Three-phase fluid treatment system applied to oil well site

Abstract

The invention provides a three-phase fluid treatment system applied to an oil well site, which comprises sensor equipment, a liquid level sensor, a liquid level sensor, a liquid level sensor, a liquid level sensor, a liquid level sensor and a liquid level sensor, wherein the sensor equipment is arranged at a wellhead of a target oil well or an inlet / outlet of each level separator; the measuring module is used for measuring the temperature, the pressure, the total mass, the total volume and the gas volume of fluid produced by a wellhead of a target oil well or each stage of separator in a preset monitoring period in real time; the control processor is used for calculating the mass fraction of oil in the liquid phase of the fluid according to the emulsification rate and the emulsification volume coefficient of the fluid, and calculating and outputting the moisture content and the oil-gas ratio of the fluid according to the mass fraction of the oil in the liquid phase of the fluid; and the visual man-machine interaction equipment is used for displaying the determined water content and oil-gas ratio of the fluid in real time through an operation terminal on an oil well site or a remote central control room interface. By means of the scheme, the technical problem that existing water content and oil-gas ratio calculation efficiency and calculation accuracy are low is solved, and the technical effect of accurately and efficiently determining the water content and the oil-gas ratio is achieved.

Description

Technical Field

[0001] The present application belongs to the technical field of oil and gas extraction, and in particular, relates to a three-phase fluid processing system applied to an oil well site. Background Art

[0002] In the process of reservoir development and oil production, the complex phenomenon of the simultaneous existence of three-phase fluids of oil, gas and water often occurs in the wellbore and the ground, and there is also the problem of emulsification or partial emulsification between oil and water.

[0003] At present, the ground separator or test manifold will separate the produced fluid into gas phase and liquid phase (oil + water) for separate measurement. The gas phase is mostly measured by volume or flow meter combined with density conversion to obtain gas production. The liquid phase is generally estimated by online moisture meter or offline sampling and testing to estimate the water cut (Water Cut), and then the volume or flow is added to deduce the production of oil and water. However, when the oil-water ratio or properties of the liquid phase are complex, and there is dissolved gas or free gas, the measurement error of this method is high; and the volume after oil and water emulsification is not a simple linear addition, which is bound to cause calculation errors caused by incomplete oil and water phase separation and delayed phase separation.

[0004] Oil-water emulsification is a multiphase microscopic dispersion phenomenon caused by factors such as colloidal asphaltene in the oil, natural surfactants or added chemicals, and shear force in the pipeline. When part of the water is encapsulated in crude oil to form an emulsion, the molecular structure and interaction will cause the actual volume to expand or shrink. In engineering calculations or daily measurement, in order to simplify the calculation of the emulsified state, it is generally assumed that there is no emulsification (the oil volume and the water volume are regarded as directly added), or it is assumed that it is completely emulsified (all water is emulsified by the oil). In the case of "partial emulsification" or "stage emulsification" (only part of the water is encapsulated by the oil), the water content and oil-gas ratio cannot be accurately determined. Furthermore, when determining the water content and oil-gas ratio, multiple manual collection and measurements are required, which is inefficient.

[0005] With regard to the technical problem of how to automatically and accurately determine the water content and oil-gas ratio when three-phase fluid is partially emulsified, there is currently no effective solution. Summary of the invention

[0006] The purpose of the present application is to provide a three-phase fluid processing system for use at an oil well site, which can automatically and accurately determine the water content and oil-gas ratio of the three-phase fluid.

[0007] The present application provides a three-phase fluid processing system for oil well site, which is implemented as follows:

[0008] A three-phase fluid processing system applied to an oil well site, comprising:

[0009] Sensor equipment, installed at the wellhead of the target oil well or the inlet and outlet of each stage of separator, used to measure in real time the temperature, pressure, total mass, total volume and gas volume of the fluid produced at the wellhead of the target oil well or each stage of separator within a preset monitoring period;

[0010] A memory for storing a pre-established data comparison table, wherein the data comparison table records the emulsification rate, emulsification volume coefficient, oil density, water density and gas density corresponding to the fluid of the target oil well at different temperatures and pressures determined by external experiments;

[0011] A control processor is provided to obtain temperature, pressure, total mass, total volume and gas volume from the sensor device, and obtain, according to the temperature and pressure, the emulsification rate, emulsification volume coefficient, oil density, water density and gas density corresponding to the temperature and pressure just collected by the fluid, calculate the oil mass fraction in the liquid phase of the fluid according to the total mass, total volume, gas volume, gas density, oil density, water density, emulsification rate and emulsification volume coefficient of the fluid, and calculate and output the water content and oil-gas ratio of the fluid according to the oil mass fraction in the liquid phase of the fluid;

[0012] Visual human-computer interaction equipment is used to display the water content and oil-gas ratio of the determined fluid in real time through the operation terminal at the oil well site or the remote central control room interface.

[0013] In one embodiment, the sensor device comprises:

[0014] Temperature detector, used to collect real-time temperature;

[0015] Pressure detector, used to collect real-time pressure.

[0016] In one embodiment, the sensor device comprises:

[0017] Storage tanks are installed at the wellhead of the target oil well or at the entrance and exit of each stage of separators;

[0018] A weight sensor is disposed below the storage tank and is used to detect weight data;

[0019] A cursor is arranged in the storage tank and is used to sense the height of water, oil and gas in the storage tank to determine the total mass, total volume and gas volume of the collected fluid.

[0020] In one embodiment, the three-phase fluid processing system applied to an oil well site further comprises:

[0021] The stirring shear test equipment is arranged in the bypass pipeline, and is used to simulate the actual working conditions by changing the shear strength and temperature, determine the actual expansion ratio or contraction ratio of the fluid volume, so as to determine the emulsification rate and emulsification volume coefficient of the fluid, and store them in the memory.

[0022] In one embodiment, the three-phase fluid processing system applied to an oil well site further comprises:

[0023] The central control equipment is used to adjust the separator pressure and demulsifier injection amount according to the water content and oil-gas ratio.

[0024] In one embodiment, the oil mass fraction in the liquid phase of the fluid is calculated based on the total mass, total volume, gas volume, gas density, oil density, water density, emulsification rate and emulsification volume coefficient of the fluid, including:

[0025] Determine the liquid phase mass and liquid phase volume based on the total mass, total volume, gas volume and gas density of the fluid;

[0026] According to the total mass of the fluid, the gas volume and the gas density, the liquid mass is determined according to the following formula:

[0027] M l =M total -ρ g v g

[0028] Among them, M l Indicates the mass of the liquid phase, M total represents the total mass, v g represents the gas volume, ρ g Indicates gas density;

[0029] Based on the total volume and gas volume, the liquid volume is determined according to the following formula:

[0030] V l =V total -v g

[0031] Among them, V l Represents the volume of the liquid phase, V total Indicates the total volume;

[0032] The oil mass fraction in the liquid phase of the fluid is calculated based on the liquid phase mass, liquid phase volume, emulsification rate, emulsification volume coefficient, oil density and water density of the fluid.

[0033] In one embodiment, the oil mass fraction in the liquid phase of the fluid is calculated based on the liquid phase mass, liquid phase volume, emulsification rate, emulsification volume coefficient, oil density and water density of the fluid, including:

[0034] The oil mass fraction in the liquid phase of the fluid is calculated according to the following formula:

[0035]

[0036] Among them, α represents the oil mass fraction, r represents the emulsification rate, δ represents the emulsification volume coefficient, and M l represents the mass of the liquid phase, ρ w represents the water density, ρ o Indicates oil density, V l Represents the volume of the liquid phase.

[0037] In one embodiment, the oil mass fraction in the liquid phase of the fluid is calculated based on the liquid phase mass, liquid phase volume, emulsification rate, emulsification volume coefficient, oil density and water density of the fluid, including:

[0038] The oil mass fraction in the liquid phase of the fluid is calculated according to the following formula:

[0039]

[0040] Among them, α represents the oil mass fraction, r represents the emulsification rate, δ represents the emulsification volume coefficient, and M l represents the mass of the liquid phase, ρ w represents the water density, ρ o Indicates oil density, V l represents the volume of the liquid phase, and s represents the proportion of the oil phase that can be emulsified.

[0041] In one embodiment, determining the water content of the fluid according to the mass fraction of oil in the liquid phase of the fluid comprises:

[0042] Calculate the moisture content according to the following formula:

[0043]

[0044] Among them, f w represents water content, α represents oil mass fraction, ρ w represents the water density, ρ o Indicates oil density.

[0045] In one embodiment, determining the oil-gas ratio of the fluid according to the mass fraction of oil in the liquid phase of the fluid comprises:

[0046] The oil-gas ratio is calculated according to the following formula:

[0047]

[0048] Where GOR represents the gas-oil ratio, v g represents the gas volume, ρ w represents the water density, ρo Indicates oil density, M total Indicates the total mass.

[0049] The present application provides a three-phase fluid processing system for use at an oil well site, comprising: a sensor device, arranged at the wellhead of a target oil well or at the inlet and outlet of each stage of a separator, for real-time measurement of the temperature, pressure, total mass, total volume and gas volume of the fluid produced at the wellhead of the target oil well or at each stage of a separator within a preset monitoring period; a memory device, for storing a pre-established data comparison table, wherein the data comparison table records the emulsification rate, emulsification volume coefficient, oil density, water density and gas density corresponding to the fluid of the target oil well at different temperatures and pressures determined by external experiments; a control processor, for obtaining the temperature, pressure, total mass, total volume and gas volume of the fluid produced at the wellhead of the target oil well or at each stage of a separator within a preset monitoring period; a memory device, for storing a pre-established data comparison table, wherein the data comparison table records the emulsification rate, emulsification volume coefficient, oil density, water density and gas density corresponding to the fluid of the target oil well at different temperatures and pressures determined by external experiments; and a control processor, for obtaining the temperature, pressure, total mass, total volume and gas volume of the fluid produced at the wellhead of the target oil well or at each stage of a separator from the sensor device. force, total mass, total volume and gas volume, and according to the temperature and pressure, obtain the corresponding emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the fluid at the temperature and pressure just collected, calculate the oil mass fraction in the liquid phase of the fluid according to the total mass, total volume, gas volume, gas density, oil density, water density, emulsification rate and emulsification volume coefficient of the fluid, and calculate and output the water content and oil-gas ratio of the fluid according to the oil mass fraction in the liquid phase of the fluid; a visual human-computer interaction device is used to display the determined water content and oil-gas ratio of the fluid in real time through the operation terminal at the oil well site or the remote central control room interface. That is, through the setting of the sensor device, the oil and gas parameters from the wellhead can be directly collected, and then these parameters are transmitted to the control processor to realize the automatic calculation of the water content and oil-gas ratio, because the emulsification rate and emulsification volume coefficient are introduced in the calculation process, so that the calculation result is more accurate. The above scheme solves the technical problems of low calculation efficiency and accuracy of the existing water content and oil-gas ratio, and achieves the technical effect of accurately and efficiently determining the water content and oil-gas ratio. BRIEF DESCRIPTION OF THE DRAWINGS

[0050] In order to more clearly illustrate the embodiments of the present application or the technical solutions in the prior art, the drawings required for use in the embodiments or the description of the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments recorded in the present application. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying creative labor.

[0051] Figure 1 It is a schematic diagram of the architecture of an embodiment of a three-phase fluid processing system provided by the present application and applied to an oil well site;

[0052] Figure 2 It is a schematic diagram of the architecture of the sensor device provided by this application;

[0053] Figure 3It is a method flow chart of an embodiment of a method for determining the water content and oil-gas ratio of a three-phase system provided by the present application;

[0054] Figure 4 This is a flow chart of a method for automatically calculating water content and oil-gas ratio according to an embodiment of the present application;

[0055] Figure 5 It is a hardware structure block diagram of an electronic device for determining a water content and oil-gas ratio of a three-phase system provided by the present application;

[0056] Figure 6 It is a schematic diagram of the module structure of an embodiment of a device for determining the water content and oil-gas ratio of a three-phase system provided in the present application. DETAILED DESCRIPTION

[0057] In order to enable those skilled in the art to better understand the technical solutions in this application, the technical solutions in the embodiments of this application will be clearly and completely described below in conjunction with the drawings in the embodiments of this application. Obviously, the described embodiments are only part of the embodiments of this application, not all of them. Based on the embodiments in this application, all other embodiments obtained by ordinary technicians in this field without creative work should fall within the scope of protection of this application.

[0058] It should also be noted that in the embodiments of this specification, certain software, components, models and other existing solutions in the industry may be mentioned. They should be regarded as exemplary. Their purpose is only to illustrate the feasibility of implementing the technical solution of this application, but it does not mean that the applicant has or will necessarily use the solution.

[0059] Considering the simultaneous existence of three-phase fluids of oil, gas and water, when the gas phase production is relatively large, if the oil-water distribution is estimated based only on the liquid mass, there will be a large deviation. For example, for some heavy oil wells, the gas specific gravity is high. If the gas mass is ignored, the mass of the liquid phase will be overestimated, which will affect the accuracy of the water content and the gas-oil ratio (GOR). Through the separator parameters and the empirical curve, only volume separation can be done. For example, the gas phase volume is calculated by the separator gas production, and then the remaining mass is regarded as the liquid phase. This method has poor accuracy in the case of severe emulsification. In addition, the conversion of dissolved gas in the oil phase into free gas will also cause inaccurate estimation of the oil phase volume. That is, the existing GOR calculation is generally obtained by assuming that the oil volume is known, but when the oil-water ratio in the liquid phase is unclear or part of the water is emulsified by oil, the oil volume cannot be accurately obtained. If the emulsification or the influence of free gas is ignored, the GOR result will deviate from the actual situation.

[0060] Furthermore, the existing water content calculation method only focuses on the oil-water two-phase (ignoring the gas phase) or only considers the gas phase as a volume deduction, and does not take into account the correction caused by the gas mass. That is, in the existing measurement process, only the presence or absence of emulsification is distinguished, without considering key parameters such as how much water is emulsified and the volume deviation after emulsification, resulting in low accuracy of the calculation results of water content and GOR.

[0061] To this end, a three-phase model is provided in this example that can fully consider the effect of the gas phase on the total mass and can finely distinguish between partial water emulsification and free water stratification. By introducing the emulsification rate (i.e., the proportion of water emulsified) and the emulsification volume coefficient (i.e., quantifying the effect of emulsification expansion or contraction) in the liquid phase, combined with the mass and volume conservation equations, the ratio of the oil and water phases can be obtained. Then, based on this, on the one hand, the water content can be calculated synchronously, and on the other hand, the gas-oil ratio (GOR) can be obtained through the oil phase volume, thereby achieving one-stop, accurate three-phase metering.

[0062] That is, in response to the existing problem of low accuracy in calculating water cut and oil-gas ratio in complex three-phase fluid scenarios, especially when there is an obvious emulsification effect, this example proposes a solution to simultaneously calculate water cut and oil-gas ratio on the premise of known total volume, gas phase information, emulsification rate, and emulsification volume coefficient. This method can accurately determine the water cut and oil-gas ratio, thereby making the measurement and reservoir analysis of the three-phase system more accurate and scientific.

[0063] In this example, a three-phase fluid processing system applied to an oil well site is provided, such as Figure 1 As shown, it may include:

[0064] 1) Sensor equipment 100, which is arranged at the wellhead of the target oil well or the inlet and outlet of each stage separator, is used to measure in real time the temperature, pressure, total mass, total volume and gas volume of the fluid produced at the wellhead of the target oil well or each stage separator within a preset monitoring period;

[0065] 2) A memory 200, for storing a pre-established data comparison table, wherein the data comparison table records the emulsification rate, emulsification volume coefficient, oil density, water density and gas density corresponding to the fluid of the target oil well at different temperatures and pressures determined by external experiments;

[0066] 3) A control processor 300 is used to obtain the temperature, pressure, total mass, total volume and gas volume from the sensor device, and obtain the emulsification rate, emulsification volume coefficient, oil density, water density and gas density corresponding to the temperature and pressure of the fluid collected according to the temperature and pressure, calculate the oil mass fraction in the liquid phase of the fluid according to the total mass, total volume, gas volume, gas density, oil density, water density, emulsification rate and emulsification volume coefficient of the fluid, and calculate and output the water content and oil-gas ratio of the fluid according to the oil mass fraction in the liquid phase of the fluid;

[0067] 4) Visual human-computer interaction device 400, used to display the determined water content and oil-gas ratio of the fluid in real time through the operation terminal at the oil well site or the remote central control room interface.

[0068] The sensor device 100 may include: a temperature detector for collecting real-time temperature; and a pressure detector for collecting real-time pressure. That is, temperature data and pressure data may be obtained through the sensor device.

[0069] Furthermore, the sensor device 100 can also be Figure 2 The device shown includes: a storage tank 210, which is arranged at the wellhead of the target oil well or the entrance and exit of each stage separator; a weight sensor 220, which is arranged below the storage tank and is used to detect weight data; a cursor 230, which is arranged in the storage tank and is used to sense the height of water, oil and gas in the storage tank to determine the total mass, total volume and gas volume of the collected fluid. That is, by arranging a weight sensor for weighing below the storage tank and arranging a cursor in the storage tank, the height of each fluid in the tank is obtained to determine the volume of each fluid.

[0070] After the weight, temperature, pressure, volume and other data are obtained through the sensor equipment, they are transmitted to the control processor, which can directly obtain the water content and oil-gas ratio. That is, in actual field use, it is only necessary to set up a storage tank at the oil outlet, and then measure the height, temperature, pressure, mass and other data to obtain the oil-gas ratio and water content.

[0071] In order to obtain the emulsification rate and emulsification volume coefficient, a stirring shear test device can be set in the three-phase fluid processing system used in the oil well site, and the stirring shear test device is set in the bypass pipeline to simulate the actual working conditions by changing the shear strength and temperature, and determine the actual expansion ratio or contraction ratio of the fluid volume to determine the emulsification rate and emulsification volume coefficient of the fluid, and store them in the memory. The emulsification rate and emulsification volume coefficient can be curve change values ​​set according to the corresponding pressure and temperature.

[0072] In order to control the actual working conditions, the above three-phase fluid processing system applied to the oil well site may also include: a central control device for adjusting the pressure of the separator and the injection amount of the demulsifier according to the water content and the oil-gas ratio.

[0073] The control processor 300 may include: an oil-water-gas three-phase fluid metering device, wherein the oil-water-gas three-phase fluid metering device may include: a gas phase measurement unit, a liquid phase quality detection unit and a calculation control unit connected in sequence, wherein the gas phase measurement unit is used to obtain the gas volume v g and density ρ g And transmit it to the calculation control unit; the liquid mass detection unit is used to combine the total mass of the system to generate the liquid mass M l And provide ρ o , w , δ, r and other parameters; a calculation control unit is used to calculate and output the water content and oil-gas ratio according to the above parameters, and display or transmit the results to the upper system; when the calculation result shows that the oil mass fraction α exceeds the allowable range or the system detects abnormal parameters, it can trigger an automatic alarm or adjust the operating conditions of the separator to re-measure.

[0074] Specifically, the control processor 300 can also obtain data such as the total mass, gas phase volume, gas density, oil-water density, emulsification rate, and emulsification volume coefficient of the three-phase system from the oil field site, separator control system, or downhole / wellhead sensor network. The communication interface and real-time data transmission module of the control processor 300 support wired or wireless communication, and specifically, may include but are not limited to Ethernet, 5G / 4G, industrial bus protocol, or satellite link, etc., for realizing continuous real-time acquisition of sensor or downhole data and transmitting the acquired data to the operation and logic processing module; the operation and logic processing module is embedded with calculation instructions and logic flow corresponding to the above calculation method, which is used to automatically deduct the gas phase mass and volume according to the input real-time data to calculate the total mass and total volume of the liquid phase; establish and solve the partial emulsification volume conservation equation to obtain the oil mass fraction α; calculate the water content and oil-gas ratio based on the solved α; if it is detected that α exceeds the normal range or the emulsification parameters do not match, a warning is issued and data correction or process adjustment is triggered; the database / storage module is used to save model parameters, real-time and historical measurement data, calculated α, f w , GOR and other result information, and supports playback or comparative analysis. The above-mentioned visual human-computer interaction device 400 can specifically display key results such as water content and oil-gas ratio to users in real time through a graphical interface, report or cloud interface, and can interact with external systems (such as separator control unit, upper monitoring platform) for data or control operations, thereby realizing digital management and online automatic control of oilfield production.

[0075] In the process of the fluid produced by the oil well being extracted to the ground through the wellhead, the fluid is first roughly separated by the primary separator, and the produced fluid is still in a state of oil-water-gas three-phase mixture, in which part of the water is emulsified by the oil. For this reason, a three-phase fluid processing system applied to the oil well site can be configured on the separator / gathering pipeline. The three-phase fluid processing system may include: a sensor network, through which the total mass of the three-phase fluid is measured (or the total flow is collected and the total mass is calculated based on the total flow), the gas volume V g (can be obtained by a gas flow meter or volume meter), gas density ρ g (can be converted from an online density meter or state equation), and oil density ρ o , water density ρ w (It can be obtained by placing two online density meters at the oil and water outlets or by temperature and pressure correction). Furthermore, a stirring / shear test unit can be set up to obtain the emulsification rate r and the emulsification volume coefficient δ. In order to obtain more accurate emulsification rate r and emulsification volume coefficient δ, the actual volume expansion / contraction in the test system such as shear strength and temperature can be changed in a bypass line or laboratory simulation device to determine a more accurate emulsification rate r and emulsification volume coefficient δ. In order to obtain more reliable parameters.

[0076] Based on the above-mentioned three-phase fluid processing system applied to the oil well site, a method for determining the water content and oil-gas ratio of a three-phase system is provided in this example. Although the present application provides method operation steps or device structures as shown in the following embodiments or drawings, more or fewer operation steps or module units may be included in the method or device based on routine or no creative labor. In the steps or structures where there is no necessary causal relationship logically, the execution order of these steps or the module structure of the device is not limited to the execution order or module structure described in the embodiments of the present application and shown in the drawings. When the method or module structure described is applied to an actual device or terminal product, it can be connected according to the method or module structure shown in the embodiments or drawings for sequential execution or parallel execution (for example, a parallel processor or a multi-threaded processing environment, or even a distributed processing environment).

[0077] Specifically, Figure 3 As shown, the above method for determining the water content and oil-gas ratio of the three-phase system may include the following steps:

[0078] Step 301: Collect the total mass, total volume and gas volume of the fluid produced at the wellhead of the target oil well within a preset monitoring period, wherein the produced fluid is in a three-phase mixed state of oil, water and gas;

[0079] Step 302: Obtaining the emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the fluid;

[0080] Step 303: Determine the liquid phase mass and liquid phase volume of the fluid according to the total mass, total volume, gas volume and gas density of the fluid;

[0081] Step 304: Calculate the oil mass fraction in the liquid phase of the fluid according to the liquid phase mass, liquid phase volume, emulsification rate, emulsification volume coefficient, oil density and water density of the fluid;

[0082] Specifically, the liquid phase mass and liquid phase volume can be determined based on the total mass, total volume, gas volume and gas density of the fluid. Then, the liquid phase mass can be determined based on the total mass, gas volume and gas density of the fluid according to the following formula:

[0083] M l =M total -ρ g v g

[0084] Among them, M l Indicates the mass of the liquid phase, M total represents the total mass, v g represents the gas volume, ρ g Indicates gas density;

[0085] Then, based on the total volume and gas volume, the liquid volume is determined according to the following formula:

[0086] V l =V total -v g

[0087] Among them, V l Represents the volume of the liquid phase, V total Indicates the total volume;

[0088] Furthermore, the oil mass fraction in the liquid phase of the fluid is calculated based on the liquid phase mass, liquid phase volume, emulsification rate, emulsification volume coefficient, oil density and water density of the fluid.

[0089] For the oil mass fraction, two calculation methods are given in this example:

[0090] Method 1: Calculate the oil mass fraction in the liquid phase of the fluid according to the following formula:

[0091]

[0092] Among them, α represents the oil mass fraction, r represents the emulsification rate, δ represents the emulsification volume coefficient, and M l represents the mass of the liquid phase, ρ w represents the water density, ρ o Indicates oil density, V l Represents the volume of the liquid phase.

[0093] Method 2: Introduce the "oil emulsification rate s", where s represents the proportion of the oil phase that can be emulsified, and then calculate the oil mass fraction in the liquid phase of the fluid according to the following formula:

[0094]

[0095] Among them, α represents the oil mass fraction, r represents the emulsification rate, δ represents the emulsification volume coefficient, and M l represents the mass of the liquid phase, ρ w represents the water density, ρ o Indicates oil density, V l represents the volume of the liquid phase, and s represents the proportion of the oil phase that can be emulsified.

[0096] Step 305: Determine the water content and oil-gas ratio of the fluid according to the mass fraction of oil in the liquid phase of the fluid.

[0097] When implementing, the water content of the fluid can be determined from the mass ratio dimension or the volume ratio dimension:

[0098] For example, the oil-gas ratio in the mass ratio dimension is determined according to the following formula:

[0099]

[0100] Where GOR represents the gas-oil ratio, v g represents the gas volume, ρ w represents the water density, ρ o Indicates oil density, M total Indicates the total mass.

[0101] For example, the oil-gas ratio in the volume ratio dimension is determined as follows:

[0102] The gas volume is converted into the standard volume under standard temperature and pressure. Based on the standard volume, the oil-gas ratio under standard working conditions is calculated according to the following formula:

[0103]

[0104] in, Indicates the standard volume at standard temperature and pressure, V o Represents the volume of the oil phase.

[0105] The water content can be calculated according to the mass fraction of oil in the liquid phase of the fluid using the following formula:

[0106]

[0107] Among them, f wrepresents water content, α represents oil mass fraction, ρ w represents the water density, ρ o Indicates oil density.

[0108] That is, the total mass, total volume and gas volume of the fluid produced at the wellhead of the target oil well within the preset monitoring period, as well as the emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the obtained fluid, are combined to calculate the oil mass fraction in the liquid phase of the fluid, thereby further determining the water content and oil-gas ratio of the fluid. That is, the emulsification rate and emulsification volume coefficient of the fluid are introduced to calculate the water content and oil-gas ratio, thereby solving the technical problem of low accuracy of the existing water content and oil-gas ratio calculation, and achieving the technical effect of efficiently and accurately determining the water content and oil-gas ratio.

[0109] When implemented, the emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the fluid can be determined through external experiments or environmental simulations. Specifically, the emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the target oil well at different temperatures and pressures can be recorded. Then, when used in actual calculations, the temperature and pressure of the wellhead of the target oil well within a preset monitoring period can be collected; a pre-established data comparison table is retrieved, wherein the data comparison table records the emulsification rate, emulsification volume coefficient, oil density, water density and gas density corresponding to the fluid of the target oil well at different temperatures and pressures determined by external experiments; according to the temperature and pressure, the emulsification rate, emulsification volume coefficient, oil density, water density and gas density corresponding to the temperature and pressure are found from the data comparison table; the found emulsification rate, emulsification volume coefficient, oil density, water density and gas density are used as the emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the fluid.

[0110] Furthermore, the water content and oil-gas ratio of the fluid can be determined according to the oil mass fraction in the liquid phase of the fluid in the above manner. After the water content and oil-gas ratio of the fluid are determined, the pressure required for the separator and the injection amount of the emulsifier can be determined according to the water content and the oil-gas ratio. Then, according to the determined pressure required for the separator, the pressure of the separator is adjusted; and the emulsifier is injected according to the determined injection amount of the emulsifier.

[0111] The above method is described below in conjunction with a specific embodiment. However, it should be noted that this specific embodiment is only for better illustrating the present application and does not constitute an improper limitation on the present application.

[0112] Most of the existing methods use a step-by-step approach to determine the water cut and GOR, which requires separate measurements of oil-water and oil-gas separation, resulting in increased equipment and operating costs, as well as the problem of low accuracy of the determined water cut and GOR due to the lack of consideration of the emulsification situation when determining the water cut and GOR. In this case, for the oil-water-gas three-phase mixed fluid commonly found in oilfield well sites and ground gathering and transportation environments, a digital water cut and oil-gas ratio synchronous calculation method and system that takes into account both gas phase mass correction and partial emulsification effect of oil and water is provided. On the basis of conventional three-phase separation and measurement, "gas volume" and "gas density" are introduced to accurately deduct the gas phase mass. Furthermore, "emulsification rate" and "emulsification volume coefficient" are used to quantitatively characterize the volume deviation and dispersion ratio of emulsified water, thereby achieving the following goals:

[0113] 1) Accurately deduct the influence of the gas phase to avoid miscalculating the gas phase mass into the liquid phase under conditions of high gas-oil ratio or significant dissolved gas content, and reduce the calculation errors of water content and oil-gas ratio caused by changes in gas density or measurement deviations.

[0114] 2) Flexible handling of partial emulsification phenomenon, by setting the emulsification rate r and the emulsification volume coefficient δ, distinguishing between "free water" and "emulsified water wrapped in oil", to overcome the technical problem of inaccurate prediction results caused by the existing assumption of no emulsification or full emulsification. Furthermore, in this case, the water cut and the gas-oil ratio are obtained simultaneously, that is, the water content (Water Cut) in the liquid phase and the volume ratio (GOR) of the gas phase to the oil phase can be obtained at the same time through one calculation, which is helpful to improve the separator design, production measurement and dynamic analysis of the reservoir, and reduce the trouble caused by the existing need for multiple equipment or segmented manual operation;

[0115] 3) Digitalization and onlineization. In this case, the formulas and logic processes are embedded in the real-time data acquisition and transmission network of the well site or ground metering system, and the embedded computing unit or host computer software is used to automatically solve the oil-water distribution, water content and oil-gas ratio, support data storage, visualization and remote monitoring, so as to meet the needs of digital and automated management of modern oil fields. The above methods can more comprehensively adapt to various field conditions with high water content, high viscosity, complex emulsification and significant gas phase influence, and provide a simple-to-operate and reliable metering method and its supporting system for oil field production, output fluid metering, separator optimization and reservoir evaluation.

[0116] Specifically, in this example, a three-phase system measurement method is provided that takes partial emulsification into consideration and can simultaneously calculate the water content and the oil-gas ratio, including:

[0117] S1: Measure or obtain the total mass M of the oil-water-gas three-phase system total , total volume V total , gas volume vg and gas density ρ g , calculate the liquid mass M l =M total -ρ g v g and liquid volume V l =V total -v g ;

[0118] S2: Determine the emulsification rate r and the emulsification volume coefficient δ;

[0119] S3: Determine the oil density ρ o and water density ρ w ;

[0120] S4: Calculate the oil mass fraction α in the liquid phase according to the following volume equation:

[0121]

[0122] Wherein, r represents the emulsification rate and δ represents the emulsification volume coefficient.

[0123] S5: After the oil mass fraction α is calculated, the water content is calculated according to the following formula:

[0124]

[0125] The oil-gas ratio is calculated according to the following formula:

[0126]

[0127] Among them, in the above step S2, the emulsification rate r and the emulsification volume coefficient δ can be determined in the following manner: the oil-water mixture to be tested (i.e., the sample) is placed in an adjustable speed stirring or shearing device, and then the actual reservoir environment is simulated by adjusting the stirring time, temperature and shear strength, and the actual volume and phase separation of the reservoir system after emulsification are further determined, thereby obtaining the emulsification rate r and the emulsification volume coefficient δ.

[0128] Among them, in the above step S2, the emulsification rate r and the emulsification volume coefficient δ can also be determined in the following manner: an online sensor is used to monitor the volume change of the mixed liquid in real time, and the emulsification volume coefficient δ is determined according to the volume change of the mixed liquid. Furthermore, the free water ratio is measured in combination with phase separation sampling, and the emulsification rate r is determined according to the free water ratio.

[0129] In the above step S3, the oil density ρ can be determined as follows: o and water density ρ w ; Simulate the reservoir system, temperature and pressure conditions, and then measure the oil density ρ using a laboratory density meter or an online density metero and water density ρ w If the temperature and pressure of the produced fluid change, the oil density ρ o and water density ρ w Make corresponding conversions to ensure that the gas phase density ρ g The parameters are in the same working condition.

[0130] In this example, the calculation of the gas-oil ratio (GOR) is extended to accommodate different gas conditions. When the GOR needs to be defined under standard conditions, the V measured on site can be used as the GOR. g Converted to V at standard temperature and pressure g std , and then substitute it into the following formula to obtain the GOR under standard conditions, that is, GOR std :

[0131]

[0132] Furthermore, in the case where the gas is partially dissolved in the oil phase, the free gas V can be re-determined after deducting the dissolved gas content. g Then, based on the re-determined v g To calculate GOR, the calculation results are more consistent with the actual conditions of the on-site separator or process.

[0133] Considering that different emulsification situations have different impacts on the results, in order to adapt to more scenario requirements, in this example, in addition to introducing α, the "oil emulsification rate s" is also introduced for the volume conservation equation, where s represents the proportion of the oil phase that can be emulsified. Based on this, the volume conservation equation is expanded to:

[0134]

[0135] Through this multi-parameter coupling solution, the results can meet more complex emulsification scenarios. Similarly, after determining α, the water content f can be calculated in the above way. w with GOR.

[0136] The above moisture content f w GOR can be used in the automatic metering system on the oil field site by measuring ρ g 、v g 、M total 、V total , o , w , δ, r and other parameters are input into the embedded computing unit, and α is obtained in real time. Then, the moisture content f is calculated and output. w and GOR; when detected Or if the value of α is too large or too small, the system will automatically alarm or trigger data correction.

[0137] Specifically, the above method can be linked with the operating status of the demulsification equipment or the multi-stage separator, and the moisture content f calculated in real time can be used to calculate the moisture content f. w and GOR, automatically adjusting the separator pressure or emulsifier injection volume to optimize separation efficiency. For situations with ultra-high water content or high gas-oil ratio, early warnings can be issued and corresponding process adjustments can be made to improve the separation effect of oil-water and gas-liquid.

[0138] In this example, an oil-water-gas three-phase fluid metering device is also provided, comprising: a gas phase measurement unit, a liquid phase quality detection unit and a calculation control unit connected in sequence, wherein the gas phase measurement unit is used to obtain the gas volume v g and density ρ g And transmit it to the calculation control unit; the liquid mass detection unit is used to combine the total mass of the system to generate the liquid mass M l And provide ρ o , w , δ, r and other parameters; a calculation control unit, used to calculate and output the water content and oil-gas ratio according to the above parameters, and display or transmit the results to the upper system; when the calculation result shows that the oil mass fraction α exceeds the allowable range or the system detects abnormal parameters, it triggers an automatic alarm or adjusts the operating conditions of the separator.

[0139] In this example, a digital system is also provided, including: a data acquisition module, a communication interface and real-time data transmission module, an operation and logic processing module, a database / storage module, and a visualization / human-computer interaction module, wherein the data acquisition module is used to obtain the total mass, gas volume, gas density, oil-water density, emulsification rate, emulsification volume coefficient and other data of the three-phase system from the oil field site, separator control system or downhole / wellhead sensor network; the communication interface and real-time data transmission module supports wired or wireless communication methods, specifically, it can include but is not limited to Ethernet, 5G / 4G, industrial bus protocol or satellite link, etc., for realizing the sensor or downhole Continuous real-time data collection and transmission of the collected data to the calculation and logic processing module; the calculation and logic processing module is embedded with calculation instructions and logic processes corresponding to the above calculation method, which is used to automatically deduct the gas phase mass and volume according to the input real-time data to calculate the total mass and volume of the liquid phase; establish and solve the partial emulsification volume conservation equation to obtain the oil mass fraction α; calculate the water content and oil-gas ratio based on the solved α; if it is detected that α exceeds the normal range or the emulsification parameters do not match, a warning is issued and data correction or process adjustment is triggered; the database / storage module is used to save model parameters, real-time and historical measurement data, calculated α, f w, GOR and other result information, and supports playback or comparative analysis; the visualization / human-computer interaction module is used to display key results such as water cut and oil-gas ratio to users in real time through a graphical interface, report or cloud interface, and can interact with external systems (such as separator control unit, upper monitoring platform) for data or control operations, thereby realizing digital management and online automatic regulation of oilfield production.

[0140] The above-mentioned oil-water-gas three-phase fluid processing system may include:

[0141] 1) Wellsite / separator environment:

[0142] In the process of the fluid produced by the oil well being extracted to the ground through the wellhead, after the fluid is roughly separated by the primary separator, the produced fluid still presents a three-phase mixture of oil, water and gas, in which part of the water is emulsified by the oil. For this reason, a set of digital metering system can be configured on the separator / gathering pipeline. The digital metering system may include: a sensor network, which measures the total mass of the three-phase fluid (or collects the total flow and converts the total mass based on the total flow), the gas volume V g (can be obtained by a gas flow meter or volume meter), gas density ρ g (can be converted from an online density meter or state equation), and oil density ρ o , water density ρ w (It can be obtained by placing two online density meters at the oil and water outlets or by temperature and pressure correction). Furthermore, a stirring / shear test unit can be set up to obtain the emulsification rate r and the emulsification volume coefficient δ. In order to obtain more accurate emulsification rate r and emulsification volume coefficient δ, the actual volume expansion / contraction in the test system such as shear strength and temperature can be changed in a bypass line or laboratory simulation device to determine a more accurate emulsification rate r and emulsification volume coefficient δ. In order to obtain more reliable parameters.

[0143] 2) Digital systems include:

[0144] Data acquisition module and communication interface for real-time acquisition of v from sensors or separator control systems g 、M total 、V total , o , w , δ and r, and transmit the data to the calculation and logic processing module through 4G / 5G network or industrial Ethernet;

[0145] The calculation and logic processing module is used to embed the core formula and solution algorithm, automatically deduct the gas phase mass, establish the liquid phase volume equation to solve α, and then calculate the moisture content f based on the calculated α w and gas-oil ratio GOR;

[0146] Database / storage module, used to save operating parameters, historical data and calculation results;

[0147] The visualization / human-computer interaction module is used to display the calculation results in real time and retrieve historical data remotely through the well site operation terminal or the remote control room interface.

[0148] Taking a specific example as an example, a gas flow meter and a gas density meter with temperature and pressure compensation function are installed at the oil well site. The gas volume v is obtained in real time through the gas flow meter and the gas density meter. g (m 3 / h level) and gas density ρ g (kg / m 3 ), and the obtained gas volume V g (m 3 / h level), and the gas density ρ g (kg / m 3 ) is transmitted to the communication module in real time. Assuming that the v sampled in the current acquisition period is g =0.35m 3 , g =kg / m 3 .

[0149] A high-precision mass flow meter or weighing sensor is configured at the oil well site to obtain the total mass M of the system. total ; and the total volume V of the container can be determined by equipment calibration or comprehensive measurement total For example: M total =1500kg, V total =2.0m 3 The oil density and water density are measured under the same temperature and pressure conditions or calibrated by PVT (Process Verification Test, small batch process verification test): ρ o =850kg / m 3 , ρ w =1000kg / m 3 Through bypass piping or online sampling tests, it is determined that under the current flow and temperature conditions, about 40% of the water enters the emulsion, and the volume is measured to have an expansion of about 3%. Based on this, it can be determined that the emulsification rate r = 0.4 and the emulsification volume coefficient δ = 1.03.

[0150] Furthermore, for more extreme temperature and pressure conditions, PVT corrections can be made to the oil density, water density and gas volume. To this end, if the oil well uses a multi-stage separation system, the gas phase data and liquid phase data can be measured separately at the inlet and outlet of each stage of the separator to perform PVT on the data, thereby improving the measurement accuracy.

[0151] Based on the multiple parameters obtained above, the following Figure 4 The water content and oil-gas ratio are automatically calculated in the following way:

[0152] S1: Calculate the liquid mass and volume:

[0153] M l =M total -ρ g v g =1500-(2×0.35)=1500-0.7=1499.3kg

[0154] V l =V total -v g =2-0.35=1.65m 3

[0155] S2: Establish the volume conservation equation:

[0156]

[0157] Let α = M o / M l The above values ​​are substituted one by one, and the linear solver in the operation and logic processing module is used to automatically calculate the oil mass fraction α=0.68, which means that the oil accounts for about 68% of the liquid phase mass.

[0158] S3: Calculate the moisture content f w :

[0159]

[0160] S4: Calculate the gas-oil ratio GOR:

[0161] Oil phase volume:

[0162]

[0163] Oil-gas ratio:

[0164]

[0165] Furthermore, if it is necessary to determine the GOR under standard conditions, the gas volume can be further converted to the standard conditions, and then the ratio is calculated to determine the GOR under standard conditions.

[0166] For the above-mentioned digital system, the results can be displayed and automatically fed back. Specifically, the calculation and logic processing module can calculate the f w =0.28, GOR = 0.29 (dimensionless or m 3 / m 3form) into the database and displayed in real time on the visualization module interface; if in the next measurement cycle ρ g or v g If the values ​​of parameters such as Alternatively, if the value of α is too large or too small, the system can issue a warning and suggest that the field engineer check the operating status of the sensor or separator, clean the storage tank, and re-run the f w and calculation of GOR.

[0167] In the above example, the sensor data and calculation results can be transmitted back to the oilfield control room or cloud platform through 4G / 5G or industrial Ethernet; for the control room, the separator pressure, demulsifier injection volume or production capacity allocation can be adjusted according to the real-time water content and GOR distribution of each well site / separator, thereby improving the separation efficiency and system stability. In this way, the water content and GOR are centrally determined, avoiding the problem of overly cumbersome process caused by estimating the water content separately and then manually calculating the oil-gas ratio. Furthermore, this method is closer to the actual three-phase partial emulsification conditions, which can improve the accuracy of the determined water content, especially in the case of high water content, high viscosity and easy emulsification wells, which can reduce the measurement error, thereby realizing the fine control of the difference between dissolved gas and free gas, and can effectively grasp the dynamic changes of the oil-gas ratio, which is of great value for pipeline transportation and reservoir evaluation.

[0168] Through the above method, the water content and oil-gas ratio can be accurately calculated in the actual well site environment, and the results can be digitally displayed and transmitted, so as to effectively guide the oil and gas production process.

[0169] The method embodiments provided in the above embodiments of the present application can be executed in a mobile terminal, a computer terminal or a similar computing device. Taking running on an electronic device as an example, Figure 5 This is a hardware structure block diagram of an electronic device for determining the water content and oil-gas ratio of a three-phase system provided by this application. Figure 5 As shown, the electronic device 10 may include one or more (only one is shown in the figure) processors 02 (the processor 02 may include but is not limited to a processing device such as a microprocessor MCU or a programmable logic device FPGA), a memory 04 for storing data, and a transmission module 06 for communication functions. It can be understood by those skilled in the art that Figure 5 The structure shown is only for illustration and does not limit the structure of the above electronic device. Figure 5 More or fewer components as shown, or with Figure 5 Different configurations shown.

[0170] The memory 04 can be used to store software programs and modules of application software, such as program instructions / modules corresponding to the method for determining the water content and oil-gas ratio of the three-phase system in the embodiment of the present application. The processor 02 executes various functional applications and data processing by running the software programs and modules stored in the memory 04, that is, the method for determining the water content and oil-gas ratio of the three-phase system of the above-mentioned application is realized. The memory 04 may include a high-speed random access memory, and may also include a non-volatile memory, such as one or more magnetic storage devices, flash memory, or other non-volatile solid-state memory. In some examples, the memory 04 may further include a memory remotely arranged relative to the processor 02, and these remote memories may be connected to the electronic device 10 via a network. Examples of the above-mentioned network include, but are not limited to, the Internet, an intranet, a local area network, a mobile communication network, and combinations thereof.

[0171] The transmission module 06 is used to receive or send data via a network. The specific example of the above network may include a wireless network provided by a communication provider of the electronic device 10. In one example, the transmission module 06 includes a network adapter (Network Interface Controller, NIC), which can be connected to other network devices through a base station so as to communicate with the Internet. In one example, the transmission module 06 can be a radio frequency (Radio Frequency, RF) module, which is used to communicate with the Internet wirelessly.

[0172] At the software level, the water content and oil-gas ratio determination device of the three-phase system can be as follows: Figure 6 As shown, including:

[0173] The acquisition module 601 is used to acquire the total mass, total volume and gas volume of the fluid produced at the wellhead of the target oil well within a preset monitoring period, wherein the produced fluid is in a three-phase mixed state of oil, water and gas;

[0174] An acquisition module 602 is used to acquire the emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the fluid;

[0175] A first determination module 603 is used to determine the liquid phase mass and liquid phase volume of the fluid according to the total mass, total volume, gas volume and gas density of the fluid;

[0176] A calculation module 604 is used to calculate the oil mass fraction in the liquid phase of the fluid according to the liquid phase mass, liquid phase volume, emulsification rate, emulsification volume coefficient, oil density and water density of the fluid;

[0177] The second determination module 605 is used to determine the water content and the oil-gas ratio of the fluid according to the mass fraction of oil in the liquid phase of the fluid.

[0178] In one embodiment, the calculation module 604 may be specifically configured to calculate the oil mass fraction in the liquid phase of the fluid according to the following formula:

[0179]

[0180] Among them, α represents the oil mass fraction, r represents the emulsification rate, δ represents the emulsification volume coefficient, and M l represents the mass of the liquid phase, ρ w represents the water density, ρ o Indicates oil density, V l Represents the volume of the liquid phase.

[0181] In one embodiment, the calculation module 604 may be specifically configured to calculate the oil mass fraction in the liquid phase of the fluid according to the following formula:

[0182]

[0183] Among them, α represents the oil mass fraction, r represents the emulsification rate, δ represents the emulsification volume coefficient, and M l represents the mass of the liquid phase, ρ w represents the water density, ρ o Indicates oil density, V l represents the volume of the liquid phase, and s represents the proportion of the oil phase that can be emulsified.

[0184] In one embodiment, the second determination module 605 may be specifically used to calculate the moisture content according to the following formula:

[0185]

[0186] Among them, f w represents water content, α represents oil mass fraction, ρ w represents the water density, ρ o Indicates oil density.

[0187] In one embodiment, the second determination module 605 may be used to calculate the oil-gas ratio according to the following formula:

[0188]

[0189] Where GOR represents the gas-oil ratio, v g represents the gas volume, ρ w represents the water density, ρ o Indicates oil density, M total Indicates the total mass.

[0190] In one embodiment, after determining the oil-gas ratio of the fluid according to the mass fraction of oil in the liquid phase of the fluid, the second determination module 605 may also convert the gas volume into a standard volume at a standard temperature and pressure; and calculate the oil-gas ratio under standard working conditions according to the standard volume according to the following formula:

[0191]

[0192] in, Indicates the standard volume at standard temperature and pressure, V o Represents the volume of the oil phase.

[0193] In one embodiment, the acquisition module 602 can specifically collect the temperature and pressure of the target oil well wellhead within a preset monitoring period; call a pre-established data comparison table, wherein the data comparison table records the emulsification rate, emulsification volume coefficient, oil density, water density and gas density corresponding to the fluid of the target oil well determined by external experiments at different temperatures and pressures; according to the temperature and pressure, find out the emulsification rate, emulsification volume coefficient, oil density, water density and gas density corresponding to the temperature and pressure from the data comparison table; use the found emulsification rate, emulsification volume coefficient, oil density, water density and gas density as the emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the fluid.

[0194] In one embodiment, the water content and oil-gas ratio of the above-mentioned three-phase system are determined. After the water content and oil-gas ratio of the fluid are determined according to the oil mass fraction in the liquid phase of the fluid, the required pressure of the separator and the required injection amount of the emulsifier can also be determined according to the water content and the oil-gas ratio; the pressure of the separator is adjusted according to the determined required pressure of the separator; and the emulsifier is injected according to the determined required injection amount of the emulsifier.

[0195] Each embodiment in this specification is described in a progressive manner, and the same or similar parts between the embodiments can be referred to each other, and each embodiment focuses on the differences from other embodiments. In particular, for the hardware + program embodiment, since it is basically similar to the method embodiment, the description is relatively simple, and the relevant parts can be referred to the partial description of the method embodiment.

[0196] The above is a description of a specific embodiment of the specification. Other embodiments are within the scope of the appended claims. In some cases, the actions or steps recorded in the claims can be performed in an order different from that in the embodiments and still achieve the desired results. In addition, the processes depicted in the drawings do not necessarily require the specific order or continuous order shown to achieve the desired results. In some embodiments, multitasking and parallel processing are also possible or may be advantageous.

[0197] Although the present application provides method operation steps as described in the embodiments or flowcharts, more or fewer operation steps may be included based on conventional or non-creative labor. The order of steps listed in the embodiments is only one way of executing the order of many steps and does not represent the only execution order. When the actual device or client product is executed, it can be executed in the order of the method shown in the embodiments or the drawings or in parallel (for example, in a parallel processor or multi-threaded processing environment).

[0198] Although the present specification embodiment provides the method operation steps as described in the embodiment or flow chart, more or less operation steps may be included based on conventional or non-creative means. The order of steps listed in the embodiment is only one way in the order of execution of many steps, and does not represent a unique execution order. When the device or terminal product in practice is executed, it can be executed in sequence or in parallel (such as a parallel processor or a multi-threaded processing environment, or even a distributed data processing environment) according to the method shown in the embodiment or the accompanying drawings. The term "include", "comprise" or any other variant thereof is intended to cover non-exclusive inclusion, so that the process, method, product or equipment including a series of elements not only includes those elements, but also includes other elements not clearly listed, or also includes elements inherent to such process, method, product or equipment. In the absence of more restrictions, it is not excluded that there are other identical or equivalent elements in the process, method, product or equipment including the elements.

[0199] For the convenience of description, the above devices are described in various modules according to their functions. Of course, when implementing the embodiments of this specification, the functions of each module can be implemented in the same or more software and / or hardware, or the module implementing the same function can be implemented by a combination of multiple sub-modules or sub-units. The device embodiments described above are only schematic. For example, the division of the units is only a logical function division. There may be other division methods in actual implementation. For example, multiple units or components can be combined or integrated into another system, or some features can be ignored or not executed. Another point is that the mutual coupling or direct coupling or communication connection shown or discussed can be through some interfaces, indirect coupling or communication connection of devices or units, which can be electrical, mechanical or other forms.

[0200] Those skilled in the art also know that, in addition to implementing the controller in a purely computer-readable program code, the controller can be made to implement the same function in the form of logic gates, switches, application-specific integrated circuits, programmable logic controllers, and embedded microcontrollers by logically programming the method steps. Therefore, such a controller can be considered as a hardware component, and the devices for implementing various functions included therein can also be considered as structures within the hardware component. Or even, the devices for implementing various functions can be considered as both software modules for implementing the method and structures within the hardware component.

[0201] The present application is described with reference to the flowcharts and / or block diagrams of the methods, devices (systems), and computer program products according to the embodiments of the present application. It should be understood that each process and / or box in the flowchart and / or block diagram, as well as the combination of the processes and / or boxes in the flowchart and / or block diagram, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, a special-purpose computer, an embedded processor, or other programmable data processing device to generate a machine, so that the instructions executed by the processor of the computer or other programmable data processing device generate instructions for implementing the processes in the flowchart and / or block diagram. Figure 1 A process or multiple processes and / or boxes Figure 1 A device that provides the functions specified in a block or multiple blocks.

[0202] Those skilled in the art will appreciate that the embodiments of this specification may be provided as methods, systems or computer program products. Therefore, the embodiments of this specification may take the form of complete hardware embodiments, complete software embodiments or embodiments combining software and hardware. Moreover, the embodiments of this specification may take the form of a computer program product implemented on one or more computer-usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) containing computer-usable program codes.

[0203] The present specification embodiments may be described in the general context of computer-executable instructions executed by a computer, such as program modules. Generally, program modules include routines, programs, objects, components, data structures, etc. that perform specific tasks or implement specific abstract data types. The present specification embodiments may also be practiced in distributed computing environments where tasks are performed by remote processing devices connected through a communication network. In a distributed computing environment, program modules may be located in local and remote computer storage media, including storage devices.

[0204] Each embodiment in this specification is described in a progressive manner, and the same and similar parts between the embodiments can be referred to each other, and each embodiment focuses on the differences from other embodiments. In particular, for the system embodiment, since it is basically similar to the method embodiment, the description is relatively simple, and the relevant parts can be referred to the partial description of the method embodiment. In the description of this specification, the description of the reference terms "one embodiment", "some embodiments", "example", "specific example", or "some examples" means that the specific features, structures, materials or characteristics described in conjunction with the embodiment or example are included in at least one embodiment or example of the embodiment of this specification. In this specification, the schematic representation of the above terms does not necessarily target the same embodiment or example. Moreover, the specific features, structures, materials or characteristics described can be combined in any one or more embodiments or examples in a suitable manner. In addition, in the absence of contradiction, a person skilled in the art can combine and combine the different embodiments or examples described in this specification and the features of different embodiments or examples.

[0205] The above is only an example of the embodiment of the present specification and is not intended to limit the embodiment of the present specification. For those skilled in the art, the embodiment of the present specification may have various changes and variations. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the embodiment of the present specification shall be included in the scope of the claims of the embodiment of the present specification.

Claims

1. A three-phase fluid treatment system applied to an oil well site, characterized in that: include: Sensor equipment, installed at the wellhead of the target oil well or the inlet and outlet of each stage of separator, used to measure in real time the temperature, pressure, total mass, total volume and gas volume of the fluid produced at the wellhead of the target oil well or each stage of separator within a preset monitoring period; A memory for storing a pre-established data comparison table, wherein the data comparison table records the emulsification rate, emulsification volume coefficient, oil density, water density and gas density corresponding to the fluid of the target oil well at different temperatures and pressures determined by external experiments; a control processor, configured to obtain temperature, pressure, total mass, total volume and gas volume from the sensor device, and obtain, based on the temperature and pressure, the emulsification rate, emulsification volume coefficient, oil density, water density and gas density corresponding to the fluid at the collected temperature and pressure, calculate the oil mass fraction in the liquid phase of the fluid based on the total mass, total volume, gas volume, gas density, oil density, water density, emulsification rate and emulsification volume coefficient of the fluid, and calculate and output the water content and oil-gas ratio of the fluid based on the oil mass fraction in the liquid phase of the fluid; Visual human-computer interaction equipment is used to display the water content and oil-gas ratio of the determined fluid in real time through the operation terminal at the oil well site or the remote central control room interface.

2. The three-phase fluid treatment system applied to an oil well site according to claim 1, characterized in that: The sensor device comprises: Temperature detector, used to collect real-time temperature; Pressure detector, used to collect real-time pressure.

3. The three-phase fluid treatment system for oil well site according to claim 1, characterized in that: The sensor device comprises: Storage tanks are installed at the wellhead of the target oil well or at the entrance and exit of each stage of separators; A weight sensor is disposed below the storage tank and is used to detect weight data; A cursor is arranged in the storage tank and is used to sense the height of water, oil and gas in the storage tank to determine the total mass, total volume and gas volume of the collected fluid.

4. The three-phase fluid treatment system for oil well site according to claim 1, characterized in that: Also includes: The stirring shear test equipment is arranged in the bypass pipeline, and is used to simulate the actual working conditions by changing the shear strength and temperature, determine the actual expansion ratio or contraction ratio of the fluid volume, so as to determine the emulsification rate and emulsification volume coefficient of the fluid, and store them in the memory.

5. The three-phase fluid treatment system for oil well site according to claim 1, characterized in that: Also includes: The central control equipment is used to adjust the separator pressure and demulsifier injection amount according to the water content and oil-gas ratio.

6. The three-phase fluid treatment system for oil well site according to claim 1, characterized in that: The oil mass fraction in the liquid phase of the fluid is calculated based on the total mass, total volume, gas volume, gas density, oil density, water density, emulsification rate and emulsification volume coefficient of the fluid, including: Determine the liquid phase mass and liquid phase volume based on the total mass, total volume, gas volume and gas density of the fluid; According to the total mass of the fluid, the gas volume and the gas density, the mass of the liquid phase is determined according to the following formula: M l =M total -r g v g Among them, M l Indicates the mass of the liquid phase, M total represents the total mass, v g represents the gas volume, ρ g Indicates gas density; Based on the total volume and gas volume, the liquid volume is determined according to the following formula: V l =V total -v g Among them, V l Represents the volume of the liquid phase, V total Indicates the total volume; The oil mass fraction in the liquid phase of the fluid is calculated based on the liquid phase mass, liquid phase volume, emulsification rate, emulsification volume coefficient, oil density and water density of the fluid.

7. The three-phase fluid treatment system for use at an oil well site according to claim 6, characterized in that: The oil mass fraction in the liquid phase of the fluid is calculated according to the liquid phase mass, liquid phase volume, emulsification rate, emulsification volume coefficient, oil density and water density of the fluid, including: The oil mass fraction in the liquid phase of the fluid is calculated according to the following formula: Among them, α represents the oil mass fraction, r represents the emulsification rate, δ represents the emulsification volume coefficient, and M l represents the mass of the liquid phase, ρ w represents the water density, ρ o Indicates oil density, V l Represents the volume of the liquid phase.

8. The three-phase fluid treatment system for oil well site according to claim 6, characterized in that: The oil mass fraction in the liquid phase of the fluid is calculated according to the liquid phase mass, liquid phase volume, emulsification rate, emulsification volume coefficient, oil density and water density of the fluid, including: The oil mass fraction in the liquid phase of the fluid is calculated according to the following formula: Among them, α represents the oil mass fraction, r represents the emulsification rate, δ represents the emulsification volume coefficient, and M l represents the mass of the liquid phase, ρ w represents the water density, ρ o Indicates oil density, V l represents the volume of the liquid phase, and s represents the proportion of the oil phase that can be emulsified.

9. The three-phase fluid treatment system for oil well site according to claim 1, characterized in that: Determining the water content of the fluid according to the mass fraction of oil in the liquid phase of the fluid comprises: Calculate the moisture content according to the following formula: Among them, f w represents water content, α represents oil mass fraction, ρ w represents the water density, ρ o Indicates oil density.

10. The three-phase fluid processing system for oil well site according to claim 1, characterized in that: Determining the oil-gas ratio of the fluid according to the mass fraction of oil in the liquid phase of the fluid comprises: The oil-gas ratio is calculated according to the following formula: Where GOR represents the gas-oil ratio, v g represents the gas volume, ρ w represents the water density, ρ o Indicates oil density, M total Indicates the total mass.

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