67 results about "Fluid density" patented technology

The invention discloses a method for predicting the erosion rate of a control manifold of an offshore oil and gas exploration well. The method comprises the following steps: constructing a support vector machine model; wherein the input parameters of the support vector machine model are the manifold diameter, the manifold bending angle, the fluid speed, the fluid density and the fluid viscosity, and the output parameter of the support vector machine is the maximum erosion rate of the well control manifold; optimizing penalty function coefficients and kernel function parameters of the support vector machine model by adopting a genetic algorithm to obtain an optimized support vector machine model; training the optimized support vector machine model to obtain a well control manifold erosion rate prediction model; and acquiring the manifold diameter, manifold bending angle, fluid velocity, fluid density and fluid viscosity of the to-be-predicted well control manifold, and inputting into the well control manifold erosion rate prediction model to obtain the maximum erosion rate of the to-be-predicted well control manifold. According to the well control manifold erosion rate prediction method provided by the invention, the maximum erosion rate of the well control manifold can be accurately predicted.

The invention discloses an integrated intelligent flow sensor and a dynamic compensation system and method thereof.The sensor is of an integrated flow channel structure, a flow sensor, a temperature sensor and a pressure sensor are integrated, and compact design and signal isolation are achieved; the system calls a fluid physical property database by synchronously collecting three-parameter signals, and dynamically calculates the fluid density based on real-time temperature and pressure data; according to the method, the volume flow under the original working condition is dynamically compensated, and the high-precision volume flow and the directly-output mass flow are obtained. Flow measurement is fundamentally upgraded into'multi-parameter-material flow 'conversion based on the physical principle, and high-precision measurement is still guaranteed when the fluid state fluctuates.

The invention relates to an offshore CCUS well building shaft temperature and pressure coupling calculation method which comprises the following steps: substituting an initial temperature and pressure profile of a shaft into a shaft drilling fluid density prediction model to obtain drilling fluid density, and substituting the initial temperature and pressure profile into a rheological property prediction model to obtain drilling fluid viscosity; fluid pressure in the drill stem and fluid pressure in the annulus are obtained; all nodes with shaft pressure prediction differences meeting the precision requirement are selected; the fluid temperature is updated through the temperature model and the fluid density of the node with the difference value meeting the precision requirement of the wellbore pressure prediction difference value of the node; according to the fluid with the updated temperature, adjacent nodes with the shaft pressure prediction difference meeting the precision requirement are selected; selecting nodes corresponding to all fluids of which the circulating flowing time in the shaft meets the preset time requirement from all nodes of which the shaft pressure prediction difference meets the precision requirement; and taking the temperature and the pressure of the node meeting the requirements as final wellbore temperature and pressure profiles.

The present application belongs to the technical field of bearing lubrication state monitoring, and particularly relates to a bearing lubrication state real-time monitoring method based on fluid dynamics model correction, which comprises the following steps: obtaining original vibration acceleration signals and running state data, performing variational modal decomposition on the original vibration acceleration signals to extract cavitation characteristic components; calculating a cavitation kinetic energy impact index according to the extracted cavitation characteristic components and the running state data; dynamically correcting the equivalent fluid density of lubricating oil according to the cavitation kinetic energy impact index and the contact area pressure of the bearing estimated from the running state data; solving the minimum oil film thickness of the lubricating oil film by using the corrected equivalent fluid density, and determining a lubrication safety margin index in combination with the temperature rise rate of the bearing. The present application overcomes the defect that the monitoring result is distorted due to the single-phase fluid assumption, and improves the accuracy of bearing lubrication state monitoring and early risk warning.

The invention discloses an oil-water interface depth determination method and related equipment, and relates to the technical field of oil-gas exploration, and the method comprises the steps: obtaining formation pressure test data and formation test data of a target oil-water system; fluid density under the formation condition is obtained according to the formation testing data, and the straight slope is obtained through calculation; the slope of the straight line is used as a constraint value, in combination with formation pressure test data, a straight line intercept is determined, fluid fitting lines are obtained, and the fluid fitting lines comprise a water layer fitting line and an oil layer fitting line; and determining the oil-water interface depth of the target oil-water system according to the intersection point of the water layer fitting line and the oil layer fitting line. According to the method, the fluid density under the formation condition is obtained by comprehensively utilizing the formation pressure test data and the formation test data, and the oil-water interface depth of the target oil-water system is accurately determined in combination with a scientific fitting analysis method.

The present application relates to a kind of downhole hold rate measurement method, downhole fluid interface and geometric distribution determination method, belong to oil and gas exploration technical field.The downhole hold rate measurement method utilizes multiple tuning forks distributed on flow cross section, realizes oil-water determination by comparing the size of fluid density collected by tuning fork with the size of preset oil-water density distinguishing threshold, realizes the representation of downhole fluid hold rate using the time proportion of oil / water collected by tuning fork, with the advantages of good universality, high measurement efficiency and high resolution.The downhole fluid interface determination method utilizes multiple tuning forks distributed on flow cross section to realize oil-water determination, identifies oil-water interface point according to oil-water alternative switching phenomenon, and determines horizontal well oil-water interface.The downhole fluid geometric distribution determination method utilizes multiple tuning forks distributed on flow cross section to realize oil-water determination, combines local oil hold rate calculation and tuning fork position distribution, and draws fluid geometric distribution diagram.

The present disclosure provides a fluid property measurement apparatus and a fluid property online measurement method. The apparatus includes: a testing cylinder provided with a fluid inlet and a fluid outlet; a liquid stabilizing mechanism including a pre-liquid delivery structure and a gas delivery structure, the pre-liquid delivery structure including a defoaming tank and a detachable pipeline connected thereto, the detachable pipeline being connected to the fluid inlet, and the gas delivery structure including a gas passage capable of injecting gas into the testing cylinder; and a measuring mechanism including a mass detector connected to a bottom of the testing cylinder and a liquid level detector connected within the testing cylinder. The present disclosure solves the problem of online measurement of drilling fluid density in the technical field of fluid measurement.

An improved fluid transfer accuracy, information collection, and overall management. A system may utilize a pump to transfer fluid from a source to a target vessel, a meter for measuring an amount of fluid transferred, a density meter to detect actual fluid density, and a control unit to determine actual fluid transfer amount based on density. As an example, a fluid flow meter can be coupled with a flow conduit to determine fluid volume, along with the density meter to detect real-time density of transferred fluid. During a fluid transfer event, such as aircraft refueling, LPG fueling, or other refined fuels or valuable liquids, fluid volume can be converted to fluid weight in real-time based on actual density. The real-time fluid weight can be used to determine if a target fluid weight has been reached, and fluid flow can be shut off at the appropriate time.

The invention discloses a digital twinning and hanging load coupled well leakage monitoring system and method. According to the system, a full-shaft multi-physics-field coupled digital twinborn model is constructed, a fluid density correction model changing along with pressure and temperature and an unsteady fluid mechanics calculation method are combined, and the theoretical pumping pressure and the theoretical hook hanging load are obtained; based on the deviation between the actually-measured pump pressure and the theoretical pump pressure and the deviation between the actually-measured hook hanging load and the theoretical hook hanging load, a pump pressure-hanging load cooperative judgment mechanism is established, and well leakage state recognition is achieved; determining a well leakage position through a virtual monitoring node arranged along a shaft in combination with pressure wave propagation characteristics; meanwhile, self-adaptive switching of monitoring modes is achieved according to the state of the underground pressure measuring instrument. The accuracy and real-time performance of well leakage identification can be improved, and the influence of temperature and pressure disturbance on the identification result is reduced.

The present invention seeks to solve the problem of hydraulic discontinuity by combining two approaches. It promotes the reduction of fluid density, via dilution of the inhibitor product with a water-based fluid, as well as increasing the fluid flow rate. The first approach reduces the hydrostatic gradient in the injection line, and the second approach increases the pressure drop due to friction in the line. Combined phenomena that prevent hydraulic discontinuity of the injection.To this end, the present invention adds to the surface equipment an assembly of an industrial water tank, pump and a line junction (flow T). This assembly will be responsible for diluting the inhibitor in the injection line, ensuring the minimum inhibitory concentration.

The invention relates to the technical field of oil and gas exploitation, and discloses a thickened carbon dioxide fluid flow friction resistance testing system and method. The method comprises the following steps: S1, liquefying carbon dioxide gas into liquid carbon dioxide; s2, preparing the liquid carbon dioxide, a cosolvent and a thickening agent into a thickened carbon dioxide fluid, and recording the density as shown in the specification; s3, the thickened carbon dioxide fluid is introduced into the testing pipeline, the flow speed of the thickened carbon dioxide fluid introduced into the testing pipeline is as follows, and the pressure difference of the thickened carbon dioxide fluid flowing through the inlet end and the outlet end of the testing pipeline is recorded; s4, calculating the friction resistance coefficient according to a formula (1), wherein D is the diameter of the test pipeline; l is the length of the test pipeline; s1 and S2 are the solubility of the cosolvent and the thickening agent in the liquid carbon dioxide. The invention creatively provides a friction coefficient calculation formula, and the numerical relationship between the friction of the thickened carbon dioxide fluid in the shaft and each parameter can be quickly calculated and evaluated according to the formula.

A fire protection sprinkler including a frame body having an inlet, an outlet, defining an internal passageway extending between the inlet and the outlet along a sprinkler axis. A dome shaped deflector member is centered, axially aligned with the sprinkler axis, and spaced from the outlet. The deflector member has an outer surface and an inner surface that preferably includes: a peripheral region, a central region and an intermediate region. The intermediate region includes a primary deflecting surface, and a secondary deflecting surface that is surrounded by the primary deflecting surface. The deflector member provides for generation of a non-circular spray pattern defined by four zones of fluid density concentrically formed about the sprinkler axis.

The invention discloses a method and an algorithm for determining operation parameters of a refrigerating system of a cold therapy cabin. A sensor in the refrigerating system collects parameters, a flow sensor determines the mass composition of fluid by measuring the density of the fluid, and a pressure and temperature sensor is used for determining state parameters of the fluid. Thermodynamic parameters of the refrigerating system of the cold therapy cabin are calculated, wherein the parameters comprise the liquid-phase refrigerant density, the mass components of all gas-liquid separation components, the enthalpy value of a mixing point of each stage of condensation evaporator, the enthalpy value of each stage of condensation evaporator and the enthalpy value of the evaporator; according to thermodynamic parameters of the refrigeration system, system operation parameters are determined, and cycle components, cooling capacity and system COP are predicted; the thermodynamic efficiency of the refrigeration system is improved by determining the operation parameters of the refrigeration system of the cold therapy cabin and predicting the circulation components, the cooling capacity and the COP of the system through the algorithm, and stable and efficient operation of the refrigeration system of the cold therapy cabin is achieved according to the predicted actual operation parameters.

The invention provides a maximum horizontal principal stress obtaining method based on a Mohr-Coulomb criterion, and belongs to the technical field of reservoir rock mechanics research. The maximum horizontal principal stress obtaining method comprises the steps that formation pore pressure and rock strength parameters are obtained through comprehensive logging data, and drilling fluid column pressure is calculated through drilling fluid density data; measuring the minimum horizontal principal stress; the well wall caving width is obtained through the dual-hole-diameter logging data; according to a calculation equation, factors such as tectonic stress, drilling working conditions and formation fluid are fully considered in the method, and the well wall caving width is obtained through well logging information; indoor rock core testing is not needed; the calculation precision is high, and a scientific basis is provided for oil reservoir engineering, drilling engineering and yield increase engineering.

This invention belongs to the field of oil and gas field development technology and relates to a method for calculating gas well water production based on wellbore pressure gradient. Specifically, it involves acquiring the target gas well's flowing pressure test data, calculating the density of the gas-water two-phase flow mixture at the wellbore flowing pressure test point under the given conditions according to a gas-water two-phase flow model, calculating the water holdup at the wellbore flowing pressure test point under the current conditions based on regional fluid characteristics and the wellbore mixed fluid density, converting the water holdup to a water-gas ratio under standard conditions, and calculating the water production of a single well based on the metered gas production. The gas well water production calculation method based on wellbore pressure gradient established by the above process solves the problem of inaccurate water production measurement in some gas wells, realizing quantitative calculation of gas and water production, which is of great significance for the formulation of gas well production management measures and the refined development of gas fields.

The invention belongs to the technical field of bearing lubrication state monitoring, and particularly relates to a bearing lubrication state real-time monitoring method based on hydrodynamic model correction, and the method comprises the steps: obtaining an original vibration acceleration signal and operation state data, carrying out the variational mode decomposition of the original vibration acceleration signal, and extracting a cavitation feature component; calculating a cavitation kinetic energy impact index according to the extracted cavitation characteristic component and the operation state data; dynamically correcting the equivalent fluid density of the lubricating oil according to the cavitation kinetic energy impact index and the contact area pressure of the bearing estimated by the running state data; and solving the minimum oil film thickness of a lubricating oil film by utilizing the corrected equivalent fluid density, and determining a lubrication safety margin index by combining the temperature rise rate of the bearing. According to the invention, the defect of monitoring result distortion caused by single-phase fluid hypothesis is overcome, and the accuracy of bearing lubrication state monitoring and early risk early warning is improved.

The application belongs to the technical field of flow meter calibration, and discloses a differential pressure transmitter and differential pressure flow meter gas-liquid two-phase flow calculation method and system; the method comprises the following steps: installing a differential pressure flow meter on a gas-liquid two-phase flow pipeline, connecting a differential pressure transmitter to the pressure tapping of the differential pressure flow meter; collecting the real-time output current of the differential pressure transmitter and statistically analyzing it to mark the saturation risk state; when it is detected that the saturation risk state jumps from 1 back to 0, recording the output current in the sampling time length at a preset sampling rate to obtain a recovery waveform, statistically analyzing and calculating the waveform features according to the recovery waveform; based on a preset fingerprint table, inquiring the permanent offset corresponding to the waveform features, compensating the output current converted into an engineering differential pressure value to obtain a corrected differential pressure value; combining fluid density and device parameters to calculate and obtain gas phase mass flow and liquid phase mass flow; the application solves the long-existing precision error of differential pressure type two-phase flow measurement under wide working conditions and dynamic flow patterns.

The invention provides a horizontal well collapse pressure determination method and device, equipment and a storage medium, and the method comprises the steps: for each well section of a target horizontal well, determining horizontal principal stress corresponding to the well section based on the rock mechanics parameters of the well section and a preset horizontal principal stress formula, and determining the collapse pressure of the target horizontal well based on the horizontal principal stress corresponding to the well section; the method comprises the following steps: accumulating the liquid column pressure from 0 according to the cohesive force, the internal friction angle, the formation pore pressure and the effective stress coefficient which are obtained in advance, carrying out iterative processing on a capacity function until the value of the capacity function is equal to 0, and further determining the liquid column pressure corresponding to the capacity function being 0 as the collapse pressure corresponding to a well section. According to the method, the geostress model based on the micro-structure is used as a support, the influence of factors such as liquid column pressure and borehole wall percolation zone pore pressure change is considered at the same time, the collapse pressure is determined accurately and reliably, and technical support can be provided for borehole wall stability of the deep coal horizontal well, optimal design of drilling fluid density, reduction of underground complex accidents and improvement of drilling speed and efficiency.

A method for inferring an inferred speed of sound of a flow fluid is disclosed. The method is conducted by a computer system (200) having a processor (210) and a memory (220), the processor (210) configured to execute instructions from the memory (220) and store data in the memory (220), the memory (220) having a SoS inference module (202). The method includes inferring, by the SoS inference module (202), the inferred speed of sound of the flow fluid based on an inferential relationship between a measured density of the flow fluid and the inferred speed of sound of the flow fluid.

This invention discloses a multi-source fusion monitoring method based on gravity gradient tensor and sedimentary evolution, belonging to the field of water conservancy engineering monitoring technology, including the following steps: Data acquisition: acquiring gravity / gravity gradient data, surface geometric deformation data, and spectral data. Spatial constraint: constructing a dynamic mask using geometric deformation data to constrain the spatial boundary of gravity inversion. Physical enhancement: performing gradient processing or fusion on gravity data to obtain high-resolution mass distribution. Density correction: calculating the dynamic density of sediments over time based on a sedimentary evolution model, and correcting the background fluid density based on spectral data. Coupled solution: substituting the above parameters into the coupling equation to solve for the volume or mass of sediments. This invention can achieve long-term, continuous, non-contact, and quantitative accurate monitoring of reservoir capacity changes and sediment deposition volume through the synergistic fusion of satellite gravity observation, airborne gravity gradient tensor observation, optical remote sensing, and sedimentary physical evolution models.

This invention relates to the field of predictive maintenance technology and discloses a method for predicting the life of flange seals based on digital twins. The method includes: first, acquiring initial parameters to establish an initial reference acoustic energy density; then, acquiring real-time data to calculate the real-time raw acoustic energy density. Phase cancellation is performed based on the node spatial distance and real-time sound velocity to eliminate interference energy and obtain the decoupled true acoustic energy density. The decoupled density is compared with the reference density and substituted into an exponential model to calculate the microcavitation degradation factor. The degradation factor and real-time temperature are used to modulate the fluid density, thereby obtaining the fluid equivalent wave velocity, and combining this with pressure variables to calculate the asynchronous warping phase difference. The real-time residual clamping stress is obtained by reducing the preload stress based on the cosine value of this phase difference and the acoustic energy attenuation ratio. Finally, the transient fatigue damage evolution rate is calculated based on the residual stress and operating time to estimate the remaining life.

The invention discloses a shaft pressure prediction method and system in the well killing fluid injection process, and belongs to the technical field of oil exploitation. According to the initial concentration of calcium ions in well killing fluid and the calcium ion concentration analytic solution, the time-varying value of the concentration of other ions in the well killing fluid is determined; according to the calcium ion concentration analytic solution and the time-varying value of the concentration of other ions in the kill fluid, a function that the density of the kill fluid changes along with time in the injection process is fitted, the real-time density of the kill fluid is determined, by establishing a wellbore pressure calculation model considering the density time-varying effect, wellbore pressure values corresponding to different times are predicted, and the real-time density of the kill fluid is calculated. Therefore, the space-time decay rule of the wellbore pressure is obtained. According to the method, the real-time density of the well killing fluid is determined, a density decay model and a pressure calculation model are coupled, and a wellbore pressure calculation model considering the density time-varying effect is established, so that the chained influence of the performance decay of the well killing fluid on the wellbore pressure environment can be clearly described, and the space-time decay rule of the wellbore pressure is obtained.

The invention relates to an underground holdup measuring method and an underground fluid interface and geometric distribution determining method, and belongs to the technical field of oil-gas exploration. According to the underground holdup measuring method, a plurality of tuning forks distributed on a flow cross section are utilized, oil-water judgment is achieved by comparing the fluid density collected by the tuning forks with a preset oil-water density distinguishing threshold value, and characterization of the underground fluid holdup is achieved by utilizing the time proportion of oil / water collected by the tuning forks. The method has the advantages of good universality, high measurement efficiency and high resolution. According to the method for determining the underground fluid interface, oil-water judgment is achieved through a plurality of tuning forks distributed on a flowing section, an oil-water demarcation point is recognized according to the oil-water alternate switching phenomenon, and the oil-water interface of the horizontal well is determined. According to the underground fluid geometric distribution determination method, oil-water judgment is achieved through a plurality of tuning forks distributed on a flowing cross section, and a fluid geometric distribution diagram is drawn by combining local oil holdup calculation and tuning fork position distribution.

An unloading valve for use in evacuating fluids from a wellbore annulus. The unloading valve can include a valve body, an intake to the valve body, a discharge from the valve body, and an induced pressure differential valve control system configured to automatically close the intake to the valve body in response to a change in the density of fluids passing through the unloading valve. In some embodiments, the induced pressure differential valve control system includes a flow sleeve, a valve element, a draw tube and a biasing spring. The flow sleeve includes a flow constriction that produces a pressure differential (AP) as the fluids pass through the flow sleeve that is communicated by the draw tube to the valve element. The biasing spring is configured to urge the valve element into a closed position when the pressure differential (AP) falls below a threshold value.

The present application relates to the technical field of fault early warning, more specifically, the present application relates to a kind of cutting fluid filling equipment's fault automatic early warning method and system, comprising: the acquisition cutting fluid filling loop's multiple-source flow variable data, include pressure, flow and fluid density data;Based on the pressure data and flow data in the multiple-source flow variable data.The present application constructs impedance factor and the discrete significance of statistics by combining the principle of fluid mechanics, quantifies the severity of failure, and establishes a negative correlation mapping between fault significance and algorithm calculation dimension, improves the extended isolation forest algorithm, automatically reduces the feature dimension to reduce the calculation redundancy when facing serious failure, maintains high-precision in weak failure, thereby solving the problem of slow response and wasted computing power of existing fixed dimension algorithm in high-speed filling scene, realizing real-time, low-latency and accurate early warning.

The invention belongs to the technical field of flowmeter verification, and discloses a gas-liquid two-phase flow calculation method and system for a differential pressure transmitter and a differential pressure flowmeter. The method comprises the following steps: installing a differential pressure flowmeter on a gas-liquid two-phase flow pipeline, and connecting a differential pressure transmitter to a pressure tap of the differential pressure flowmeter; the real-time output current of the differential pressure transmitter is collected and subjected to statistical analysis, so that the saturation risk state is marked; when it is detected that the saturation risk state jumps from 1 to 0, recording the output current within the sampling duration at a preset sampling rate, obtaining a recovery waveform, and carrying out statistical analysis and calculation on waveform characteristics according to the recovery waveform; querying a permanent offset corresponding to the waveform feature based on a preset fingerprint table, and compensating the output current converted into the engineering differential pressure value to obtain a corrected differential pressure value; the gas phase mass flow and the liquid phase mass flow are calculated by combining the fluid density and the device parameters; according to the invention, the problem of long-term precision misalignment of differential pressure type two-phase flow measurement under a wide working condition and a dynamic flow pattern is solved.

A method for performing underground operations includes: allowing fluid to flow through a borehole in an underground formation; providing pressure constraints; providing downhole formation pressure constraints; using a mathematical model to simulate the fluid pressure in the borehole; and using an optimization algorithm to determine boundaries for fluid velocity and fluid density. The optimization algorithm uses pressure constraints and downhole formation constraints to simultaneously determine the boundaries for fluid velocity and fluid density. The method also includes using the determined boundaries to perform the underground operations.

The application discloses a thickener dosing control method and system, relates to mineral processing, and comprises the following steps: obtaining a concentration value measured by an i-th concentration sensor at different depths at time t; obtaining overflow water turbidity T, effective viscosity of overflow water or underflow, volume fraction of fine particles and volume fraction of coarse particles in overflow water, Zeta potential at a feeding end, Zeta potential at an overflow end and time derivative of the Zeta potential at the overflow end, and particle equivalent diameter d, particle density, fluid density and fluid viscosity; calculating an effective settling velocity of a particle group; performing online correction on the effective settling velocity by using a least square method or a Kalman filtering algorithm; performing time lag correction on the concentration values at different depths by using the corrected effective settling velocity; correcting the overflow water turbidity T according to the corrected concentration profile; and respectively calculating a flocculant dosing rate and a coagulant dosing rate; and the application improves the accurate and collaborative control of the flocculant dosing rate and the coagulant dosing rate by using an artificial intelligence model.

The invention provides an online correction method and system for an underground supercritical carbon dioxide venturi tube flowmeter. The online correction method comprises the steps that an initial curve of underground correction is obtained; a corrected zero drift value is obtained, and zero calibration is completed; performing flow coefficient correction on each to-be-corrected well layer of the target well, specifically, keeping a non-detection well layer closed, injecting supercritical carbon dioxide into the to-be-corrected well layer from the ground, and collecting fluid pressure and temperature data; the fluid density and expansion coefficient are calculated through a state equation or an NIST database, the first underground flow is calculated in combination with the outflow coefficient curve, and error comparison is conducted on the first underground flow and the ground injection flow; and if the error exceeds the preset range, calling a corresponding outflow coefficient based on the interval where the Reynolds number is located through an iteration method, and recalculating the second flow until the difference value of the two times of flow calculation meets the precision requirement. On-line and high-precision correction of the downhole flowmeter is achieved, and the measurement accuracy of the supercritical carbon dioxide injection flow is remarkably improved.

The present application relates to a kind of debris flow movement dynamics simulation method and system, wherein the method comprises: determining debris flow movement dynamics control equation according to the flow rate of debris flow fluid;Debris flow movement dynamics control equation includes continuity equation and momentum equation;Debris flow fluid density is obtained according to debris flow movement dynamics control equation;The amount of suspended sediment of suspended sediment and the single-width sediment transport rate of bed surface layer sediment are determined according to the density of debris flow fluid;The thickness of moving load layer is determined using the thickness calculation formula of moving load layer;The shape of the bottom of debris flow gully is calculated using the amount of suspended sediment of suspended sediment, the single-width sediment transport rate of bed surface layer sediment and the thickness of moving load layer thereof.The present application obtains the amount of suspended sediment of suspended sediment, the single-width sediment transport rate of bed surface layer sediment and the thickness of moving load layer thereof based on debris flow movement dynamics control equation, and based on this, the shape of the bottom of debris flow gully can be more accurately calculated, which provides a basis for the design of foundation depth of prevention and control engineering.