Method for determining water cut and oil-gas ratio in a three-phase system

Abstract

The application provides a method for determining water content and oil-gas ratio of a three-phase system, which comprises the following steps: collecting total mass, total volume and gas volume of fluid produced by a target wellhead within a preset monitoring period, wherein the produced fluid is in a three-phase mixed state of oil, water and gas; obtaining emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the fluid; determining 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; calculating 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; and determining water content and oil-gas ratio of the fluid according to the oil mass fraction in the liquid phase of the fluid. The above scheme solves the technical problem that the existing water content and oil-gas ratio calculation has low accuracy, and achieves the technical effect of efficiently and accurately determining the water content and oil-gas ratio.

Description

TECHNICAL FIELD

[0001] The application belongs to the technical field of oil and gas exploitation, and particularly relates to a method for determining water content and oil-gas ratio of a three-phase system. BACKGROUND

[0002] In the process of reservoir development and oil production, complex phenomena of simultaneous existence of oil, gas and water three-phase fluid often occur in wellbore and ground links, and emulsification or partial emulsification problems exist between oil and water.

[0003] At present, the ground separator or test manifold separates and measures the output fluid into gas phase and liquid phase (oil + water), the gas phase is measured by volume metering or flow meter combined with density conversion to obtain gas production. The liquid phase is generally estimated by online water content meter or offline sampling test to estimate the water content (Water Cut), and then the volume or flow is added to calculate the oil and water production. However, when the oil and water ratio or property of the liquid phase is complex, and there is dissolved gas or free gas, the measurement error of this method is high; and after emulsification, the volume is not simply linearly added, which will inevitably cause calculation deviation caused by incomplete and delayed phase separation of oil and water.

[0004] Oil-water emulsification is a multi-phase micro-dispersion phenomenon caused by factors such as colloid bitumen in oil, natural surfactants or additional chemicals, and shear force in the pipeline. When part of the water is wrapped in the oil to form an emulsion, the actual volume will expand or shrink due to molecular structure and interaction. In engineering calculation or daily measurement, in order to simplify the calculation of emulsification state, it is generally assumed that there is no emulsification (the oil volume and water volume are directly added), or it is assumed that there is complete emulsification (all water is emulsified by oil), and for the case of "partial emulsification" or "stage emulsification" (only part of the water is wrapped by oil), the water content and oil-gas ratio cannot be accurately determined.

[0005] For the case of partial emulsification of three-phase fluid, how to accurately determine the water content and oil-gas ratio, an effective solution has not been proposed. SUMMARY

[0006] The application aims to provide a method for determining water content and oil-gas ratio of a three-phase system, which can accurately and efficiently determine the water content and oil-gas ratio of a three-phase fluid.

[0007] The application provides a method for determining water content and oil-gas ratio of a three-phase system, which is realized as follows:

[0008] A method for determining water content and oil-gas ratio of a three-phase system, the method comprises:

[0009] The total mass, total volume and gas volume of the fluid produced by the target oil well wellhead in a preset monitoring period are collected, wherein the produced fluid is in a three-phase mixed state of oil, water and gas;

[0010] The emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the fluid are obtained;

[0011] The liquid phase mass and liquid phase volume of the fluid are determined according to the total mass, total volume, gas volume and gas density of the fluid;

[0012] 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;

[0013] The water cut and oil-gas ratio of the fluid are determined according to the oil mass fraction in the liquid phase of the fluid.

[0014] In one embodiment, 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:

[0015] The oil mass fraction in the liquid phase of the fluid is calculated according to the following formula:

[0016]

[0017] Wherein, α represents the oil mass fraction, r represents the emulsification rate, δ represents the emulsification volume coefficient, M l represents the liquid phase mass, ρ w represents the water density, ρ o represents the oil density, V l represents the liquid phase volume.

[0018] In one embodiment, 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:

[0019] The oil mass fraction in the liquid phase of the fluid is calculated according to the following formula:

[0020]

[0021] Wherein, α represents the oil mass fraction, r represents the emulsification rate, δ represents the emulsification volume coefficient, M l represents the liquid phase mass, ρ w represents the water density, ρ o represents the oil density, V l represents the liquid phase volume, and s represents the proportion that can be emulsified in the oil phase.

[0022] In one embodiment, determining the water cut of the fluid according to the oil mass fraction in the liquid phase of the fluid comprises:

[0023] The water cut is calculated according to the following formula:

[0024]

[0025] wherein f w represents the water cut, a represents the oil mass fraction, p w represents the water density, p o represents the oil density.

[0026] In one embodiment, determining the gas-oil ratio of the fluid according to the oil mass fraction in the liquid phase of the fluid comprises:

[0027] The gas-oil ratio is calculated according to the following formula:

[0028]

[0029] wherein GOR represents the gas-oil ratio, v g represents the gas volume, p w represents the water density, p o represents the oil density, M total represents the total mass.

[0030] In one embodiment, after determining the gas-oil ratio of the fluid according to the oil mass fraction in the liquid phase of the fluid, further comprising:

[0031] Converting the gas volume into a standard volume under standard temperature and pressure;

[0032] According to the standard volume, the gas-oil ratio under standard working conditions is calculated according to the following formula:

[0033]

[0034] wherein V represents the standard volume under standard temperature and pressure, V o represents the oil phase volume.

[0035] In one embodiment, obtaining the emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the fluid comprises:

[0036] Collecting the temperature and pressure of the target oil well wellhead within a preset monitoring period;

[0037] Accessing a pre-established data reference table, wherein the data reference table records the emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the fluid of the target oil well determined by external experiments under different temperatures and pressures;

[0038] According to the temperature and pressure, the emulsification rate, the emulsification volume coefficient, the oil density, the water density and the gas density corresponding to the temperature and pressure are found from the data table;

[0039] The found emulsification rate, the emulsification volume coefficient, the oil density, the water density and the gas density are taken as the emulsification rate, the emulsification volume coefficient, the oil density, the water density and the gas density of the fluid.

[0040] In one embodiment, after determining the water cut and the oil-gas ratio of the fluid according to the oil mass fraction in the liquid phase of the fluid, further comprising:

[0041] According to the water cut and the oil-gas ratio, determining the required pressure of the separator and the required injection amount of the emulsifier;

[0042] According to the determined required pressure of the separator, adjusting the pressure of the separator;

[0043] According to the determined required injection amount of the emulsifier, injecting the emulsifier.

[0044] An electronic device comprising a processor and a memory for storing processor-executable instructions, the processor implementing the steps of the above method when executing the instructions.

[0045] A computer-readable storage medium having stored thereon computer programs / instructions, the computer programs / instructions being executed by a processor to implement the steps of the above method.

[0046] The method for determining the water cut and the oil-gas ratio of a three-phase system provided in the present application combines the total mass, the total volume and the gas volume of the fluid produced by the target oil well wellhead within a preset monitoring period, and the obtained emulsification rate, the emulsification volume coefficient, the oil density, the water density and the gas density of the fluid, to calculate the oil mass fraction in the liquid phase of the fluid, thereby further determining the water cut and the oil-gas ratio of the fluid. That is, the emulsification rate and the emulsification volume coefficient of the fluid are introduced to calculate the water cut and the oil-gas ratio, thereby solving the technical problem of low accuracy of the existing water cut and oil-gas ratio calculation, and achieving the technical effect of efficiently and accurately determining the water cut and the oil-gas ratio. BRIEF DESCRIPTION OF DRAWINGS

[0047] In order to more clearly illustrate the technical solutions in the embodiments of the present application or the prior art, the drawings needed in the embodiment or prior art description will be briefly introduced below. Obviously, the drawings in the following description are only some embodiments described in the present application, and other drawings can also be obtained by those skilled in the art without creative labor.

[0048] Figure 1is a method flow chart of one embodiment of the method for determining water cut and oil-gas ratio of a three-phase system provided by the present application;

[0049] Figure 2 is a method flow chart of one embodiment of the method for automatically calculating water cut and oil-gas ratio provided by the present application;

[0050] Figure 3 is a hardware structure block diagram of an electronic device of the method for determining water cut and oil-gas ratio of a three-phase system provided by the present application;

[0051] Figure 4 is a module structure schematic diagram of one embodiment of the device for determining water cut and oil-gas ratio of a three-phase system provided by the present application. DETAILED DESCRIPTION

[0052] In order to make the person skilled in the art better understand the technical solutions in the present application, the technical solutions in the embodiments of the present application will be described clearly and completely below in combination with the drawings in the embodiments of the present application. Obviously, the described embodiments are only a part of the embodiments of the present application, rather than all the embodiments. Based on the embodiments in the present application, all other embodiments obtained by the person skilled in the art without creative labor should belong to the protection scope of the present application.

[0053] It should also be noted that in the embodiments of the present application, some software, components, models and other industry existing solutions may be mentioned, which should be considered as exemplary, and the purpose is only to illustrate the feasibility of the implementation of the technical solutions in the present application, but does not mean that the applicant has or will necessarily use the solutions.

[0054] Considering the case where oil, gas and water three-phase fluids exist at the same time, if only based on the liquid mass to calculate the oil-water distribution, a large deviation will occur when the gas phase production is relatively large. For example: for some heavy oil wells, the gas specific gravity is high, and if the gas mass is ignored, the mass of the liquid phase will be overestimated, which will affect the accuracy of the water cut and the oil-gas ratio (GOR). Through the separator parameters and the empirical curve, only volume splitting can be done, for example, the gas phase volume is calculated through the separator gas production, and then the remaining mass is all regarded as liquid phase. This way has poor accuracy of the calculation result for the case of serious emulsification. In addition, the transformation 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 assumed to be known oil volume, but when the oil-water ratio in the liquid phase is unclear or part of the water is emulsified by the oil, the oil volume cannot be accurately obtained. If emulsification or the influence of free gas is ignored, the result of GOR will deviate from the actual value.

[0055] Further, the existing water content calculation method only targets oil-water two-phase (ignoring gas phase) or only considers gas phase as volume deduction, and the correction of gas mass is not considered. That is, in the existing measurement process, only whether there is emulsification is distinguished, and the key parameters such as how much water is emulsified and the volume deviation after emulsification are not considered, thereby resulting in low accuracy of the calculated results of water content and GOR.

[0056] Therefore, in this case, a three-phase model is provided, which can not only consider the influence of gas phase on total mass, but also finely distinguish between partial water emulsification and free water layering. By introducing emulsification rate (i.e., the proportion of water emulsified) and emulsification volume coefficient (i.e., quantifying the influence of emulsification expansion or contraction) in the liquid phase, and combining the mass and volume conservation equations, the ratio of oil and water two-phase is 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 by the volume of the oil phase, thereby realizing one-stop and accurate three-phase measurement.

[0057] That is, in order to solve the problem of low accuracy of water content and gas-oil ratio calculation in the existing three-phase fluid complex scene, especially when there is obvious emulsification effect, in this case, a scheme is proposed for simultaneously calculating water content and gas-oil ratio under the premise of known total mass, gas phase information, and emulsification rate and emulsification volume coefficient. This way can accurately determine the water content and gas-oil ratio, thereby making the measurement of three-phase system and the analysis of oil reservoir more accurate and scientific.

[0058] Figure 1 is a method flowchart of an embodiment of the method for determining water content and gas-oil ratio of a three-phase system provided by the present application. Although the method operation steps or device structures are provided as described in the following embodiments or drawings, more or fewer operation steps or module units can be included in the method or device based on conventional or non-creative labor. In steps or structures that do not have necessary causal relationship in logic, the execution order of the steps or the module structure of the device is not limited to the execution order or module structure shown in the embodiments and drawings of the present application. When the method or module structure is applied in actual device or terminal product, it can be sequentially executed or executed in parallel (for example, parallel processor or multi-thread processing environment, even distributed processing environment) according to the method or module structure shown in the embodiments or drawings.

[0059] Specifically, as shown in Figure 1 The method for determining water content and gas-oil ratio of a three-phase system can include the following steps:

[0060] Step 101: Collecting the total mass, total volume and gas volume of the fluid produced by 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;

[0061] Step 102: obtaining the emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the fluid;

[0062] Step 103: determining 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;

[0063] Step 104: calculating 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;

[0064] Specifically, the liquid phase mass and liquid phase volume can be determined according to the total mass, total volume, gas volume and gas density of the fluid, and then the liquid phase mass can be determined according to the total mass, gas volume and gas density of the fluid according to the following formula:

[0065] M l = M total - p g v g

[0066] Wherein, M l represents the liquid phase mass, M total represents the total mass, v g represents the gas volume, and p g represents the gas density;

[0067] And then the liquid phase volume can be determined according to the total volume and gas volume according to the following formula:

[0068] V l = V total -v g

[0069] Wherein, V l represents the liquid phase volume, and V total represents the total volume;

[0070] Further, the oil mass fraction in the liquid phase of the fluid can be calculated according to the liquid phase mass, liquid phase volume, emulsification rate, emulsification volume coefficient, oil density and water density of the fluid.

[0071] For the oil mass fraction, two calculation methods are given in this example:

[0072] Method 1: the oil mass fraction in the liquid phase of the fluid is calculated according to the following formula:

[0073]

[0074] Wherein, a represents the oil mass fraction, r represents the emulsification rate, d represents the emulsification volume coefficient, M l represents the liquid phase mass, and p wρ represents water density o V represents oil density l V represents liquid phase volume.

[0075] Method 2: Introducing "emulsification rate s of oil", wherein s represents the proportion that can be emulsified in the oil phase, then the oil mass fraction in the liquid phase of the fluid is calculated according to the following formula:

[0076]

[0077] wherein α represents oil mass fraction, r represents emulsification rate, δ represents emulsification volume coefficient, M l ρ represents liquid phase mass w ρ represents water density o V represents oil density l V represents liquid phase volume, and s represents the proportion that can be emulsified in the oil phase.

[0078] Step 105: determining water cut and oil-gas ratio of the fluid according to the oil mass fraction in the liquid phase of the fluid.

[0079] In implementation, considering the determination of water cut of the fluid, it can be determined from mass ratio dimension or volume ratio dimension:

[0080] For example, the oil-gas ratio in mass ratio dimension is determined according to the following formula:

[0081]

[0082] wherein GOR represents oil-gas ratio, v g ρ represents gas volume w ρ represents water density o M represents oil density total M represents total mass.

[0083] For example, the oil-gas ratio in volume ratio dimension is determined according to the following method:

[0084] The gas volume is converted into standard volume under standard temperature and pressure, and the oil-gas ratio under standard working condition is calculated according to the standard volume according to the following formula:

[0085]

[0086] wherein, V represents standard volume under standard temperature and pressure o M represents oil phase volume.

[0087] For water cut, the water cut is calculated according to the oil mass fraction in the liquid phase of the fluid according to the following formula:

[0088]

[0089] wherein f w represents water cut, a represents oil mass fraction, p w represents water density, p o represents oil density.

[0090] That is, the total mass, total volume and gas volume of the fluid produced by the wellhead of the target oil well in a preset monitoring period are combined, and the emulsion rate, emulsion volume coefficient, oil density, water density and gas density of the obtained fluid are obtained, and the oil mass fraction in the liquid phase of the fluid is calculated, so as to further determine the water cut and the oil-gas ratio of the fluid. That is, the emulsion rate and the emulsion volume coefficient of the fluid are introduced to calculate the water cut and the oil-gas ratio, so as to solve the technical problem that the existing water cut and oil-gas ratio calculation accuracy is low, and achieve the technical effect of efficiently and accurately determining the water cut and the oil-gas ratio.

[0091] In implementation, the emulsion rate, the emulsion volume coefficient, the oil density, the water density and the gas density of the fluid can be determined through external experiments or environmental simulation. Specifically, the emulsion rate, the emulsion volume coefficient, the oil density, the water density and the gas density of the target oil well under different temperatures and pressures can be recorded, and then the temperature and pressure of the wellhead of the target oil well in a preset monitoring period can be collected in actual calculation and use. A pre-established data reference table is called, wherein the data reference table records the emulsion rate, the emulsion volume coefficient, the oil density, the water density and the gas density of the fluid of the target oil well under different temperatures and pressures determined through external experiments. According to the temperature and pressure, the emulsion rate, the emulsion volume coefficient, the oil density, the water density and the gas density corresponding to the temperature and pressure are found out from the data reference table. The found emulsion rate, emulsion volume coefficient, oil density, water density and gas density are used as the emulsion rate, emulsion volume coefficient, oil density, water density and gas density of the fluid.

[0092] Further, according to the oil mass fraction in the liquid phase of the fluid, the water cut and the oil-gas ratio of the fluid can be determined by the above-mentioned method. After the water cut and the oil-gas ratio of the fluid are determined, the required pressure of the separator and the required injection amount of the emulsifier can be determined according to the water cut and the oil-gas ratio. Then, 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.

[0093] Based on the above-mentioned method for determining the water cut and the oil-gas ratio of the three-phase system, in this example, a three-phase fluid processing system applied to an oil well site is also provided, comprising:

[0094] 1) a sensor device arranged at the wellhead of the target oil well or at the inlet of each stage separator, for measuring the temperature, pressure, total mass, total volume and gas volume of the fluid produced by the wellhead of the target oil well or each stage separator in real time within a preset monitoring period;

[0095] 2) a memory for storing a pre-established data reference table, wherein the data reference table records the emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the fluid of the target oil well at different temperatures and pressures determined by external experiments;

[0096] 3) a control processor for acquiring the temperature, pressure, total mass, total volume and gas volume from the sensor device, and acquiring the emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the fluid at the collected temperature and pressure according to the temperature and pressure, calculating 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 calculating and outputting the water cut and oil-gas ratio of the fluid according to the oil mass fraction in the liquid phase of the fluid;

[0097] 4) a visual human-computer interaction device for displaying the determined water cut and oil-gas ratio of the fluid in real time through an operation terminal on the oil well site or a central control room interface remotely.

[0098] Specifically, the sensor device described above can include a temperature detector for collecting real-time temperature and a pressure detector for collecting real-time pressure. That is, the temperature data and pressure data can be acquired through the sensor device.

[0099] Further, the sensor device described above can also include a storage tank arranged at the wellhead of the target oil well or at the inlet of each stage separator, a weight sensor arranged below the storage tank for detecting weight data, and a vernier arranged in the storage tank for sensing 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 vernier in the storage tank to obtain the height of each fluid in the tank, the volume of each fluid can be determined.

[0100] After acquiring the weight, temperature, pressure, volume and other data through the sensor device, the data is transmitted to the control processor, and the control processor can directly obtain the water cut and oil-gas ratio. That is, in actual field use, only a storage tank needs to be arranged at the oil outlet, and then the height, temperature, pressure, mass and other data are measured to obtain the oil-gas ratio and water cut.

[0101] In order to obtain the emulsification rate and the emulsification volume coefficient, a stirring and shearing test device can be arranged in the three-phase fluid treatment system applied to the oil well site, the stirring and shearing test device is arranged in a bypass pipeline, is used for simulating the actual working condition by changing the shearing intensity and the temperature, determining the actual expansion ratio or contraction ratio of the fluid volume, determining the emulsification rate and the emulsification volume coefficient of the fluid, and storing in the memory. The emulsification rate and the emulsification volume coefficient can be set as curve change values corresponding to different pressures and temperatures.

[0102] In order to control the actual working condition, the three-phase fluid treatment system applied to the oil well site can further comprise a central control device for adjusting the pressure of the separator and the amount of demulsifier injection according to the water cut and the oil-gas ratio.

[0103] The above method will be described below in combination with a specific embodiment, however, it is worth noting that the specific embodiment is only for better illustrating the present application and does not constitute an improper limitation on the present application.

[0104] In view of the problems that the existing determination of the water cut and the GOR is mostly in a step-by-step manner, so that oil-water separation measurement and oil-gas separation measurement are needed respectively, resulting in increased equipment and operation cost, and the existing determination of the water cut and the GOR does not consider the emulsification, resulting in low accuracy of the determined water cut and GOR. In this case, a digital water cut and oil-gas ratio synchronous calculation method and system considering gas phase mass correction and oil-water partial emulsification effect are provided for the oil-water-gas three-phase mixed fluid commonly seen in the oil field well site and the ground gathering and transportation environment. By introducing "gas volume" and "gas density" on the basis of the conventional three-phase separation and metering, the gas phase mass is accurately deducted, further, the "emulsification rate" and the "emulsification volume coefficient" are used to quantitatively represent the volume deviation and dispersion ratio of the emulsified water, so as to achieve the following goals:

[0105] 1) Accurately deduct the influence of the gas phase, in the working condition of high gas-oil ratio or significant dissolved gas volume, avoid miscounting the gas phase mass into the liquid phase, and reduce the calculation error of the water cut and the oil-gas ratio caused by the change of the gas density or the measurement deviation.

[0106] 2) Flexibly handle the partial emulsification phenomenon, by setting the emulsification rate r and the emulsification volume coefficient δ, the "free water" and the "emulsified water wrapped by oil" are distinguished, so as to overcome the technical problem that the prediction result is inaccurate due to the existing assumption of no emulsification or full emulsification. Further, in this case, the water cut and the oil-gas ratio are obtained simultaneously, that is, the water content (Water Cut) in the liquid phase and the volume ratio (GOR) of the gas phase and the oil phase can be obtained at the same time through one calculation, so as to help to perfect the separator design, the yield metering and the dynamic analysis of the oil reservoir, and reduce the trouble caused by the existing multiple devices or segmented manual operation;

[0107] 3) Digitization and online, in this case, the formula and logic flow embedded in the real-time data acquisition and transmission network of well site or ground measurement system, using embedded computing unit or PC software to automatically solve the oil-water distribution, water cut and oil-gas ratio, support data storage, visualization and remote monitoring, to meet the needs of modern oilfield digital, automated management. Through the above way can more fully adapt to various high water cut, high viscosity, complex emulsion and significant gas phase influence of the field conditions, for oilfield production, production fluid measurement, separator optimization and reservoir evaluation to provide a simple operation, reliable results of measurement method and supporting system.

[0108] Specifically, in this case, a three-phase system measurement method considering partial emulsification and capable of simultaneously calculating water cut and oil-gas ratio is provided, which comprises:

[0109] S1: measuring or obtaining total mass M of oil-water-gas three-phase system total , total volume V total , gas volume v g and gas density ρ g , calculating liquid phase mass M l = M total - ρ g v g and liquid phase volume V l = V total - v g ;

[0110] S2: determining emulsification rate r and emulsification volume coefficient δ;

[0111] S3: determining oil density ρ o and water density ρ w ;

[0112] S4: calculating oil mass fraction α in the liquid phase according to the following volume equation:

[0113]

[0114] Wherein, r represents the emulsification rate, and δ represents the emulsification volume coefficient.

[0115] S5: after calculating the oil mass fraction α, the water cut is calculated according to the following formula:

[0116]

[0117] The oil-gas ratio is calculated according to the following formula:

[0118]

[0119] In the step S2, the emulsification rate r and the emulsification volume coefficient δ can be determined in the following way: the oil-water mixture to be measured (i.e. the sample) is placed in a speed-adjustable stirring or shearing device, and then the actual reservoir environment is simulated by adjusting the stirring time, temperature and shearing strength, and the actual volume of the emulsified reservoir system and the phase separation condition are further determined, so as to obtain the emulsification rate r and the emulsification volume coefficient δ.

[0120] In the step S2, the emulsification rate r and the emulsification volume coefficient δ can also be determined in the following way: the volume change of the mixed liquid is monitored in real time by using an online sensor, the emulsification volume coefficient δ is determined according to the volume change of the mixed liquid, and further, the free water proportion is measured by phase separation sampling, and the emulsification rate r is determined according to the free water proportion.

[0121] In the step S3, the oil density ρ o and the water density ρ w can be determined in the following way: the system, temperature and pressure conditions of the simulated reservoir are simulated, and then the oil density ρ o and the water density ρ w are measured by using a laboratory densimeter or an online density measuring instrument. o If the temperature and pressure of the produced fluid change, the oil density ρ w and the water density ρ g are converted according to the known PVT rule, so as to ensure that the parameters such as the gas phase density ρ g are in the same working condition.

[0122] In this example, the calculation of the gas-oil ratio (GOR) is extended in consideration of the adaptation to different gas states. When it is necessary to define the GOR under standard working conditions, the V g measured in the field can be converted to the V under standard temperature and pressure, and then substituted into the following formula to obtain the GOR under standard working conditions, i.e. GOR std :

[0123]

[0124] Further, for the case that the gas is dissolved in the oil phase, the free gas V g can be re-determined after deducting the dissolved gas amount, and then the GOR is calculated according to the re-determined v g , so that the calculation result is more consistent with the actual condition of the field separator or the process flow.

[0125] Considering that the influence on the result is different for different emulsification cases, in order to adapt to more scene requirements, in this example, for the volume conservation equation, in addition to introducing alpha, an "emulsification rate s of oil" is also introduced, where s represents the proportion of the oil phase that can be emulsified, based on this, the volume conservation equation is extended to:

[0126]

[0127] Through this multi-parameter coupled solving mode, the result can meet more complex emulsification scenarios, and after alpha is determined, the water cut f can be calculated in the above-mentioned manner w and GOR.

[0128] The above-mentioned water cut f w and GOR can be applied in the automatic metering system of the oil field site, by inputting the measured ρ g , v g , M total , V total , ρ o , ρ w , δ, r and other parameters to the embedded calculation unit, real-time solution is obtained α, and then the water cut f w and GOR are calculated and output; when it is detected that or alpha is too large or too small, the system automatically alarms or triggers data correction.

[0129] Specifically, the above-mentioned method can be linked with the running state of the demulsification equipment or the multi-stage separator, according to the real-time calculated water cut f w and GOR, the pressure of the separator or the injection amount of the emulsifier is automatically adjusted, so as to optimize the separation efficiency. For the case of ultra-high water cut or high gas-oil ratio, a warning can be issued and corresponding process adjustment can be taken to improve the separation effect of oil-water and gas-liquid.

[0130] In this example, an oil-water-gas three-phase fluid metering device is also provided, which comprises: a gas phase measurement unit, a liquid phase mass 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 the density ρ g and transmit them to the calculation control unit; the liquid phase mass detection unit is used to generate the liquid phase mass M l in combination with the total mass of the system and provide ρ o , ρ w , δ, r and other parameters; the calculation control unit is used to calculate and output the water cut and the oil-gas ratio according to the above-mentioned parameters, and display or transmit the results to the upper system; when the calculation result shows that the oil mass fraction alpha exceeds the allowed interval or the system detects abnormal parameters, automatic alarm or adjustment of the operating conditions of the separator is triggered.

[0131] In this example, a digitization 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 total mass, gas volume, gas density, oil-water density, emulsion rate, emulsion volume coefficient, etc. of the three-phase system from the oilfield site, separator control system or downhole / wellhead sensor network; the communication interface and real-time data transmission module supports wired or wireless communication mode, specifically, it can include but 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, for automatically deducting gas phase mass and volume according to the input real-time data, to calculate the total liquid mass and total liquid volume; establishing and solving the partial emulsion volume conservation equation to obtain the oil mass fraction a; calculating the water cut and oil-gas ratio based on the solved a; if a is detected to be out of the normal interval or the emulsion parameters are not matched, 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 a, f w , GOR, etc. result information, and supports playback or comparative analysis; the visualization / human-computer interaction module is used to show the key results such as water cut and oil-gas ratio to the user 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) or control operation, so as to realize digital management and online automatic regulation of oilfield production.

[0132] The above oil-water-gas three-phase fluid treatment system can include:

[0133] 1) Well site / separator environment:

[0134] In the process of producing fluid from the oil well to the ground through the wellhead, the produced fluid is still in the state of oil-water-gas three-phase mixture after being coarsely separated by the primary separator, and part of the water is emulsified by oil. Therefore, a digital metering system can be configured on the separator / gathering pipeline, which can include: a sensor network, which measures the total mass (or total flow rate, which is converted into total mass based on the total flow rate) of the three-phase fluid, the gas volume V g (which can be obtained by a gas flow meter or a volume meter), the gas density p g (which can be obtained by an online density meter or a state equation), and the oil density p o , the water density p w(Which can be obtained by two online density meters placed at the oil-water outlet or through temperature and pressure correction). Further, a stirring / shearing 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 can be determined by changing the shear strength, temperature, etc. in the bypass line or laboratory simulation device, so as to obtain more reliable parameters.

[0135] 2) The digitization system comprises:

[0136] a data acquisition module and a communication interface for acquiring information such as v g , M total , V total , ρ o , ρ w , δ and r from the sensor or separator control system in real time, and transmitting the data to the operation and logic processing module through a 4G / 5G network or an industrial Ethernet network;

[0137] an operation and logic processing module for embedding core formulas and solving algorithms, establishing a liquid volume equation by automatically deducting the gas phase mass to obtain α, and then calculating the water cut f w and the gas-oil ratio GOR through the calculated α;

[0138] a database / storage module for saving operating parameters, historical data and calculation results;

[0139] a visualization / human-computer interaction module for displaying the calculation results in real time through a well site operation terminal or a remote central control room interface and remotely retrieving historical data.

[0140] Taking a specific example for illustration, 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 g (m 3 / h level) and the gas density ρ g (kg / m 3 ) are obtained in real time through the gas flow meter and the gas density meter, and the obtained gas volume v g (m 3 / h level) and the gas density ρ g (kg / m 3 ) are transmitted to the communication module in real time. Assuming that the v g = 0.35 m 3 , ρ g = kg / m 3 obtained in the current sampling period.

[0141] A high-precision mass flowmeter or weighing sensor is arranged 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 through device calibration or comprehensive measurement total . For example: M total = 1500 kg, V total = 2.0 m 3 . The oil density and water density are measured under the same temperature and pressure conditions or are corrected through PVT (Process Verification Test) to obtain: ρ o = 850 kg / m 3 , ρ w = 1000 kg / m 3 . Through bypass pipeline or online sampling test, it is determined that about 40% of the water enters the emulsion under the current flow and temperature conditions, and the volume expands by about 3%. Based on this, the emulsification rate r = 0.4 and the emulsion volume coefficient δ = 1.03 can be determined.

[0142] Further, for more extreme temperature and pressure conditions, PVT correction can be performed on the oil density, water density, and gas volume. For this purpose, if a multi-stage separation system is used in the oil well, the gas phase data and liquid phase data can be measured at the inlet and outlet of each stage separator to perform PVT on the data, thereby improving the measurement accuracy.

[0143] Based on the above-obtained multiple parameters, the water cut and oil-gas ratio can be automatically calculated in the manner as shown in Figure 2 :

[0144] S1: Calculate the liquid phase mass and volume:

[0145] M l = M total - ρ g v g = 1500 - (2 x 0.35) = 1500 - 0.7 = 1499.3 kg

[0146] V l = V total - v g = 2 - 0.35 = 1.65 m 3

[0147] S2: Establish the volume conservation equation:

[0148]

[0149] Let α = M o / M lAnd the above values are brought into each item, using the linear solver in the operation and logic processing module to automatically calculate the oil mass fraction a = 0.68, indicating that the oil accounts for about 68% of the liquid phase mass.

[0150] S3: Calculate the water content f w :

[0151]

[0152] S4: Calculate the oil-gas ratio GOR:

[0153] Oil phase volume:

[0154]

[0155] Oil-gas ratio:

[0156]

[0157] Further, if it is necessary to determine the GOR under standard conditions, the gas volume conversion value under standard conditions can be further converted, and then the ratio is calculated to determine the GOR under standard conditions.

[0158] For the above digital system, the results can be displayed and automatically fed back. Specifically, the operation and logic processing module can transmit the calculated f w = 0.28, GOR = 0.29 (dimensionless or m 3 / m 3 ) to the database and display it in real time on the visualization module interface; if the values of parameters such as p g or v g change in the next measurement period, the system automatically repeats the calculation and updates the results; if it is identified during the detection process that or the value of a is too large or too small, the system can issue a warning prompt and suggest that the on-site engineer check the sensor or separator operation status and clean the storage tank, and re-calculate f w and GOR.

[0159] In the above example, the sensor data and calculation results can be transmitted back to the control room of the oil field or the cloud platform through 4G / 5G or industrial Ethernet. For the control room, the separator pressure, demulsifier injection amount or production capacity distribution can be adjusted according to the real-time water cut and GOR distribution of each well site / separator, so as to improve the separation efficiency and system stability. In this way, the centralized determination of water cut and GOR is realized, avoiding the problem of too complicated process caused by separately estimating water cut and then manually calculating oil-gas ratio. Further, this method is closer to the actual three-phase partially emulsified working condition, which can improve the accuracy of the determined water cut, especially in the case of high water cut, high viscosity and easy emulsification wells, which can reduce the measurement error, thereby realizing fine control of the difference between dissolved gas and free gas, effectively mastering the dynamic change of oil-gas ratio, and having important value for pipeline transportation and reservoir evaluation.

[0160] In the actual well site environment, the water cut and oil-gas ratio can be accurately calculated, and the results can be digitally displayed and transmitted, so as to effectively guide the oil and gas production process.

[0161] The method 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 the running on an electronic device as an example, Figure 3 is a hardware structure block diagram of an electronic device for a three-phase system water cut and oil-gas ratio determination method provided by the present application. As shown in Figure 3 , the electronic device 10 can include one or more (only one is shown in the figure) processors 02 (the processor 02 can 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 function. Those skilled in the art can understand that Figure 3 The structure shown is only schematic, and does not limit the structure of the above-mentioned electronic device. For example, the electronic device 10 can also include more or fewer components than those shown in Figure 3 , or have a different configuration from Figure 3 .

[0162] The memory 04 can be used to store software programs of application software and modules, such as program instructions / modules corresponding to the three-phase system water cut and oil-gas ratio determination method in the embodiments 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, implements the three-phase system water cut and oil-gas ratio determination method of the application program described above. The memory 04 can include a high-speed random access memory, and can also include a non-volatile memory, such as one or more magnetic storage devices, flash memories, or other non-volatile solid-state memories. In some examples, the memory 04 can further include memories remotely arranged with respect to the processor 02, which can be connected to the electronic device 10 through 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.

[0163] The transmission module 06 is used to receive or send data via a network. Specific examples of the above-mentioned network can 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 (NIC), which can be connected to other network devices through a base station so as to be able to communicate with the Internet. In one example, the transmission module 06 can be a radio frequency (RF) module, which is used to communicate with the Internet in a wireless manner.

[0164] At the software level, the three-phase system water cut and oil-gas ratio determination device can include, as shown in the figure, Figure 4

[0165] The acquisition module 401 is used to acquire total mass, total volume, and gas volume of fluid output by a target oil well wellhead within a preset monitoring period, wherein the output fluid is in a three-phase mixed state of oil, water, and gas.

[0166] The acquisition module 401 is used to acquire total mass, total volume, and gas volume of fluid output by a target oil well wellhead within a preset monitoring period, wherein the output fluid is in a three-phase mixed state of oil, water, and gas.

[0167] The first determination module 403 is used to determine 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.

[0168] The calculation module 404 is used to calculate 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.

[0169] The second determination module 405 is used to determine water cut and oil-gas ratio of the fluid according to the oil mass fraction in the liquid phase of the fluid.

[0170] ​In one embodiment, the calculating module 404 can be specifically configured to calculate the oil mass fraction in the liquid phase of the fluid according to the following formula:

[0171]

[0172] wherein a represents the oil mass fraction, r represents the emulsification rate, δ represents the emulsification volume coefficient, M l represents the liquid phase mass, ρ w represents the water density, ρ o represents the oil density, V l represents the liquid phase volume.

[0173] In one embodiment, the calculating module 404 can be specifically configured to calculate the oil mass fraction in the liquid phase of the fluid according to the following formula:

[0174]

[0175] wherein a represents the oil mass fraction, r represents the emulsification rate, δ represents the emulsification volume coefficient, M l represents the liquid phase mass, ρ w represents the water density, ρ o represents the oil density, V l represents the liquid phase volume, and s represents the proportion that can be emulsified in the oil phase.

[0176] In one embodiment, the second determining module 405 can be specifically configured to calculate the water content according to the following formula:

[0177]

[0178] wherein f w represents the water content, a represents the oil mass fraction, ρ w represents the water density, ρ o represents the oil density.

[0179] In one embodiment, the second determining module 405 can be specifically configured to calculate the oil-gas ratio according to the following formula:

[0180]

[0181] wherein GOR represents the oil-gas ratio, v g represents the gas volume, ρ w represents the water density, ρ o represents the oil density, M total represents the total mass.

[0182] In one embodiment, the second determining module 405, after determining the oil-gas ratio of the fluid according to the oil mass fraction in the liquid phase of the fluid, can further convert the gas volume into a standard volume at a standard temperature and pressure; and calculate the oil-gas ratio at a standard working condition according to the standard volume, as follows:

[0183]

[0184] wherein, V represents the standard volume at the standard temperature and pressure, V o V represents the oil phase volume.

[0185] In one embodiment, the acquisition module 402 can specifically collect the temperature and pressure of the wellhead of the target oil well in a preset monitoring period; and call a pre-established data reference table, wherein the data reference table records the emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the fluid of the target oil well determined by external experiments at different temperatures and pressures; and 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 reference table; and take 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.

[0186] In one embodiment, the determination of the water cut and oil-gas ratio of the three-phase system can further include the following steps: after determining the water cut and oil-gas ratio of the fluid according to the oil mass fraction in the liquid phase of the fluid, determining the required pressure of the separator and the required injection amount of the emulsifier according to the water cut and oil-gas ratio; adjusting the pressure of the separator according to the determined required pressure of the separator; and injecting the emulsifier according to the determined required injection amount of the emulsifier.

[0187] The embodiments of the present application also provide a specific implementation of an electronic device capable of implementing all steps of the method for determining the water cut and oil-gas ratio of the three-phase system in the above embodiments, which specifically includes the following contents: a processor, a memory, a communications interface and a bus; wherein the processor, the memory and the communications interface complete mutual communication through the bus; the processor is used to call a computer program in the memory, and the processor implements all steps of the method for determining the water cut and oil-gas ratio of the three-phase system in the above embodiments when executing the computer program, for example, the processor implements the following steps when executing the computer program:

[0188] Step 1: collect the total mass, total volume and gas volume of the fluid produced by 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;

[0189] Step 2: obtain the emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the fluid;

[0190] Step 3: 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;

[0191] Step 4: 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;

[0192] Step 5: determine the water cut and oil-gas ratio of the fluid according to the oil mass fraction in the liquid phase of the fluid.

[0193] The embodiment of the present application also provides a computer readable storage medium capable of realizing all steps of the water cut and oil-gas ratio determination method of the three-phase system in the above-mentioned embodiment, and a computer program is stored on the computer readable storage medium. When the processor executes the computer program, all steps of the water cut and oil-gas ratio determination method of the three-phase system in the above-mentioned embodiment are realized, for example, the processor executes the computer program to realize the following steps:

[0194] Step 1: collect the total mass, total volume and gas volume of the fluid produced by 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;

[0195] Step 2: obtain the emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the fluid;

[0196] Step 3: 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;

[0197] Step 4: 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;

[0198] Step 5: determine the water cut and oil-gas ratio of the fluid according to the oil mass fraction in the liquid phase of the fluid.

[0199] From the above description, it can be known that the embodiment of the present application combines the total mass, total volume and gas volume of the fluid produced by the target oil well wellhead in the preset monitoring period, and the emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the obtained fluid, to calculate the oil mass fraction in the liquid phase of the fluid, so as to further determine the water cut and the oil-gas ratio of the fluid. That is, the emulsification rate and the emulsification volume coefficient of the fluid are introduced to calculate the water cut and the oil-gas ratio, so as to solve the technical problem that the existing water cut and oil-gas ratio calculation accuracy is low, and achieve the technical effect of efficiently and accurately determining the water cut and the oil-gas ratio.

[0200] Each of the embodiments in the specification is described in a progressive manner, and the same or similar parts between the embodiments can be referred to each other. Each embodiment mainly describes the difference from other embodiments. In particular, for the hardware+program type embodiment, since it is basically similar to the method embodiment, the description is relatively simple, and the related parts can be referred to the part of the method embodiment.

[0201] The above describes specific embodiments of the specification. Other embodiments are within the scope of the appended claims. In some cases, the actions or steps recited in the claims can be executed in an order different than the order in which they are recited, and still achieve the desired result. In addition, the processes depicted in the figures do not necessarily require the particular order shown, or sequential order, to achieve the desired results. In certain implementations, multitasking and parallel processing can be advantageous.

[0202] Although the present application provides method operation steps as described in the embodiments or flowcharts, more or fewer operation steps can be included based on conventional or non-inventive labor. The order of steps listed in the embodiments is only one of the many execution orders of the steps, and does not represent the only execution order. When the device or client product is executed in practice, the method order shown in the embodiments or the drawings can be executed in sequence or in parallel (for example, in a parallel processor or multi-thread processing environment).

[0203] Although the method operations are described in the present disclosure as a sequence of operations, it is to be understood that the logical flow of the methods can be different from that described herein. For example, unless otherwise specified, the operations can be performed in an order other than the ascending or descending order described herein. Not all operations are mandatory in this disclosure and some of the operations described can be skipped or the operations in the example can be added to or modified somewhat without departing from the scope of the disclosure. Further, words such as "then," "next," etc., are used only to help provide a logical thread through the specification. These words should not be considered to restrict the scope of the disclosure, unless otherwise specifically stated herein. The term "comprising" and its derivatives, as used herein, mean the open-ended term "including" and are used synonymously therewith. Thus, use of "comprising" in the claims is not intended to limit the scope to the complete

[0204] For ease of description, the above apparatuses are described in various modules with different functions. Of course, in the implementation of the embodiments of the present disclosure, the functions of the modules can be implemented in one or more software and / or hardware, or the modules implementing the same function can be implemented by a combination of sub-modules or sub-units. The above-described apparatus embodiments are only schematic, for example, the division of the units is only a logical function division, and in actual implementation, another division mode can be adopted, for example, a plurality of units or components can be combined or integrated into another system, or some features can be ignored or not executed. In addition, the coupling or direct coupling or communication connection between the displayed or discussed each other can be indirect coupling or communication connection through some interface, device or unit, and can be electrical, mechanical or other forms.

[0205] Those skilled in the art also know that, in addition to implementing the controller in the form of pure computer readable program code, the controller can also be implemented in the form of logic gates, switches, application specific integrated circuits, programmable logic controllers and embedded microcontrollers by logically programming the method steps to achieve the same functions. Therefore, such a controller can be considered as a hardware component, and the devices included therein for implementing various functions can also be considered as structures within the hardware component. Alternatively, the devices for implementing various functions can also be considered as both software modules implementing the method and structures within the hardware component.

[0206] The computer program instructions can also be loaded onto a computer, other programmable data processing apparatus, or other devices to cause a series of operational steps to be performed on the computer, other programmable apparatus or other devices to produce a computer implemented process such that the instructions which execute on the computer or other programmable apparatus provide processes for implementing the functions specified in the flowchart block or blocks. Figure 1 The flowchart and / or block diagram in the Figures illustrate the architecture, functionality, and operation of possible implementations of systems, methods and computer program products according to various embodiments of the present application. In this regard, each block in the flowchart and / or block diagrams can represent a module, segment, or portion of code, which comprises one or more executable Figure 1 The flowchart and / or block diagram in the Figures illustrate the architecture, functionality, and operation of possible implementations of systems, methods and computer program products according to various embodiments of the present application. In this regard, each block in the flowchart and / or block diagrams can represent a module, segment, or portion of code, which comprises one or more executable

[0207] Those skilled in the art will appreciate that embodiments of the present specification can be further implemented in a computer program product tangibly embodied in a machine-readable storage medium (e.g., magnetic disk storage, CD-ROM, optical storage, and the like) including a series of computer program flow steps executed by a computer to produce an apparatus that performs one or more of the functions of the flowchart and / or block diagram.

[0208] Embodiments of the present specification can be described in the general context of computer-executable instructions, such as program modules, being executed by a computer. Generally, program modules include routines, programs, objects, components, data structures, and the like, that perform particular tasks or implement particular abstract data types. Embodiments of the present specification can also be practiced in distributed computing environments where tasks are performed by remote processing devices that are linked through a communications network. In a distributed computing environment, program modules can be located in both local and remote computer storage media including memory storage devices.

[0209] Each of the embodiments in the specification is described in a progressive manner, and the same or similar parts between the embodiments can be referred to each other. Each of the embodiments focuses on the difference from other embodiments. In particular, the system embodiments are described simply because they are basically similar to the method embodiments, and the relevant parts can be referred to the description of the method embodiments. In the description of the specification, the description of the terms "one embodiment", "some embodiments", "an example", "a specific example", or "some examples" means that the specific features, structures, materials or characteristics described in connection with the embodiment or example are included in at least one embodiment or example of the embodiments of the specification. The illustrative description of the above terms in the specification does not necessarily refer to the same embodiment or example. Moreover, the specific features, structures, materials or characteristics described can be combined in any suitable manner in any one or more embodiments or examples. In addition, the person skilled in the art can combine and combine the different embodiments or examples described in the specification and the features of the different embodiments or examples without contradiction.

[0210] The above only describes the embodiments of the embodiments of the specification and does not limit the embodiments of the specification. The embodiments of the specification can have various changes and variations for those skilled in the art. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the embodiments of the specification shall be included in the scope of claims of the embodiments of the specification.

Claims

1. A method for determining the water cut and the oil-gas ratio of a three-phase system, characterized in that, The method comprises: collecting total mass, total volume and gas volume of fluid produced by a target oil well wellhead in a preset monitoring period, wherein the produced fluid is in a three-phase mixed state of oil, water and gas; obtaining emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the fluid; determining liquid phase mass and liquid phase volume of the fluid according to total mass, total volume, gas volume and gas density of the fluid; calculating oil mass fraction in the liquid phase of the fluid according to liquid phase mass, liquid phase volume, emulsification rate, emulsification volume coefficient, oil density and water density of the fluid; determining water cut and oil-gas ratio of the fluid according to the oil mass fraction in the liquid phase of the fluid; wherein the oil mass fraction in the liquid phase of the fluid is calculated according to liquid phase mass, liquid phase volume, emulsification rate, emulsification volume coefficient, oil density and water density of the fluid, comprising: calculating the oil mass fraction in the liquid phase of the fluid according to the following formula: or calculating the oil mass fraction in the liquid phase of the fluid according to the following formula: wherein a represents the oil mass fraction, r represents the emulsification rate, δ represents the emulsification volume coefficient, the emulsification volume coefficient is the volume ratio of expansion or contraction before and after emulsification of the fluid, M l represents the liquid phase mass, p w represents the water density, p o represents the oil density, V l represents the liquid phase volume, s represents the proportion that can be emulsified in the oil phase.

2. The method of claim 1, wherein, determining water cut of the fluid according to the oil mass fraction in the liquid phase of the fluid, comprising: calculating water cut according to the following formula: where f w represents the water content, a represents the oil mass fraction, p w represents the water density, p o represents the oil density.

3. The method of claim 1, wherein, determining oil-gas ratio of the fluid according to the oil mass fraction in the liquid phase of the fluid, comprising: calculating oil-gas ratio according to the following formula: Where GOR represents the oil-gas ratio, v g ρ represents the volume of a gas. g ρ represents the density of a gas. o M represents the density of oil. total Indicates the total mass.

4. The method of claim 3, wherein, after determining oil-gas ratio of the fluid according to the oil mass fraction in the liquid phase of the fluid, further comprising: converting gas volume into standard volume under standard temperature and pressure; calculating oil-gas ratio under standard working condition according to the standard volume: wherein, V represents the standard volume of a gas at standard temperature and pressure o V represents the volume of the oil phase.

5. The method of claim 1, wherein, obtaining emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the fluid, comprising: collecting temperature and pressure of the target oil well wellhead in the preset monitoring period; calling a pre-established data reference table, wherein the data reference table records emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the fluid of the target oil well under different temperatures and pressures determined by external experiments; finding out emulsification rate, emulsification volume coefficient, oil density, water density and gas density corresponding to the temperature and pressure from the data reference table according to the collected temperature and pressure; taking the found emulsification rate, emulsification volume coefficient, oil density, water density and gas density as emulsification rate, emulsification volume coefficient, oil density, water density and gas density of the fluid.

6. The method according to any one of claims 1 to 5, characterized in that, after determining water cut and oil-gas ratio of the fluid according to the oil mass fraction in the liquid phase of the fluid, further comprising: determining pressure required by a separator and injection amount required by an emulsifier according to the water cut and oil-gas ratio; adjusting pressure of the separator according to the determined pressure required by the separator; injecting the emulsifier according to the determined injection amount required by the emulsifier.

7. An electronic device comprising a processor and a memory for storing processor-executable instructions, the electronic device characterized by: The processor executes the instructions to implement the steps of the method of any one of claims 1 to 6.

8. A computer readable storage medium having stored thereon computer programs / instructions, characterized in that, The computer program / instructions are executed by the processor to implement the steps of the method of any one of claims 1 to 6.

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