RU86976U1 - ADAPTIVE DEVICE FOR MEASURING OIL WELL DEBIT - Google Patents

Abstract

1. An adaptive device for measuring the flow rate of oil wells, containing a vertical measuring tank with a side pipe for supplying well products to it, with an upper pipe to discharge the associated gas and a lower pipe for draining the liquid, a temperature sensor in the measuring tank separator, two sensors level (liquid) signaling device for restricting the bottom and top of the respectively measured calibrated part (in volume units) of the tank by its height, one is the same, but intermediate, placed between them, -a signaling device, a differential pressure sensor in the measuring tank, an overpressure sensor in the upper cavity of the measuring tank, as well as a controller with a multichannel, by the number of sensors, input for introducing electric information signals of these sensors into it and a control output, product supply pipe, discharge pipe associated gas with a transducer installed in the flow meter-gas meter and a pipe for draining the liquid phase with a transducer installed in it, and information The outputs of the transducers of the gas flow meter, gas meter and moisture meter are connected to the multichannel input of the controller, the controller is controlled by a three-way valve, the inputs of which are connected to the associated gas discharge and fluid drain pipelines, respectively, and its output through the check valve is connected to the discharge pipe from the well, characterized in that a mass flow meter transducer with functions for measuring the mass flow and density of the liquid phase is installed in the liquid phase discharge line, information outputs

Description

The utility model relates to oilfield equipment and can be used to measure and control the flow rate of wells at oil production facilities.

To determine the flow rate parameters of the production of oil wells (single and group), separationless and separation measuring devices are used [1, 2]. Separating devices for measuring component flow rates (oil + gas + water) are the most common in the world, and they are implemented according to the classical schemes of three-phase or two-phase flow meters of oil wells.

In turn, separation devices are structurally and functionally divided into two types:

- component flow meters with horizontal hydrocyclone separator;

- component flow meters with a vertical measuring tank-separator.

Recently, component-based flow meters with a vertical metering tank-separator are becoming more widely used, using the hydrostatic method for determining the mass flow rates of oil and gas well products [3-6].

Devices [3-6] measure the flow rate of a well by recalculating the difference in hydrostatic pressures at the installation sites of the upper and lower level sensors in the separator using predetermined constants (such as oil density, formation water density) and the filling (emptying) time of a measured calibrated tank. A specific well is connected to a device for flow rate measurement by a well switch according to a program specified by a microprocessor. The calibrated measured volume of the device is limited by the sensors of the lower and upper levels, and the measurement and calculation of the liquid rate is provided by the microprocessor based on the information signals of the sensors when the separator is in the "filling-emptying" mode. The gas flow rate in such devices is determined by the volumetric method, by replacing the known volume of the calibrated capacity in the process of displacing the liquid phase from it into the collector.

With undoubted advantages (simplicity of design and circuit solutions, instrumentation, acceptable price, respectively for the customer), component-by-unit flow meters with a vertical measuring tank-separator, using the hydrostatic method for determining the mass flow rates of oil and gas wells [3-6], their significant disadvantage is the absence circuit and software solutions that allow you to adjust the mathematical model of the measuring process so that it is most complete (accurate) with the least heat identified the object (well).

Closest to the claimed technical solution (prototype) is a device [7] for measuring the flow rate of oil wells, containing a vertical measuring tank with a lateral pipe for supplying well products to it, with an upper pipe for the discharge of associated gas and a lower pipe for draining the fluid, a sensor temperature in a measured tank-separator, two level-liquid sensors (gauges) to limit the lower and top, respectively, of the calibrated measured part (in volume units) of the tank by its height , one is the same, but intermediate, a sensor-detector placed between them, two pressure sensors for measuring pressure in the upper cavity of the measuring tank and for measuring pressure at the lower level of its measured calibrated part, as well as a controller with a multichannel, by the number of sensors, input for introducing into it the electrical information signals of these sensors and the control output, the product supply pipe, the associated gas discharge pipe and the liquid phase discharge pipe, respectively controlled by the controller a three-way valve, the inlets of which are connected to the associated gas discharge and fluid drainage pipelines, respectively, and its outlet through the check valve is connected to the discharge pipe from the well, in the associated gas discharge and liquid drainage pipelines, respectively, transducers of gas and liquid phase flow meters, information the outputs of which are connected to the multi-channel input of the controller. In addition, a moisture meter transducer is installed in the liquid drain line, the information output of which is also connected to the multi-channel input of the controller.

The use of this design solution allowed us to create a device for measuring the flow rate of oil wells with increased functionality. Note the most significant of them:

- a twofold increase in the frequency of measurement of flow rates for liquid and gas due to an additional measurement of the flow rate of the liquid at the time of emptying the calibrated tank, taking into account the time of filling, and the gas phase - at the time of filling the calibrated tank with liquid, thereby increasing the reliability of measurement due to its duplication ;

- at the same time, in its development this device has the prospect of creating a self-adjusting algorithm on its basis by comparing the measurement results using the hydrostatic method and directly flow meters, liquid and gas meters and a moisture meter in order to continuously adjust (refine) the algorithm for measuring the component composition of wells .

However, this device (prototype) has a significant drawback, which is as follows. The numerical values of pairs of discrete time series for liquid and gas flow rates are the result of measuring the discrete values of these parameters, respectively, by the hydrostatic method (filling and replacing the volume of the measuring tank occupied by the liquid separated by gas) and liquid and gas flow meters, the flow transducers of which are installed respectively in pipelines for draining the liquid phase and venting associated gas. Consider a pair of discrete time series, one of which is a set of numerical discrete samples of the mass flow rate of a liquid (oil-water mixture) [3-6], measured by the hydrostatic method (filling and replacing the volume of a calibrated measuring tank occupied by a liquid separated by gas), and the other represents are the numerical values of the result of measuring the flow rate of the liquid by the flow meter-liquid counter .. The resulting time series are sets of discrete values of the flow rate of the product well, moreover, the numerical values of the measured flow rates have different dimensions, namely, the hydrostatic method gives a dimension in mass units of measurement of fluid flow (kg / hour or t / day), and the volumetric method implemented using a flow meter-counter of liquid gives a dimension in volumetric flow units (m ³ / hour or m ³ / day). It is natural to assume that comparing the measured numerical values of the same physical quantity (flow rate) with different dimensions may encounter certain difficulties. Moreover, it is incorrect to combine, compare and use these measurements to develop control actions - correctors of the algorithm for measuring the production rate of wells (self-tuning algorithm) with the aim, for example, of refining the model of the measuring process and, ultimately, improving the accuracy of the measurement.

Thus, the purpose of the claimed object (otherwise, the required technical result) is to provide the well-known technical solution of higher consumer properties:

- optimization of the structural diagram of the device, in which it is possible to duplicate measurements by combining two devices (methods) in one measurement cycle for the purpose of obtaining numerical values of measured production rates of wells in the liquid phase having the same dimension (t / day or kg / hour );

- giving the device adaptability properties with respect to the measuring model of the object (well).

As bench and industrial tests of the inventive device and operating experience of the prototype device show, the goal (technical result) is achieved by the fact that the device for measuring the flow rate of oil wells containing a vertical measuring tank with a side pipe for supplying well products with the upper pipe for evacuation of associated gas and a lower nozzle for draining the liquid, a temperature sensor in the measuring tank-separator, two level sensors (liquid) to limit bottom and top, respectively, of the calibrated measured part (in volume units) of the tank by its height, one is the same, but intermediate, placed between them, a signaling device, a differential pressure sensor in the measuring tank, an overpressure sensor in the upper cavity of the measuring tank, as well as a controller with a multichannel, according to the number of sensors, input for introducing electric information signals of these sensors into it and a control output, a product supply pipeline, an associated gas discharge pipeline a gas with a gas flow meter counter transducer installed and a liquid phase discharge pipeline with a moisture meter transducer installed in it, and the information outputs of the gas meter and gas meter transducers are connected to a multichannel controller input controlled by a three-way valve controller, the inputs of which are connected to the associated discharge pipelines gas and fluid draining, respectively, and its outlet through a non-return valve is connected to the flow line from the well, in addition to the pipeline deletion of the liquid phase, a mass flowmeter transducer with functions for measuring the mass flow rate and density of the liquid phase is installed, the information outputs of which are mass flow rate and density connected to the multi-channel input of the controller.

In addition, the controller of an adaptive device for measuring oil production rates is configured to, for each well connected to the measurement, pairwise compare on one side the numerical values of discrete time series, each of which contains at least 10 samples of mass flow rate, density of the liquid phase (water-oil mixture), associated petroleum gas flow rate (parameters of the 1st group), measured by the hydrostatic method (filling and replacing the volume of the measured calibrated tank occupied by the liquid gas, and on the other hand, the corresponding numerical values of the same parameters (parameters of the 2nd group), but measured by a mass meter with functions of measuring mass flow and density and a flow meter - gas meter, and determination using statistical criteria (for example, F -criterion) the equidistance (unequality) of the measured pairwise values of the parameters of the 1st and 2nd groups and their compatibility.

In addition, the controller of the adaptive device for measuring oil production rates is configured to update the measurement results after the next connection of each current well from the group of wells to measure the parameters of the 1st and 2nd groups, respectively, while maintaining a constant number of discrete readings for each pair of homogeneous measured and compared parameters.

In addition, the controller of the adaptive device for measuring oil production rates is configured to select and store those numerical values of discrete time series of parameters of the 1st and / or 2nd groups, the variation coefficients of which are minimal for a given measurement error and which (numerical values) in the future they can be used to calculate the derived indicators of oil well production.

In addition, the controller of the adaptive device for measuring the flow rate of oil wells is configured to, for each well connected to the measurement, determine the mass of salable oil from the results of measurements at the well

Where: - the mass of free (separated) gas released in the separator from one ton of reservoir oil, measured in the metering unit;

W is the volumetric coefficient of water cut of the mixture, measured by a hygrometer in the metering unit;

V _cm - volume of the mixture, measured by the measuring installation by filling a calibrated container portion corresponding _to V;.

G _f - the value of the gas factor inherent in this particular well (reservoir), nm ³ / t;

ρ _g - the density of associated petroleum gas, reduced to standard conditions, tn / m ³ ;

ρ _n - oil density of a particular well.

In addition, the controller of the adaptive device for measuring oil flow rates is configured to set the three-way valve to a position in which modes of maintaining a constant liquid level in the measuring tank and continuously measuring the parameters of the 2nd group (flow rate and fluid density and flow rate) can be implemented gas), respectively, a mass flow meter with the functions of measuring mass flow and density of the liquid phase and a gas flow meter.

The required technical result is ensured by the presence of the essential features (characterizing the proposed design of the device for measuring the flow rate of a group of oil wells) of the above distinctive features, and the failure to find equivalent technical solutions with the same properties of undoubted industrial applicability in public sources of patent and technical information implies that the claimed object meets the criteria " utility model. "

The figure shows a schematic diagram of an adaptive device for measuring the flow rate of oil wells.

The adaptive device (see the figure) consists of a vertical measuring tank 1 with a side pipe 2 for supplying well products to it, with an upper pipe 3 for discharging associated gas and a lower pipe 4 for draining the fluid. It contains a temperature sensor 5 in a measured tank-separator, level 6 sensors and level 7 sensors (liquids) for restricting the measured and measured part (in units of volume) of the tank from above and below the height of the tank according to its height H, an intermediate sensor 8, overpressure sensor 9 for measuring pressure in the upper cavity of a measuring tank filled with gas, a hydrostatic pressure difference sensor 10 for measuring differential pressure in the calibrated part of the measuring tank, and also a controller 11 with multi-channel, about the number of sensors, input 12 for introducing electrical information signals of these sensors into it and control output 13, product supply pipe 14, associated gas discharge pipe 15 and liquid phase discharge pipe 16, respectively controlled by a controller 11 three-way valve 17, the inputs of which are “a” and “b” are connected to pipelines 15 and 16 for associated gas discharge and fluid draining, respectively, and its outlet “c” through the check valve 18 is connected to the discharge pipe 19. On pipelines 15 and 16 for associated gas discharge and draining the liquid phase respectively installed converters 20, 21 and 22 of the gas flow-meter, moisture and mass flow meter with a measurement function of mass flow and density of the liquid phase. The information outputs of the transducers 20, 21, including the mass flow meter transducer 22 (output information buses 23 and 24) are connected to the multi-channel input 12 of the controller 11.

The adaptive device operates as follows. According to the previously known - (according to the results of productivity tests) productivity for a particular well, the most acceptable filling of the measuring tank with liquid corresponding to its expected flow rate is established (set), that is, a specific part of the calibrated measured volume V is involved, based on the condition that the device provides a minimum possible time t _c . The exit "to" of the valve 17 when preparing the device for operation is connected by a temporary pipeline (a separate position not shown) to the flow line of the well through a non-return valve 18, and the production of the well through a production supply line 14, which, as in the prototype device, is equipped with a gas pre-sampling unit ( this node is shown in the drawing, but is not indicated by a separate position), enters the measuring tank 1, where it is degassed. The three-way electrically operated crane 17 is in a position in which the input “b” of the crane and its output “c” are open. Associated gas, the flow rate of which is measured by the flow meter-counter 20, under the existing overpressure in the measuring tank 1 through the gas discharge pipe 15, the converter of the gas flow meter-counter 20, the valve input “b” and its output “c” are directed to the flow line of the well. Accordingly, the liquid begins to fill the cavity of the measuring tank of a given volume.

When the liquid reaches the initial reference level, the controller 11, by the signal of the sensor-signaling device 6, turns on the controller timer. After that, the measurement time starts, that is, the duration of filling the corresponding measured part of the tank with liquid from one level to another is monitored and taken into account, and the hydrostatic pressure of the liquid column is determined by the value of the output current I ₁ of the pressure sensor 10.

When the liquid reaches the second (predetermined) reference level, the controller, by the signal of the corresponding sensor-detector (7 or 8), records the measurement time t _c and the hydrostatic pressure of the liquid column P ₂ by the value of the output current I ₂ of the pressure sensor 10. Then, according to the well-known algorithm [1, 3], the controller calculates the mass flow rate of the liquid phase.

Thus, the processes of measuring the flow rate of both liquid and gas are combined in time.

A moisture meter 21 installed on the pipe 16 measures the percentage or quantity of water in the production of the well. Note that the controller 11 contains a program [3] that provides the calculation of the mass flow rate of water as the most representative component of the oil-water mixture. The availability of additional information obtained using a moisture meter, as practice shows, significantly increases the reliability of measuring the production rate of oil wells.

After the process of filling the cavity with the measured volume of the tank from the minimum level to the maximum (or intermediate) three-way electrically operated valve 17 is switched by the command from the controller 11 to the "liquid drain" position. The liquid begins to be displaced from the measured part of the calibrated reservoir by the compressed gas available in its upper part, and through the inlet “a” and outlet “c” of the valve 17 enters the flow line of the well. Thus, the gas flow rate is determined by the volumetric method, by replacing the known (calibrated) volume in the process of gas displacement of liquid into the reservoir. At the same time as measuring the gas volumetric flow rate according to the algorithm given in [1, 3], the mass flowmeter 22 of the liquid, the transducer of which is installed on the pipe 16, measures the mass flow rate and the density of the liquid phase displaced by the gas from the measuring tank, that is, the flow measurement processes both gas and liquid are combined in time.

The check valve 18 protects the device from unauthorized backflow of products.

As mass can be selected, for example, vibration mass flow meters (BMP), which use the effect of the occurrence of Coriolis accelerations (Coriolis effect) when the medium is flowing through a vibrating pipe segment [10, 11]. Coriolis mass flowmeters of various designs (with one curved measuring tube, with two parallel curved measuring tubes, straight tube, etc.) are widely used, including in the oil industry. In our case, their value is due to the fact that they can measure the mass flow rate of the oil-water mixture and its density with high accuracy. Thus, it was possible to compare the measurement results in two parameters: mass flow rate (hydrostatic and Coriolis methods) and density (differential pressure in the measuring tank and natural frequency of the vibrating tube of the Coriolis flowmeter).

Recalculation of the parameters of the state of production recorded in the measured part of the reservoir by the controller (based on information signals from the sensors) into the well production rate, controller 11 performs according to well-known dependencies embedded in its standard software (RF certificates for other computers No. 990761 and 990762) developed earlier by the applicant’s staff and improved at the filing date of this application.

Thus, during the operation of the device, three pairs of discrete time series are formed in the controller’s memory for each well connected to the measurement, which are numerical values of the following parameters:

- the mass flow rate of the liquid phase, measured respectively by the hydrostatic method (filling the calibrated measuring tank with liquid) and when emptying the calibrated measuring tank, taking into account the previously measured time of filling, with a mass flow meter, the converter of which is installed in the liquid phase discharge line;

- the volumetric flow rate of the gas phase, measured in the process of replacing the volume of the calibrated measuring tank occupied by the liquid, the separated gas and, accordingly, the gas flow meter, the converter of which is installed in the associated gas discharge pipe;

- the density of the liquid phase, measured using a differential pressure sensor and, accordingly, a mass meter in the density measurement mode in the process of emptying the measuring calibrated capacity.

The mathematical model of the measuring process, in fact, is a model of an object (well), which is characterized by a number of technological parameters controlled and measured by a device for measuring the flow rate of oil wells [1-6]. The task is to find a criterion by which it would be possible to adjust the mathematical model so that it most fully (accurately) with the least error identifies the object (well). In other words, under certain conditions, namely, if there is a certain criterion, the device for measuring oil production will operate in a self-adjusting mode, as a result of which the measured (controlled) object (well) is most fully identified through its technological parameters.

In order to be able to use the obtained results in the form of numerical values of discrete samples in each pair (of 3 pairs) of discrete time series to determine other (derived) indicators (parameters) of the well, they (results) must be checked (from the metrological point Vision) on indifference (non-uniformity), since they were obtained [8, 9] by measurements using various methods (hydrostatic and instrumental). In our case, the controller is made with the possibility, for each well connected to the measurement, of pairwise comparison on one side of the numerical values of discrete time series, each of which contains at least 10 samples of mass flow, density of the liquid phase (oil-water mixture), and associated oil flow gas (parameters of the 1st group), measured by the hydrostatic method (filling and replacing the volume of a calibrated measuring tank occupied by a liquid separated by gas) and, on the other hand, corresponding the measured values of the same parameters (parameters of the 2nd group), but measured by a mass meter with the functions of measuring mass flow and density and a flow meter - gas meter, and determining, using statistical criteria [9] (for example, the F-criterion), the measured uniformity (unequality) values of the parameters of the 1st and 2nd groups and their compatibility. In addition, the controller is configured to update the measurement results after the next connection of each current well from the group of wells to measure the parameters of the first and second groups, respectively, while maintaining a constant number of discrete samples for each pair of homogeneous measured and compared parameters. The number of measurements (measurement cycles) equal to 10 is taken from the calculation of the representativeness of the (statistical) time discrete series [9, 12].

Thus, for each well connected to the measurement, the controller remembers the results of the last 10 measurements for each pair of homogeneous parameters (flow rate and density of the liquid phase, flow rate of the gas phase), compares them in pairs and, based on the statistical F-criterion [9], confirms or It does not confirm the hypothesis of uniformity and compatibility of measurements, moreover, a test for compatibility of measurements is carried out regardless of the outcome of the test for equalness of the corresponding discrete time series.

When confirming the compatibility hypothesis of numerical sequences of paired discrete time series, the question arises of choosing the numerical values of a particular series for their use as reporting material for each well and, for example, for calculating derivatives, relatively speaking, of indirect indicators (parameters) of a well, such as flow oil Q _n , water consumption Q _in , mass free (separated) gas released in the separator from one ton of reservoir oil and others. Regardless of this point, the question of choosing the best option in the theory of measurement and production control systems has been resolved [13]. The most complete, physically adequate to many problems of control and management, as well as a fairly general assessment of accuracy is the mean square error of the value estimate. The most common estimate of a parameter given by a continuous or, as in our case, discrete implementation, in the general case, of a random process, is the estimate of mathematical expectation. In turn, the optimal estimate of the error in estimating the mathematical expectation from a discrete series of points of realization of a random process is the mean square error (see formula 3-24 [13, p. 351]), for a concrete estimate of which it is necessary to know the correlation function of the process. As a matter of fact, the mean square error of the estimate of the mathematical expectation of each of the paired discrete time series can be the criterion by the numerical value of which we can judge the preference of this or that series for its further use for the purpose of refining the mathematical model of the measurement object (well), including number and to determine the derived parameters, as mentioned above. However, knowledge of the correlation function of the process requires a rather lengthy implementation of the discrete time series (up to one hundred samples), which makes it impossible for us to practically use this estimate, since the meaning of measurements for the purpose of their operational use in refining the model of the object is lost.

In our opinion, the most preferred criterion, from the point of view of the speed of its use and application in the device, is the coefficient of variation of a specific numerical sequence (time series), determined by the formula

where x ₁₀ is the estimate of the mathematical expectation of the parameter (a particular discrete time series);

x _i is the i-th sample of the measured parameter (i = 1 ... 10);

n is the number of discrete samples in a row equal to 10.

From each pair of discrete time series, preference is given to the series with the lowest coefficient of variation. It is these time discrete series, their numerical values, that should be further used both for current reporting on well flow rates and for determining derived indicators. Thus, the controller is configured to select, store and provide information to the consumer of those numerical values of discrete time series of parameters of the 1st and / or 2nd groups, the variation coefficients υ of which are minimal for a given measurement error, and then uses them (numerical values) for calculating the derivative indicators of oil well production, including such as oil consumption Q _n , water consumption Q _c , mass free (separated) gas released in the separator from one ton of reservoir oil.

Recently, in connection with the introduction of GOST R 8.615-2005, the determination of marketable oil based on the measurement results (for each individual well) of crude oil production has become relevant.

With the generally accepted single-pipe collection system, the entire oil and gas mixture after a group metering unit (GZU) is fed to the separation units of technological facilities: booster pump stations (BPS), complex assembly points (KSP), central commodity parks (CTP), oil treatment plants (UPN), in which almost complete gas separation takes place, and oil becomes marketable. Without taking into account oil losses throughout the entire production chain, the material balance for one ton of reservoir oil mass at the end of the described process chain can be represented as:

Where - the total mass of gas released from one ton of reservoir oil at all stages of separation.

Since formulas (2) and (3) of the material balance are reduced to the same mass (1 tn) of reservoir oil , then, solving them together, we get:

In the resulting expression for measured parameters and are determined under operating conditions (at pressure P and temperature T) of the metering unit.

Value determined from the expression:

Substituting expression (5) into equation (4), we obtain:

The resulting expression to determine according to the results of measurement (or calculation) at the well shows that the greater the gas factor of oil, the greater the difference between and . This expression can be used to reduce the balance of salable oil from measurements on a separate well, since it allows the results of measuring the mass oil content in the gas storage unit for each well to determine the contribution of this well to the mass of marketable oil measured at the final nodes of the oil metering (UCN), but for this it is necessary to know the values of the parameters G _f and ρ _g (determined in the study of all reservoir oils), as well as measure the mass of free gas released in the separator. The numerical values of the parameters G _f and ρ _g included in formula (6) are determined in the study of reservoir oils of exploited fields, and and measured on a certified metering system. It is natural to assume (proved and experimentally) that a comparison of the results of measuring the volume and mass of marketable oil of any particular well that has passed through a commercial metering unit and supplied to the oil pipeline system and is certified by a measuring unit allows revealing an unbalance. There are many reasons for the unbalance: the presence of unaccounted mechanical impurities in crude oil, technological oil losses during collection, transportation and preparation, the accuracy class of measuring instruments of commercial metering units and operational (measuring units).

When assessing the influence of each of the parameters included in formula (6) on the error of determination we have theoretically and experimentally proved that the error in determining the mass of salable oil is approximately equal to the relative error in measuring oil on the gas unit. In actual field practice, oil, as a rule, can be watered, therefore, depending on the measurement scheme and instrumentation of the GZU in formula (6), instead of any of the well-known expressions can be applied [6]:

where: M _n - mass content of oil in the mixture;

M _cm , V _cm - measured in GZU, respectively, the mass and volume of the mixture;

ρ _cm , ρ _in , ρ _n - respectively, the density of the mixture, water and oil;

W is the water cut ratio of the mixture.

An analysis of the above formulas (7 ... 10) and a description of their applicability in various instrumentation variants [4] show that all four options can be reduced to two:

1. The water content of the mixture W is determined through the measured and set density of the mixture (ρ _cm ), oil (ρ _n ) and water (ρ _in );

2. The water content of the mixture W is measured by special instruments.

Therefore, in the future, only formulas (9) and (10) can be used.

Substituting in (6) the mass of the oil content M _n in the mixture, determined by the formula (9), we obtain:

where: M _cm is the mass of the oil-water mixture measured by mass-measuring devices in the metering unit, t;

ρ _cm is the density of the oil-water mixture, measured in the metering unit (at P and T in the installation), t / m ³ ;

ρ _in - the density of water (at P and T in the installation) of each well, tn / m ³ ;

W is the volumetric coefficient of water cut of the mixture, measured by a hygrometer in the metering unit.

Solving together (6) and (10), taking into account the well-known equality

we get the expression for according to the measurements of the volumetric mass GZU:

Formula (12) can be used to determine the mass of salable oil from the results of measurements at the well and is recommended for adjusting the algorithms of calculators of currently produced single and group metering units entered in the SI Register, as well as as material for the development of new regulatory documents for the development of GOST R 8.615-2005.

A positive aspect of this technical solution of an adaptive device for measuring oil production is also the fact that the controller is configured to set the three-way valve to a position in which modes of maintaining a constant liquid level in the measuring tank and continuous measurement of the parameters of the 2nd group can be implemented (flow rate and liquid density and gas flow rate), respectively, a mass flow meter with the functions of measuring the mass flow rate and the density of the liquid phase and flow rate rum gas meter. This undoubtedly expands the functionality of the proposed technical solution.

Thus, the use of this design solution allowed us to create a device for measuring the flow rate of oil wells with increased functionality. Note the most significant of them:

1. double (artificial) increase in the frequency of measurement of flow rates for liquid and gas through the use of processes of both filling and emptying the measured calibrated capacity, moreover, each of the measured numerical values of flow rates for liquid has the same dimension (kg / h or t / day);

2. improving the reliability of the measurement due to its duplication;

3. the possibility of continuous adjustment (refinement) of the algorithm for measuring the component composition of wells by comparing the results of measurements with three parameters of the measurement object (oil well):

- according to the numerical values of the mass flow rates of the liquid (oil-water mixture) obtained using the hydrostatic method and directly the mass flow meter of the liquid in the mode of measuring the mass flow rate of the liquid;

- according to the numerical values of the volumetric flow rates of the gas phase obtained by replacing the known volume of the measured tank occupied by the liquid, the separated gas and the gas flow meter counter;

- by the numerical values of the density of the oil-water mixture, measured using a differential pressure sensor using the dependence given in [4, p.17], and directly by a mass flow meter in the density measurement mode, which led to the creation of an adaptive (self-adjusting) algorithm in the structure of the proposed constructive solution of the device, which, in turn, allows you to adjust the mathematical model of the measuring process in real time so that it is most complete (accurate) with the smallest identified the object (well) with error.

4. Introduction to the device of modes of maintaining a constant liquid level in the measuring tank and continuous measurement of the parameters of the 2nd group (flow rate and density of the liquid and gas flow rate), respectively, by a mass flow meter with the functions of measuring the mass flow rate and density of the liquid phase and a gas flow meter.

All this taken together allowed us to create a device for measuring the flow rate of oil wells, which allows a high degree of accuracy to identify the mathematical model of the measuring process of an object (well), which allows us to relate it (device) to the class of adaptive devices [14].

The set of essential features (including distinguishing ones) of the claimed device for measuring the flow rate of a group of oil wells ensures the achievement of the required technical result, meets the criteria of the "utility model" and is subject to protection by a title of protection of the Russian Federation in accordance with the request of the applicant.

SOURCES OF INFORMATION TAKEN INTO ACCOUNT WHEN DRAWING OUT THIS APPLICATION:

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4. NTZ “Automation, telemechanization and communication in the oil industry”. M, OJSC "VNIIOENG", 2001, No. 1-2, p.16-18.

5. RF, description of the utility model according to patent No. 36858, IPC ЕВВ 47/10, priority November 20, 2003.

6. RF, description of the utility model according to patent No. 61344, IPC ЕВВ 47/10, priority 01/19/2006.

7. RF, description of the utility model according to patent No. 77348, IPC ЕВВ 47/10, priority 11.06.2008 (prototype).

8. Sergeev A.G., Latyshev M.V., Teregerya V.V. Metrology, standardization, certification: Textbook. Allowance. - Ed. 2nd, rev. and add. - M .: Logos, 2005 .-- 560 s, (p. 84, 85).

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10. Measurements, control, automation, 1980, No. 7-8, (p. 27-32).

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Claims (6)

1. An adaptive device for measuring the flow rate of oil wells, containing a vertical measuring tank with a side pipe for supplying well products to it, with an upper pipe to discharge the associated gas and a lower pipe for draining the liquid, a temperature sensor in the measuring tank separator, two sensors level (liquid) signaling device for restricting the bottom and top of the respectively measured calibrated part (in volume units) of the tank by its height, one is the same, but intermediate, placed between them, -a signaling device, a differential pressure sensor in the measuring tank, an overpressure sensor in the upper cavity of the measuring tank, as well as a controller with a multichannel, by the number of sensors, input for introducing electric information signals of these sensors into it and a control output, product supply pipe, discharge pipe associated gas with a transducer installed in the flow meter-gas meter and a pipe for draining the liquid phase with a transducer installed in it, and information The outputs of the transducers of the gas flow meter, gas meter and moisture meter are connected to the multichannel input of the controller, the controller is controlled by a three-way valve, the inputs of which are connected to the associated gas discharge and fluid drain pipelines, respectively, and its output through the check valve is connected to the discharge pipe from the well, characterized in that a mass flow meter transducer with functions for measuring the mass flow and density of the liquid phase is installed in the liquid phase discharge line, information outputs which by mass flow rate and density are connected to the multi-channel input of the controller. 2. The adaptive device for measuring the flow rate of oil wells according to claim 1, characterized in that the controller is configured to, for each well connected to the measurement, pairwise comparison on one side of the numerical values of discrete time series, each of which contains at least 10 samples of mass flow rate, density of the liquid phase (oil-water mixture), flow rate of associated petroleum gas (parameters of the 1st group), measured by the hydrostatic method (filling and replacing the volume of the measured calibrated tank occupied liquid separated by gas) and, on the other hand, the corresponding numerical values of the same parameters (parameters of the 2nd group), but measured by a mass meter with functions of measuring mass flow and density and a gas flow meter, and determination using statistical criteria (for example, F -criterion) of the equidistance (unequality) of the measured values of the parameters of the 1st and 2nd groups and their compatibility. 3. The adaptive device for measuring the flow rate of oil wells according to claim 2, characterized in that the controller is configured to update the measurement results after the next connection of each current well from the group of wells to measure the parameters of the 1st and 2nd groups, respectively, while maintaining a constant number of discrete samples for each pair of homogeneous measured and compared parameters. 4. An adaptive device for measuring the flow rate of oil wells according to claims 1 and 2, characterized in that the controller is configured to select and store those numerical values of discrete time series of parameters of the 1st and / or 2nd groups, the variation coefficients of which for a given measurement errors are minimal and which (numerical values) can be further used to calculate the derived indicators of oil well production. 5. The adaptive device for measuring the flow rate of oil wells according to claim 1, characterized in that the controller is configured to, for each well connected to the measurement, determine the mass of salable oil from the results of measurements at the well

Where

- the mass of free (separated) gas released in the separator from one ton of reservoir oil, measured in the metering unit; W is the volumetric coefficient of water cut of the mixture, measured by a hygrometer in the metering unit; V _cm is the volume of the mixture measured by the meter by filling the corresponding part of the calibrated container; G _f - the value of the gas factor inherent in this particular well (reservoir), nm ³ / t; ρ _g - the density of associated petroleum gas, reduced to standard conditions, tn / m ³ ; ρ _n - oil density. 6. The adaptive device for measuring the flow rate of oil wells according to claim 1, characterized in that the controller is configured to establish a three-way valve in such a position that modes of maintaining a constant liquid level in the measuring tank and continuous measurement of the parameters of the 2nd group can be implemented (flow rate and liquid density and gas flow rate), respectively, a mass flow meter with functions for measuring mass flow and density of the liquid phase and a gas flow meter.