RU2562628C1 - Method of liquid dynamic level determination in well - Google Patents

Abstract

FIELD: oil and gas industry.

SUBSTANCE: small volume of petroleum gas released from the well is measured by the gas meter and converted to the well conditions. The gas volume change results in change of its pressure in the well, it is suggested to estimate it as average of wellhead pressure and pressure in zone of the liquid dynamic level P(h_dyn). The later parameter is determined as per the known Laplace-Babine exponential formula, in it the unknown valuable is the dynamic level of the liquid in well (h_dyn). The dynamic level of the liquid in well is determined by division of the released gas volume under well conditions by area of the well annulus, where the associated petroleum gas presents. It ism suggested to solve the technical task under iteration method, for this on a first approximation h_dyn is assumed as maximum possible value at operated pump unit, namely depth of the pump unit. Under the second calculation cycle in P(h_dyn) calculations the dynamic level is used obtained during the first iteration cycle. The calculations are made until the dynamic level of the liquid is constant value.

EFFECT: increased accuracy of measurements of liquid level in the well; method is based on known Boyle-Mariotte law, when product of gas pressure and its volume if constant value at isothermal processes of gas pressure and volume change.

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Description

The claimed invention relates to the theory and practice of operating oil wells using deep pumping equipment and can be used in the oil industry.

In an oil well, the annulus between the lift pipe casing and the casing is usually filled with two media: gas (associated petroleum gas) and liquid with a certain dissolved gas content. The boundary between the media in the current well is called the dynamic fluid level. Its depth from the wellhead is determined with the necessary frequency to estimate the pressure at the intake of the downhole pump, to determine the volume of fluid in the well, and other purposes. Corrosion processes occur in liquid and gas media at different speeds, so it is important to know the average value of the dynamic level of a liquid.

The dynamic and static levels in oil wells are determined by echo sounding of the annulus, that is, the depth of the level is judged by the time the sound wave travels (p. 202 in the book: Vasilievsky V.N., Petrov A.I. Well Research Operator. Textbook for workers. - M .: Nedra, 1983. - 310 p.). The method is the main one in the oil industry, but has several drawbacks. First, with insufficient pressure in the well, to measure the level it is necessary to release annular gas into the atmosphere. Secondly, the accuracy of measurements depends on the component composition of associated petroleum gas in the well (APG) and, as a result, the speed of propagation of a sound wave in a changing medium.

A device for measuring the level of liquid in a well is known (RF patent for PM No. 101495, publ. 01.20.2011, bull. No. 2), in which the acoustic signal generator descends on a scraper wire and actually shows the moment of its entry under the liquid level. This method of determining the level requires depressurization of the annular space or the use of a small-sized lubricator (such devices are not manufactured in the factory in the Russian Federation).

Closest to the technical solution to the claimed invention is a method of measuring the liquid level in a well according to the patent of the Russian Federation for invention No. 2232267 (publ. July 10, 2004). According to this patent, a part of the associated petroleum gas from the annulus of the well is transferred to a tank of a given volume, and the liquid level is determined from the equation of state of the gas at a constant gas temperature.

According to the prototype, associated petroleum gas in the well is considered as gas with equal pressure at all points, and this pressure is fixed directly at the mouth - P_mouth. Meanwhile, the liquid level in the well may be at a depth of 1000 m or more. The APG pressure at a certain depth in the well P (h), including in the zone of the liquid level, in oilfield practice is estimated using the Laplace-Babinet formula [p. 134 at source: Korotaev Yu.P., Shirkovsky A.I. Gas production, transportation and underground storage. Textbook for high schools. - M .: Nedra, 1984. - 487 p.), And the gas pressure is estimated as the average value between P_mouth and P (h). According to the patent for invention No. 2232267, this fact is not taken into account, and in our opinion this leads to an increase in measurement error.

The second disadvantage of the prototype is that the stationary capacity of a given volume is a pressure vessel and is an additional source of danger in the well.

The technical task of the invention is the creation of a method for determining the level of fluid in the well based on changes and taking into account the parameters of associated petroleum gas in the well while increasing the accuracy of measurements and safety measures. It is proposed to use such a concept as the state of associated petroleum gas in the annulus as an informational component of a well according to the invention, and taking into account its real properties under well conditions.

The task of the invention is achieved by the fact that by the method of determining the dynamic liquid level in the well, which consists in the short-term release of a certain part of the associated petroleum gas from the annulus of the well, associated petroleum gas (APG) is released into the atmosphere through a gas meter, in a first approximation, for the value the dynamic fluid level h _dynes receiving depth of the submersible pump the well _pump arrangement h, are calculated by APG pressure zone dynamic level P (h _dynes), and ynamic liquid level is determined on the basis of the law of Boyle-Mariotte formula 1 (derivation of the formula 1 is shown separately at the end of the text), whereupon the calculation cycle is repeated with the already obtained by the formula 1 value h _dynes, the calculations carried out in the iteration operation several cycles until until the value of h _din becomes a constant value.

Where

h _din - dynamic fluid level in the well;

ΔV is the volume of APG released through the gas meter from the annular space reduced to the downhole conditions; determined by formula 2;

S is the average cross-sectional area of associated gas in the well;

P (h _dyn1,2 ) - gas pressure in the zone of the dynamic level, is determined by the formula 3;

P _mouth1 - gas pressure in the annulus at the wellhead until the release of gas of volume ΔV;

P _mouth2 - gas pressure in the annulus at the wellhead after the release of gas with a volume ΔV.

The volume of associated gas measured by a gas meter at the wellhead is brought into the well conditions according to the Mendeleev-Clapeyron equation by formula 2:

Where

V _account - the volume of APG on the gas meter;

P _atm is atmospheric pressure (0.1 MPa);

T _mouth - APG temperature at the wellhead;

T (h _din ) - APG temperature in the zone of the dynamic level of the well;

P (h _dyn1 ) - pressure in the zone of the dynamic level at P _set1 .

The pressure in the zone of the dynamic liquid level in oilfield practice is determined by the formula 3 (Laplace-Babinet formula):

Where

P _mouth - gas pressure in the annulus at the wellhead;

ρ _Rel - relative relative density of APG in the annulus, kg / m ³

T _cf , z _cf are the average values of the temperature and the RNG supercompressibility coefficient from the wellhead to h _dyne (T _{cf is} measured in degrees K, and the parameter z _cf is dimensionless).

In the formula 3 there is no information on the parameter h _dyn , and according to the invention, at the first stage of calculations, it is assumed that h _dyn = h _pump .

This calculation algorithm is laid down in the controller (program department) of the device according to the measurement of the dynamic level, a general view of which is shown in the drawing, where 1 is a submersible pump on a column of elevator pipes, 2 is an electrically adjustable valve of the annular space of the well, 3 is a manometer (pressure sensor), 4 - thermometer, 5 - gas meter, 6 - electrically adjustable valve at the gas outlet, 7 - gas scattering candle, 8 - device controller, 9 - thermal insulation of the measuring device.

The implementation of the method will consider an example.

An oil well has the following parameters:

- inner ⌀ casing string D = 197 mm;

- external ⌀ columns of elevator pipes d = 73 mm;

- the depth of the submersible pump h _us = 1000 m;

- relative air density of the gas ρ _rel = 0.95;

- APG super compressibility coefficient z = 0.91 (constant along the wellbore);

- the temperature of the fluids along the wellbore evenly rises from the wellhead to the submersible pump: from T _mouth = 15 ° C (288 K) to T _pump = 25 ° C (298 K).

Before gas production starts (valve 2 is open and valve 6 is closed)

P _set1 = 0.800 MPa. The electrically adjustable valve 6 at the command of controller 8 opens smoothly and the volume of associated petroleum gas is passed through the gas meter V _account = 0.50 m (at atmospheric pressure and temperature T _set = 15 ° C (288 K)). After this action, the APG pressure at the mouth decreases to P _mouth2 = 0.790 MPa. Associated petroleum gas is removed into the atmosphere through a dispersion candle 7. To ensure the isothermal process of gas exit, the device is covered with thermal insulation 9.

1. According to formula 3, the controller finds in the first iteration cycle the APG pressure at the maximum possible depth, that is, at h _dyn = h _nacoc , and the average gas temperature T _cf = (15 + 25) / 2 = 20 ° C = 293 K. the pressure is considered two times at the wellhead pressure P _set1 and P _set2 .

2. The volume of released gas V _account , measured by a gas meter at the wellhead, is given in the well conditions by the formula 2:

3. The dynamic fluid level in the well is found in the first stage of the iteration:

where S = π (D ² -d ² ) / 4 = 3.14 (0.197 ² -0.073 ² ) / 4 = 0.0264 m ² .

4. The obtained value of h _dyn = 183 m is used by the controller in the second cycle of calculations (paragraphs 1-3).

The gas temperature at a depth of 183 m is preliminarily determined by a linear relationship:

The average APG temperature T _cf = (15 + 16.8) / 2 = 15.9 ° С = 288.9 K.

For these values of h _dyn = 183 m and T _cf = 288.9 K, we find the APG pressure in the zone of the dynamic level two times: before and after gas release.

On the first point:

On the second point:

On the third point:

According to the calculations of the second cycle, h _dyn = 189.7 m.

5. The obtained value of h _dyn = 189.7 m is used by the controller in the third cycle of calculations (paragraphs 1-3).

The gas temperature is preliminarily determined at a depth of 189.7 m according to a linear relationship:

The average APG temperature T _cf = (15 + 16.9) / 2 = 15.95 ° С = 289 K.

On the first point:

On the second point:

On the third point:

According to the calculations of the third cycle, h _din = 189.9 m.

Subsequent calculations in the iteration mode show that the value of the dynamic level of the well is stabilized at 190 m.

In contrast to the prototype of the claimed invention takes into account the increase in APG pressure down the wellbore, and this increases the accuracy of measuring the liquid level. There is also no vessel operating under pressure, since part of the associated petroleum gas is discharged from the annulus of the well directly into the atmosphere without an intermediate vessel, and the recorded gas volume according to the invention is converted to downhole conditions in terms of parameters: pressure and temperature.

According to the invention, the expected technical result is achieved, and the method can be carried out by a device of both stationary and portable nature. Modern pressure gauges have a sensitivity of up to a thousandth of one atmosphere, therefore the volume of produced APG from the annulus is a small amount, therefore this process will take a short period of time.

The industrial implementation of the proposed method will allow a more accurate way to determine the dynamic fluid level in oil producing wells, which is especially relevant when approaching the dynamic fluid level to the reception of the downhole pump of the well.

The conclusion of formula 1:

We write down the Boyle-Mariotte equation:

where P ₁ is the average pressure of APG in the annulus before the release of gas with a volume ΔV; P ₁ = (P _{mouth 1} + P (h _dyn1 )) / 2;

P ₂ is the average APG pressure in the annulus after the release of gas with a volume ΔV; P ₂ = (P _mouth2 + P (h _dyn2 )) / 2.

It is also known that V ₂ = V ₁ + ΔV, therefore:

откуда выражаем V₂ и в последующем h_дин:

from where we express V ₂ and subsequently h _dyne :

Claims (1)

A method for determining the dynamic fluid level in a borehole, comprising the intermittent release of a certain part of associated gas from the shell side wellbore space in an isothermal mode, characterized in that the liquefied petroleum gas (APG) volume V _account is exhausted to atmosphere through a gas meter, for the calculation iteration method a first approximation of the dynamic fluid level value h _dynes take depth h submersible pump well _pump arrangement, are calculated by the formula 3, the pressure NG in the zone of the dynamic level P (h _dynes) released volume of gas V _expense of formula 2 is converted in the downhole conditions, and the dynamic fluid level is determined on the basis of the law of Boyle-Mariotte formula 1, followed by calculation loop is repeated with the already obtained by the formula 1 the value of h _dyn , the calculations are carried out in the iteration mode in several cycles until the value of h _dyn becomes a constant value:

Where
h _din - dynamic fluid level in the well;
ΔV is the volume of APG released through the gas meter from the annular space reduced to the downhole conditions; determined by formula 2;
S is the average cross-sectional area of associated gas in the well;
P (h _dyn1,2 ) - gas pressure in the zone of the dynamic level, is determined by the formula 3;
P _mouth1 - gas pressure in the annulus at the wellhead until the release of gas of volume ΔV;
P _mouth2 - gas pressure in the annulus at the wellhead after the release of gas with a volume of ΔV;
ΔV is the volume of associated gas measured by the gas meter at the wellhead, is brought into the well conditions according to the Mendeleev-Clapeyron equation by formula 2:

Where
V _account - the volume of APG on the gas meter;
P _atm is atmospheric pressure (0.1 MPa);
T _mouth - APG temperature at the wellhead;
Т (h _din ) - APG temperature in the zone of the dynamic level of the well;
P (h _dyn1 ) - pressure in the zone of the dynamic level at P _set1 ;
P (h _din ) - the pressure in the zone of the dynamic liquid level is determined by the formula 3 (Laplace-Babinet formula):

Where
P _mouth - gas pressure in the annulus at the wellhead;
ρ _rel - relative relative density of APG in the annulus, kg / m ³ ;
T _cf , z _cf are the average values of the temperature and the RNG supercompressibility coefficient from the wellhead to h _dyne (T _{cf is} measured in degrees K, and the parameter z _cf is dimensionless).

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