• 专利附录
  • 专利说明
  • 权利要求
  • 类似技术
  • 同族专利
  • 引用文献
  • 法律状态
  • 优先权
    • 专利摘要:
    SYSTEM AND METHOD FOR MONITORING POSITION USING ULTRASONIC SENSOR. The present invention relates to an ultrasonic position detection system. In one embodiment, the system includes an ultrasonic sensor (34) configured to monitor the position of a device (56). The system also includes positioning logic (36). The system is controlled by logic to direct an ultrasonic pulse (122) toward the device. The logic is configured to compute transit time and ultrasonic pulse velocity. Based on these parameters, the logic computes the path length between the sensor and the device, which corresponds to the location of the device in relation to the location of the sensor. In additional embodiments the ultrasonic positioning system can include multiple sensors in communication with the positioning logic to monitor multiple devices.
    公开号:BR112014026124A2
    申请号:R112014026124-5
    申请日:2013-04-23
    公开日:2021-05-04
    发明作者:Donald Scott Coonrod；Emanuel John Gottlieb；Donald Roy Augenstein
    申请人:Cameron Technologies Limited；
    IPC主号:
    专利说明:

    [001] [001] This section is intended to introduce the reader to various aspects of the technique that may be related to various aspects of the modalities described herein. This discussion is believed to be useful in providing the reader with fundamental information to facilitate a better understanding of the various aspects of the present modalities. Accordingly, it is to be understood that these statements are to be read in this light, and not as admissions of the prior art.
    [002] [002] In order to meet consumer and industrial demand for natural resources, companies often invest significant amounts of time and money to research and extract oil, natural gas and other underground resources from the earth. Specifically, once an underground resource is discovered, drilling and production systems are often employed to access and extract the resource. These systems can be located on-shore or offshore, depending on the location of a desired resource. Such systems generally include a wellhead assembly through which resources are extracted.
    [003] [003] In the case of an offshore system, such a wellhead assembly may include one or more subsea components that control drilling and/or extraction operations. For example, such components may include one or more production trees (often referred to as "Christmas trees"), control modules, an eruption preventative controller system, and various liners, valves, fluid conduits, and the like. , which generally facilitate the extraction of resources from a well for transport to the surface. Al-
    [004] [004] Position monitoring (also referred to as gap) with respect to such linear motion components has been a continuing challenge for the industry, specifically with respect to devices that are positioned in subsea environments. Without a proper position monitoring system, it is difficult for operators to assess the position of a linearly actuated component or how far the component has translated in response to an actuation event. Furthermore, due to the harsh environments in which subsea equipment is operated, the ability to monitor the condition of subsea equipment is also useful. Having a reliable position monitoring system in place can provide improved condition monitoring of subsea equipment. For example, position monitoring can be useful in determining whether or not a specific component exhibits expected behavior in response to an actuation control input. In the absence of reliable position information, condition monitoring metrics can rely more heavily on the relationship between time parameters and actuation parameters, which may be insufficient to accurately delineate a normalized condition status.
    [005] [005] Existing solutions for position monitoring included the use of electromechanical position detection devices in conjunction with linearly actuated components. An example of an electromechanical position sensing device is a linear variable differential transformer (LVDT). However, the use of electromechanical devices in position monitoring is not without disadvantages. For example, electromechanical devices such as LVDTs may be subject to a common mode failure as they are subject to a level of mechanical degradation similar to the component being monitored. In addition, the incorporation of electromechanical position sensing devices into existing subsea equipment may require that existing equipment be redesigned and modified to accommodate the electromechanical position sensing devices and associated components, which may not only is it costly and time-consuming, it is often impractical. summary
    [006] [006] Certain aspects of some of the modalities described here are presented below. It is to be understood that these aspects are presented merely to provide the reader with a brief summary of certain forms which the invention may take and that these aspects are not intended to limit the scope of the invention. Indeed, the invention may encompass a variety of aspects which may not be discussed below.
    [007] [007] The modalities of this description refer to general
    [008] [008] Several refinements of the characteristics noted above exist in relation to various aspects of the present modalities. Additional features can also be incorporated into these various aspects as well. These refinements and additional features can exist individually or in any combination. For example, various features discussed below in connection with one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present description alone or in any combination. Again, the brief summary presented above is intended only to familiarize the reader with certain aspects and contexts of some modalities, without limitation to the subject matter claimed.
    [009] [009] These and other features, aspects and advantages of certain embodiments will be better understood when the following detailed description is read with reference to the accompanying drawings, in which like characters represent equal parts throughout all drawings, in which:
    [0010] [0010] Figure 1 is a block diagram that presents a subsea resource extraction system, according to aspects of the present description;
    [0011] [0011] Figure 2 is a block diagram that presents a preventive eruption controller system that is part of the resource extraction system of Figure 1, in which the preventive eruption controller system incorporates the position detection system ultrasonic and has multiple eruption preventive controllers, each having at least one ultrasonic position detection device, according to aspects of the present description;
    [0012] [0012] Figure 3 is a more detailed partially cut-away perspective view of a piston-type eruption preventive controller that may form part of the eruption preventive controller system of Figure 2;
    [0013] [0013] Figure 4 is a cross-sectional view showing an actuator assembly of the piston-type eruption preventive controller of Figure 3 that has a piston in a retracted (open) position, in accordance with aspects of the present description;
    [0014] [0014] Figure 5 is a cross-sectional view showing an actuator assembly shown in Figure 4, but with the piston in an extended (closed) position;
    [0015] [0015] Figure 6 is a more detailed cross-sectional view showing an ultrasonic position sensing device installed in the actuator assembly of the piston type eruption preventive controller shown in Figures 3 to 5, and being configured to detect the position of the piston, in accordance with aspects of the present description;
    [0016] [0016] Figure 7 is a cross-sectional perspective view of the actuator assembly shown in Figures 4 and 5 and shows the ultrasonic position sensing device installed in the actuator assembly;
    [0017] [0017] Figure 8 is a flowchart showing a process for determining a path length that corresponds to the position of a moving component using an ultrasonic position sensing system, in accordance with aspects of the present description;
    [0018] [0018] Figure 9 is a cross-sectional view showing a portion of the plunger-type eruption preventive controller actuator assembly of Figures 4 and 5 that includes multiple ultrasonic position sensing devices, in accordance with aspects of the pre- feel description;
    [0019] [0019] Figures 10 to 12 collectively show a transducer assembly that can be used in an ultrasonic position sensing device, according to a modality;
    [0020] [0020] Figures 13 and 14 collectively show a transducer assembly that can be used in an ultrasonic position detection device, according to another modality;
    [0021] [0021] Figure 15 is a flowchart that presents a process by which the position monitoring techniques presented here are used to monitor the operation of a device and trigger an alarm condition if an abnormal device behavior is detected; and
    [0022] [0022] Figure 16 shows an example of a graphical user interface element that can be displayed to monitor the operation of a device for which position information is acquired using an ultrasonic position sensor, in accordance with aspects of the present description . Detailed Description of Specific Modalities
    [0023] [0023] One or more specific modalities of this description will be described below. In an effort to provide a concise description of these modalities, all actual features and implementations may not be described in the specification. It should be appreciated that in developing such an implementation, as in any engineering and design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related constraints. and business-related, which may vary from one implementation to another. Furthermore, it should be appreciated that such a development effort could be complex and time-consuming, but nonetheless be a routine design, fabrication, and manufacturing task for those skilled in the art having the benefit of this description.
    [0024] [0024] When introducing elements of various modalities, the articles "a", "an", "the" and "said" are intended to mean that there are one or more of the elements. The terms "comprising", "including" and "having" are intended to be inclusive and mean that there may be additional elements other than the elements listed. Furthermore, any use of "top", "bottom", "above", "below" and other directional terms and variations of these terms is made for convenience, but does not require any specific guidance of the components.
    [0025] [0025] Referring initially to Figure 1, an exemplary resource extraction system 10 is illustrated in accordance with an embodiment of the present invention. System 10 is configured to facilitate the extraction of a resource, such as oil or natural gas, from a well
    [0026] [0026] System 10 can be used in a variety of drilling or extraction applications. Furthermore, although system 10 is presented as an offshore or “submarine” system, it will be appreciated that onshore systems are also available. In the system 10 shown, surface rig 14 is mounted on a drilling rig located above the surface of the water, while pile rig 18 is coupled to wellhead 20 near the seabed. The surface equipment 14 and the stack equipment 18 may be coupled together by means of the riser equipment 16.
    [0027] [0027] As can be appreciated, surface equipment 14 can include a variety of devices and systems, such as pumps, power supplies, cable and hose reels, control units, a diverter, a rocker arm, a spider and the like. Similarly, the riser column equipment 16 may also include a variety of components, such as column gaskets and connectors, filling valves, control units and a pressure-temperature transducer, to name a few. The riser equipment 16 can facilitate the transport of extracted resources (e.g. oil and/or gas) to the surface equipment 14 of the pile equipment 18 and the well 12.
    [0028] [0028] The stack equipment 18 may include a number of components, including a blow-out preventive controller (BOP) system 22. The blow-up preventive controller system 22, which is sometimes referred to as the blow-out preventive controller stack can include multiple eruption preventative controllers arranged in a stack-like configuration along a portion.
    [0029] [0029] The blowout preventive controller system 22 generally works during the operation of the resource extraction system 10 to regulate and/or monitor the wellbore pressure to help control the volume of fluid that is being extracted from well 12 through wellhead 20. For example, if well pressures are detected as receiving a safe threshold level during drilling or resource extraction, which could indicate the likelihood of an eruption to occur, a or more blowout preventive controllers of system 22 can be actuated through hydraulic control inputs to seal wellhead 20, thus capping well 12. As an example, in the case of a piston type blowout preventive controller, each pair of opposite pistons can be actuated towards the center of a wellbore using respective
    [0030] [0030] The pistons used in breakout preventive controllers represent an example of a linearly actuated device or component. That is, such pistons can translate in a linear direction in response to a control input to actuate another component, such as a spool (in piston-type blow-out controllers) or a shutter unit (in controllers annular eruption preventers). As will be discussed in more detail below with reference to Figure 2, the eruption preventive controller system 22 of the presently presented embodiments includes a position sensing system that utilizes ultrasonic position sensing devices that enable the system to extract air. Features 10 Determine the linear position of a linearly actuated component or device being monitored. As used herein, the terms device and component can generally be used interchangeably when referring to an object that has its position monitored by the position detection system.
    [0031] [0031] One aspect of position monitoring may refer to a determination of the linear position (eg the position along a linear motion path) of a device of interest with respect to the position of the ultrasonic position sensor. For example, in the case of an eruption preventive controller, the position sensing system can use an ultrasonic positioning to determine the linear position of a piston within an eruption preventive controller. For example, in a piston-type eruption preventative controller, the position of the piston can indicate how far its corresponding piston has moved in response to actuation. Furthermore, it should be understood that position monitoring, as implemented by the position sensing system, may also be able to monitor the position of a stationary device or, to a certain degree, a device that moves in a non- linear (eg a circular path, a curved path, etc.).
    [0032] [0032] Other components of the equipment stack 18 of Figure 1 include a production tree 24, commonly referred to as a "Christmas tree", a subsea control module 26, and a subsea electronic module 28. The tree 24 may include a arrangement of valves, and other components that control the flow of a resource extracted from well 12 and upwards to the ascending column equipment 16 which, in turn, facilitates the transmission of the extracted resource upwards to the equipment of surface 14, as discussed above. In some embodiments, the arbor 24 may also provide additional functions, including flow control, chemical injection functionality, and pressure relief. As an example, only tree 24 can be a model of an underwater production tree manufactured by Cameron International Corporation of Houston, Texas.
    [0033] [0033] The subsea control module 26 can provide an electronic and/or hydraulic control of the various components of the stack equipment 18, including the eruption preventive controller system
    [0034] [0034] With these points in mind, Figure 2 is a block diagram showing an example of an eruption preventive controller system 22 that has multiple eruption preventive controllers 32, including an annular eruption preventive controller 32a and at least two piston-type burst preventive controllers 32b and 32c. Of course, other modalities may use less or more blowout preventative controllers 32. As discussed above, the piston type blowout preventive controllers can be adapted for different functions based on the type of piston blocks equipped . For example, a plunger-type blow-out controller may include tube plungers that are configured to close around a tube within a wellbore to restrict fluid flow within the annular conduit between the tube and the wellbore. well, but not within the pipe itself, shear plungers to cut through a drill string or casing, or blind plungers configured to seal a wellbore. The plungers can also include blind shear plungers that are configured to seal a wellbore even when occupied by a drill string or casing. Consequently, the piston-type burst preventative controllers 32b and 32c of Figure 2 can be any of the aforementioned piston-type burst-preventative controllers and may perform the same or different functions.
    [0035] [0035] Figure 2 further illustrates an ultrasonic position detection system, presented here by means of the ultrasonic position detection devices 34 and the positioning logic 36, which is shown as being contained within the electronic module. subsea tronic 28. As will be discussed below in more detail, an ultrasonic position sensing device 34 can be provided for each linearly actuated device in which position monitoring is desired. For example, with respect to each of the piston-type blowout preventive controllers 32b and 32c, at least two sensors 34 may be provided, each being configured to detect the linear position of a respective pair of opposing pistons. As generally shown in Figure 2, sensors 34 may be located on opposite ends of plunger type eruption preventative controllers 32b and 32c. The annular blowout preventive controller 32a, which may include a piston to drive a shutter unit, also includes a corresponding sensor 34 to monitor the linear position of the piston.
    [0036] [0036] Each position sensing device 34 includes an ultrasound transducer configured to convert an electrical signal received from positioning logic 36 into an acoustic signal in the form of an ultrasonic pulse. The pulse is then transmitted by the position sensing device towards a surface of the linearly actuated device. The reflection of the ultrasonic pulse off a surface of the linearly actuated device, which may be referred to as an echo, is then directed back to the position sensing device 34 and received by the transducer, converted back into a signal. electrical and transmitted back to the positioning logic 36. This path from the positioning logic 36 to the sensor 34 and to the linearly actuated device and back can be re-
    [0037] [0037] The positioning logic 36 is configured to determine various parameters, including the total transit time along the signal path, the ultrasound pulse speed and any delay time in the signal path between the logic. 36 and the linearly actuated device. As will be discussed below in more detail with respect to Figure 8, based on the above parameters, positioning logic 36 calculates the path length along which the ultrasonic pulse travels to determine the linear position of the device (for example, the piston of an eruption preventer controller) being monitored. That is, logic 36 determines the position of the linearly actuated device with respect to the position of the sensor 34 with which it is associated. Also, although certain modalities described here refer to the use of the position monitoring system to assess the linear position of a specific component, the position monitoring system can also be used to determine the position of a component that is stationary or moves in a non-linear mode with respect to sensor 34.
    [0038] [0038] As shown in Figure 2, communication cables 38 may include wiring that transfers the signals between the ultrasonic position sensors 34 and the positioning logic 36 in the subsea electronics module 28. The module 28 may be disposed within an accommodation that is able to withstand the underwater environment. In other embodiments, the positioning logic 36 may be positioned close to the linearly actuated device, such as on the housing of an eruption preventer controller that has a piston/plunger that is being monitored using a respective sensor 34 Furthermore, the positioning logic 36 may also be distributed, in some way, through the subsea electronics module 28 and onto the housing of a subsea component containing the linearly actuated device(s) of interest.
    [0039] [0039] Collectively, the subsea control module 26 and the electronics module 28 may include a communication circuit that provides communication with each other, with various subsea components in the stack equipment 18 and with the surface equipment. 14 and/or ascending column equipment 16. For example, an umbilical that contains one or more cables for transferring data can transmit data from stack equipment 18, subsea control module 16 and/or electronics module 28 to surface equipment 14 and/or to riser equipment 16. In one modality, such data can be transmitted according to a communication protocol, such as Modbus, CAN bus or any other communication protocol. suitable wired or wireless communication. Consequently, the position information acquired using the ultrasonic position sensing system can be transmitted to the surface equipment 14, thus allowing an operator to monitor the operation of various subsea devices monitored by the sensors 34 .
    [0040] [0040] Referring now to Figure 3, a partial cross-sectional perspective view of a plunger type eruption preventative controller 32 including an ultrasonic position sensor 34 is illustrated according to an embodiment. The piston-type burst preventative controller 32 includes a body 42, hood 44, actuator assemblies 46 and closure members 47 in the form of piston blocks. In the present embodiment, the plungers 47 are shown as tube plungers by way of example only. As discussed above, other embodiments of the eruption preventative controller 32 may include shear plungers, blind plungers (sometimes referred to as seal plungers) or blind shear plungers. The body 42 includes a wellbore 48, a plunger cavity 50, and upper and lower bolted connections 52 that can be used to mount additional components above and below the eruption preventive controller 32, such as when the eruption preventive controller 32 is disposed as a part of an eruption preventive controller stack assembly.
    [0041] [0041] Hoods 44 are coupled to body 42 by hood connectors 54. These connectors 54 may allow hoods 44 to be removed from body 42 of blowout controller 32 to provide access to pistons 47. Respective actuator assemblies 46 are mounted on hoods 44 at opposite ends of the body
    [0042] [0042] As additionally shown in Figure 3, the end of the cylinder 58 opposite the hood 44 is coupled to a head 60 by means of bolted connectors 62. In one embodiment, an ultrasonic position sensor 34 may be installed within the head 60 of each actuator assembly 46 to provide a linear position monitoring of the pistons 56 within their respective cylinders 58. For example, if the pistons 56 are actuated to actuate the pistons 47 to at least partially seal the wellbore 48, the using ultrasonic position sensors 34 in conjunction with positioning logic 36 can allow an operator to monitor the movement of pistons 56 and pistons 47 and determine if they are responding to the actuation event (eg, a hydraulic control input) in an expected mode.
    [0043] [0043] Figures 4 and 5 provide cross-sectional listings, which show one of the actuator assemblies 46 of Figure 3 in more detail. As shown, actuator assembly 46 is mounted to hood 44 and coupled to piston 47. In the illustrated embodiment, piston 47 is shown as a tube piston with the end farthest from piston 47 (i.e., closer to wellbore 48) which includes a plug 68 which forms a seal around a tube disposed within wellbore 48 when both arms 47 are extended from their respective piston cavities 50 into wellbore 48. As discussed above, other types of plungers 47 may include shear plungers and blind plungers.
    [0044] [0044] In addition to the cylinder 58 containing the piston 56, the actuator assembly 46 also includes a piston rod 70, the head 60, a slide sleeve 76 and a locking rod 78. The piston 56 includes a piston body main 80 and a flange 82. The body 80 and flange 82 portions of the piston 56 may include one or more seals, referred to by reference numerals 84 and 86, respectively. As shown in Figures 4 and 5, the body seal(s) 84 circumferentially encircles the piston body 80 while sealingly mating the inner wall of the cylinder 58. Similarly, the Flange seal(s) 86 circumferentially encircles piston flange 82 while sealingly engaging the inner wall of cylinder 58.
    [0045] [0045] The coupling of the body seal 84 and the flange seal 86 with the cylinder 58 divides the interior of the cylinder 58 into three hydraulically isolated chambers: an extension chamber 88, an inactive fluid chamber 94 and a chamber of retract 98. An extension port 90 provides hydraulic communication with the extension chamber 88, which is formed between the head 60 and the flange seal 86. Similarly, an inactive fluid port 96 provides hydraulic communication with the inactive fluid chamber 94, which is formed in an annular region defined by the cylinder 58 and the piston 56 between the body seal(s) 84 and the flange seal(s) 86. Additionally, a retraction port 100 provides fluid communication with retraction chamber 98 which is formed in an annular region defined by cylinder 58 and piston 56 between body seal(s) 84 and hood 44.
    [0046] [0046] In operation, the extension chamber 88 and the retraction chamber 98 may be in fluid communication with a hydraulic fluid supply (not shown in Figures 4 or 5) regulated by a control system. In some embodiments, hydraulic fluid expelled from the extension chamber 88 and the retraction chamber 98 can be recycled into the hydraulic fluid supply or can be vented to the surrounding environment. The inactive fluid chamber 94 can be pressure balanced with the surrounding environment such that the fluid pressure within the inactive chamber 94 does not exist to the movement of the piston 56 when actuated. In certain embodiments, the dead fluid chamber 94 can be left open to the surrounding environment (e.g., sea water) or it can be coupled to a pressure compensation system that maintains a balanced pressure with the dead fluid chamber 94 .
    [0047] [0047] Referring to Figure 4, the actuator assembly 46 is shown in a fully retracted position, in which the piston 56 is
    [0048] Consequently, as hydraulic fluid is supplied to the extension chamber 88, the piston 56 will continue to move in a linear direction towards the bonnet 44 until the piston 56 makes contact with the bonnet 44. This is shown in Figure 5, which illustrates the actuator assembly 46 in a fully extended position (sometimes referred to as the closed position). Although the actuator assembly 46 is actuated by hydraulic pressure, many applications may also include a mechanical lock in order to maintain the position of the piston 47, such as in situations where there is a loss of hydraulic pressure. In order to positively lock piston 56 and thus piston 47 in position, sliding sleeve 76 is rotationally fixed relative to piston 56 and threadedly coupled with a locking rod 78 which is rotatably coupled to head 60. The sleeve slide 76 moves axially with respect to locking rod 78 when locking rod 78 is rotated, thereby locking the position of piston 56 and piston 47.
    [0049] [0049] When the piston 56 is actuated from an initially retracted position, as shown in Figure 4, and begins to translate linearly away from the head 60 towards the bonnet 44, the distance 104 (Figure 6) between the head 60 and piston 56 continues to increase until piston 56 reaches the end of its stroke, as shown in Figure 5, ie body 80 of piston 56 has made contact with bonnet 44. The ultrasonic position sensor 34 may be provided on head 60 of actuator assembly 46 to allow monitoring of the position of piston 56. Sensor 34 may be configured to transmit an ultrasonic pulse and receive a corresponding echo due to reflection of that pulse off a surface. of piston 56. As will be described in more detail below, the time that elapses between transmitting the pulse and receiving the corresponding echo can be used by the positioning logic to determine how far the pulse has traveled and thus determine the linear position of piston 56. In most cases, the device of interest may actually be a piston 47. However, as piston 47 is actuated by piston 56, knowing the linear position of piston 56, one may be able to deduce how far plunger 47 has moved.
    [0050] [0050] Referring now to Figure 6, a more detailed cross-sectional view is provided, which illustrates an ultrasonic position sensor 34, according to an embodiment. Specifically, sensor 34 is shown as being installed in head 60 of actuator assembly 46 shown in Figures 4 and 5 and configured to direct ultrasonic pulses toward piston 56.
    [0051] [0051] The sensor 34 can be secured within the recess using any suitable mechanism. For example, in one embodiment, both the recess 108 and the sensor housing 110 may be threaded and generally cylindrical in shape. Consequently, the sensor 34 can be installed in the head 60 simply by rotating the sensor housing 110 into the recess 108, thus allowing the respective threads to mate with one another. In other embodiments, sensor 34 can be secured within recess 108 using an adhesive, connectors, or any other suitable technique. In general, this provides for a relatively simple installation of the sensor 34 without requiring significant and/or complex redesign of existing subsea equipment.
    [0052] [0052] To monitor the linear position of piston 56 during operation, ultrasonic position sensor 34 can intermittently transmit an ultrasonic pulse 122. Pulse 122 can originate from transducer 112 and propagate through window 116 and into the chamber. -
    [0053] [0053] After propagating through window 116, pulse 122 then travels the distance 104 between head 60 and piston 56 through hydraulic fluid 120. When impacting piston 56, pulse 122 is reflected in the form of a corresponding echo 124. Transducer 112 receives echo 124 as it propagates back toward sensor 34 through hydraulic fluid 120 and window 116. Transducer 112 can operate at any suitable frequency, such as between approximately 200 kilohertz and 5, 0 megahertz. In one embodiment, transducer 112 is configured to operate at a frequency of approximately 1.6 megahertz. Further, although not expressly shown in Figure 6, sensor 34 may include a wire that can be routed through aperture 118, which may have a diameter or width that is less than that of recess 108. Referring briefly back to Figure 2, this wiring can represent the wiring 38 that provides the communication between the sensors 34 and the positioning logic 36.
    [0054] [0054] Although recess 108 is shown in Figure 6 as having a width (e.g., a diameter in the case of a circular recess) that is larger than that of opening 118, in one embodiment, recess 108 may be an opening extending through the entire end cap 60. That is, opening 118 and recess 108 can be the same width. In such an embodiment, the sensor housing 110 may be configured to extend through the end cap 60. Also, in such an embodiment, the wiring of the transducer module 112 and/or the RTD 114 may form a connector coupled to the housing 110, at that the connector is configured to electronically connect the wiring within the sensor 34 of the positioning logic 36. For example, such connector may be accessible from outside the cylinder 58 of the blow-out controller 32 and may be coupled to the positioning logic using one or more suitable cables. This mode also allows the ultrasound detection device 34 to be installed outside the eruption preventive controller 32 or any other component in which it is to be installed, which avoids the need for any disassembly of the end cap 60 of the eruption preventive controller body 32 during installation. For example, where recess 108 extends through the entire end cap 60 and includes threads that engage corresponding threads on sensor 34, sensor 34 can be installed from the outside by rotating sensor assembly 110 into recess 108 of the exterior of the end cap 60 until the threads securely engage each other.
    [0055] [0055] As will be discussed below in more detail with respect to Figure 8, the positioning logic 36 can obtain or otherwise determine several parameters, which are used to compute the path length along which the ultrasonic pulse 122 shifted before being reflected. This path length can correspond to distance 104, which can allow an operator to determine the linear position of a specific device, such as piston 56 in this example. The parameters obtained and/or determined by the positioning logic include a velocity of sound (VOS) computed through a fluid as a function of temperature and pressure, a delay time and a signal path transit time. For example, the temperature parameter (eg the temperature inside the extension chamber 88) can be measured using the temperature sensing device 114. The pressure parameter (eg the pressure inside the extension chamber). extension 88) may be provided by positioning logic 36 as an expected pressure value or, in other embodiments, it may be measured pressure information provided to positioning logic 36 by one or more pressure sensing devices.
    [0056] [0056] The delay time can represent non-fluid delays present in the signal path which, as discussed above, includes the entire path (both electrical and acoustic portions) between the positioning logic 36 and the monitored device. For example, the presence of window 116 and wiring 38 can introduce non-fluid delays. By subtracting the delay time from the total transit time and dividing the result by two, the fluid transit time of pulse 122 (or its corresponding echo 124) can be determined. Consequently, since the ultrasonic pulse velocity/echo through the hydraulic fluid 120 and the fluid transit time are known, the travel length between the head 60 and the piston 56 can be calculated by logic of positioning 36, thus providing the linear position of piston 56. By knowing the linear position of piston 56, system 10 can determine how far piston 47 has moved. In some embodiments, fluid 120 does not necessarily need to be a liquid. For example, fluid 120 can include a gas or a mixture of gases, such as air.
    [0057] [0057] In the present example, the ultrasonic position sensor 34 is used to monitor the linear position of a piston in an eruption preventive controller of a subsea resource extraction system 10. Consequently, the sensor 34 can be designed to be durable enough to withstand the harsh environmental conditions often associated with subsea operations. In one embodiment, the sensor housing 110, within which the sensor 34 is disposed, may be fabricated using titanium, stainless steel, or any other suitable type of metal, alloy, or superalloy, and may be capable of operating at pressures between approximately 96.6 kPa (14 pounds per square inch (PSI)) to 96,600 kPa (14,000 PSI). For example, window 116 of sensor housing 110 can support loads up to 96,600 kPa (14,000 PSI). Sensor 34 may also be capable of withstanding operating temperatures between 0 to 100 degrees Celsius.
    [0058] [0058] As shown in Figure 6, sensor 34 may be recessed within recess 38 by a distance shown by reference numeral 125. This distance 125 may be selected based, at least partially, on certain properties of window 116 , such as thickness and sound velocity characteristics, to compensate for a signal reverberation within the middle of the window 116. This reverberation is due to the resonant properties of the window 116. For example, when the ultrasonic pulse 122 is transmitted from the sensor 34 , a portion of signal 122 may reverberate within window 116 before dissipating. The amount of time it takes for the reverberation to dissipate can constitute what is sometimes referred to as a signal deadband. If an echo (eg 124) arrives at sensor 34 within this signal deadband, sensor 34 may be unable to acquire an accurate measurement due to interference from the reverberation of the signal going within window 116. This is generally more problematic. -
    [0059] [0059] Distance 125 can be selected as a function of window thickness and its resonance properties. For example, a plastic material such as ULTEM™ or PEEK may have resonant properties in which an ultrasonic signal reverberates within window 116 for approximately two round-trip cycles before dissipating. Thus, in this example, the goal in selecting distance 125 is that the earliest time at which an echo 124 reflected from piston 56 returns to the sensor is outside the signal deadband time, with the most extreme case being when piston 56 is in the open position. Furthermore, it should be noted that the plastic materials discussed above generally have lower resonant properties when compared to those of certain other materials, specifically metals such as steel. In comparison, in a sensor where the ultrasonic pulse 122 is transmitted through a metallic material such as steel, the ultrasonic signal can reverberate for approximately ten or more round-trip cycles within the steel before dissipating. This can result in a longer deadband, which may require a greater distance 125 compared to that of a sensor 34 that uses a lower resonant plastic material of similar thickness, such as ULTEM™.
    [0060] [0060] Figure 7 is a cross-sectional view in more detailed perspective, showing the actuator assembly 46 of a controller.
    [0061] [0061] Figure 7 also presents a handle 128 that can be coupled to rotate the locking rod 78 to lock an extended piston 56 in the extended position. For example, handle 128 may be coupled and operated by a remotely operated vehicle (ROV) or a manned underwater vehicle, such as a submarine. Furthermore, Figure 7 also shows an embodiment in which at least part of the positioning logic 36 is located over the eruption preventive controller housing rather than being centered with the subsea electronic module 28, as shown in Figure 2. Eng For example, the positioning logic 36 may be distributed across multiple components, with portions of the logic 36 being housed in a subsea envelope, referred to herein as a positioning unit 126, and affixed or otherwise secured to a component housing. , here the head 60 of an eruption preventive controller 32. In this arrangement, all positioning units 126 collectively make up the positioning logic 36, and each positioning unit 126 is configured to receive input parameters and compute the information of position for a linearly actuated device being monitored by a respective sensor 34.
    [0062] [0062] Thus, in Figure 7, the two positioning units 126 shown can correspond to sensors 34 that monitor piston movement within cylinders 58 and 58'. For example, the wiring extending through opening 118 can connect each sensor 34 to its respective positioning unit 126. In addition, each positioning unit 126 can be configured to communicate position information to the subsea control module. 26 and/or the subsea electronic module 28, which can then transfer the information to the surface. Furthermore, although the above-described embodiment shows the sensor 34 as being installed in the head 60, other embodiments may include a sensor 34 installed on the piston 56 itself. Thus, in such embodiments, the positioning logic 36 can determine the linear position of piston 56 relative to the location of head 60 or some other point or reference.
    [0063] [0063] Having generally described the operation of sensor 34 above, a process 130 by which positioning logic 36 can compute the linear position of a monitored device is now described in further detail with reference to Figure 8. Generally, the position - linear tion of a device of interest (eg a piston/plunger of an eruption preventive controller), can be deter- mined using the following equation: d = VOS × t fluid , (Eq. 1)
    [0064] [0064] where VOS represents the velocity of the ultrasonic pulse emitted by the sensor 34 through a given medium (such as a hydraulic fluid within the extension chamber 88) and tfluid represents the fluid transit time in one direction of the ultrasonic pulse ( or its corresponding reflection), which can be equivalent to the total transit time in one direction along the signal path with the non-fluid delays removed. These parameters are then used to determine the distance d through which the ultrasonic pulse moves from the sensor 34 to the device of interest, thus allowing to determine the linear position of the device in relation to the position of the sensor 34.
    [0065] [0065] As discussed above, VOS can be determined as a function of pressure and temperature. For example, in one modality, VOS can be computed according to the Wayne Wilson equation for the speed of sound in distilled water as a function of temperature and pressure, as published in the Journal of the Acoustic Society of America , Vol. 31, No. 8, 1959. This equation is provided below. 1 T    VOS = [ A0 A1 A2 A3 ] A4 × T 2   3 T  T 4  , (Eq. 2a)
    [0066] [0066] where T represents the temperature in Celsius and An represents the coefficients to compute the speed of sound, where the coefficients An are calculated as a function of pressure, as shown below:  a0 a1 a2 a3  b 1  0 b1 b2 b3   
    [0067] [0067] Here, P represents the pressure in bar and an, bn, cn, dn, and en all represent additional subcoefficients for computing the speed of sound. Thus, substituting Equation 2b into Equation 2a, the VOS can be computed as follows:   a0 a1 a2 a3   1    1      b0 b1 b2 b3    T    
    [0068] [0068] Equation 2c can be written in expanded form as: VOS = A0 + A1T + A2T 2 + A3T 3 + A4T 4 , (Eq. 2d)
    [0069] [0069] where: A0 = a0 + a1P + a2 P 2 + a3 P3 A1 = b0 + b1P + b2 P2 + b3 P3
    [0070] [0070] A2 = c0 + c1P + c2 P 2 + c3 P3
    [0071] [0071] A3 = d0 + d1P + d2 P2 + d3 P3
    [0072] [0072] A4 = e0 + e1P + e2 P 2 + e3P3
    [0073] [0073]
    [0074] [0074] When applied to determine the speed of sound through distilled water under a known pressure and temperature, the following coefficients can be used in Wilson's speed of sound equation (Equations 2a-2d above): A0 = 1402.859 + 1.050469e−2 P + 1.633786e−7 P 2 − 3.889257e−12 P3 A1 = 5.023859+ 6.138077e−5 P −1.080177e −8 P 2 + 2.477679e−13P3 A2 = −5.690577e−2 − 1.071154e− 6 P + 2.215786e−10 P2 − 5.088886e−15 P3 A3 = 2.884942e−4 + 1.582394e−8 P − 2.420956e −12 P 2 + 5.086237e−17 P3 A4 = −8.238863e −7 − 6.839540e− 11P + 9.711687e−15 P 2 − 1.845198e−19 P3
    [0075] [0075] The computed values for the An coefficients can then be substituted in Equation 2d above to obtain the speed of sound through distilled water at a pressure and temperature represented by P and T, respectively.
    [0076] [0076] As can be appreciated, the steps described above to determine VOS can correspond to steps 132 and 138 of process 130 shown in Figure 8. For example, in step 132, a temperature value (T) 134 and a value pressure (P) 136 are purchased. As discussed above, the temperature value can be obtained using the temperature sensing device 114 of the ultrasonic position sensor 34, while the pressure can be supplied to the positioning logic 36 as an expected or measured value (for example, measured by a pressure sensing device on the eruption preventative controller or other subsea equipment). In some embodiments, the temperature may also be provided to the positioning logic 36 as an expected value rather than being a measured value provided by the temperature sensing device 114. Once these parameters are determined in step 132, the logic of positioning 36 can compute the speed of sound 140 according to Wilson's equation in step 138.
    [0077] [0077] It should additionally be noted that the specific example of the numerical coefficients provided above corresponds to the properties of distilled water. Nevertheless, these coefficients can provide a relatively accurate speed of sound, calculated using hydraulic fluids that are largely water-based (eg 99% water-based hydraulic fluids). In addition, the above numerical coefficients can also be adjusted to account for any differences in the properties of distilled water and a water-based hydraulic fluid to further improve the accuracy of the velocity of sound calculation.
    [0078] [0078] The other parameters used by the positioning logic to determine the distance d of Equation 1 include the total transit time of the ultrasonic signal, including any non-fluid portions of the signal path (eg window 116, wiring 38 ), and a non-fluid delay time that corresponds to delays that non-fluid portions of the signal path contribute. Since the total transit time and non-fluid delay times are known, the fluid transit time in one direction (eg, that of the pulse or echo) is determined as follows: ttotal − τ t fluid = , (Eq. 3) 2
    [0079] [0079] where ttotal represents the total transit time of both electronic and acoustic signals along the signal path, i.e., positioning logic 36, along wiring 38 to transducer 112, through window 116, through a fluid medium (eg, hydraulic fluid 120) in one direction toward a device of interest, and back through each of these components after pulse reflection. Consequently, the non-fluid components in this signal path, which may include window 116 and wiring 38 introduce some amount of delay, represented above in Equation 3 as τ. Thus, the fluid transit time in one direction (eg, either the pulse from the sensor to the device of interest or the echo from the device back to the sensor) is determined by removing the non-fluid delay τ from the time. of transit total, ttotal, and dividing the result by two, where dividing by two gives a time value that corresponds to the fluid transit time in one direction (rather than a round-trip time).
    [0080] [0080] The total transit time, ttotal, can be determined through the pulse-echo path processing performed by the positioning logic 36. For example, the positioning logic 136 can determine the amount of time that elapses between sending a signal that causes the pulse and receiving a signal that results from the color echo.
    [0081] [0081] where L represents the length of the portion of the signal path through the non-fluid component and C represents the speed of the signal through the non-fluid component. The result is multiplied by two to account for the non-fluid delay in both the outward and return paths. As an example only, assuming that wire 38 has a length of approximately 6 meters and that the signal speed through wire 38 is approximately 1.4*108 meters/second, the non-fluid delay contributed by the wiring ( τwire) is approximately 0.0857 microseconds (µs). Similarly, assuming the window 116 of the sensor 34 has a thickness of approximately 15.74 millimeters and allows the ultrasonic pulse to pass through it at a velocity of approximately 2424 meters/second, the non-fluid delay contributed by the window 116 (τwindow) is of approximately 13.0724 µs.
    [0082] [0082] These non-fluid delay components (τwire and τwindow) are then summed to obtain the total non-fluid delay time τ, which is represented by step 146 of process 130 in Figure 8. For example, the characteristics of wire length and speed 148 and transducer window length and speed characteristics 150 are provided in step 146. Using the above expression presented in Equation 4, the positioning logic can compute the total non-fluid delay time (τ) 152 based on parameters 148 and 150.
    [0083] [0083] After which, step 154 of process 130 provides the computation of the path length 156 between the sensor 34 and the linearly actuated device using the calculated speed of sound (VOS) 140, the transit time of pulse - total echo 144 along the signal path, and the non-fluid delay time 152. Using Equation 3, the fluid transit time in one direction can be calculated as half the total transit time 144 minus the time of non-fluid delay 152. Consequently, once the fluid transit time is known, the run length 156 can be computed in accordance with Equation 1. When applied to the examples described above with reference to a preventative eruption controller , travel length 156 may represent linear position information relating to how far a piston, and thus its corresponding piston, has moved in response to an actuation input.
    [0084] [0084] The stroke length result 156 of Figure 8 generally generates a measure of how far the piston is from the window 116 of the sensor 34. As will be appreciated, for even further accuracy in some embodiments, the calculated stroke length 156 can be further reduced by the distance the sensor 34 is recessed into the head 60 (for example, distance 125 of Figure 6) to provide a measurement of the piston's distance with respect to the inner wall (e.g., forming part of extension chamber 88) of head 60.
    [0085] [0085] As noted above, in a modality where a hydraulic fluid used to actuate a device is not distilled water or substantially water-based, the coefficients used in Equations 2a-2d above can be adjusted, such as through empirical testing , to provide accurate sound velocity results when ultrasonic signals are transmitted through non-water fluids or those that are not substantially water-based. In another embodiment, rather than relying on Equations 2a-2d for calculating the speed of sound, a combination of multiple sensors 34 can be used to determine the position of a device of interest, with at least one sensor being targeted to the device of interest and another sensor being directed to a generally constant reference point. In such a modality, these sensors can be referred to as a measurement sensor and a reference sensor, respectively.
    [0086] [0086] An example of such an embodiment is shown in Figure 9. Specifically, Figure 9 shows an embodiment of the eruption preventive controller 32 of the above described piston type, in which a piston 56 is actuated using a hydraulic fluid other than water or substantially water-based, such as an oil-based hydraulic fluid. Here, to determine the position of piston 56, sensors 34a and 34b are provided within cylinder 58, with sensor 34a being a measurement sensor and sensor 34b being a reference sensor. Sensor 34a is oriented and configured, like sensor 34 shown in Figure 6, to measure distance 172 (d2) between head 60 and piston 56. Sensor 34b is identical to sensor 34a, but is oriented to measure the distance 170 (d1) between the inner wall of the cylinder 58 and the shaft 80 of the piston 56. As can be appreciated, the distance 170 is generally constant, except for periods when the piston 56 is in or near position. closed (eg when flange portion 82 of piston 56 enters the line of sight of sensor 34b). However, excluding such periods, the distance 170 measured by sensor 34 is a known distance d1. Consequently, the velocity of sound through the hydraulic fluid within the inactive fluid chamber 94 can be determined as follows: 2× d1 VOS = , (Eq. 5) t1_ fluid
    [0087] [0087] where VOS represents the speed of sound over the known distance d1 and t1_fluid represents the round trip fluid transit time of an ultrasonic signal from sensor 34b to axis 82 and back. As can be appreciated, the fluid transit time t1_fluid can be calculated in a manner similar to that described above, i.e. determining the total transit time and removing non-fluid delays (e.g., spinning delays, delays imposed by window ).
    [0088] [0088] When the calculated VOS sound velocity using Equation 5 above is known, the distance 172 can be calculated as follows: VOS × t2 _ fluid d2 = , (Eq. 6) 2
    [0089] [0089] Here, t2_fluid represents the round-trip fluid transit time of an ultrasonic pulse (and its corresponding echo) emitted by sensor 34a, which can again be calculated by measuring the total round-trip transit time along the signal path of sensor 34a and removing non-fluid delays (e.g., wiring delays, window imposed delays). Division by a factor of two results in a fluid transit time in one direction which, when multiplied by the known VOS value of Equation 5, provides the distance d2 corresponding to the travel length between the sensor 34b and the piston 56. As discussed above, any distance by which sensor 34b is recessed can be subtracted from the travel length (d2) to determine the distance of piston 56 from head 60 of cylinder 58.
    [0090] [0090] As can be appreciated, although the speed of sound through a fluid may vary as the pressure and/or temperature characteristics change, in a subsea application that uses the 32 piston type eruption preventive controller, the temperature and pressure characteristics are generally not expected to vary.
    [0091] [0091] As additionally shown in Figure 8, cylinder 58 may include sensor 34c positioned within inner wall 175 at the end of cylinder 58 opposite head 60, i.e., the end that flange 82 contacts when piston 56 is actuated to the closed position. This sensor 34c can be used in place of or in addition to sensor 34a to assess the position of piston 56. For example, the distance 174 (d3) between sensor 34c and flange 82 of piston 56 can be determined using the known distance 170 (d1). For example, similar to the calculation of d2 by Equation 6 above, the distance d3 can be calculated as follows: VOS × t3 _ fluid d3 = 2 , (Eq. 7)
    [0092] [0092] Thus, the distance d3 generally indicates how far the piston 56 is with respect to the sensor 34c on the inner wall 175. Furthermore, in this example, the distance of the piston with respect to the head 60 can also be calculated by adding a known width 176 of the piston flange 82 to the calculated distance d3, and subtracting the result from the length of cylinder 58, as measured from head 60 to inner wall 175. In addition, some embodiments may include both sensors 34a and 34c, wherein the results obtained using each respective sensor can provide a degree of redundancy (eg if one sensor fails) or can be compared against each other for validation purposes.
    [0093] [0093] The position calculation algorithms described above can be implemented using a suitably configured hardware and/or software in the form of coded computer instructions, stored on one or more media readable by tangible machines. In a software implementation, the software can furthermore provide a graphical user interface that can display the information for presentation to a human operator. For example, the position measurements acquired by the ultrasonic position sensing system can be displayed on a workstation monitor located on the surface of the resource extraction system 10 or at a remote location. The software may also be configured to save data logs to monitor device positions (for example, the position of plungers) over time. Furthermore, in the event that an accurate measurement cannot be obtained, the software can provide a visual and/or audible alarm to alert an operator. In some embodiments, a virtual (eg part of the software graphical user interface) or hardware-based (eg a workstation component) oscilloscope can be provided to display the ultrasonic waveform. which is transmitted and received. An example of such a user interface will be described below in more detail with respect to Figure 16. In an additional embodiment, a signal stacking can be used to some degree to improve the signal-to-noise ratio.
    [0094] [0094] As discussed above with reference to Figure 6, each ultrasonic position sensor 34 includes a transducer 112.
    [0095] [0095] The transducer 112 includes the window 116 described above, as well as a coating 180, a piezoelectric material 182, a positive conductor 184, a negative conductor 186. The transducer 112 also includes the resistance temperature detector (RTD) described above to acquire temperature data and can be a two-wire or four-wire RTD. As best shown in Figure 10, positive lead 184, negative lead 186, and RTD 114 extend outward from the rear end (e.g., end opposite window 116) of transducer 112. When mounted with a device such as like the head 60 of an eruption preventative controller 32, portions of the positive conductor 184, the negative conductor 186 and the RTD 114 may extend through the opening 118 (Figure 6). Liner 180 generally contains the components of transducer 112 and may be designed to mount within sensor housing 110, as shown in Figure 6. In one embodiment, liner 180 may be formed using the same high-strength plastic material. compressive strength than Window 116, such as ULTEM™, PEEK or Vespel™. In other embodiments, coating 180 can be formed using a metallic material, such as steel, titanium or their alloys. The piezoelectric material 182 can be formed using a crystal or a ceramic material. For example, in one embodiment, the piezoelectric material 182 may include lead zirconate titanate (PZT).
    [0096] [0096] Another embodiment of transducer 112 is illustrated in Figures 13 and 14. Specifically, Figures 13 and 14 show assembled and exploded perspective views, respectively, of transducer 112. Here, transducer 112 includes window 116 and RTD 114, as well as a coating 190, a piezoelectric material 192, a charge cylinder 194, a cap 196, positive 198 and negative conductors 200 and an epoxy casing 202. The coating 190, the charge cylinder 194 and the lid 196 can be formed using a highly compressible plastic or a metallic material such as steel. Piezoelectric material 192 may include PZT. Further, in this embodiment, window 116 can include a highly compressible plastic, such as ULTEM™, PEEK or Vespel™, or can be formed as a wear plate using aluminum oxide (alumina). In some embodiments, the window 116 may include an alumina wear plate interposed between a plastic window and the piezoelectric material 192. Due to the alumina's impedance, density, and velocity characteristics with respect to sound, such an embodiment can allow acoustic energy to be transmitted through an alumina wear plate and into a plastic window with reduced distortion, provided the dimensions and thickness of such wear plate are selected accordingly.
    [0097] [0097] Referring to Figure 15, a process 208 for operating a system that includes an ultrasonic positioning system (for example, system 36) for monitoring the position of certain devices is illustrated according to an embodiment. As shown, process 208 begins at step 210, where a system input is received. Input can represent a command to move a device within the system to a desired position. For example, in the context of a subsea system, the input may represent a command to close or open a plunger of an eruption preventative controller, where the closed or open position represents the desired position. The system can actuate (eg hydraulic actuation) the device in accordance with the input received to cause the device to move to the desired position.
    [0098] [0098] As the device (eg, plunger) moves towards the desired position, one or more associated ultrasonic sensors 34 can provide the position information to the system, as shown in step 212. The expectation is that the device being acted on will move to the desired position at the conclusion of the acting process. Decision logic 214 determines whether abnormal system behavior is detected. In this context, abnormal behavior can be any type of movement (or lack of movement) that deviates from expected behavior. For example, if the device being actuated is a plunger that fails to reach a closed position in response to a command to close the plunger, process 208 may trigger an alarm to indicate to the system that the plunger cannot close as indicated in step
    [0099] [0099] Consequently, an operator can assess the situation based on the alarm and, if necessary, temporarily shut down the system for maintenance or repair procedures. As will be appreciated, the positioning system modalities described here can operate on the basis of a closed-loop or open-loop control.
    [00100] [00100] Figure 16 shows an example of a graphical user interface (GUI) element 220 that can be part of the positioning system 36. This GUI element 220 can be displayed, for example, on a workstation located on the surface of resource extraction system 10 or at a remote location in communication with resource extraction system 10. GUI element 220 includes a window 222 that can display waveform 224 of a corresponding signal. to a given sensor 34. With respect to the device being monitored by sensor 34, window 226 displays various parameters including temperature (field 228), pressure (field 230), device position (field 232), as well as velocity. - device city when moving (field 234).
    [00101] [00101] GUI element 220 also includes indicators 236 and
    [00102] [00102] The ultrasonic position detection system and techniques described here can provide position information that is substantially as accurate as position information obtained using other existing solutions, such as position monitoring using LVDTs or other electromechanical position sensors. However, as discussed above, the ultrasonic position detection system integrates much more easily with existing subsea components and does not require a substantial and complex redesign of existing equipment. Also, as the ultrasonic position sensors 34 described here are generally not subject to common-mode failure mechanisms, as is the case with some electromechanical position sensors, the position information obtained by the detection system Ultrasonic position can better maintain its accuracy over time.
    [00103] [00103] Position information obtained using the presently described ultrasonic position detection techniques may also provide some degree of condition monitoring. For example, linearly actuated devices can have an expected operating wear profile, which describes how the devices are expected to behave as they gradually wear out over time. Having access to accurate position information obtained using the ultrasonic position sensors 34, an operator can monitor the condition of such linear motion devices over time. For example, if the distance traveled by a plunger of an eruption preventative controller that has been in operation for a given amount of time in response to a certain amount of actuation pressure falls within an expected range, it may be concluded that the eruption preventative controller is functioning normally according to its wear profile. However, a distance traveled in response to the same actuation pressure that is less than or greater than the expected range can signal that the eruption preventative controller may need maintenance or replacement.
    [00104] [00104] Although the examples described above have focused on using an ultrasonic position sensor to monitor the position of a plunger of an eruption preventer controller, it should be appreciated that the techniques described above can be generally applicable to any device or component of a system that moves, such as in response to an actuation. For example, in the context of the oil field industry, other types of components that have linearly actuated devices that can be monitored using the ultrasonic positioning techniques described here include blowout preventer gate valves, wellhead connectors , a lower marine ascending column package connector, blow-out preventer throttle and shut-off valves and connectors, subsea tree valves, manifold valves, process separation valves, process compression valves and valves of process control, to name a few. Furthermore, as discussed above, non-linearly moving components can also be monitored using the position sensing techniques described above.
    [00105] [00105] Although aspects of the present description may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein.
    But it should be understood that the invention is not intended to be limited to the specific forms described.
    Rather, the invention shall cover all equivalent and alternative modifications that fall within the spirit and scope of the invention, as defined by the following appended claims.
    权利要求:
    Claims (10)
    [1]
    1. System, characterized in that it comprises: a component (56) configured for movement; a sensor (34) comprising a transducer (112) for transmitting an ultrasonic signal (122) through a fluid medium (120) toward a surface of the component; and a positioning logic (36) configured to determine the velocity of the ultrasonic signal through the fluid, as a function of the fluid temperature and pressure, determine a propagation time of the ultrasonic signal from the sensor to the component surface, and determine the distance traveled. by the ultrasonic signal as it propagates from the sensor to the surface of the component based on velocity and propagation time, where the determined distance corresponds to the position of the component (56) relative to the position of the sensor.
    [2]
    2. System according to claim 1, characterized in that it comprises a temperature detection device (114) that provides the temperature for the positioning logic.
    [3]
    3. System according to claim 2, characterized in that the temperature detection device comprises a resistance temperature detector (RTD) incorporated in the transducer.
    [4]
    4. System according to claim 1, characterized in that the fluid pressure is provided for the positioning logic as an expected pressure value or a measured pressure value, provided by a pressure sensing device.
    [5]
    5. System according to claim 1, characterized in that the propagation time from the sensor to the component surface is determined based on a total transit time along a signal path between the positioning logic and the component surface subtracted by a delay time introduced into the signal path by non-fluid components.
    [6]
    6. System according to claim 5, characterized in that the non-fluid components comprise a wiring (38) that couples the sensor in the positioning logic and a sensor window (116) through which the ultrasonic signal is transmitted .
    [7]
    7. System according to claim 1, characterized in that the component is configured to move linearly, and in that the distance determined by the positioning logic corresponds to a linear position of the component in relation to the position of the sensor.
    [8]
    8. Method characterized in that it comprises: transmitting an ultrasonic signal (122) into a fluid medium (120) towards a device (56) using a transducer (112) of a sensor (34) disposed in a oil field component (40), wherein the ultrasonic signal is transmitted through a sensor window (116) into the fluid medium (120), and wherein the device is configured for movement within the oil field component. oil; determine the velocity of the ultrasonic signal through the fluid medium as a function of the temperature and pressure of the fluid medium; determine the transit time required for the ultrasonic signal to propagate from the sensor to the device; using speed and transit time to determine a path length (156) that the ultrasonic signal travels to reach the device; and using the determined path length to identify the location of the device in the oil field component relative to the location of the sensor.
    [9]
    9. Method according to claim 8, characterized in that determining the transit time comprises determining a first time required for the ultrasonic signal to propagate from the transducer to the device and reducing the first time by a second time that corresponds to a delay time introduced by the window through which the ultrasonic signal is transmitted.
    [10]
    10. Method according to claim 9, characterized in that the device is configured to move to a desired position within the oil field component in response to a control input, and wherein the method comprises indicating a condition alarm if the device fails to move to the desired position in response to the control input.
    类似技术:
    公开号 | 公开日 | 专利标题
    BR112014026124A2|2021-05-04|system and method for position monitoring using ultrasonic sensor
    US9163471B2|2015-10-20|Position monitoring system and method
    US20170030757A1|2017-02-02|Wireless measurement of the position of a piston in an accumulator
    US9804039B2|2017-10-31|System and method for position monitoring using ultrasonic sensor
    US7980305B2|2011-07-19|Ram BOP position sensor
    US9416649B2|2016-08-16|Method and system for determination of pipe location in blowout preventers
    US9033048B2|2015-05-19|Apparatuses and methods for determining wellbore influx condition using qualitative indications
    US8408074B2|2013-04-02|Riser annulus flow meter and method
    US10145236B2|2018-12-04|Methods and systems for monitoring a blowout preventor
    US10273774B2|2019-04-30|Assembly and method for monitoring position of blowout preventer rams
    US10240618B2|2019-03-26|Accumulator volume detector using an optical measurement
    AU2008216253B2|2013-10-31|Ram bop position sensor
    KR20150063752A|2015-06-10|Pressure Vessel and Test Apparatus for Drilling Equipment Using The Same
    WO2016010779A1|2016-01-21|Measurement system
    同族专利:
    公开号 | 公开日
    US20130283917A1|2013-10-31|
    WO2013163213A1|2013-10-31|
    SG11201405700WA|2014-11-27|
    NO20141133A1|2014-11-11|
    US9187974B2|2015-11-17|
    GB2515935A|2015-01-07|
    GB201417662D0|2014-11-19|
    GB2515935B|2015-12-16|
    引用文献:
    公开号 | 申请日 | 公开日 | 申请人 | 专利标题
    US2802196A|1954-08-24|1957-08-06|Francis J Fry|Variable frequency transducer|
    US3510698A|1967-04-17|1970-05-05|Dynamics Corp America|Electroacoustical transducer|
    US3952216A|1975-04-04|1976-04-20|The United States Of America As Represented By The Secretary Of The Navy|Multiple-frequency transducer|
    US4543649A|1983-10-17|1985-09-24|Teknar, Inc.|System for ultrasonically detecting the relative position of a moveable device|
    US4922423A|1987-12-10|1990-05-01|Koomey Paul C|Position and seal wear indicator for valves and blowout preventers|
    US5164548A|1988-02-08|1992-11-17|Chevron Research And Technology Company|Method and apparatus for ultrasonic scanning of a borehole having improved sensor array and timing circuit|
    US5025708A|1990-01-30|1991-06-25|Baroid Technology, Inc.|Actuator with automatic lock|
    GB2280918B|1993-08-02|1996-12-11|Hydril Co|Position instrumented blowout preventer|
    AT401785B|1994-03-02|1996-11-25|Wimmer Alois Ing|SAFETY DEVICE ON HYDRAULIC PISTON-CYLINDER UNITS|
    US5552222A|1995-01-27|1996-09-03|General Electric Company|Electrically conductive articles comprising insulation resistant to corona discharge-induced degradation|
    JPH10249768A|1997-03-12|1998-09-22|Tokai Rubber Ind Ltd|Force sensor|
    US6227040B1|1998-02-03|2001-05-08|Caldon, Inc.|Method and apparatus for determining the viscosity of a fluid in a container|
    JP2001349900A|1999-12-28|2001-12-21|Fujitsu Ltd|Acceleration sensor and acceleration sensor apparatus|
    DE10161915A1|2000-12-27|2002-08-29|Surpass Industry Co|Flow rate measuring method, ultrasonic flow rate meter, flow rate measuring method, temperature or pressure measuring method, ultrasonic thermometer and ultrasonic pressure sensor|
    US6478087B2|2001-03-01|2002-11-12|Cooper Cameron Corporation|Apparatus and method for sensing the profile and position of a well component in a well bore|
    JP4538163B2|2001-03-30|2010-09-08|サーパス工業株式会社|Flow rate measuring method, flow rate measuring device, flow rate measuring method, and flow rate measuring device|
    US6860327B2|2002-11-26|2005-03-01|Woodco Usa|Pressure containing assembly used to detect the location of anomalies within a blowout preventer stack|
    US7300033B1|2006-08-22|2007-11-27|Cameron International Corporation|Blowout preventer operator locking system|
    US7832706B2|2007-02-16|2010-11-16|Hydrill USA Manufacturing LLC|RAM BOP position sensor|
    US7954362B2|2007-07-27|2011-06-07|Multiphase Flow International Llc|Ultrasound multiphase fraction meter and method for determining phase fractions in a multiphase fluid|
    US7836780B2|2008-02-26|2010-11-23|Rosemount Inc.|Sensor tube with reduced coherent vortex shedding|
    US20090268553A1|2008-04-24|2009-10-29|Pepperl+Fuchs, Inc.|Ultrasonic sensor system and method for sensing distance|
    DE102008055116A1|2008-12-23|2010-07-01|Robert Bosch Gmbh|Method for producing an ultrasonic transducer|
    US8616062B2|2010-02-16|2013-12-31|Hitachi-Ge Nuclear Energy, Ltd.|Ultrasonic inspection system and ultrasonic inspection method|
    SG185569A1|2010-07-01|2012-12-28|Nat Oilwell Varco Lp|Blowout preventer monitoring system and method of using same|WO2013050051A1|2011-10-04|2013-04-11|Cameron International Corporation|Subsea retrievable pressure sensor|
    US9804039B2|2012-04-27|2017-10-31|Cameron International Corporation|System and method for position monitoring using ultrasonic sensor|
    GB2542300A|2014-07-14|2017-03-15|Cameron Int Corp|Measurement system|
    US9677573B2|2014-02-14|2017-06-13|Cameron International Corporation|Measurement system|
    US10046351B2|2014-07-14|2018-08-14|Graco Minnesota Inc.|Material dispense tracking and control|
    US10018009B2|2015-02-26|2018-07-10|Cameron International Corporation|Locking apparatus|
    US10830009B2|2015-05-06|2020-11-10|Schlumberger Technology Corporation|Continuous mud circulation during drilling operations|
    US9732879B2|2015-09-10|2017-08-15|Cameron International Corporation|Sensor assembly for monitoring a fluid extraction component|
    US9587461B1|2015-09-11|2017-03-07|Cameron International Corporation|Systems and methods for monitoring blowout preventer equipment|
    US10145236B2|2015-09-25|2018-12-04|Ensco International Incorporated|Methods and systems for monitoring a blowout preventor|
    US10428601B2|2015-12-07|2019-10-01|Schlumberger Technology Corporation|Proximity detection between tubulars for blind stabbing|
    US10408010B2|2015-12-08|2019-09-10|Schlumberger Technology Corporaton|Pipe ram assembly for many actuation cycles|
    US10508509B2|2015-12-08|2019-12-17|Schlumberger Technology Corporation|Devices for continuous mud-circulation drilling systems|
    CN106321068B|2016-09-05|2019-10-11|中海石油有限公司|A kind of tube and casing in downhole ground detection sensor driving means|
    US10208555B2|2016-09-27|2019-02-19|Cameron International Corporation|Blowout preventer monitoring systems and methods|
    US10975686B2|2017-04-20|2021-04-13|General Electric Company|Detection system including sensor and method of operating such|
    WO2019018317A1|2017-07-17|2019-01-24|Essential Products, Inc.|Distance-based door and window state detection|
    US10495740B2|2017-08-21|2019-12-03|Hamilton Sundstrand Corporation|Short range ultrasonic measurement|
    WO2019050810A1|2017-09-06|2019-03-14|Noble Drilling Services Inc.|Self actuating ram actuator for well pressure control device|
    US11197962B2|2018-02-26|2021-12-14|Verily Life Sciences Llc|Waveform reconstruction for ultrasound time of flight measurements|
    US10900347B2|2018-03-01|2021-01-26|Cameron International Corporation|BOP elastomer health monitoring|
    US10689953B2|2018-05-22|2020-06-23|Schlumberger Technology Corporation|Orientation measurements for rig equipment|
    CN109931107B|2019-03-14|2020-05-19|中国矿业大学|Interference protection device and method for hydraulic support and cutting part of coal mining machine|
    US11078937B2|2019-10-17|2021-08-03|Hamilton Sunstrand Corporation|Performance enhancement of controllers for varying temperature conditions in hydraulic actuators|
    CN111636844A|2020-06-18|2020-09-08|海塔石油科技有限公司|Pressure rotary pumping blowout preventer|
    CN112571207A|2020-12-07|2021-03-30|宜都市鹏信光电机械有限公司|Polisher with coolant liquid adds and reminds function|
    法律状态:
    2018-10-23| B25A| Requested transfer of rights approved|Owner name: CAMERON TECHNOLOGIES LIMITED (NL) |
    2018-12-04| B06F| Objections, documents and/or translations needed after an examination request according [chapter 6.6 patent gazette]|
    2020-02-11| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|
    优先权:
    申请号 | 申请日 | 专利标题
    US13/457,871|2012-04-27|
    US13/457,871|US9187974B2|2012-04-27|2012-04-27|System and method for position monitoring using ultrasonic sensor|
    PCT/US2013/037836|WO2013163213A1|2012-04-27|2013-04-23|System and method for position monitoring using ultrasonic sensor|
    [返回顶部]