Patent Publication Number: US-2021189821-A1

Title: Rotary latch device

Description:
TECHNICAL FIELD 
     The present disclosure relates generally to wellhead systems, and, more particularly, to latching devices for use with wellhead systems. 
     BACKGROUND 
     Tools and equipment can be used for a wide variety of purposes with oil and gas wells. For example, wireline tools can lower instruments into a wellbore on the end of a wireline cable to measure wellbore properties or perform operations within the wellbore. During operation, tools and equipment can be attached and removed from an oil and gas well. 
     Wellhead systems can provide a surface interface to allow tools and equipment to be coupled with an oil and gas well. For example, a wireline tool can be aligned with and coupled to a wellhead system. However, one drawback of conventional interfaces is that aligning and coupling a tool to the surface interface often requires personnel to be exposed to potentially hazardous conditions. Further, tools may be improperly aligned and/or incompletely secured to conventional interfaces. Improper alignment or incomplete coupling can lead to leakage or a risk of blowout. Therefore, what is needed is an apparatus, system or method that addresses one or more of the foregoing issues, among one or more other issues. 
     SUMMARY OF THE INVENTION 
     A latching assembly to couple a first mandrel to a second mandrel is disclosed. The latching assembly includes a plurality of wedge members disposed circumferentially and a guide plate. Each wedge member may include a semi-annular wedge body, an upper engagement lip, a lower engagement lip, and a guide pin. The guide plate may include a plurality of guide slots to translate and rotate the plurality of wedge members via the respective guide pins. Because the plurality of wedge members can be translated and rotated to lock and release the first mandrel to and from the second mandrel, the latching assembly can simplify the connection and disconnection of a first mandrel with the second mandrel. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Various embodiments of the present disclosure will be understood more fully from the detailed description given below and from the accompanying drawings of various embodiments of the disclosure. In the drawings, like reference numbers may indicate identical or functionally similar elements. 
         FIG. 1  is an elevation view of an embodiment of a rotary latch device. 
         FIG. 2  is an isometric view of the rotary latch device of  FIG. 1 . 
         FIG. 3  is a partial cross-sectional view of the rotary latch device of  FIG. 1  with a latching assembly in a released position. 
         FIG. 4  is an isometric view of the rotary latch device of  FIG. 1  with the device housing shown in hidden lines to show the latching mechanism in a released position. 
         FIG. 5  is an isometric view of the rotary latch device of  FIG. 1  with the device housing shown in hidden lines and with the latching assembly in a released position. 
         FIG. 6  is a partial cross-sectional view of the rotary latch device of  FIG. 1  with a latching assembly in an engaged position. 
         FIG. 7  is an isometric view of the rotary latch device of  FIG. 1  with the device housing shown in hidden lines and with the latching assembly in an engaged position. 
         FIG. 8  is an isometric view of an embodiment of a rotary latch device. 
         FIG. 9  is a partial cross-sectional view of the rotary latch device of  FIG. 8 . 
     
    
    
     DETAILED DESCRIPTION 
       FIG. 1  is an elevation view of an embodiment of a rotary latch device  100 .  FIG. 2  is an isometric view of the rotary latch device  100  of  FIG. 1 . With reference to  FIGS. 1 and 2 , the rotary latch device  100  can receive a tool mandrel  110  and latch and/or engage the tool mandrel  110  to a wellhead connection mandrel  120 . 
     In the depicted example, the rotary latch device  100  can be coupled to the wellhead connection mandrel  120 . As illustrated, the wellhead connection mandrel  120  can be coupled to a lower portion  106  of the device housing  102 . In some applications, the wellhead connection mandrel  120  can allow access to a wellbore via a wellhead in fluid communication with the wellhead connection mandrel  120 . The wellhead connection mandrel  120  can be coupled to downstream wellbore components with a flange  122 . Fasteners  126  can extend through fastener holes  124  to secure the flange  122  to downstream wellbore components. As described herein, the rotary latch device  100  can be coupled to the wellhead connection mandrel  120  to facilitate and simplify remote engagement and latching of the tool mandrel  110  to the wellhead connection mandrel  120 . 
     During operation, the rotary latch device  100  can receive the tool mandrel  110  via a receiver  130 . Optionally, the tool mandrel  110  can be part of a wellbore tool or equipment, such as a wireline tool, etc., configured for use in the wellbore. In some embodiments, the tool mandrel  110  can be coupled to other portions of a wellbore tool or other wellbore components via a flange  112 . Fasteners  116  can extend through fastener holes  114  to secure the flange  112  to other portions of the wellbore tool or other wellbore components. 
     In the illustrated embodiment, the rotary latch device  100  includes a receiver  130  to align and direct the tool mandrel  110  into engagement with the wellhead connection mandrel  120  within the device housing  102 . As shown, the receiver  130  extends out of the upper portion  104  of the device housing  102 . The receiver  130  can include a flared portion  134  that tapers into the receiver mandrel  136 . Advantageously, by increasing the diameter of the flared portion  134  relative to the receiver mandrel  136 , the tool mandrel  110  can be directed and self-aligned into the receiver mandrel  136 , during a stab-in procedure. Optionally, the receiver  130  can include support tabs  132  extending from the flared portion  134  of the receiver  130  to the device housing  102 . 
     Upon entering the receiver mandrel  136 , the receiver mandrel  136  can direct the tool mandrel  110  into alignment and engagement with the wellhead connection mandrel  120 . Upon engagement with the wellhead connection mandrel  120 , the rotary latch device  100  can latch or lock the tool mandrel  110  to the wellhead connection mandrel  120 . In some embodiments, the latch mechanism of the rotary latch device  100  can be actuated by an actuation assembly disposed within an actuation housing  108 . 
       FIG. 3  is a partial cross-sectional view of the rotary latch device  100  of  FIG. 1  with a latching assembly  140  in a released position. In the depicted example, the latching assembly  140  is shown in a released position or configuration to permit engagement of the tool mandrel  110  with the wellhead connection mandrel  120  or to permit removal of the tool mandrel  110  from the rotary latch device  100 . 
     In the depicted example, the tool mandrel  110  is shown engaged with the wellhead connection mandrel  120 . As illustrated, the mating flange  118  of the tool mandrel  110  engages with the mating flange  128  of the wellhead connection mandrel  120 . Optionally, the mating flange  118  and the mating flange  128  can sealingly engage to prevent leaks. 
     In some embodiments, the tool mandrel  110  includes a mandrel extension  117  configured to extend into and engage with the inner bore of wellhead connection mandrel  120 . The mandrel extension  117  can further aid in aligning the tool mandrel  110  with the wellhead connection mandrel  120  during engagement. Sealing elements may also be included at the interface between mandrel extension  117  and the inner bore of wellhead connection mandrel  120 . As illustrated, the wellhead connection mandrel  120  can further be coupled to the rotary latch device  100  at a coupling flange  129 . 
     As illustrated, the irising wedges  150  of the latching assembly  140  can be circumferentially spaced apart in a released configuration to allow the tool mandrel  110  to engage or disengage from the wellhead connection mandrel  120 . As can be appreciated, the irising wedges  150  can be sufficiently radially spaced apart to allow the tool mandrel  110  to move axially relative to the wellhead connection mandrel  120 . 
       FIGS. 4 and 5  are isometric views of the rotary latch device  100  of  FIG. 1  with the device housing  102  shown in hidden lines to show the latching assembly  140  in a released position. With reference to  FIGS. 3-5 , each of the irising wedges  150  has a generally semi-annular shape. Each irising wedge  150  can be a geometric sector of an overall annular shape. In the illustrated embodiment, the latching assembly  140  includes 8 semi-annular irising wedges  150  that can be arranged to form an annular shape as described herein. In some embodiments, the latching assembly  140  can include any suitable number of irising wedges  150 . 
     As shown, each irising wedge  150  can include an upper engagement lip  152  and a lower engagement lip  154 , each radially extending from the main body of irising wedge  150 . As illustrated, the lower engagement lip  154  can be axially spaced apart from the upper engagement lip  152 . The axial space between lower engagement lip  154  and upper engagement lip should be sufficient to accommodate the combined axial width of mating flange  118  of tool mandrel  110  and mating flange  128  of wellhead connection mandrel  120 . Further, an inner circumferential engagement surface  156  can be defined opposite to the outer surface  158  and between the upper engagement lip  152  and the lower engagement lip  154 . 
     In the depicted example, the irising wedges  150  are disposed between an upper guide plate  162  and a lower guide plate  166  to retain and guide the irising wedges  150 . During operation, the irising wedges  150  can be moved into a released configuration by rotating an upper guide plate  162  and/or a lower guide plate  166 . As the upper guide plate  162  and/or the lower guide plate  166  are rotated, guide slots  164 ,  168  can engage with guide pins  159  to translate and/or rotate the irising wedges  150  into the released configuration. In some embodiments, as the upper guide plate  162  is rotated in a counter-clockwise direction, the guide slots  164  can engage with the guide pins  159  to radially move the irising wedges  150  away from the wellhead connection mandrel  120 . 
     As illustrated, the upper guide plate  162  includes a plurality of angularly disposed guide slots  164 . The upper guide plate  162  can include a corresponding number of guide slots  164  to receive a respective guide pin  159  from each irising wedge  150 . As can be appreciated, the guide slots  164  can be formed with a desired angle having a radial and/or tangential component to provide a desired actuation behavior of the irising wedges  150  when the upper guide plate  162  is rotated. It should be understood that the guide pins  159  of irising wedges  150  may engage only with guide slots  164  in upper guide plate  162 , only with guide slots  168  in lower guide plate  166 , or with a combination of both. Further, in some embodiments, guide slots may only be present on one of upper guide plate  162  or lower guide plate  166 . 
     In some embodiments, the lower guide plate  166  can include a plurality of angularly disposed guide slots  168 . Optionally, the guide slots  168  can be offset in position and/or angle from the guide slots  164 . Further, the guide pins  159  extending into the guide slots  168  can be offset from the guide pins  159  extending into the guide slots  164 . As can be appreciated, the guide slots  168  can be formed with a desired angle having a radial and/or tangential component and offset to provide a desired actuation behavior of the irising wedges  150  when the upper guide plate  162  and/or the lower guide plate  166  is rotated. 
     During operation, the upper guide plate  162  and/or the lower guide plate  166  can be rotated by an actuation assembly  170  engaged with an actuating gear  160  coupled to the upper guide plate  162  and/or the lower guide plate  166 . In the depicted example, the actuation assembly  170  can rotate one or both of the upper guide plate  162  and the lower guide plate  166  to move the irising wedges  150 . Optionally, portions of the device housing  102  can rotate as the irising wedges  150  are moved to provide a visual signal of engagement or disengagement of the tool mandrel  110 . 
     In some embodiments, the actuation assembly  170  can include a worm gear  174  that is in meshed engagement with gear teeth  161  of the actuating gear  160 . By rotating an actuator shaft  172  of the actuation assembly  170 , the worm gear  174  coupled to the actuator shaft  172  can rotate the actuating gear  160  and therefore rotate the upper guide plate  162  and/or the lower guide plate  166  to actuate the irising wedges  150 . 
     Optionally, the actuator shaft  172  and the worm gear  174  can be driven by a motor, such as an electric motor and/or a hydraulic motor. In some embodiments, the motor can rotate the actuator shaft  172  via a shaft input  176  coupled to the actuator shaft  172 . Advantageously, by actuating the irising wedges  150  with a motor, the tool mandrel  110  can be engaged and/or disengaged from the wellhead connection mandrel  120  remotely. 
       FIG. 6  is a partial cross-sectional view of the rotary latch device  100  of  FIG. 1  with a latching assembly  140  in an engaged position. In the depicted example, the latching assembly  140  is shown in a latched or locked position to secure the tool mandrel  110  to the wellhead connection mandrel  120  during operation. 
     As described herein, the irising wedges  150  can radially converge or constrict to engage and retain the tool mandrel  110  with the wellhead connection mandrel  120 . In some embodiments, the irising wedges  150  cooperatively form an annular shape as the irising wedges  150  converge around the tool mandrel  110  and the wellhead connection mandrel  120 . As illustrated, the irising wedges  150  are both axially and radially aligned to engage with the mating flanges  118 ,  128 . 
       FIG. 7  is an isometric view of the rotary latch device  100  of  FIG. 1  with the device housing  102  shown in hidden lines and with the latching assembly  140  in an engaged position. With reference to  FIGS. 6 and 7 , upon converging to a locked position, each of the irising wedges  150  can at least partially enclose the mating flanges  118 ,  128 . For example, an upper axial engagement surface defined by the upper engagement lip  152  can engage against the upper surface of the mating flange  118 . A lower axial engagement surface defined by the lower engagement lip  154  can engage against the lower surface of the mating flange  128 . As illustrated, the lower axial engagement surface is axially spaced apart from the upper axial engagement surface. Advantageously, the upper axial engagement surface and the lower axial engagement surface can cooperatively constrain the mating flanges  118 ,  128  to prevent axial movement of the tool mandrel  110  and the wellhead connection mandrel  120  relative to each other. 
     In some embodiments, the inner circumferential engagement surface  156  between the upper engagement lip  152  and the lower engagement lip  154  can engage against the edges of the mating flanges  118 ,  128 . In some embodiments, the inner circumferential engagement surface  156  can limit radial movement of the mating flanges  118 ,  128  and can improve stability of the coupling between the tool mandrel  110  and the wellhead connection mandrel  120 . 
     Optionally, the inner edges of the upper engagement lip  152  and the lower engagement lip  154  can define mandrel engagement surface  157  configured to engage against portions of the tool mandrel  110  and the wellhead connection mandrel  120 . In some applications, the mandrel engagement surface  157  can limit radial movement of the tool mandrel  110  and the wellhead connection mandrel  120 . 
     During operation, the irising wedges  150  can be moved into a locking configuration by rotating an upper guide plate  162  and/or a lower guide plate  166 . As the upper guide plate  162  and/or the lower guide plate  166  are rotated, guide slots  164 ,  168  can engage with the guide pins  159  of the irising wedges  150  to translate and/or rotate the irising wedges  150  into the locking configuration. In some embodiments, as the upper guide plate  162  is rotated in a clockwise direction, the guide slots  164  can engage with the guide pins  159  to radially move the irising wedges  150  toward the mating flanges  118 ,  128  to retain the tool mandrel  110  with the wellhead connection mandrel  120 . 
     As can be appreciated, the guide slots  164 ,  168  of the upper guide plate  162  and the lower guide plate  166  can be configured to rotate and/or translate the irising wedges  150  into an annular shape upon rotation of the upper guide plate  162  and/or the lower guide plate  166 . 
     During operation, the actuation assembly  170  can rotate one or both of the upper guide plate  162  and the lower guide plate  166  to move the irising wedges  150  between a released position and an engaged or locked position. 
       FIG. 8  is an isometric view of an embodiment of a rotary latch device  200 .  FIG. 9  is a partial cross-sectional view of the rotary latch device  200  of  FIG. 8 . With reference to  FIGS. 8 and 9 , the rotary latch device  200  can be inverted or flipped in comparison to the rotary latch device  100 , such that the rotary latch device  200  can receive a wellhead connection mandrel  220  and latch and/or engage the wellhead connection mandrel  220  to a tool mandrel  210 . As can be appreciated, the rotary latch device  200  can include features that are similar to those of rotary latch device  100 . Accordingly, similar features may be referred to with similar reference numerals. 
     In the depicted example, the rotary latch device  200  can be coupled to the tool mandrel  210 . As illustrated, the tool mandrel  210  can be coupled to an upper portion  204  of the device housing  202 . Optionally, the tool mandrel  210  can be part of a wellbore tool or equipment, such as a wireline tool, etc., configured for use in the wellbore. In some embodiments, the tool mandrel  210  can be coupled to other portions of a wellbore tool or other wellbore components via a threaded portion  211 . As described herein, the rotary latch device  200  can be coupled to the tool mandrel  210  to facilitate and simplify remote engagement and latching of the wellhead connection mandrel  220  to the tool mandrel  210 . 
     During operation, the rotary latch device  200  can receive the wellhead connection mandrel  220  via a receiver  230 . In some applications, the wellhead connection mandrel  220  can allow access to a wellbore via a wellhead in fluid communication with the wellhead connection mandrel  220 . The wellhead connection mandrel  220  can be coupled to downstream wellbore components with a threaded connection  222 . Optionally, the threaded connection  222  can be outfitted with a variety of connection types and/or sizes. Advantageously, the rotary latch device  200  can allow rapid connection and disconnection of the tool mandrel  210  from the wellhead connection mandrel  220 . 
     In the illustrated embodiment, the rotary latch device  200  includes a receiver  230  to align and direct the wellhead connection mandrel  220  into engagement with the tool mandrel  210  within the device housing  202 . As shown, the receiver  230  extends out of the lower portion  206  of the device housing  202 . The receiver  230  can include a flared portion  234  that tapers into the receiver mandrel  236 . Advantageously, by increasing the diameter of the flared portion  234  relative to the receiver mandrel  236 , the wellhead connection mandrel  220  can be directed and self-aligned into the receiver mandrel  236  during a stab-in procedure. Optionally, the receiver  230  can include support tabs  232  extending from the flared portion  234  of the receiver  230  to the device housing  202 . 
     Upon entering the receiver mandrel  236 , the receiver mandrel  236  can direct the wellhead connection mandrel  220  into alignment and engagement with the tool mandrel  210 . Upon engagement with the tool mandrel  210 , the rotary latch device  200  can latch or lock the wellhead connection mandrel  220  to the tool mandrel  210 , similar to as described with respect to rotary latch device  100 . 
     In the depicted example, the latching assembly  240  is shown in a released position or configuration to permit engagement of the wellhead connection mandrel  220  with the tool mandrel  210  or to permit removal of the wellhead connection mandrel  220  from the rotary latch device  200 . 
     In the depicted example, the wellhead connection mandrel  220  is shown engaged with the tool mandrel  210 . As illustrated, the mating flange  228  of the wellhead connection mandrel  220  engages with the mating flange  218  of the tool mandrel  210 . Optionally, the mating flange  228  and the mating flange  218  can sealingly engage to prevent leaks. 
     In some embodiments, the wellhead connection mandrel  220  includes a mandrel extension  227  configured to extend into and engage with the inner bore of tool mandrel  210 . The mandrel extension  227  can further aid in aligning the wellhead connection mandrel  220  with the tool mandrel  210  during engagement. Sealing elements may also be included at the interface between mandrel extension  227  and the inner bore of tool mandrel  210 . As illustrated, the tool mandrel  210  can further be coupled to the rotary latch device  200  at a coupling flange  219 . 
     Similar to rotary latch device  100 , the rotary latch device  200  can include a latching assembly  240  with a plurality of irising wedges  250  to allow the wellhead connection mandrel  220  to engage or disengage from the tool mandrel  210 . As can be appreciated, the latching assembly  240  can operate in a similar manner as described with respect to latching assembly  140 . For example, the irising wedges  250  can radially converge or constrict to engage and retain the tool mandrel  210  with the wellhead connection mandrel  220 . In some embodiments, the irising wedges  250  cooperatively form an annular shape as the irising wedges  250  converge around the tool mandrel  210  and the wellhead connection mandrel  220 . In an engagement position, the irising wedges  250  can be both axially and radially aligned to engage with the mating flanges  218 ,  228 . 
     In some embodiments, the latching assembly  240  can be actuated by an actuation assembly  270 . Optionally, the actuation assembly  270  can include a motor or actuator that is operatively coupled to a drive mechanism, such as a worm gear to rotate the upper guide plate  262  and/or the lower guide plate  266  to actuate the irising wedges  250 . In some embodiments, the actuation assembly  270  can include a motor that is coupled to a worm gear by a belt or other drive mechanism. Further, the actuation assembly  270  or the rotary latch device  200  generally can be controlled by hardware disposed within the control boxes  280   a  and  280   b . The control boxes  280   a  and  280   b  can include control hardware, wireless transceivers, and/or power supplies. The actuation assembly  270  and the control boxes  280   a  and  280   b  can be coupled or otherwise attached to the device housing  202 . 
     It is understood that variations may be made in the foregoing without departing from the scope of the present disclosure. In several exemplary embodiments, the elements and teachings of the various illustrative exemplary embodiments may be combined in whole or in part in some or all of the illustrative exemplary embodiments. In addition, one or more of the elements and teachings of the various illustrative exemplary embodiments may be omitted, at least in part, and/or combined, at least in part, with one or more of the other elements and teachings of the various illustrative embodiments. 
     Any spatial references, such as, for example, “upper,” “lower,” “above,” “below,” “between,” “bottom,” “vertical,” “horizontal,” “angular,” “upwards,” “downwards,” “side-to-side,” “left-to-right,” “right-to-left,” “top-to-bottom,” “bottom-to-top,” “top,” “bottom,” “bottom-up,” “top-down,” etc., are for the purpose of illustration only and do not limit the specific orientation or location of the structure described above. 
     In several exemplary embodiments, while different steps, processes, and procedures are described as appearing as distinct acts, one or more of the steps, one or more of the processes, and/or one or more of the procedures may also be performed in different orders, simultaneously and/or sequentially. In several exemplary embodiments, the steps, processes, and/or procedures may be merged into one or more steps, processes and/or procedures. 
     In several exemplary embodiments, one or more of the operational steps in each embodiment may be omitted. Moreover, in some instances, some features of the present disclosure may be employed without a corresponding use of the other features. Moreover, one or more of the above-described embodiments and/or variations may be combined in whole or in part with any one or more of the other above-described embodiments and/or variations. 
     Although several exemplary embodiments have been described in detail above, the embodiments described are exemplary only and are not limiting, and those skilled in the art will readily appreciate that many other modifications, changes and/or substitutions are possible in the exemplary embodiments without materially departing from the novel teachings and advantages of the present disclosure. Accordingly, all such modifications, changes, and/or substitutions are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, any means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Moreover, it is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the word “means” together with an associated function.