RU2749256C1 - Mobile standard of the 2nd discharge for verification of well measurement units - Google Patents

Abstract

FIELD: measuring equipment.SUBSTANCE: invention relates to measuring equipment, namely to devices used to measure the parameters of a multiphase flow and transfer the unit of mass flow rate of well production to working measuring instruments. The standard contains a line for supplying an oil-gas-water mixture, a horizontally oriented separation and measuring tank, a vertically oriented oil analyzer, a liquid measurement line, a gas measurement line, and an automated control system. Moreover, the separation-measuring tank consists of two communicating vessels, a lower tank for receiving liquid and an upper tank for receiving gas, equipped with a hydrocyclone with a gas swirler. The hydrocyclone is connected to the oil-gas-water mixture supply line and is partially submerged in the container for receiving the liquid. Antifoam, a drop catcher, a level meter, and a pressure transducer are installed in the separation-measuring tank. A liquid measurement line is connected to the container for receiving liquid, and a gas measurement line is connected to the container for receiving gas. The gas measurement line contains a system for measuring the content of dropping liquid in the associated petroleum gas flow. The liquid measurement line contains a moisture transducer installed at the liquid outlet from the separation and measurement tank, three parallel sections, into which liquid mass flow meters are connected, and a multiphase flow meter. A differential pressure transducer and an oil-gas-water mixture sampler connected to the oil-gas-water mixture supply line to the oil analyzer are connected to the oil-gas-water mixture supply line. The oil analyzer contains a rotary housing mounted on a support with the ability to fix the vertical position. The analyzer housing contains a level gauge with an interface level meter, pressure and temperature transducers and a hydrostatic pressure sensor, the sensing elements of the level gauge and auxiliary structures are located inside the analyzer case. The automated control system includes a control cabinet with a controller complete with a display. These structural elements are located in a block-container type box, located on the base, divided by a sealed explosion-proof partition into two rooms, a technological unit and a control unit.EFFECT: invention ensures possibility of measuring the parameters of the multiphase flow of the well product (oil and gas-water mixture) and transferring the mass flow rate unit of the well product to the working means for measuring the mass flow rate and the amount of crude oil, gas in operation, for checking and determining with increased accuracy the flow rates of oil wells for oil and gas, with the purpose of ensuring the uniformity of measurements of mass flow.1 cl, 8 dwg

Description

The field of technology.

The invention relates to measuring equipment, namely to devices used in oil production for measuring the parameters of the multiphase flow of well production (oil and gas-water mixture), measuring the mass flow rate and mass of crude separated oil, measuring the volumetric flow rate and volume of free petroleum gas, measuring the volume or mass fraction of water , measuring the mass flow rate and mass of crude oil without taking into account water in the flow, and can be used to transfer the unit of mass flow rate of well products to working means for measuring the mass flow rate and amount of crude oil, gas in operation, to verify and determine with increased accuracy the flow rates of oil wells for oil and gas, in order to ensure the uniformity of mass flow measurements.

State of the art.

Periodic verification of working measuring instruments, stationary measuring installations designed for operational accounting of production rates (oil and gas-water mixture) of oil and gas condensate wells in pressurized gathering systems located at wells, well pads or at the entrance to oil treatment plants requires the use of mobile measuring complexes-standards not less than the 2nd accuracy category. The rules for checking working measuring instruments are determined in accordance with GOST 8.637-2013 “GSI. State verification scheme for instruments for measuring the mass flow rate of multiphase flows ”. In this case, it is necessary to ensure the transfer of a multiphase flow rate unit from the primary state standard to the standards of the 1st category and, further, to the standards of the 2nd category and field measuring installations. The most convenient way to calibrate stationary measuring installations is the use of mobile verification devices-standards of the 2nd category.

From the prior art, metering installations with storage tanks are known, the design of which is based on a separation method for determining the flow rates of phases (source [1]: Dahl E. Handbook of multiphase flow metering / E. Dahl, C. Michelsen // The Norwegian Society for Oil and Gas Measurement, Revision 2, March 2005. Source [2]: I. R. Yagudin, V. N. Petrov, A. F. Dresvyannikov. A promising direction in the development of mobile calibration facilities for measuring crude oil // Bulletin of Kazan Technological University. / / 2013, v.16, No. 4, pp. 203-208 Source [3]: Type description to the certificate of type approval of the measuring instrument "Working standard of the 2nd category of the unit of quantities of the mass flow rate of crude oil, mobile" RU.E .29.006A No. 47152, with registration No. 50353-12. Source [4]: Type description to the certificate of type approval of measuring instruments "Laboratory for metrological mobile measurements of crude oil and petroleum gas" LMSN "RU.E.29.006A No. 47579, with registration number No. 50727 -12. FSUE VNIIR, Federal Fund for Ensuring the Uniformity of Measurements (State Register of Measuring Instruments). 1-6 (2012). Source [5]: Description of the type to the certificate of type approval of the measuring instrument "Mobile measuring unit UZM.T" RU.E.29.006A No. 37558, with registration No. 27867-09. FSUE VNIIR, Federal Fund for Ensuring the Uniformity of Measurements (State Register of Measuring Instruments). 1-5 (2009). Source [6]: Description of the type to the certificate of approval of the type of measuring instrument "Mass-measuring transportable type" ASMA-T "RU.E.29.006A No. 24351, with registration No. 14055-04. FGU TsSM RB, Federal Fund for Ensuring the Uniformity of Measurements (State Register of Measuring Instruments). 1-5 (2004). FSUE VNIIR, Federal Fund for Ensuring the Uniformity of Measurements (State Register of Measuring Instruments). 1-7, 2012).

Installations [1-6] have a number of disadvantages. The main disadvantage of using separation plants [1-6] with storage separation tanks during verification is their inertia, high error due to entrainment of liquid by gas or entrapment of gas by liquid, influence on the operating conditions of measurement, and the presence of limitations on the ranges of measured parameters. The design of measuring installations [1-6] during measurements allow a relatively high measurement error, similar to stationary measuring installations located in the wells, therefore they cannot be used for periodic verification of stationary measuring installations, since they only provide a comparison of two measuring instruments measuring with the same precision. To ensure the verification of stationary measuring installations, a higher measurement accuracy is required, a second order standard is required.

Among the existing measuring installations, three main schemes of the measurement process can be distinguished, which determine the following types of measuring installations: hydrostatic type, dynamic type, multiphase type (source [8]: E. Toski. Evolution of multiphase flow measurements and their impact on operation control / E. Toski , E. Okugbaye, B. Tuveni, B. V. Hanssen, D. Smith // Oil and Gas Review. No. 12,2003. P. 68–77.).

Plants of the hydrostatic type. The inlet gas is separated from the liquid in a separation vessel. The measurement of the flow rate of liquid and gas is carried out by determining the rate of loading / unloading in a calibrated vertical vessel (level gauge) using hydrostatic pressure sensors. The water cut is measured, for example, by recalculating the ratio of laboratory densities of water, oil and the actual density measured using a hydrostatic pressure sensor.

Plants of the hydrostatic type have a simple design and low cost. Due to the cyclic operation of the unit with a constant flow of well production (gas or oil), a minimum pressure drop is created in them during measurement and there is no additional back pressure on the well during the measurement. This achieves high reliability of liquid flow measurements. At the same time, the accuracy of determining the water cut of well production is sensitive to the presence of free and dissolved gas. Even an insignificant content of free gas in a liquid significantly affects the density of the liquid, which leads to an increase in the error in determining the water cut. The accuracy of determining the amount of gas directly depends on the ratio of the gas flow rate and the liquid flow rate. With a high gas-oil ratio of the production produced in the well, an extremely fast emptying of the calibrated tank occurs in the installation and the inertia in the operation of the actuators leads to an increase in the error. In installations of this type, it is impossible to calculate the ratio of the amounts of free and dissolved gas, as well as the amount of dropping liquid in the gas flow.

Installations of a dynamic type. The inlet gas is separated from the liquid in a separation vessel. The flow rate of liquid and gas is measured using flow meters located in individual metering lines. The water cut is measured using a moisture meter installed in the liquid measuring line.

The most accurate settings at the moment. They have a wide range of flow rate measurements due to the possibility of using flow meters of different capacity, as well as the possibility of their combinations. This allows the installation to be used on wells that differ significantly in productivity. The use of regulating devices in the measuring lines makes it possible to ensure a sufficient flow rate of the medium in the flow meters. As in installations of a hydrostatic type, in this case it is also impossible to determine the amount of free and dissolved gas, as well as the amount of dropping liquid in the gas flow, without additional methods. Another negative factor is the influence of residual free gas on the readings of a Coriolis meter when measuring liquid flow.

Installations of multiphase type. The inlet gas is not separated from the liquid. The measurement does not require phase separation (no separation). The installations use multiphase flow meters. A multiphase flow meter measures a wide range of liquid and gas parameters: temperature, pressure, differential pressure, dielectric permeability, mass of the medium, density of the medium. The flow is scanned using a radioisotope or optical sensor. All these parameters enter the control station containing the computer and are processed according to the embedded mathematical models.

The main advantage is that there is no need to separate the well production into gas and liquid components of the flow. This significantly reduces the size of the installation and partly eliminates the errors introduced by the separation process. Laboratory data on the component composition of the gas make it possible to apply algorithms for calculating the amount of dissolved and free gas. The disadvantages of existing multiphase installations include the difficulty in setting up / calibrating on a real installation. Computational algorithms opaque. The need for additional processing of the received data. In addition, as the practice of testing multiphase flows at Tyumen State University at the scientific and testing metrological stand has shown (the stand is certified as a working standard for a mass flow unit of gas-liquid mixtures by the Federal Agency for Technical Regulation and Metrology), multiphase installations in a number of modes do not achieve the accuracy required for the standard.

There is a known method for determining the water cut of a liquid in the production of oil wells and a device that implements the method (source [9]: patent for invention RU 2299322). The device contains: a separation unit, including a gas separator (separation tank for separating liquid and gas), for separating the well product into gas and liquid, a measuring tank, a level gauge for analyzing the composition liquids, flow switches, gauge pressure gauge, drain liquid line, gas pipeline (gas line), well inlet, manifold outlet, drain outlet, check valve, condensate sump, safety valve, inlet axial swirler, separation trays, gas separator flange connection and measuring tank, funnel of the priority minimum supply system, the branch pipe of the flow selection of the priority minimum supply system, the lower separation tray, the drip tray, the barrier of the priority minimum supply system, the pipe of the priority minimum supply system, shut-off valves (valves and valves), enclosing structures of a full-profile module of the "sarcophagus", transverse support beam for the gas separator, vertical struts integrated into the module frame. The system of priority minimum flow, consisting of a pipe flow selection branch pipe with a funnel located on top and a barrier, at any flow rates, ensures a guaranteed supply of a certain amount of well product to the bottom of the measuring tank in the zone where the well product flows into the level gauge reservoir. The elements of the priority minimum flow system have a calculated limited throughput and are organized so that the excess flow overflows through the barrier and funnel and moves according to the general separation scheme. At the same time, if the well productivity is close to the lower measurement limit of the device, then almost the entire flow passes through the system of the priority minimum supply, but when the well productivity is high, then, on the contrary, most of the flow moves according to the general separation scheme. A level gauge intended for analyzing the composition of a liquid contains a system for heating the contents of the level gauge tank, a dispenser for supplying chemicals to the level gauge tank, flanges of the level gauge, a differential pressure sensor in the level gauge tank, a temperature sensor, and a transmitter-receiver system of the level gauge.

There is a known method for determining the water cut of a liquid in the production of oil wells and a device that implements the method (source [10]: patent for invention RU 2396427). The device contains a gas separator (separation tank) for separating well production into gas and liquid, a measuring tank, a two-level level gauge for analyzing the composition of a liquid, gauge of differential pressure of measuring vessel, lower sensor (membrane) of gauge of differential pressure of measuring vessel, upper sensor (membrane) of gauge of differential pressure of measuring vessel, temperature gauge of measuring vessel, gauge pressure sensor, flow switch, flat bottom of measuring vessel, drain liquid line, valve return, inlet from the well to the gas separator, outlet to the reservoir, gas pipeline (gas line), lower separation tray, flow selection pipe of the priority minimum supply system, barrier of the priority minimum supply system, funnel of the priority minimum supply system, pipe of the priority minimum supply system. A two-level level gauge for analyzing the composition of a liquid, contains a level gauge reservoir (cylindrical vessel), a system for heating the contents of the level gauge tank, an electrically driven shut-off valve, a dispenser for supplying chemicals to a two-level level gauge tank, a gauge tank differential pressure gauge, and a level gauge tank temperature sensor. The principle of operation of the device is based on a hydrostatic method for measuring mass, based on the dependence of the hydrostatic pressure of a liquid column in height on the density of the liquid. The densities of water and oil in the composition of the liquid are determined when emptying the vessel, collecting a data array, plotting the dependence of the density of the discharged liquid on the height of the liquid column or the time of emptying, select within the upper and lower horizontal linear density sections of water and oil, respectively, and the mass water cut of the well production determined by the selected values of the density of water and oil.

The disadvantages of the devices [9; 10] are the multistage nature of the method implemented by the device and the need for controlled full-fledged separation of the well product into oil and water. The principle of operation of the device is based on a hydrostatic method for measuring mass, based on the dependence of the hydrostatic pressure of a liquid column in height on the density of the liquid. The accuracy of determining the water cut of well production is sensitive to the presence of free and dissolved gas. The accuracy of determining the amount of gas directly depends on the ratio of the gas flow rate and the liquid flow rate. With a high gas-oil ratio of the production produced in the well, an extremely fast emptying of the calibrated tank occurs in the installation and the inertia in the operation of the actuators leads to an increase in the error. In installations of this type, it is impossible to calculate the ratio of the amounts of free and dissolved gas, as well as the amount of dropping liquid in the gas flow. The device [9; 10] is not suitable for use as a standard of the 2nd category, since it does not provide the measurement accuracy required for verification of working instruments for measuring well production. A level gauge designed for analyzing the composition of a liquid, problematic applicability in mobile measuring installations for verifying working measuring instruments. Sensing elements of the level gauge and auxiliary structures are located outside its housing. There are stagnant "dead zones" that are not taken into account by the level gauge, which affects the course of measurements as a whole. Most of the fittings are connected by welding, which leads to the "guidance" of the body after welding, and increases the measurement error. The level gauge cannot be rotated for easy dismantling. The design of the level gauge that implements the method, which creates difficulties for use in mobile measuring installations. The reservoir is not collapsible, which makes it non-repairable. There are stagnant "dead zones" that are not taken into account by the level gauge, since it is located outside the tank, which affects the course of measurements as a whole. The design of the level gauge reduces the efficiency and accuracy of metering well production rates. The device has a high measurement error of well production as with low water cut. In the separation tank, the design of which, although it significantly increases the degree of separation of the oil-water-gas mixture into phases, at the same time does not exclude the ingress of residual gas into the measuring line of the liquid due to the design of the partition of the settling part of the separation tank in the form of a set of corners.

Currently, there are no mobile metrological devices that allow verifying (comparing) operating technical means, devices intended for measuring and accounting for well production, certifying technical means in accordance with the State System for Verifying Means of Hydrocarbon Raw Materials Means, without stopping production.

Known mobile measuring installations in their mass have an accuracy class similar to that of stationary installations and cannot serve for verification purposes, are not capable of acting as a verification tool for stationary measuring installations.

The error in measuring well production in known devices depends on the degree of water cut and reaches values that do not allow the use of known devices as a 2-grade standard.

The problem, when measuring the amount of gas, is the presence, in the gas flow, of a dropping liquid. It is not possible to completely catch the measuring dropping liquid with the separator of the installation due to the limited size of the separator, the wide range of well rates and the impossibility of lowering the pressure in the system. The presence of droplet liquid in the gas measurement line distorts and introduces an additional error in the result of measuring the amount of gas with a gas flow meter, as well as in the result of measuring the amount of liquid. When measuring with volumetric flow meters, the droplet liquid in the flow does not introduce large deviations in the measurement of the gas volume, but the volumetric flowmeter does not take into account the presence of droplet liquid in the flow, the mass fraction of which is significant, due to the high density of the liquid in comparison with the density of the gas. Thus, it is impossible to calculate or measure the mass fraction of the dropping liquid. When measuring with mass flow meters, the mass of the passing gas mass is measured together with the dropping liquid. But it is impossible to calculate the mass of the dropping liquid separately from the mass of the gas.

Purpose of development: creation of a means for periodic verification of working measuring instruments - a mobile standard of the 2nd category. The developed standard makes it possible to calibrate measuring installations without stopping the measurement process, without dismantling liquid and gas measuring instruments.

The main disadvantage of using separation plants with storage tanks during verification is their inertia, increased error due to entrainment of liquid by gas or entrapment of gas by liquid, influence on the operating conditions of measurement, and the presence of restrictions on the ranges of measured parameters [1,2].

The solution to this complex problem could be the use of multiphase flow meters of a non-separation type or the use of combined devices containing separators of one type or another.

The essence of the invention.

The technical result consists in providing the possibility of measuring the parameters of the multiphase flow of the well product (oil and gas-water mixture), and transferring the unit of the mass flow rate of the well product to the working means of measuring the mass flow rate and the amount of crude oil and gas in operation, for verification and determination of the flow rates of oil wells with increased accuracy for oil and gas, in order to ensure the uniformity of mass flow measurements.

The technical result is achieved by the fact that the mobile standard of the 2nd category for verifying the installations for measuring well production contains a supply line for an oil and gas-water mixture, a horizontally oriented separation-measuring tank, a vertically oriented oil analyzer, a liquid measurement line, a gas measurement line, an automated control system. Moreover, the separation-measuring tank consists of two communicating vessels, a lower tank for receiving liquid and an upper tank for receiving gas, equipped with a hydrocyclone with a gas swirler. The hydrocyclone is connected to the oil-gas-water mixture supply line and is partially submerged in the container for receiving the liquid. A defoamer, a drop catcher, a level meter, and a pressure transducer are installed in the separation-measuring tank. A liquid measurement line is connected to the container for receiving liquid, and a gas measurement line is connected to the container for receiving gas. The gas measurement line contains a system for measuring the content of dropping liquid in the associated petroleum gas flow. The liquid measurement line contains a moisture transducer installed at the liquid outlet from the separation and measurement tank, three parallel sections, into which liquid mass flow meters are connected, and a multiphase flow meter. A differential pressure transducer and an oil-gas-water mixture sampler connected to the oil-gas-water mixture supply line to the oil analyzer are connected to the oil-gas-water mixture supply line. The oil analyzer contains a rotary housing mounted on a support with the ability to fix the vertical position. The analyzer housing contains a level gauge with an interface level meter, pressure and temperature transducers and a hydrostatic pressure sensor, level gauge sensing elements and auxiliary structures are located inside the analyzer case. The automated control system, designed for collecting and processing information, as well as for archiving, indicating and transmitting information to the upper level, includes a control cabinet with a controller complete with a display. These structural elements are located in a block-container type box, located on the base, divided by a sealed explosion-proof partition into two rooms, a technological unit and a control unit.

Mobile standard of the 2nd category for verification of downhole production measurement installations (hereinafter referred to as the "standard") has a wide range of operating conditions. The accuracy of the standard is an order of magnitude higher than traditional metering installations, it makes it possible to certify the stock of metering devices in all oil companies of Russia. It is possible to calculate the ratio of the amounts of free and dissolved gas, as well as the amount of dropping liquid in the gas flow. EFFECT: reduction of measurement errors of production of wells with both high and low water cut, which provides a reduction in the cost of extracting hydrocarbon raw materials from the bowels.

The invention is illustrated by graphic materials:

Fig. 1 is a combined schematic diagram of the standard;

Fig. 2 is a general view of a mobile standard in a box (box walls are not shown);

Fig. 3 is a general view of a mobile standard on a platform of a high-traffic vehicle (without container walls);

Fig. 4 is a general view of a mobile standard on a platform of a high-traffic vehicle, combined diagram: front, top, side view;

Fig. 5 is a standard in a container (walls are not shown), combined scheme: front, top, side view;

Fig. 6 is a side view and sectional view of a separation-measuring tank (A-A), a combined diagram;

Fig. 7 is an oil analyzer, general view;

Fig. 8 - oil analyzer combined scheme: front view (G-G) in section, side (D-D) in section, isometric;

The following positions are indicated by numbers on the graphics:

1- oil-gas-water mixture supply line;

2- separation and measuring tank;

3- oil analyzer;

4- liquid measurement line;

5- inlet manifold;

6- coarse filter;

7- manual shut-off valves;

8- manometer;

9- gas measurement line;

10- container for receiving liquid;

11- capacity for receiving gas;

12- hydrocyclone;

13- gas swirler;

14- antifoam;

15-string drop catcher;

16- level meter;

17- pressure transducer;

18- system for measuring droplet liquid content;

19- gas volumetric flow meter, measurement systems;

20- gas mass flow meter, measurement systems;

21- pressure sensor, measurement systems;

22- temperature sensor, measurement systems;

23- flow regulator, measurement systems;

24 - ball valve, measurement systems;

25- moisture transducer for liquid measurement line;

26- liquid mass flow meters;

27 - multiphase flow meter;

28 - differential pressure transducer of the oil-gas-water mixture supply line;

29- oil-gas-water mixture sampler connected to the oil-gas-water mixture supply line to the oil analyzer,

30 - measuring the level of separation of the oil analyzer;

31- pressure transducer of the oil analyzer;

32- temperature converter of the oil analyzer;

33- hydrostatic pressure sensor of the oil analyzer;

34- automated control system;

35- electrical cabinet;

36 - power cabinet for controller power supply;

37- control cabinet with controller complete with display;

38 - box of block-container type;

39 - box base;

40- bypass line;

41- manual shut-off valves;

42 - scattering candle;

43 - gas discharge line to the candle from the separation tank and from the oil analyzer tank to the scattering candle 42 with a valve (normally closed);

44- gas sampler of the gas discharge line to the candle from the separation tank;

45 - shut-off valves with manual drive of the gas discharge line to the spark plug from the separation tank;

46 - line of gas discharge from the tank of the oil analyzer to the outlet of a special spring-loaded safety valve;

47- valve (normally closed) of the gas discharge line from the tank of the oil analyzer;

48 - shut-off valves with a manual drive of the gas discharge line from the tank of the oil analyzer;

49 - liquid outlet line with in-line volumetric multiphase moisture converter;

50 - gas measurement line with a droplet liquid content measurement system;

51- volumetric flow transducer of the droplet liquid content measuring system;

52 - mass flow transducer of the droplet liquid content measuring system;

53- manually operated shut-off valves, droplet liquid content measurement systems;

54 - shut-off and control valve of the droplet liquid content measurement system;

55 - liquid measurement line with a pipeline with a diameter of 25 mm;

56 - mass flow transducer, liquid measurement lines with a pipeline with a diameter of 25 mm;

57 - shut-off valves with a manual drive, liquid measurement lines with a pipeline with a diameter of 25 mm;

58- shut-off and control valve, liquid measurement lines with a pipeline with a diameter of 25 mm;

59 - liquid measurement line with a pipeline with a diameter of 80 mm;

60 - mass flow transducer, liquid measurement lines with a pipeline with a diameter of 80 mm;

61 - shut-off valves with a manual drive, liquid measurement lines with a pipeline with a diameter of 80 mm;

62 - shut-off and control valve for liquid measurement lines with a pipeline with a diameter of 80 mm;

63 - liquid measurement line with a multiphase flow meter;

64 - shut-off valves with a manual drive, liquid measurement lines with a multiphase flow meter;

65 - shut-off and control valve for liquid measurement lines with a multiphase flow meter;

66 - drainage system with flanged shut-off valves with manual drive;

67- drainage tank;

68 - outlet manifold with shut-off shut-off valves flanged with a manual drive, a check valve, a pressure converter and a manometer;

69- technological pipelines;

70 - shut-off valves for air discharge (at the upper points of the process piping);

71- oil analyzer case;

72- bottom of the oil analyzer;

73- oil analyzer flange;

74- oil analyzer support;

75- bearing units of the oil analyzer;

76 - oil analyzer position lock;

77 - level gauge clamp;

78- branch pipe of differential pressure of the oil analyzer;

79 - oil analyzer heating branch pipe;

80- oil analyzer level gauge;

81- thermal converter.

Implementation of the invention.

Mobile standard of the 2nd category for verifying working instruments for measuring well production (hereinafter referred to as the “standard”) without stopping production, designed to transfer the unit of mass flow rate of a gas-liquid mixture to working instruments for measuring mass flow and the amount of crude oil, gas in operation, for determinations with increased accuracy of oil wells flow rates for oil and gas.

The standard provides direct measurements of the average mass flow rate and mass of liquid and oil (liquid), direct measurements of the average volumetric flow rate and volume of free petroleum gas (hereinafter referred to as gas) reduced to standard conditions (hereinafter referred to as STU), direct measurements of the moisture content Wm (mass) or Wo (volumetric) liquid.

The standard provides operational accounting of production rates of oil and gas condensate wells in pressurized gathering systems, carried out in the following ways:

−measurements of mass / volume moisture content of the liquid phase;

- measurement of the content of the residual dissolved gas using the method of changing the density;

- measuring the content of residual dissolved gas using the method of changing the level of the oil-gas-water mixture in the oil analyzer.

The standard contains, a supply line for an oil and gas-water mixture 1, a horizontally oriented separation and measurement tank 2, a vertically oriented oil analyzer 3, a liquid measurement line 4, a gas measurement line 9, an automated control system 34. Moreover, the separation and measurement tank 2 consists of two communicating vessels, the lower tank for receiving liquid 10 and the upper tank for receiving gas 11, equipped with a hydrocyclone 12 with a gas swirler 13. The hydrocyclone 12 is connected to the oil-gas-water mixture supply line 1 and is partially immersed in a tank for receiving liquid 10. An antifoam agent 14 is installed in the separation-measuring tank 2 , a droplet catcher 15, a level meter 16, a pressure transducer 17. A liquid measurement line 4 is connected to the container for receiving liquid 10, a gas measuring line is connected to the container for receiving gas. 9. The gas measuring line 9 contains a system 18 for measuring the content of droplet liquid in the associated flow. petroleum gas. The liquid measurement line 4 contains a moisture transducer 25 installed at the liquid outlet from the separation-measuring tank 2, three parallel sections (55.59.63) into which are connected liquid mass flow meters 26, a multiphase flow meter 27. The oil-gas-water mixture supply line 1 is connected differential pressure transducer 28 and sampler 29 of the oil-gas-water mixture connected to the line for supplying the oil-gas-water mixture to the oil analyzer 3. The oil analyzer 3 contains a rotary housing 71 mounted on a support 74 with the possibility of fixing the vertical position. In the housing 71 of the oil analyzer 3 there is a level gauge 80 with an interface level meter 30, with pressure transducers 31 and temperature 32 and a hydrostatic pressure sensor 33, the sensing elements (30,31,32,33) of the level gauge and auxiliary structures are located inside the body 71 of the oil analyzer 3. Automated control system 34, includes a control cabinet 37 with a controller complete with a display. These structural elements are located in a box 38 of a block-container type, located on the base 39, divided by a sealed explosion-proof partition into two rooms, a technological unit (BT) and a control unit (BC).

The structural elements of the standard listed above are located in a box 38 of a block-type located on the base 39, divided by a sealed explosion-proof partition into two rooms, a technological unit and a control unit.

The technological block is designed to accommodate, shelter and ensure normal operating conditions for technological equipment and standard measuring instruments.

The technological block (BT) contains: a liquid measurement line 4, a gas measurement line 9 with a system 18 for measuring the content of dropping liquid; oil and gas-water mixture supply line 1, separation and measuring tank 2, oil analyzer 3, measuring instruments, instrumentation and automation, pipeline fittings, shut-off and control valves, heating, ventilation, lighting, fire alarm systems.

Description of BT elements.

Oil-gas-water mixture supply line 1 with an inlet manifold 5, with a coarse filter 6, with a sampler 29, with a stirrer made in accordance with GOST 2517-2012 with a flanged shut-off valve with a manual drive and a pressure gauge. A differential pressure transducer 28 and a sampler 29 of an oil and gas-water mixture connected to the supply line of an oil and gas-water mixture to an oil analyzer 3 are connected to the supply line of the oil-gas-water mixture 1;

Bypass line 40 with shut-off shut-off valves 41 flanged with a manual drive;

Gas discharge line to the plug 43 from the separation-measuring tank 2 and from the oil analyzer tank 3 to the scattering plug 42 42 with a valve (normally closed), with a gas sampler 44 and flanged shut-off valves with a manual drive;

Gas discharge line 46 from the tank of the oil analyzer to the outlet of a special spring-loaded safety valve (SPPK), with a valve (normally closed) and flanged shut-off valves with a manual drive;

The gas measurement line 9 contains a system 18 for measuring the content of droplet liquid in the flow of associated petroleum gas, a gas volumetric flow meter 19, a gas mass flow meter 20, made in the form of an ultrasonic gas volumetric flow meter and a Coriolis gas mass flow meter are connected to the gas outlet from the gas receiving tank 11 , pressure sensor 21, temperature sensor 22, flow regulator 23, ball valve 24.

In the gas measurement line 9, an ultrasonic flow meter with an error of 0.5% and a Coriolis mass flow meter 20 with an error of 0.1% are installed in series. The availability of volumetric and mass flow data based on the known gas density makes it possible to account for the amount of dropping liquid in the flow. To calculate the gas density, you will need to take into account the component composition of the gas.

The principle of the system 18 for measuring the content of dropping liquid consists in the sequential installation of volumetric flow meters 19.51 and mass type 20.52. The calculation of the mass of dropping liquid is carried out according to a given algorithm (formulas) according to the result of measuring the volume of gas by a volumetric flowmeter, a mass flowmeter of the mass of gas and the density of a mixture of gas and droplet liquid and the laboratory value of the density of the associated gas. After the calculation, the volume of the droplet liquid is subtracted from the volume of the gas and the mass of the droplet liquid is added to the mass of the measured liquid. Measurements of the droplet liquid content in the associated petroleum gas flow are carried out using the results of measurements of the mass and volume of the separated associated gas.

The liquid measurement line 4 contains a humidity transducer 25 installed at the liquid outlet from the separation tank 10, three parallel sections (55,59,63), which are connected to liquid mass flow meters 26, a multiphase flow meter 27. The liquid measurement line is made with a flow volumetric multiphase transducer humidity 25.

The line for measuring the liquid 4 contains meters 26 of the mass flow rate of the liquid. For measuring the amount of liquid, the measuring line consists of two parallel sections of different cross-sections (pipelines 25 mm and 80 mm), designed for different flow rates. In each of the two parallel sections of the liquid measurement line, a Coriolis mass flow meter 26 is installed with an error of 0.1%. To increase the measurement accuracy, an additional flow meter is installed in the liquid measuring line. The maximum permissible gas content in the flow should not exceed 5%.

Liquid measurement line 4 contains a pipeline 55 with a diameter of 25 mm with a mass flow transducer, flanged shut-off valves with a manual drive, a shut-off and control valve;

Liquid measurement line 4 contains a pipeline 59 with a diameter of 80 mm with a mass flow transducer, flanged shut-off valves with a manual drive, a shut-off and control valve;

The liquid measurement line 4 contains a pipeline 63 with a 27 multiphase flow meter, with flanged shut-off valves with a manual drive, a shut-off and control valve.

Also, the BT contains technological pipelines 69, shut-off valves 70 for air discharge (at the upper points of the process piping), safety valve 47, scattering plug 42. Drainage system 66 with manually operated flanged shut-off valves includes a drain tank 67. Outlet manifold 68 is made with shut-off shut-off valves flanged with a manual drive, a check valve, a pressure converter and a manometer.

Separation-measuring tank 2 serves to separate associated gas from liquid, two-stage combined separation of crude oil into oil and gas fractions and can be used in various installations for operational metering of production rates of oil wells, including for the production of oil wells with increased gas content and allows to increase the intensity of gas release from the oil-gas-water mixture.

The separation-measuring tank 2 consists of two communicating vessels, the lower tank 10 for receiving liquid (the second stage of separation), and the upper tank 11 for receiving gas, contains a hydrocyclone 12 with a gas swirler 13, designed to separate gas from liquid (first separation stage) , the hydrocyclone 12 is connected to the oil-gas-water mixture supply line 1 and is partially submerged in the container 10 for receiving the liquid. Defoamers 14 are installed in the containers, made in the form of a package of mass transfer nozzles. The container 11 for receiving the gas contains a string droplet catcher 15. The container 10 for receiving the liquid is equipped with a level meter 16 and a pressure transducer 17. The liquid measuring line 4 is connected to the container 10 for receiving the liquid, and the gas measuring line 9 is connected to the container 11 for receiving gas.

The gas receiving capacity 11 contains two blocks of drop catchers made in the form of Pall rings and string grids with a developed contact surface.

The liquid receiving container 10 contains a gas separation unit in the form of Pall rings.

Separation measuring tank 2 includes an inlet pipeline, a body of a separation tank with an inlet made in the form of a hydrocyclone 12, a drop catcher 15 and defoamers 14 made in the form of a package of mass transfer nozzles, Pall rings located in the direction of movement of the mixture to be separated. Defoamers 14 are installed in the body of the separation tank by means of a vertical partition located in the body. The antifoam mass transfer nozzles are made in the form of Pall rings. The droplet catcher 15 is made with a string.

The hydrocyclone 12 is partially submerged in the lower liquid receiving container 10. This makes it possible to reduce the size of the tank and the entire plant, improving transport conditions and increasing mobility.

During the separation process, the multiphase flow initially enters the cylindrical-type hydrocyclone 12, in which the main separation of gas and liquid occurs under operating conditions, this is the first separation stage.

Since in the hydrocyclone secondary entrapment of gas by liquid can be observed, as well as the reverse process of secondary entrainment of droplet moisture by the gas flow. To improve the quality of separation, the second stage is used, made in the form of interconnected separation tanks: the upper 11 gas tank and the lower 10 liquid tank. The gas outlet from the hydrocyclone 12 is made in the form of a gas swirler 13.

Separation measuring tank 2 is horizontally oriented.

The implementation of the defoamer 14 in the form of a package of mass transfer nozzles, located in the direction of movement of the liquid in the separation tank, can significantly increase the surface area of the mass transfer, which helps to improve the release of gas from the liquid. The presence of a vertical baffle allows, firstly, to fix the package of mass transfer nozzles in the separator body and orient them along the flow of the oil-water-gas mixture, and, secondly, it ensures the passage of the entire separated mixture through the mass transfer nozzles, which also contributes to an increase in the degree of separation of the mixture into gas and liquid components.

The implementation of the mass-transfer nozzles of the antifoam separator in the separation vessel in the form of Pall rings makes it possible to improve the separation of gas from the liquid and the separation of the dropping liquid from the gas.

The use of a gas swirler 13, as well as the implementation of a droplet catcher 15 with a string make it possible to maximally clean the gas flow from residual liquid droplets.

Oil analyzer 3 (device for analyzing the composition of the borehole fluid) is designed to determine the proportion of water in the flow of the borehole fluid (oil and gas-water mixture), as well as to determine the density of water and oil. Oil Analyzer 3 operates on a hydrostatic principle. Oil analyzer 3 is made with an interface level meter 30, with pressure transducers 31 and temperature 32 and a hydrostatic pressure sensor 33. Oil analyzer 3 is a vertical vessel into which a fluid sample is taken from a well. Oil analyzer 3, consists of housing 71, bottom 72, flange 73, support 74, bearing assemblies 75, position retainer 76, level gauge retainer 77, differential pressure pipe 78, heating pipe 79, level meter 80, thermal converter 81. Oil analyzer 3 is equipped with sensitive elements: pressure sensors 31, temperature 32, and level meters 30. The measurement process in the analyzer occurs after the sample is separated into separate phases: gas, oil and water. To accelerate the phase separation process analyzer equipped with a heater (heating temperature to 35 ° ^C) and a dosing pump for the administration of demulsifier. For the oil analyzer, a method is used that allows to determine the content of dissolved gas in oil. The method is based on the sequential reduction of the sample in the analyzer to normal conditions.

The use of an oil analyzer 3 as part of a mobile standard of the 2nd category increases the efficiency and accuracy of metering the production rates of oil and gas condensate wells in pressurized gathering systems.

Oil analyzer 3 makes it possible to reduce the dimensions of the standard, since the sensitive elements of the level gauge and auxiliary structures are located inside the analyzer tank. The analyzer is compact and can be housed in the device in blocks with limited dimensions, providing a reduction in overall dimensions and increased mobility of the device.

The design features of the oil analyzer are as follows: the sensing elements of the 80 level gauge and auxiliary structures (the level gauge clamp, the differential pressure nozzle, the heating nozzle, the thermowell and the sensitive element of the thermal converter) are located inside the rotary housing 71. The sensing elements of the 80 level gauge are located inside the housing 71, and the probe tip elements of the level gauge are immersed in the clamp of the level gauge, thereby ensuring the absence of "dead" zones.

The operation of the differential pressure sensor is provided due to the presence of two threaded nipples located on the end surface of the flange 73. The first nipple measures the pressure at the upper point, and the second nipple - at the bottom, and is a structure of the differential pressure pipe 78, one end welded to the flange 73, with a specially provided hole, and the second end is located in the lower part of the housing 71, namely, slightly not reaching the latch 77 of the level gauge. In addition to the two threaded connections for the differential pressure sensor, flange 73 has three more threaded connections: two for gas inlet / outlet, and the third for purging.

The body 71 of the oil analyzer 3 is made of a thick-walled pipe of increased accuracy made of stainless steel with three welded nipples, two of which are located in the lower and upper parts of the body, intended for the inlet of the measured gas-liquid medium (in operation, only one inlet nipple is used, and the second is muffled ). The third fitting is the thermostat fitting. However, most of the fittings are mounted with a sleeve connection, which excludes the "guidance" of the body after welding, which contributes to the correct measurement result.

To heat the liquid, a heating pipe 79 is provided, which goes around the entire height of the housing 71. Both ends of the pipe 79 are welded to the bottom 72, in which openings are provided for the inlet / outlet of the coolant.

To ensure the convenience of disassembling the level gauge 80, the analyzer design provides for the possibility of rotation of the housing 71, which is provided by the bearing assemblies 75 bolted to the support 74. The analyzer housing 71 can be rotated by 160 ° with the following fixed to each other: the bottom 72, the flange 73, the retainer 77 level gauge, differential pressure branch pipe 78, heating branch pipe 79, level gauge 80, thermal converter 81. For fixing / unlocking the housing 71 in the vertical position, a position lock 76 is used. For this, a rod is located on the bottom 72, which fits into the position lock 76, then by moving the handle of the movable part of the position lock, the rod is limited in movement, as a result of which the housing 71 is fixed in a vertical position.

The control unit (BC) is designed to shelter and place an automated control system for controlling the operation of standard devices, an automated workstation for an operator (AWP) and a power supply system.

The control unit (BC) contains: an automated control system 34, a control cabinet 37 with a controller complete with a display, an electrical cabinet 35, a power cabinet 36 for powering the controller, a heating, lighting, ventilation, fire alarm system, an operator's automated workstation.

The automated control system 34 consists of an electrical cabinet 35 and a control cabinet 37 with a controller complete with an LCD display, is intended for collecting and processing information, as well as for archiving, indicating and transmitting information to the upper level, the automated control system 34 allows you to combine data from various measurements obtained from the measuring devices of the standard described above, and systematize the results, analyze and make calculations according to the laid down algorithms and formulas, to ensure maximum accuracy and reduce measurement errors.

The BC contains a power cabinet for powering the controller, lighting system, ventilation, heating with thermal control, fire alarm, a locksmith's workbench, a sleeping place, measuring instruments for controlling the operating level control system in the ESI, an operator's workstation, terminal blocks.

Work description.

The field of application of the standard is oil and gas industry enterprises in terms of testing, calibration and verification of the measuring installation, as well as in terms of accounting, in the process of oil production, mass and mass flow rate of the liquid phase of the oil and gas-water mixture, mass and mass flow rate of the liquid phase of the oil and gas-water mixture without metering of water, as well as the volume and volumetric flow rate of free petroleum gas in the composition of the oil and gas-water mixture reduced to standard conditions.

The standard is intended for transferring the unit of mass flow rate of the oil and gas-water mixture to the working means of measuring the mass flow rate and the amount of crude oil and gas under operating conditions, for determining with increased accuracy the flow rates of oil wells for oil and gas during experimental studies, as well as for certifying measurement techniques.

The standard provides measurements of mass and mass flow rate of the liquid phase of the oil-gas-water mixture.

Hydrostatic measurement method (reference mode).

In the initial state, the oil-gas-water mixture enters the Etalon, passing the liquid filter 6 (Fs), enters the separation-measuring tank 2 2 (EC). The gas-oil-gas mixture passes through the defoamer 14 and leaves the separation tank into the liquid measurement line 4.

At the beginning of the measurement, the control valve 62 (ЗРК1) or 58 (ЗРК3) is closed, the control valve 54 (ЗРК2) is opened, the readings of the differential pressure sensor 28 with a remote membrane 28 (PDIT1) are recorded, and the start time of the measurement is recorded. The oil-gas-water mixture entering the separation-measuring tank 2, passing through the hydrocyclone 12, is divided into its constituent phases - liquid and gaseous. The separated associated petroleum gas, passing through the droplet separator 15, leaves the separation-measuring tank 2 into the gas measurement line 9. The liquid phase of the oil-gas-water mixture enters and accumulates in the lower tank 10. The liquid level is controlled by the level meter 16 (LIT2). When the liquid reaches a predetermined level, the readings of the differential pressure transducer 28 with a remote diaphragm 28 (PDIT1), as well as the time of the end of the measurement, are recorded. Next, the control valve 62 (ЗРК1) or 58 (ЗРК3) is opened and the control valve 54 (ЗРК2) is closed, as a result of which the liquid is displaced from the liquid container 10 by the gas phase. After a specified time (time of hydrodynamic stabilization of the flow), the measurement cycle is repeated.

Measurements with Mass Flow Meters (Reference Mode).

Before bump measurement, select the applied mass flow meter 27 (FQT2) or 56 (FQT5) (depending on the flow rate of the liquid phase of the oil-gas-water mixture).

In the initial state, the control valves 62 (ЗРК1) or 58 (ЗРК3) and 54 (ЗРК2) are partially open. The oil-gas-water mixture enters the mobile standard, passing the filter 6 of the FS liquid, enters the separation-measuring tank 2 EC. The oil-gas-water mixture entering the separation-measuring tank 2, passing through the hydrocyclone 12 apparatus, is divided into its constituent phases - liquid and gaseous. The separated associated petroleum gas, passing through the droplet catcher 15, leaves the separation tank 2 into the gas measurement line 9. The liquid phase of the oil and gas-water mixture leaves the separation measurement tank 2 into the liquid measurement line 4 4. In the separation and measurement tank 2, a given level of the oil and gas-water liquid phase is always maintained mixture, which is controlled by the level gauge 16 (LIT2). When the liquid level drops below the set value, the control valve 62 (ЗРК1) or 58 (ЗРК3) (depending on the selected mass flow meter 60 (FQT2) or 59 (FQT5) partially opens, and the control valve 54 (ЗРК2) partially closes until the level stabilizes liquid in tank 10 in the specified range.When the liquid level rises above the specified value, the control valve 62 (ЗРК1) or 58 (ЗРК3) (depending on the selected mass flow meter 60 (FQT2) or 59 (FQT5)) partially closes, and the control valve ЗРК2 partially opens until the liquid level in the separation tank stabilizes within the specified range. When the liquid level in the tank 10 is stabilized, measurements are started. The mass flow rate of the liquid phase of the oil-gas-water mixture, the accumulated mass (mass flow meter 60 (FQT2) or 59 (FQT5)) , measurement time.

Measurements using a multiphase flow meter (DUT mode).

The oil-gas-water mixture, passing through the filter 6 of the FS liquid, enters the multiphase flow meter 27 (FQT1). Using the multiphase flowmeter 27 (FQT1), measurements of the mass and mass flow rate of the liquid phase of the oil-gas-water mixture, the volume and volumetric flow rate of the liquid phase of the oil-gas-water mixture, and the measurement time are performed.

Methods for measuring mass and mass flow rate of the liquid phase of an oil and gas-water mixture without taking into account water, used in the Standard.

Measurements using a humidity transducer (reference mode).

The oil-gas-water mixture enters the Etalon, passing the filter 6 of the FS liquid, enters the separation-measuring tank 2 EC. The oil-gas-water mixture entering the separation-measuring tank 2, passing through the hydrocyclone 12, is divided into its constituent phases - liquid and gaseous. The separated associated petroleum gas, passing through the droplet catcher 15, leaves the separation tank 2 into the gas measurement line 9. The liquid phase of the oil-gas-water mixture leaves the separation tank 2 into the liquid measurement line 4. In the liquid measurement line, measurements of the volumetric moisture content of the liquid phase of the oil-gas-water mixture are carried out using a converter humidity 25 (AT1). These measured values are used to calculate the mass and mass flow rate of the liquid phase of the oil-gas-water mixture excluding water in the automated control system 34 ACS.

Measurements using an oil analyzer (reference mode).

The oil-gas-water mixture enters the Etalon passing through the sampler 25 (P), in which samples of the oil-gas-water mixture are taken, which are subsequently fed into the tank of the oil analyzer 3 (EA). Sampling of the oil-gas-water mixture is carried out until the tank of the oil analyzer 3 (EA) is filled. The liquid level in the tank of the oil analyzer 3 (EA) is monitored by the 30 level gauge (LIT1). Further, by opening the valve (H32) of the gas discharge line 46, the associated petroleum gas contained in the oil and gas-water mixture is discharged onto the scattering plug 42. After the discharge of the associated petroleum gas, the electric heating system of the oil analyzer tank 3 is activated, and the thermal process of separating the oil-water emulsion into components components - formation water and oil. This process is controlled by an interface level meter 30 (LIT1). Upon reaching a stable phase boundary, by opening the NZ3 valve, the separated associated petroleum gas begins to flow into the oil analyzer tank from the separation tank. Next, the NZ4 valve is opened, and the associated petroleum gas entering the tank of the oil analyzer 3 displaces the liquid in it into the outlet manifold 68. In the process of emptying the tank of the oil analyzer 3, the liquid level is monitored by a level gauge 80, the interface level is controlled by an interface level meter 30 (LIT1) , the differential pressure in each unit of time by the differential pressure transducer 28 (PDIT1), the liquid temperature by the temperature measuring transducer 32 (TIT1). Based on the results of these measurements, the mass moisture content of the liquid phase of the oil-gas-water mixture is calculated. This value is used to calculate in the automated control system 34 the mass and mass flow rate of the liquid phase of the oil-gas-water mixture excluding water.

Measurements using a multiphase flow meter (DUT mode).

The oil-gas-water mixture, passing through the filter 6 of the FS liquid, enters the multiphase flow meter 27 (FQT1). Using the multiphase flowmeter 27 (FQT1), measurements of the mass and mass flow rate of the liquid phase of the oil and gas-water mixture without taking into account water, volume, and volumetric flow of the liquid phase of the oil and gas-water mixture without taking into account water, measurement time are performed.

Measurement of the volume and volumetric flow rate of petroleum gas in the composition of the oil-gas-water mixture.

Measurements using a mass flow meter (reference mode).

The oil-gas-water mixture enters the Etalon, passing the filter 6 of the FS liquid, enters the separation-measuring tank 2 EC. The oil-gas-water mixture entering the separation-measuring tank, passing through the hydrocyclone 12, is divided into its constituent phases - liquid and gaseous. The liquid phase of the oil-gas-water mixture leaves the separation tank into the liquid measurement line 4. The separated associated petroleum gas, passing through the droplet separator, leaves the separation tank into the gas measurement line 9, where the mass and mass flow rate of the associated gas are measured using a mass flow meter 20 (FQT3) ... These measurement results are the initial for the calculation in the automated control system 34 of the volume and volumetric flow rate of associated petroleum gas reduced to standard conditions.

Measurements using a volumetric flow meter (reference mode).

The oil-gas-water mixture enters the Etalon, passing the filter 6 of the FS liquid, enters the separation-measuring tank 2 EC. The oil-gas-water mixture entering the separation-measuring tank, passing through the hydrocyclone 12, is divided into its constituent phases - liquid and gaseous. The liquid phase of the oil-gas-water mixture leaves the separation tank into the liquid measurement line 4. The separated associated petroleum gas, passing through the droplet separator, leaves the separation tank into the gas measurement line 9, where the volume and volumetric flow rate of the associated gas are measured under operating conditions using a volumetric flow meter 19 (FQT4), temperatures using a TIT2 temperature transmitter, and pressure using a PIT4 gauge pressure transmitter. These measurement results are the initial for the calculation in the automated control system 34 of the volume and volumetric flow rate of associated petroleum gas reduced to standard conditions.

Measurements using a multiphase flow meter (DUT mode).

The oil-gas-water mixture, passing through the filter 6 of the FS liquid, enters the multiphase flow meter 27 (FQT1). With the use of a multiphase flowmeter 27 (FQT1), measurements of the volume and volumetric flow rate of associated petroleum gas reduced to standard conditions, and the measurement time are performed.

Measurements using an oil analyzer using the method of changing the density of an oil and gas-water mixture (reference mode).

The oil-gas-water mixture enters the Etalon passing through the sampler 25 (P), in which samples of the oil-gas-water mixture are taken, which are then fed into the tank of the oil analyzer 3 (EA). Sampling of the oil-gas-water mixture is carried out until the tank of the oil analyzer 3 (EA) is filled. The liquid level in the tank of the oil analyzer 3 (EA) is monitored by the 30 level gauge (LIT1). Further, by opening the valve H32, the associated petroleum gas contained in the oil and gas-water mixture is discharged to the scattering plug 42. In the process of discharging the gas, the results of measurements of the differential pressure transducer 28 (PDIT1), the LIT1 level gauge, and the temperature transducer 32 (TIT1) are recorded at each time unit. At the point in time when the reading of the differential pressure transducer 28 (PDIT1) stops changing, the measurement is finished. These measurement results are the initial ones for calculating in the automated control system 34 the content of dissolved gas in the oil-gas-water mixture, on the basis of which, in turn, the volume and volumetric flow rate of associated petroleum gas are calculated.

Measurements with an oil analyzer using the method of changing the level of an oil / gas / water mixture in an oil analyzer (reference mode).

The oil-gas-water mixture enters the Etalon passing through the sampler 25 (P), in which samples of the oil-gas-water mixture are taken, which are subsequently fed into the tank of the oil analyzer 3 (EA). Sampling of the oil-gas-water mixture is carried out until the equilibration of the excess pressure in the EA oil analyzer and in the separation tank. The liquid level in the tank of the oil analyzer 3 (EA) is monitored by the 30 level gauge (LIT1). Further, by opening the valve H32, the associated petroleum gas contained in the oil and gas-water mixture is discharged to the scattering plug 42. In the process of discharging the gas, the measurement results of the LIT1 level gauge, the temperature transducer 32 (TIT1) are recorded at each time unit. At the moment when the readings of the LIT1 level transmitter stop changing, the measurements are finished. These measurement results are the initial ones for calculating in the automated control system 34 the content of dissolved gas in the oil-gas-water mixture, on the basis of which, in turn, the volume and volumetric flow rate of associated petroleum gas are calculated.

Measurement of the mass content of dropping liquid in the associated petroleum gas flow.

The oil-gas-water mixture enters the Etalon, passing the filter 6 of the FS liquid, enters the separation-measuring tank 2 EC. The oil-gas-water mixture entering the separation-measuring tank, passing through the hydrocyclone 12, is divided into its constituent phases - liquid and gaseous. The liquid phase of the oil-gas-water mixture leaves the separation tank into the liquid measurement line 4. The separated associated petroleum gas, passing through the droplet separator, leaves the separation tank into the gas measurement line 9, where measurements of the volume, volumetric flow rate, mass and mass flow rate of the associated petroleum gas are carried out under operating conditions using a mass flow meter 20 (FQT3) and a volumetric flow meter 19 (FQT4), temperature using a TIT2 temperature transmitter, and pressure using a PIT4 gauge pressure transmitter. These measurement results are the initial ones for calculating in the automated control system 34 the mass content of the droplet liquid in the associated petroleum gas flow.

Thus, the standard provides:

- direct measurements of the average mass flow rate and mass of liquid and oil (hereinafter referred to as liquid);

- direct measurements of the average volumetric flow rate and the volume of free petroleum gas (hereinafter referred to as gas), reduced to standard conditions);

- direct measurements of moisture content, mass or volume, of a liquid.

The standard provides the following functions:

- work in automatic mode;

- measurement (calculation) of the mass flow rate of the liquid mixture;

- measurement (calculation) of the mass and mass flow rate of oil excluding water in the composition of the gas-liquid mixture;

- measurement (calculation) of the volumetric content of gas in the gas-liquid mixture;

- measurements with the required accuracy of gas temperature and pressure at the point of measurement of its volumetric flow;

- measuring the volume and volumetric flow rate of gas;

The use of a well production composition analyzer in the Device provides:

1) measuring the volume and volumetric flow rate of the dissolved gas;

2) calculating the volume and volumetric flow rate of gas;

3) calculation of the gas density in r.u. by gas composition (indirect method);

4) measuring (calculating) the volume and mass fraction of water in the liquid mixture;

5) the temperature of heating the liquid mixture in the analyzer tank;

- maintaining the working level of the liquid mixture in the separation tank;

- regulation of the heating temperature of the liquid mixture in the analyzer tank;

- manual and remote control of lighting, heaters, valve electric drives;

- transfer of measured and calculated parameters to an automated control system (hereinafter - ACS);

- input of primary data (constants) for calculations and measurements (standard parameters, oil well production parameters);

- measurement of the duration of time intervals during which measurements were performed;

- signaling about the end of the verification period for measuring instruments (hereinafter - MI) included in the standard;

- calculation, display on the display of the ACS, storing and archiving in the non-volatile memory (EMP) of the ACS for a period of at least 3 months, issuing to a portable personal computer, to top-level information systems or transmission in "online" mode via the Internet, upon request operator, the following measurement information (hereinafter referred to as AI) for each measurement:

1) time and date of each of the measurements, indicating the selected measurement method in accordance with TU 28.99.39-092-00137182-2019;

2) the values of the masses and mass flow rates of crude oil, oil, volumes and average volume flow rates of gas reduced to Art. at .;

3) initial primary data (constants) for calculations and measurements;

4) alarms:

- pressure out of limit values;

- limiting gas content in BT;

- refusal to execute commands for switching shut-off and control valves with an electric drive;

- failure of any of the sensors with current output signals;

- the temperature of the working medium is outside the specified measurement range;

- temperature rise in BT and BC rooms outside the specified range;

- error messages;

- failure in the power supply of the standard.

- automated control:

1) heating system BT and BK;

2) turning on the fan when the volumetric concentration reaches 10% of the lower flammable limit (hereinafter referred to as NKPV);

3) by turning off all current collectors in the BT and turning on the local light sound alarm when reaching 50% - NKPV;

4) disconnection of all current collectors BT, BK in the event of a fire.

- signaling of the position of shut-off and control valves with an electric drive;

- printing of reporting documents, event logs;

- privileged access by means of passwords according to the levels of control and work with the program;

- change of access level;

- displaying several graphs of measured values (trends) on the operator's workstation at the same time;

- supply of control signals to the control elements of the working measuring instruments.

During the separation process, the multiphase flow initially enters a cylindrical-type hydrocyclone where the main separation of gas and liquid occurs under operating conditions.

Description of the principle of measurement in the gas line 9: The oil-gas-water mixture enters the standard, passing the filter 6 of the FS liquid, enters the separation-measuring tank 2 EC. The oil-gas-water mixture entering the separation-measuring tank, passing through the hydrocyclone 12, is divided into its constituent phases - liquid and gaseous. The liquid phase of the oil-gas-water mixture leaves the separation tank 2 into the liquid measurement line 4. The separated associated petroleum gas, passing through the droplet catcher 15, leaves the separation measuring tank 2 into the gas measurement line 9, where the volume, volumetric flow rate, mass and mass flow rate of the associated oil gas are measured. gas under operating conditions using a mass flow meter 20 (FQT3) and a volumetric flow meter 19 (FQT4), temperatures using a TIT2 temperature transmitter, and pressure using a PIT4 gauge pressure transmitter. These measurement results are the initial ones for calculating in the automated control system 34 the mass content of the droplet liquid in the associated petroleum gas flow.

The mass content of the dropping liquid in the associated petroleum gas flow is calculated by the formula.

The gas phase after the hydrocyclone 12 enters the upper separation-measuring tank 2, where two blocks of droplet catchers 15 in the form of Pall rings and string nets pass successively. Both droplet catcher blocks have a developed contact surface, on which droplets are deposited. The separated moisture flows into the lower separation-measuring tank of the liquid, and the dried gas enters the measuring line. The water-oil mixture separated in the hydrocyclone enters the lower separation-measuring tank, in which the process of freeing the liquid from the residual free gas continues. To improve the speed and quality of separation, a gas separation unit in the form of Pall rings is installed in the lower tank. An additional factor contributing to the separation of free gas is the drop in the flow rate of the liquid in the container. As a result, the time of its residence in the container is increased, which makes it possible for the gas to come to the surface and leave the liquid before it leaves the container. The released gas is discharged into the upper separation-measuring tank.

After the separation unit, gas and liquid enter the measuring lines equipped with a system of measuring devices. An ultrasonic flow meter with an error of 0.5% and a Coriolis mass flow meter with an error of 0.1% are installed in series in the line for measuring the amount of gas. The availability of volumetric and mass flow data based on the known gas density makes it possible to account for the amount of dropping liquid in the flow. To calculate the gas density, you will need to take into account the component composition of the gas.

Liquid measuring line 9 consists of two parallel sections of different cross-sections, designed for different flow rates. Each line is equipped with a Coriolis mass flow meter with an accuracy of 0.1%. To increase the measurement accuracy, an additional flow meter is provided. The maximum permissible gas content in the flow should not exceed 5%.

Determination of the proportion of water in the fluid flow, as well as the density of water and oil, is carried out by the oil analyzer 3 (hereinafter referred to as the analyzer), operating on the hydrostatic principle.

The essence of measurement using a well fluid composition analyzer is as follows - discrete indirect measurements are performed in a dynamic mode, by taking representative samples from the flow of the oil and gas-water mixture with a sampler into the tank of the oil analyzer, further thermal separation of the oil-water mixture into its constituent components (water and oil), emptying ( or discharge of associated petroleum gas to the spark plug, depending on the method used) the capacity of the oil analyzer and measurements using a differential pressure transducer, a level gauge and a temperature measuring transducer.

Measurement by the method of mass / volumetric moisture content of the liquid phase is carried out as follows: the oil-gas-water mixture enters through the sampler 25 (P), in which samples of the oil-gas-water mixture are taken, which then enter the tank of the oil analyzer 3 (EA). Sampling of the oil-gas-water mixture is carried out until the tank of the oil analyzer 3 (EA) is filled. The liquid level in the tank of the oil analyzer 3 (EA) is controlled by the LIT level gauge. Further, by opening the H31 valve, the associated petroleum gas contained in the oil and gas-water mixture is discharged to the scattering plug 42. After the associated petroleum gas is discharged, the electric heating system of the oil analyzer tank is activated, and the thermal process of separating the oil-water emulsion into its constituent components - formation water and oil ... This process is controlled by an interface level meter 30 (LIT). Upon reaching a stable phase boundary, by opening the НЗ2 valve, the separated associated petroleum gas begins to flow into the tank of the oil analyzer from the separation tank EC. Next, the NZ3 valve is opened, and the associated petroleum gas entering the tank of the oil analyzer displaces the liquid in it into the outlet manifold 68. In the process of emptying the tank of the oil analyzer, the liquid level is monitored by a level gauge 71, the interface level is controlled by an interface level meter 30 (LIT) , differential pressure in each unit of time by the PDIT differential pressure transducer, liquid temperature by the TIT temperature measuring transducer. Based on the results of these measurements, the mass moisture content of the liquid phase of the oil-gas-water mixture is calculated. This value is used to calculate in the automated control system 34 the mass and mass flow rate of the liquid phase of the oil-gas-water mixture excluding water.

The measurement of the content of the residual dissolved gas using the density variation method is carried out as follows: the oil-gas-water mixture enters through the sampler 25 (P), in which samples of the oil-gas-water mixture are taken, which then enter the tank of the oil analyzer 3 (EA). Sampling of the oil-gas-water mixture is carried out until the tank of the oil analyzer 3 (EA) is filled. The liquid level in the tank of the oil analyzer 3 (EA) is controlled by the LIT level gauge. Further, by opening the valve H31, the associated petroleum gas contained in the oil-gas-water mixture is discharged to the diffusion plug 42. In the process of discharging the gas, the measurement results of the PDIT differential pressure transducer, LIT level gauge, and TIT temperature transducer are recorded at each time unit. At the point in time when the reading of the differential pressure transmitter PDIT stops changing, the measurement is finished. These measurement results are the initial ones for calculating in the automated control system 34 the content of dissolved gas in the oil-gas-water mixture, on the basis of which, in turn, the volume and volumetric flow rate of associated petroleum gas are calculated.

The measurement of the content of the residual dissolved gas using the method of changing the level of the oil-gas-water mixture in the oil analyzer is carried out as follows: the oil-gas-water mixture enters through the sampler 25 (P), in which samples of the oil-gas-water mixture are taken, which subsequently enter the tank of the oil analyzer 3 (EA) ... Sampling of the oil-gas-water mixture is carried out until the equilibration of the excess pressure in the EA oil analyzer and in the EU separation tank. The liquid level in the tank of the oil analyzer 3 (EA) is controlled by the LIT level gauge. Further, by opening the valve H31, the associated petroleum gas contained in the oil and gas-water mixture is discharged to the scattering plug 42. In the process of discharging the gas, the measurement results of the LIT level gauge, the TIT temperature transducer are recorded at each time unit. At the moment when the readings of the LIT level transmitter stop changing, the measurements are finished. These measurement results are the initial ones for calculating in the automated control system 34 the content of dissolved gas in the oil-gas-water mixture, on the basis of which, in turn, the volume and volumetric flow rate of associated petroleum gas are calculated.

Thus, the 3 standard oil analyzer has become more versatile due to the compactness achieved by placing the 71 level gauge and auxiliary structures inside the analyzer vessel. And also thanks to the collapsible body, which makes it possible to lighten the structure and excludes special equipment for dismantling, and the bearing assemblies that ensure the rotation of the body, in turn, exclude the dependence of the level gauge dismantling on the height of the building ceiling.

The essence of measurement using an oil analyzer is as follows - discrete indirect measurements are performed in a dynamic mode, by taking representative samples from the flow of the oil and gas-water mixture with a sampler into the tank of the oil analyzer, further thermal separation of the oil-water mixture into its constituent components (water and oil), emptying (or discharging associated petroleum gas per candle, depending on the method used) the capacity of the oil analyzer and measurements using a differential pressure transducer, a level gauge and a temperature measuring transducer.

Measurements using an oil analyzer are carried out by the following methods:

• measurement of mass / volume moisture content of the liquid phase;

• measurement of the residual dissolved gas content using the density variation method;

• measuring the content of residual dissolved gas using the method of changing the level of an oil-gas-water mixture in an oil analyzer.

Method for measuring the mass / volume moisture content of the liquid phase.

Discrete indirect measurements are performed in a dynamic mode, by taking representative samples from the flow of the oil and gas-water mixture by a sampler into the tank of the oil analyzer, further thermal separation of the water-oil mixture into its component components (water and oil), emptying the tank of the oil analyzer and measurements using a differential pressure transducer, level gauge, etc. temperature measuring transducer.

Residual dissolved gas measurement using the density variation method

Discrete indirect measurements are carried out in a dynamic mode, by taking representative samples from the flow of the oil-gas-water mixture by a sampler into the tank of the oil analyzer, further discharge of associated petroleum gas to the diffusion plug 42 and fixing changes in the density of the oil-gas-water mixture by measuring the differential pressure with a transducer in the calibrated volume of the oil-gas analyzer and the level of the oil-gas-water mixture. mixture with a level meter.

Measurement of the residual dissolved gas content using the method of changing the level of an oil-gas-water mixture in an oil analyzer

Discrete indirect measurements are performed in a dynamic mode, by taking representative samples from the flow of the oil and gas-water mixture by a sampler into the tank of the oil analyzer, further discharging the associated petroleum gas to the diffusion plug 42 and fixing changes in the level of the oil and gas-water mixture with a level meter.

A mobile standard of the 2nd category for verifying installations for measuring well production (standard) is carried out using a dynamic measurement scheme with multi-stage partial separation of the input multiphase flow into liquid and gas. The quality of the separation of the multiphase flow into liquid and gas directly affects the accuracy of measuring the flow rate of the phases. The separation process implemented in the device consists of primary separation of a multiphase flow into liquid and gas in a hydrocyclone and secondary separation of a multiphase flow into liquid and gas using separation tanks. To improve the quality of separation, drip-catchers based on Pall rings and string grids are installed in the separation tanks. The problem of determining the proportion of water in the liquid phase is solved by using a hydrostatic type analyzer of the mixture composition. The analyzer additionally allows to determine the proportion of gas dissolved in oil. The determination of the density of free gas is based on a calculation using laboratory data on the composition of the gas.

An increase in the accuracy of the installation was achieved in the following ways:

- Use of multi-stage separation of multiphase flow into liquid and gas;

- The use of liquid flow meters that maintain the required measurement accuracy in the presence of a certain amount of free gas;

- The use of a redundant flow meter in the measuring line of the liquid to control the metrological characteristics;

- Application of two different types of flow meters (Coriolis and ultrasonic) in the gas measuring line;

- Using a measuring device to determine the quality of separation of liquid from gas and gas from liquid;

- Calculation of the amount of residual free and dissolved gas in the separated liquid;

- Calculation of the amount of dropping liquid in the gas flow;

Separation measuring capacity. The well fluid flows through the inlet pipeline into the hydrocyclone of the separation tank, where the primary separation of associated gas from crude oil takes place. The separated crude oil then enters the body of the separation vessel, where the defoamer is located, installed in the direction of liquid movement, and the separated gas is directed through string droplets into the gas line. Antifoam mass transfer nozzles have a large specific contact surface of the phases and thus provide a high throughput, a decrease in hydraulic resistance and an intensification of the separation process of a gas-liquid mixture.

In turn, the gas enters the separator on the hydrocyclone through a swirler, where, swirling under the influence of centrifugal force, part of the droplet liquid settles on the walls of the inlet fitting and flows into the main cavity of the gas separator through a specially designed groove, then the gas passes through a coalescer, which is two partitions made of perforated stainless steel sheet. The gap between the sheets is filled with Pall rings (volume 0.1 m3). To clean the coalescer from possible waxing, a steaming pipeline is provided.

In the outlet part of the separator, a package is provided, consisting of four string droplet catchers KS 430. In the string droplet catcher package, the final gas is purified from droplet liquid.

The separation-measuring tank of the 2nd standard provides a high-quality separation of the flow into gas and liquid phases, reduces the cost of further oil treatment by reducing the number of separation stages, and improves the quality of commercial oil. The separation-measuring tank also improves the accuracy of measuring the oil flow rate by eliminating the ingress of gas into measuring devices for liquids and liquid droplets into gas flow meters.

A mobile standard of the 2nd category for verification of downhole production measurement installations, implemented by applicants using commercially available devices and materials, provides the ability to transfer the unit of mass flow of well products to working instruments for measuring the mass flow and amount of crude oil, gas in operation, for verification and with increased accuracy of oil wells flow rates for oil and gas, in order to ensure the uniformity of mass flow rate measurements.

Claims (1)

A mobile standard of the 2nd category for verifying installations for measuring well production, characterized by the fact that it contains a supply line for an oil and gas-water mixture, a horizontally oriented separation-measuring tank, a vertically oriented oil analyzer, a liquid measurement line, a gas measurement line, an automated control system, and separation- the measuring tank consists of two communicating vessels, a lower tank for receiving liquid and an upper tank for receiving gas, equipped with a hydrocyclone with a gas swirler, the hydrocyclone is connected to the oil-gas-water mixture supply line and partially immersed in a tank for receiving liquid, a defoamer is installed in the separation-measuring tank, a drop catcher, a level meter, a pressure transducer, a liquid measurement line is connected to a container for receiving a liquid, a gas measurement line is connected to a container for receiving a gas, a gas measurement line contains a system for measuring the content of droplet liquid in the flow along of available petroleum gas, the liquid measurement line contains a moisture transducer installed at the liquid outlet from the separation and measurement tank, three parallel sections to which liquid mass flow meters are connected, a multiphase flow meter, a differential pressure transducer and an oil and gas-water mixture sampler connected to the oil-gas-water mixture supply line a line for supplying an oil-gas-water mixture to an oil analyzer, the oil analyzer contains a rotary housing mounted on a support with the possibility of fixing a vertical position, in the housing there is a level gauge with an interface level meter, with pressure and temperature transducers and a hydrostatic pressure sensor, the sensitive elements of the level meter and auxiliary structures are located inside the analyzer case, an automated control system designed for collecting and processing information, as well as for archiving, displaying and transmitting information to the upper level Aries, includes a control cabinet with a controller complete with a display, these structural elements are located in a block-container type box, located on the base, divided by a sealed explosion-proof partition into two rooms, a technological block and a control unit.

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