Patent Publication Number: US-2019186240-A1

Title: Tubing Installation Assembly

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This original non-provisional application claims the benefit of U.S. Provisional Patent Application Ser. No. 62/608,215 filed on Dec. 20, 2017 and entitled “Improved Tubing Installation Assembly” which is incorporated by reference herein. 
    
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not applicable. 
     BACKGROUND 
     The present disclosure relates to systems, such as liner hangers and running tools, for running a tubing string into a subterranean well and cementing the tubing string in the borehole. Such systems are typically designed so that, once the liner hanger is in place and fully actuated, the running tool is removed from the well and a treating string is run into the well to connect to the liner hanger. Treating operations, such as fracturing, can then occur through the treating string. Embodiments of the present disclosure may permit the running tool to function as a landed seal assembly, allowing treating operations to occur without tripping the running string out and a treating string back in. 
     Field 
     The use of liners and liner hangers is well known in the art. A tubing string may be run into a well and secured to previously installed casing once the tubing string reaches its desired position. Such tubing string may comprise a liner, a liner hanger at the top of the liner, and a running string connected to and above the liner hanger. Upon actuation of the liner hanger—such as applicants Sentinel™ or Sentinel Shield™ liner hangers—slips or other holding devices may be radially expanded to engage the casing. The holding devices grip the casing and secure the tubing string (e.g. the liner) at the desired location and hold the weight of the tubing string, which may exceed several hundred thousand pounds, so that the liner does not fall further down the well. 
     Liner hangers may also include a packer, such as a liner top packer. Such packer is in place to prevent fluid communication between the annulus surrounding the liner and the region of the wellbore above the liner hanger. In some liner hangers, the packer is set by mechanical force applied to the top of the liner hanger assembly, such as to the top of a polished bore receptacle (PBR) or other tubing. The mechanical force may be applied by a stomp sub having dogs or collet fingers configured to engage the upper end of the PBR or other tubing. One example stomp sub having collet fingers is described in U.S. patent application Ser. No. 15/247,897, the disclosure of which is hereby incorporated in its entirety by reference. The force applied to the end of the PBR or other tubing may longitudinally compress an elastomeric packer element between setting rings and/or thimbles. Such longitudinally compressed elastomeric element thereby radially expands against the casing to form a fluid seal between the liner hanger assembly and the inner casing wall. Other embodiment liner top packers may incorporate a metal to metal seal which is formed by swedging of the packer element. Hangers with such metal element are within the scope herein. 
     For cemented liner completions, the liner top packer is typically set after the cement has been placed. Once the tubing string is anchored in the casing by engagement of the slips or other holding devices, the running string may be disconnected from the liner hanger assembly. Cement may then be pumped down the running string, through the liner hanger and liner, and then pushed up from the lower end of the liner so that the cement surrounds the liner and fills the wellbore annulus from bottom to top (e.g. from the toe of the liner back up to the element of the liner top packer). The running tool may contain a cement bushing or packoff to prevent cement flowing out of the running tool from move up into and around the PBR or other tubing rather than down through the liner or liner hanger. The liner top packer may be set after the cement is run and before it cures, allowing cement to cure both above and below the packer element. 
     A wiper plug, wiper dart, wiper ball, combinations thereof, or similar devices may be used to push the cement through and out of the liner. Such device may latch into and seal against a latch assembly at the toe of the well which closes off the interior of the liner from the annulus and prevents cement from flowing back into the liner. After the wiper dart or other device passes into the liner hanger, and in at least some cases after the wiper dart/wiper plug latches into the toe of the liner, the running tool may then be moved for setting of the liner top packer. 
     Once the packer is set, the running string, and running tool assembly on which the liner was previously suspended, may be removed from the well. A treating string, such as a frac string, may then be introduced into the well and connected to the liner hanger assembly, such as by stabbing into the PBR or other tubing at the top of the liner top packer. The treating string may a landed seal assembly, with a sealing element that engages and creates a fluid seal against the inside of the PBR or other tubing, forcing the treating fluid down the liner and isolating the annulus between the casing and the treating string from the fluid and fluid pressure used in the treatment. The sealing element is positioned within the PBR or other tubing so that the piston force from the treatment&#39;s fluid pressure does not force the landed seal assembly out of the PBR or other tubing. The treating string may have a locating sub to verify the position of the treating string with respect to the PBR or other tubing. For example, the treating string may have a simply top sub which tags the upper end of the PBR or upper tubing or may have a latch that connects to the upper end of the PBR or other tubing. Such locating sub&#39;s position may be fixed, such as through a pup joint, relative to the sealing element so that the position of the sealing element in the PBR or other tubing can be known through engagement of the locating sub with PBR or other tubing&#39;s upper end. 
     The need for separate running strings and treating strings increases the time and cost of completing wells. Trip times for these strings run from several hours and into days which increases rig time and the risk of accidents, delays, or other problems. Cost is further increased because of the different tools used in the running string and treating string. 
     Embodiments of the present disclosure eliminate the need for a separate running string and treating string, thereby improving the cost and risk factors associated with completing wells. Components of the running string may be configured to perform similar functions associated with a treating string. For example, the cement bushing of the running string may double as the landed seal of the frac string. Also, the stomp sub may double as a locating sub. To facilitate these components performing both functions, the stomp sub may be slidingly connected to tubing, such as a mandrel, positioned between the stomp stub and seal element or seal sub. This allows the stomp sub to be positioned generally adjacent to the seal element during the run-in and cementing stages and spaced apart from the seal element during the treating stages. 
     When used with reference to the figures, unless otherwise specified, the terms “upwell,” “above,” “top,” “upper,” “downwell,” “below,” “bottom,” “lower,” and like terms are used relative to the direction of normal production and/or flow of fluids and or gas through the tool and wellbore. Thus, normal production results in migration through the wellbore and production string from the downwell to upwell direction without regard to whether the tubing string is disposed in a vertical wellbore, a horizontal wellbore, or some combination of both. Similarly, during the fracing process, fracing fluids and/or gasses move from the surface in the downwell direction to the portion of the tubing string within the formation. 
    
    
     
       BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS 
         FIG. 1  shows a cross sectional view of one embodiment assembly according to the present disclosure. 
         FIG. 2  shows one embodiment running tool according to the present disclosure as it may be run into a well. 
         FIG. 3  shows one embodiment top sub according to the present disclosure. 
         FIG. 4  shows one embodiment stomp sub according to the present disclosure. 
         FIG. 5  shows one embodiment seal sub according to the present disclosure. 
         FIG. 6  shows one embodiment running tool according to the present disclosure partially retracted from within the polished bore receptacle. 
         FIG. 7  shows one embodiment running tool according to the present disclosure in a treating state. 
         FIG. 8  shows one embodiment of a stomp sub engaged on an end of a polished bore receptacle and connected to a top sub. 
     
    
    
       FIG. 1  illustrates an embodiment assembly according to the present disclosure. Assembly  100  comprises running string  110 , polished bore receptacle or PBR  120 , running mandrel  130 , crossovers  140  and  150 , seal sub  400 , running nut  500 , liner top packer  600  and hanging element  700 . Top sub  200  and stomp sub  300  may be located around the running mandrel  130  and top sub  200  may be located such that it is partially surrounding the running mandrel  130  and a portion of the running string  110 . Liner, not shown, may be connected below the hanging element  700  and may create a continuous tubing path for fluid flow between the assembly  100  and the subterranean formation to be treated and/or produced. The liner may include a hydraulic port sub at the toe, which is closed when run in but may be opened by application of fluid pressure. 
     Running string  110 , running mandrel  130 , crossovers  140 ,  150  and seal sub  400  connect to liner top packer  600  and thereby to PBR  120  and hanging element  700  through a releasable connection of the running nut  500  to the top of the liner top packer  600 . In some embodiments, the running nut is threadedly connected to the liner top packer, such as through threaded connection  510 , though other types of connection are within the scope of the present disclosure. 
     Liner top packer  600  may comprise a packer mandrel  640 , with one or more elastomeric elements  630 , setting slips  620 , cone  625 , and adaptor  610  for transferring force to the setting slips therearound. One or more setting sheer pins  612  may fix adaptor  610  to packer mandrel  640 . PBR  120  is connected to adaptor  610  which engages setting slips  620 . Setting slips  620  may also have shear pins, not shown, fixing it to packer mandrel  640 . 
     Hanging element  700  may be a tubing anchor such as is illustrated in  FIG. 1 , may be a liner hanger such as Applicant&#39;s Sentinel™ Liner hanger or Applicant&#39;s liner hanger as described in U.S. patent application Ser. No. 15/610,559 or other device that holds the liner and assembly in a desired location when actuated. The illustrated hanger  700  has a hanger mandrel  750  with a piston assembly  710 , cones  720 ,  730  and slips  740  therearound. A passageway  712  permits fluid communication between the interior of the anchor into the piston assembly  710 . In certain embodiments, the inner diameter of the running tool, PBR, liner hanger and liner will be coordinated, e.g. substantially the same, to facilitate the desired pumping of cement and/or treatment fluids. 
     In operation, assembly  100  and attached liner are run into a well on running string  110  until the hanging element  700  and packing element  600  are in a desired location. Running string  110 , assembly  100  and the liner may form a closed fluid system in which pressure may be increased by pumps attached to the running string  110  at surface. Such an increase in pressure is communicated through passageway  712  to a piston in piston assembly  710 , applying force into the cones  720 ,  730  and slips  740 , forcing the slips  740  outward to engage the casing string in which the assembly  100  has been placed. Once set, slips  740  can bear the weight of the PBR  120 , liner top packer  600 , hanging element  700  and attached liner, allowing the running tool to be disengaged from the liner top packer  600 , such as by rotating the running string  110  to unthread a threaded connection. 
       FIG. 2  illustrates the configuration of the running tool inside the PBR  120  while connected to the liner top packer  600 , e.g. during run in of the assembly  100  and any attached liner. Running tool comprises running nut  500 , seal sub  400 , crossovers  140 ,  150 , running mandrel  130 , top sub  200  and stomp sub  300 . It will be appreciated that, in the embodiment of  FIG. 2 , running nut  500 , seal sub  400  and crossovers  140 ,  150  are connected to one another in sequence, with crossover  140  connected to running mandrel  130 . In the run in position, stomp sub  300  is fixed to crossover  140  via stomp sub shear pin ( 350  in  FIG. 4 ). 
     Mandrel gap  105  represents a length of plain tubing, in the running mandrel  130  and in the PBR  120 , around or in which there are no other features relevant to the objects of the present disclosure. Such mandrel gap  105  may be of variable length depending on the stroke length desired for the running tool inside the PBR  120  or other factors. In some embodiments, the length of tubing corresponding to the mandrel gap  105  may be about 10 to about 12 feet, though the exact length may vary substantially. Similarly, running nut gap  505  represents a length (such as about 24 inches) of the running nut  500  and a corresponding portion of the PBR  120 . Mandrel gap  105  and running nut gap  505  are included for illustration purposes only in order to decrease the length of certain figures, thereby assisting in the illustration of other portions of the running tool. 
     The top sub  200 , stomp sub  300  and seal sub  400  may be generally tubular and are shown in more detail in  FIGS. 3, 4 and 5 , respectively. Top sub  200  comprises a body  210  and a ratchet ring  220  positioned in a slot of body  210 . Body  210  may be fixed to the running string  110  and overlap with the upper end of running mandrel  130 . Internal shoulder  112  may be part of top sub  200  or, as illustrated in  FIG. 3 , of the bottom of running string  110 . 
     It will be appreciated that different embodiment top subs may be employed. It is not required that top sub be configured so that it fixes to the stomp sub and any configuration top sub that may apply downward force to the stomp sub, including, e.g., a tool joint or other shoulder of a pipe joint in the running string, may be used as top sub. 
     Stomp sub  300 , which may be a dog sub as shown in  FIG. 4 , comprises a body  310 , upper retainer  320 , a plurality of dogs  330  with springs  332  arranged around circumference of dog sub, lower retainer  340 , stomp sub shear pin  350 , and rack  305 . Bolts or screws  302  may be used to secure, or partially secure, retainers or other components to the body  310 . Stomp sub  300  slidingly engages running mandrel  130  and may be secured to crossover  140  via stomp sub shear pin  350 . Dogs  330  may be retained in their retracted position because of engagement of the dogs&#39;  330  outer surface against the inner surface of PBR  120 . 
     Seal sub  400  may comprise a body  405 , seal stacks  410 ,  412 ,  414 ,  416 ,  418 ,  420 , seal retainer  430 , and seal stack ring  440 . Seal stack ring  440  may be threadingly connected to body  405  or other component of seal sub such that turning seal stack ring  440  applies longitudinal force to seal retainer  430  and therethough to seal stacks  410 ,  412 ,  414 ,  416 ,  418 ,  420 . Seal sub  400  may be configured such that the outer diameter of body  405  is smaller than the inner diameter of PBR  120  but permitting seals  410  through  420  to engage body  405  and inner diameter of PBR  120 , creating a fluid tight seal therebetween. During cementing operations, seal sub may serve as a cement bushing. 
     Seal stacks  410  through  420  may be required to swab out of and into the PBR  120  multiple times. Further, at least one or more of seal stacks  410 ,  412 ,  414 ,  416 ,  418 ,  420  may be required to function after being removed from and then reinserted into PBR  120 . In some embodiments, seal stacks  410  through  420  may be chevron seals, bonded seal assemblies or other sealing structures chosen to facilitate such movement and function, including sealing after removal and reinsertion. Further, while the illustrated embodiment contains six seal stacks, seal sub  400  may contain more or fewer such stacks. 
     After the hanging element is set, running tool may be released from the run in state. In some embodiments, such transition my begin by releasing the running nut  500  from the liner top packer  600 . In the embodiment of  FIGS. 1 and 2 , this is done by unthreading the threaded connection  510 . Such threaded connection may be a left-hand thread with all other threaded connections of the running string  110  and running tool being right-hand threads. This permits unthreading of the running nut  500  without backing off other threaded connections. 
     After the running nut is released, cementing of the liner may begin. Cement is pumped through the running string  110 , assembly  100 , and down the liner. Once the desired volume of cement has been pumped into the running string  110 , a wiper plug may introduced into the running string  110 . It will be appreciated that release of the running nut  500 , and therefore the running tool, may create a length of open PBR between the running nut  500  and the upper end of the liner top packer  600 . In some embodiments, the larger inner diameter of the PBR may permit a wiper plug to substantially exit the running tool before entering the packer and decentralize and to lodged between the running nut  500  and liner top packer  600 . Therefore, it may be desirable to lower the running tool, and therefore the running nut to within 24 inches, and perhaps within 12 inches of the liner top packer  600  before the wiper plug exits the running nut  500 . In such an arrangement, the wiper plug can remain substantially centralized in the running nut  500  to facilitate its entry into the liner top packer  600 . 
     Following cementing, the running tool may be reciprocated within the PBR  120  and fluid circulated to help clear any cement from within the PBR  120  and or the running tool. The stomp sub  300  may be removed from the PBR  120  during or following this step. In some embodiments, reciprocation and removal of the running tool may facilitate clearing of debris from the PBR of other tubing in which the running tool is positioned. When stomp sub  300  is removed from the PBR  120 , springs  332  force dogs  330  outward, causing dogs  330  to engage the upper end of PBR  120 . Engagement of dogs  330  on the end of PBR  120  prevents movement of the running tool into the PBR  120 . Downward force applied to the running string  110 , and thereby to running mandrel  130  and crossovers  140 ,  150 , causes the stomp sub shear pin  350  to break, releasing the stomp sub  300  and permitting the running mandrel  130  to slide within the stomp sub  300 . Upper guide  320  and lower guide  340  may control or limit the movement of dogs  330  to assist in the dogs  330  proper positioning relative to the end of PBR  120 . 
       FIG. 6  illustrates the running tool just prior to breaking stomp sub shear pins  350 . Running string  110  and top sub  200  have been pulled upward away from the PBR  120  and the dogs  330  of stomp sub  300  are engaged against the upper edge of PBR  120 . Running nut  500  has pulled away from the upper end of the liner top packer, as reflected by the continuation lines in PBR  120  at  107 . After breaking the stomp sub shear pins  350 , running mandrel  130  is slidable within the stomp sub  300 , permitting reciprocation of the running tool. The running string  110  may then be moved down until the top sub  200  engages the stomp sub  300 , as illustrated in  FIGS. 7 and 8 , placing the running tool in the treating state. Ratchet ring  220  engages rack  305  to connect the top sub  200  with stomp sub  300 . Further, shoulder  112  may engage with a corresponding shoulder  307  on the body  310  of stomp sub  300  to facilitate the transfer of force from the running string  110  into the stomp tool  300 . Once such engagement occurs, additional downward force on running string  110  is transferred through top sub  200 , stomp sub  300  and to PBR  120  through dogs  330 . It will be appreciated that, in this configuration, the stomp sub  300  is fixed along the running mandrel  130  distally from the crossover  140 . Further, with stomp sub  300  engaged on PBR, running nut  500  has now moved to within about 24 inches, or other distance as may be desirable, of the upper end of the liner top packer  600 . 
     Once the top sub  200  engages the stomp sub  300 , the running tool may set the liner top packer  600 . Force applied to the running string is transferred through the stomp sub  300  to the PBR  120  as described above, which is further transferred to the adaptor  610  and cone  625  of the liner top packer. The shear pins in cone  625  may be broken in response to such force and cone  625  moved towards the thimble  627  of the liner top packer  600 . In certain embodiments it is desirable that the shear pins in cone  625  have greater strength than the stomp sub shear pins  350  so that stomp sub  300  can be released from running mandrel  130  without setting, or partially setting, liner top packer  600 . Movement of cone  625  longitudinally compresses the elastomeric element  630 , extruding the element  630  outward against the host casing and creating a fluid seal therebetween. After a desired pack off force is loaded into the element, packer slip shear pins  612  may release, allowing packer slips  620  to travel outward up the cone  625  to engage the casing and lock the cone  625  and element  630  in the set position. 
     Following setting of the liner top packer  600 , the running tool may be removed from the PBR  120  so that fluid may be introduced in the annular space between the PBR  120  and the host casing. Following the introduction of such fluids, the running tool may be reinserted into the PBR  120 , creating a fluid seal between the seal sub  400  and the inner wall of the PBR  120 , creating a pressure isolated flowpath for subsequent treatment of the subterranean formation adjacent to the installed liner. 
     It will be appreciated that the spacing of the top sub  200  and the stomp sub  300  in the run in position must be configured to permit setting of all elements of the liner top packer  600 . In the embodiments of  FIGS. 1 and 2 , this means permitting a stroke of PBR  120  sufficient to compress the element  630  and to set slips  620 . In certain embodiments, this is accomplished by setting the gap between top sub  200  and stomp sub  300  between 12 and 24 inches less than the length required to remove the dogs  330  from the PBR. In other words, with reference to the configuration in  FIG. 6 , top sub  200  is between 12 and 24 inches closer to dog sub  300  than the running nut  500  is to the top of the liner top packer  600 . This permits top sub  200  to apply downward force to stomp sub  300  and move PBR  120  without running nut  500  contacting the liner top packer  600 . Further, in this position, seal sub  400  is positioned close to the bottom of the PBR, permitting substantially the full length of the PBR to be available during high pressure treating operations so that the piston effect from fluid pressure does not eject the seal assembly out of the PBR. 
     It will be appreciated that the running string will need to be selected based on both the tensile forces experienced during run in, the burst forces that may experienced during the treatment, and any chemicals the planned treatment may include. Such concerns are will known in the art and running strings meeting such parameters can be readily selected. 
     The present disclosure includes preferred or illustrative embodiments in which specific tools are described. For example, embodiment tools may incorporate one or more debris barriers or latches for engaging a PBR as are known in the art frac strings or other treating strings. Alternative embodiments of such tools can be used in carrying out the invention as claimed and such alternative embodiments are limited only by the claims themselves. Other aspects and advantages of the present invention may be obtained from a study of this disclosure and the drawings, along with the appended claims.