EA024819B1 - Device for determining a component composition of a downhole fluid - Google Patents

Abstract

The invention relates to measuring technology and can be used, in particular, in the petroleum industry for measuring, in real-time mode, the fractional composition (percentage ratio of phases) of a flow of a multi-component two-phase medium comprising oil, gas and water, and, specifically, a flow of a downhole fluid, and also for determining the mass and volumetric flow rate of the oil in other measuring systems in petroleum-extracting and oil-refining installations. Claimed is a device for determining the component composition of a downhole fluid, the device comprising a pipe section with connecting flanges, within which temperature and pressure sensors are mounted, and also a system for measuring the electrophysical characteristics of the downhole fluid, wherein the outputs of the two sensors and of the system for measuring the electrophysical characteristics are connected to a computer. The novelty consists in that the system for measuring the electrophysical characteristics is equipped with units for measuring the dielectric constant and/or electrical conductivity, and one or more ultrasonic meters, the outputs of which are connected to the computer, are additionally inserted into the device, wherein each of the above-mentioned ultrasonic meters is intended for recording the propagation rate and the amplitude of a signal at a fixed acoustic oscillation frequency.

Description

The invention relates to measuring technique and can be used, in particular, in the oil industry for measuring in real time the fractional composition (percentage of phases) of a stream of a multicomponent two-phase medium, including oil, gas and water, namely, the flow of a well fluid, and also to determine the mass and volumetric flow rate of oil as part of other measuring systems at oil production and oil preparation facilities.

State of the art

To ensure effective control and regulation of the oil production process, it is necessary to measure as accurately as possible the amount of oil recovered from the reservoir, which allows for optimal operation and maximum total production over the life of the field. It is required to measure the production of individual wells individually, since, for example, a sharp increase in water cut in an individual well is difficult to detect when measuring the total production from several wells, and even more so from group measurements it is impossible to accurately determine in which particular well the water cut increased to carry out any work on it to reduce production costs.

Therefore, there is a great need for a device that meets the following set of requirements: the device must provide continuous determination of the relative amounts (concentrations) of components in the well fluid (water, oil and gas) in a wide range of values, since this is important independent field information;

the device should provide measurement of the instantaneous specific consumption of gas and liquid in a wide range of values, i.e. Assume simple scaling or universality of the solution, since typical fields are in the late stages of production and can have a significant variation in productive parameters in neighboring wells;

the device must allow sequential inclusion in the pipeline system, without providing noticeable hydraulic resistance to the flow of the borehole fluid, since low-production wells may not be able to provide sufficient wellhead pressure;

the measuring part of the device should have a simple design that provides reliability and fault tolerance in a continuous flow of well fluid;

installation of the device should be economically feasible based on the calculation of the equipment of each well, and not group measurements for a whole cluster of wells;

device maintenance should be carried out without the use of highly qualified personnel with special approvals, for example, to work with radioactive sources, etc., since this will lead to a significant increase in operating costs that are unacceptable for the operation of deposits in the later stages;

the device requires compactness and mobility, which simplifies transportation and installation without the use of special equipment, due to its inaccessibility at remote cluster sites and the general inaccessibility of oil and gas fields for a long period of time of the year;

the device requires universality of connection, which allows directing the flow of well fluid in both forward and reverse directions, which is very important when switching flows during well operation.

A device for measuring the production of oil wells is described in patent KI2168011, class. ЕВВ 47/10, 2001. The installation includes a switch for wells, an inlet pipe connecting the switch with a gravity-type separator for separating gas, and pipelines for removing gas and liquid from the separator. A vortex-type gas flowmeter is installed on the gas line, and a Coriolis-type mass flowmeter (also a densitometer) is installed on the liquid line for measuring the flow rate and density of the oil-water emulsion, as well as a device for continuously measuring the water content in the oil-water emulsion (capacitive, microwave, infrared or radio frequency hydrometer). The unit is equipped with a controller designed to process data from the densitometer and moisture meter for calculating the instantaneous water cut, mass oil flow rate, etc. The device operates in a wide range of flow rates, allows accurate measurement of the mass and volumetric flow rates of gas and liquid, and is ideal for group measurements from a whole bush wells.

However, the known device has several significant disadvantages.

Firstly, the presence of a gravitational separator assumes a cumulative mode of operation, therefore, the device can only perform discrete measurements, yielding flow rates averaged over a long time interval (corresponds to the phase separation time, and for viscous oils it can take tens of minutes).

Secondly, the bulkiness of the device complicates and increases the cost of delivery to the field, the complexity and specificity of the initial setup and adjustment during operation and requires the presence of highly qualified specialists.

Thirdly, the device provides serious hydraulic resistance to the flow and does not allow inversion of the flow direction of the well fluid.

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In addition, the cost of the device makes it economically impractical to use it for individual measurements at each well.

A device for measuring the production of oil wells, described in patent KI2270981, class. ЕВВ 47/10, 2004. The installation includes a switch for wells, an inlet pipe connecting the switch with a cyclone (vortex) type separator designed to separate gas, pipelines for removing gas and liquid from the separator. Both lines are equipped with single-phase Coriolis type flow meters, which, in addition to expenses, make it possible to measure the density of the medium, and a device for continuously measuring the water content in the oil-water emulsion (capacitive, microwave, infrared or radio frequency moisture meter) is integrated in the liquid line. The unit is equipped with a controller designed to process data from the densitometer and moisture meter to calculate the instantaneous water cut, mass flow rate of oil, etc. The device allows you to accurately measure the instantaneous mass and volumetric flow rates of gas and liquid, well suited for group measurements from a whole wellbore.

However, the known device also has several significant disadvantages.

Firstly, the presence of a cyclone separator imposes a restriction on the minimum allowable flow rate, which excludes its use for individual measurements on low-rate wells.

Secondly, the bulkiness of the device complicates and increases the cost of delivery to the field, the complexity and specificity of the initial setup and adjustment during operation requires the presence of highly qualified specialists.

Thirdly, the known device also does not allow inversion of the direction of flow of the well fluid.

Fourth, the known device, like the above analogue, makes it economically impractical to use it for individual measurements because of the cost of the device.

Closest to the claimed device by technical nature is a device taken as a prototype described in patent I84802361, cl. Ο01Ν 33/22, 1989. The device includes a measuring section connected to the pipeline rupture for passing the oil-gas mixture flow, on which a gamma-radiation densitometer (densitometer) is located to measure the instantaneous density of the oil-gas mixture (hr) and an electromagnetic type flow meter for determining the instantaneous value of the dielectric constant of the oil-gas mixture (hedgehog). The device also includes a controller configured to set the density of pure oil (i.e., anhydrous, degassed oil), water and free gas, and also to determine the volume fraction of water by solving a system of three equations including the values of hw and hedgehog as constant coefficients, and the value of the volume fraction of water, oil and gas - as unknown in the equations of this system. The device is functionally represented by a pipe on which two coaxial inductors are installed, operating at a frequency of 400 MG c, between which the phase difference is measured, which is associated with the dielectric constant of the medium and, as a result, with the relative amount of water in the mixture in the pipe. Further, on the tube there is a radioactive source of Cg ¹³⁷ placed in a lead collimator to create a narrow beam of gamma quanta and a receiver based on a scintillation transducer to record the intensity of the gamma ray flux passing through the mixture in the tube. Thus, a measurement of the density of the medium is carried out, and as a result, its gas saturation coefficient. The initial values of the gas saturation coefficients for pure substances are obtained by calibration measurements on reference mixtures. In addition, a temperature sensor is located on the pipe to measure the current temperature of the mixture in the pipe, since the dielectric constant of the oil-water mixture has a pronounced temperature dependence. In one embodiment, a pressure sensor can be installed on the pipe to take into account the dependence of gas density on pressure and correct the calculation of the relative amount of gas. The device operates in a wide range of flow rates, allows you to accurately measure the instantaneous mass and volumetric flow rates of gas and liquid, has compact dimensions, provides minimal hydraulic resistance to flow and allows inverting the direction of the well fluid.

The main disadvantage of the device is the presence of a radioactive source, which imposes serious restrictions on operation, requires highly qualified personnel with special tolerances during initial setup and adjustment during operation.

In addition, the known device, as well as the above counterparts, makes it economically impractical to use it for individual measurements at each well of the field due to the high cost of the device itself and measures related to ensuring radiation safety of the device.

Disclosure of invention

The objective of the present invention is to remedy these disadvantages, namely the creation of such a device that would combine the compactness of the prototype, but would have ease of maintenance, no need to ensure the protection of the device, the reliability of the results obtained - 2,024,819 tons and their independence from flow conditions and composition mixtures.

The specified task in the device for determining the component composition of oil and gas wells, including a pipe segment with connecting flanges, inside which temperature and pressure sensors are installed, as well as a system for measuring the electrophysical characteristics of the well fluid, while the outputs of both sensors and the system for measuring electrophysical characteristics are connected to the computational the device, it is decided that the system for measuring electrical characteristics is equipped with measuring units dielectric permeability and / or conductivity, and the apparatus additionally administered one or more ultrasonic gauges, whose outputs are connected to a computing device, each of said ultrasonic meters for registering the propagation velocity and amplitude of the signal at a fixed frequency acoustic oscillations.

Since the determination of the component composition of a gas-liquid mixture without phase separation should be based on measuring the physical properties of the medium, which are significantly different for individual components, to determine the specific moisture content in the claimed solution, the electrophysical properties of the medium, which are most strongly contrasted between water and oil gas, will be measured, such as dielectric constant and electrical conductivity (electrical impedance), and for determining the specific gas content - acoustic properties and medium, most strongly contrasting between a gas and a liquid, such as speed of ultrasonic waves and attenuation coefficient of the acoustic oscillations. The acoustic properties of the medium depend on the density, viscosity and thermophysical characteristics of the medium; therefore, acoustic measurements can determine gas not only in a free, but also in a dissolved form by a change in the viscosity of a liquid. For direct measurement of the electrophysical properties of the well fluid, the claimed solution proposes a capacitive flow-through sensor, in which the electrical impedance depends on the electrophysical properties of the gas-liquid medium flowing through it.

Since the electrophysical and acoustic properties of the components are unknown a priori and, moreover, can vary for different well fluids, before measurements it is necessary to calibrate the device, which is designed to determine the physical properties of the components of the mixture. Using discrete calibration points, a simple analytical function is constructed that relates the measured properties of the medium to the component composition. After that, the determination of the component composition is a solution to the inverse problem of the measured properties of the medium. Measurements of the component composition must be adjusted taking into account the gas-liquid mixture flow regime, since the electrophysical and acoustic properties substantially depend not only on the component composition, but also on the degree of their mixing. Fundamentally, the difference between the proposed solution lies precisely in the approach to measuring not one physical characteristic of the medium, but several, namely, electrical and acoustic impedance. Conventional solutions, as a rule, use one type of measurement to determine the specific contents of the components, with large sensitivity limitations in certain parts of the range. In the claimed solution, acoustic measurements are necessary to determine the specific gas content, and electrophysical measurements are necessary to determine the specific fraction of water in the fluid, which gives the full component composition of the well fluid. In the water-in-oil field, it is sufficient to measure the absolute value of the electric impedance of the capacitive sensor, and when the phases turn to oil-in-water mode, when the dependence of the impedance on the specific fraction of water drops, it is most reliable to switch to measuring the phase shift between current and voltage by capacitive sensor.

To determine the electrophysical characteristics of the well fluid, a capacitive sensor made in the form of a coaxial capacitor with one cylindrical shell and a second shell in the form of a central rod or in the form of a cylindrical capacitor with plates in the form of diametrically located cylinder segments can be used as a dielectric permittivity meter.

To determine the electrophysical characteristics of the well fluid, a system of inductive coils located coaxially to each other and to the pipe axis or located coaxially to each other and orthogonal to the pipe axis can be used as a medium conductivity meter.

To determine the acoustic characteristics of the borehole fluid, an ultrasonic transducer made in the form of one or more pairs of piezoceramic source-receiver transducers located in the pipe cross section is diametrically opposite to each other as a relative gas content meter.

To perform the inventive device with wide functional capabilities, the pipe segment, inside which the sensors are installed, is made up of several module sections hermetically connected to each other, each of which is equipped with one or more types of meters. The modularity of the device architecture allows you to quickly change the composition of the measuring sections, expand the ranges of the device if necessary. This is important for long-term operations in real oil and gas wells, when during operation, the flow regimes of 3,048,819 fluids can be changed due to a change in the operating modes of the well, the use of optimizing operations, such as hydraulic fracturing or acid treatment, the launch of pumps of various configurations, fitting changes and stuff. Therefore, the operation of the modules can be considered independently of each other.

To reduce the dimensions of the device while increasing its speed, the measuring device is made on the basis of a microcontroller equipped with an input interface for digitizing signals from sensors.

To enable continuous monitoring of the state of the well, the measuring device is equipped with a non-volatile drive for storing measurements, an autonomous power supply and an external interface connected to the radio channel module.

Brief Description of the Drawings

In FIG. 1 shows an embodiment of the inventive device with a capacitive coaxial sensor and a single ultrasonic meter for the propagation velocity and amplitude of the acoustic signal, including: a pipe section 1 in which an ultrasonic meter is installed, consisting of a source 2a and a receiver 2b, as well as a capacitive sensor, consisting of an external cylindrical plates 3 and the central rod 4; pressure sensors 5 and temperature 6; controller 7 with input interface 8; mounting flanges 9a and 9b.

In FIG. 2a-c shows an embodiment of the inventive device with a capacitive sensor made in the form of two pairs of diametrically arranged electrodes 10a-10d and two diametrically located ultrasonic meters 2a-b and 2c-d.

In FIG. 3 presents an embodiment of the inventive device of a modular type with a radio transmitting channel, consisting of four pipe modules interconnected by flanges in a single unit, three of which are equipped with measuring sensors, and the fourth is a backup. The device further includes: a module for acoustic meters of gas 11; thermobarometry module 12; module dielcometric measuring the water content 13; standby module 14; controller 15 output interface (radio module with antenna); autonomous power supply module 16.

In FIG. 4 shows another embodiment of a module of a dielcometric meter for measuring the water content 13, including: coaxial with the pipe coil 17a and 17b of an induction conductivity meter 18.

In FIG. 5 shows yet another embodiment of a module of a dielcometric water content meter 13, including: inductors 19a and 19b located on the pipe surface diametrically opposite to each other.

In FIG. Figure 6 shows graphs of the dependences of the electrical conductivity and permittivity of the oil-water mixture on the specific fraction of water, where: 21 is the dependence of the electrical conductivity of the oil-water mixture; 22 - dependence of the dielectric constant of a water-oil emulsion; 23 - region of emulsions of the type water-in-oil; 24 is a region of oil-in-water emulsions.

In FIG. Figure 7 shows graphs of the dependences of the amplitude of acoustic vibrations after passing through a gas-liquid mixture and the speed of propagation of an acoustic wave on the specific gas content in a medium, where 25 is the dependence of the amplitude of acoustic vibrations; 26 - dependence of the speed of the acoustic wave.

The best embodiment of the invention

Consider the operation of the inventive device shown in FIG. 3. A mixture of oil, water and gas in arbitrary proportions (well fluid) enters the device through the flange 9a. Ultrasonic waves are emitted from one of the diametrically located piezoelectric transducers 2a pass through the flowing mixture, changing their characteristics depending on the medium’s properties, and get on exactly the same transducer 2b, the signal from which is fed to the controller 7 through the input interface 8, where the analog signal is converted digitally, and the controller 7 calculates its parameters: the speed of the ultrasonic wave and its amplitude. The hydrostatic pressure sensors 5 and temperature 6 are installed on the pipe wall, the signal outputs of which are also connected to the controller 7 through the input interface 8.

As mentioned above, the amplitude of an acoustic wave and its mean free path depend on the properties of the mixture, and mainly on its average density, i.e. the ratio between the gas fraction and the liquid. In FIG. 7 presents high-quality graphs reflecting the behavior of the dependence of the amplitude of the acoustic wave 25 and the propagation velocity of the wave 26 on the relative gas content in the liquid. It follows from the general theory of the propagation of acoustic waves in gas and liquid media that the attenuation of an acoustic signal depends on many parameters of the medium, in particular, on its density, viscosity, thermal conductivity, etc., in particular, the attenuation is much higher in a gas medium than in a liquid the graph obtained in the experimental setup confirms this fact, and we see a significant drop in the amplitude of the signal in the receiver with increasing concentration of gas bubbles from the liquid, the point b - corresponds to the zero gas content and i is maximal in amplitude, point a, on the contrary, corresponds to amplitude in a purely gaseous medium. These points serve as calibration parameters, based on which, from the measured amplitude η, we can determine the ratio between the gas and liquid phases. In the same way, the propagation velocity of an acoustic wave carries information about the relationship between the gas and liquid fractions. Further, the mixture falls into the interval of operation of the water content meter 13, which can be implemented using a dielectric constant sensor consisting of capacitor plates 10a and 10b. The signal output of the meter is also connected to the controller 7, where the dielectric constant of the medium flowing in the internal volume of the device is calculated. Further processing of the data consists in calculating the gas saturation parameters from the available calibration values of the speed and attenuation amplitude of the ultrasonic signal taking into account the temperature of the medium and hydrostatic pressure, calculating the water saturation of the liquid part of the medium from the available calibration values of the dielectric permittivity meter (previously recorded in the memory of controller 7). The inventive device in this case has a limitation on the range of changes in water concentration, namely, the sensitivity of the capacitive sensor to the amount of water has a limitation of not more than 80% of water at zero gas content. To overcome this limitation, the water content meter 13 can be implemented using the mixture conductivity sensor 18 (see Fig. 4a) whose sensitivity, on the contrary, is below the emulsion circulation point, namely, with relative amounts of water more than 40%. Thus, the use of both modules (permittivity and electrical conductivity) will allow us to calculate the electrical impedance of the mixture, which, when taking into account the gas content, allows us to reliably (not worse than 5%) determine the relative water content. An example of such a relationship can be seen in FIG. 6, which shows qualitative diagrams of the dielectric constant 22 and the electrical conductivity of the mixture 21, depending on the water content. It can be seen from these diagrams that in the region of low water content 23, it is the capacitive method that has high sensitivity up to values of about 40% water, followed by a range from 40 to 60% (depending on the properties of liquids and thermobaric conditions) in which one and the other method do not show obvious advantages, and the upper range of water content 24, in which the concentration of oil droplets determines the values of electrical resistivity. The module shown in FIG. 4 can additionally be incorporated into the device of FIG. 3, instead of the backup module 14. Thus, a combination of these two characteristics called electrical impedance is the best indicator of water content in the entire range.

Measurement of temperature and pressure simultaneously with impedance measurements allows both to introduce corrections due to temperature coefficients of physical properties and to recalculate the relative concentrations of the components to absolute values under normal conditions.

Technical applicability

To test the operability of the claimed device, a laboratory setup was assembled from the measuring cell in the form of a vertical pipe into which the test liquid was poured. A certain air flow from the compressor was supplied through the lower part of the pipe to create the movement of gas bubbles in a liquid with a given concentration. Liquids with various electrophysical properties were poured into the pipe: mixtures of water with different levels of mineralization and transformer oil to obtain different values of the dielectric constant and conductivity of the test medium. Air was supplied only to aqueous solutions with different salinity for fire safety reasons. The air supply to the measuring cell was controlled using a needle valve from a small-sized compressor with receiver ΡΚΟΚΑΒ providing a uniform air supply with a flow rate of up to 350 l / min.

Electrical measurements were carried out both with the VAD-40 serial dielcometric sensor manufactured by NPO Technokom and with a laboratory model setup in a wide frequency range with an upper limit of 100 MHz. The model setup for determining the electrophysical properties was a capacitor with plane-parallel electrodes connected to a sinusoidal voltage generator with an adjustable frequency assembled on a ΑΌ9957 frequency synthesizer (manufactured by Apaod Oeu1ee8) and a current sensor, between which plates various sample media were placed. The signals from the generator and the current sensor were supplied for comparison to a phase detector assembled on a ΑΌ8302 controller (manufactured by Apaod Oeu1ee8), and then to a two-channel high-speed ADC assembled on an AI9650 controller (manufactured by Apaod oeuuuuee8). As a result of comparing the current and voltage signals on the capacitor, the electrical impedance and phase shift between the current and voltage on the capacitor were calculated, which depend on the electrophysical properties of the medium filling the space between the plates - conductivity and permittivity.

For acoustic measurements, a pair of piezoceramic transducers on barium titanate was taken, hermetically mounted in the pipe wall diametrically opposite to each other in the pipe cross section, the signal was measured both in the forward flow direction and in the opposite direction (by reversing the source to the receiver and vice versa) to compensate for the movement the medium itself, at ultrasound frequencies up to 100 kHz. We measured both the travel time of the acoustic wave from the source to the receiver and the amplitude of the acoustic vibrations after passing through the medium. One of the piezoceramic transducers acted as an ultrasound source; pulses of a given frequency from an adjustable

- 5,024,819 ultrasonic frequency generators (UHF), and the second is the role of an ultrasound receiver that converts acoustic vibrations of the medium into electrical pulses that are received for digitization at the input of an ADC connected to a personal computer (PC) for subsequent analysis. A comparison of the data obtained from the source and receiver of ultrasound allows us to calculate both the speed of propagation of the acoustic wave and the attenuation of the amplitude of the acoustic vibrations. In turn, these characteristics depend on the density, viscosity, and thermophysical properties of the medium, which allows one to calculate the component composition based on a simple physical model.

As a temperature sensor, a TP008E type thermocouple converter manufactured by Thermoautomatics was used, connected to a low-frequency multi-channel ADC E14-440 block manufactured by L-Sagb. To measure hydrostatic pressure, a small-sized pressure sensor of the DM5007 type manufactured by Manotom was selected with a digital output of the measurement results. Acoustic and dielcometric sensors were connected to the ADC units for digitizing signals and transmitting via the I8V bus to a PC for further conversion and calculations.

To test the operability of acoustic and dielcometric meters, measurements were made on a series of model mixtures of known composition. In FIG. 6 shows the qualitative dependence of the conductivity and dielectric constant along the оси axis on the specific fraction of water in the liquid along the X axis, and in FIG. Figure 7 shows the dependence of the amplitude of the acoustic signal along the оси axis on the specific fraction of gas along the X axis. Qualitatively, with an increase in the specific fraction of water in a liquid, the conductivity and permittivity increase, and with an increase in gas content, the amplitude of the acoustic signal decreases. The same diagram shows the dependence of the speed of an acoustic wave in a gas-liquid medium on the specific fraction of gas in a liquid. For the practical determination of the specific fraction of water in a liquid and the gas content in a mixture, calibration measurements are required for reference mixtures, for example, pure water, pure transformer oil, clean air, and several mixtures with characteristic compositions, from which approximation dependences of the measured values on the composition of the mixture are constructed. Having such dependences, it is easy to solve the inverse problem, i.e. determine the component composition by the measured electrophysical and acoustic properties.

Thus, the operability of two methods for determining the relative amount of gas in a liquid and the amount of water in a liquid was tested; tests showed that the proposed technical solution provides the determination of the fractional content of oil, gas and water components with an accuracy of no worse than 5%.

Claims (9)

1. A device for determining the phase composition of the borehole fluid, including a pipe segment with connecting flanges, inside which temperature and pressure sensors are installed, as well as a system for measuring the electrophysical characteristics of the borehole fluid, while the outputs of both sensors and the system for measuring the electrophysical characteristics are connected to a computing device, characterized in that the system for measuring electrical characteristics is equipped with blocks for measuring the dielectric constant and / or electro conductivity, and one or more ultrasonic meters are additionally introduced into the device, the outputs of which are connected to a computing device, and each of these ultrasonic meters is designed to record the propagation velocity and signal amplitude at a fixed frequency of acoustic vibrations. 2. The device according to claim 1, characterized in that as the unit for measuring the dielectric constant, a capacitive sensor is used, made in the form of a coaxial capacitor with one lining of a cylindrical shape and a second lining in the form of a central rod. 3. The device according to claim 1, characterized in that as the unit for measuring the dielectric constant, a capacitive sensor is used, made in the form of a cylindrical capacitor with plates in the form of diametrically located segments of the cylinder. 4. The device according to claim 1, characterized in that as a unit for measuring the electrical conductivity of the medium used a system of inductive coils located coaxially to each other and to the axis of the pipe. 5. The device according to claim 1, characterized in that a system of inductive coils located coaxially to each other and orthogonal to the axis of the pipe is used as a unit for measuring the electrical conductivity of the medium. 6. The device according to claim 1, characterized in that an ultrasonic transducer made in the form of one or more pairs of piezoceramic source-receiver transducers located in the cross section of the pipe is diametrically opposite to each other as a relative gas content sensor. 7. The device according to claim 1, characterized in that the pipe segment, inside which the sensors are installed, is made integral, consisting of several module sections hermetically connected to each other, each of which is equipped with one or more types of meters. - 6,048,819 8. The device according to claim 1, characterized in that the measuring device is based on a microcontroller equipped with an input interface for digitizing signals from sensors. 9. The device according to claim 1, characterized in that the measuring device is equipped with a non-volatile drive for storing measurements, an autonomous power source and an external interface connected to the radio channel module. - 7,048,819