CN117266832A - Method and system for inverting oil-gas well two-phase flow output profile by using DAS - Google Patents
Method and system for inverting oil-gas well two-phase flow output profile by using DAS Download PDFInfo
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Abstract
The invention discloses a method and a system for inverting a two-phase flow output profile of an oil and gas well. And carrying out Fourier transform (FFT) on the depth direction and the time direction according to the original data measured by optical fiber processing to obtain a frequency-wave number slope, obtaining sound velocity according to the slope, and obtaining the proportion of oil or water in different mixtures according to an empirical formula so as to obtain an oil-water biphase abortion section. The invention has the advantages that: the method has the advantages of high precision, real-time performance and high efficiency, improves the working efficiency and reduces the labor cost. The method helps to optimize the production operation of the oil and gas well, adjust production parameters and maximize the output of the oil field.
Description
Technical Field
The invention relates to the technical field of oil and gas engineering, in particular to a method and a system for inverting the two-phase flow output profile of an oil and gas well by utilizing DAS based on distributed acoustic wave sensing data.
Background
The working principle of DAS: DAS is a sensing technology that captures sound waves by optical fibers by collecting and analyzing the sound produced at the surface or downhole. By utilizing the principle of coherent optical time domain reflection measurement, coherent short pulse laser is injected into an optical fiber, when external vibration acts on the optical fiber, the internal structure of the fiber core can be slightly changed due to the elasto-optical effect, so that the change of a backward Rayleigh scattering signal is caused, the received reflected light intensity is changed, and the intensity change of the Rayleigh scattering light signal before and after a downhole event is detected
At present, no single method can directly invert the two-phase flow from DAS data, and the final result can be obtained by combining multiple methods. Only the phase fractions of the two-phase flow of oil/water/gas at different acoustic velocities are obtained from different flow rates.
Abbreviation and key term definitions
Distributed acoustic wave sensing (DAS, distributed Acoustic Sensing);
phase fraction/phase ratio (meaning the same), the volume or mass ratio of the different phases in a mixture;
two-phase flow, which refers to a fluid containing two components, such as an oil-water mixed fluid containing oil and water;
the liquid production profile refers to the production flow at a specific depth;
inflow control valves (ICV, inflow Control Valve).
Disclosure of Invention
The invention provides a method and a system for inverting a two-phase flow output profile of an oil and gas well by utilizing DAS (data acquisition system) aiming at the defects of the prior art. According to the original data measured by optical fiber processing, fourier transformation (FFT, fast Fourier Transform) is carried out on the depth direction and the time direction to obtain a frequency-wave number slope, according to the slope, sound velocity can be obtained, and in different mixtures, the proportion of oil or water can be obtained according to an empirical formula, so that an oil-water biphase abortion section can be obtained.
In order to achieve the above object, the present invention adopts the following technical scheme:
a method for inverting a dual phase flow production profile of an oil and gas well using a DAS, comprising:
1) And (3) data acquisition: an optical fiber sensor is used to place an optical fiber in an oil and gas well to collect data of two-phase flow production in the oil and gas well. The data includes information of the arrival time difference or phase difference of the sound wave at the sensor.
2) Preprocessing data: the collected raw data is preprocessed and filtered to remove noise and interference and to extract useful signals. The original data is divided into a series of data blocks. Each data block has a size nx×nt. For the next block of data, the window is shifted forward by Nt time samples and Nx/2 spatial samples.
3) Performing Fourier transform: a two-dimensional fourier transform (FFT) is performed on the preprocessed data to move the data from the time domain to the frequency-wavenumber (f-k) domain.
4) Calculating a sound velocity slope value: from the fourier transformed data, a frequency-wavenumber slope is calculated over the frequency-wavenumber (f-k) domain.
5) Acoustic velocity inversion: and calculating the flow velocity under the Doppler effect according to the slope and the initial sound velocity value, and calculating the sound velocity distribution.
6) And according to the sound velocity distribution obtained by calculation, a two-phase fluid mixing rule is applied to calculate the phase proportion.
7) And reconstructing a biphasic miscarriage liquid profile in the oil and gas well according to the obtained sound velocity distribution, the obtained phase proportion and the obtained flow velocity.
Further, the sound velocity slope value is calculated in the f-k domain in step 3), as follows:
wherein, c m Is the sound velocity value in the mixture, lambda is the wavelength, k is the angular wave number,is the wave number.
Further, in the step 4), a two-phase fluid mixing rule is applied to calculate the phase proportion, and the specific steps are as follows:
41 Calculating the total volume modulus K of the mixture t . From the volume proportions of the mixture and the bulk modulus of each phase, K is calculated using the harmonic mean of the Reuss approximation t . The formula is as follows:
wherein alpha is 0 Is the porosity of the material, K 0 Is the initial rigidity of the rock-soil material, K w Is the stiffness of the pore water, d is the viscosity of the pore water, et is the elastic modulus of the material.
42 Calculating the density ρ of the mixture m . Let the mixture be a homogeneous oil-water mixture with a density ρ m Is the arithmetic mean of the densities of the oil phase and the water phase:
ρ m ＝α 0 ρ 0 +(1-α 0 )
wherein ρ is 0 Is the mass density of the solid portion of the material.
43 To calculate K) t Is calculated ρ by the formula sum of (2) m Formula (1) substitution formula (b)And the oil-water modulus is expressed as K according to sound velocity and density 0 ＝c 0 2 And K w ＝c w 2 ρ w . Then, the sound velocity c of the phase ratio is calculated using the following formula m ：
Wherein ρ is w Is the mass density of the liquid c w Is the speed of sound of the liquid.
44 Solving for alpha 0 For the binary one-time equation of the unknown number, alpha is calculated 0 Is a root of (2):
in the method, in the process of the invention,
further, the step of calculating the flow rate under the doppler effect in step 8) is as follows:
51 Based on actual measurement or known conditions, the rising sound velocity c is obtained u And decreasing sound velocity c d Is a numerical value of (2);
52 Using the principle of the doppler effect, the observation frequencies of the observation point 1 and the observation point 2 are calculated. According to the formulaAnd->Where v is the fluid velocity and f is the primary wave frequency.
53 Determining the frequency at the same original wavelength, i.e
54 Substituting the equation of step 53) into the equation of step 52) to obtain an expression of fluid flow rate and static sound velocity:and->
55 Using fluid flow velocity v m Multiplying the cross-sectional area of the conduit to obtain the flow rate.
56 Combining the phase fractions to obtain the flow of the different phases.
57 From the flow rates of the different phases and the known cross-sectional area, the velocity of each phase is calculated. The velocity is obtained by dividing the fluid flow by the cross-sectional area.
58 According to the relation between the sound velocity and the speed, the ratio of the speed of each phase to the sound velocity is obtained.
59 According to the ratio relation and the velocity, the velocity of each phase is calculated, and thus the velocity distribution is obtained.
The invention also discloses a system for inverting the two-phase flow output profile of the oil and gas well by using the DAS, which can be used for implementing the method for inverting the two-phase flow output profile of the oil and gas well by using the DAS, and specifically comprises the following steps:
and an input data module: and inputting the collected original data.
And a pretreatment module: the collected raw data is subjected to preprocessing and filtering operations to remove noise and interference signals and extract useful signals.
And a Fourier transform module: and performing two-dimensional Fourier transform on the preprocessed data, and converting the data from a time domain into a frequency-wave number (f-k) domain.
A sound velocity slope calculation module: on the frequency-wavenumber (f-k) domain, the frequency-wavenumber slope is calculated from the fourier transformed data.
And a sound velocity inversion module: and calculating to obtain sound velocity distribution by methods such as numerical solution according to the slope and the initial sound velocity value.
And a phase ratio calculation module: and according to the sound velocity distribution obtained by calculation, calculating the phase proportion by applying a two-phase fluid mixing rule.
And a section reconstruction module: from the phase-contrast calculation results, the sound velocity distribution and the phase-contrast are combined to reconstruct the two-phase flow section in the oil-gas well.
The invention also discloses a computer device, which comprises a memory, a processor and a computer program stored on the memory and capable of running on the processor, wherein the method for inverting the two-phase flow production profile of the oil and gas well by using the DAS is realized when the processor executes the program.
The invention also discloses a computer readable storage medium, on which a computer program is stored, which when executed by a processor, implements the method for inverting the two-phase flow production profile of an oil and gas well by using the DAS.
Compared with the prior art, the invention has the advantages that:
1. high precision: and carrying out liquid production profile measurement of the oil-water two-phase flow by adopting a distributed acoustic wave sensing DAS (Distributed Acoustic Sensing) technology. Through pretreatment, fourier transformation and inversion calculation, the high-precision inversion of the two-phase flow output profile in the oil and gas well can be realized. Since the optical fiber sensor has high sensitivity and high resolution, accurate data input can be provided.
2. Real-time performance: and the optical fiber sensor is adopted to collect data, and the data is processed in real time through the preprocessing and calculating module, so that the real-time inversion of the two-phase flow output profile of the oil and gas well is realized. This may provide timely production profile information, helping operators make quick decisions.
3. Quick measurement: the DAS measurement time is very short, and the measurement and data processing can be completed in 2-3 hours when the yield is stable. The method makes the measuring process more efficient, can reduce the measuring time, shorten the production stopping time and reduce the measuring cost of the oil field.
4. And (3) automation: the rapid processing and analysis of a large amount of data can be realized through the automatic processing of modules such as data acquisition, preprocessing, fourier transformation, inversion calculation and the like. Therefore, the working efficiency can be improved, and the labor cost can be reduced.
5. Yield maximization: the distribution condition of the oil-water two-phase flow in the well bore can be known by quantitatively analyzing the liquid production profile, and the distribution condition comprises parameters such as the proportion of liquid phase and gas phase, the flow rate and the like. Thus, the method can help to optimize the production operation of the oil and gas well, adjust the production parameters and maximize the output of the oil field.
Drawings
FIG. 1 is a technical roadmap of a method for inverting a two-phase flow production profile of an oil and gas well using a DAS in accordance with an embodiment of the invention.
FIG. 2 is a block read process diagram of the original data according to an embodiment of the present invention;
FIG. 3 is a graph of noise picked up by a sensor array from eddy currents when the eddy currents reach a sensor location in accordance with an embodiment of the invention;
FIG. 4 is a schematic diagram of the mechanism of sound waves generated by the production fluid passing through an ICV in accordance with an embodiment of the present invention;
FIG. 5 is a graph of frequency wavenumbers showing two different lines representing rising (positive slope) and falling (negative slope) speeds of sound plotted against wavenumber rather than angular wavenumber for an embodiment of the present invention;
FIG. 6 is a graph of the recombination fraction for three different fluid mixtures for an embodiment of the present invention;
fig. 7 is a schematic diagram showing the effect of doppler shift on the observed frequencies of two sensors in the flow direction according to an embodiment of the present invention.
Detailed Description
The invention will be described in further detail below with reference to the accompanying drawings and by way of examples in order to make the objects, technical solutions and advantages of the invention more apparent.
As shown in fig. 1, the present invention provides a method for inverting a two-phase flow production profile of an oil and gas well by using DAS, comprising:
the data collected by the optical fiber in the oil field is preprocessed.
In order to be able to acquire variations in the acoustic signal, it is necessary to sample at a very high time sampling rate, typically 5kHz to 25kHz, which results in a very large DAS data file that requires pre-processing of the acquired raw data. For raw data, assuming a horizontal well length of 4000m, sampling at 1 meter intervals at a sampling rate of 10kHz, 4000 tens of thousands of samples per second can be taken, assuming a standard-of-text file is saved, averaging to 4 significant digits per data, then a 160MB data file per second would be stored, 9.6GB per minute, which is a challenge for both processing and viewing the data, and viewing only the raw data, it is difficult to observe useful signal characteristics over such a wide frequency band. By converting the data into the frequency-wavenumber (f-k) domain, the propagation of acoustic wave energy and the frequency-dependent attenuation of that energy with distance can be detected. In most cases, a file of one minute acoustic data cannot be loaded with computer resources. To overcome the difficulty of processing large data files, the original data is divided into a series of data blocks for processing. The size of the data block (nx×nt) depends on the spatial and temporal resolution of the desired computed velocity profile. For the next block of data, the window is shifted forward by Nt time samples and Nx/2 spatial samples. The halving of the spatial window size is done to increase the repeatability of the results and to increase the spatial resolution in the results (Xiao, 2014). The end result is a set of f-k maps overlapping in distance and covering the entire file content, as shown in fig. 2, with the speed and volume phase ratios calculated from each block.
These data can be converted into f-k (frequency f-wavenumber k) space when the propagating acoustic wave is measured in the time and space domains. Analysis of the time-varying signal by fourier transformation provides the frequency content of the data (in s -1 Or Hz). Similarly, analysis of the spatially correlated signal may yield spatial frequency or wavenumber information (in ft -1 In units). Thus, the f-k map can be constructed by providing the data to a two-dimensional Fourier transform algorithm. Such operations can reveal data features that are not readily detectable in the time-space domain, such as trends, discontinuities, and self-similarity.
Basically, fourier analysis involves decomposing a signal into sine waves of different frequencies (called analytical functions). In principle, the transformation measures the similarity between the signal and the analysis function by an inner product operation between the two. The fourier formula is represented as formula 1:
f (ζ) is the fourier transform of the variable ζ, representing the frequency, F (t) is the signal in the time domain, i is the imaginary unit,f (ζ) is typically complex, the processed data is discrete, and the formula used in the calculation is the discrete fourier transform:
F k refers to the Fourier coefficient obtained by transforming the kth discrete time domain measurement value, due to the signalsIs a true measured real value and should ignore negative frequencies.
And calculating the sound velocity slope value of the f-k domain, and then, according to the calculated sound velocity, calculating the phase proportion by applying a two-phase fluid mixing rule.
Since the velocity measurements are based on tracking acoustic waves, it is important to know how these waves are generated. Turbulent pipe flow is essentially related to self-generated pressure fluctuations (known as vortices) whose velocity of motion approaches the volume average flow rate (fig. 3). However, the frequency bands of the sound waves generated by these fluctuations are very low and are not always shown in DAS data (Silva et al 2012). If an inflow control valve (Inflow Control Valve, ICV) is used for completion, a strong acoustic wave is generated when fluid is forced to contract through the valve, as shown in fig. 4. The acoustic wave propagates through the fluid in two directions in the wellbore: in line with and opposite to the flow direction. By tracking the propagation path of the acoustic wave, the upward velocity (c) of the acoustic wave can be obtained u ) And the down-link speed (c) d )。
The dynamic pressure exerted by the acoustic waves causes localized changes in the radial strain of the tube wall. This strain is captured by the optical sensor within the DAS. To more easily understand this process, it is assumed that only one sound wave is tracked. In this case, the sensors along the wellbore will have some time delay to capture the pressure fluctuations as the wave passes through the fluid. The speed of sound is then calculated from the known distance between the travel time and the sensor (annalsis and Trehan, 2013). Since several superimposed signals are picked up, these signals are fed into a two-dimensional fourier transform based signal processing algorithm that extracts the data from the time-space domain into the frequency-wave number domain.
Measuring sound velocity from f-k domain
Since DAS measures the acoustic amplitude in a non-dispersive medium (the phenomenon that the phase velocity of an optical wave does not change with frequency, a medium having such a characteristic is called a non-dispersive medium), the speed of sound is independent of frequency; thus, the speed of energy transmission and sound propagation is the same (Dean, 1979). This phenomenon is shown in the f-k plot as a line emanating from the origin, corresponding to the Gao Fuli leaf coefficient shown in fig. 5. The method described is not applicable to dispersive media by the sound velocity of the medium corresponding to the slope line in the frequency-wavenumber plot.
c m Is the sound velocity value in the mixture, lambda is the wavelength, k is the angular wave number,is the wave number.
Fluid mixing model for calculating phase proportion
The next step in characterizing the flow by sound speed is to convert these measurements into phase information. The process follows the two-stage model shown in the work of Chaudhuri et al (2012).
ρ m Is the mixture density, kt is the bulk modulus of the fluid mixture and the pipe, and the bulk modulus and the mixture density are determined from the mixing equation for these two properties, assuming a homogeneous miscella, with a density arithmetic mean of:
ρ m ＝α 0 ρ 0 +(1-α 0 ) (5)
whereas the bulk modulus of the fluid mixture is expressed as a harmonic mean of the Reuss approximation (Mavko and Mukerji, 1998) as follows:
the above includes the pipe diameter d, the pipe wall thickness t, the Young's modulus E, substituting equations 5 and 6 into equation 4, and expressing the oil-water modulus as: k (K) 0 ＝c 0 2 And K w ＝c w 2 ρ w Then, it is possible to obtain:
the left hand side of the equation is obtained by processing measured data, the right hand side is aimed at individual phase properties, phase densities can be obtained in the laboratory by PVT analysis, all of which are assessed at wellbore pressure and temperature at that depth and time, which can be obtained by DTS and ICV sensors. The only unknown in the equation is alpha 0 Converting equation 7 to α 0 The coefficients of the binary once equation of (2) are:
solving this binary once equation yields two roots:
fig. 5 shows the relationship of the two-phase fluid fractions for the fluid properties listed in table 1, and for each measured sound velocity, a unique phase fraction of oil-water flow can be determined. But the situation will be different when gas is present, there are two possible phase-contrast solutions in each sound speed measurement between about 300 and 500 meters/second for this particular mixture. The lowest mixed sound velocity when gas is present is about 300 meters per second, even below the sound velocity in a single phase gas. This is because the rate of change of compressibility is much higher than the rate of change of density as more gas is added to the oil. For example, if only 5% gas is added to the oil, the bulk modulus of the mixture will be reduced by approximately three times with little change in density. When a small amount of gas is added to the liquid, this eventually results in a sharp drop in sound velocity.
Outside the range of 300-500m/s sound speed, the solution returns to a positive phase root and a negative phase root, which need to be discarded. When two positive roots are present, it is necessary to decide which solution to accept based on the fluid properties. For example, assuming that the sound speed of 400m/s is measured in an oil-gas mixture (dashed line in fig. 6), if the flow is known to be rich, the corresponding Gas Volume Fraction (GVF) is 0.9, if we know that the flow is rich, the corresponding Gas Volume Fraction (GVF) is around 0.2.
Table 1 fluid properties for solving a two-phase proportional model
| Properties of (C) | Water and its preparation method | Oil (oil) | Air flow | |
| Density of | ρ(kg/m 3 ) | 1100 | 820 | 100 |
| Sound velocity | c(m/s) | 1525 | 1050 | 500 |
| Bulk modulus | K(GPa) | 2.56 | 0.905 | 2.50x 10 -2 |
Calculating flow velocity under Doppler effect
After the rising sound velocity (c) u) And decreasing the sound velocity (c d ) The flow rate is then calculated using the doppler principle. As shown in fig. 7, when the sound source moves toward the stationary point, the frequency observed at the point on the left side of the fluid (point 2) is higher than the original wave frequency f, and when the sound source is away from the point, the frequency observed at point 1 is lower than the actual wave frequency. The two frequencies may be combined into one frequency f.
And->
V is the fluid velocity, the frequencies of both observation points are calculated at the same original wavelength, so
The formula is substituted into the above formula, and a clear expression of the fluid flow velocity and the static sound velocity in the mixture is obtained:
and->
v m Is the fluid flow rate, c m Is the static sound velocity, the flow is by the fluid flow velocity v of the mixture m Calculated by multiplying the cross-sectional area of the pipe.
The doppler effect is a phenomenon in which the frequency of an observed wave changes when an observer moves relative to a wave source because of the doppler shift caused by the flow velocity of the fluid.
When a wave source approaches a point of view, the observer receives a higher frequency than the original frequency emitted by the wave source. This is because the wave source movement causes the arrival speed of the wave peak (or wave front) to increase, allowing the observer to receive more wave peaks (or wave fronts) per unit time. This results in the observer measuring a higher frequency than the original frequency.
Therefore, when the flow velocity is calculated, the influence of Doppler effect is considered, the final fluid velocity is calculated, the obtained fluid velocity can be multiplied by the cross-sectional area of the pipeline to obtain the flow, and the flow of different phases can be obtained by combining the phase fractions before the flow is combined, so that the final liquid production section is obtained.
In yet another embodiment of the present invention, a system for inverting a two-phase flow production profile of an oil and gas well using DAS is provided, which can be used to implement the method for inverting a two-phase flow production profile of an oil and gas well using DAS described above, specifically including:
and an input data module: and inputting the collected original data.
And a pretreatment module: the collected raw data is subjected to preprocessing and filtering operations to remove noise and interference signals and extract useful signals.
And a Fourier transform module: and performing two-dimensional Fourier transform on the preprocessed data, and converting the data from a time domain into a frequency-wave number (f-k) domain.
A sound velocity slope calculation module: on the frequency-wavenumber (f-k) domain, the frequency-wavenumber slope is calculated from the fourier transformed data.
And a sound velocity inversion module: and calculating to obtain sound velocity distribution by methods such as numerical solution according to the slope and the initial sound velocity value.
And a phase ratio calculation module: and according to the sound velocity distribution obtained by calculation, calculating the phase proportion by applying a two-phase fluid mixing rule.
And a section reconstruction module: from the phase-contrast calculation results, the sound velocity distribution and the phase-contrast are combined to reconstruct the two-phase flow section in the oil-gas well.
In yet another embodiment of the present invention, a terminal device is provided, the terminal device including a processor and a memory, the memory for storing a computer program, the computer program including program instructions, the processor for executing the program instructions stored by the computer storage medium. The processor may be a central processing unit (Central Processing Unit, CPU), but may also be other general purpose processors, digital signal processors (Digital Signal Processor, DSP), application specific integrated circuits (Application Specific Integrated Circuit, ASIC), off-the-shelf Programmable gate arrays (FPGAs) or other Programmable logic devices, discrete gate or transistor logic devices, discrete hardware components, etc., which are the computational core and control core of the terminal adapted to implement one or more instructions, in particular adapted to load and execute one or more instructions to implement a corresponding method flow or a corresponding function; the processor of the embodiment of the invention can be used for the operation of a method for inverting the two-phase flow output profile of an oil and gas well by using DAS, and comprises the following steps:
1) And (3) data acquisition: an optical fiber sensor is used to place an optical fiber in an oil and gas well to collect data of two-phase flow production in the oil and gas well. The data includes information of the arrival time difference or phase difference of the sound wave at the sensor. By tracking the propagation path of the sound wave, the upward velocity and the downward velocity of the sound wave are obtained.
2) Preprocessing data: the collected raw data is preprocessed and filtered to remove noise and interference and to extract useful signals. The original data is divided into a series of data blocks. Each data block has a size nx×nt. For the next block of data, the window is shifted forward by Nt time samples and Nx/2 spatial samples.
3) Performing Fourier transform: a two-dimensional fourier transform (FFT) is performed on the preprocessed data to move the data from the time domain to the frequency-wavenumber (f-k) domain.
4) Calculating a sound velocity slope value: from the fourier transformed data, a frequency-wavenumber slope is calculated over the frequency-wavenumber (f-k) domain.
5) Acoustic velocity inversion: from the slope and the initial sound velocity value, a sound velocity distribution is calculated.
6) And according to the sound velocity distribution obtained by calculation, a two-phase fluid mixing rule is applied to calculate the phase proportion.
7) And according to the phase proportion, combining the obtained sound velocity distribution with the phase proportion to reconstruct the two-phase flow section in the oil-gas well.
In a further embodiment of the present invention, the present invention also provides a storage medium, in particular, a computer readable storage medium (Memory), which is a Memory device in a terminal device, for storing programs and data. It will be appreciated that the computer readable storage medium herein may include both a built-in storage medium in the terminal device and an extended storage medium supported by the terminal device. The computer-readable storage medium provides a storage space storing an operating system of the terminal. Also stored in the memory space are one or more instructions, which may be one or more computer programs (including program code), adapted to be loaded and executed by the processor. The computer readable storage medium herein may be a high-speed RAM memory or a non-volatile memory (non-volatile memory), such as at least one magnetic disk memory.
One or more instructions stored in a computer-readable storage medium may be loaded and executed by a processor to perform the corresponding steps of the method of inverting a two-phase flow production profile of an oil and gas well using a DAS in the above embodiments; one or more instructions in a computer-readable storage medium are loaded by a processor and perform the steps of:
1) And (3) data acquisition: an optical fiber sensor is used to place an optical fiber in an oil and gas well to collect data of two-phase flow production in the oil and gas well. The data includes information of the arrival time difference or phase difference of the sound wave at the sensor. By tracking the propagation path of the sound wave, the upward velocity and the downward velocity of the sound wave are obtained.
2) Preprocessing data: the collected raw data is preprocessed and filtered to remove noise and interference and to extract useful signals. The original data is divided into a series of data blocks. Each data block has a size nx×nt. For the next block of data, the window is shifted forward by Nt time samples and Nx/2 spatial samples.
3) Performing Fourier transform: a two-dimensional fourier transform (FFT) is performed on the preprocessed data to move the data from the time domain to the frequency-wavenumber (f-k) domain.
4) Calculating a sound velocity slope value: from the fourier transformed data, a frequency-wavenumber slope is calculated over the frequency-wavenumber (f-k) domain.
5) Acoustic velocity inversion: from the slope and the initial sound velocity value, a sound velocity distribution is calculated.
6) And according to the sound velocity distribution obtained by calculation, a two-phase fluid mixing rule is applied to calculate the phase proportion.
7) And according to the phase proportion, combining the obtained sound velocity distribution with the phase proportion to reconstruct the two-phase flow section in the oil-gas well.
It will be appreciated by those skilled in the art that embodiments of the present invention may be provided as a method, system, or computer program product. Accordingly, the present invention may take the form of an entirely hardware embodiment, an entirely software embodiment or an embodiment combining software and hardware aspects. Furthermore, the present invention may take the form of a computer program product embodied on one or more computer-usable storage media (including, but not limited to, disk storage, CD-ROM, optical storage, and the like) having computer-usable program code embodied therein.
The present invention is described with reference to flowchart illustrations and/or block diagrams of methods, apparatus (systems) and computer program products according to embodiments of the invention. It will be understood that each flow and/or block of the flowchart illustrations and/or block diagrams, and combinations of flows and/or blocks in the flowchart illustrations and/or block diagrams, can be implemented by computer program instructions. These computer program instructions may be provided to a processor of a general purpose computer, special purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, create means for implementing the functions specified in the flowchart flow or flows and/or block diagram block or blocks.
These computer program instructions may also be stored in a computer-readable memory that can direct a computer or other programmable data processing apparatus to function in a particular manner, such that the instructions stored in the computer-readable memory produce an article of manufacture including instruction means which implement the function specified in the flowchart flow or flows and/or block diagram block or blocks.
These computer program instructions may also be loaded onto a computer or other programmable data processing apparatus to cause a series of operational steps to be performed on the computer or other programmable apparatus to produce a computer implemented process such that the instructions which execute on the computer or other programmable apparatus provide steps for implementing the functions specified in the flowchart flow or flows and/or block diagram block or blocks.
Those of ordinary skill in the art will appreciate that the embodiments described herein are intended to aid the reader in understanding the practice of the invention and that the scope of the invention is not limited to such specific statements and embodiments. Those of ordinary skill in the art can make various other specific modifications and combinations from the teachings of the present disclosure without departing from the spirit thereof, and such modifications and combinations remain within the scope of the present disclosure.
Claims (7)
1. A method for inverting a two-phase flow production profile of an oil and gas well using a DAS, comprising:
1) And (3) data acquisition: arranging an optical fiber in an oil and gas well by using an optical fiber sensor so as to acquire data of two-phase flow output in the oil and gas well; the data comprises information of arrival time difference or phase difference of the sound wave to the sensor;
2) Preprocessing data: preprocessing and filtering the collected original data to eliminate noise and interference and extract useful signals; dividing the original data into a series of data blocks; the size of each data block is Nx Nt; for the next data block, the window is moved forward by Nt time samples and Nx/2 spatial samples;
3) Performing Fourier transform: performing two-dimensional Fourier transform on the preprocessed data to change the data from a time domain to a frequency-wave number domain;
4) Calculating a sound velocity slope value: calculating a frequency-wave number slope on the frequency-wave number domain according to the data after the Fourier transform;
5) Acoustic velocity inversion: calculating sound velocity distribution according to the slope and the initial sound velocity value;
6) According to the sound velocity distribution obtained by calculation, a two-phase fluid mixing rule is applied to calculate the phase proportion;
7) And according to the phase proportion, combining the obtained sound velocity distribution with the phase proportion to reconstruct the two-phase flow section in the oil-gas well.
2. The method for inverting a two-phase flow production profile of an oil and gas well using DAS of claim 1, wherein: in step 3) a sound velocity slope value is calculated in the f-k domain, as follows:
wherein, c m Is the sound velocity value in the mixture, lambda is the wavelength, k is the angular wave number,is the wave number.
3. The method for inverting a two-phase flow production profile of an oil and gas well using DAS of claim 1, wherein: in the step 4), a two-phase fluid mixing rule is applied to calculate the phase proportion, and the specific steps are as follows:
41 Calculating the total volume modulus K of the mixture t The method comprises the steps of carrying out a first treatment on the surface of the From the volume proportions of the mixture and the bulk modulus of each phase, K is calculated using the harmonic mean of the Reuss approximation t The method comprises the steps of carrying out a first treatment on the surface of the The formula is as follows:
wherein alpha is 0 Is the porosity of the material, K 0 Is the initial rigidity of the rock-soil material, K w Is the stiffness of the pore water, d is the viscosity of the pore water, et is the elastic modulus of the material;
42 Calculating the density ρ of the mixture m The method comprises the steps of carrying out a first treatment on the surface of the Let the mixture be a homogeneous oil-water mixture with a density ρ m Is the arithmetic mean of the densities of the oil phase and the water phase:
ρ m ＝α 0 ρ 0 +(1-α 0 )
wherein ρ is 0 Is the mass density of the solid portion of the material;
43 To calculate K) t Is calculated ρ by the formula sum of (2) m Formula (1) substitution formula (b)And the oil-water modulus is expressed as K according to sound velocity and density 0 ＝c 0 2 And K w ＝c w 2 ρ w The method comprises the steps of carrying out a first treatment on the surface of the Then, the sound velocity c of the phase ratio is calculated using the following formula m ：
Wherein ρ is w Is the mass density of the liquid c w Is the speed of sound of the liquid;
44 Solving for alpha 0 For the binary one-time equation of the unknown number, alpha is calculated 0 Is a root of (2):
in the method, in the process of the invention,
4. the method for inverting a two-phase flow production profile of an oil and gas well using DAS of claim 1, wherein: the step of calculating the sound velocity distribution in step 5) is as follows:
51 Based on actual measurement or known conditions, the rising sound velocity c is obtained u And decreasing sound velocity c d Is a numerical value of (2);
52 Using Doppler effect principle to calculate the observation frequency of the observation point 1 and the observation point 2; according to the formulaAnd->Where v is the fluid velocity and f is the primary wave frequency;
53 Determining the frequency at the same original wavelength, i.e
54 Substituting the equation of step 53) into the equation of step 52) to obtain an expression of fluid flow rate and static sound velocity:and->
55 Using fluid flow velocity v m Multiplying the cross-sectional area of the pipeline to obtain flow;
56 Combining the phase fractions to obtain the flow of different phases;
57 Calculating the velocity of each phase based on the flow rates of the different phases and the known cross-sectional area; velocity is obtained by dividing the fluid flow by the cross-sectional area;
58 Obtaining the ratio of the speed of each phase to the sound velocity according to the relation between the sound velocity and the speed;
59 According to the ratio relation and the velocity, the velocity of each phase is calculated, and thus the velocity distribution is obtained.
5. A system for inverting a two-phase flow production profile of an oil and gas well using DAS, comprising: the system can be used to implement the method of inverting a dual phase flow production profile of an oil and gas well using DAS of one of claims 1 to 4;
the system comprises:
and an input data module: inputting the collected original data;
and a pretreatment module: preprocessing and filtering the collected original data to remove noise and interference signals and extract useful signals;
and a Fourier transform module: performing two-dimensional Fourier transform on the preprocessed data, and converting the data from a time domain into a frequency-wave number domain;
a sound velocity slope calculation module: calculating a frequency-wave number slope according to the data after Fourier transformation in a frequency-wave number domain;
and a sound velocity inversion module: according to the slope and the initial sound velocity value, calculating to obtain sound velocity distribution by a numerical solution method;
and a phase ratio calculation module: according to the sound velocity distribution obtained by calculation, calculating the phase proportion by applying a two-phase fluid mixing rule;
and a section reconstruction module: from the phase-contrast calculation results, the sound velocity distribution and the phase-contrast are combined to reconstruct the two-phase flow section in the oil-gas well.
6. A computer device, characterized by: a computer program comprising a memory, a processor and stored on the memory and executable on the processor, which when executed implements the method of inverting a two-phase flow production profile of an oil and gas well using DAS as claimed in one of claims 1 to 4.
7. A computer-readable storage medium, characterized by: a computer program stored thereon, which when executed by a processor, implements a method of inverting a two-phase flow production profile of an oil and gas well using a DAS as claimed in one of claims 1 to 4.
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