JP6952952B2 - Multiphase flow measuring device, multiphase flow measuring method and program - Google Patents

Description

The present invention relates to a technique for measuring the volumetric flow rate of each component of a multiphase flow using the measured value of a Koriori flow meter.

The output in oil-producing wells is generally a mixture of gas, oil and accompanying water and is produced as a multiphase flow. Here, it is assumed that the liquid phase of oil and accompanying water is the main, and a mixed phase flow in which gas is occasionally mixed as the gas phase is assumed. It is assumed that the solid phase is not included.

For multiphase flows produced from oil production wells, it is important to understand the volumetric flow rate of each component. For example, by knowing the occupancy rate of accompanying water and gas in the product, it is possible to evaluate the economic efficiency such as the return on investment of the well and to diagnose the degree of deterioration of the well. In addition, by grasping the approximate tendency of the volumetric flow rate of each component during production, it is possible to monitor gas contamination that affects facility equipment and perform sampling control according to the volume of accompanying water and gas. become. In particular, in such a case, real-time performance is required rather than highly accurate measured values.

Special Table 2002-525623

Conventionally, in order to grasp the volumetric flow rate of each component of a multiphase flow, for example, a separation device such as a main separation device or a test separation device is used to separate gas, oil, and accompanying water, and then each flow meter is used. The volumetric flow rate is measured for each component. However, by using the separation device, the equipment is large-scale and there is no real-time performance, and when it is integrated into the main separation device, it becomes difficult to grasp the components of each well.

It is also practiced to measure the volumetric flow rate for each component using a multiphase flow meter that combines a plurality of sensors, but the configuration is complicated and the device becomes expensive.

Therefore, an object of the present invention is to grasp the volumetric flow rate of each component of the multiphase flow in real time with a simple configuration.

In order to solve the above problems, the mixed phase flow measuring device according to one aspect of the present invention is at least a mass flow rate measurement value and a density from a Koriori flow meter that measures a fluid to be measured including oil and accompanying water from an oil production well. A gas volume flow rate based on a measurement value acquisition unit that acquires a measured value and a temperature measurement value of a temperature sensor that measures the temperature of the fluid to be measured, and a mass flow rate measurement value and a density measurement value from the measurement value acquisition unit. And a volume flow rate calculation unit that calculates each volume flow rate of the oil and the accompanying water based on the liquid phase volume flow rate and the temperature measurement value acquired by the measurement value acquisition unit. Is characterized by the provision of.
Here, an excitation signal is acquired from the Koriori flow meter, and a gas mixing detection unit for detecting that gas is mixed in the measurement target fluid is provided based on the excitation signal, and the volume flow rate calculation unit is the gas. When the contamination detection unit is detected, the gas volume flow rate and the liquid phase volume flow rate can be calculated.
At this time, the volumetric flow rate calculation unit can calculate each volumetric flow rate of the petroleum and the accompanying water based on the temperature measurement value when the gas mixing detection unit is not detected.
Further, based on the standard state input unit that accepts the input of the standard state oil density and the standard state accompanying water density, the standard state oil density, the standard state accompanying water density, and the temperature measurement value input to the standard state input unit. A concomitant water ratio calculation unit for calculating the ratio of the concomitant water in the fluid to be measured is provided, and the volume flow rate calculation unit is calculated by the liquid phase volume flow rate and the concomitant water ratio calculation unit. The volumetric flow rates of the oil and the accompanying water may be calculated based on the proportion of the accompanying water.
In order to solve the above problems, the mixed phase flow measurement method according to one aspect of the present invention is at least a mass flow rate measurement value and a density from a Koriori flow meter that measures a fluid to be measured including oil and accompanying water from an oil production well. The step of inputting the measured value to the measured value acquisition unit, the step of inputting the temperature measured value of the temperature sensor for measuring the temperature of the measurement target fluid into the measured value acquisition unit, the mass flow rate measured value, and the density measured value. Based on the step of calculating the gas volume flow rate and the liquid phase volume flow rate by the volume flow rate calculation unit based on the above, and the volume flow rate of each of the oil and the accompanying water based on the liquid phase volume flow rate and the temperature measurement value, the volume flow rate. It is characterized by providing a step for calculation by the calculation unit.
In order to solve the above problems, the program according to one aspect of the present invention is used in a computer, and at least a mass flow rate measurement value from a Koriori flow meter that measures a fluid to be measured including oil and accompanying water from an oil production well. And the step of inputting the density measurement value, the step of inputting the temperature measurement value of the temperature sensor for measuring the temperature of the measurement target fluid, and the gas volume flow rate and the liquid phase based on the mass flow rate measurement value and the density measurement value. It is characterized in that a step of calculating the volume flow rate and a step of calculating each volume flow rate of the oil and the accompanying water based on the liquid phase volume flow rate and the temperature measurement value are provided.

According to the present invention, the volumetric flow rate of each component of the multiphase flow can be grasped in real time with a simple configuration.

It is a block diagram which shows the structure of the multiphase flow measurement system including the multiphase flow measurement apparatus which concerns on this embodiment. It is a block diagram which shows the functional structure of a Coriolis flow meter and a multiphase flow measuring apparatus. It is a figure explaining the change of the drive current value and the density measurement value at the time of mixing with gas. It is a figure explaining the generation method of the reference density value. It is a flowchart explaining operation of a multiphase flow measuring apparatus.

Embodiments of the present invention will be described with reference to the drawings. FIG. 1 is a block diagram showing a configuration of a multiphase flow measuring system 10 including a multiphase flow measuring device 100 according to the present embodiment.

The multiphase flow measurement system 10 is a system for measuring the volumetric flow rate of each component of the multiphase flow, and includes a multiphase flow measuring device 100, a colioli flow meter 200, and a pressure transmitter 300.

After the pressure of the product from the production well is measured by the pressure transmitter 300 via the pipe, the mass flow rate and the like are measured by the Koriori flow meter 200 and guided to the main separation device. The multiphase flow measuring device 100 acquires the measured values of the pressure transmitter 300 and the Koriori flow meter 200, and calculates the volumetric flow rate for each component of the product.

FIG. 2 is a block diagram showing a functional configuration of the multiphase flow measuring device 100 and the Coriolis flow meter 200.

The Coriolis flowmeter 200 has a detection unit 210 and a conversion unit 220. The Koriori flow meter 200 is a flow meter that utilizes the Koriori force that acts when the measuring tube through which the fluid to be measured flows is vibrated up and down with both ends as fulcrums, and the phase difference between the upstream vibration and the downstream vibration of the measuring tube. And the vibration frequency, the mass flow rate of the fluid to be measured is measured.

The detection unit 210 includes a measuring tube 211 through which the fluid to be measured flows, a vibrating device 212 that mechanically vibrates the measuring tube 211 up and down, an upstream sensor 213 that detects the vibration displacement on the upstream side of the measuring tube 211, and a vibration displacement on the downstream side. It is provided with a downstream sensor 214 for detecting the above and a temperature sensor 215 for measuring the temperature used for temperature correction and the like.

Further, the conversion unit 220 includes an excitation circuit 221 that generates and outputs a drive current that is an excitation signal for driving the exciter 212, a calculation unit 222 that calculates a mass flow rate, and an output unit 225 that outputs measurement results and the like. It has.

Since the Koriori flow meter 200 vibrates the measuring tube 211 at a natural frequency, the density of the fluid to be measured can also be measured by measuring the vibration frequency of the measuring tube 211. Therefore, the calculation unit 222 calculates the mass flow rate of the fluid to be measured based on the phase difference, vibration frequency, temperature, etc., and the density calculation unit 223, which calculates the density of the fluid to be measured based on the vibration frequency, temperature, and the like. It is provided with a mass flow rate calculation unit 224. The calculation logic of the density calculation unit 223 and the mass flow rate calculation unit 224 can be the same as in the conventional case.

The output unit 225 includes a density measurement value calculated by the density calculation unit 223, a mass flow rate measurement value calculated by the mass flow rate calculation unit 224, a drive current value generated by the excitation circuit 221 as an excitation signal, and a temperature measurement measured by the temperature sensor 215. The value is output to the mixed phase flow measuring device 100. The vibration frequency and amplitude of the measuring tube 211 may be output to the multiphase flow measuring device 100. A temperature transmitter (temperature sensor) may be separately provided, and the temperature measurement value of the fluid to be measured measured by the temperature transmitter may be output to the multiphase flow measuring device 100. That is, the temperature sensor may be inside or outside the Coriolis flowmeter, and the portion excluding the temperature sensor can be said to be the Coriolis flowmeter.

The pressure transmitter 300 measures the pressure of the fluid to be measured and outputs the measured pressure value to the multiphase flow measuring device 100. The pressure value from the pressure transmitter 300 may be input to the conversion unit 220 of the Coriolis flow meter 200, and the value may be sent from the output unit 225 to the measurement value acquisition unit 110. In this case, the pressure value can also be used for the pressure correction calculation of the Coriolis flow meter 200. The measured pressure value is used for correcting the density, but since this effect is generally very small, the pressure transmitter 300 may be omitted.

The multiphase flow measuring device 100 includes a measured value acquisition unit 110, a standard state density input unit 120, a gas mixing detection unit 130, a reference density value generation unit 140, a gas porosity calculation unit 150, an accompanying water ratio calculation unit 160, and a volume flow rate calculation. The unit 170 is provided. These blocks can be constructed, for example, by executing a predetermined operation program by an arithmetic processing unit including a microcomputer, an input / output interface, and the like.

The multiphase flow measuring device 100 can be configured as a higher-level device of the Coriolis flow meter 200 such as a PLC and a control controller, for example. However, the present invention is not limited to this, and for example, it may be configured as an independent device, or a part or all of the functional blocks may be configured in the conversion unit 220 of the Coriolis flow meter 200. When configured as an independent device, it may be a single device or the functional blocks may be distributed among a plurality of devices.

The measurement value acquisition unit 110 acquires the density measurement value, the mass flow rate measurement value, the drive current value, and the temperature measurement value from the output unit 225 of the Koriori flow meter 200, and acquires the pressure measurement value from the pressure transmitter 300. These values are acquired as time-series data at predetermined time intervals. The measurement value acquisition unit 110 stores at least the density measurement value among the acquired measurement values as historical data for a predetermined period.

The standard state density input unit 120 receives and stores the input of the standard state densities of the oil and the accompanying water constituting the fluid to be measured. Prior to the measurement of the multiphase flow volume flow rate, the operator conducts a sample survey of the fluid to be measured and measures the standard state oil density and the standard state accompanying water density. Then, the obtained standard state oil density and the standard state accompanying water density are input to the standard state density input unit 120. Instead of inputting the density in the standard state, the density in the measured state may be subjected to temperature and pressure correction or the like to be converted to the density in the standard state.

The gas mixing detection unit 130 detects that gas is mixed in the fluid to be measured, which is mainly the liquid phase of oil and accompanying water. Here, as shown in FIG. 3A, when gas is mixed in the liquid phase, the drive current value becomes large. This is because the amplitude of the measuring tube 211 is reduced due to gas mixing, whereas the excitation circuit 221 increases the drive current in an attempt to maintain the amplitude.

Therefore, as shown in FIG. 3B, the gas mixing detection unit 130 can determine that gas has been mixed in the fluid to be measured when the drive current value exceeds a predetermined threshold value. The predetermined threshold value can be set experimentally, theoretically, or the like. Further, it may be a fixed value or a variable value according to a drive current value or the like when gas is not contained. Not limited to the drive current, gas mixing may be determined based on the vibration frequency and amplitude of the measuring tube 211. In this case, the excitation signal includes the vibration frequency and amplitude information and is output to the output unit 225.

Further, as shown in FIG. 3A, it is known that when gas is mixed in the fluid to be measured, the measurement sensitivity is lowered and the density measurement value calculated by the density calculation unit 223 of the Coriolis flow meter 200 is lowered. (For example, Japanese Patent No. 3547708). For this reason, it is not preferable to perform the measurement using the density measurement value calculated at the time of gas mixing as it is, and the conventional Coriolis flow meter causes a measurement error.

On the other hand, in the mixed phase flow measuring device 100 of the present embodiment, the reference density value generation unit 140 generates a reference density value based on the historical data of the density measurement value, and when gas contamination is detected, the reference density value is generated. The reference density value is used instead of the density measurement value for measurement. The reference density value is based on the assumption that the component ratio up to that point is maintained for the liquid phase even when gas is mixed.

A method of generating a reference density value will be described with reference to FIG. As shown again in FIG. 4A, when gas is mixed in the liquid phase, the measured density value decreases. As shown in FIG. 4B, for example, the reference density value used for the measurement during this period can be the average value of the density measurement values in the period before the gas contamination is detected. Here, a predetermined period from the time when the gas mixture is detected to the time Tr before is defined as the average calculation period, and the average value of the density measurement values in the average calculation period is used as the reference density value.

The average calculation period and time Tr can be appropriately set according to the situation and the like, but the average calculation period does not include the gas mixing period. The gas mixing period refers to a period in which gas is detected by the gas mixing detection unit 130. In addition, it is desirable to avoid it because the measured density value may be affected immediately before the detection of gas contamination.

The average value may be calculated retroactively from the recorded historical data at the time of gas contamination detection, or may be calculated sequentially like a moving average, and the corresponding average value may be read out at the time of gas contamination detection. Further, in the Coriolis flow meter 200, the density measurement value may be given a status such as good, defective, or unclear depending on the situation at the time of measurement, but the average value is calculated by the average calculation period. It is desirable to use a density measurement with a good status inside.

Further, for example, as shown in FIG. 4C, the latest density measurement value may be used as the reference density value among the density measurement values having a good status before the time Tr from the time when the gas mixture is detected. ..

The reference density value is not limited to the above example as long as it is a value obtained by using the history of density measurement values. For example, the median value, mode value, etc. of the trend data created from the history may be used as the reference density value. When gas contamination is detected multiple times, it is desirable to update the reference density value each time.

The gas porosity calculation unit 150 calculates the ratio of gas to the volume of the fluid at the time of detecting gas contamination. Generally, the gas porosity GVF in a mixture of oil and gas is
Gas porosity GVF = 1- (measured density / predicted oil density)
Can be calculated by (US Pat. No. 9500576). Here, the predicted oil density value is a value obtained by correcting the standard state oil density with the temperature value and the pressure value at that time.

However, the predicted oil density cannot be calculated in the mixed state of oil and accompanying water. Therefore, in this embodiment,
Gas porosity GVF = 1- (measured density value / reference density value)
To calculate the gas porosity. This is because it can be predicted that the tendency of the density measurement value at the time of gas mixing is consistent with the amount of gas mixed, and it is considered that the density of the liquid phase does not change rapidly before and after the gas mixing. Is.

The accompanying water ratio calculation unit 160 calculates the ratio of the accompanying water in the liquid phase. Generally, the associated water ratio (Water Cut) is
Accompanying water ratio = (Liquid phase density-Oil density predicted value) / (Accompanied water density predicted value-Oil density predicted value)
It can be calculated by (ERCB Directive017 Chapter 14-12 May 15, 2013).

The accompanying water ratio calculation unit 160 calculates the accompanying water ratio by using the measured density value as the liquidus density when the gas contamination is not detected and using the reference density value as the liquidus density when the gas contamination is detected. That is, when gas contamination is not detected,
Accompanying water ratio = (measured density value-predicted oil density) / (predicted associated water density-predicted oil density)
When gas contamination is detected,
Accompanying water ratio = (reference density value-oil density predicted value) / (accompanying water density predicted value-oil density predicted value)
And.

The oil density predicted value and the accompanying water density predicted value are the standard state oil density and the standard state accompanying water density received by the standard state density input unit 120, and the temperature measured value and the pressure measured value by a known method. It can be calculated by correcting with.

In addition, as with the reference density value, the reference accompanying water ratio is generated based on the historical data of the accompanying water ratio when gas contamination is not detected, and when gas contamination is detected, the reference accompanying water ratio is used. You may.

The volume flow rate calculation unit 170 calculates the oil volume flow rate, the accompanying water volume flow rate, and the gas volume flow rate. Further, the volume flow rate calculation unit 170 can calculate the volume of each phase by integrating each volume flow rate.

In the calculation of the volumetric flow rate, first, the volumetric flow rate of the fluid to be measured is calculated from the mass flow rate measurement value and the density measurement value of the Koriori flow meter 200 regardless of whether gas mixing is detected or not. That is,
Calculate the volume flow rate of the fluid to be measured = mass flow rate measurement value / density measurement value.

Then, when gas contamination is not detected, the fluid to be measured is composed of oil and accompanying water, so the oil volume flow rate and the accompanying water volume flow rate are calculated based on the volume flow rate of the measurement target fluid and the accompanying water ratio. .. That is,
Accompanying water volume flow rate = Measurement target fluid volume flow rate x Accompanying water ratio Oil volume flow rate = Measurement target fluid volume flow rate-Accompanied water volume flow rate.

At the time of detecting gas contamination, the fluid to be measured is composed of a gas and a mixed liquid phase of oil and accompanying water. Calculate the liquid phase volume flow rate. That is,
Gas volume flow rate = measurement target fluid volume flow rate x gas porosity
Liquid phase volume flow rate = Measured fluid volume flow rate-Gas volume flow rate is obtained.

Then, the oil volume flow rate and the accompanying water volume flow rate are calculated based on the liquid phase volume flow rate and the accompanying water volume ratio. That is,
Accompanying water volume flow rate = Liquid phase volume flow rate x Accompanied water ratio Oil volume flow rate = Liquid phase volume flow rate-Accompanying water volume flow rate.

Next, the operation of the multiphase flow measuring device 100 having the above configuration will be described with reference to the flowchart of FIG. However, the processing order is an example, and the measurement value acquisition order, production procedure, etc. can be changed as appropriate.

First, prior to the measurement of the multiphase flow volume flow rate, the standard state density input unit 120 receives the input of the accompanying water density and the oil density in the standard state from the operator, and stores them as the standard state accompanying water density and the standard state oil density. (S101).

The measurement of the multiphase flow volume flow rate is started, and the measurement value acquisition unit 110 acquires the density measurement value, the mass flow rate measurement value, the drive current value, and the temperature measurement value from the output unit 225 of the Koriori flow meter 200 (S102). At least the measured density value is recorded as a history of time-series values in a predetermined section (S103).
Further, the pressure measurement value is acquired from the pressure transmitter 300 (S104).

From the acquired mass flow rate measurement value and density measurement value, the volume flow rate calculation unit 170 calculates the volume flow rate of the fluid to be measured (S105). Further, based on the acquired temperature measurement value and pressure measurement value, the accompanying water ratio calculation unit 160 corrects the standard state oil density and the standard state accompanying water density, and the associated water density predicted value and oil at the time of measurement. The predicted density value is calculated (S106).

Based on the acquired drive current value, the gas mixing detection unit 130 determines whether or not gas is mixed in the fluid to be measured (S107). That is, if the drive current value is equal to or less than the threshold value Is, it is determined that gas is not mixed, and if the drive current value exceeds the threshold value Is, it is determined that gas is mixed.

When it is determined that gas is not mixed (S107: Yes), the accompanying water ratio calculation unit 160 calculates the accompanying water ratio based on the associated water density predicted value, the oil density predicted value, and the density measurement value (S108). Then, the volume flow rate calculation unit 170 calculates the accompanying water volume flow rate and the oil volume flow rate from the fluid volume flow rate and the accompanying water ratio (S109).

On the other hand, when it is determined that gas is mixed (S107: No), the reference density value generation unit 140 generates a reference density value from the history of the density measurement values (S110). As described above, the reference density values may be generated sequentially. In this case, the generated reference density value is read out.

Then, the gas void ratio calculation unit 150 calculates the gas void ratio, which is the ratio of the gas to the volume of the fluid, from the density measurement value and the reference density value (S111). From the calculated gas void ratio and fluid volume flow rate, the volume flow rate calculation unit 170 calculates the gas volume flow rate and the liquid phase volume flow rate, which is a mixture of oil and accompanying water (S112).

Further, the accompanying water ratio calculation unit 160 calculates the accompanying water ratio based on the associated water density predicted value, the oil density predicted value, and the reference density value (S113). Then, the volume flow rate calculation unit 170 calculates the accompanying water volume flow rate and the oil volume flow rate from the liquid phase volume flow rate and the accompanying water ratio (S114).

In both the gas non-mixing determination and the gas mixing determination determination, the volume flow rate calculation unit 170 integrates the calculated volume flow rates of each component in a predetermined closing period to calculate the volume of each component (S115). The calculated volume flow rate for each component and the volume for each component can be displayed on a display device, output as a signal, recorded, or the like. Then, each of the following measured values is acquired (S102), and the subsequent processing is repeated until the measurement is completed.

As described above, the multiphase flow measuring device 100 of the present embodiment detects gas mixing based on the drive current value of the Koriori flow meter 200, and each measured value of the Koriori flow meter 200 and the output of the pressure transmitter 300. Based on the value, the volumetric flow rate for each component of the multiphase flow is calculated by a simple calculation. Therefore, the volumetric flow rate for each component of the multiphase flow can be grasped in real time with a simple configuration.

10 ... Multiphase flow measurement system 100 ... Multiphase flow measurement device 110 ... Measurement value acquisition unit 120 ... Standard state density input unit 130 ... Gas mixture detection unit 140 ... Reference density value generation unit 150 ... Gas void ratio calculation unit 160 ... Accompanying water ratio Calculation unit 170 ... Volumetric flow rate calculation unit 200 ... Koriori flow meter 210 ... Detection unit 211 ... Measuring tube 212 ... Exciter 213 ... Upstream side sensor 214 ... Downstream side sensor 215 ... Temperature sensor 220 ... Conversion unit 221 ... Excitation circuit 222 ... Calculation unit 223 ... Density calculation unit 224 ... Mass flow rate calculation unit 225 ... Output unit 300 ... Pressure transmitter

Claims (6)

Obtain at least the mass flow rate measurement value and density measurement value from the Koriori flow meter that measures the measurement target fluid including oil and accompanying water from the oil production well, and the temperature measurement value of the temperature sensor that measures the temperature of the measurement target fluid. Measurement value acquisition unit and
The gas volume flow rate and the liquid phase volume flow rate are calculated based on the mass flow rate measurement value and the density measurement value from the measured value acquisition unit, and the liquid phase volume flow rate and the temperature measurement acquired by the measurement value acquisition unit are performed. A mixed phase flow measuring device provided with a volume flow rate calculation unit that calculates each volume flow rate of the oil and the accompanying water based on the value. An excitation signal is acquired from the Coriolis flow meter, and a gas mixing detection unit for detecting that gas is mixed in the fluid to be measured is provided based on the excitation signal.
The mixed phase flow measuring device according to claim 1, wherein the volume flow rate calculation unit calculates a gas volume flow rate and a liquid phase volume flow rate when the gas mixing detection unit is detected. The mixed phase according to claim 2, wherein the volumetric flow rate calculation unit calculates each volumetric flow rate of the petroleum and the accompanying water based on the temperature measurement value when the gas mixing detection unit is not detected. Flow measuring device. Standard state input unit that accepts input of standard state oil density and standard state accompanying water density,
An accompanying water ratio calculation unit that calculates the ratio of the accompanying water to the fluid to be measured based on the standard state oil density, the standard state accompanying water density, and the temperature measurement value input to the standard state input unit. Is provided,
The volume flow rate calculation unit is characterized in that each volume flow rate of the oil and the accompanying water is calculated based on the liquid phase volume flow rate and the ratio of the accompanying water calculated by the accompanying water ratio calculation unit. The mixed phase flow measuring apparatus according to any one of claims 1 to 3. The step of inputting at least the mass flow rate measurement value and the density measurement value from the Koriori flow meter that measures the fluid to be measured including oil from the oil production well and the accompanying water to the measurement value acquisition unit, and
A step of inputting a temperature measurement value of a temperature sensor for measuring the temperature of the fluid to be measured into the measurement value acquisition unit, and a step of inputting the temperature measurement value to the measurement value acquisition unit.
A step in which the volume flow rate calculation unit calculates the gas volume flow rate and the liquid phase volume flow rate based on the mass flow rate measurement value and the density measurement value, and
A mixed phase flow measurement method comprising: a step of calculating each volume flow rate of the oil and the accompanying water by the volume flow rate calculation unit based on the liquid phase volume flow rate and the temperature measurement value. Used in computers
Steps to enter at least mass flow and density measurements from the Koriori flowmeter to measure the fluid to be measured, including oil from oil production wells and associated water.
The step of inputting the temperature measurement value of the temperature sensor for measuring the temperature of the fluid to be measured, and
A step of calculating the gas volume flow rate and the liquid phase volume flow rate based on the mass flow rate measurement value and the density measurement value, and
A program characterized in that a step of calculating each volume flow rate of the petroleum and the accompanying water based on the liquid phase volume flow rate and the temperature measurement value is provided.

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