from above, and the casing between the upper cement retainer and the lower bridge plug. The fluid to pressure may include existing fluid from the well such as water, kill fluid, brine, drilling mud, and so on. 
     At block  408 , the method includes unsetting the upper cement retainer, further raising the drill string to reposition the upper cement retainer above the wellbore zone to be squeeze cemented, and re-setting the upper cement retainer. In examples, unsetting the upper cement retainer is performed by rotating the drill string in a second direction opposite the first direction. The re-setting of the cement retainer may be by rotating the drill string in the first direction. 
     At block  410 , the method includes introducing cement through the upper cement retainer into the wellbore zone, and allowing the cement introduced into the wellbore zone to harden. The cement introduced may be a cement slurry of cement and water. The method  400  may include drilling the upper cement retainer, drilling the cement hardened in the wellbore zone, and drilling the lower bridge plug. 
     In general, a cement retainer as a squeeze tool or squeeze packer in examples may be a type of retrievable or drillable packer in remedial cementing such as squeeze cementing. Depending on the configuration or type of cement retainer, the cement retainer may be un-settable or not un-settable. Squeeze cementing may include packer techniques, hesitation squeeze techniques, and so on. The wellbore interval to be squeezed may be isolated from the surface by a cement retainer or packer run set on tubing. Retrievable or permanent (drillable) cement retainers can be used. Further, to isolate the section below the perforations or casing leak to be squeezed, a drillable or retrievable bridge plug may be placed below the perforations or casing. The upper perforations may then be squeezed and the remaining slurry reversed out in some examples. A hesitation squeeze may involve placement of cement in a single stage but divides the placement, for example, into alternate pumping and waiting periods. This hesitation practice may utilize controlled fluid loss properties of the slurry to build filter cake nodes against the formation and inside the perforations while the parent slurry remains in a fluid state in the casing. 
     Equipment commonly employed in squeeze cementing includes high pressure pumps, retrievable or drillable type cement retainers (or squeeze packers) and retrievable or drillable bridge plugs, and so forth. In general, bridge plugs may provide a pressure and fluid boundary between sections of casing or can be used as well control barrier, and the like. Multiple zones can be isolated individually for the desired treating or testing procedures. Cement retainers may provide pressure or fluid control for remedial cementing operations. The cement retainer or squeeze packer tool may be used in conjunction with the work string tubular. Typically, as discussed, a valve built in the cement retainer tool helps hold cement in place by providing downhole pressure control. The cement retainer may have additional control features. Moreover, the cement retainer may be drillable or may be removed from the well by the use of common oil well drilling equipment and practices. 
     The cement retainer may seal off the annulus but allows fluid communication between drill pipe and the wellbore beneath the cement retainer. This type of packer contains a back pressure valve (for example, versions of a bypass valve  124 ) which will prevent the cement flowing back after the squeeze. These may be employed for remedial work on primary cement jobs, or to close off water producing zones. The packer may be run on drill pipe or wireline and set above or between sets of perforations. When the cement has been squeezed, the drill pipe can be removed closing the back pressure valve. The advantages of these packers may be depth control, the back pressure valve prevents cement back flowing, and the drill pipe recovered without disturbing the cement. As indicated for examples, the cement retainer may be unset and re-settable, such that the cement retainer can be utilized more than once. These generally can be set and released many times on one trip, such as with repairing a series of casing leaks or selectively squeezing off sets of perforations. In certain implementations, bypass ports (for example, with valve  124 ) in the packer or cement retainer may allow annular communication but these ports are typically closed during the squeeze job. When the packer or cement retainer is released there may be some backflow and the cement filter cake disturbed. In response, the packer or cement retainer may be re-set and the squeeze pressure applied until the cement sets. 
     Some examples of cement squeezing with a retrievable or drillable cement retainer involve running the cement retainer on a drill pipe and setting the cement retainer at the desired depth with bypass open. Cement slurry is pumped and with back pressure on the annulus to prevent cement falling. The setting depth of the cement retainer may be specified so not to be positioned too high above the perforations. In examples, the cement retainer may be set in a range of 30 feet to 50 feet above the perforations to be cemented. In a particular example, a tail pipe is employed below the cement retainer or packer to facilitate that only cement is squeezed into the perforations. Bridge plugs are often set in the wellbore to isolate zones which are not to be treated. The bridge plug may seal off the entire wellbore, and hold pressure from above and below. As mentioned, bridge plugs can be drillable or retrievable. 
     A downhole tool assembly for remedial cementing, such as squeeze cementing, may include two components in tandem that are lowered in a single trip via a drill string into the wellbore. The two components may be coupled via a stinger. The two components may each be a wellbore obstructer, wellbore isolator, or wellbore sealer, or any combinations thereof. The lower component may be a packer, plug, or bridge plug, and the like, in a lower position on the assembly. The upper component may be a packer, cement packer, cement retainer, or squeeze packer, and so on. The assembly can be conveyed or deployed by a drilling rig. The assembly may be connected to the drilling rig via the drill string, tubing string, or threaded pipe, and so forth. In some examples, the tandem assembly is not set on coil tubing or wireline due to no rotation feature for setting the upper cement retainer. In the illustrated example of  FIG. 1 , the lower component is a bridge plug  102  on a lower portion of the downhole tool assembly  100 , and the upper component is a cement retainer  104  on an upper portion of the downhole tool assembly  100 . Lastly, while the discussion herein at times has focused on remedial cementing, some implementations of the present techniques are applicable to other types of cementing. 
     In summary, an embodiment is a downhole tool assembly having a bridge plug and a cement retainer (for example, re-settable) to be deployed into a wellbore on a same run for remedial cementing of the wellbore. The cement retainer may be on an upper portion of the downhole tool assembly, and the bridge plug is below the cement retainer on a lower portion of the downhole tool assembly. In certain examples, the cement retainer and the bridge plug are coupled via a stinger to facilitate lowering of the cement retainer and the bridge plug on the same run into the wellbore. In a particular example, the cement retainer is coupled to the stinger via a threaded connection. The bridge plug may be coupled to the stinger via a shear pin. The downhole tool assembly to couple via a first stinger to the drill string, and wherein the cement retainer and the bridge plug are coupled via a second stinger to facilitate lowering of the cement retainer and the bridge plug on the same run via the drill string into the wellbore. Further, the cement retainer and the bridge plug may be each be composite material and are drillable. In some implementations, the downhole tool assembly to couple via a stinger to a drill string, and wherein the cement retainer is set via rotation of the drill string. In certain examples, the bridge plug has a ball seat to receive an activation ball to set the bridge plug against an inner wall of the wellbore. The cement retainer may have an internal bypass having a first operating position that opens squeeze cementing flow and a second operating position that closes squeeze cementing flow. 
     Another embodiment includes a downhole tool assembly to be lowered into a wellbore on a single trip for secondary cementing. The assembly includes a re-settable cement retainer on an upper portion of the downhole tool assembly, a bridge plug on a lower portion of the downhole tool assembly, and a lower stinger coupling the re-settable cement retainer to the bridge plug. The bridge plug is coupled to the lower stinger via a shear pin. In examples, the downhole tool assembly to couple via an upper stinger to a drill string, wherein the re-settable cement retainer is settable via rotation of the drill string and the upper stringer, and wherein the re-settable cement retainer and the bridge plug each are composite material and are drillable. In some implementations, the bridge plug has a ball seat to receive a ball dropped through the drill string to set the bridge plug. In certain examples, the re-settable cement retainer has an internal bypass having a first operating position that opens the re-settable cement retainer to squeeze cementing flow and a second operating position that closes the re-settable cement retainer to squeeze cementing flow. 
     Yet another embodiment includes a method of operating a downhole tool assembly for remedial cementing, including coupling the downhole tool assembly to a lower end of a drill string via an upper stringer. The method includes lowering the downhole tool assembly in a collapsed mode into a wellbore on a single run via the drill string. The downhole tool assembly has a lower bridge plug and a re-settable upper cement retainer via a lower stringer. In a particular example, the lower stringer is aluminum and drillable. The collapsed mode may be a mechanical slip of the upper cement retainer not radially extended, a seal of the upper cement retainer not radially extended, a mechanical slip of the lower bridge plug not radially extended, and a seal of the lower bridge plug not radially extended. The lowering of the assembly may be lowering the downhole tool assembly to below a zone in the wellbore to be squeeze cemented. The lowering of the assembly may be lowering the downhole tool assembly to below wellbore perforations to be cemented or to below a casing leak to be repaired via remedial cementing. 
     The method includes setting the lower bridge plug, wherein the lower bridge plug is coupled to the lower stinger via a shear pin. The setting of the lower bridge plug may include dropping a setting ball through the drill string and the upper cement retainer to a ball seat of the lower bridge plug and pressuring the drill string (for example, to at least 1000 psig) to set the lower bridge plug. 
     The method may then include raising the drill string to pull up the lower stringer to shear the shear pin to release the lower bridge plug from the lower stringer and the downhole tool assembly, rotating the drill string in a first direction to set the upper cement retainer against a casing of the wellbore, and performing pressure testing to confirm seal integrity and bottom-hole isolation. The seal integrity evaluated may include seal integrity of the upper cement retainer and the lower bridge plug. The pressure testing may include pressure testing the upper cement retainer from below, the lower bridge plug from above, and the casing between the upper cement retainer and the lower bridge plug 
     The method may further include rotating the drill string in a second direction different than the first direction to unset the upper cement retainer, raising the drill string to reposition the upper cement retainer above a zone of the wellbore to be squeeze cemented, and rotating the drill string in the first direction to re-set the upper cement retainer to seal against the casing. The method may then involve pressure testing by pressuring an annulus between the drill string and the casing. Lastly, the method may include raising the drill pipe to pull the upper stinger to shear pins coupling the upper stinger to the upper cement retainer to release the upper cement retainer from the upper stinger and the drill string to close a cementing internal bypass of the upper cement retainer, lowering the drill pipe to lower the upper stinger back into the upper cement retainer to open the cementing internal bypass, and pumping cement through the cementing internal bypass of the upper cement retainer to squeeze cement the zone, and raising the drill string to pull the upper stinger from the upper cement retainer to close the cementing bypass. 
     Yet another embodiment is a method of operating a downhole tool assembly for remedial cementing, including coupling the downhole tool assembly to a lower end of a drill string via an upper stringer. The method includes lowering the downhole tool assembly in a collapsed mode into a wellbore on a single run via the drill string, the downhole tool assembly including a lower bridge plug and an upper cement retainer coupled via a lower stringer, wherein the upper cement retainer is re-settable. In examples, the lower stinger is aluminum and drillable. Further, the method includes setting the lower bridge plug, wherein the lower bridge plug is coupled to the lower stinger via a shear pin. The lowering may include lowering the downhole tool assembly to below a zone in the wellbore to be squeeze cemented. Indeed, the lowering may include lowering the downhole tool assembly to below wellbore perforations to be cemented or to below a casing leak to be repaired via remedial cementing. The collapsed mode may involve a mechanical slip of the upper cement retainer not radially extended, a seal of the upper cement retainer not radially extended, a mechanical slip of the lower bridge plug not radially extended, and a seal of the lower bridge plug not radially extended. The setting of the lower bridge plug may be by dropping a setting ball through the drill string and the upper cement retainer to a ball seat of the lower bridge plug and pressuring the drill string (for example, to at least 1000 psig) to set the lower bridge plug. 
     The method may include raising the drill string to pull up the lower stringer to shear the shear pin to release the lower bridge plug from the lower stringer and the downhole tool assembly, rotating the drill string in a first direction to set the upper cement retainer against a casing of the wellbore, and performing pressure testing to confirm seal integrity and bottom-hole isolation. The seal integrity may include the seal integrity of the upper cement retainer and the lower bridge plug. The pressure testing may include pressure testing the upper cement retainer from below, the lower bridge plug from above, and the casing between the upper cement retainer and the lower bridge plug. 
     In addition, the method may include rotating the drill string in a second direction different than the first direction to unset the upper cement retainer, raising the drill string to reposition the upper cement retainer above a zone of the wellbore to be squeeze cemented, and rotating the drill string in the first direction to re-set the upper cement retainer to seal against the casing. The pressure testing may be by pressuring an annulus between the drill string and the casing. 
     Furthermore, the method may include raising the drill pipe to pull the upper stinger to shear pins coupling the upper stinger to the upper cement retainer to release the upper cement retainer from the upper stinger and the drill string to close a cementing internal bypass of the upper cement retainer. The method may also include lowering the drill pipe to lower the upper stinger back into the upper cement retainer to open the cementing internal bypass, pumping cement through the cementing internal bypass of the upper cement retainer to squeeze cement the zone, and raising the drill string to pull the upper stinger from the upper cement retainer to close the cementing bypass. 
     Yet another embodiment is a method of operating a downhole tool assembly for squeeze cementing, including coupling the downhole tool assembly to a lower end of a drill string via an upper stringer, the upper stringer coupled via a first shear pin to a cement retainer of the downhole tool assembly. The method includes deploying into a wellbore via the drill string the downhole tool assembly to below a wellbore zone to be squeeze cemented, the downhole tool assembly having the cement retainer and a bridge plug coupled via a lower stringer, the bridge plug coupled to the lower stinger via a second shear pin. The method includes setting the bridge plug by dropping an activation ball to a ball seat of the bridge plug and pressuring the drill string to at least 1000 pounds per square inch gauge (psig). The method includes raising the drill string to pull up the lower stringer to shear the second shear pin to release the bridge plug from the lower stringer and the downhole tool assembly. The method includes setting the cement retainer by rotating the drill string in a first direction. In addition, the method includes pressure testing between the cement retainer as set and the bridge plug as set to confirm seal integrity and isolation of the wellbore below the bridge plug. The cement retainer may be re-settable. 
     The deploying may include deploying the downhole tool assembly on a single run including lowering the bridge plug and the cement retainer in tandem into the wellbore as components of the downhole tool assembly on the single run. The method may include: unsetting the cement retainer by rotating the drill string in a second direction; raising the drill string to reposition the cement retainer above the wellbore zone; re-setting the cement retainer by rotating the drill string in the first direction; pressure testing by applying pressure to an annulus between the drill pipe and the casing; raising the drill pipe to pull the upper stinger to shear the first shear pin to release the cement retainer from the upper stinger and the drill pipe and to close a cementing bypass of the cement retainer; lowering the drill pipe to lower the upper stinger back into the cement retainer to open the cementing bypass; pumping cement through the cementing bypass to squeeze cement the wellbore zone; and raising the drill string to pull the upper stinger from the cement retainer to close the cementing bypass. In examples, the first shear pin is multiple shear pins. 
     A number of implementations have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure.