Abstract:
A system for monitoring the orientation and position of components in an oil well. The system includes a first well component, a second well component, and a transducer attached to the first well component, for generating a pulse. The system also includes a transceiver attached to the second well component for measuring the parameters of the pulse generated by the transducer, and a processor in communication with the transceiver that receives information about the parameters of the pulse as measured by the transceiver, and that calculates the position of the transceiver relative to the transducer.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims priority to and the benefit of U.S. Provisional Patent Application Ser. No. 61/987,300, which was filed May 1, 2014, the full disclosure of which is hereby incorporated herein by reference in its entirety. 
     BACKGROUND OF THE INVENTION 
     1. Field of Invention 
     The present disclosure relates in general to oil and gas drilling equipment, and more particularly to a system and method for monitoring the position and orientation of equipment in a wellhead assembly. 
     2. Description of Related Art 
     Subsea running tools are typically used to operate equipment within subsea wellheads and subsea production trees. This may include landing and setting of hangers, trees, wear bushings, logging tools, etc. Current running tools are generally hydraulically or mechanically operated, and are often used to assemble a subsea wellhead by landing and setting a casing hanger and associated casing string. A mechanical running tool usually lands and sets the casing hanger within the wellhead by landing on a shoulder and undergoing a series of rotations using the weight of the casing string to engage dogs or seals of the casing hanger with the wellhead. Typical hydraulic running tools land and set the casing hanger by landing the hanger on a shoulder in the wellhead. Drop balls or darts are sometimes used to block off portions of the tool, wherein hydraulic pressure will build up behind the ball or dart causing a function of the tool to operate to engage locking dogs of the hanger or set a seal between the hanger and wellhead. Pressure behind the ball or dart is increased to release the ball or dart for use in subsequent operations. Some tools are a combination of mechanical and hydraulic tools and perform operations using both mechanical functions and hydraulically powered functions. These tools are complex and require complex and expensive mechanisms to operate, and thus are prone to malfunction due to errors in both design and manufacturing. As a result, the tools installation operations may fail at rates higher than desired when used to drill, complete, or produce a subsea well. Failure of the tool installation operation means the tool and installed equipment, e.g., a casing hanger, must be pulled from and rerun into a well, adding several days and millions of dollars to a job. 
     These tools provide limited feedback to operators located on the rig. For example, limited feedback directed to the torque applied, the tension of the landing string, and the displacement of the tool based on sensors on the surface equipment may be communicated to the rig operator. When a malfunction occurs downhole, however, it is not known until the string is retrieved and the tool is inspected, taking several hours and costing thousands of dollars. Also, even if there is no malfunction, rig operators generally do not have definitive confirmation that the running tool has operated as intended at the subsea location until the running tool is retrieved and inspected. A pressure test can often be passed even if the equipment has not been installed per the specification. 
     SUMMARY OF THE INVENTION 
     An example embodiment of the present invention provides a system for monitoring the orientation and position of components in an oil well. The system includes a first well component, a second well component, and a transducer attached to the first well component, for generating a pulse. The system further includes a transceiver attached to the second well component for measuring the parameters of the pulse generated by the transducer, a processor in communication with the transceiver that receives information about the parameters of the pulse as measured by the transceiver, and that calculates the position of the transceiver relative to the transducer. 
     An alternate embodiment of the present invention provides a system for monitoring the orientation and position of components in an oil well. The system includes a well head member attached to the top of the well, a well head sensor attached to the well head member, a hanger for insertion into the well head member, and a hanger sensor attached to the hanger, the well head sensor and the hanger sensor emitting a signal when positioned a predetermined distance from one another to indicate that the hanger is properly positioned within the well head member. The system further provides a receiver for receiving the signal from, and in communication with, the hanger sensor, the well head sensor, or both the hanger sensor and the well head sensor. 
     Yet another embodiment of the present invention provides a method of determining the location of a moveable component of a well head assembly having a transceiver attached thereto relative to a stationary component of the well head assembly having a transducer attached thereto. The method includes moving the moveable component of the well head assembly relative to the stationary component of the well head assembly, and emitting a pulse from the transducer. The method also includes receiving the pulse by the transceiver, determining the position of the transceiver relative to the transducer based on the time of flight of the pulse between the transducer and the transceiver, or the strength of the pulse when received by the transceiver, and determining the position of the moveable component of the well head assembly relative to the stationary component of the wellhead assembly based on the position of the transceiver relative to the transducer. 
    
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
       Some of the features and benefits of the present invention having been stated, others will become apparent as the description proceeds when taken in conjunction with the accompanying drawings, in which: 
         FIG. 1  is a side cross-partial sectional view of a system for monitoring tool orientation in a well, according to an embodiment of the present invention. 
         FIG. 2  is an axial cross-sectional view of a system for monitoring tool orientation in a well, according to an alternate embodiment of the present invention. 
         FIG. 3  is a side cross-sectional view of the system for monitoring tool orientation of  FIG. 2 . 
     
    
    
     While the invention will be described in connection with the preferred embodiments, it will be understood that it is not intended to limit the invention to that embodiment. On the contrary, it is intended to cover all alternatives, modifications, and equivalents, as may be included within the spirit and scope of the invention as defined by the appended claims. 
     DETAILED DESCRIPTION OF INVENTION 
     The method and system of the present disclosure will now be described more fully hereinafter with reference to the accompanying drawings in which embodiments are shown. The method and system of the present disclosure may be in many different forms and should not be construed as limited to the illustrated embodiments set forth herein; rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey its scope to those skilled in the art. Like numbers refer to like elements throughout. In an embodiment, usage of the term “about” includes +/−5% of the cited magnitude. In an embodiment, usage of the term “substantially” includes +/−5% of the cited magnitude. 
     It is to be further understood that the scope of the present disclosure is not limited to the exact details of construction, operation, exact materials, or embodiments shown and described, as modifications and equivalents will be apparent to one skilled in the art. In the drawings and specification, there have been disclosed illustrative embodiments and, although specific terms are employed, they are used in a generic and descriptive sense only and not for the purpose of limitation. 
       FIG. 1  shows a side cross-sectional view of a wellhead assembly  10  according to one embodiment of the present invention, being assembled on a surface  12 , where the surface can be the seafloor. The wellhead assembly  10  is illustrated over a well  14  that intersects formation  15  below the surface  12 . In the example, a running tool assembly  16  is employed for landing a tubing hanger  18  in the wellhead assembly  10 . The tubing hanger  18  may typically be attached to a string of tubing lowered into the well. The tubing hanger  18  can be landed in the high pressure wellhead housing, as discussed below, or can alternately be landed in, e.g., a tubing hanger spool or a horizontal tree (not shown). As shown in  FIG. 1 , the tubing hanger  18  is not fully set in the wellhead assembly  10 . The running tool assembly  16  is coupled to the tubing hanger  18  by dogs  19  schematically illustrated projecting radially outward from a running tool  20  (which is part of the running tool assembly  16 ) and into an inner surface of the annular tubing hanger  18 . The running tool typically lands the tubing hanger  18  or other hangers, and sets the annular seal (discussed in greater detail below). Also part of the running tool assembly  16  is a tubular string  22 , which couples to the running tool  20  and is used for deploying, operating, and orienting the running tool  20  in the wellhead assembly  10 . Further included in the running tool assembly  16  of  FIG. 1  is a module  24  shown mounted onto the string  22  and above running tool  20 . Module  24  is an annular structure that can surround the drill string  22 , and can be attached to the running tool  20  via cables or other means. In some embodiments, the module  24  can be integral to the running tool  20 . 
     The wellhead assembly  10  includes an annular low pressure wellhead housing  25  having a conductor pipe  26  that projects into the formation  15 . An annular high pressure wellhead housing  28  surrounds the low pressure wellhead housing  25 . A blowout preventer (BOP)  27  is mounted to the high pressure wellhead housing  28 , wherein clamps (not shown) may be used for mounting the BOP  27  onto the low pressure wellhead housing  25 . Casing hangers  30 ,  31  are shown landed at axially spaced apart locations within the high pressure wellhead housing  28 . Each casing hanger  30 ,  31  connects to a separate string of casing extending into and cemented in the well. A riser (not shown) extends upward from the BOP  27  to a floating platform. 
     In some embodiments, hanger sensors  32 ,  34 ,  36 ,  38 ,  40 , and  42  are positioned on the hangers  18 ,  30 , and  31 . Specifically, hanger sensors  32 ,  42  may be positioned on tubing hanger  18 ; hanger sensors  34 ,  40  may be positioned on casing hanger  31 ; and hanger sensors  36 ,  38  may be positioned on casing hanger  30 . Corresponding well head sensors  44 ,  46 ,  48 ,  50 ,  52 , and  54  are positioned on the high pressure well head housing  28 . The hanger and well head sensors are situated so that when casing hanger  30  is fully seated (i.e., the seal has been lowered relative to the hanger by the running tool and energized) in the high pressure wellhead housing  28 , hanger sensors  36 ,  38  are adjacent well head sensors  48 ,  50 . Similarly, when casing hanger  31  is fully seated in the high pressure wellhead housing  28 , hanger sensors  34 ,  40  are adjacent wellhead sensors  46 ,  52 , and when tubing hanger  18  is fully seated in the high pressure housing  28 , hanger sensors  32 ,  42  are adjacent well head sensors  44 ,  54 . In some embodiments, the sensors may be battery powered. 
     Still referring to  FIG. 1 , there is depicted a receiver  56  for receiving signals from the hanger and well head sensors. The receiver  56  can be located, for example, on the module  24 , although it could alternately be disposed on any equipment or module in the stack. If needed, signal repeaters can be added to the system to retransmit signals from the sensors to the receiver  56 , thereby assisting in the transmission of the signals between the sensors and the receiver  56 . For example, in the embodiment of  FIG. 1 , there is shown a module stem repeater  58 , a tool stem repeater  60 , and a tool body repeater  62 . In addition, there are shown micro repeaters  64 ,  66 , and  68  on the wellhead. The signals can be transmitted from the sensors to the receiver  56  in any appropriate way, such as, for example, via wires from the repeater at the running tool  20  to the receiver  56 , or wirelessly. In embodiments where the sensors communicate with the receiver  56  wirelessly, the communication may be conducted via acoustic waves or pulses. 
     In practice, as the well head assembly  10  is assembled, the low pressure wellhead housing  25  and high pressure well head housing  28  are secured in position over the well  14  using known methods. Thereafter, the running tool  20  is used to insert the hangers  31 ,  30 ,  18  into the high pressure wellhead housing  28 . An annular seal  69  may typically be included between portions of the hangers  31 ,  30 ,  18  and the high pressure well head housing  28 . The annular seal  69  can typically be run with the corresponding hanger and the running tool  20 , but in an upper position to enable cement returns to flow upward past the hanger. Thereafter, the running tool  20  lowers and energizes the seal  69 . Each hanger can have raised ridges, or wickers  70  on an outer surface thereof. One purpose of the wickers  70  is to engage the annular seal to help create a seal between the hanger  31 ,  30 ,  18  and the high pressure well head housing  28 . In order to create a proper seal, however, it is necessary that the hangers  31 ,  30 ,  18  be axially aligned in the appropriate position relative to the high pressure well head housing  28 . This axial alignment is one function of the hanger and well head sensors. Normally, rotational orientation or alignment is not needed for casing hangers or concentric type tubing hangers. 
     For example, as casing hanger  31  arrives at its designated position in the high pressure well head housing  28 , the hanger sensors  36 ,  38  align with the corresponding well head sensors  48 ,  50 . For hangers where rotational orientation is not carried out, the sensors  36 ,  38  can be spaced around the circumference of the hanger. As the sensors align, they transmit a signal (e.g., an electromagnetic, acoustic, RFID, or other appropriate type of signal) indicating that appropriate alignment has been achieved. The signal is then received by the receiver  56 , and the operator is alerted that the casing hanger  31  is in the proper position. The range of the hanger sensors  36 ,  38  and well head sensors  48 ,  50  can be calibrated to any desired sensitivity. For example, in some applications, where it may be desired that the wicker interface length with the annular seal be a predetermined minimum length (e.g., 1 inch), the hanger sensors  36 ,  38  and well head sensors  48 ,  50  can be positioned and calibrated so that the signal (indicating that the hanger is fully set) is not transmitted by the sensors until the desired wicker interface length is achieved. The same process applies to the setting of hangers  18  and  30 . 
     In alternative embodiments, any number of sensors may be used on the hanger and the well head housing according to the needs of a particular assembly. In addition, the sensors may be configured in any way along the length of the hanger and the well head housing, or around the circumference thereof. The particular configuration of  FIG. 1  is shown by way of example only. In addition, the sensors can be any type of sensor, including, for example, radio frequency identification (RFID) sensors or proximity sensors, such as Hall effect magnetic sensors. 
     Further shown in  FIG. 1  is a controller  67  that communicates with the receiver  56  via a communication means  78 . The controller can be located subsea near the wellhead, and can communicate with an operator on the surface in any appropriate way, such as, for example, via an umbilical, wirelessly, such as by acoustic pulse, by displaying information for collection by a remotely operated vehicle, etc. In one embodiment, an output of controller  67  is available to personnel operating the running tool assembly  16 , and communication means  78  can be wireless, conductive elements, fiber optics, acoustic, or combinations thereof. In an example of landing tubing hanger  18  within wellhead assembly  10 , communication between hanger sensors  32 ,  42  and well head sensors  44 ,  54  is monitored at controller  67 , and transmitted from receiver  56  to controller  67  by communication means  78 . The position of the tubing hanger  18  can be estimated based on signals received from the sensors  32 ,  42 ,  44 ,  54 . If no signal is received by receiver  56 , this may indicate that tubing hanger  18  is at an incorrect position. Thereafter, the tubing hanger  18  can be repositioned until appropriate signals are received. Although the above description principally describes the sensors as measuring the axial position of the hangers relative to the well head housing  28 , other parameters can also be measured, such as azimuthal position, and inclination of the hangers. 
     Repositioning of the hangers  18 ,  30 ,  31  can be performed before cementing by manipulating the running tool assembly  16 . Moreover, the step of repositioning can be done based on signals received by the receiver  56 , and transmitted to the controller  67 . In addition, repositioning can be done iteratively until a signal is received indicating that the casing hanger  30 ,  31  is positioned as desired. 
     The embodiment of the present invention shown in  FIG. 1  is advantageous over known systems because it helps to ensure that the seal between the hangers and well head housing is sound, and to prevent seal leakage. It accomplishes this by helping to ensure that the components are appropriately aligned when the seal is energized. 
     Referring now to  FIGS. 2 and 3 , there is depicted an alternate embodiment of the present invention, including a transducer  72  (e.g., and acoustic transmitter) installed in a port  74  that extends through a sidewall of the BOP  27 , and a plurality of transceivers  76  formed in a transceiver array. The transceivers  76  can be attached to the running tool  20  in any appropriate configuration. The transducer  72  can send a pulse P, such as an electromagnetic or acoustic pulse, generally inwardly toward the axis A of the running tool  20 , which pulse P expands as it moves away from the transducer  72 . As the pulse P travels away from the transducer  72 , it is received by the transceivers  76 , which in turn measure parameters of the pulse, such as the time of flight of the pulse P between the transducer  72  and each transceiver  76 , and/or the strength of the pulse P. The transceivers  76  can be battery powered. Alternatively, the transceivers  76  can be of a type that do not require power, such as surface acoustic wave (SAW) chips, that instead reflect the pulse P back to the transducer  72 . 
     As particularly shown in  FIG. 2 , as the pulse P travels, it expands parallel to a plane defined by the X and Y axes. Based upon the strength, direction, and/or time of flight of the pulse P at or to a particular transceiver  76 , the position of the transceiver  76  relative to the transducer  72  along the X-Y plane can be determined. Simultaneously, as particularly shown in  FIG. 3 , the pulse P expands upward and downward relative to a datum plane D, which is positioned at a height in the BOP even with the transducer  72 , and which is substantially perpendicular to the axis A of the running tool  20 . Based upon the strength, direction, and/or time of flight of the pulse P at a particular transceiver  76 , the height H of the transceiver  76  relative to the transducer  72  can be determined as well. 
     Once the above data about the strength, direction, and/or time of flight of the pulse P is collected by the transceivers  76 , the information can be sent to a controller or processor  80 , which uses known triangulation techniques to determine the position of each transceiver  76  relative to the transducer  72 . The processor  80  can be located subsea near the wellhead, and can communicate with an operator on the surface in any appropriate way, such as, for example, via an umbilical, wirelessly, such as by acoustic pulse, by displaying information for collection by a remotely operated vehicle, etc. Transmission of the data can be achieved by any appropriate transmission means  82 , including, for example, wires (not shown) or wireless transmission via radio waves or other means. Thus, using known triangulation techniques, the generation of pulses P from the transducer  72  and subsequent measurement of the strength, direction, and/or time of flight of those pulses P by the transceivers can generate the necessary data to determine the position and orientation of the running tool  20  relative to the BOP  27 . The processor can also convey information to the operator about the position of the running tool  20 . This can be accomplished, for example, by providing the information on a display screen (not shown). 
     Although the transducer  72  is shown in  FIGS. 2 and 3  to be attached to the BOP  27 , in practice the transducer  72  could be attached to any part of the system, such as, for example, a drilling connector, well head housing, or tree body. Similarly, the transceivers could be attached to any equipment lowered into a well, such as, for example, a drill string, or a hanger. In addition, the position of the transducer  72  and transceivers  76  could be reversed, so that the transducer  72  is attached to the running tool  20  or other equipment lowered into the well, and the transceivers  76  are attached to stationary parts of the system, such as the BOP or the well head housing. 
     The embodiment of the present invention shown in  FIGS. 2 and 3  provides certain advantages over other known systems. For example, the ability to accurately determine the position of the running tool  20  or other equipment reduces the number of trips needed to place components in the well. Using the transducers and transceivers described herein, downhole equipment can more easily be located and installed in a single trip as the operator gets real time feedback. Furthermore, installation of the downhole equipment is more accurate, which leads to long term reliability of the equipment. 
     The present invention described herein, therefore, is well adapted to carry out the objects and attain the ends and advantages mentioned, as well as others inherent therein. While a presently preferred embodiment of the invention has been given for purposes of disclosure, numerous changes exist in the details of procedures for accomplishing the desired results. Previously known devices are limited to indicating the downhole arrival of the well tool. These devices however are unable to calculate the orientation, alignment, or axial inclination of components in the wellhead assembly, which are features of embodiments herein, and which enables a more precise installation of such components. These and other similar modifications will readily suggest themselves to those skilled in the art, and are intended to be encompassed within the spirit of the present invention disclosed herein and the scope of the appended claims.