Abstract:
A wellhead assembly having a tubular magnetized in at least one selected location, and a sensor proximate the magnetized location that monitors a magnetic field from the magnetized location. The magnetic field changes in response to changes in mechanical stress of the magnetized location, so that signals from the sensor represent loads applied to the tubular. Analyzing the signals over time provides fatigue loading data useful for estimating structural integrity of the tubular and its fatigue life. Example tubulars include a low pressure housing, a high pressure housing, conductor pipes respectively coupled with the housings, a string of tubing, a string of casing, housing and tubing connections, housing and tubing seals, tubing hangers, tubing risers, and other underwater structural components that require fatigue monitoring, or can be monitored for fatigue.

Description:
BACKGROUND OF THE INVENTION 
     1. Field of Invention 
     The present disclosure relates in general to monitoring fatigue loading in a component of a wellhead system by sensing a magnetized portion of the component. The disclosure further relates to magnetizing the component in strategic locations and disposing sensors proximate the magnetized locations. 
     2. Description of Prior Art 
     Wellheads used in the production of hydrocarbons extracted from subterranean formations typically comprise a wellhead assembly attached at the upper end of a wellbore formed into a hydrocarbon producing formation. Wellhead assemblies usually provide support hangers for suspending strings of production tubing and casing into the wellbore. A string of casing usually lines the wellbore, thereby isolating the wellbore from the surrounding formation. The tubing typically lies concentric within the casing and provides a conduit therein for producing the hydrocarbons entrained within the formation. A production tree is usually provided atop a wellhead housing, and is commonly used to control and distribute the fluids produced from the wellbore and selectively provide fluid communication or access to the tubing, casing, and/or annuluses between strings of concentric tubing and casing. 
     Wellhead housings, especially those subsea, typically include an outer low pressure housing welded onto a conductor pipe, where the conductor pipe is installed to a first depth in the well, usually by driving or jetting the conductor pipe. A drill bit inserts through the installed conductor pipe for drilling the well deeper to a second depth so that a high pressure housing can land within the low pressure housing. The high pressure housing usually has a length of pipe welded onto its lower end that extends into the wellbore past a lower end of the conductor pipe. The well is then drilled to its ultimate depth and completed, where completion includes landing casing strings in the high pressure housing that lines the wellbore, cementing between the casing string and wellbore wall, and landing production tubing within the production casing. 
     Once in operation, forces externally applied to the wellhead assembly such as from drilling, completion, workover operations, waves, and sea currents, can generate bending moments on the high and low pressure housings. As the widths of the low and high pressure housings reduce proximate attachment to the conductor pipes, stresses can concentrate along this change of thickness. Over time, repeated bending moments and other applied forces can fatigue load components of the wellhead assembly. Thus the safety of using a wellhead after ten years of operation is sometimes questioned; which can lead to the expensive option of replacing the aged wellhead. Moreover, the inability to directly measure wellhead fatigue sometimes requires a higher class welding connection, which can be unnecessarily expensive. Monitoring fatigue in a wellhead assembly remains a challenge for the industry. Strain gages have been used for measuring strain in a wellhead assembly, but they often become detached when subjected to the harsh environment within a wellhead assembly. Excessive wires/cables were hard to handle for sensor communication under the subsea environment. Finite element models have been used for fatigue analysis, but most require a transfer function to extrapolate the measured load of riser which is connected to the wellhead. The lack of the real fatigue data from the field had contributed to the uncertainty of the finite element analysis result. 
     SUMMARY OF THE INVENTION 
     Disclosed herein is a method and apparatus for wellbore operations that includes a real time analysis of fatigue loading of components of a wellhead assembly. In one example a method of operating a wellbore includes sensing a magnetic field that intersects a portion of a tubular that is in the wellbore and that forms part of a wellhead assembly. Variations in the magnetic field are identified that are from loads applied to the tubular, and fatigue loading on the tubular is estimated based on the applied loads. The method can included magnetizing a selected portion of the tubular to form magnetic field. In this example, the magnetized portion of the tubular resembles an oval shape. Further, the oval shape can have an elongate side oriented in a direction that is parallel with an axis of the wellbore, oblique with an axis of the wellbore, or perpendicular with an axis of the wellbore. Optionally, the step of sensing includes providing a sensor in the magnetic field and monitoring an output of the sensor. The sensor can be part of a sensor system with a plurality of sensors connected by a sensing line, and wherein the sensors sense a change in the magnetic field. The sensing line can be made up of an optical fiber, electrical line, cable, or combinations thereof; and the sensors can be magneto-optic sensors, solid state magnetic sensors, inductive sensors, or combinations thereof. In an example, the change in the magnetic field is a change in the magnitude of the magnetic field. Also, an operating life of the tubular can be estimated based on the information gathered. The tubular can be a component of the wellhead assembly, such as a low pressure housing, a low pressure conductor pipe; a high pressure housing, a high pressure conductor pipe, a casing hanger, a tubing hanger, a length of casing, or a length of production tubing. 
     In a further embodiment, a method of wellbore operations includes sensing a characteristic of a magnetic field from a magnetized portion of a tubular that is in the wellbore and that forms part of a wellhead assembly, identifying changes in the characteristic of the magnetic field that are caused by a stress in the tubular, estimating real time fatigue damage to the tubular based on the identified changes in the characteristic of the magnetic field, and preparing a real time structural confirmation analysis of the tubular. A fatigue failure of the tubular can be estimated from the collected information, as well as a prediction of a residual life of the tubular. Moreover, a different wellhead assembly can be designed based on changes in the characteristic of the magnetic field that are caused by stresses experienced by the tubular over time. In one example, the magnetized portion of the tubular is strategically disposed proximate a change in thickness of the tubular, proximate a weld in the tubular, or both. 
     Further disclosed herein is a wellhead assembly that includes a tubular with magnetized locations strategically positioned thereon and that form magnetic fields, where the magnetic fields project outward from the tubular. A sensor system is included that is made up of sensors disposed in the magnetic fields and that generate signals in response to changes in the magnetic fields. An intelligent information processing system is included that is in communication with the sensor system; which can include a processor for correlating the changes in the magnetic fields to loads experienced by the tubular. 
    
    
     
       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. 1A  is a side perspective view of a wellhead tubular having selected portions that are magnetized, and a sensor system for measuring changes in a magnetized portion on an outer surface, and in accordance with the present invention. 
         FIG. 1B  is a sectional view of the wellhead tubular of  FIG. 1A  with the sensor system on an inner surface, and in accordance with the present invention. 
         FIG. 2  is a sectional view of a wellhead tubular having selected portions that are magnetized, and a sensor system for measuring changes in magnetized portion on an inner surface, and in accordance with the present invention. 
         FIG. 3  is a sectional view of a subsea wellhead with tubulars from  FIGS. 1 and 2  and in accordance with the present invention. 
     
    
    
     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. 
     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. 
     Shown in perspective view in  FIG. 1A  is an example of a tubular  10  that includes a housing portion  12  and a lower diameter conductor portion  14  depending from one end of the housing portion  12 . A transition  16  connects the housing and conductor portions  12 ,  14 ; and accounts for the changes in diameter of these respective portions with side walls that depend radially inward away from housing portion  12  and in a direction towards an axis A X  of tubular  10 . A series of magnetized areas  18  are shown formed at various locations on an outer surface of tubular  10 . In one example the magnetized areas  18  each have regions with different polarities so that a magnetic field M is generated proximate each areas  18 , which projects outward from the tubular  10 . A characteristic of the magnetic field M can change in response to stresses within the material of the tubular  10  that occurs in one of the magnetized areas  18 . These stresses may be induced by compression or tension in the tubular  10 . One characteristic that is altered is the magnitude of the magnetic field, which can be measured in units of Gauss or Tesla. 
     A sensor system  20  is shown mounted adjacent the tubular  10  that includes sensors  22  disposed proximate to the magnetized areas  18 . Embodiments exist wherein each magnetized area  18  includes a corresponding sensor  22 , but not shown herein for the sake of clarity. In the example of  FIG. 1 , sensor line  24  extends between adjacent sensors  22 , wherein line  24  may be arranged in the curved fashion as shown. In some examples, a designated amount of sensor line  24  is required to be provided between adjacent sensors  22  to ensure proper operation of sensors  22 . Example sensors  22  include magneto-optic sensors, solid state magnetic sensors, such as Hall effect sensors and inductive sensors. A further example of a sensor includes optical fibers that are locally coated with a magnetostrictive material. As will be described in more detail below, the sensors  22  are responsive to changes in the magnetic field M and will emit a corresponding signal communicated through sensor line  24  which can be analyzed real time, or stored and used for creating historical data. 
     As noted above, the magnetized areas  18  are strategically located on the tubular  10  in locations that may be of interest to assess applied loads onto the tubular  10 , which in one case may be adjacent a box/pin connection  25  shown formed on conductor portion  14 . As is known, conductor  14  can be formed from a string of individual segments S 1 , S 2  connected by box/pin connection  25 . Welds  28  are shown connecting the individual box and pin portions  26 ,  27  to adjacent conductor segments S 1 , S 2 ; magnetized areas  18  are shown provided adjacent welds  28 .  FIG. 1B  illustrates tubular  10  in a sectional view with magnetized areas  18  provided adjacent box/pin connection  25 , and sensors  22  disposed adjacent magnetized areas  18 . The example of sensor system  20  of  FIG. 1B  includes line  24  that connects to sensors  22  proximate box/pin connection  25 , line  24  also connects to sensors  22  disposed adjacent magnetized areas  18  between box/pin connection  25  and transition  16 . Line  24  exits from within tubular  10  through a passage  29  that is formed radially through housing portion  12 . 
     Referring now to  FIG. 2 , a sectional view is shown of a tubular  30  that includes a housing portion  31  coupled to a smaller diameter elongate conductor portion  32  by a transition  33  that projects radially inward to compensate for the differences in diameters of the housing  31  and conductor  32  portions. Tubular  30  also includes magnetized areas  18 ; the magnetized areas  18  of  FIG. 2  though are shown provided on an inner surface of tubular  30 . Also included in the embodiment of  FIG. 2  is a sensor system  20  with sensors  22  proximate some of the magnetized areas  18  and connected by a sensor line  24  for communicating sensed changes in magnetic field characteristic for analysis. While embodiments exist where sensors  22  are provided next to each magnetized area  18 , some sensors  22  are omitted in order to improve clarity of the figure. In one example, tubular  30  of  FIG. 2  is a low pressure housing, whereas tubular  10  of  FIG. 1  is a high pressure housing. Similar to tubular  10 , tubular  30  includes a box/pin connection  34  between segments SG 1 , SG 2 ; where box/pin connection  34  includes a box portion  35  threaded to a pin portion  36 . Welds  37  connect box portion  35  to segment SG 1  and connects pin portion  36  to SG 2 . Sensor system  20  of  FIG. 2 , similar to sensor system  20  of  FIG. 1B , includes sensors  22  proximate magnetized areas  18  along the box/pin connection  34  and on conductor portion  32  and spaced away from transition  33 . Line  24  connects to the sensors  22  and exits through a passage  38  formed radially through conductor portion  31 . 
       FIG. 3  provides in section view one example of a wellhead assembly  39  disposed on the sea floor  40 . In this example, wellhead assembly  39  includes a low pressure tubular  42  along its outer circumference which includes a low pressure housing  44  coupled to a conductor pipe  45 . Conductor pipe  45  extends downward from low pressure housing  44  and into a wellbore  46  that is formed through a formation  48  beneath sea floor  40 . A transition  49 , shown having a thickness reduction with distance from low pressure tubular  42 , connects low pressure housing  44  and conductor  45 . A weld  50  shown providing connection between conductor  45  and transition  49 . 
     Coaxially disposed within low pressure tubular  42  is a high pressure tubular  52  that includes a high pressure housing  54  shown set coaxially within low pressure housing  44 . Similar to the low pressure tubular  42 , a conductor  55  depends downward from high pressure housing  54  into wellbore  46 . A weld  50  connects an upper end of conductor  55  with a transition  56 , which couples to a lower end of high pressure housing  54 . Similar to transition  49 , high pressure transition  56  has a thickness that reduces with distance from high pressure housing  54 . Further in example of  FIG. 3 , magnetized areas  18  are shown provided at strategic locations on the tubulars  42 ,  52 . More specifically, magnetized areas  18  are formed on an inner surface of low pressure tubular  42 , which in one example provides some protection for the associated sensor systems  20  during installation of low pressure housing  42  within wellbore  46 . An outer surface of high pressure tubular  52  is shown having magnetized areas  18  and with sensor systems  20  set along those areas so that its sensors  22  can sense magnetic field changes that occur when stresses are applied to tubular  52 . 
     Further in the example of  FIG. 3 , a passage  58  is shown formed radially through the low pressure tubular  42 , in which sensor lines  24  from the sensor systems  20  are routed to outside of the wellhead assembly  39 . Thus signals from the sensor systems  20  can be transmitted to a location remote from the wellhead assembly  39  for monitoring and analysis. Optionally, a remotely operated vehicle (ROV)  60  may be provided subsea and used to manipulate the sensor lines  24  outside of wellhead assembly  39  and connect to a connector (not shown) to complete a communication link to above the sea surface. Optionally, a communication pod  62  is provided on an outer surface of wellhead assembly  39  and which may connect to sensor lines  24  for communication such as through a communication line  64  shown coupled to a side of communication pod  62 . 
     An information handling system (IHS)  66  is schematically illustrated in  FIG. 3  and coupled to a communication line  68  which is configured for receiving data signals from sensors  22 . The IHS  66  includes one or more of the following exemplary devices, a computer, a processor, a data storage device accessible by the processor, a controller, nonvolatile storage area accessible by the processor, software, firmware, or other logic for performing each of the steps described herein, and combinations thereof. The IHS  66  can be subsea, remote from the wellhead assembly  39  (either subsea or above the sea surface), a production rig, or a remote facility. Examples exist wherein IHS  66  is in real time constant communication with sensor systems  20 . Data signals from the sensors  22  can be transmitted to IHS  66  through line  24 , communication line  64 , or via telemetry generated from subsea. In an example, data signals received by IHS  66  are processed by HIS  66  to estimate fatigue in the magnetized material, and also in the material adjacent the magnetized areas  18 . Optionally, IHS  66  is used to estimate damage from fatigue in the structure being monitored with the sensors  22 . Moreover, in an example, a loading history of the monitored structure is generated by monitoring/collecting data signals from the sensors  22 , which is used to estimate fatigue damage in the monitored structure. 
     Still referring to  FIG. 3 , an inner circumference of high pressure tubular  52  defines a main bore  70 , which is generally coaxial with an axis A X  of wellhead assembly  39  and in which a casing hanger  72  may optionally be included with wellhead assembly  39 . Production casing  74  is shown depending into wellbore  46  from a lower end of casing hanger  72 . Optionally, a tubing hanger  76  may be landed within casing  74  and from which production tubing  78  projects into wellbore  46  and that is coaxial with casing  74 . Embodiments exist wherein magnetized areas  18  are provided onto selected locations within hangers  72 ,  76 , casing  74 , and/or tubing  78  for monitoring stresses and other loads applied to these elements. 
     In one example of operation, the magnetized areas  18  may be formed onto the wellhead members (i.e. tubulars  10 ,  30 ,  42 ,  52 , hangers  72 ,  76 , casing  74  and/or tubing  78 ) by applying a pulse of high current with electrodes (not shown) that are set onto the particular wellhead member. This example is sometimes referred to as electrical current pulse magnetization. Strategic placement of the electrodes can form shapes of the magnetized areas as desired. In the examples of  FIGS. 1 through 3 , the magnetized areas  18  are shown as oval shaped and having an elongate side oriented generally parallel within an axis of its associated tubular  10 ,  30 ,  42 ,  52 , or wellhead assembly  39 . However, embodiments exist wherein the elongate sides are generally oblique to these axes, or perpendicular to the axis and extending circumferentially around the associated tubular member. Other magnetization techniques may be employed, such as placement of permanent magnets within the wellhead member as well as formation of an electromagnet. In examples wherein magnetized areas are disposed proximate to a weld, the particular weld is performed prior to the step of magnetizing the tubular member to form these magnetized area. In an optional embodiment, magnetization occurs prior to mechanical assembly, such as the threaded connection of a box and pin connection  25  of  FIG. 1 . In an example, the magnetic field M ( FIG. 1 ) projecting from the magnetized areas  18  has characteristics that vary when stress is applied to the material of the magnetized area  18 . The stress can be as a result of tension or compression. 
     One example of calibrating a sensor system  20  ( FIGS. 1-3 ) includes applying a known stress to a member, such as a tubular, having a magnetized area and monitoring changes in the magnetic field associated with the magnetized area. This example of calibration can include taking into account the dimensions of the material, type of material, temperature of the member, and size of the magnetized area. Knowing the value or values of applied stress or stresses with an amount or amounts of measured change in magnetic field can yield data for correlating measurements of magnetic field changes from tubulars installed in a wellhead assembly to values of applied stress. Thus by installing a wellhead assembly having magnetized areas and sensor assemblies, real time loading data can be collected and ultimately used for creating a fatigue analysis of the tubulars within the wellhead assembly. Fatigue analysis can then be used for assessing the structural integrity of tubulars within the wellhead assembly as well as predicting when a fatigue failure may occur. As such, the useful life of an entire wellhead assembly  39  ( FIG. 3 ) can be estimated using the method and system described herein. Moreover, data obtained from one or more wellhead assemblies in a particular wellbore, can be used for designing a wellhead assembly that is to be installed and used in a different wellbore. Further, known methods are in place so that a single line can extend between multiple sensors, wherein the sensors are in series, and yet knowing the time delay of a signal after applying a pulse through the signal line, a particular sensor at a particular location can be identified from which the designated signal is obtained. 
     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. For example, the apparatus and method described herein can be used to monitor fatigue in a structure or material of any shape, that can be magnetized or have a portion that emits a magnetic field; and is not limited to material disposed in a wellbore or used in conjunction with wellbore operations. 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.