Patent Abstract:
An assembly for landing a tubing hanger in a subsea well includes a riser extending from a subsea wellhead assembly to a vessel at the surface of the sea. A tubing hanger having a string of tubing suspended therefrom is lowered through the riser with a string of conduit, and the tubing hanger lands within the subsea wellhead assembly. A sensor is positioned adjacent the subsea wellhead assembly to monitor the axial position of the tubing hanger within the subsea wellhead assembly. The sensor also communicates the axial position of the tubing hanger to the surface. A locking mechanism is carried by the tubing hanger and is selectively operable to lock the tubing hanger in place relative to the subsea wellhead assembly when the tubing hanger reaches a predetermined axial location.

Full Description:
RELATED APPLICATION 
   This nonprovisional application claims the benefit and priority of provisional patent application U.S. Ser. No. 60/709,521, filed on Aug. 19, 2005, which is hereby incorporated by reference in its entirety. 

   BACKGROUND OF THE INVENTION 
   1. Field of the Invention 
   This invention relates in general to offshore drilling, and in particular to equipment and methods for running conduit with an offshore rig. 
   2. Background of the Invention 
   When drilling subsea wells, a low pressure wellhead housing is installed with a string of conductor casing or pipe extending therefrom into the sea floor. A high pressure wellhead housing is then landed in the bore of the low pressure wellhead housing with another string casing extending therefrom to a deeper depth. Additional strings of casing that extend deeper into the subsea well, until at least one string reaches a production depth, are suspended from casing hangers landed within the bore of the high pressure housing. A tubing hanger is then landed for supporting a string of production tubing that receives the hydrocarbons from the subsea well after the deepest string of casing is perforated. 
   Typically, the tubing hanger is lowered into the subsea wellhead assembly through a riser extending from a vessel at the surface. In previous systems, the tubing hanger had downward facing shoulders that would land on an upward facing support within the subsea housing. The downward facing shoulders typically increased the outer diameter of the tubing hanger, and thus also increased the minimum allowable diameter of the riser through which the tubing hanger was lowered. In other previous systems, the retractable locking assemblies were located on the outer periphery of the tubing hanger so that the outer diameter of the tubing hanger was smaller than previous tubing hangers. These locking assemblies were typically actuated mechanically when landing within the subsea wellhead housing by profiles formed in the subsea wellhead assembly that would engage and actuate the locking assembly radially outward to land upon the support surfaces in the subsea wellhead assembly. However, these assemblies required the tubing hanger to be oriented properly for such actuation to occur. 
   SUMMARY OF THE INVENTION 
   An assembly for landing a tubing hanger in a subsea well includes a riser extending from a subsea wellhead assembly to a vessel at the surface of the sea. A tubing hanger having a string of tubing suspended therefrom is lowered through the riser with a string of conduit, and the tubing hanger lands within the subsea wellhead assembly. A sensor is positioned adjacent the subsea wellhead assembly to monitor the axial position of the tubing hanger within the subsea wellhead assembly. The sensor also communicates the axial position of the tubing hanger to the surface. A locking mechanism is carried by the tubing hanger and is selectively operable to lock the tubing hanger in place relative to the subsea wellhead assembly when the tubing hanger reaches a predetermined axial location. 
   The sensor can have a receiver attached to an outer periphery of the riser. Alternatively, the sensor can also be carried by a remote operated vehicle. 
   In the assembly, the subsea wellhead assembly can also include a wellhead housing having a grooved profile formed in an inner bore thereof. The locking mechanism can also have a plurality of locking members or locking dogs positioned within an annular groove formed in the outer circumference of the tubing hanger. The locking members can have a lock profile that matingly engages the grooved profile when the locking members are actuated radially outward. 
   In the assembly, the locking mechanism can include an electrically-actuated solenoid in electrical communication with the vessel. The solenoid can have an extended position and a contracted position. The locking mechanism can also have a plurality of locking members that matingly engage an interior surface of the wellhead housing assembly when actuated radially outward by the solenoid when the solenoid moves to the extended position. The solenoid can be in the contracted position until the tubing hanger is lowered to the predetermined axial position, and the solenoid can be actuated to its extended position with an electrical current from the surface. 
   The assembly can also include a remote operated vehicle positioned adjacent the subsea wellhead assembly with an acoustical transmitter that selectively transmits an acoustical wave into the subsea wellhead assembly. Also in the assembly, the locking mechanism can have an accoustically-actuated solenoid that has an extended position and a contracted position. The locking mechanism can also have a plurality of locking members that matingly engage an interior surface of the wellhead housing assembly when actuated radially outward by the solenoid when the solenoid moves to the extended position. The solenoid can be in the contracted position until the tubing hanger is lowered to the predetermined axial position and the solenoid can be actuated to its extended position when the acoustic wave is transmitted into the subsea wellhead assembly. 
   The assembly can also include a controller on the vessel. The controller can have a power source and a modem. The controller having a first source terminal connecting to the string of conduit and a second source terminal connecting to the riser. The assembly can also include a conductor positioned on the outer surface of the string of tubing that can engage an interior surface of the subsea wellhead assembly to thereby define an electrical circuit for supplying power from the vessel to the sensor, the axial position transmitter, and the locking mechanism. 
   An assembly for landing a tubing hanger in a subsea well can also have a riser extending from a subsea wellhead assembly to a vessel at the surface of the sea. A tubing hanger with a string of tubing suspended therefrom is lowered through the riser with a string of conduit, and lands within the subsea wellhead assembly. An axial position transmitter is positioned adjacent the tubing hanger, and is in electrical communication with the vessel. The axial position transmitter transmits an axial position signal while being lowered through the riser and subsea wellhead assembly. A sensor is positioned adjacent the subsea wellhead assembly. The sensor receives the axial position signal and communicates the axial position of the axial position transmitter within the subsea wellhead assembly to the surface. A locking mechanism is carried by the tubing hanger, and is selectively operable to lock the tubing hanger in place relative to the subsea wellhead assembly when the axial position transmitter reaches a predetermined axial location. 
   The sensor can have a receiver attached to an outer periphery of the riser. Alternatively, the sensor can also be carried by a remote operated vehicle. 
   The assembly can also include a remote operated vehicle that is positioned adjacent the subsea wellhead assembly, and has an acoustical transmitter that selectively transmits an acoustical wave into the subsea wellhead assembly. In the assembly, the locking mechanism can also include an accoustically-actuated solenoid having an extended position and a contracted position. The locking mechanism can further include a plurality of locking members that can matingly engage an interior surface of the wellhead housing assembly when actuated radially outward by the solenoid when the solenoid moves to the extended position. The solenoid can be in the contracted position until the tubing hanger is lowered to the predetermined axial position, and the solenoid can be actuated to its extended position when the acoustic wave is transmitted into the subsea wellhead assembly. 
   The assembly can further include that the remote operated vehicle includes a stab and an electric coil housed within the stab. The electric coil can transmit a plurality of magnetic waves into the subsea wellhead housing. The sensor can receive reflections of the magnetic field waves responsive to the tubing hanger being lowered into the subsea wellhead assembly in order to determine the axial position of the tubing hanger. The assembly can further include that the tubing hanger can be connected to the string of conduit with a tubing hanger running tool having a smaller outer diameter than the tubing hanger. The sensor can receive a variation in the reflections of magnetic waves reflecting from the outer surface of the tubing than from the outer wall of the tubing hanger running tool, thereby signaling when the tubing hanger is in the predetermined axial position. Alternatively, the assembly can include that the axial position transmitter comprises a magnetized material. The sensor can receive a variation in the reflections of magnetic waves reflecting from the outer surface of the tubing than from the magnetized material of the axial position transmitter to signal when the tubing hanger is in the predetermined axial position. 
   In the assembly, the subsea wellhead assembly can include a wellhead housing having a grooved profile formed in an inner bore thereof. The locking mechanism can also include a plurality of inwardly-biased locking members positioned within an annular groove formed in the outer circumference of the tubing hanger. The locking members can have a lock profile that matingly engages the grooved profile when the locking members are actuated radially outward. The locking mechanism can also include a lock cam that is selectively movable between upper and lower positions. The lock cam can have an inclined surface that engages the locking members to actuate the locking members radially outward when the lock cam moves to the upper position. The assembly can further include that the locking mechanism also has an electrically-actuated solenoid in electrical communication with the vessel. The solenoid can be in contact with the lock cam to selectively move the lock cam between the upper and lower positions when the solenoid actuates between an extended position and a contracted position. The locking members can be actuated radially outward by the lock cam when the solenoid actuates to the extended position and moves the lock cam to its upper position. The solenoid can be in the contracted position until the tubing hanger is lowered to the predetermined axial position. The solenoid can be actuated to its extended position with an electrical current from the surface. 
   The assembly can also include a controller on the vessel. The controller can have a power source and a modern. The controller can have a first source terminal connecting to the string of conduit and a second source terminal connecting to the on the riser. The assembly can also have a conductor positioned on the outer surface of the string of tubing that engages an interior surface of the subsea wellhead assembly, which can thereby define an electrical circuit for supplying power from the vessel to the sensor and the locking mechanism. 
   The modem can receive signals from the sensor pertaining to the axial position of the tubing hanger within the subsea wellhead assembly. The modem can be used for communicating electric signals to the solenoid in order to actuate the solenoid when the tubing hanger is in the predetermined axial position. 
   A method of landing a tubing hanger in a subsea well includes the step of extending a riser from a subsea wellhead assembly to a vessel at the surface of the sea. A tubing hanger having a string of tubing suspended therefrom is then lowered with a string of conduit through the riser to within the subsea wellhead assembly. The axial position of the tubing hanger within the subsea wellhead assembly is monitored with a sensor positioned adjacent the subsea wellhead assembly. The axial position of the tubing hanger is communicated to the surface with the sensor. The tubing hanger is locked in place relative to the subsea wellhead assembly when the tubing hanger reaches a predetermined axial location, with a locking mechanism carried by the tubing hanger. 
   In the method, the locking of the tubing hanger step can be performed by actuating a solenoid to an extended position, which causes a plurality of inwardly-bias locking members to move radially outward and engage an interior surface of the subsea wellhead assembly. 
   In the method, lowering of the tubing hanger step can also include providing an axial position transmitter adjacent the tubing hanger and that is carried by the string of conduit. The lowering of the tubing hanger step can also include transmitting signals to the receiver with the axial position transmitter as the tubing hanger and the axial position transmitter are lowered through the riser and the subsea wellhead assembly. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
       FIG. 1  is a schematic view of a tubing hanger being run through a riser and wellhead system in accordance with an embodiment of this invention. 
       FIG. 2  is a schematic vertical view a portion of the tubing hanger and the riser and wellhead system of  FIG. 1 . 
       FIG. 3  is an enlarged schematic view of the portion of the tubing hanger and the riser and wellhead system of  FIG. 2  in an unlocked position. 
       FIG. 4  is an enlarged schematic view of the portion of the tubing hanger and the riser and wellhead system of  FIG. 2  in a locked and landed position. 
       FIG. 5  is a schematic view of an alternative embodiment of a tubing hanger being run through a riser and wellhead system in accordance with an embodiment of this invention. 
       FIG. 6  is a schematic view of an alternative embodiment of a tubing hanger being run through a riser and wellhead system in accordance with an embodiment of this invention. 
   

   DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
   Referring to  FIG. 1 , a wellhead  11  is schematically shown located at sea floor  13 . Wellhead  11  may be a wellhead housing, a tubing hanger spool, or a Christmas tree of a type that supports a tubing hanger within. An adapter  15  connects wellhead  11  to a subsea set of pipe rams  17 . Pipe rams  17  will seal around pipe of a designated size range but will not fully close access to the well if no pipe is present. The subsea pressure control equipment also includes a set of shear rams  19  in the preferred embodiment. Shear rams  19  are used to completely close access to the well in an event of an emergency, and will cut any lines or pipe within the well bore. Pipe rams  17 ,  19  may be controlled by ultrasonic signals or they may be controlled by an umbilical leading to the surface. 
   A riser  21  extends from shear rams  19  upward. Most drilling risers use flanged ends on the individual riser pipes that bolt together. Riser  21 , on the other hand, preferably utilizes casing with threaded ends that are secured together, the casing being typically smaller in diameter than a conventional drilling riser. Riser  21  extends upward past sea level  23  to a blowout prevent (“BOP”) stack  25 . BOP stack  25  is an assembly of pressure control equipment that will close on the outer diameter of a size range of tubular members as well as fully close when a tubular member is not located within. BOP stack  25  serves as the primary pressure control unit for the drilling and completion operation. 
   Riser  21  and BOP stack  25  are supported by a tensioner (not shown) of a floating vessel or platform  27 . Platform  27  may be of a variety of types and will have a derrick and drawworks for drilling and completion operations. 
     FIG. 1  illustrates a string of production tubing  29  lowered into the well below wellhead  11 . A tubing hanger  31 , secured to the upper end of production tubing  29 , lands in wellhead  11 . A tubing hanger running tool  33  releasably secures to tubing hanger  31  for running and locking it to wellhead  11 , and for setting a seal between tubing hanger  31  and the inner diameter of wellhead  11 . Tubing hanger running tool  33  typically includes a quick disconnect member  35  on its upper end that extends through rams  17 ,  19 . Rams  17  will be able to close and seal on disconnect member  35 . Disconnect member  35  is secured to the lower end of a string of conduit  37 , which may also be tubing or it could be drill pipe. Disconnect member  35  allows running tool  33  to be disconnected from conduit  37  in the event of an emergency. While tubing hanger  31  is described herein as that for hanging tubing  29 , those readily skilled in the art will readily appreciate that a casing hanger and a string of casing are interchangeable within the scope of this invention with tubing hanger  31  and tubing  29  associate therewith. 
   In the preferred embodiment, a controller  39  is positioned on platform  27 . Controller  39  is for controlling downhole activities, including landing tubing hanger  31 , and sending and receiving signals from downhole sensors and transmitters. Controller  39  includes a modem  41  for sending and receiving the signals to the downhole sensors and transmitters, and a power supply  43  for transmitting power to downhole. Controller  39  is preferably positioned adjacent an upper portion of riser  21 . A first source terminal  45  extends between controller  39  and conduit  37  so that controller  39  is in electrical communication with conduit  37 . A second source terminal  47  extends between controller  39  and riser  21  so that controller  39  is in electrical communication with riser  21 . In the preferred embodiment, second source terminal  47  acts as an electrical ground when there is a closed electrical circuit including conduit  37  and riser  21 . 
   Referring to  FIG. 2 , a conductor  48  is positioned between production tubing  29  and a string of casing  52  extending downward from wellhead  11 . Conductor  48  advantageously closes an electrical circuit that includes controller  39 , conduit  37 , and riser  21  so that modem  41  and power supply  43  are in electrical communication with downhole equipment located above conductor  48 . As will be readily appreciated by those skilled in the art, conductor  48  can be several devices that have a desired conductivity in order to close an electrical circuit. For example, conductor  48  can be centralizers to aid in the landing of production tubing  29 . Conductor  48  can also be a brush ring with metallic bristles that attaches to the outer circumference of production tubing  29 . 
   Referring to  FIGS. 1 and 2 , a receiver  51  is preferably positioned on riser  21  in electrical communication with controller  39 . In the embodiment shown in  FIGS. 1 and 2 , an axial position transmitter  49  that is positioned on tubing hanger running tool  33  transmits a signal when the electrical circuit including controller  39 , conduit  37 , conductor  48 , and riser  21  is closed. Receiver  51  receives the signal from axial position transmitter  49  and conveys that signal to controller  39  and modem  41 . 
   As best shown in  FIG. 2 , a grooved profile  53  is formed on an inner surface of wellhead  11 . In the preferred embodiment, tubing hanger  31  engages grooved profile  53  when landing in wellhead  11 . At least one, and preferably a plurality of suspension dogs  55  are positioned along an outer circumference of tubing hanger  31 . A counter-oriented grooved profile  57  is preferably formed on suspension dogs  55  for engaging grooved profile  53  of wellhead  11 . Suspension dogs  55  are preferably located within an annular groove  59  formed along an outer circumference of tubing hanger  31 . Dogs  55  are selectively moveable between a radially inward position within annular groove  59  ( FIGS. 2 and 3 ) and a radially outward position ( FIG. 4 ). 
   Referring to  FIGS. 2-4 , a cam  61  is located within annular groove  59 , in contact with dogs  55 . Cam  61  has an inclined face  63  that slidingly engages a lower portion of dogs  55 . An upper portion of dogs  55  engages a downward facing surface  65  formed by annular groove  59 . Inclined face  63  extends so that cam  61  is narrower near its upper portion, and wider near its lower portion. 
   A solenoid  67  is positioned within annular groove  59 , between an upward facing ledge  69  of annular groove  59  and a lower surface of cam  61 . Solenoid  67  is in electrical communication with controller  39 , which electronically actuates solenoid  67  between a contracted position shown in  FIG. 3  and an expanded position shown in  FIG. 4 . An O-ring or retention spring  71  extends circumferentially around annular groove  59  through dogs  55 . Retention spring  71  biases dogs  55  radially inward within annular groove  59 . 
   In operation, tubing hanger  31  with the string of production tubing  29  hanging therefrom is lowered into the bore of wellhead  11  and casing  52 . Suspension dogs  55  are preferably radially inward, solenoid  61  being in the contracted position illustrated in  FIGS. 2 and 3 . Controller  39  is in electrical communication with production tubing  29  through first source terminal  45 , and with casing  52  through second source terminal  47 . An electrical circuit is closed when production tubing  29  and casing  52  are both in contact with conductor  48 . The circuit is closed before tubing hanger  31  reaches an axial depth such that dogs  55  are below grooved profile  53 . Axial position transmitter  49  receives electrical power from power supply  43 , and in turn transmits a signal that is received by receiver  51 . Receiver  51  transmits an electrical signal that is indicative of the axial position of axial position transmitter  49  to modem  41  in controller  39 . 
   When axial position transmitter  49  reaches a predetermined depth location, which is typically within wellhead  11 , modem  41  of controller  39  sends an electrical signal to actuate solenoid  67  from its contracted position ( FIG. 3 ) to its extended position ( FIG. 4 ). Solenoid  67  moves cam  61  axially upward, causing inclined face  63  to slidingly engage a lower portion of each of suspension dogs  55 . Downward facing surface  65  prevents dogs  55  from moving axially upward with cam  61 . Instead, suspension dogs  55  move radially outward to their radially outward position shown in  FIG. 4  in response to inclined face  63  slidingly engaging dogs  55 . Grooved profile  57  on the radially outward surface of dogs  55  engages grooved profile  53  of wellhead  11 . Tubing hanger  31  is landed within wellhead bore  11  when dogs  55  engage grooved profile  53 . 
   Referring to  FIG. 5 , additional embodiments using a remote operated vehicle or ROV  81  are disclosed for landing tubing hanger  31  in wellhead  11 . ROV  81  is positioned adjacent wellhead  11  and has a control line  83  extending to the surface. An operator can control various functions of ROV  81  via control line  83 . An ROV stab  85  extends from ROV  81  for connection with a stab receptacle  87 . As shown in  FIG. 5 , stab receptacle  87  is part of adapter  15 , however, those skilled in the art will readily appreciate that stab receptacle  87  can be located in various other parts of the wellhead assembly. 
   In one embodiment, receiver  51  senses and transmits signals pertaining to the axial position of axial position transmitter  49  as described above. In this embodiment however, solenoid  67  is an acoustically-actuated solenoid. When in the proper axial position for actuating suspension dogs  55 , ROV  81  transmits an acoustical wave W 1  into the wellhead assembly to actuated solenoid  67 . 
   In another embodiment using ROV  81  shown in  FIG. 6 , an electric coil  89  is positioned within a portion of ROV stab  85 . Electric coil  89  transmits a magnetic field wave W 2  into the wellhead assembly. As tubing  29 , tubing hanger  31 , and tubing hanger running tool  33  passes through electric field wave W 2  from electric coil  89 , different signals are communicated to ROV  81 . These signals can be based upon the presence of metal and the relative distance of the metal from electric coil  89 . Therefore, operator can determine when there is a reduction of diameter from tubing hanger  31  to tubing hanger running tool  33 . Additionally, in this embodiment, axial position transmitter  49  can comprise a magnetized material that would enhance or magnify the reaction to electrical field wave W 2 . Dogs  55  can be actuated radially outward when tubing hanger  31  is in a predetermined axial location with either the electrically or acoustically actuated solenoids  67  as described above. 
   The assembly and methods described herein allow an operator to utilize narrower drilling risers and BOP systems than typically used in the past. Previous assemblies included tubing hangers that could not fit through such narrow risers because of the width of the orientation devices used to mechanically align the tubing hanger within the bore of the wellhead housing, and because of the width of the locking members that engage the bore of the subsea wellhead housing. The assembly and methods described herein also does not require the tubing hanger to be aligned for automatically, mechanically actuating locking members upon landing. Rather, the locking members remain retracted radially inward until at the correct axial position for being actuated to engage the grooved profile of the bore of the wellhead housing. 
   The assembly described herein is configured to permit drilling and completion through a slim bore riser, typically comprising commercially available well casings, with a BOP positioned at or near the surface or subsea, while accommodating large bore completions. 
   While the invention has been shown in only some of its forms, it should be apparent to those skilled in the art that it is not so limited, but susceptible to various changes without departing from the scope of the invention. For example, the process and equipment used for landing production tubing  29  and tubing hanger  31  can easily be utilized for landing casing hangers and intermediate strings of casing.

Technology Classification (CPC): 4