Patent Publication Number: US-11661807-B1

Title: Rotating hanger assemblies and methods

Description:
BACKGROUND 
     This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the presently described embodiments. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present embodiments. Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art. 
     In order to meet consumer and industrial demand for natural resources, companies often invest significant amounts of time and money in finding and extracting oil, natural gas, and other subterranean resources from the earth. Particularly, once a desired subterranean resource such as oil or natural gas is discovered, drilling and production systems are often employed to access and extract the resource. These systems may be located onshore or offshore depending on the location of a desired resource. Further, such systems generally include a wellhead assembly mounted on a well through which the resource is accessed or extracted. These wellhead assemblies may include a wide variety of components, such as various casings, valves, hangers, pumps, fluid conduits, and the like, that facilitate drilling or production operations. 
     As will be appreciated, various tubular strings can be run into wells through wellhead assemblies. For instance, wells are often lined with casing that generally serves to stabilize the well and to isolate fluids within the wellbore from certain formations penetrated by the well (e.g., to prevent contamination of freshwater reservoirs). Such casing is frequently cemented into place within the well. During a cement job, cement can be pumped down a casing string in a well, out the bottom of the casing string, and then up the annular space surrounding the casing string. The cement is then allowed to set in the annular space. Wells can also include tubing strings that facilitate flow of fluids through the wells. Hangers can be attached to the casing and tubing strings and received within wellheads to enable these tubular strings to be suspended in the wells from the hangers. 
     SUMMARY 
     Certain aspects of some embodiments disclosed herein are set forth below. It should be understood that these aspects are presented merely to provide the reader with a brief summary of certain forms the invention might take and that these aspects are not intended to limit the scope of the invention. Indeed, the invention may encompass a variety of aspects that may not be set forth below. 
     Embodiments of the present disclosure generally relate to wellhead hangers for suspending tubular strings in wells. In some embodiments, a wellhead hanger assembly includes a wellhead hanger, an inner sleeve, a running tool, and an outer sleeve that transmits torque from the running tool to the wellhead hanger to drive rotation of the wellhead hanger. In some instances, the outer sleeve is in castellated engagement with the wellhead hanger, but the outer sleeve could also or instead engage the wellhead hanger in some other manner to transmit torque and drive rotation of the wellhead hanger. The running tool and the outer sleeve may be coupled via dogs that allow the running tool to transmit torque to the outer sleeve when rotated in one direction but not the other. The inner sleeve may include ribs or other projections that interact with slots of the outer sleeve to facilitate disconnection and removal of the inner sleeve from the wellhead hanger. 
     Various refinements of the features noted above may exist in relation to various aspects of the present embodiments. Further features may also be incorporated in these various aspects as well. These refinements and additional features may exist individually or in any combination. For instance, various features discussed below in relation to one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination. Again, the brief summary presented above is intended only to familiarize the reader with certain aspects and contexts of some embodiments without limitation to the claimed subject matter. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       These and other features, aspects, and advantages of certain embodiments will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein: 
         FIG.  1    generally depicts various components, including one or more tubular strings and associated hangers, that can be installed at a well in accordance with one embodiment of the present disclosure; 
         FIG.  2    is a perspective view of a wellhead hanger assembly including a wellhead hanger, a running tool, an inner sleeve, and an outer sleeve for transmitting torque from the running tool to the wellhead hanger in accordance with one embodiment; 
         FIG.  3    is an exploded view of the wellhead hanger assembly of  FIG.  2    in accordance with one embodiment; 
         FIG.  4    is an axial cross-section of the wellhead hanger assembly of  FIG.  2    in accordance with one embodiment; 
         FIG.  5    is a radial cross-section of the wellhead hanger assembly of  FIG.  2    in accordance with one embodiment; 
         FIGS.  6 - 11    generally depict a running procedure for installing the wellhead hanger of the wellhead hanger assembly of  FIGS.  2 - 5    in a wellhead in accordance with one embodiment; and 
         FIG.  12    is a perspective view of another wellhead hanger assembly in accordance with one embodiment. 
     
    
    
     DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS 
     Specific embodiments of the present disclosure are described below. In an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers&#39; specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure. 
     When introducing elements of various embodiments, the articles “a,” “an,” “the,” and “said” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Moreover, any use of “top,” “bottom,” “above,” “below,” other directional terms, and variations of these terms is made for convenience, but does not require any particular orientation of the components. 
     Turning now to the present figures, a system  10  is illustrated in  FIG.  1    in accordance with one embodiment. Notably, the system  10  is a production system that facilitates extraction of a resource, such as oil, from a reservoir  12  through a well  14 . Wellhead equipment  16  is installed on the well  14 . As depicted, the wellhead equipment  16  includes at least one casing head  18  and tubing head  20 , as well as wellhead hangers  22 . But the components of the wellhead equipment  16  can differ between applications, and could include a variety of casing heads, tubing heads, spools, hangers, sealing assemblies, stuffing boxes, pumping tees, and pressure gauges, to name only a few possibilities. 
     The wellhead hangers  22  can be positioned on landing shoulders  24  within hollow wellhead bodies (e.g., within the tubing and casing heads). These landing shoulders  24  can be integral parts of tubing and casing heads or can be provided by other components, such as sealing assemblies or landing rings disposed in the tubing and casing heads. Each of the hangers  22  can be connected to a tubular string, such as a tubing string  26  or a casing string  28 , to suspend the string within the well  14 . The well  14  can include a single casing string  28  or include multiple casing strings  28  of different diameters. Casing strings  28  are often cemented in place within the well. During a cement job, cement is typically pumped down the casing string. A plug is then pumped down the casing string with a displacement fluid (e.g., drilling mud) to cause the cement to flow out of the bottom of the casing string and up the annular space around the casing string. 
     Rotating a casing string during cementing can increase uniformity of the cement about the casing string and reduce the size or frequency of undesirable cavities or fissures in the cement. Further, rotating tubular strings can also facilitate running of the strings into the well through the wellhead. Any suitable devices or machines may be used to rotate the wellhead hangers (and their attached tubular strings) and to run the strings into wells. For example, a top drive can be used to run a casing string into a well and to rotate the casing string. In some instances, the tubular strings are rotated via wellhead hangers attached to the strings. 
     One example of a wellhead hanger assembly  40  is generally depicted in  FIGS.  2 - 11   . As shown in  FIGS.  2 - 4   , the assembly  40  includes a wellhead hanger  42  (provided here as a mandrel-type casing hanger), a running tool  44 , an inner sleeve  46 , and an outer sleeve  48 . The running tool  44  may be coupled to the wellhead hanger  42  by the inner sleeve  46  and the outer sleeve  48  in any suitable manner. As shown in  FIGS.  2  and  4   , the outer sleeve  48  is positioned to transmit torque from the running tool  44  to the wellhead hanger  42  via castellated engagement of the outer sleeve  48  with the wellhead hanger  42 . As described in further detail below, the wellhead hanger assembly  40  may be configured such that the running tool  44  can be rotated (e.g., by a landing joint) in one direction (e.g., clockwise) to drive synchronous rotation of the outer sleeve  48  and the wellhead hanger  42  with the running tool  44 , while the running tool  44  can be rotated in an opposite direction (e.g., counterclockwise) to freely rotate the running tool  44  with respect to the outer sleeve  48  and the wellhead hanger  42 . 
     The wellhead hanger  42  is shown in  FIGS.  2 - 4    as having flow-by holes  50  and slots  52  spaced circumferentially about a flange of the wellhead hanger  42 . The slots  52  receive castellations  54  of the outer sleeve  48 . The castellations  54  may extend axially from the outer sleeve  48  into the mating slots  52  in at least some embodiments, including that shown in  FIGS.  2 - 4   . But other arrangements could be used, such as castellations extending radially into slots. Also, the locations of the castellations  54  and the slots  52  could be reversed, with castellations on the wellhead hanger received in slots of the outer sleeve. Mating engagement of the slots  52  and the castellations  54  allow torque to be transmitted from the outer sleeve  48  to the wellhead hanger  42 . The wellhead hanger assembly  40  may include any suitable number of castellations  54  and mating slots  52  for transmitting torque between the outer sleeve  48  and the wellhead hanger  42 . Additionally, the castellations  54  and slots  52  may have a generally rectangular profile, such as shown in  FIGS.  2  and  3   , or any other suitable shape. 
     The wellhead hanger  42  is also depicted as having a threaded surface  56  for receiving a casing string at the bottom of the wellhead hanger  42  and a neck  58  with a threaded surface  60 . The depicted inner sleeve  46  includes a threaded surface  62  that allows the inner sleeve  46  to be threaded to the wellhead hanger  42  (via mating engagement of threaded surfaces  60  and  62 ). The inner sleeve  46  may include radial protrusions that are received by slots in the outer sleeve  48 . In  FIGS.  2  and  3   , these radial protrusions are shown in the form of external ribs  66  that extend axially along the inner sleeve  46  and are received within slots  82  of the outer sleeve  48 . As discussed further below, engagement of the external ribs  66  and the slots  82  can facilitate unthreading of the inner sleeve  46  from the wellhead hanger  42 . 
     The inner sleeve  46  may also include a threaded surface  70  for receiving the running tool  44 . As shown in  FIGS.  3  and  4   , the running tool  44  includes a threaded surface  72  the allows the running tool  44  to be threaded to the inner sleeve  46  (via mating engagement of threaded surfaces  70  and  72 ). The depicted running tool  44  also includes a stop shoulder  74  (e.g., an annular flange) and recesses  76 , as well as a threaded surface  78  (e.g., for receiving a landing joint). As discussed below, the shoulder  74  may be used to lift the outer sleeve  48  out of castellated engagement with the wellhead hanger  42 . As also discussed further below, the recesses  76  may be one-way torque transmission recesses configured to transmit torque from the running tool  44  to the outer sleeve  48  when the running tool  44  is rotated in one direction (e.g., clockwise) but not when the running tool  44  is rotated in an opposite direction (e.g., counterclockwise). 
     During assembly of the wellhead hanger assembly  40 , the inner sleeve  46  may be threaded to the wellhead hanger  42 , the running tool  44  may be threaded to the inner sleeve  46 , and the outer sleeve  48  may be positioned in castellated engagement with the wellhead hanger  42 . Positioning the outer sleeve  48  in castellated engagement with the wellhead hanger  42  may include moving the outer sleeve axially (e.g., downward along the running tool  44  and the inner sleeve  46 ) to receive the external ribs  66  of the inner sleeve  46  within the slots  82  of the outer sleeve  48 . The slots  82  may include openings  84  in a lower end of the outer sleeve  48 , and these openings  84  may be axially aligned with the ribs  66  so that the ribs  66  enter the slots  82  through the openings  84  as the outer sleeve is moved toward the wellhead hanger  42 . After receiving the ribs  66  through the openings  84 , the ribs  66  may pass into portions of the slots  82  that are wider than the openings  84 , and the outer sleeve  48  may be rotated (e.g., clockwise for the assembly  40  depicted in  FIGS.  2  and  3   ) with respect to the inner sleeve  46  such that lateral shoulders  86  of the slots  82  are aligned axially below the ribs  66  (as shown in  FIG.  2   ). After receiving the ribs  66  in the slots  82 , the outer sleeve  48  may be moved into castellated engagement with the wellhead hanger  42 . In at least one embodiment, such as that depicted in  FIGS.  2 - 4   , the wellhead hanger assembly  40  includes three ribs  66 , with three mating slots  82 , spaced at 120-degree intervals around the assembly  40 . 
     The outer sleeve  48  may be coupled to the running tool  44  with dogs  92 . As shown in  FIGS.  3  and  5   , the dogs  92  can be installed in radial openings  94  of the outer sleeve  48  to extend radially inward from the outer sleeve  48  into the recesses  76  of the running tool  44 . The dogs  92  may be retained in the openings  94  by caps  96 . Springs  98  can be installed between the dogs  92  and the caps  96  to bias the dogs  92  radially inward. 
     Each recess  76  is shown in  FIG.  5    as having a stop surface  102  and an angled return surface  104 . In at least some embodiments, the stop surfaces  102  are radial stop surfaces formed orthogonal to the outer circumference of the running tool  44 . In the embodiment depicted in  FIGS.  2 - 5   , the running tool  44  is rotated clockwise to transmit torque to the outer sleeve  48  via engagement of the stop surfaces  102  with the dogs  92 , with the stop surfaces  102  bearing against the dogs  92  to prevent relative rotation of the running tool  44  with respect to the outer sleeve  48 . When the running tool  44  is rotated in the opposite direction (counterclockwise for the embodiment depicted in  FIGS.  2 - 5   ), the running tool  44  rotates with respect to the outer sleeve  48  and the return surfaces  104  push the dogs  92  radially outward, allowing the dogs  92  to exit the recesses  76  and the running tool  44  to freely rotate without driving synchronous rotation of the outer sleeve  48 . In other instances, the dogs  92  may also or instead include angled return surfaces  104  that allow the dogs  92  to exit the recesses  76  when the running tool  44  is rotated in the opposite direction (i.e., counterclockwise in the embodiment depicted in  FIGS.  2 - 5   ). 
     The wellhead hanger assembly  40  includes a bore  106  that may be used to route fluid (e.g., drilling fluid or cement slurry) into a well. Seals may be provided to inhibit leakage of fluid from the bore  106 . For instance, as shown in  FIG.  4   , seals  108  are positioned to seal between the inner sleeve  46  and the wellhead hanger  42  or the running tool  44 . 
       FIGS.  6 - 11    generally depict aspects of a running procedure for installing the wellhead hanger  42  in a wellhead in accordance with one embodiment. As shown in  FIG.  6   , the wellhead hanger  42  is a casing hanger coupled to a casing string  110  via mating engagement of threaded surface  56  with a threaded surface  112  of the casing string  110 . A landing joint  114  with a threaded surface  116  is coupled to the top of the wellhead hanger assembly  40 , via mating engagement of threaded surfaces  78  and  116 , and may be used to lower the wellhead hanger assembly  40  into a wellhead  120  (e.g., into a casing head or other wellhead housing). As shown in  FIG.  6   , the wellhead hanger  42  may be landed on a landing shoulder  122  of the wellhead  120 , and the wellhead  120  may include access ports  124 . 
     In at least some embodiments, such as that described herein with reference to  FIGS.  6 - 11   , the threaded surfaces  56 ,  70 ,  72 ,  78 ,  112 , and  116  have right-handed threads and the threaded surfaces  60  and  62  have left-handed threads. With the wellhead hanger assembly  40  within the wellhead  120 , the running tool  44  is rotated clockwise to rotate the wellhead hanger  42  and the attached casing string  110  clockwise. More specifically, clockwise rotation of the running tool  44  drives synchronous rotation of the outer sleeve  48  (via interaction of dogs  92  and stop surfaces  102 ) and of the wellhead hanger  42  (via castellated engagement with the outer sleeve  48 ). 
     The running tool  44  may then be rotated counterclockwise to unthread the running tool  44  from the inner sleeve  46  and move to the position depicted in  FIG.  7   . As discussed above, return surfaces  104  of the recesses  76  allow the dogs  92  to exit the recesses  76 . This allows the running tool  44  to rotate counterclockwise with respect to the outer sleeve  48  (and the wellhead hanger  42 ) and unthread from the inner sleeve  46 . 
     After unthreading the running tool  44  from the inner sleeve  46 , the running tool  44  may be pulled away from the wellhead hanger  42  to lift the outer sleeve  48 , via the shoulder  74  of the running tool  44 , out of castellated engagement with the wellhead hanger  42 , as shown in  FIGS.  8  and  9   . In some instances, the running tool  44  is pulled away from the wellhead hanger  42  until the shoulders  86  of the slots  82  of the outer sleeve  48  contact the lower ends of the ribs  66  of the inner sleeve  46 . Once the outer sleeve  48  is pulled out of castellated engagement with the wellhead hanger  42 , the running tool  44  may again be rotated clockwise to unthread the inner sleeve  46  from the wellhead hanger  42 , as shown in  FIG.  10   . More specifically, with the outer sleeve  48  freed from the wellhead hanger  42 , this clockwise rotation of the running tool  44  drives (via the dogs  92 ) clockwise rotation of the outer sleeve  48  with respect to the wellhead hanger  42 . Sides of the slots  82  of the outer sleeve  48  bear against the ribs  66  of the inner sleeve  46  to drive clockwise rotation of the inner sleeve  46 , which unthreads the inner sleeve  46  from the wellhead hanger  42 . 
     With the inner sleeve  46  unthreaded from the wellhead hanger  42 , the running tool  44  may be lifted with a straight pull to remove the running tool  44 , the inner sleeve  46 , and the outer sleeve  48  from the wellhead  120 , leaving the wellhead hanger  42  and the casing string  110  as shown in  FIG.  11   . The inner sleeve  46  may be carried by the outer sleeve  48  out of the wellhead  120  through engagement of the ribs  66  of the inner sleeve  46  with the shoulders  86  of the slots  82  of the outer sleeve  48 . 
     Although the wellhead hanger assembly  40  may be configured to provide right-handed (clockwise) rotation of the wellhead hanger  42 , such as described above with respect to  FIGS.  6 - 11   , in other instances a wellhead hanger assembly  40  may be configured for left-handed (counterclockwise) rotation of the wellhead hanger  42 . In  FIG.  12   , for example, a wellhead hanger assembly  40  for left-handed rotation of the wellhead hanger  42  is depicted. This depicted wellhead hanger assembly  40  may be substantially identical to that depicted in  FIGS.  2 - 5    but with the orientation of certain features reversed so that the wellhead hanger  42  can be run into and installed in a wellhead in the manner described above for  FIGS.  6 - 11    (with the directions of rotation also reversed). In the embodiment of  FIG.  12   , the orientation of the recesses  76  of the running tool  44  is reversed so that counterclockwise rotation of the running tool  44  drives synchronous counterclockwise rotation of the outer sleeve  48 , while the running tool  44  can freely rotate in the clockwise direction with respect to the outer sleeve  48 . The orientation of the slots  82  of the outer sleeve  48  are also reversed in  FIG.  12   . Additionally, the thread directions of at least the threaded surfaces  60 ,  62 ,  70 , and  72  are reversed compared with those described above with respect to  FIGS.  6 - 11    (i.e., the threaded surfaces  60  and  62  have right-handed threads and the threaded surfaces  70  and  72  have left-handed threads in the embodiment of  FIG.  12   ). 
     Although certain embodiments may be described above in the context of casing hangers, it is noted that the presently disclosed techniques could also be used to rotate other kinds of hangers, such as those connected to other tubular strings or to rods. The running tools and outer sleeves described herein can be used to transmit torque to the hangers (whether casing hangers or some other types of hangers), causing the hangers to rotate synchronously with the running tools. Once rotation is completed and the hangers are landed, the running tools and associated sleeves can be removed from the hangers. 
     While the aspects of the present disclosure may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. But it should be understood that the invention is not intended to be limited to the particular forms disclosed. Rather, the invention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the following appended claims.