阅读说明：本技术 用于防喷器的传感器系统及其使用方法 (Sensor system for blowout preventer and method of using the same ) 是由 尤里·阿列克谢耶维奇·普罗特尼科夫 陈成波 史蒂文·克洛普曼 伊马德·安达拉维斯·安达拉维斯 于 2017-12-04 设计创作，主要内容包括：一种用于海底油气井的传感器系统包括壳体、发射线圈、接收线圈和处理器。所述壳体限定了钻井管柱从中输送穿过的内部空间。所述发射线圈联接到所述壳体并且被配置为传导电流脉冲并在所述内部空间内感应出电磁场。所述电磁场与所述电流脉冲相对应并且与所述钻井管柱相互作用。所述接收线圈联接到所述壳体并且被配置为检测所述电磁场,包括由于所述钻井管柱与所述电磁场相互作用而引起的所述电磁场的扰动。所述处理器联接到所述发射线圈和所述接收线圈。所述处理器被配置为基于所述电流脉冲和由所述接收线圈检测到的所述电磁场来计算所述钻井管柱的直径。(A sensor system for a subsea hydrocarbon well includes a housing, a transmit coil, a receive coil, and a processor. The housing defines an interior space through which a drill string is conveyed. The transmit coil is coupled to the housing and configured to conduct a current pulse and induce an electromagnetic field within the interior space. The electromagnetic field corresponds to the current pulse and interacts with the drill string. The receive coil is coupled to the housing and configured to detect the electromagnetic field, including perturbations of the electromagnetic field due to interaction of the drill string with the electromagnetic field. The processor is coupled to the transmit coil and the receive coil. The processor is configured to calculate a diameter of the drill string based on the current pulse and the electromagnetic field detected by the receive coil.)

1. A sensor system for a subsea hydrocarbon well, the sensor system comprising:

a housing defining an interior space through which a drill string is conveyed;

a transmitter coil coupled to the housing, the transmitter coil configured to conduct a current pulse and induce an electromagnetic field within the interior space corresponding to the current pulse, and the drill string interacting with the electromagnetic field;

a first receive coil coupled to the housing, the first receive coil configured to detect the electromagnetic field, including perturbations of the electromagnetic field due to interaction of the drill string with the electromagnetic field; and

a processor coupled to the transmit coil and the first receive coil, the processor configured to calculate a diameter of the drill string based on the current pulse and the electromagnetic field detected by the first receive coil.

2. The sensor system of claim 1, wherein the first receive coil is separated from the transmit coil by a separation distance in an axial direction of the housing.

3. The sensor system of claim 1, further comprising a second receive coil coupled to the processor, the second receive coil configured to detect the electromagnetic field, including perturbations of the electromagnetic field due to interaction of the drill string with the electromagnetic field, the processor further configured to calculate the diameter of the drill string proximate the second receive coil based on the electromagnetic field detected by the first receive coil and the second receive coil.

4. The sensor system of claim 1, wherein the processor is further configured to track the diameter of the drill string proximate the first receive coil over a period of time.

5. The sensor system of claim 4, wherein the processor is further configured to detect a presence of a tubular joint of the drill string within the interior space based on a change in the diameter of the drill string over the period of time.

6. The sensor system of claim 5, further comprising an array of solid state sensors coupled to the housing, the array of solid state sensors configured to track an axial position of the drill string within the interior space to detect lateral translation.

7. The sensor system of claim 6, wherein the processor is further configured to enhance detection of the presence of the pipe joint based on the lateral translation of the drill string detected by the array of solid state sensors.

8. The sensor system of claim 7, wherein the processor is further configured to generate a digital profile of the drill string based on the diameter tracked over the period of time.

9. The sensor system of claim 4, wherein the processor is further configured to detect the presence of a drill collar on the drill string within the interior space based on a change in the diameter of the drill string over the period of time.

10. The sensor system of claim 1, wherein the housing comprises a wall, and wherein the first receive coil and the transmit coil are disposed within the wall.

11. The sensor system of claim 10, wherein the wall comprises a ferromagnetic metal.

12. The sensor system of claim 1, wherein the housing comprises a wall having an outer surface, and wherein the first receive coil and the transmit coil are disposed on the outer surface of the wall.

13. A subsea blowout preventer, comprising:

a cylindrical housing defining an interior space through which a drilling string is conveyed;

a communication interface configured to communicatively couple to a drilling platform through a communication channel; and

a sensor system, the sensor system comprising:

a transmitter coil coupled to the cylindrical housing, the transmitter coil configured to periodically generate an electromagnetic field within the interior space and the drill string interacts with the electromagnetic field;

a first receive coil coupled to the cylindrical housing, the first receive coil configured to detect the electromagnetic field, including perturbations of the electromagnetic field due to interaction of the drill string with the electromagnetic field; and

a processor coupled to the communication interface, the transmitter coil, and the first receiver coil, the processor configured to track a diameter of the drill string based on the electromagnetic field detected by the first receiver coil, and transmit data representing the diameter onto the communication channel through the communication interface.

14. The subsea blowout preventer of claim 13, further comprising a pulse generator coupled to the transmit coil, the pulse generator configured to periodically generate current pulses corresponding to the electromagnetic field.

15. The subsea blowout preventer of claim 13, further comprising a Low Pass Filter (LPF) coupled between the first receive coil and the processor, the LPF configured to reduce noise of an analog signal induced in the first receive coil by the electromagnetic field.

16. The subsea blowout preventer of claim 14, further comprising an analog-to-digital converter coupled between the LPF and the processor, the analog-to-digital converter configured to convert an analog signal from the LPF into a digital voltage signal utilized at the processor.

17. A method of operating a sensor system at a subsea hydrocarbon well, the method comprising:

generating a current pulse;

conducting the current pulse through a transmitting coil to induce an electromagnetic field within an interior space of a housing of the sensor system;

detecting the electromagnetic field at a first receiver coil, including perturbations of the electromagnetic field due to interaction of a drill string with the electromagnetic field as it is conveyed through the housing; and

calculating a diameter of the drill string based on the electromagnetic field detected by the first receive coil.

18. The method of claim 17, further comprising tracking the diameter of the drill string over time.

19. The method of claim 18, further comprising detecting the presence of a tubular joint of the drill string based on the diameter tracked over time.

20. The method of claim 19, further comprising applying a curve fit to the detected electromagnetic field tracked by the first receive coil over time to improve detection of the diameter of the pipe joint.

21. The method of claim 17, further comprising transmitting data representative of the diameter from the subsea well to a drilling platform.

22. The method of claim 17, further comprising tracking an axial position of the drill string within the housing.

Background

The field of the present disclosure relates generally to blowout preventers, and more particularly, to sensor systems for determining the position of pipe joints within blowout preventers.

Subsea oil and gas production typically involves drilling and operating wells to locate and recover hydrocarbons. The drilling rig is located at a relatively deep water well site. Tools such as, for example, but not limited to, drilling tools, tubing, and drill pipe, are employed in these wells to explore underwater reservoirs. It is important to prevent fluid spillage and leakage from the well to the environment. Drilling operators typically try best to prevent spills or leaks, however, the penetration of high pressure reservoirs and formations during drilling can result in sudden increases in pressure or "kicks" in the wellbore itself. Greater pressure activation may cause the drill pipe casing, drilling mud, and hydrocarbons to be ejected from the wellbore, resulting in well failure.

Blowout preventers are commonly used in the drilling and completion of oil and gas wells to protect drilling and operating personnel, as well as the well site and its equipment from blowouts. Typically, blowout preventers are remotely controlled valves or sets of valves that can close a wellbore in the event of an unexpected rise in well pressure. Some known blowout preventers include several valves arranged in groups around the drill string. The valves within a given set typically differ from each other in their manner of operation and pressure rating, thus providing varying degrees of well control. For example, many known blowout preventers include a blind shear ram type valve configured to sever and crimp drill pipe if the other valves in the set are unable to control the well pressure, thereby serving as a final emergency protection against the blowout.

During a blowout, when the valves of the blowout preventer are activated, it is expected that the shear rams will sever the drilling string to prevent the blowout from affecting upstream drilling equipment. The shear rams are positioned such that when the valves of the blowout preventer are actuated, the drilling string is severed from more than one side. The shear rams may fail to sever the drill string for various reasons including, but not limited to, lateral movement of the drill string inside the blowout preventer, and the presence of pipe joints near the shear rams. Accordingly, it is desirable to know the position of the pipe joints relative to the shear rams of the blowout preventer, and to know the nature of the movement of the drill string during operation.

Disclosure of Invention

In one aspect, a sensor system for a subsea hydrocarbon well is provided. The sensor system includes a housing, a transmitting coil, a first receiving coil, and a processor. The housing defines an interior space through which a drill string is conveyed. A transmitter coil is coupled to the housing and configured to conduct the current pulse and induce an electromagnetic field within the interior space. The electromagnetic field corresponds to the current pulse and interacts with the drill string. A first receive coil is coupled to the housing and is configured to detect the electromagnetic field and a disturbance of the electromagnetic field due to interaction of the drill string therewith. The processor is coupled to the transmit coil and the first receive coil. The processor is configured to calculate a diameter of the drill string based on the current pulses and the electromagnetic field detected by the first receive coil.

In another aspect, a subsea blowout preventer is provided. A subsea blowout preventer includes a cylindrical housing, a communication interface, and a sensor system. The cylindrical housing defines an interior space through which a drill string is conveyed. The communication interface is configured to communicatively couple to a drilling platform through a communication channel. The sensor system includes a transmitting coil, a first receiving coil, and a processor. The transmitter coil is coupled to the cylindrical housing. The transmitter coil is configured to periodically generate an electromagnetic field within the interior space and the drill string interacts with the electromagnetic field. The first receive coil is coupled to the cylindrical housing. The first receive coil is configured to detect an electromagnetic field, including perturbations of the electromagnetic field due to interaction of the drill string with the electromagnetic field. The processor is coupled to the communication interface, the transmit coil, and the first receive coil. The processor is configured to track a diameter of the drill string based on the electromagnetic field detected by the first receive coil and transmit data representing the diameter onto a communication channel through the communication interface.

In yet another aspect, a method of operating a sensor system at a subsea well is provided. The method includes generating a current pulse. The method includes conducting a current pulse through a transmitting coil to induce an electromagnetic field within an interior space of a sensor system housing. The method includes detecting an electromagnetic field at a first receiver coil, including perturbations of the electromagnetic field due to interaction of the drill string with the electromagnetic field as it is conveyed through the housing. The method includes calculating a diameter of the drill string based on the electromagnetic field detected by the first receive coil.

Drawings

These and other features, aspects, and advantages of the present disclosure will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein:

FIG. 1 is a schematic side view of an exemplary subsea hydrocarbon well including a blowout preventer;

FIG. 2 is a schematic side view of an exemplary sensor system for use in the subsea well shown in FIG. 1;

FIG. 3 is a schematic side view of an exemplary arrangement of the sensor coil shown in FIG. 2;

FIG. 4 is a schematic side view of an alternative arrangement of the sensor coil shown in FIG. 2;

FIG. 5 is a schematic side view of another alternative arrangement of the sensor coil shown in FIG. 2;

FIG. 6 is a schematic view of the sensor system shown in FIG. 2;

FIG. 7 is a graph of voltage and current over time for the sensor system shown in FIGS. 2 and 6;

FIG. 8 is a schematic cross-sectional view of an alternative embodiment of the sensor system shown in FIGS. 2 and 6; and is

Fig. 9 is a flow chart of an exemplary method of operating the sensor system shown in fig. 2 and 6.

Unless otherwise specified, the drawings provided herein are intended to illustrate features of embodiments of the present disclosure. These features are believed to be applicable to a variety of systems that include one or more embodiments of the present disclosure. Accordingly, the drawings are not meant to include all of the conventional features known to those of ordinary skill in the art for practicing the embodiments disclosed herein.

Detailed Description

In the following specification and claims, reference will be made to a number of terms which shall be defined to have the following meanings.

The singular forms "a", "an" and "the" include plural references unless the context clearly dictates otherwise.

"optional" or "optionally" means that the subsequently described event or circumstance may or may not occur, and that the description includes instances where the event occurs and instances where it does not.

Approximating language, as used herein throughout the specification and claims, may be applied to modify any quantitative representation that could permissibly vary without resulting in a change in the basic function to which it is related. Accordingly, a value modified by a term or terms, such as "about", "approximately" and "substantially", are not to be limited to the precise value specified. In at least some cases, the approximating language may correspond to the precision of an instrument for measuring the value. Here and throughout the specification and claims, range limitations may be combined and/or interchanged, such ranges are identified and include all the sub-ranges contained therein unless context or language indicates otherwise.

Some embodiments involve the use of one or more electronic or computing devices. Such devices typically include a processor, processing device, or controller, such as a general purpose Central Processing Unit (CPU), a Graphics Processing Unit (GPU), a microcontroller, a Reduced Instruction Set Computer (RISC) processor, an Application Specific Integrated Circuit (ASIC), a Programmable Logic Circuit (PLC), a Field Programmable Gate Array (FPGA), a Digital Signal Processing (DSP) device, and/or any other circuit or processing device capable of performing the functions described herein. The methods described herein may be encoded as executable instructions embodied in a computer-readable medium (including, but not limited to, a storage device and/or a memory device). Such instructions, when executed by a processing device, cause the processing device to perform at least a portion of the methods described herein. The above examples are exemplary only, and thus are not intended to limit in any way the definition and/or meaning of the terms processor, processing device, and controller.

In the embodiments described herein, memory may include, but is not limited to, computer-readable media such as Random Access Memory (RAM) and computer-readable non-volatile media such as flash memory. Alternatively, a floppy disk, a compact disc-read only memory (CD-ROM), a magneto-optical disk (MOD), and/or a Digital Versatile Disc (DVD) may also be used. Also, in the embodiments described herein, additional input channels may be, but are not limited to, computer peripherals associated with an operator interface, such as a mouse and a keyboard. Alternatively, other computer peripherals may be used, which may include, for example, but are not limited to, a scanner. Further, in the exemplary embodiment, additional output channels may include, but are not limited to, an operator interface monitor.

Embodiments of the present disclosure relate to subsea blowout preventers, and more particularly, to a sensor system for detecting and tracking pipe joints of subsea hydrocarbon wells. The sensor system described herein may be implemented within a blowout preventer stack, lower riser assembly, or independently positioned above the blowout preventer stack and lower riser assembly. The sensor systems described herein provide a sensor coil comprising a transmit coil and at least one receive coil embedded within a housing of the sensor system. A transmitter coil driven by the current pulses generates an electromagnetic field within the interior space of the housing that interacts with the drill string as it is conveyed through the housing, thereby generating a disturbance of the electromagnetic field. The electromagnetic field (including disturbances due to interaction of the drill string with the electromagnetic field) is detected by the receiver coil and processed to determine the diameter of the drill string proximate the receiver coil. The diameter of the drill string is tracked over time. The time varying nature of the diameter of the drill string enables the presence of a coupling of the drill string within the housing to be detected by the sensor system. Detecting the position of the tubular joints enables the blowout preventer to operate more efficiently in the event of elevated pressures in the well, as shear-type blowout preventers may fail when sheared by the tubular joints. Knowing the position of the tubular joint enables an operator to move the drill string up or down to move the shear rams away from the tubular joint. The sensor systems described herein also provide position tracking and digital profile construction of the drill string as it is conveyed through a housing in which the sensor system is embedded.

Fig. 1 is a schematic side view of an exemplary subsea well 100. The hydrocarbon well 100 includes a platform 102 connected to a wellhead 106 on the seabed 108 via a riser or drill string 104. In alternative embodiments, the platform 102 may be replaced by any other suitable vessel at the surface.

As shown in the cross-sectional view, the drill string 104 includes an end at which a drill bit (not shown) is rotated to extend a subsea well through a formation below the seabed 108. Mud is circulated from a mud tank (not shown) on the drilling platform 102 through the drill string 104 to the drill bit and back to the drilling platform 102 through the annulus 112 between the drill string and the protective sleeve 114 of the drill string 104. The mud maintains hydrostatic pressure to equalize the pressure of the fluid produced from the well and cool the drill bit, while also carrying the crushed or cut rock to the surface through the annulus 112. At the surface, the mud returning from the well is filtered to remove rocks and debris and recirculated.

During drilling, high pressure hydrocarbons or other well fluids may kick from the drilled formation into the drill string 104 and may occur unpredictably. Blowout preventer stack 116 is disposed at or near the seabed 108 for protecting wells and equipment that may be damaged in such situations. In alternative embodiments, blowout preventer stack 116 (sometimes referred to as a stack) may be located at different locations along drilling string 104, according to the requirements or specifications of certain offshore drilling rigs. Blowout preventer stack 116 includes a lower stack 118 attached to wellhead 106, and a lower riser assembly (LMRP)120 attached to the distal end of drill string 104. The lower set 118 and the LMRP120 are connected during drilling.

The lower stack 118 and LMRP include a plurality of blowout preventers 122 configured to be in an open state during normal operation. Blowout preventer 122 is configured to close to interrupt fluid flow through drilling string 104 when a pressure activation occurs. The hydrocarbon well 100 includes a wireline or hydraulic line 124 for transmitting control signals from the drilling platform 102 to a controller 126 located at the blowout preventer stack 116. In alternative embodiments, the controller 126 may be located remotely from the blowout preventer stack 116 and communicatively coupled via a wired or wireless network. Controller 126 controls blowout preventer 122 to be in an open state or a closed state based on signals from drilling platform 102 transmitted through cable or hydraulic line 124. The controller 126 also communicates information to the drilling platform 102 including, for example and without limitation, the current status, i.e., open or closed, of each blowout preventer 122.

Fig. 2 is a schematic side view of an exemplary sensor system 200 for use in subsea hydrocarbon wells 100 (shown in fig. 1). The sensor system 200 includes a cylindrical housing 202 defining an interior space 204 within which the drill string 104 is conveyed. In alternative embodiments, the sensor system 200 may utilize any other suitably shaped housing for interacting with the subsea well 100. For example, the cylindrical housing 202 may be replaced by a rectangular housing. Referring again to fig. 2, in certain embodiments, the cylindrical housing 202 is located within subsea equipment such as, for example, the blowout preventer stack 116 (shown in fig. 1). In alternative embodiments, the cylindrical housing 202 is located above the blowout preventer stack 116, within the LMRP120 (as shown in figure 1), or independent of the blowout preventer 122 (as shown in figure 1). In certain embodiments, the sensor system 200 is located at or near the drilling platform 102 and is used in conjunction with additional installation equipment for the sensor system 200 at the sea floor 108. In such embodiments, the sensor system 200 at the drilling platform 102 may be used to generate a digital profile for a given tubular joint when a tubular segment of the drilling string 104 is engaged at the surface. The digital profile enables the sensor system 200 at the sea floor 108 to more accurately detect the presence of the pipe joint as it passes through the cylindrical housing 202 at the sea floor 108.

In certain embodiments, the cylindrical housing 202 has an adjustable length that is selected according to the length of the drill string 104 to be monitored. In certain embodiments, the cylindrical housing 202 has the same or greater length as the blowout preventer stack 116. In certain embodiments, the cylindrical housing 202 is made of a flexible material (such as, for example, an elastomeric material, a rubber fabric, or other suitable flexible material). In an alternative embodiment, the cylindrical housing 202 is made of a rigid material that is placed along the outer surface of the drill string 104 or along the inner surface of the blowout preventer stack 116.

The drilling string 104 includes an upper tubular segment 206 and a lower tubular segment 208 coupled together at a tubular joint 210. Notably, the pipe joint 210 has a larger diameter than the respective diameters of the upper and lower pipe sections 206, 208. The drill string 104 translates vertically in the axial direction of the cylindrical housing 202. The drill string 104 also translates or oscillates laterally in an orthogonal direction relative to the axial direction of the cylindrical housing 202 while the drill string rotates. Generally, the lateral translation of the drill string 104 and the presence of the pipe joint 210 within the interior space 204 affect the proximity of the drill string 104 to the walls of the cylindrical housing 202.

The sensor system 200 includes a sensor coil including a transmit coil 212 coupled to the cylindrical housing 202. In one embodiment, the transmit coil 212 comprises a circumferential conductive coil. The transmit coil 212 conducts current pulses that induce corresponding electromagnetic fields that interact (e.g., electromagnetically couple) with the drill string 104. The current pulses are for example, but not limited to, a pair of periodic and square waves of opposite polarity. In one embodiment, the current pulses deliver approximately 0.5 watts of continuous power to the transmit coil 212 at approximately a 10% duty cycle. In such embodiments, the current pulse itself delivers approximately 5 watts over its duration. In certain embodiments, the power available at the subsea location is limited. For example, existing blowout preventers may have a continuous excess power of less than 10 watts. Thus, in such embodiments, the efficiency of inducing an electromagnetic field within the interior space 204 is an important design consideration.

The sensor system 200 includes a first receive coil 214 coupled to the cylindrical housing 202. In one embodiment, the first receive coil 214 comprises a circumferential conductive coil. The first receive coil 214 is configured to detect an electromagnetic field representative of a corresponding electromagnetic field induced by the current pulse, as well as perturbations of the electromagnetic field due to interaction of the electromagnetic field with the drill string 104. In certain embodiments, the sensor system 200 includes a second receive coil 216 coupled to the cylindrical housing 202. The second receive coil 216 comprises a circumferential conductive coil. The second receive coil 216 is also configured to detect electromagnetic fields (including perturbations).

Fig. 3-5 are schematic side views of exemplary arrangements of sensor coils within sensor system 200 (shown in fig. 2). The arrangements shown in fig. 3-5 exhibit different properties, particularly with respect to the amount of current required to be conducted through the transmitter coil 212 to induce a detectable electromagnetic field within the interior space 204, and with which the drill string 104 may interact. For example, in certain embodiments, where the transmit coil 212, the first receive coil 214, and the second receive coil 216 are located outside the cylindrical housing 202, the induced electromagnetic field must penetrate the cylindrical housing 202 itself before radiating within the interior space 204.

Fig. 3 shows the transmit coil 212, the first receive coil 214, and the second receive coil 216 embedded within an insert 302, which itself is embedded within a void in the inner surface 304 of the cylindrical housing 202. In certain embodiments, the insert 302 is constructed of the same or similar material as the cylindrical housing 202 (such as, for example, but not limited to, carbon steel). In an alternative embodiment, the insert 302 is constructed of another material such as, for example, but not limited to, titanium, stainless steel, or a plastic polymer.

Fig. 4 shows the transmit coil 212, the first receive coil 214, and the second receive coil 216 embedded within inserts 402 that are coupled to the outer surface 404 of the cylindrical housing 202. In certain embodiments, the insert 402 is constructed of the same or similar material as the cylindrical housing 202 (such as, for example, but not limited to, carbon steel). In an alternative embodiment, the insert 402 is constructed of another material, such as, for example, but not limited to, titanium, stainless steel, or a plastic polymer.

Fig. 5 shows the transmit coil 212, the first receive coil 214 and the second receive coil 216 embedded within the wall 502 of the cylindrical housing 202 itself. The cylindrical housing 202 may be constructed of, for example, but not limited to, carbon steel, ferromagnetic metals, and non-magnetic metals (such as, for example, aluminum, stainless steel, titanium, polymers), or any combination thereof.

Fig. 6 is a schematic diagram of a sensor system 200 (as shown in fig. 2). The sensor system 200 includes a transmit coil 212, a first receive coil 214, and a second receive coil 216 coupled to the cylindrical housing 202. The transmit coil 212 is electrically coupled to a pulse generator 602 configured to generate a current pulse conducted by the transmit coil 212. In certain embodiments, pulse generator 602 is a configurable device that enables adjustments to be made to, for example, but not limited to, output power, current amplitude, voltage amplitude, and duty cycle.

The sensor system 200 includes a processor 604. Processor 604 is coupled to an analog/digital (a/D) converter 606. The a/D converter 606 is a bi-directional device that converts analog signals to digital and digital signals to analog. In certain embodiments, processor 604 is configured to control pulse generator 602 through a/D converter 606. In such an embodiment, processor 604 transmits the digital control signal to a/D converter 606, where it is converted to an analog control signal and transmitted to pulse generator 602. In an alternative embodiment, processor 604 directly controls pulse generator 602 using a digital control signal.

The sensor system 200 includes a first Low Pass Filter (LPF)608 and a second LPF 610 coupled to the first receive coil 214 and the second receive coil 216, respectively. An electromagnetic field corresponding to the current pulse conducted through the transmitter coil 212 interacts with the drill string 104, which alters the electromagnetic field. The generated electromagnetic field includes perturbations of the electromagnetic field due to the interaction of the drill string 104 with the electromagnetic field. The electromagnetic field induces a first current in the first receiving coil 214 and a second current in the second receiving coil 216. The first current is representative of an outer dimension of the drill string 104 proximate the first receive coil 214. The second current is representative of an outer dimension of the drill string 104 proximate the second receive coil 216. Generally, as the pipe joint 210 passes through the cylindrical housing 202, the outer dimension of the drill string 104 increases, and the respective voltage magnitudes of the first and second currents induced in the first and second receiver coils 214, 216 increase. The LPFs 608 and 610 remove high frequency noise from the first and second current voltages before they are received at the a/D converter 606, converted to digital voltage signals, and transmitted to the processor 604.

The processor 604 is configured to calculate a diameter of the drill string 104 based on the current pulses and the digital voltage signals representing the electromagnetic field detected by the first receiver sensor coil 214 and the second receiver sensor coil 216. The signal is related to the diameter of the drill string 104. In one embodiment, the processor 604 is configured to calculate the parameter S according to equation 1 below, where S corresponds to a diameter of the drill string 104 based on one of the first and second voltage signals V from the first and second receive coils 214, 216, and t represents time.

As a number of pipe segments and pipe joints 210 of the drill string 104 are conveyed through the cylindrical housing 202, the diameter of the drill string 104 detected by the sensor system 200 changes over time. In addition, the pipe joint 210 conveys an electromagnetic field induced by the transmitting coil 212. Accordingly, the electromagnetic field detected by the first receiver coil 214 varies over time relative to the electromagnetic field detected by the second receiver coil 216 because the transmitter coil 212 and the first and second receiver coils 214, 216 are each spaced apart by a separation distance along the axial direction of the cylindrical housing 202. In certain embodiments, processor 604 calculates the diameter based on a mathematical combination (including, for example, but not limited to, an addition, a subtraction, a time shift, a scaling, or other suitable mathematical combination) of the electromagnetic fields detected by first receiver sensor coil 214 and second receiver sensor coil 216.

Processor 604 is configured to track parameter S over a period of time, thereby facilitating determination of the diameter of drilling string 104 and detection of the presence of tubular joint 210 within cylindrical housing 202. In alternative embodiments, determining the diameter of the drill string 104 enables the detection of the presence of various other downhole equipment, including, for example, but not limited to, drill collars, stabilizers, centralizers, measuring devices, drill bits, junk baskets, and steering tools. Given the separation of the first receive coil 214 and the second receive coil 216 in the axial direction, the detection of the presence of the pipe joint 210 by the first receive coil 214 may lead or lag in time the same detection by the second receive coil 216, depending on the direction of conveyance of the drill string 104, i.e., towards the surface or towards the seabed 108. For example, as the drill string 104 is conveyed toward the seabed 108, the presence of the pipe joint 210 will result in a temporary rise in the parameter S and the diameter of the drill string 104, which corresponds to the current pulse conducted through the transmit coil 212. This temporary rise will occur first in the voltage signal generated by the first receive coil 214 and later in the voltage signal of the second receive coil 216.

Fig. 7 is a graph 700 of voltage and current over time for the sensor system 200, illustrating a temporary rise in the parameter S corresponding to the pipe joint 210. Graph 700 includes a vertical axis 710 representing voltage and current magnitudes. Graph 700 includes a horizontal axis 720 representing time of operation of sensor system 200. Graph 700 shows a graph with0 to t₂Current pulse 730 of a duration. The time t is shown on the graph 700 for the purpose of integration described in equation 1₃Wherein t is₃-t₂＝t₂-t₁. The graph 700 also shows a voltage signal 740 representative of the drill string 104 interacting with the electromagnetic field induced by the current pulse 730 and detected by one of the first and second receiver coils 214, 216 in the absence of the pipe joint 210. The graph 700 also shows a voltage signal 750 representative of the drill string 104 interacting with the electromagnetic field in the presence of the pipe joint 210 and detected by one of the first and second receiver coils 214, 216.

Referring again to fig. 6, in certain embodiments, processor 604 is configured to apply a phase shift to the integration described in equation 1 to further reduce noise. In certain embodiments, the pulse generator 602 is configured to generate a pair of current pulses having opposite polarities to reduce the effects of magnetic noise and residual magnetization of the drill string 104. In certain embodiments, the processor 604 is configured to apply a curve fit to the calculated parameters S of the drill string 104 to the cylindrical housing 202 to enhance detection of the pipe joint 210. In an alternative embodiment, the differential signal is calculated as the difference between the parameters S of the first receive coil 214 and the second receive coil 216, which is used to cancel the effects of variations in the electromagnetic properties of the metal comprising the drill string 104.

The processor 604 is embedded in the sensor system 200 at the sea floor 108. Processor 604 is coupled to a communication interface that communicatively couples processor 604 to drilling platform 102 through a communication channel 612 that enables data to be communicated from processor 604 to drilling platform 102. In certain embodiments, the communication channel 612 includes, for example, but is not limited to, a power line channel, an ethernet channel, a serial channel, a fiber optic channel, or any other communication device suitable for carrying data from the sea floor 108 to the drilling platform 102. The communication interface includes, for example but not limited to, a processor, driver, microcontroller, or other processing circuitry for converting data from processor 604 onto communication channel 612. In one embodiment, the processor 604 is configured to calculate the parameter S as an integer, such as a 16-bit integer, and transmit the integer over the communication channel 612. In some embodiments, such transmission occurs periodically (e.g., approximately every 200 milliseconds). In other embodiments, the frequency at which the transmission is made and the data representative of the calculated parameters may be varied to meet the specific requirements of the subsea well 100. In certain embodiments, communication channel 612 may be an existing data channel for subsea well 100 or more specifically for blowout preventer stack 116.

In alternative embodiments, processor 604 may be located at drilling platform 102. In such an embodiment, the subsea components of the sensor system 200 package the digital voltage signals into messages that are transmitted onto the communication channel 612 before the digital voltage signals are processed and the parameter S is calculated.

Fig. 8 is a schematic cross-sectional view of one embodiment of a sensor system 200 (shown in fig. 2 and 6). In the embodiment of fig. 8, sensor system 200 includes an array of solid state sensors 802, 804, 806, and 808 coupled to cylindrical housing 202. Sensors 802, 804, 806, and 808 track the position of the drill string 104 within the cylindrical housing 202. In such embodiments, processor 604 (as shown in fig. 6) is coupled to sensors 802, 804, 806, and 808 and is configured to enhance detection of pipe joint 210 using position tracking of drill string 104 by compensating for lateral movement of drill string 104 as voltage signals from first receive coil 214 and second receive coil 216 are processed to calculate and track changes in the diameter of drill string 104 to cylindrical housing 202 over time. For example, as the drill string 104 moves laterally toward the solid state sensor 804, the solid state sensor 804 detects that the drill string 104 moves closer, and the solid state sensor 808 detects that the drill string 104 moves correspondingly farther away. In some cases, such movement of the drill string 104 introduces noise into the currents induced by the electromagnetic field in the first and second receive coils 214, 216. The processor 604 mitigates noise by tracking the position of the drill string 104 and may cancel out at least a portion of the noise present in the voltage signals generated by the first and second receive coils 214, 216. In alternative embodiments, the sensor system 200 may include fewer solid state sensors, or in other embodiments, more solid state sensors may be included for tracking the position of the drill string 104.

Fig. 9 is a flow chart of an exemplary method 900 of operating sensor system 200 (shown in fig. 2 and 6). The method 900 begins at start step 910. At a generating step 920, a current pulse is generated at the pulse generator 602. The pulse generator 602 transmits a current pulse to the transmit coil 212, which conducts 930 the current pulse to induce an electromagnetic field within the interior space 204 of the housing 202 of the sensor system 200.

As subsea well 100 operates, drilling string 104 is conveyed through housing 202 of sensor system 200, which is located within blowout preventer stack 116, for example, but not limited to, at seabed 108, to interact with the electromagnetic field induced at conducting step 930. The drilling string 104 includes a pipe joint 210 that joins together an upper pipe section 206 and a lower pipe section 208, each of which interacts uniquely and temporally with the electromagnetic field. The first receive coil 214 detects 940 an electromagnetic field (including perturbations of the electromagnetic field due to interaction of the electromagnetic field with the drill string 104). During the detection 940, a current is induced in the first receive coil 214, which generates an analog voltage signal. The analog voltage signal is filtered by the LPF 608 and converted by the a/D converter 606 into a digital voltage signal that is received by the processor 604. The processor 604 calculates 950 a diameter of the drill string 104 based on the electromagnetic field detected by the first receive coil 214.

The above-described sensor system provides a sensor system for detecting and tracking pipe joints in a drilling string for subsea hydrocarbon wells. The sensor system described herein may be implemented within a blowout preventer stack, lower riser assembly, or independently positioned above the blowout preventer stack and lower riser assembly. The sensor systems described herein provide a transmit coil and a receive coil embedded within a housing of the sensor system. A transmitter coil driven by the current pulses generates an electromagnetic field within the interior space of the housing that interacts with the drill string as the drill string is conveyed through the housing. The electromagnetic field (including perturbations of the electromagnetic field due to its interaction with the drill string) is detected by the receiver coil and processed to determine the diameter of the drill string near the receiver coil based on the calculated parameter S. The diameter of the drill string is tracked over time. The time varying nature of the diameter of the drill string enables the presence of a coupling of the drill string within the housing to be detected by the sensor system. Detecting the presence of a tubular joint enables a blowout preventer to operate more efficiently in the event of elevated pressures in the well, as shear-type blowout preventers may perform poorly when sheared by the tubular joint. The sensor systems described herein also provide position tracking and digital profile building of pipe joints in a drill string as the drill string is conveyed through a housing in which the sensor system is embedded.

Exemplary technical effects of the methods, systems, and devices described herein include at least one of: (a) the reliability of pipe joint position sensing is improved; (b) reducing power consumption for pipe joint position sensing; (c) the service life of the pipe joint position sensing is prolonged; (d) the influence of the axial displacement of the drilling string on the position detection of the pipe joint is reduced; (e) improving the self-monitoring of the sensor system for health; (f) tracking an axial position of the drilling string; (g) improving operation of a shear-type blowout preventer by detecting a pipe joint; and (h) improve the reliability of the blowout preventer.

Exemplary embodiments of methods, systems, and apparatus for a sensor system are not limited to the specific embodiments described herein, but rather, components of systems and/or steps of the methods may be utilized independently and separately from other components and/or steps described herein. For example, the methods may also be used in conjunction with other non-conventional sensor systems and are not limited to practice with only the systems and methods described herein. Rather, the exemplary embodiment can be implemented and utilized in connection with many other applications, equipment, and systems that may benefit from increased reliability and availability, as well as reduced maintenance and costs.

Although specific features of various embodiments of the disclosure may be shown in some drawings and not in others, this is for convenience only. In accordance with the principles of the present disclosure, any feature of a drawing may be referenced and/or claimed in combination with any feature of any other drawing.

This written description uses examples to disclose the embodiments, including the best mode, and also to enable any person skilled in the art to practice the embodiments, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the disclosure is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they include structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims.