RU2386811C1 - Adaptive method of definition of residual (free) gas content at group gage units - Google Patents

Abstract

FIELD: oil-and-gas production.

SUBSTANCE: method is in alternate changing of mass and density, previously separated from gas liquid, gas mass and inclusion volume fraction of water and oil of each well, passed correspondingly through mass counters of liquid, gas and continuous drymetre during fixed time space, with recalculation into daily output agreeably by mass velocity crude oil (water-oil mixture), mass velocity of oil and volume flow of oil gas. Novelty of method is in definition of residue (free) gas content by formula

. On conditions that difference between

and

changes to the value

, where

correspondingly is calculated and medium measured densities of oil-water-gas mixture, W - average watering of water-oil mixture, measured by continuous drymetre, Δ ρ_abc - absolute accuracy of densimetre instrumentation. Further numerical value K_g can be used for updating of oil mass M_og in oil-water-gas mixture and volume V_g of residue free gas.

EFFECT: higher consumer properties in comparison to known already technical decisions.

2 cl, 1 dwg

Description

The invention relates to the field of measuring and controlling the flow rate of oil wells and can be used in information-measuring systems for production, transport, preparation of oil, gas and water.

There is a known [1, 2] method of direct weighing with a scale (for example, tensometric) of a measuring tank together with a liquid (oil-water mixture). At the same time, associated petroleum gas is preliminarily removed from the tank, and the controller gives the result of measuring the flow rate of the oil well connected to the measurement (from the group of wells) in units of mass - t / day, based on the result of weighing the measuring tank together with the liquid and according to the known time of filling the tank with liquid. Further, according to the known values of the densities of oil and water (the result of laboratory analysis) and the percentage of water in oil measured by a moisture meter, entered into the controller in the form of settings, the flow rates (in units of mass) of oil and water are determined. The daily gas volume is measured using volumetric (tachometric or vortex) gas meters [1-3].

The disadvantage of this method is the fact that after separation in the measuring tank with a liquid (oil + water), due to various circumstances (for example, poor-quality separation), there is always unaccounted-for free gas in the form of a finely dispersed structure, which occupies a well-defined volume [4] measuring calibrated capacity and which in this installation is perceived as a liquid. In this installation, this fact is not taken into account.

A known hydrostatic method [3] for measuring and controlling the flow rate of oil wells, based on the dependence of the hydrostatic pressure of a liquid column of height H on the density of the mixture

where g is the acceleration of gravity, m / s ² ; N - the height of the column of a mixture of liquids, m; ΔР - pressure drop of the column of a mixture of liquids, N / m ² ; ρ _cm is the density of the mixture of liquids, kg / m ³ .

From the formula (1) the density of the mixture ρ _{cm is} determined.

And the flow rates of wells by liquid (mixture) and gas are determined respectively by the formulas:

where S is the cross-sectional area of the tank, determined during the manufacture of the measuring tank; t _i is the filling time of the measuring capacitance; V _i = S · H is the calibrated volume of fluid.

The well production rate for oil and water is determined indirectly by the known densities of water and oil and the mixture density ρ _cm determined by formula (1).

With all the advantages of the hydrostatic method for measuring the flow rate of oil wells (in mass units), there is a significant drawback, which is as follows. Due to various circumstances (poor-quality separation, lack of time for full bubbling of gas bubbles) after separation, oil always contains finely divided free gas [4], which occupies a well-defined volume in the volume of a calibrated tank V _k . The share of free gas K in the volume V _k (unseparated) in the process of measuring the flow rate of oil wells will be perceived as a water-oil mixture, which, in turn, gives an additional error in determining the density of the mixture and, accordingly, the flow rate of the mixture, oil and gas.

Also known is the volumetric method for measuring the flow rate of oil wells, which is implemented by separation measuring devices, mainly automated group metering units [1].

Separating devices for measuring component flow rates (oil + gas + water) are the most common in the world, and they are implemented according to the classical schemes of three-phase or two-phase flow meters of oil wells.

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

- component flow meters with horizontal hydrocyclone separator;

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

In modern pressurized pressurized systems for collecting and transporting well products, automated separation and metering units of the automatic control system (type ZUG, Sputnik, AGZU, etc.) are used [5]. The principle of operation of such installations can be considered by the example of the operation of the Sputnik-A installation. Well production via flow lines is fed to a multi-way switch, each position of which corresponds to the supply of one well to measure production. The products of this well are sent to a horizontal type gas separator, consisting of upper and lower tanks. The products of the remaining wells, bypassing the gas separator, are sent to the collection manifold.

Oil flows from the upper tank of the gas separator to the lower, here its level rises, and at a certain position of the float, the shutter on the gas line of the gas separator closes. The pressure in the gas separator rises, and oil begins to flow through the flow meter into the collection manifold. After that, the liquid level in the lower tank decreases, the float lowers with the opening of the gas line damper, after which the process is repeated. The duration of this cycle depends on the flow rate of the well.

In the local automation unit (BMA), the accumulated volumes of liquid passing through the flow meter and the amount of gas passing through the gas flow meter installed on the flow gas line from the separator are recorded.

The next well is included in the measurement on command from the BMA using a hydraulic actuator.

Installations with a horizontal gas separator, similar to those described above, are used everywhere in the oil fields of the Russian Federation. The main disadvantage of the volumetric method for measuring the flow rate of wells, implemented using automated batch plants with horizontal gas separators, is that it does not make it possible to transfer (without appropriate technical and functional modernization) to mass measurements of well production. He also does not solve the problem of accounting for residual (free) gas.

Known technical solutions [6-8], which to one degree or another improve (structurally and functionally) the technical characteristics of horizontal type installations for measuring the flow rate of a group of oil wells, also do not solve these problems.

There is also a method [9] for determining the gas factor in group metering units, which consists in separating oil in a separator of a group metering unit, determining the instant flow rate of a well, measuring the time of pressure change to boundary values, measuring the boundary values of the separation pressure and determining the gas factor from the relation which includes the above parameters.

The disadvantage of this method is, firstly, that a volumetric method for measuring well production is used, and secondly, the problem of accounting for residual (free) gas is not solved.

There is one more question, which, in our opinion, is worth discussing here. The work [10] discusses the problems associated with the implementation of the national standard GOST R 8.615-2005. “Measurements of the amount of oil and gas extracted from the bowels of the earth.” In this work, it is noted that over the past 4 years, more than 700 plants with a horizontal gas separator were commissioned at the country's fields, half of which were commissioned by oil companies as uncertified as a means of measurement. Therefore, there is a rather voluminous task to modernize a huge number of metering installations in order to ensure the possibility of their certification in accordance with the requirements of this standard.

The closest technical solution (prototype) to the claimed method is a direct measurement method [11] for a certain period of time of the mass of crude oil (oil-water mixture), oil in the mixture and the volume of oil gas under standard conditions using a complex of technical means - measuring systems "KTS- IU ”(Technical conditions 4213-020-0013793-2006) as part of automated group metering units (AGZU). When measuring the production of a well, it is divided into crude oil and gas in the separator AGZU. According to the specified KTS-IU control algorithm, the water-oil mixture and gas accumulated in the separator of the AGZU are periodically or continuously (for gas) discharged into a common collector. At the AGZU output, when products are dumped into the collector, direct independent measurements of the following physical quantities are performed:

- mass and density of crude oil - using mass Coriolis type counters;

- masses of gas - using meters of the same type;

- crude oil temperature - using temperature converters ;.

- volume fraction of water and oil in the oil-water mixture - using a flow hydrometer of crude oil;

- the time of measuring the production of the well and the operating time of the well per month - by the timer of the information processing unit.

Additionally, laboratory standardized methods measure the density of formation water and gas under standard conditions, the values of which are entered into the information processing unit (BOI) KTS-IU as conditionally constant values for a given well.

Based on the results of direct measurements of physical quantities, automatically using BOI KTS-IU the following calculations are performed:

- the mass of oil in the oil-water mixture (t);

- the volume of oil gas in standard conditions (nm ³ );

- mass flow of crude oil (t / day);

- mass oil consumption (t / day);

- volumetric flow rate of oil gas (nm ³ / day).

This measurement method is more than known, free from the above disadvantages and meets the requirements of the national standard GOST R 8.615-2005. “Measurements of the amount of oil and gas extracted from the bowels of the earth.”

A disadvantage of the known technical solution of the method (prototype) for measuring oil production rate is also an error in determining the production rate of oil wells in the presence of uncontrolled free (unseparated) gas in the measuring tank. As the results of field tests show, the volume of free associated gas can reach (1-10)% of the volume V _{cm of the} measuring capacity.

Thus, the purpose of the claimed object (otherwise, the required technical result) is to provide the well-known technical solution of higher consumer properties by introducing into the process of determining the residual (free) gas content with the ability to correct the result of measuring the flow rate of the well for oil.

The required technical result is achieved by the fact that in the inventive method, according to the prototype method, which consists in alternately, according to a given program, measuring the mass and density of the liquid preliminarily separated from the gas, the mass of the gas and the volume fraction of water and oil of each well that have passed through mass liquid meters, respectively , gas and flow hygrometer for a fixed period of time, with recalculation into daily output, respectively, according to the mass flow rate of crude oil (oil-water mixture), mass flow rate oil and the volumetric flow rate of oil gas, the calculated value of the density of crude oil is calculated by the formula

,

,

where ρ _n and ρ _in are the densities of oil and water, respectively, measured by laboratory methods for each well;

W is the average water content of the oil-water mixture, determined by a number of instantaneous values of Wi measured by a flow hydrometer.

, при этом, если разность

и

изменяется на величину Δρ>Δρ_абс (где Δ ρ_абс - абсолютная погрешность измерения плотномера), то остаточное газосодержание сырой нефти определяют по формулеBased on a number of instantaneous values of the density of crude oil for each connected to measure the oil well, the average density value is determined,

Moreover, if the difference

and

changes by Δρ> Δρ _abs (where Δ ρ _abs is the absolute measurement error of the density meter), then the residual gas content of crude oil is determined by the formula

and the numerical value of K _g is subsequently used to adjust the mass of oil M _ng in the oil-gas mixture and the volume V _g in the mixture according to the formulas:

;

;

The required technical result is ensured by the presence of a combination of essential features (characterizing the proposed adaptive method for determining the residual (free) gas content in group metering units) of the above distinguishing features, and the non-detection of equivalent technical solutions with the same properties and undoubted industrial applicability in public sources of patent and technical information implies compliance of the claimed object with the criteria of the invention.

The drawing shows a schematic diagram of a device that implements an adaptive method for determining the residual (free) gas content in group metering installations.

The device (see drawing) consists of a horizontal hydrocyclone separator 1 with a lateral inlet pipe 2 and gas and liquid discharge pipes 3 and 4, respectively. It contains a controller 5 with a multi-channel input 6 and with control outputs 7 and 8. The device contains a float 9 of the level regulator, a gas line damper 10, pipelines 11, 12 and 13 for supplying to the product separator, gas outlet and liquid drain, respectively, electrically controlled by the controller 5 switch of wells 14 and a three-way valve 15, non-return valve 16, pre-assembled manifold 17, as well as a temperature sensor 18, an overpressure sensor in the separator, a mass meter and a crude oil density meter 20, a moisture meter 21, a mass gas meter 22. The information outputs of the sensors are connected to the multi-channel input 6 of the controller 5.

The device operates as follows. By means of the controller 5, through the switch of wells 12, through the switch of the wells 12, oil wells are alternately connected to measure the flow rate.

The production of one of the wells through the pipe 11 enters through the pipe 2 into the separator 1, where the separation of liquid and associated gas. The products of the remaining wells, bypassing the gas separator, are sent to the collector 17.

A three-way electrically operated valve 13 is in a position in which associated gas under excess pressure in the separator 1 is sent through a mass gas meter 22 to the collection manifold 17, and the liquid fills the lower (storage) cavity of the separation tank. The float 9 in the storage tank through a system of levers when it reaches the upper limit level of the liquid closes the valve on the gas line. The pressure in the storage tank rises, and crude oil (oil-water mixture) through the discharge pipe 4, the mass meter and densitometer 20, a moisture meter 21, a three-way valve 15 and a check valve 16 begins to flow into the collection manifold 17. After that, the liquid level in the storage tank decreases, the float 9 lowers and opens the shutter 10, after which the process is repeated. Then, the controller 5 sends a command to the switch wells 12 for connection to the measurement of the next well.

When the product is discharged into the collector (respectively, according to crude oil and gas), information about the mass and density of crude oil, the mass of gas, the temperature of crude oil, the volume fraction of water and oil, and the time of measuring the production of the well is received into controller 5. On the basis of these results obtained by direct measurements of physical quantities, and also based on input to the controller (for each well), so-called semi-fixed quantities of oil density ρ _n and the water density ρ _{in the} measured laboratory method, the controller automatically performs the following calculation:

- the mass of oil in the oil-water mixture (t);

- the volume of oil gas in standard conditions (nm ³ );

- mass flow of crude oil (t / day);

- mass oil consumption (t / day);

- volumetric flow rate of oil gas (nm ³ / day).

In reality, as we showed earlier, a part of the storage tank volume V _cm is occupied by free (unseparated) gas V _g , which, firstly, needs to be measured (determined), and secondly, to use its numerical value to adjust the mass of oil in the oil-gas mixture . With the appearance of a volume of V _g in the mixture, the volume of oil V _H in the mixture decreases, therefore, we can write

where K _g is the fraction of the volume of free gas in oil (gas content).

In [12], when analyzing the effect of free gas on the metrological characteristics of volumetric-weight (mass) flow meters, the following expression was obtained

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

W is the water content of the mixture;

K is the fraction of the volume of free gas.

Let us analyze expression (5) from the point of view of its applicability to justify our adaptive method for determining the residual (free) gas content in group metering units. The numerator of expression (5) is the calculated value of the density of the oil-water mixture (naturally, excluding free gas). For clarity of the further discussion, we write the numerator of formula (5) in the form:

(6) является некоторой средней оценкой плотности смеси, поскольку, в свою очередь, аргументы функции (5) получены статистическим усреднением лабораторных измерений значений (ρ_н, ρ_в) и измеряемых влагомером значений W_i. Note that the calculated value

(6) is some average estimate of the density of the mixture, since, in turn, the arguments of function (5) were obtained by statistical averaging of laboratory measurements of the values (ρ _n , ρ _c ) and the values of W _i measured by the hydrometer _.

Formula (5) was obtained [12] under the assumption that the presence of a certain fraction of free gas in an oil-gas mixture has practically no effect on its mass, measured by a mass, for example, Coriolis flowmeter, but affects the density of an oil-gas mixture, measured by the same device, but via the channel " measuring the density of the mixture. " It is this density that the Coriolis flowmeter measures. Moving from instantaneous measurements of the density of the mixture to its average estimates, and taking into account formula (6), formula (5) is transformed to:

From the formula (7) follows the final expression for determining the value of K _g - volume fraction of free gas (gas content):

- измеряемые величины, а

- рассчитываемая величина при известных ρ_н, ρ_в и W.where the parameters W and

- measured values, and

- the calculated value for known ρ _n, ρ _in and W.

Thus, for each well connected for measurement, the controller (5) performs the following operations:

;- based on the measured values (average estimates) ρ _n, ρ _in and W calculates the density

;

- on the basis of a number of instantaneous values of the density of crude oil determines the average value of the density

и

изменяется на величину Δρ>Δρ_а6с, где Δρ_абс - абсолютная погрешность измерения плотномера, то остаточное газосодержание сырой нефти определяют по формуле (8).- if the difference

and

changes by Δρ> Δρ _a6s , where Δρ _abs is the absolute error of the density meter, the residual gas content of crude oil is determined by the formula (8).

Subsequently, the numerical value of K _{g is} used to adjust the mass of oil M _ng in the oil-gas mixture and the volume V _{g of} free (unseparated) gas in the mixture by substituting, for example, the K _g value in the formulas given in [12, p. 18 (26) and p.16 (4)]:

or similar, depending, in each case, on the implemented algorithms taking into account pressure, temperature, etc.

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

Information sources

1. NTZ “Automation, telemechanization and communication in the oil industry. M .: VNIIOENG OJSC, 2003. - No. 4 - p. 7-18.

2. Installation mass measuring transportable "ASMA-T-03-180-300A", 40100.00.00.000TO. Interregional Joint-Stock Company Nefteavtomatika (Ufa), Serafimovsky Experimental Plant of Automation and Telemechanics, 2000.

3. Abramov G.S., Barychev A.V., Zimin M.I. Practical flow measurement in industry. - M.: VNIIOENG. - 2000 .-- 472 p. (80-83).

4. Magazine "World of measurements". - M. 2006 - No. 11. - p. 92.

5. Handbook of oil production / VVAndreev, K.R. Urazakov, V.U. Dalimov and others; Ed. K.R. Urazakova. - M.: Nedra-Business Center LLC, 2000. - 374 p. (P. 259-263).

6. USSR Copyright Certificate No. 1043293, cl. ЕВВ 43/00.

7. Copyright certificate of the USSR No. 1165777, cl. ЕВВ 47/10.

8. RF, description of the invention to patent No. 2136881, C1, ЕВВ 47/10, 10.28.97.

9. NTZ “Automation, telemechanization and communication in the oil industry. M .: VNIIOENG OJSC, 2007. - No. 9 - p.2-6.

10. Copyright certificate of the USSR No. 901486, cl. ЕВВ 47/10.

11. The ICG. “Methodology for measuring the amount of crude oil and oil gas in a separate well using the measuring system" KTS-IU ", 2000.

12. NTZ “Automation, telemechanization and communication in the oil industry. M .: VNIIOENG OJSC, 2006. - No. 11 - p.2-19.

Claims (2)

1. An adaptive method for determining the residual (free) gas content in group metering plants, which consists in alternately, according to a given program, measuring the mass and density previously separated from the gas fluid, the mass of gas and the volume fraction of water and oil of each well, passed through mass meters, respectively liquids, gas and flow hydrometer for a fixed period of time, with conversion to daily output, respectively, according to the mass flow rate of crude oil (oil-water mixture), mass course of oil and gas volumetric flow rate, characterized in that the calculated estimated density value of the crude oil by the formula

where ρ _n and ρ _in are the densities of oil and water, respectively, measured by laboratory methods for each well;
W is the average water content of the oil-water mixture, determined from a number of instantaneous values of W _i measured by the flow hydrometer,
on the basis of a series of instantaneous values of the density of crude oil for each connected to measure the oil well, the average density value is determined

in this case, if the difference

and

changes by Δρ≥Δρ _abs (where Δ ρ _abs is the absolute measurement error of the density meter), then the residual gas content of crude oil is determined by the formula

2. The adaptive method for determining the residual (free) gas content in group metering plants according to claim 1, characterized in that the numerical value of K _g can be used to adjust the mass of oil M _ng in the oil-gas mixture and the volume V _{g of} residual free gas in the mixture, respectively formulas: