Blowout preventer control system

Abstract

The invention discloses a blowout preventer control system, and relates to the field of blowout preventers, the blowout preventer control system comprises a remote console, the remote console comprises a pressure preparation assembly, a pressure storage assembly and a pressure direction control assembly, the pressure preparation assembly is used for providing oil, the pressure storage assembly is used for storing hydraulic energy, and the pressure direction control assembly is used for controlling the flowing direction of hydraulic oil; the output end of the pressure preparation assembly is connected with the output end of the pressure storage assembly, the output end of the pressure storage assembly is connected with the pressure direction control assembly, the blowout preventer set is connected with the pressure direction control assembly, and the pressure preparation assembly and the pressure direction control assembly are skid-mounted. The operation module comprises a driller station and emergency control boxes, the driller station is connected with the remote console, the emergency control boxes are connected with the remote console, a main control button and a blowout preventer closing button are arranged on each emergency control box, and the multiple emergency control boxes are distributed on the drilling platform.

Description

Technical Field

[0001] This invention relates to the field of blowout preventers, and particularly to a blowout preventer control system. Background Technology

[0002] In offshore oil and gas resource development, especially in deep-sea drilling operations, the safety control system of the drilling platform is a core component for ensuring operational safety. Among these, the hydraulic control technology for the diverter and blowout preventer directly affects wellhead pressure management, drilling fluid circulation efficiency, and the ability to respond to sudden blowouts.

[0003] Offshore drilling systems typically include a marine riser that connects the drilling platform to the subsea wellhead equipment, a blowout preventer assembly connected to the wellhead, and a wellbore that can be lowered from the drilling platform into the well via the marine riser. Drilling mud can enter the well through the wellbore and return to the surface in the annulus between the wellbore and the marine riser. Sometimes, unexpected pressure spikes can occur in the annulus, such as from pressurized formation fluids entering the well (also known as "well kick"). The opening of blowout preventers and diverters is a typical safety measure to deal with well kicks and other dangerous pressure changes.

[0004] Currently, the opening of the blowout preventer (BOP) assembly and the flow divider is controlled by a blowout preventer control system. This system is located on the drilling platform and includes a driller's platform, which is the main control interface. The driller's platform displays pressure information for accumulators, manifolds, and the BOP, as well as the operating status of multiple valves and pumps, and various buttons, handles, or touchscreens. When the BOP assembly needs to be opened, the operator needs to move to the driller's platform. However, in an emergency, the time required for the operator to move to the driller's platform is relatively long, making it difficult to quickly operate the platform and notify personnel to evacuate in a timely manner, thus increasing the probability of safety accidents. Summary of the Invention

[0005] In view of this, the purpose of the present invention is to provide a blowout preventer control system that solves the problem of high probability of safety accidents in existing systems.

[0006] To solve the above-mentioned technical problems, the technical solution used in this invention is as follows:

[0007] The blowout preventer control system of the present invention includes:

[0008] Remote control console: The remote control console includes a pressure generating component, a pressure storage component, and a pressure directional control component. The pressure generating component is used to provide hydraulic fluid, the pressure storage component is used to store hydraulic energy, and the pressure directional control component is used to control the flow direction of the hydraulic fluid. The output end of the pressure generating component is connected to the output end of the pressure storage component, the output end of the pressure storage component is connected to the pressure directional control component, the blowout preventer assembly is connected to the pressure directional control component, and the pressure generating component and the pressure directional control component are skid-mounted.

[0009] Operation Module: The operation module includes a driller's platform and an emergency control box. The driller's platform is connected to the remote control console, and the emergency control box is connected to the remote control console. The emergency control box is equipped with a main control button and a blowout preventer shutdown button. There are multiple emergency control boxes, which are distributed on the drilling platform.

[0010] The beneficial effects of this invention are as follows: Operators can control the opening of the blowout preventer (BOP) by operating the driller's platform or the emergency control box. The emergency control box has a simpler structure than the driller's platform. Multiple emergency control boxes are set up and distributed on the drilling platform. In case of an emergency, operators can quickly reach the emergency control box and press the main control button and the BOP shutdown button. The emergency control box provides flexible and reliable control of the remote control console. Multiple emergency control boxes are placed in places that are more easily accessible to operators, making operation convenient and quick. In case of an emergency, it reminds operators to evacuate the site in time and shuts down the BOP assembly, ensuring the safety of operators and workover equipment to the greatest extent. Attached Figure Description

[0011] The above and other objects, features, and advantages of the invention will become clearer through a more detailed description of the preferred embodiments illustrated in the accompanying drawings. The same reference numerals denote the same parts throughout the drawings, and the drawings are not intentionally drawn to scale with actual dimensions; the focus is on illustrating the gist of the invention.

[0012] Figure 1 This is an overall structural elevation view of an embodiment of this application.

[0013] Figure 2 This is a plan view of the overall structure of an embodiment of this application.

[0014] Figure 3 This is an elevation view of the remote control console in an embodiment of this application.

[0015] Figure 4 This is an elevation view of the emergency control box in an embodiment of this application.

[0016] Figure 5 This is a schematic diagram of the energy storage group in the embodiments of this application.

[0017] Figure 6 This is a schematic diagram of another state of the energy storage group in an embodiment of this application.

[0018] Figure 7 This is an architecture diagram from an embodiment of this application.

[0019] Figure 8 This is a flowchart illustrating an optional method of reusing pre-stored mechanical potential energy to accelerate blowout preventer gate closure, as described in an embodiment of this application. Detailed Implementation

[0020] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only a part of the embodiments of the present invention, and not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those of ordinary skill in the art without creative effort are within the scope of protection of the present invention.

[0021] Reference Figures 1-8 The present invention provides a blowout preventer control system, comprising:

[0022] The remote control console 1 includes a pressure generating component and a pressure storage component. The pressure generating component includes a pressure driving unit and an oil tank containing oil. The pressure driving unit includes an electric pump 11, the input of which is connected to the output of the oil tank. The pressure storage component includes an accumulator group 13, the output of which is connected to the input of the accumulator group. The oil tank, electric pump 11, and accumulator are connected by pipelines. When the electric pump 11 is started, it delivers the oil from the oil tank to the accumulator group 13. The accumulator group 13 stores energy and inputs high-pressure oil to the blowout preventer group. A relay is installed between the electric pump 11 and the accumulator group 13. The relay monitors the pressure of the accumulator's main pipeline and converts the pressure signal into an electrical signal. It automatically controls the start and stop of the electric pump 11 according to the system's hydraulic pressure, thereby maintaining the pressure of the accumulator group 13 within the set operating range.

[0023] The pressure drive unit also includes an air pump 12, which is connected in parallel with the electric pump 11. A relay is provided between the air pump 12 and the accumulator group 13 to control the start and stop of the air pump 12. A first electric three-way valve is connected to the oil tank output end. The three valve ports of the first electric three-way valve are respectively connected to the oil tank output end, the electric pump 11 input end, and the air pump 12 input end. Correspondingly, a second electric three-way valve is connected to the accumulator input end. The three valve ports of the second electric three-way valve are respectively connected to the electric pump 11 output end, the air pump 12 output end, and the accumulator input end. Thus, when the platform experiences a power outage or the main generator fails, causing the electric pump 11 to be unable to work, the air pump 12 can become the power source. It can independently pressurize and replenish the pressure of the accumulator. Furthermore, when a large number of continuous operations (such as repeated testing or handling complex well control situations) are required, causing the electric pump 11 to be unable to maintain the system pressure on its own, the air pump 12 can be started as an auxiliary.

[0024] The blowout preventer assembly includes a gate blowout preventer 21 and an annular blowout preventer. The gate blowout preventer 21 is installed at the wellhead and is fitted onto the outer wall of the wellbore. The annular blowout preventer is fitted onto the outer wall of the wellbore and is located on top of the gate blowout preventer 21. The pressure storage assembly output is connected to a pressure directional assembly. The pressure preparation assembly and the pressure directional assembly are skid-mounted.

[0025] The pressure control assembly includes a first three-position four-way valve 14 and a second three-position four-way valve 15. The first three-position four-way valve 14 includes ports A, B, P, and T. Port A of the first three-position four-way valve 14 is connected to the closing chamber of the gate blowout preventer 21, port B of the first three-position four-way valve 14 is connected to the opening chamber of the gate blowout preventer 21, port P of the first three-position four-way valve 14 is connected to one output end of the accumulator group 13, and port T of the first three-position four-way valve 14 is connected to the input end of the oil tank. Port T of the first three-position four-way valve 14 is used to receive hydraulic oil flowing back from the gate blowout preventer 21. Under the action of the first three-position four-way valve 14, the direction of hydraulic oil flow to the gate blowout preventer 21 can be controlled, thereby accurately commanding the gate blowout preventer 21 to perform three states: open, closed, or hold.

[0026] When the first three-position four-way valve 14 is in the holding state, the P port, T port, A port and B port of the first three-position four-way valve 14 are isolated from each other, achieving the effect of locking the hydraulic pressure. The oil in the closing chamber and opening chamber of the gate blowout preventer 21 is sealed inside, and the piston cannot move, so that the gate blowout preventer 21 is firmly locked in the current position. When the gate blowout preventer 21 is closed, the first three-position four-way valve 14 is in the holding state, and the gate blowout preventer 21 will remain closed under hydraulic locking, reducing the possibility of accidental opening due to well pressure.

[0027] When the first three-position four-way valve 14 is closed, port P is connected to port A and port B is connected to port T, allowing oil to flow from port P to port A. Then, the oil enters the closing chamber of the gate blowout preventer 21. The oil in the opening chamber of the gate blowout preventer 21 is pushed out by the piston. The oil flows through port B to port T and finally flows back to the oil tank, thereby closing the gate blowout preventer 21 and causing the gate blowout preventer 21 to push the gate core to close the wellbore.

[0028] When the first three-position four-way valve 14 is in the open state, port P is connected to port B, and port A is connected to port T. Oil enters port B from port P, and then enters the opening chamber of the blowout preventer. The oil in the closing chamber of the gate blowout preventer 21 is pushed out by the piston, passes through port A to port T, and finally flows back to the oil tank, thereby opening the gate blowout preventer 21. The gate blowout preventer 21 retracts the gate core to open the wellbore.

[0029] Correspondingly, the second three-position four-way valve 15 is connected to the accumulator group 13, the oil tank and the annular blowout preventer in the same way as the first three-position four-way valve 14. The second three-position four-way valve 15 is connected in parallel with the first three-position four-way valve 14, thereby reducing the mutual influence between the first three-position four-way valve 14 and the second three-position four-way valve 15. The second three-position four-way valve 15 is used to control the state of the annular blowout preventer.

[0030] A diverter 23 is installed on the outer wall of the wellbore. The diverter 23 is located at the top of the blowout preventer assembly. The diverter 23 is mainly used to guide the fluid in the wellbore to be discharged safely. When shallow drilling encounters low-pressure shallow gas or fluid intrusion, the diverter 23 will quickly guide the fluid away from the drilling platform to a designated area to prevent blowout or fire. The blowout preventer assembly is the core equipment of high-pressure well control. It is used to seal the wellhead and completely prevent fluid from gushing out. When high-pressure formation fluid intrusion or loss of control occurs, the wellbore can be forcibly closed by the gate blowout preventer 21 and the annular blowout preventer to prevent blowout.

[0031] Operation Module 3: Operation Module 3 serves as the human-machine interface. Operation Module 3 includes a shunt controller 31, which is connected to the shunt 23 and to another output terminal of the energy storage group 13. The shunt controller 31 is used to control the shunt 23.

[0032] The operation module 3 also includes a driller's platform 32, which is the main control interface. The driller's platform 32 is connected to the remote control console 1. By remotely operating the driller's platform 32, the remote control console 1 can be controlled, thereby controlling the opening and closing of the blowout preventer assembly. The number of driller's platforms 32 depends on the specific situation. In this embodiment, there are two driller's platforms 32, which are distributed at both ends of the skid, making it convenient for the staff to operate. When an emergency occurs at the construction site, the operator can operate the driller's platform 32 to open the remote control console 1, and the oil in the accumulator group 13 enters the blowout preventer assembly to close the blowout preventer assembly.

[0033] The operation module 3 also includes an emergency control box 33, which is connected to the remote control console 1. The emergency control box 33 is equipped with a main control button and a blowout preventer shutdown button. The number of emergency control boxes 33 depends on the specific situation. In this embodiment, there are four emergency control boxes 33, which are distributed on the drilling platform. The four emergency control boxes 33 are located in places that are easily accessible to the operators, such as the doorway and inside the workshop, to further facilitate the operation of the staff. In case of an emergency, the main control button and the blowout preventer shutdown button are pressed. Under the action of the emergency control box 33, the emergency control box 33 can flexibly and reliably control the remote control console 1. The four emergency control boxes 33 are arranged in places that are more easily accessible to the operators, making the operation convenient and quick. In case of an emergency, the operators are reminded to evacuate the site in time, and the blowout preventer assembly is shut down to ensure the safety of the operators and workover equipment to the greatest extent.

[0034] The pressure storage assembly includes a mounting unit 4, which includes a support base 41, a first frame 42, and a second frame 43. The first frame 42 is hinged to the support base 41, and correspondingly, the second frame 43 is also hinged to the support base 41. The first frame 42 and the second frame 43 are arranged parallel to each other. The accumulator group 13 includes multiple accumulators, which are evenly distributed on the first frame 42 and the second frame 43. The end of the first frame 42 away from the second frame 43 is detachably connected to a wall panel. The first frame 42 and the second frame 43 are detachably connected. 3. By connecting with a pin, the connection between the first frame 42 and the second frame 43 can be disassembled, allowing the first frame 42 and the second frame 43 to form a variable angle, facilitating the rotation of the second frame 43. When the accumulator needs maintenance, the second frame 43 rotates around the support base 41, placing the second frame 43 flat. Afterwards, after disassembling the connection between the first frame 42 and the wall panel, the first frame 42 can also rotate around the support base 41, placing the first frame 42 more flat, making the accumulator easier to disassemble, convenient for replacement and maintenance, thereby reducing maintenance costs and improving user experience.

[0035] The mounting unit 4 also includes a manifold 44, which connects to each accumulator, enabling the high-pressure gas stored in each accumulator to be used in the blowout preventer control system, thereby improving utilization efficiency. The manifold 44 includes a first support pipe 441 and a second support pipe 442. The first support pipe 441 connects to multiple accumulators installed on the first frame 42, and correspondingly, the second support pipe 442 connects to multiple accumulators installed on the second frame 43. The support base 41 includes two fixing plates 411, which are arranged parallel to each other. The first frame 42 is located between the two fixing plates 411. The two ends of the first support pipe 441 pass through the side walls of the first frame 42 that are close to it, and the first support pipe 441 is fixedly connected to the first frame 42. The two ends of the first support pipe 441 are rotatably connected to the fixing plates 411 that are close to it.

[0036] Correspondingly, the connection method between the second support tube 442 and the second frame 43 is consistent with the connection method between the first support tube 441 and the first frame 42, and the connection method between the second support tube 442 and the fixing plate 411 is consistent with the connection method between the first support tube 441 and the fixing plate 411. In this embodiment, no detailed description is given. This allows the second frame 43 to rotate around the support base 41. The first support tube 441 can support the first frame 42 and connect to the first accumulator group 13. The second support tube 442 can support the second frame 43 and connect to the second accumulator group 13. This makes the structure of the accumulator group 13 simpler and saves costs.

[0037] The execution module is used to control the opening action of the distributor valve core and, through the valve core structure, to generate directional fluid dynamics in the drilling fluid, synchronously triggering the pre-sealing action of the gate blowout preventer.

[0038] The synchronized operation of the distributor valve core and the gate blowout preventer is achieved through a combination of mechanical feedback and hydrodynamics: when the valve core opens to a specific angle, a mechanical trigger signal (such as a position sensor) synchronously activates the hydraulic control circuit of the blowout preventer; simultaneously, the directional hydrodynamic force generated by the valve core groove pushes the gate to begin a small-amplitude movement. The two work in a synchronized sequence, with the signal ensuring oil circuit continuity and the hydrodynamic force providing initial thrust, enabling the gate to synchronously initiate a pre-sealing action during the valve core opening process, thus achieving a causal relationship and time-synchronized operation.

[0039] The remote control console is used to convert directional fluid power into mechanical thrust, drive the gate blowout preventer to move toward the center of the wellhead until the sealing surface is in contact, and maintain the pre-sealing contact force during the opening of the diverter.

[0040] In the wellhead equipment of offshore drilling platforms, the wellhead center refers to the geometric centerline of the vertical wellhead channel, which is the core reference point for drilling fluid circulation and drill string passage. For example, for a 30-inch diameter wellhead casing, the vertical line containing its center is the wellhead center. The gate blowout preventer needs to move from both sides towards this center to accurately wrap the drill string or seal the wellhead.

[0041] Sealing surface fit refers to the state in which the sealing contact surface (usually a hard metal sealing surface or a soft rubber sealing surface) on the gate blowout preventer is in complete contact with the wellhead casing and drill string surface without any gaps. For example, the rubber sealing surface of the gate is tightly fitted to the outer wall of the drill pipe to form an annular sealing band, preventing drilling fluid from leaking from the wellhead, which is a key state for achieving wellhead pressure control.

[0042] In some embodiments, sensors monitor the contact force on the gate sealing surface in real time and feed the data back to a remote control console. When pressure and flow changes during the diverter's opening process cause the contact force to deviate from the target range, the remote control console adjusts the operating state of hydraulic components (such as relief valves), increases or decreases the hydraulic oil input, and compensates for the contact force deviation by adjusting the piston thrust, ensuring that the contact force remains stable throughout the diverter's opening process. Its core principle is to counteract the interference of operating condition changes on the contact force through real-time monitoring and dynamic adjustment.

[0043] The acoustic detection module is used to capture changes in the physical characteristics of the fluid discharged from the distributor in real time, and generates a trigger signal when the change exceeds a preset threshold.

[0044] Physical characteristics include, but are not limited to, acoustic characteristics (such as sound wave attenuation and frequency distribution), as well as abnormal changes in the physical properties of fluids such as pressure pulsations (such as instantaneous peak pressure changes), flow velocity (such as sudden changes in discharge rate), and density (such as increased density due to increased sand content). For example, a drilling fluid flow velocity suddenly increasing from 1.5 m / s to 3 m / s due to well kick, or a pressure pulsation amplitude increasing from 0.5 MPa to 2 MPa, both fall under the category of changes in physical characteristics.

[0045] The mechanical trigger module is used to respond to a trigger signal and release oil pressure to perform the well shut-in action of the blowout preventer;

[0046] The control module is used to establish the energy transfer path between the pre-sealing contact force and the shut-in action, and reuse the pre-stored mechanical potential energy to accelerate the closure of the gate blowout preventer when the shut-in action is performed.

[0047] It should be noted that the energy transfer path consists of a complete link comprised of sensing, control, storage, and remote control console components. Sensors collect mechanical and hydraulic parameters during the pre-sealing stage. The remote control console generates energy storage commands based on these parameters, driving an energy storage structure (such as a spring assembly) to store mechanical potential energy via hydraulic components. During well shut-in, the remote control console triggers the energy storage structure to release the potential energy, which is then converted into the power to close the gate via a conversion component (such as a hydraulic amplifier). Energy completes the conversion and transfer of "hydraulic energy → mechanical energy → hydraulic energy" along the path, achieving efficient energy utilization.

[0048] The mechanical potential energy stored during the pre-sealing stage is released in a concentrated manner during well shut-in, and combined with a hydraulic amplification mechanism, the closing speed is increased. Conventional well shut-in relies on real-time hydraulic power, while when reusing potential energy, the stored potential energy is converted into instantaneously enhanced hydraulic energy through a specific structure (such as an amplifier), significantly increasing the driving pressure. This concentrated release and amplification effect of energy can increase the gate driving force without additional energy, thereby accelerating the closing speed. Its gain stems from the pre-stored and efficient conversion of potential energy.

[0049] The emergency linkage channel is used to activate a shut-off mechanism independent of the main control link when the opening angle of the shunt exceeds the first safety threshold.

[0050] In some embodiments, during conventional drilling operations, the first safety threshold for the splitter opening angle is set to 60°. When the opening angle exceeds 60°, it indicates excessive drilling fluid discharge, which may lead to wellhead pressure runaway, thus activating an independent shut-in mechanism. In high-pressure gas well operations, due to the higher risk, the first safety threshold is set to 45°. When the splitter opening angle reaches 46°, a shut-in action independent of the main control link is immediately triggered, increasing safety redundancy.

[0051] The main control link refers to the conventional control path led by the control module and connected in series with the execution module, remote control console, acoustic detection module, and mechanical triggering module. For example: the acoustic detection module detects an anomaly → generates a trigger signal → the mechanical triggering module receives the signal and releases oil pressure → the control module reuses pre-stored potential energy to accelerate well shut-in. This complete signal transmission and action execution chain is the main control link.

[0052] A shut-off mechanism independent of the main control link refers to an emergency safety path designed independently without relying on the signal transmission and logic control of the main control link. For example, the emergency linkage channel directly monitors the fluid status at the distributor outlet through a cross-array ultrasonic sensor, without the need for complex calculations by the control module. Once a risk is determined, it directly drives the blowout preventer to shut off the well, avoiding safety vulnerabilities in the event of a main link failure (such as signal interruption or module failure).

[0053] The execution module controls the opening of the diverter valve core and utilizes the valve core structure to generate directional fluid dynamics in the drilling fluid, simultaneously triggering the pre-sealing action of the gate blowout preventer. This breaks down the relatively independent control logic of the two, avoiding the action response time difference caused by complex signal transmission and timing control, improving the coordination between the diverter and blowout preventer actions, and helping to prevent temporary loss of wellhead pressure control. The remote control console converts the directional fluid dynamics into mechanical thrust, driving the gate blowout preventer to move and maintain the pre-sealing contact force. Combined with the control module reusing pre-stored mechanical potential energy during well shut-in, energy distribution and transmission are optimized, solving the problems of insufficient energy reserves or low transmission efficiency in conventional hydraulic systems. This accelerates the closing speed of the gate blowout preventer and ensures timely emergency response. The acoustic detection module captures changes in fluid physical characteristics in real time and generates trigger signals. The mechanical triggering module responds to the signals to execute the well shut-in action, forming a precise and rapid emergency triggering mechanism, further improving the reliability of well shut-in actions in emergency situations. The emergency linkage channel activates an independent shut-off mechanism when the shunt opening angle exceeds the first safety threshold, adding extra safety protection to the system and reducing the risk of emergency failure due to main control link failure, thereby further reducing the probability of safety accidents.

[0054] Furthermore, the dynamic flow field optimization mechanism of the valve core structure includes:

[0055] An array of piezoelectric ceramic micro-actuators is embedded in the surface of an asymmetric spiral groove to receive viscosity sensor data of drilling fluid in real time.

[0056] The core design of the asymmetric spiral groove lies in breaking the symmetry of fluid flow. The grooves are distributed in a right-handed spiral along the valve core axis, with the left groove being deeper (initial depth 8mm) than the right (initial depth 5mm), and the spiral angle gradually changing from 30° at the inlet to 15° at the outlet. When drilling fluid flows through, the grooves guide the fluid, causing the flow velocity on the left to be higher than on the right, forming a clockwise rotating jet, which in turn generates an axial thrust (directional fluid dynamics) pointing towards the center of the wellhead. This force acts on the hydraulic piston of the gate blowout preventer through the transmission linkage, pushing the piston to make an initial displacement in the pre-sealing direction. The optimal pitch gradient is adjusted according to the flow resistance characteristics caused by viscosity changes, driving the piezoelectric ceramic micro-actuator array to deform and adjust the groove depth distribution.

[0057] Among these factors, drilling fluid viscosity is the core factor affecting its flow resistance. The higher the viscosity, the stronger the intermolecular cohesion, and the greater the flow resistance (flow resistance) when flowing through the valve core; the lower the viscosity, the smaller the flow resistance. For example, when the drilling fluid viscosity increases from 50 mPa·s to 100 mPa·s, the flow resistance through the valve core increases by about 1.8 times, resulting in a weakening of directional fluid dynamics, which requires adjustment and adaptation through valve core structure.

[0058] The pitch gradient refers to the rate of change of the pitch (axial distance between adjacent grooves) of the helical grooves with the length of the valve core. When flow resistance is high (e.g., high-viscosity drilling fluid), the pitch gradient needs to be reduced (gradual pitch change) to lower fluid flow resistance; when flow resistance is low (e.g., low-viscosity drilling fluid), the pitch gradient needs to be increased (steeper pitch change) to enhance directional fluid dynamics. For example, when the drilling fluid viscosity is 80 mPa•s (high flow resistance), the pitch increases slowly from 20 mm to 30 mm (gradient 0.5 mm / cm); when the viscosity drops to 30 mPa•s (low flow resistance), the pitch increases rapidly from 10 mm to 40 mm (gradient 3 mm / cm), adjusting the gradient to adapt to changes in flow resistance.

[0059] An array of piezoelectric ceramic micro-actuators is embedded in the surface of a spiral groove, which produces minute deformations (elongation or contraction) when energized. By controlling the deformation amplitude of the actuators at different positions, the groove depth can be adjusted differentially (the adjustment range is usually within the set range of 0.1-1mm to avoid excessive deformation that could damage the valve core). For example, if the flow resistance indicator shows excessive resistance on the left side of the groove, the left actuator is energized with a 20mA current to produce a 0.5mm elongation deformation, increasing the groove depth by 0.5mm; if the resistance on the right side is insufficient, the right actuator is energized with a -10mA current (in reverse) to produce a 0.3mm contraction deformation, reducing the groove depth by 0.3mm, thus creating a "deeper on the left, shallower on the right" depth distribution to balance the flow resistance.

[0060] A distributed pressure sensor array is set on the surface of the guide vane that is linked to the valve core;

[0061] A wing tilt angle compensation signal is generated based on the pressure distribution data output by a distributed pressure sensor array.

[0062] The wingplate tilt angle compensation signal is input into the damping controller of the hydraulic piston;

[0063] Based on the dynamic adjustment signal output by the damping controller, the fluctuation of the pre-sealed contact force is stabilized within the set range.

[0064] The distributed pressure sensors on the surface of the guide vane (e.g., 16 sensors arranged in a matrix) collect pressure values ​​at different locations, and the direction of fluid impact is determined by comparing the pressure differences at each point. For example, if the pressure of the sensor on the left side of the vane is 0.3 MPa and that on the right side is 0.2 MPa (pressure difference 0.1 MPa), it indicates that the fluid is deflected to the left. At this time, a compensation signal of "vane deflected 1° to the left" is generated (the compensation angle increases by 0.5° for every 0.05 MPa increase in pressure difference) to counteract the effect of the deflection.

[0065] After receiving the wingplate tilt angle compensation signal, the damping controller stabilizes the wingplate attitude by adjusting the damping force of the hydraulic piston, thereby controlling the fluctuation of the pre-sealing contact force. For example, if the compensation signal requires a 1° adjustment of the wingplate tilt angle, the controller will calculate the need to increase the hydraulic damping force by 0.2 MPa and output a corresponding current signal to the hydraulic valve to increase the piston damping, preventing the wingplate from excessively swaying due to fluid impact. Ultimately, the fluctuation of the pre-sealing contact force is stabilized within the set range of ±5% (e.g., if the target contact force is 100 kN, the actual fluctuation is controlled between 95-105 kN).

[0066] Among them, the deformation control of the piezoelectric ceramic micro-actuator array uses the real-time viscosity value of the drilling fluid as the input parameter; the generation of the vane tilt angle compensation signal is based on the dynamic gradient of the pressure distribution output by the distributed pressure sensor array; and the damping controller of the hydraulic piston adjusts the output damping force with the goal of stabilizing the fluctuation of the pre-sealed contact force.

[0067] Based on the embodiments provided in this application, drilling fluid viscosity data is received in real time via a piezoelectric ceramic micro-actuator array. The pitch gradient and depth distribution of the spiral groove are dynamically adjusted to adapt to changes in flow resistance. Simultaneously, distributed pressure sensors are used to collect pressure signals from the flanges, generating tilt angle compensation commands and stabilizing the pre-sealing contact force through a damping controller. The ingenuity of this design lies in breaking through the passive adaptation mode of traditional fixed valve cores. It combines the microsecond-level response characteristics of piezoelectric ceramics with pressure feedback control, enabling the valve core structure to actively adapt to the complex working conditions of frequent fluctuations in viscosity and pressure of offshore drilling fluids. This fundamentally avoids the problem of decreased sealing surface fit accuracy caused by flow field turbulence, achieving stable control of the pre-sealing contact force.

[0068] Furthermore, the acoustic detection module captures changes in the physical characteristics of the fluid discharged from the distributor in real time, and generates a trigger signal when the change exceeds a preset threshold, including:

[0069] The original acoustic signal of the fluid discharged from the diverter is collected in real time using a piezoelectric ceramic sensor array installed on the wall of the discharge pipe.

[0070] The raw acoustic signal is processed synchronously using a dual-channel processor: the first channel extracts the time-domain attenuation characteristics of the fluid acoustic wave in the target frequency band; the second channel analyzes the vibration transmission characteristics of the hydraulic pipeline.

[0071] The selection of the target frequency band is based on the acoustic characteristics of common anomalies in offshore drilling. During gas intrusion, gas mixed into the drilling fluid will generate high-frequency turbulent noise (bubble bursting sound) of 2-5kHz; in the early stage of sand blockage, solid particles impacting the pipe wall will generate pulse sound waves of 1-3kHz; during wellhead micro-leakage, high-speed fluid jet will generate a continuous whistling sound of 500-1500Hz.

[0072] Therefore, the target frequency band typically covers 500Hz-5kHz. By focusing on this range, the characteristic sound waves of the above-mentioned anomalies can be accurately captured, eliminating low-frequency mechanical vibrations (such as platform equipment below 100Hz) and high-frequency electromagnetic interference (above 10kHz). This is based on acoustic data analysis from laboratory simulations (air intrusion / sand blockage simulation devices) and field failure cases.

[0073] A mechanical vibration noise suppression model is constructed based on the output of the second channel;

[0074] The mechanical vibration noise suppression model employs the LMS (Least Mean Square) adaptive filtering algorithm, the core of which utilizes the pipeline vibration signal from the second channel as "reference noise." The second channel extracts the vibration transmission characteristics of the hydraulic pipeline (such as vibration frequency and amplitude) as a feature template for the noise source; the adaptive filtering algorithm performs correlation analysis between the fluid acoustic wave signal from the first channel and the reference noise, dynamically adjusting the filter coefficients to cancel out the components in the output signal related to the reference noise.

[0075] For example, when the platform pump vibrates and generates 120Hz mechanical noise, the model identifies this frequency component using the LMS algorithm and filters it out specifically from the acoustic signal in the first channel, preserving the acoustic characteristics of the fluid itself. Its core is to eliminate the interference of environmental vibrations on fluid acoustic detection through a "noise reference-adaptive cancellation" mechanism.

[0076] The output of the first channel is noise-suppressed to generate fluid acoustic characteristics.

[0077] Simultaneously collect fluid pressure pulsation characteristics of the venting pipeline;

[0078] Calculate the deviation of fluid acoustic characteristics from the reference acoustic state;

[0079] It should be explained that the reference acoustic state refers to the stable acoustic characteristics of the fluid discharged from the distributor under normal drilling operation conditions. Its calibration must be performed when drilling fluid parameters (density, viscosity, sand content) are stable and there are no abnormalities such as well kicks / losses. The acoustic signals of the discharged fluid are continuously acquired using a piezoelectric ceramic sensor array. A stable period of 10-30 minutes is selected (such as a period of normal drilling fluid circulation and stable drilling rate). After noise reduction and filtering, acoustic characteristics (such as frequency distribution, amplitude range, and attenuation coefficient) are extracted to form a reference template. This reference is dynamically updated, calibrated hourly with the latest stable data to adapt to slow changes in the drilling fluid (such as gradual changes in sand content with increasing well depth).

[0080] The deviation is used to quantify the difference between the current fluid acoustic characteristics and the baseline state. The calculation logic is as follows: the noise-suppressed fluid acoustic characteristics (such as frequency spectrum and amplitude envelope) are decomposed into N characteristic parameters (such as peak frequency, total energy, and dominant bandwidth); the normalized difference between each parameter and the corresponding parameter in the baseline state is calculated as (current value - baseline value) / baseline value; and the comprehensive deviation is obtained by weighted summation (the weights are set according to the sensitivity of the parameters to anomalies, such as peak frequency having a higher weight than total energy). For example, when air intrusion occurs, the peak frequency shifts to higher frequencies, and its normalized difference increases, directly increasing the deviation and intuitively reflecting the degree of abnormality in the acoustic state.

[0081] When the deviation exceeds the acoustic threshold and the fluid pressure pulsation characteristic quantity simultaneously exceeds the associated threshold, it is determined that the change in physical characteristics exceeds the preset critical value.

[0082] Among them, the acoustic threshold and the correlation threshold adopt a "logical AND" relationship, the core of which is to avoid misjudgment of a single signal through double verification.

[0083] Acoustic signals may become abnormal due to local wear in the pipeline (non-dangerous conditions), while pressure pulsation signals can reflect the overall flow state (e.g., well kicks are always accompanied by a sudden increase in pressure); when setting, the acoustic threshold corresponds to "significant deviation from the benchmark" (e.g., deviation > 0.6), and the pressure pulsation threshold corresponds to "exceeding the normal fluctuation range" (e.g., pulsation amplitude > twice the normal average).

[0084] For example, in conventional drilling fluid circulation operations (moderate viscosity, low sand content), the normal fluctuation range of the baseline deviation is 0-0.3, and the acoustic threshold is set at 0.6. When the deviation exceeds 0.6 (such as a surge in the proportion of high-frequency sound waves due to gas intrusion), the acoustic characteristics are considered abnormal. In high-density drilling fluid operations (such as deep well control), the baseline acoustic characteristics are more stable, with a normal fluctuation range of 0-0.2, and the acoustic threshold is set at 0.5, making it more sensitive to detect anomalies (such as subtle acoustic changes caused by gas mixing in high-density fluids).

[0085] For example, during conventional drilling, the normal average pressure pulsation in the venting pipe is 0.3 MPa, and the associated threshold is set at 0.8 MPa (approximately 2.7 times the normal average). When the pulsation amplitude exceeds 0.8 MPa (such as a pressure surge caused by a well kick), it is triggered in conjunction with the acoustic threshold. During underbalanced drilling (lower pressure), the normal average pulsation is 0.1 MPa, and the associated threshold is set at 0.3 MPa (approximately 3 times the normal average) to avoid misjudging minor fluctuations in low-pressure environments.

[0086] Only when both exceed the limits is it considered a valid anomaly, which can rule out single sensor failure (such as false alarms from acoustic sensors) or local non-dangerous disturbances (such as temporary sand impacts), improve the reliability of the trigger signal, and comply with the safety principle of "better safe than sorry" in offshore drilling.

[0087] Among them, when the deviation exceeds the acoustic threshold and the pressure pulsation characteristic quantity simultaneously exceeds the correlation threshold, it includes:

[0088] Synchronous determination requires ensuring that there is an overlap between the peak moment of the pressure pulsation characteristic quantity and the period of continuous exceeding of the acoustic deviation limit;

[0089] The width of the overlapping time window is dynamically adjusted according to the fluid flow rate in the discharge pipe.

[0090] Among them, the fluid acoustic features are extracted by the fluid acoustic wave signal after suppressing mechanical vibration noise; the deviation is determined by the dynamic comparison between real-time acoustic features and preset reference acoustic state; the triggering of the associated threshold needs to simultaneously meet the over-limit conditions of acoustic deviation and pressure pulsation features.

[0091] Based on the embodiments provided in this application, after acquiring the raw acoustic wave signal using a piezoelectric ceramic sensor array, a dual-channel processor extracts the time-domain attenuation characteristics of the fluid acoustic wave and the pipeline vibration characteristics, respectively. An environmental interference is eliminated by constructing a mechanical vibration noise suppression model, and then a dual threshold determination is performed by combining the fluid pressure pulsation characteristics. Its ingenuity lies in addressing the environmental challenges of strong vibration and high noise on offshore platforms by innovatively correlating and verifying acoustic and pressure characteristics. Through progressive analysis of signal separation, noise suppression, and feature fusion, it solves the problem of misjudgment caused by interference in single-signal detection, ensuring accurate capture of abnormal changes in drilling fluid discharge status even in complex environments.

[0092] Furthermore, the mechanical trigger module achieves hydraulic pressure release control through the following steps:

[0093] Real-time acquisition of hydraulic circuit pressure signals;

[0094] The intrinsic mode components of pressure fluctuations are obtained through empirical mode decomposition, and the evolution sequence of sample entropy values ​​for each mode component is calculated.

[0095] It needs to be explained how effective Empirical Mode Decomposition (EMD) is for detecting anomalies in pressure signals.

[0096] EMD is suitable for processing nonlinear and non-stationary pressure signals from offshore hydraulic systems (signal fluctuations caused by platform swaying and pump start-stop). Its core advantage is that it can decompose complex signals into several intrinsic mode components (IMFs), each corresponding to fluctuations at different frequency scales. The second-order mode is a high-frequency random component, reflecting instantaneous pressure changes (such as pressure pulses caused by well kicks); the third-order mode is a low-frequency trend component, reflecting the overall trend of pressure changes (such as a continuous rise in pressure before well shut-in).

[0097] In abnormal conditions (such as a sudden pressure surge requiring well shut-in), the second-order mode exhibits a significant increase in sample entropy (representing randomness) due to the increased abrupt change signals; the third-order mode shows a continuous decrease in sample entropy (representing complexity) due to the unidirectional pressure change. This combination of "high-frequency entropy increase + low-frequency entropy decrease" can effectively distinguish between normal fluctuations (stable entropy values ​​in each mode) and dangerous anomalies, accurately pinpointing the pressure characteristics that require well shut-in.

[0098] When the entropy value of the second-order modal component, which represents high-frequency randomness, increases beyond the set abrupt change threshold, and the entropy value of the third-order modal component, which represents low-frequency trend, decreases continuously, the hydraulic actuator is driven to compress the energy storage spring.

[0099] The mutation threshold (critical value for the increase in entropy of the second-order modal component samples) is set based on the fluctuation range of the sample entropy value under normal operating conditions, reflecting the significant enhancement of high-frequency randomness. For example, when a conventional hydraulic system is running stably, the normal fluctuation range of the entropy value of the second-order modal sample is 0.1-0.3, and the mutation threshold is set to 0.5 (i.e., an increase exceeding 0.5 is considered a mutation). When a well kick causes an increase in pressure pulses, the entropy value suddenly increases from 0.2 to 0.8 (an increase of 0.6 > 0.5), triggering an action. In high-pressure oil and gas well operations, the system is more sensitive to pressure mutations, with a normal entropy value fluctuation range of 0.05-0.2. The mutation threshold is set to 0.3 to ensure earlier detection of potential risks (e.g., an increase of 0.35 > 0.3 when the entropy value increases from 0.15 to 0.5, triggering an action).

[0100] The "continuous decrease" of the entropy value of the third-order modal component sample refers to the entropy value continuously decreasing within a set time period and meeting the following conditions: The time period is based on the sampling frequency of the hydraulic system (usually 10Hz, i.e., sampling once every 0.1 seconds), for three consecutive sampling periods (a total of 0.3 seconds). The entropy value of each period decreases by ≥5% compared to the previous period (e.g., the entropy value of the first period is 0.4, the second period is ≤0.38, and the third period is ≤0.36). For example, if the pressure before the well kick shows a continuous upward trend, the entropy value of the third-order modal component decreases from 0.4→0.37→0.34 (decreasing for three consecutive periods, with a decrease of ≥7% per period), satisfying the "continuous decrease" criterion, and triggering well shut-in in conjunction with the increase in entropy of the second-order modal component.

[0101] The spring mechanical locking is completed before the electromagnet attracts the firing pin latch;

[0102] In some embodiments, the spring mechanical locking is achieved using a "pawl-ratchet" mechanism. When the energy-storing spring is compressed, the connected ratchet rotates with the spring seat, and the ratchet teeth have a unidirectional inclined structure. The elastic pawl fixed to the housing engages with the ratchet teeth, allowing the ratchet to rotate only in the direction of spring compression (the pawl slides along the tooth surface). When rotating in the opposite direction, the pawl engages in the tooth groove, preventing the spring from rebounding. When the electromagnet receives a trigger signal and attracts the striker pin to latch, it releases the pawl in conjunction (e.g., by pulling the pawl away from the tooth groove), and the energy stored in the spring is released instantaneously. This structure locks without continuous energy consumption after the spring is compressed, ensuring that energy is not lost in emergencies.

[0103] The tip of the firing pin adopts a composite diaphragm structure that is resistant to hydrogen sulfide corrosion, and the primary and secondary diaphragms are linked by a hydraulic damping chamber.

[0104] After the main diaphragm ruptures, the secondary diaphragm, under the pressure regulation of the hydraulic damping chamber, blocks the oil passage for a delayed period.

[0105] Among them, staged sealing is achieved through structural differences and hydraulic damping, adapting to the timing requirements of well shut-in operations:

[0106] The main diaphragm is made of a thin and brittle material (such as reinforced resin), which is prone to breakage under hydraulic pressure; the secondary diaphragm is made of a tough material (such as oil-resistant rubber), which has higher strength; the hydraulic damping chamber is located between the main and secondary diaphragms, and the chamber is connected to the external oil circuit through a small throttling orifice;

[0107] After the main diaphragm ruptures, high-pressure oil enters the damping chamber, pushing the secondary diaphragm to move in the sealing direction. However, the throttle orifice restricts the oil flow rate, causing the secondary diaphragm to slowly adhere to the oil circuit port (the delay time is determined by the diameter of the throttle orifice, usually tens to hundreds of milliseconds). The rapid rupture of the main diaphragm achieves the initial release of oil pressure, while the delayed sealing of the secondary diaphragm avoids the gate impact caused by a sudden drop in oil pressure, ensuring a smooth well shut-in operation and protecting the sealing surface from damage.

[0108] Based on the embodiments provided in this application, the intrinsic modal components of pressure fluctuations are extracted through empirical mode decomposition, and the pressure mutation trend is identified based on the sample entropy value evolution sequence. This allows for the pre-activation of the energy storage spring for mechanical locking to store energy. The striking pin employs a composite diaphragm structure resistant to hydrogen sulfide corrosion, and a hydraulic damping chamber enables delayed sealing of the secondary diaphragm after the primary diaphragm ruptures. The ingenuity of this design lies in combining the pressure mutation prediction mechanism with adaptability to the unique marine environment. It ensures the response speed of well shut-in actions through advance energy reserves, while utilizing the corrosion resistance and damping delay design of the composite diaphragm to avoid the impact of sudden oil pressure drops on the gate, thus meeting the demands of highly corrosive and frequently fluctuating pressure conditions at sea.

[0109] Furthermore, the control module establishes an energy transfer path between the pre-sealing contact force and the shut-in action, reusing pre-stored mechanical potential energy to accelerate the closure of the gate blowout preventer during the shut-in action, including:

[0110] S301, the gate acceleration data during the pre-sealing stage is collected in real time by the gate linkage displacement sensor;

[0111] S302 generates a control command for dynamically adjusting the compression of the disc spring by combining the contact force establishment rate calculated in real time based on the gate acceleration data and the hydraulic chamber pressure value collected in real time.

[0112] The core of deriving the contact force establishment rate from the gate's acceleration data lies in combining the system's dynamic characteristics. The gate's linkage displacement sensor collects the acceleration signal (a), and the real-time contact force (F) is calculated using a dynamic model (F=ma+kx+cv, where m is the gate's mass, k is the system stiffness, x is the displacement, v is the velocity, and c is the damping coefficient). The contact force establishment rate is the derivative of the contact force with respect to time (dF / dt), reflecting how quickly the contact force increases as the gate moves. For example, in the initial pre-sealing stage, the gate accelerates contact, the acceleration a increases, F rises rapidly, and dF / dt becomes a positive and relatively large value, intuitively demonstrating the dynamic process of the sealing surface contact.

[0113] The control commands are generated based on a closed-loop control with two inputs: "contact force build-up rate" and "hydraulic pressure". Specifically, if the contact force build-up rate is too fast (which may cause impact on the sealing surface), the controller generates a "reduce disc spring compression" command (achieved by reducing the hydraulic chamber pressure); if the current hydraulic chamber pressure is lower than the target value (unable to provide sufficient compression force), a "increase compression" command is generated (increase the injection of hydraulic oil).

[0114] In some embodiments, a fuzzy control algorithm is used to fuzzify the rate and pressure signals into fuzzy quantities such as "fast / slow" and "high / low". Specific control commands (such as the percentage of proportional valve opening) are output through preset rules (such as "fast rate and high pressure → significantly reduce compression") to achieve dynamic adaptation of the disc spring compression.

[0115] S303 controls the proportional valve to inject hydraulic oil into the hydraulic chamber according to the control command, driving the hydraulic piston to move to mechanically compress the disc spring assembly to store mechanical potential energy.

[0116] S304, calculates the spring energy storage efficiency in real time as the ratio of stored deformation energy to input hydraulic energy. When the ratio is lower than the optimization threshold, a negative pressure pulse is injected into the hydraulic chamber to calibrate the deformation state of the disc spring assembly.

[0117] It should be noted that the negative pressure pulse is used to address deformation deviations in disc springs caused by friction and hysteresis (such as actual compression less than the commanded value). The mechanism involves the following: when the energy storage efficiency (stored deformation energy / input hydraulic energy) is below the optimization threshold, the controller triggers the negative pressure generator to inject a brief negative pressure pulse (pressure lower than atmospheric pressure, lasting tens of milliseconds) into the hydraulic chamber. The negative pressure causes the hydraulic piston to briefly retract, releasing localized stress in the spring assembly, eliminating the "dead zone" caused by friction jamming, and restoring the spring deformation to a state matching the command. The effect is similar to "mechanical reset," breaking the static friction between the spring and piston through instantaneous negative pressure, ensuring deformation accuracy, improving the stability of energy storage efficiency, and preventing insufficient energy reserves due to long-term use.

[0118] The optimization threshold is the minimum acceptable value for spring energy storage efficiency (stored deformation energy / input hydraulic energy), set according to the energy utilization requirements of different drilling scenarios. For example, in conventional drilling operations (with moderate shut-in speed requirements), the normal range for energy storage efficiency is 60%-80%, and the optimization threshold is set at 60%. When the efficiency drops to 58% (below 60%), a negative pressure pulse is injected for calibration to ensure that the energy reserve is not lower than the basic requirement. In high-pressure gas well operations (requiring rapid shut-in), the energy storage efficiency requirement is higher, with a normal range of 70%-90%, and the optimization threshold is set at 70%. When the efficiency drops to 68% (below 70%), calibration is immediately initiated to ensure that the potential energy released is sufficient to drive rapid shut-in, meeting the safety redundancy requirements of the high-pressure environment.

[0119] S305 releases the mechanical potential energy stored in the disc spring assembly when performing the well shut-in operation, and drives the gate blowout preventer to close faster through the gain of the hydraulic amplifier.

[0120] The hydraulic amplifier uses an "area difference piston" structure, which amplifies pressure by the difference in the pressure-bearing areas on both sides of the piston (gain = area of ​​the large end / area of ​​the small end).

[0121] Based on historical energy storage efficiency data (such as the potential energy conversion efficiency of the past 10 well shut-ins), if the efficiency is low (such as below 70%), the controller increases the gain (such as increasing the area ratio) to convert the same potential energy into greater thrust; if the efficiency is too high, causing gate impact (such as exceeding 90%), the gain is reduced; the adjustment is achieved by changing the effective pressure area of ​​the piston's large end through the servo motor (such as moving the shielding ring to change the oil supply area), ensuring that the potential energy conversion efficiency is maintained in the optimal range of 75%-85% each time the well is shut in, balancing the closing speed and the smoothness of the operation.

[0122] S306 dynamically adjusts the gain value of the hydraulic amplifier based on historical energy storage efficiency data to optimize potential energy conversion efficiency.

[0123] Among them, the generation of disc spring compression control commands integrates gate acceleration data and hydraulic chamber pressure; energy storage efficiency is optimized by calibrating the deformation state of the disc spring assembly through negative pressure pulses; and the gain value of the hydraulic amplifier is dynamically adjusted based on historical energy storage efficiency data.

[0124] Based on the embodiments provided in this application, the compression of the disc spring is dynamically adjusted by using gate acceleration and hydraulic chamber pressure data. Combined with negative pressure pulse calibration, energy storage efficiency is ensured. During well shut-in, pre-stored mechanical potential energy is released, and conversion efficiency is optimized through a hydraulic amplifier. This overcomes the limitations of traditional systems in energy utilization, converting the process energy of the pre-sealing stage into emergency energy during well shut-in. Dynamic adjustment and calibration address the issue of spring performance decay, significantly improving the energy utilization efficiency and response speed of well shut-in operations in scenarios where energy supply on offshore platforms is easily affected by swaying.

[0125] Furthermore, the emergency response channel activates a silo-shutdown mechanism independent of the main control link, including:

[0126] The three-dimensional velocity field distribution of the drilling fluid discharge is collected by a cross-array ultrasonic sensor at the outlet of the distributor.

[0127] The velocity gradient tensor is decomposed into rotational and strain components. When the energy proportion of the rotational component exceeds a set threshold, it is marked as an effective vortex core.

[0128] It should be noted that in a three-dimensional velocity field, the velocity gradient tensor is a 3×3 matrix (▽v), where the elements are... / (i and j represent the x, y, and z directions) represent the velocity components. exist Rate of change of direction.

[0129] Where i represents the direction of the velocity component (i=x,y,z corresponds to vx,vy,vz), and j represents the direction of the spatial coordinate (j=x,y,z corresponds to the x, y, z axes). / It covers all the partial derivatives of the velocity components in the spatial direction, totaling 3 (velocity components) × 3 (spatial direction) = 9 elements, which fully describes the velocity variation characteristics of the three-dimensional flow field.

[0130] During decomposition, it is split into a symmetric component (strain tensor) and an antisymmetric component (rotation tensor) through mathematical transformation. The rotation component (vorticity tensor) is the antisymmetric component, and its corresponding vorticity vector vec = ▽ × v represents the rotational intensity of the fluid; the strain component is the symmetric component, i.e., (▽V + ▽V) T ) / 2, characterizing the tensile or shear deformation of the fluid, where T denotes the transpose, and for the velocity gradient tensor ▽V (a 3×3 matrix), its transpose matrix ▽vT It is the matrix obtained by swapping the rows and columns of the original matrix.

[0131] Taking a three-dimensional velocity field as an example, the elements of the velocity gradient tensor ▽V are: / (i and j represent the three directions x, y, and z), and its transpose matrix ▽v T The elements are / .

[0132] Therefore, the formula for calculating the strain components is (▽V + ▽V) T The physical meaning of ) / 2 is: by averaging the original tensor and its transpose tensor, the symmetrical deformation component (tension or shear) in the velocity gradient can be extracted. This component is only related to the shape change of the fluid and does not contain rotational information, thus achieving separation from the rotational component (antisymmetric component). For example, when vortices appear during drilling fluid discharge, the modulus of the rotational component increases significantly, while the strain component dominates in uniform flow. The existence of the vortex core can be accurately identified through decomposition.

[0133] The "energy" of the rotational component is quantified by the square integral of vorticity, calculated as: Rotational component energy = ∫(vec×vec) / 2dV (where V is the volume of the fluid element), reflecting the total intensity of the vortex. The proportion of rotational component energy is the ratio of this energy to the total energy of the velocity gradient tensor (rotational component energy + strain component energy). For example, during normal venting, this proportion is usually below 15%, but when an effective vortex core appears, the proportion jumps sharply to over 30%, which is used as the quantitative standard for vortex core identification.

[0134] Calculate the projected distance between the center of the vortex core and the center of gravity of the platform on the horizontal plane;

[0135] Establish a mutually exclusive function between the platform's roll angular velocity and the projected distance;

[0136] in, ; For mutual exclusion functions, The platform's roll angular velocity, This represents the projection distance.

[0137] It needs to be explained that, It represents the platform's roll rate (usually measured in rad / s), describing the rate at which the platform rolls about its longitudinal axis (from bow to stern). It represents the projected distance (usually in meters) between the center of the vortex core and the center of gravity of the platform on the horizontal plane, describing the horizontal distance between the center of the dangerous vortex formed by the released fluid and the stable core (projection of the center of gravity) of the platform.

[0138] It represents the product of angular velocity ω and distance d. Indicates taking The absolute value. The absolute value ensures that the function result is always non-negative, which is consistent with the characteristics of a mutually exclusive function as a risk metric (the larger the value, the higher the risk).

[0139] This product has the dimension of velocity ((rad / s)*m=m / s). It can be intuitively understood as the amplitude of the tangential linear velocity at the vortex core position d due to the platform's roll angular velocity ω. This linear velocity reflects the potential of the disturbance torque exerted by the vortex core on the platform. The larger the distance d, the greater the linear velocity produced by the same angular velocity ω, meaning a greater potential for the vortex core to exert a toppling torque on the platform (torque = force × lever arm; here, the force is related to the dynamic pressure generated by the vortex core impact, and the lever arm is approximately d).

[0140] The larger ω and d are, the more likely the dangerous vortex is to appear far from the platform's stable core during violent platform swaying, amplifying the instability risk through their coupling. The absolute value |ω×d| quantifies the dynamic instability risk caused by the coupling between the platform's rolling motion and the location of the venting vortex core. A larger value indicates more violent platform swaying (larger ω) and a greater distance of the dangerous vortex from the platform's stable center (larger d), resulting in a higher risk of system instability (such as platform overturning or equipment failure) due to their combined effect.

[0141] Based on the embodiments provided in this application, a three-dimensional velocity field of drilling fluid is acquired using a cross-array ultrasonic sensor. The velocity gradient tensor is decomposed to identify effective vortex cores, and the projected distance between the vortex core and the platform's center of gravity is calculated. Then, a mutual exclusion function is used to correlate the platform's roll angular velocity with the projected distance. The ingenuity of this design lies in breaking through the traditional static angle threshold judgment mode, deeply coupling the shunt opening state with the dynamic attitude of the offshore platform. This makes the activation logic of the shut-in mechanism more closely match the dynamic stress environment of the platform affected by ocean waves, avoiding misjudgments or omissions caused by static thresholds.

[0142] Furthermore, the method also includes:

[0143] When the value of the mutual exclusion function exceeds the second safety threshold but the pressure entropy change rate of the hydraulic circuit does not exceed the entropy change rate limit, it is judged as a risk of vortex interference.

[0144] When the value of the mutual exclusion function exceeds the third safety threshold and the pressure entropy change rate of the hydraulic circuit decreases continuously, it is determined to be a risk of system failure.

[0145] For example, the mutual exclusion function can be F(ω,d)=|ω×d|, which physically represents the "risk coupling degree" formed by the platform's roll angular velocity ω and the projected distance d between the vortex core and the center of gravity. The larger ω is (the more violent the platform swaying) and the larger d is (the farther the vortex core is from the center), the higher the coupling degree, and the greater the potential overturning moment.

[0146] The second safety threshold (vortex interference risk) is set based on the "maximum coupling degree that the platform can offset by adjusting the counterweight" in the sea trial data. If it is set to 0.8 (unit: rad•m / s), the roll amplitude has not yet threatened the structural safety.

[0147] The third safety threshold (system failure risk) is set based on the "coupling degree critical value that may cause wellhead equipment overload" in the simulation calculation. For example, if it is set to 1.5, the well must be shut down urgently if this value is exceeded to avoid equipment damage.

[0148] It should be noted that the pressure entropy change rate is calculated using the sliding window method. Within a 5-second sliding window, the sample entropy of the pressure signal is calculated every 0.5 seconds. The entropy change rate is the ratio of the difference between two adjacent entropy values ​​to the time interval. For example, during vortex interference, although the pressure fluctuations are violent, a pattern can be discerned, and the entropy change rate does not exceed 0.02 (entropy value / second), indicating that the system is functioning normally. When the system fails, the disorder of the pressure signal continues to increase, and the entropy change rate continuously decreases (e.g., from 0.03 to -0.01), reflecting that the system has lost its controllability, thus distinguishing the type of risk.

[0149] For example, the "continuous decrease" of the pressure entropy change rate is based on the system sampling period (hydraulic circuit pressure signals are typically sampled at a frequency of 10Hz, i.e., one data point is generated every 0.1 seconds). For example, the time period is set to three consecutive sampling periods (a total of 0.3 seconds); the decrease amplitude is: the pressure entropy change rate in each period decreases by ≥8% compared to the previous period (the entropy change rate is the ratio of the difference in entropy values ​​between adjacent windows to time). For example, in the initial stage of system failure risk, the pressure entropy change rate is 0.05→0.046→0.042 (the decrease in each period is 8% and 8.7% respectively). If the decrease amplitude is ≥8% for three consecutive periods, it is judged as "continuous decrease". Combined with the mutual exclusion function value exceeding the limit, the system failure risk response mechanism is triggered.

[0150] To mitigate the risk of vortex interference, the gravity storage tank is unlocked, and a correction signal for the falling trajectory of the counterweight is generated based on the mutual exclusion function value. The horizontal displacement of the counterweight is then adjusted via a hydraulic servo mechanism to counteract the platform's swaying.

[0151] It should be noted that the counterweight in the gravity storage tank achieves horizontal displacement control through a hydraulic servo mechanism: when the mutual exclusion function value exceeds the second safety threshold, the controller calculates the required reaction torque (M=mg•Δx, where m is the counterweight mass, g is the gravitational acceleration, and Δx is the horizontal displacement) based on F(ω,d).

[0152] The hydraulic servo valve receives a command and drives the hydraulic cylinder to move the counterweight in the opposite direction of the sway (e.g., if the platform sways to the left, the counterweight moves to the right), generating a counter-torque to counteract the sway. For example, when the platform's sway angular velocity ω = 0.2 rad / s, moving the counterweight 0.5 m is sufficient to generate a sufficient counter-torque, reducing the sway amplitude by more than 40%.

[0153] To mitigate the risk of system failure, the burst valve is activated synchronously, and the phase angle of the hydraulic pulse sequence is dynamically adjusted based on the position of the vortex core, so that the oil pressure peak avoids the fluid impact at the moment the vortex core passes through.

[0154] Among these methods, real-time monitoring of the vortex core position (using a cross-array ultrasonic sensor with a sampling frequency of 100Hz) is used to predict the time t0 for the vortex core to reach the wellhead center using a linear prediction algorithm (such as least squares fitting); the phase angle of the hydraulic pulse sequence is adjusted so that the pressure peak time is offset from t0 by at least 0.1 seconds.

[0155] If the vortex core moves at a speed of 1 m / s and is currently 3 m from the center, with a predicted t0 = 3 s, the pulse phase angle is set so that the peak value appears at 2.8 s or 3.2 s. The algorithm updates the prediction every 0.1 seconds to ensure that the phase adjustment always adapts to the dynamic position of the vortex core and avoids sealing failure caused by the superposition of pressure peak and fluid impact.

[0156] Among them, the construction of the mutual exclusion function is related to the platform's roll angular velocity and the vortex core projection distance; the judgment of system failure risk requires the mutual exclusion function to exceed the limit and the hydraulic circuit pressure entropy rate of change to decrease simultaneously; the correction of the counterweight falling trajectory is achieved by adjusting the horizontal displacement to cancel the platform's sway; the phase angle adjustment of the hydraulic pulse sequence is based on the dynamic matching of the fluid impact timing according to the vortex core position.

[0157] Based on the embodiments provided in this application, vortex interference risk and system failure risk are distinguished according to the combined characteristics of the mutual exclusion function value and the hydraulic circuit pressure entropy change rate. The former is counteracted by adjusting the counterweight block through a gravity accumulator and hydraulic servo mechanism to offset platform sway, while the latter is mitigated by activating the burst valve and dynamically adjusting the hydraulic pulse phase to avoid vortex core impact. Given the complex causes of risks at sea, this tiered approach maintains operational continuity during vortex interference and improves the well shut-in success rate in the event of system failure, thus balancing safety and operational efficiency.

[0158] Furthermore, a mechanical vibration noise suppression model is constructed based on the output of the second channel, including:

[0159] The vibration transmission characteristics of the hydraulic pipeline analyzed by the second channel are matched in real time to the frequency range corresponding to the time-domain attenuation characteristics of the fluid acoustic wave extracted by the first channel.

[0160] Based on this matching relationship, the mechanical vibration noise suppression model applies an adaptive filtering algorithm to dynamically cancel mechanical vibration noise in the same frequency band during the generation of fluid acoustic features.

[0161] In some embodiments, the adaptive filtering algorithm can be the NLMS (Normalized Least Mean Square) algorithm. Specifically, the advantage of using the NLMS algorithm is that it has a fast convergence speed and is not sensitive to changes in signal amplitude.

[0162] The reference signal is the vibration transmission characteristics of the hydraulic pipeline in the second channel (such as vibration acceleration signal); the filter step size factor is set to 0.01 (to balance convergence speed and stability), and convergence is completed within 100ms;

[0163] In real time, the fluid acoustic wave signal of the first channel is subtracted from the noise estimate output by the filter to cancel out mechanical vibration noise in the same frequency band (such as pump vibration at 200-500Hz), thereby improving the signal-to-noise ratio of the fluid acoustic characteristics by more than 20dB and ensuring the accuracy of anomaly detection.

[0164] Based on the embodiments provided in this application, the frequency range of the vibration transmission characteristics of hydraulic pipelines and the time-domain attenuation characteristics of fluid acoustic waves are matched in real time, and an adaptive filtering algorithm is applied to dynamically cancel noise in the same frequency band. This overcomes the limitations of traditional fixed-frequency band filtering. Considering the characteristics of multiple vibration sources and dynamic frequency changes on offshore platforms, targeted noise reduction is performed by locking overlapping frequency bands. This improves the targeting of noise suppression while avoiding the loss of useful signals, ensuring the accuracy of fluid acoustic feature extraction.

[0165] The above are merely preferred embodiments of the present invention and do not limit the scope of the patent. Any equivalent structural or procedural transformations made based on the description and drawings of the present invention, or direct or indirect applications in other related technical fields, are similarly included within the scope of patent protection of the present invention.

Claims

1. A blowout preventer control system, characterized in that, include: Remote control console: The remote control console includes a pressure generating component, a pressure storage component, and a pressure directional control component. The pressure generating component is used to provide hydraulic fluid, the pressure storage component is used to store hydraulic energy, and the pressure directional control component is used to control the flow direction of the hydraulic fluid. The output end of the pressure generating component is connected to the output end of the pressure storage component, the output end of the pressure storage component is connected to the pressure directional control component, the blowout preventer assembly is connected to the pressure directional control component, and the pressure generating component and the pressure directional control component are skid-mounted. Operation Module: The operation module includes a driller's platform and an emergency control box. The driller's platform is connected to the remote control console, and the emergency control box is connected to the remote control console. The emergency control box is equipped with a main control button and a blowout preventer shutdown button. There are multiple emergency control boxes, which are distributed on the drilling platform.

2. The blowout preventer control system according to claim 1, characterized in that, The pressure storage assembly includes an accumulator group and an installation unit. The output end of the pressure generation assembly is connected to the input end of the accumulator group, the output end of the accumulator group is connected to the pressure direction control assembly, and the accumulator group is rotatably connected to the installation unit.

3. The blowout preventer control system according to claim 2, characterized in that, The installation unit includes a support base, a first frame, and a second frame. The first frame and the second frame are rotatably connected to the support base. The first frame and the second frame are arranged relatively parallel to each other. The end of the first frame away from the second frame is detachably connected to the wall panel. The first frame and the second frame are detachably connected to each other.

4. The blowout preventer control system according to claim 1, characterized in that, The blowout preventer assembly is equipped with a flow divider at the top. The operation module includes a flow divider controller, which is connected to the flow divider and to another output terminal of the accumulator assembly. The flow divider controller is used to control the flow divider.

5. The blowout preventer control system according to claim 1, characterized in that, The pressure generating assembly includes an oil tank, an air pump, and an electric pump. The air pump and the electric pump are connected in parallel. A first electric three-way valve is connected to the output end of the oil tank. The three valve ports of the first electric three-way valve are respectively connected to the output end of the oil tank, the input end of the electric pump, and the input end of the air pump. A second electric three-way valve is connected to the input end of the accumulator. The three valve ports of the second electric three-way valve are respectively connected to the output end of the electric pump, the output end of the air pump, and the input end of the accumulator.

6. The blowout preventer control system according to claim 5, characterized in that, A relay is provided between the electric pump and the accumulator group, and the relay is used to automatically control the start and stop of the electric pump.

7. The blowout preventer control system according to claim 5, characterized in that, A relay is provided between the air pump and the accumulator group, and the relay is used to control the start and stop of the air pump.

8. The blowout preventer control system according to claim 1, characterized in that, include: The execution module is used to control the opening action of the distributor valve core and, through the valve core structure, to generate directional fluid dynamics in the drilling fluid, synchronously triggering the pre-sealing action of the gate blowout preventer. The acoustic detection module is used to capture changes in the physical characteristics of the fluid discharged from the distributor in real time, and generates a trigger signal when the change exceeds a preset threshold. A mechanical triggering module is used to respond to the triggering signal and release oil pressure to perform the well shut-in action of the blowout preventer; The control module is used to establish the energy transfer path between the pre-sealing contact force and the shut-in action, and reuse the pre-stored mechanical potential energy to accelerate the closure of the gate blowout preventer when the shut-in action is performed. The emergency linkage channel is used to activate a shut-off mechanism independent of the main control link when the opening angle of the shunt exceeds the first safety threshold.

9. The blowout preventer control system according to claim 8, characterized in that, The dynamic flow field optimization mechanism of the valve core structure includes: An array of piezoelectric ceramic micro-actuators is embedded in the surface of an asymmetric spiral groove to receive viscosity sensor data of drilling fluid in real time. The optimal pitch gradient is adjusted based on the flow resistance characteristics caused by viscosity changes, driving the piezoelectric ceramic micro-actuator array to deform and adjust the groove depth distribution. A distributed pressure sensor array is set on the surface of the guide vane that is linked to the valve core; A wing tilt angle compensation signal is generated based on the pressure distribution data output by the distributed pressure sensor array. The wing plate tilt angle compensation signal is input into the damping controller of the hydraulic piston; The pre-sealed contact force fluctuation is stabilized within a set range based on the dynamic adjustment signal output by the damping controller.

10. The blowout preventer control system according to claim 8, characterized in that, The acoustic detection module captures changes in the physical characteristics of the fluid discharged from the distributor in real time. When the change exceeds a preset threshold, a trigger signal is generated, including: The original acoustic signal of the fluid discharged from the diverter is collected in real time using a piezoelectric ceramic sensor array installed on the wall of the discharge pipe. The original acoustic signal is processed synchronously using a dual-channel processor: the first channel extracts the time-domain attenuation characteristics of the fluid acoustic wave in the target frequency band; the second channel analyzes the vibration transmission characteristics of the hydraulic pipeline. A mechanical vibration noise suppression model is constructed based on the output of the second channel; The output of the first channel is noise-suppressed to generate fluid acoustic characteristics. Simultaneously collect fluid pressure pulsation characteristics of the venting pipeline; Calculate the deviation of the fluid acoustic characteristics from the reference acoustic state; When the deviation exceeds the acoustic threshold and the fluid pressure pulsation characteristic quantity simultaneously exceeds the associated threshold, it is determined that the physical characteristic change quantity exceeds the preset critical value.

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