RU2823636C1 - Method of measuring mass flow rate of crude oil and volume of undissolved gas in oil well product - Google Patents

Abstract

FIELD: oil, gas and coke-chemical industry.

SUBSTANCE: method for measuring mass flow rate of crude oil and volume of undissolved gas in oil well products includes a cycle of filling oil well products into a measuring tank with removal of free gas into the pressure line of the well, product discharge cycle from the tank when the liquid level in the tank reaches the uppermost position, the crude oil flow rate is measured by the rate of filling the calibrated part of the measuring tank, and the volumetric flow rate of the gas is measured by the rate of its emptying. At that, switching of the product filling into the container to the drain and back are made when the liquid level reaches the known density in the outer vertical tube of the extreme upper and lower positions, connected on one side with the gas discharge line from the container, and on the other - with the lower part of the reservoir filled with formation water. At that, formation water and liquid of known density in the vertical tube are separated by a flexible membrane. Location of the lower level sensor in the outer tube is located at the level of the end of the product drain pipe from the measuring vessel.

EFFECT: simpler measurements and higher accuracy.

1 cl, 2 dwg

Description

The present invention relates to the oil industry and can be used to measure the volume of undissolved gas in oil, as well as the mass of crude (water-cut) oil in the production of an oil well.

The measurement of oil well production in most cases is carried out by automated group measuring units (AGMU) of a stationary or mobile type. For example, to measure gas flow rate, there is a known method based on determining the rate of filling two measuring tanks in turn and their subsequent emptying / RF Patent No. 2082107. Method for determining the amount of oil, gas and water in well production. Application 05/18/95 Publ. 06/20/97 /. The flow rate of the water-oil mixture is determined by the time of filling the containers, and the flow rate of the free gas phase is determined by the rate of emptying of the containers. The disadvantage of the device is that during measurements, dispersed aqueous and gas phases in the form of drops and bubbles are present in the liquid filling a cylindrical container, which leads to a significant measurement error.

A known installation for determining the production rate of a well / RF Patent No. 2133826. Installation for determining the production rate of wells. Application 05.01.98 Publ. 27.07.99 / Water flow is determined by the known densities of oil and water, as well as the hydrostatic pressure of the liquid column in the measuring cylinder. When the upper level in the measuring tank is reached, the sensors send a signal to switch the flow to another tank and measure the hydrostatic pressure, which determines the average density of the liquid. Based on the previously known densities of oil and water, the water content in the volume of liquid is calculated.

The installation has a significant error due to the presence of part of the free dispersed gas in the volume of oil.

There is a known method for determining the flow rates of oil, associated gas and water / Patent RU No. 2504653 C1. Application 07/30/2012 Published 01/20/2014 /. To measure the liquid flow rate, the measuring tank is filled with the well product, and after the maximum level of the water-oil mixture is reached, the inlet valve of the measuring tank is closed and held for time to separate free gas from the liquid. After determining the flow rate of the water-oil mixture based on the filling rate and the volume of separated liquid, the gas phase is gradually withdrawn from the upper part of the measuring tank by a compressor through a reducer reducing to atmospheric pressure. The compressor pumps the extracted gas into the well reservoir. The gas is pumped out until the pressure in the measuring tank drops to atmospheric value. The gas factor is calculated based on the compressor performance and its operating time.

However, the use of a compressor is complicated due to changes in gas injection pressure into the reservoir, which varies over wide ranges even within one oil field.

The closest to the proposed invention in technical essence is a method for measuring oil and associated gas flow rates of oil wells / patent RU No. 2439316 C2. Application 04/05/2010. Publ. 10.01.2012 /. The method includes the flow of produced products from a tubing string into a separator and the separation of gas and oil in it. Next, sequential selection of oil and gas is carried out from the separator with their quantity measured by a flow switch according to the time of filling and emptying of the measuring part of the separator, respectively. Switching of oil and gas flows is accomplished by increasing pressure on each side of the two-way flow switch piston by locking the oil and gas outlets from the separator at the upper and lower ends of a vertical perforated pipe.

The disadvantage of this method is that when the pressure in the separator increases, the oil and gas flows are blocked by a spherical shut-off element floating on the phase interface, which does not ensure the stability of pipeline closure, which leads to a significant error in measuring the time of oil filling and draining, as well as the reliability of the carried out measurements.

The technical objective of the proposed method is to simplify measurements and increase their accuracy.

The solution to the stated technical problem is achieved by the fact that in the known method of measuring the flow rates of oil, water and free associated petroleum gas, which includes a cycle of filling oil well products into a measuring tank with the discharge of free gas into the pressure line of the well, a cycle of draining products from the tank when the liquid level reaches containers in the extreme upper position, measuring the flow rate of crude oil by the rate of filling of the calibrated part of the container, and the volumetric flow rate of gas - by the speed of its emptying, according to the invention, switching the loading of products into the container to drain and back is carried out when the liquid level reaches a known density in the outer vertical tube of the extreme upper and lower positions, connected on one side to the gas outlet line from the tank, and on the other - to the lower part of the tank filled with formation water, and the formation water and liquid of known density in a vertical tube are separated by a flexible membrane, and the location of the lower level sensor in the outer tube is located at the level of the end of the pipe for draining products from the measuring tank.

In fig. 1 and 2 show an example of the method. To separator 1 for measuring the mass of crude oil and the volume of undissolved gas, line 3 for introducing products from the well is connected through valve 2 (not shown in the figure). Inside the container 1 there is a pipe 4 for gas removal and a pipe 5 for draining products from the container 1. A gas exhaust line 6 connected to a gas pressure throttle 7 is connected to the pipe 4 from the outside of the container 1. Connected to the same throttle 7 is a line 8 for draining liquid from container 1, on which an electromagnetic valve 9 is installed, and a valve 11 is also installed on line 10 for draining liquid into the manifold.

Outside, parallel to the measuring tank 1, a vertical tube 12 is installed, in the upper part connected to the gas outlet line 6, and in the lower part connected through a tube 13 to the cavity of the flexible membrane 14 through a tap 15. The membrane 14 is made of a material that does not offer resistance when it moves under due to the pressure difference in the upper and lower cavities of its body. On a vertical tube 12 filled with a liquid of known density, gas-liquid level position sensors are installed at different levels. The lower sensor 16 is located directly above the membrane body 14, and the upper sensor 17 is located at a height below the end of the pipe 4 in tank 1.

Liquid level sensors 16 and 17 in a vertical tube 12 (Fig. 2) consist of a housing 18 with a sealed contact 19 and a permanent magnet 20 located on the outside of the tube 12 opposite each other. Contacts 16 and 17 are connected to a controller (not shown in the figure), which includes a timer. Inside the vertical tube 12, a float 21 is freely located on the surface of the liquid.

The output ends of the sealed contacts 19 of both sensors 16 and 17, as well as the contacts of the solenoid valve 9, are connected to the controller (not shown in Figs. 1 and 2). A check valve 22 is installed on the liquid entry line into the measuring tank 1. A pressure gauge 23 is installed in the upper part of the measuring tank 1, and a valve 24 is installed in the lower part. The volume of the membrane body 14 is made disproportionately larger than the volume of the tube 12 using the small diameter of the latter.

The measurement method is carried out as follows.

Before measuring well production, the vertical tube 12 is preliminarily calibrated with a liquid of known density, for example, process water or a non-freezing liquid, for example, tinted alcohol.

First, a small volume of liquid (water) with a density of 1000 kg/m ³ is poured into container 1 through tap 24 to a height in the container that exceeds the level of the end of the product drain pipe 5. Next, drain the filled liquid from the container through tap 24 and turn it off. In the space between the drain pipe 5 and the lower bottom of the container 1, there will remain “trapped” water, which, through the open tap 15 of line 13, will displace liquid of known density from the upper part of the membrane body 14 into tube 12. The achieved liquid level in tube 12 should be established at approximately the location of the end of the pipe 5 for draining products from container 1. To do this, excess liquid filled from the upper part of the membrane body 14 is removed through a valve in the body (not shown in Fig. 2). After this, the level sensor 16 is fixed to the tube 12 at the resulting liquid level in it.

The next calibration step is to pour water into measuring container 1 through tap 24 to a level corresponding to the maximum specified differential hydrostatic pressure. The increased pressure on the membrane 14 from below will force the liquid from the membrane body 14 into the tube 12 to a much greater height. At the reached liquid level in tube 12, the upper level sensor 17 is fixed. After this, the liquid from container 1 is drained through tap 24. At this point, the calibration of the measuring part is considered complete.

The volume of the above-membrane part of the membrane body 14 is selected such that the vertical movement of the membrane itself to ensure the displacement of liquid from the body into the tube 12 to the level of the sensor 17 is negligible.

The captured water in the bottom of tank 1 will almost always be present when measuring well flow rates and will be freed from oil and gas. In flooded wells, it will gradually be replaced by mineralized produced water. Therefore, periodic adjustments are made to the position of the level sensor 16 on the tube 12.

To carry out measurements, the installation is connected to the manifold line of the well with valves 2 and 11. On the manifold line between the connection points of the installation there is a burst valve (also not shown in the figure). The value of the hydrostatic pressure drop in tank 1 will show a zero value. When valves 2 and 11 are opened and the burst valve on the manifold is closed, the control unit program will close the solenoid valve 9. The cycle of filling the product into measuring tank 1 will begin and the hydrostatic pressure drop in it will increase.

At the same time, through line 13, this pressure difference will be transmitted to the membrane 14 from below, pushing a liquid of known density into tube 12. When the hydrostatic pressure drop in container 1 reaches the maximum specified value, the liquid level in tube 12 will also reach its maximum value and sensor 17 will close its sealed contact 19. In this case, the electromagnetic valve 9 will open and the cycle of draining the product into the collector through lines 8 and 10 will begin. Contact 19 will close when the ferromagnetic float 21 passes through the magnet 20 and transfers the magnetic field to the contact area 19.

Draining of liquid from container 1 will occur due to the pressure of the accumulating gas in its upper part due to the installation of throttle 7. Increasing the gas throttling pressure by an amount of about 0.05 MPa will ensure that the product is “squeezed out” to be drained at low gas contents of oil.

When the minimum differential hydrostatic pressure, usually zero, is reached, the liquid level in the tube reaches sensor 16, closes contact 19 and closes the product drain with solenoid valve 9. Then the filling pattern is repeated, etc.

The density of crude (watered) oil ρ _сн entering tank 1 is calculated by the formula:

where: ρ _n - density of anhydrous oil, kg/m ³ ;

ρ _in - density of formation water, kg/m ³ ;

B - water cut of well production, dollars. units

The mass flow rate of crude oil is calculated:

where: ρ _liquid - density of the liquid in the tube 12, kg/m ³ ;

D _c - internal diameter of the container 1, m;

N _wt - distance between sensors 16 and 17, m;

T ₁ - time of filling container 1 (time of movement of the liquid level in tube 12 from sensor 16 to sensor 17), s.

The volumetric flow rate of undissolved gas is calculated:

where: T ₂ - time to drain the product from container 1 (time of movement of the liquid level in tube 12 from sensor 17 to sensor 16), s.

The lower density of crude oil compared to the density of water can lead to the fact that the liquid level in container 1 at the end of the filling cycle will be higher than the end of the pipe 4. Therefore, the installation location of the sensor 17 should be selected with some margin in the distance between it and the end of the pipe 4.

The technical and economic advantages of the proposed method are simplicity and increased accuracy of measurements, as well as the ability to measure significant volumes of crude oil and undissolved gas.

Claims (1)

A method for measuring the mass flow rate of crude oil and the volume of undissolved gas in the production of an oil well, including a cycle of loading oil well products into a measuring tank with the removal of free gas into the pressure line of the well, a cycle of draining the product from the tank when the liquid level in the tank reaches the highest position, measuring the flow rate crude oil according to the rate of filling of the calibrated part of the measuring tank, and the volumetric gas flow rate - according to the speed of its emptying, characterized in that switching the loading of products into the measuring tank to drain and back is made when the liquid level reaches a known density in the outer vertical tube of the extreme upper and lower positions , connected on one side to the gas outlet line from the tank, and on the other, to the lower part of the measuring tank filled with formation water, whereby the formation water and liquid of known density in the vertical tube are separated by a flexible membrane, and the location of the lower level sensor is in the outer tube is located at the level of the end of the pipe for draining products from the measuring tank.

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