117 results about "Fluid density" patented technology

The invention discloses a thickener dosing control method and system, and relates to mineral processing. The method comprises the following steps: acquiring concentration values measured by an ith concentration sensor at different depths at a moment t; obtaining the turbidity T of the overflow water, the effective viscosity of the overflow water or underflow, the volume fraction of fine particles and the volume fraction of coarse particles in the overflow water, the Zeta potential of the feeding end, the Zeta potential of the overflow end, the time derivative of the Zeta potential of the overflow end, the equivalent diameter d of the particles, the density of the particles, the density of the fluid and the viscosity of the fluid; calculating the effective settling velocity of the particle swarm; carrying out online correction on the effective settling velocity by utilizing 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 turbidity T of the overflow water according to the corrected concentration profile; respectively calculating a flocculant dosing rate and a coagulant dosing rate; according to the invention, accurate cooperative control of the dosing rate of the flocculating agent and the coagulant is improved through the artificial intelligence model.

The utility model relates to the technical field of petroleum drilling and production, in particular to drilling fluid on-line monitoring equipment which comprises a surge tank, a manual three-way ball valve, an anti-explosion pneumatic ball valve, an anti-explosion pressure transmitter, an overflow chamber, a drain pipe and an anti-explosion temperature transmitter. Fluid is pumped by a pump and guided into a surge tank, temperature measurement is carried out through an anti-explosion temperature transmitter, real-time temperature data are output, high-temperature alarm is carried out through linkage with an anti-explosion pneumatic ball valve, flow adjustment is carried out on the fluid through a manual three-way ball valve, and the fluid continuously flows upwards to an overflow port through the anti-explosion pneumatic ball valve and then overflows into an overflow chamber. And during measurement, the explosion-proof pneumatic ball valve is closed, the fluid in a measurement area is static, the output pressure is measured through the explosion-proof pressure transmitter, the density of the output fluid is calculated by adopting a formula, and the equipment can detect the fluid in real time and give a high-temperature alarm, is rapid in detection and high in efficiency, and is suitable for large-scale popularization and application. The device is suitable for various complex working conditions and fluids.

The invention discloses a density measurement array and a method for inverting a three-dimensional flow field based on a fluid density field change rate. According to the method, a temperature sensing array comprising temperature probes and an array structure is constructed through a temperature sensor, the temperature probes are arranged with a speed measurement point as the center, and the distance range is unequal from the micron level to the meter level. The array structure can adopt various geometric forms such as a rectangle, a circle and the like. Modeling is carried out by measuring a space distribution field of temperature, combining with calibration of a flow velocity meter and utilizing the relation between the temperature distribution change rate and the flow velocity, so that flow velocity information is inverted. By integrating a plurality of arrays, multi-point measurement of a three-dimensional flow field can be realized. According to the method, high-precision flow velocity measurement can be realized in an environment without scattering particles, and the measurement accuracy is further improved through multi-parameter verification. The range of measuring the fluid scale is wide, and an innovative solution is provided for monitoring the fluid flow speed.

The invention discloses an offshore deep continuous foam liquid drainage gas production process pipe column and an operation method, the pipe column comprises a production sleeve, an oil pipe, a lower suspension packer, an upper suspension packer and a continuous oil pipe, a production packer and a top packer are sequentially arranged between the oil pipe and the production sleeve from top to bottom, the oil pipe is located above the production packer for punching, and the continuous oil pipe is located above the production packer for drilling. The lower suspension packer is arranged below the punching position, the upper suspension packer is arranged above the punching position, the upper suspension packer is connected with the lower suspension packer in a sealed mode through an inserting head, and the lower portion of the lower suspension packer is connected with the coiled tubing. A foam scrubbing agent channel from an oil pipe and sleeve annulus to an oil pipe and continuous oil pipe annulus is established through cooperation of multiple tools, the foam scrubbing agent is introduced into a deep shaft liquid accumulation well section below a production packer and above a production layer from the oil pipe and production sleeve annulus, and the fluid density of a shaft is reduced; the mixed fluid is discharged from the continuous oil pipe and the upper oil pipe, and continuous and stable discharging and mining of the gas well are achieved.

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.

A method includes flowing, in a closed loop geothermal well residing in a target subterranean zone, a first heat transfer working fluid and flowing, in the geothermal well, a second working fluid from the surface inlet to the downhole location of the geothermal well. The second working fluid resides upstream of the first heat transfer working fluid. The second working fluid includes a fluid density greater than a fluid density of the first heat transfer working fluid. The method also includes circulating, in the geothermal well, the second working fluid pushing, with the second working fluid, the first heat transfer working fluid toward a surface outlet of the geothermal well. The method also includes collecting energy from the mobilized first heat transfer working fluid received at the surface outlet of the geothermal well.

The invention relates to a safety density window prediction method and device considering fluctuation pressure, a medium and equipment. The method comprises the steps that real-time drilling dynamic parameters of a target well are obtained; on the basis of the real-time drilling dynamic parameters, a steady-state fluctuation pressure prediction model is established in combination with a HZ-Ba fluid model, fluctuation pressure generated in a shaft under the current working condition is dynamically calculated through the steady-state fluctuation pressure prediction model, and the fluctuation pressure comprises excitation pressure and swabbing pressure; carrying out equivalent density conversion on the calculated fluctuation pressure, respectively superposing the calculated fluctuation pressure with a static formation pressure parameter, and updating and outputting a safe drilling fluid density window considering the influence of the fluctuation pressure in real time; the output safe drilling fluid density window considering the fluctuation pressure influence is applied to field drilling fluid density design, and the reasonability of a fluctuation pressure calculation model and the reliability of the safe drilling fluid density window are verified by monitoring whether falling blocks return from the ground or not and monitoring well diameter logging data in real time.

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.

Embodiments of the present application provide a simulation method and device for killing well, electronic equipment, storage medium and product. The method comprises: obtaining a killing well boundary matrix equation, wherein the killing well boundary matrix equation comprises different killing fluid densities and volumes corresponding to each killing fluid density; determining a first time length for killing fluid to reach the bottom of the simulated well drill string from the ground and a second time length for killing fluid to return to the ground from the bottom of the simulated well drill string through the annular space according to the obtained parameter information of the simulated well; and obtaining a third time length, and then determining the distribution data of the killing fluid with different densities in the drill string and the distribution data in the annular space according to the killing well boundary matrix equation, the first time length, the second time length and the third time length. The distribution data in the drill string and the distribution data in the annular space can be used to simulate the distribution state of the killing fluid with different densities in the well. The method improves the flexibility of the killing well simulation method.

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 invention discloses a dynamic optimization method for drilling parameters of a high-sulfur-content stratum, and relates to the technical field of oil-gas field development. The method comprises the following steps that engineering parameters in the drilling process are obtained in real time; the engineering parameters comprise to-be-optimized drilling parameters and hydrogen sulfide concentration; the hydrogen sulfide escape risk index is calculated in combination with engineering parameters, in the formula, H2Srisk represents the hydrogen sulfide escape risk index, CHS represents the hydrogen sulfide concentration, rho represents the drilling fluid density, G represents the geological risk, and k1, k2 and k3 all represent weights. A dynamic optimization function is established and solved, and when the dynamic optimization function value is minimum, the corresponding drilling parameter combination is the optimal drilling parameter combination. According to the method, the escape risk of hydrogen sulfide can be greatly reduced, the mechanical drilling speed is increased, equipment corrosion and vibration are reduced, safety and efficiency are both considered, and the method adapts to complex working conditions and is suitable for various high-sulfur-content stratum drilling scenes.

The invention provides a system for calculating fluid density by using a state equation, and belongs to the field of chemical process simulation. The system is provided with a state equation calculation module which is used for calculating the density solution (real density solution or pseudo density solution) of the system by utilizing a state equation according to the set pressure, temperature and component composition of the fluid system. Wherein the calculation process uses a dual search algorithm to iterate the density until the pressure value or the temperature value converges, and comprises the following steps: dynamically selecting a search path by using local curvature information of a pressure-density function or a temperature-density function: when the curvature of the function meets a solvable condition, constructing a quadratic approximation model to approach a density solution; and when the function curvature does not meet the solvable condition, switching to a first-order approximation model, and determining a density extrapolation starting point in combination with a preset density extrapolation starting point slope threshold. And after the density extrapolation starting point is obtained, the module calculates a pseudo density value through an extrapolation method. The system does not need an analytical solution of a state equation or continuation of a complex field, and the solving efficiency is greatly improved.

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.

The invention discloses a method for predicting the pressure loss of a radiant tube elbow. The method comprises the following steps: performing an experiment to obtain a pressure loss-speed experiment curve of a single radiant tube elbow; constructing a radiant tube elbow physical model, and calculating by using different flow models to obtain a pressure loss-speed calculation curve; comparing the pressure loss-speed experimental curve with the calculation curve, and determining a matched flow model; building radiant tube elbow physical models with different geometric parameters, and calculating corresponding data of different geometric parameters, flow velocity and elbow pressure loss based on the matched flow model; a pressure loss prediction relational expression is established, the pressure loss is a direct proportion function of the bend resistance coefficient and the fluid density, the pressure loss is a power function of the flow speed, and the bend resistance coefficient is a power function of the bending ratio and the bending angle of the bend; and fitting and determining a pressure loss prediction relational expression based on the corresponding data and predicting the pressure loss of the radiant tube elbow. The prediction error of the pressure loss of the radiant tube elbow can be reduced.

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.

A flow control device having a centrifugal clutch that includes a flyweight having a density between that of a target fluid and a non-target fluid. A valve is operably connected to the clutch. A method for discriminating between a target fluid and a nontarget fluid includes rotating a centrifugal clutch having a flyweight whose density is between the target fluid and the nontarget fluid, radially displacing the flyweight when a fluid density of fluid surrounding the centrifugal clutch is less than the density of the flyweight. The method includes driving a valve with the centrifugal clutch to an actuated position. A wellbore system, including a borehole in a subsurface formation, a string in the borehole, and a fluid density discriminator, disposed within or as a part of the string.

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.

Systems and methods for digitally simulating a fluid flow in a three-dimensional computer-aided design (CAD) model of a simulation space include digitally simulating movement of one or more digital particles representing the fluid from one or more first voxels in a mesh to one or more second voxels in the mesh, performing one or more interaction operations on the one or more digital particles at the one or more second voxels to determine a distribution of the one or more digital particles. A first quantity represented by the distribution of the one or more digital particles is based on a temperature and a pressure at the one or more second voxels and a reference fluid density. A second quantity represented by the distribution of the one or more digital particles is based on the reference fluid density, velocities of the one or more digital particles, and a mean fluid velocity.

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.