Detection Method for Solids Content of Fracturing Flowback Fluid

Abstract

A method for detecting the solid content rate of fracturing flowback fluid, the method comprising: sampling the fracturing flowback fluid to be measured to obtain a multiphase flow sample, and performing four-phase separation on oil, gas, water and solids in the multiphase flow sample; performing nuclear magnetic resonance on pure water, water and oil respectively to obtain the first amplitude values of the corresponding free decay signals, and using the first amplitude values to determine the hydrogen index corresponding to water and oil; applying a diffusion editing pulse sequence to water and oil to obtain the diffusion coefficients corresponding to water and oil; using the first antenna and the second antenna of a multiphase flow nuclear magnetic resonance flowmeter to respectively perform pulse emission on the fracturing flowback fluid to be measured, collecting the corresponding echo signals, and determining the solid content rate of the fracturing flowback fluid to be measured according to the echo signals, the hydrogen index and the diffusion coefficient. The present invention utilizes nuclear magnetic resonance technology, does not rely on nuclear magnetic resonance spectra throughout the process, realizes the measurement of the four-phase content of fracturing flowback fluid, accurately determines the solid content rate of fracturing flowback fluid, and realizes efficient, environmentally friendly and safe on-line detection.

Description

Technical Field

[0001] The present invention relates to the technical field of fracturing flowback fluid detection, and particularly to a method for detecting the solid content rate of fracturing flowback fluid. Background Art

[0002] In the oil fracturing project, the real-time flow rate and phase content rate detection of the flowback fluid are effective means to evaluate the fracturing effect. The flowback fluid is composed of four different components: crude oil, fracturing fluid, natural gas, and sand. In addition, the flowback fluid often maintains a high-speed continuous flow state, and online detection is required, which brings great difficulties to the quantitative detection of the phase content rate.

[0003] The existing detection methods sample the multiphase flow in the pipeline, and then use the methods of natural sedimentation or centrifugation to achieve stratification based on the density differences of each component, and then conduct measurement. The disadvantages of these methods are very obvious: (1) Sampling is required after blocking the fluid flow state (hindering construction); (2) The samples after detection are discarded, causing pollution; (3) It takes time from sampling to laboratory detection, resulting in lag of detection data and low efficiency; (4) During the sampling process, due to the changes in the temperature and pressure of the sample, the physical properties of the sample may change, and the measurement results cannot reflect the true data of the fluid in the pipeline.

[0004] The application of nuclear magnetic resonance technology in the quantitative detection of complex fluids has been very mature, and it stands out due to its advantages such as accuracy, greenness, and safety compared with other technologies. However, the current nuclear magnetic resonance detection technology for complex fluids also relies on sampling measurement, that is, it cannot be used for online measurement of flowing fluids. We previously proposed a nuclear magnetic resonance phase content rate measurement method for oil, gas, and water three-phase flows. However, due to the large amount of solid phase in the fracturing flowback fluid, and the amount of solid phase is one of the important indicators for evaluating the sand-carrying capacity of the fracturing fluid, it cannot be ignored. Therefore, the demand for the detection technology of the phase content rate of oil, gas, water, and solid four-phase flows is urgent. Summary of the Invention

[0005] The main purpose of the embodiments of the present invention is to provide a method for detecting the solid content rate of fracturing flowback fluid, which can measure the content of each phase of the four components of oil, gas, water, and solid contained in the fracturing flowback fluid, and accurately determine the solid content rate of the fracturing flowback fluid.

[0006] To achieve the above purpose, the embodiments of the present invention provide a method for detecting the solid content rate of fracturing flowback fluid, and the method includes:

[0007] Sampling the fracturing flowback fluid to be measured to obtain a multiphase flow sample, and separating the four phases of oil, gas, water, and solid in the multiphase flow sample;

[0008] Perform nuclear magnetic resonance on the pure water and the water and oil in the multiphase flow sample respectively to obtain the initial amplitudes of the corresponding free induction decay signals, and use the initial amplitudes to determine the hydrogen indices corresponding to the water and oil in the multiphase flow sample;

[0009] Apply a diffusion editing pulse sequence to the water and oil in the multiphase flow sample to obtain the diffusion coefficients corresponding to the water and oil in the multiphase flow sample;

[0010] Use the first antenna and the second antenna of the multiphase flow nuclear magnetic resonance flowmeter to perform pulse emission on the fracturing flowback fluid to be measured respectively, collect the echo signals corresponding to the first antenna and the second antenna, and determine the solid content of the fracturing flowback fluid to be measured according to the echo signals, hydrogen indices and diffusion coefficients.

[0011] Optionally, in an embodiment of the present invention, the method further includes: evaluating the fracturing effect in the petroleum fracturing project by using the solid content of the fracturing flowback fluid to be measured.

[0012] Optionally, in an embodiment of the present invention, the four-phase separation of the oil, gas, water and solid in the multiphase flow sample includes: using the static method or centrifugation technology to perform four-phase separation on the oil, gas, water and solid in the multiphase flow sample.

[0013] Optionally, in an embodiment of the present invention, the performing nuclear magnetic resonance on the pure water and the water and oil in the multiphase flow sample respectively to obtain the initial amplitudes of the corresponding free induction decay signals includes: putting the pure water and the water and oil in the multiphase flow sample into a test container respectively; wherein, the inner diameter and outer diameter of the test container are the same as the inner diameter and outer diameter of the fluid tube of the multiphase flow nuclear magnetic resonance flowmeter, and the length of the test container is greater than the lengths of the first antenna and the second antenna of the multiphase flow nuclear magnetic resonance flowmeter; placing the test container in the detection area of the multiphase flow nuclear magnetic resonance flowmeter, and measuring the initial amplitudes of the corresponding free induction decay signals of the pure water and the water and oil in the multiphase flow sample.

[0014] Optionally, in an embodiment of the present invention, the using the initial amplitudes to determine the hydrogen indices corresponding to the water and oil in the multiphase flow sample includes: determining the hydrogen index of the water in the multiphase flow sample according to the ratio of the initial amplitude of the free induction decay signal of the water in the multiphase flow sample to the initial amplitude of the free induction decay signal of the pure water; determining the hydrogen index of the oil in the multiphase flow sample according to the ratio of the initial amplitude of the free induction decay signal of the oil in the multiphase flow sample to the initial amplitude of the free induction decay signal of the pure water.

[0015] Optionally, in an embodiment of the present invention, the method further includes: measuring the pressure in the fluid tube by using a pressure gauge in the fluid tube of the multiphase flow nuclear magnetic resonance flowmeter, and determining the hydrogen index and diffusion coefficient of the gas in the multiphase flow sample according to the tube pressure.

[0016] Optionally, in an embodiment of the present invention, using the first antenna and the second antenna of the multiphase flow nuclear magnetic resonance flowmeter to respectively perform pulse emission on the fracturing flowback fluid to be measured, and collecting the echo signals corresponding to the first antenna and the second antenna includes: connecting the fracturing flowback fluid to be measured to the fluid pipe of the multiphase flow nuclear magnetic resonance flowmeter to enable the fracturing flowback fluid to be measured to continuously flow under the probe of the multiphase flow nuclear magnetic resonance flowmeter, using the second antenna of the multiphase flow nuclear magnetic resonance flowmeter to emit a pulse sequence to the fracturing flowback fluid to be measured, collecting the second echo signal, and determining the flow rate of the fracturing flowback fluid to be measured according to the attenuation rate of the second echo signal; wherein, the second echo signal includes a second first amplitude value; using the first antenna of the multiphase flow nuclear magnetic resonance flowmeter to emit a 90-degree pulse to the fracturing flowback fluid to be measured, and collecting the first echo signal, and the first echo signal includes a first first amplitude value.

[0017] Optionally, in an embodiment of the present invention, determining the solid content rate of the fracturing flowback fluid to be measured according to the echo signal, hydrogen index, and diffusion coefficient includes: determining the water content rate and oil content rate in the fracturing flowback fluid to be measured according to the flow rate of the fracturing flowback fluid to be measured, the first first amplitude value, the second first amplitude value, and the first amplitude value and hydrogen index of the free decay signals corresponding to water and oil in the multiphase sample; determining the gas content rate and solid content rate in the fracturing flowback fluid to be measured according to the second echo signal, and the diffusion coefficients, water content rate, and oil content rate corresponding to water, oil, and gas in the multiphase sample.

[0018] The present invention applies nuclear magnetic resonance technology to measure the solid content rate of fracturing flowback fluid, and the whole process does not depend on nuclear magnetic resonance spectroscopy, realizing the measurement of the content of each phase of the four components of oil, gas, water, and solid contained in the fracturing flowback fluid, accurately determining the solid content rate of the fracturing flowback fluid, and realizing efficient, environmentally friendly, and safe on-line detection. Description of the Drawings

[0019] In order to more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the following will briefly introduce the drawings required for use in the description of the embodiments. Obviously, the following drawings are only some embodiments of the present invention. For those of ordinary skill in the art, without creative efforts, other drawings can also be obtained based on these drawings.

[0020] Figure 1 It is a flowchart of a method for detecting the solid content rate of a fracturing flowback fluid according to an embodiment of the present invention;

[0021] Figure 2 It is a flowchart of determining the first amplitude value of the free decay signal in an embodiment of the present invention;

[0022] Figure 3Flow chart for collecting echo signals in an embodiment of the present invention;

[0023] Figure 4 Flow chart for determining the solid content in an embodiment of the present invention;

[0024] Figure 5 Flow chart for detecting the solid content of fracturing flowback fluid in a specific embodiment of the present invention;

[0025] Figure 6 Schematic diagram of a static magnetic field including a double uniform gradient magnetic field and a double antenna structure in an embodiment of the present invention;

[0026] Figure 7 Schematic diagram of a pulse sequence transmitted by antenna A2 in an embodiment of the present invention. Detailed implementation manners

[0027] An embodiment of the present invention provides a method for detecting the solid content of fracturing flowback fluid, which is applicable to all laboratory and engineering application fields involving on-line measurement of the component content of solid-containing oil and gas multiphase flow.

[0028] Next, the technical solutions in the embodiments of the present invention will be clearly and completely described in conjunction with the accompanying drawings in the embodiments of the present invention. Obviously, the described embodiments are only a part of the embodiments of the present invention, rather than all the embodiments. All other embodiments obtained by those of ordinary skill in the art based on the embodiments of the present invention without creative efforts shall fall within the protection scope of the present invention.

[0029] Currently, in the multi-phase flow phase content technology, the on-line detection scheme for the phase content of oil-gas-water three-phase flow mainly detects the phase content based on the relaxation time difference or diffusion coefficient difference of each component of the three-phase flow, but it cannot measure the four-phase flow containing solid phases such as formation sand. In addition, the existing technology can only be applied to oil production engineering to detect the multi-phase flow produced underground, and cannot be applied to the field of fracturing engineering. In these engineering fields, on the one hand, the fluid components are more complex, and on the other hand, the relaxation time differences between the components are not obvious, so it is difficult to distinguish.

[0030] In view of the practical problem that nuclear magnetic resonance technology cannot be applied to the measurement of the content of 3-phase and above mixed fluid components in flow, the present invention realizes the quantitative evaluation of the content of different fluid components based on the difference in the magnetization speed of different fluid components, does not require the collection of relaxation information of the fluid to be measured, and has a fast measurement speed (the measurement period is less than 10 milliseconds).

[0031] As Figure 1 shown is a flow chart of a method for detecting the solid content of fracturing flowback fluid in an embodiment of the present invention. The method shown in the figure includes:

[0032] Step S1, sample the fracturing flowback fluid to be measured to obtain a multiphase flow sample, and perform four-phase separation on the oil, gas, water, and solids in the multiphase flow sample.

[0033] Among them, the fracturing flowback fluid to be measured belongs to multiphase flow. Sample the fracturing flowback fluid to be measured, and then separate the four phases of oil, gas, water, and solids by static settling or centrifugation. The gas in the fracturing flowback fluid to be measured is natural gas.

[0034] Step S2, perform nuclear magnetic resonance on pure water, water, and oil in the multiphase flow sample respectively to obtain the first amplitude values of the corresponding free induction decay signals, and use the first amplitude values to determine the hydrogen indices corresponding to water and oil in the multiphase flow sample.

[0035] Among them, use a multiphase flow nuclear magnetic resonance flowmeter to perform nuclear magnetic resonance on pure water, water, and oil in the multiphase flow sample respectively, and measure the first amplitude values of the free induction decay (FID) signals (the FID signal is a continuously decaying signal, and the maximum amplitude at the beginning of the signal decay is the first amplitude value). Further, the ratio of the FID first amplitude values of the oil and water samples to the FID first amplitude value of the pure water reagent is the hydrogen index of the oil and water.

[0036] Step S3, apply a diffusion editing pulse sequence to the water and oil in the multiphase flow sample to obtain the diffusion coefficients corresponding to the water and oil in the multiphase flow sample.

[0037] Among them, apply a diffusion editing (Diffusion Ecoding) pulse sequence to the oil and water samples in the multiphase flow sample, and measure the diffusion coefficients of the oil and water.

[0038] Step S4, use the first antenna and the second antenna of the multiphase flow nuclear magnetic resonance flowmeter to perform pulse emission on the fracturing flowback fluid to be measured respectively, collect the echo signals corresponding to the first antenna and the second antenna, and determine the solid content rate of the fracturing flowback fluid to be measured according to the echo signals, hydrogen index, and diffusion coefficient.

[0039] Among them, as Figure 6 shown, the multiphase flow nuclear magnetic resonance flowmeter includes a magnet structure with a dual uniform gradient magnetic field and a dual solenoid antenna structure. There are two regions with uniform gradient magnetic fields (with the same magnetic field gradient G) in the static magnetic field generated by the nuclear magnetic resonance probe of the multiphase flow nuclear magnetic resonance flowmeter, and the detection dual antennas are respectively placed in these two uniform gradient magnetic field regions.

[0040] Further, the multiphase flow nuclear magnetic resonance flowmeter needs to be calibrated as follows when leaving the factory: Pass pure water fluid with a fixed flow rate v' through the fluid tube of the nuclear magnetic resonance flowmeter, and determine the effective lengths L1 and L2 of the magnet according to the FID signal amplitudes collected by the first antenna A1 and the second antenna A2. Specifically, it can be determined according to the following formula.

[0041]

[0042] In the above formula, only L 1,2 is the unknown, and L 1,2 refers to L1 and L2.

[0043] Connect the nuclear magnetic resonance multiphase flowmeter to the fluid pipeline to be measured, and make the fluid pass through the probe under continuous flow. First, perform the flow rate measurement. The second antenna A2 emits Figure 7 the pulse sequence shown, collect the echo train (including the first amplitude value M2(v / L2) of the FID), and measure the flow rate v through the attenuation rate of the echo train according to the existing methods related to nuclear magnetic resonance flowmeters.

[0044] The first antenna A1 emits a 90° pulse, and collects the first amplitude value M1(v / L1) of the FID signal, as well as the first amplitude value M2(v / L2) of the FID signal collected by the second antenna A2 previously:

[0045]

[0046]

[0047] Among them, T 1,水 , T 1,油 are the transverse relaxation times of water and oil respectively. The unknowns in formulas (1) and (2) are only S 油 , S 水 , and the others are known numbers. Through the pulse sequence emitted by the second antenna A2, the amplitude M2(2τ1 + 2nτ) of the (n - 1)th echo signal collected:

[0048]

[0049] Among them, T 2,水 , T 2,油 are the transverse relaxation times of water and oil respectively, γ is the gyromagnetic ratio, which is a fixed value, τ1 is the half echo interval time of the first window of the pulse sequence, τ is the half echo interval time of other echoes, M 0,油 , M 0,气 and M 0,水 are the first amplitude values of the free induction decay (FID) signals corresponding to oil, gas and water respectively, D 油 , D 气 and D 水 are the diffusion coefficients of oil, gas and water respectively, and G is the magnetic field gradient of the multiphase flow nuclear magnetic resonance flowmeter.

[0050] In addition, usually once the components of natural gas are determined, the echo amplitude M 0,气 can be known, and the determination of the components depends on the sampling measurement at the oil field site.

[0051] Since most of the solid phase has no NMR response, the solid phase component is not included in equation (3). 油 , S 水 It can be obtained from equations (1) and (2). The only unknown in equation (3) is S 气 Since there are only four components in the tube: oil, gas, water, and solid, equation (4) always holds true.

[0052] S 水 +S 油 +S 气 +S 固 =1 (4)

[0053] Among them, S 油 , S 水 , S 气 and S 固 are the phase contents of oil, water, gas and solid, i.e. oil content, water content, gas content and solid content. Combining equations (3) and (4) can obtain S 气 , S 固 .

[0054] As an embodiment of the present invention, the method further includes: using the solid content of the fracturing flowback fluid to be tested to evaluate the fracturing effect in the petroleum fracturing project.

[0055] Among them, the existing technology cannot directly measure the solid content. The method used is to accurately measure the content of oil, water and gas, that is, S oil, S water, S gas, and then use formula (4) to deduce the solid content.

[0056] As an embodiment of the present invention, the four-phase separation of oil, gas, water and solid in the multiphase flow sample includes: utilizing static method or centrifugal technology to perform four-phase separation of oil, gas, water and solid in the multiphase flow sample.

[0057] As an embodiment of the present invention, Figure 2 As shown, pure water and water and oil in the multiphase flow sample are subjected to nuclear magnetic resonance respectively, and the first amplitude values ​​of the corresponding free decay signals are obtained, including:

[0058] Step S21, placing pure water and water and oil in the multiphase flow sample into a test container respectively; wherein the inner diameter and outer diameter of the test container are the same as the inner diameter and outer diameter of the fluid tube of the multiphase flow nuclear magnetic resonance flowmeter, and the length of the test container is greater than the length of the first antenna and the second antenna of the multiphase flow nuclear magnetic resonance flowmeter.

[0059] Among them, prepare 3 test containers. The inner and outer diameters of the test containers are the same as those of the fluid tube of the multiphase flow nuclear magnetic resonance flowmeter, and the length is greater than the length of the antenna of the multiphase flow nuclear magnetic resonance flowmeter. Fill 2 single-phase fluids (oil, water) into 2 test containers respectively, and fill pure water reagent into another test container.

[0060] Step S22, place the test container in the detection area of the multiphase flow nuclear magnetic resonance flowmeter, and measure the initial amplitudes of the free decay signals corresponding to water and oil in the pure water and the multiphase flow sample.

[0061] Among them, place 3 test containers into the detection area of the multiphase flow nuclear magnetic resonance flowmeter respectively, and measure the initial amplitudes of the corresponding free induction decay (FID) signals. The ratio of the FID initial amplitudes of oil and water to the FID initial amplitude of the pure water reagent is the hydrogen index of oil and water. The hydrogen index of natural gas is proportional to the pressure in the pipe, which can be obtained by looking up a table. A pressure gauge can be installed on the nuclear magnetic resonance pipeline to read the pressure in the pipe in real time. The diffusion coefficient of natural gas is proportional to the pressure in the pipe and can also be obtained by looking up a table.

[0062] In this embodiment, determining the hydrogen indices corresponding to water and oil in the multiphase flow sample by using the initial amplitude includes:

[0063] Determine the hydrogen index of water in the multiphase flow sample according to the ratio of the initial amplitude of the free decay signal of water in the multiphase flow sample to the initial amplitude of the free decay signal of the pure water;

[0064] Determine the hydrogen index of oil in the multiphase flow sample according to the ratio of the initial amplitude of the free decay signal of oil in the multiphase flow sample to the initial amplitude of the free decay signal of the pure water.

[0065] As an embodiment of the present invention, the method further includes: measuring the pressure in the pipe by using a pressure gauge in the fluid tube of the multiphase flow nuclear magnetic resonance flowmeter, and determining the hydrogen index and diffusion coefficient of gas in the multiphase flow sample according to the pressure in the pipe.

[0066] In this embodiment, as Figure 3 shown, by using the first antenna and the second antenna of the multiphase flow nuclear magnetic resonance flowmeter, pulse emissions are respectively carried out on the fracturing flowback fluid to be measured, and collecting the echo signals corresponding to the first antenna and the second antenna includes:

[0067] Step S31: Connect the fracturing flowback fluid to be measured to the fluid pipe of the multiphase flow nuclear magnetic resonance flowmeter, so that the fracturing flowback fluid to be measured flows continuously under the probe of the multiphase flow nuclear magnetic resonance flowmeter. Use the second antenna of the multiphase flow nuclear magnetic resonance flowmeter to emit a pulse sequence to the fracturing flowback fluid to be measured, collect the second echo signal, and determine the flow rate of the fracturing flowback fluid to be measured according to the attenuation rate of the second echo signal; wherein, the second echo signal includes a second first amplitude value.

[0068] Step S32: Use the first antenna of the multiphase flow nuclear magnetic resonance flowmeter to emit a 90-degree pulse to the fracturing flowback fluid to be measured, and collect the first echo signal, and the first echo signal includes a first first amplitude value.

[0069] In this embodiment, as Figure 4 shown, determining the solid content rate of the fracturing flowback fluid to be measured according to the echo signal, hydrogen index and diffusion coefficient includes:

[0070] Step S41: Determine the water content rate and oil content rate in the fracturing flowback fluid to be measured according to the flow rate, first first amplitude value, second first amplitude value of the fracturing flowback fluid to be measured, and the first amplitude value and hydrogen index of the free decay signals corresponding to water and oil in the multiphase flow sample.

[0071] Step S42: Determine the gas content rate and solid content rate in the fracturing flowback fluid to be measured according to the second echo signal, and the diffusion coefficients, water content rate and oil content rate corresponding to water, oil and gas in the multiphase flow sample.

[0072] As Figure 5 shown is the flowchart of detecting the solid content rate of fracturing flowback fluid in a specific embodiment of the present invention. First, sample the multiphase flow, and then separate the oil, gas, water and solid phases by means of standing, centrifugation or sedimentation in a separation tank. Prepare 3 test containers, the inner and outer diameters of the test containers are the same as the inner and outer diameters of the fluid pipe of the nuclear magnetic resonance multiphase flowmeter, and the length is greater than the length of the antenna of the nuclear magnetic resonance multiphase flowmeter. Fill 2 single-phase fluids (oil, water) into 2 test containers respectively, and fill pure water reagent into another test container. Place the 3 test containers into the detection area of the nuclear magnetic resonance multiphase flowmeter respectively, and measure the amplitude of the free induction decay (FID) signal to obtain M 0,油 、M 0,水 . The ratio of the FID first amplitude value of the oil and water samples to the FID first amplitude value of the pure water reagent is the hydrogen index HI 油 、HI 水 . The HI 气 of natural gas is proportional to the pressure in the pipe, which can be obtained by looking up a table. For this reason, a pressure gauge needs to be installed on the nuclear magnetic resonance pipeline to read the pressure in the pipe in real time.

[0073] Then, a diffusion encoding pulse sequence is applied to the oil and water samples to measure the diffusion coefficients D of the oil and water. 油 , D 水 The diffusion coefficient of natural gas is D 气 It is proportional to the pressure inside the pipe and can also be obtained by looking up the table.

[0074] In addition, there is a calibration experiment that needs to be completed before the instrument leaves the factory: a pure water fluid with a fixed flow rate v' is passed through the fluid tube of the nuclear magnetic resonance flowmeter, and the effective lengths L1 and L2 of the magnet are determined by the amplitude of the FID signal collected by antennas A1 and A2.

[0075] Connect the NMR multiphase flowmeter to the manifold of the fluid to be measured, and allow the fluid to flow through the probe in a continuous flow. First, measure the flow rate. Antenna A2 transmits Figure 7 The pulse sequence shown collects an echo train (including the first amplitude of the FID) and measures the flow velocity v by the echo train attenuation rate according to the existing nuclear magnetic resonance flowmeter related methods.

[0076] Antenna A1 emits a 90° pulse to collect the first amplitude of the FID signal, as well as the first amplitude of the FID signal collected by antenna A2. The amplitude of the n-1th echo signal collected by the pulse sequence emitted by antenna A2. Since most solid phases do not respond to nuclear magnetic resonance, the S 油 , S 水 , S 气 and S 固 The relationship between S 油 , S 水 , S 气 and S 固 The specific process refers to formula (1) to formula (3).

[0077] The present invention uses nuclear magnetic resonance technology to measure the solid content of fracturing return fluid, and the whole process does not rely on nuclear magnetic resonance spectrum, so as to measure the content of each phase of the four components of oil, gas, water and solid contained in the fracturing return fluid, accurately determine the solid content of the fracturing return fluid, and realize efficient, environmentally friendly and safe online detection.

[0078] Those skilled in the art will appreciate that embodiments of the present invention may be provided as methods, systems, or computer program products. Therefore, the present invention may take the form of a complete hardware embodiment, a complete software embodiment, or an embodiment combining software and hardware. Moreover, the present invention may take the form of a computer program product implemented on one or more computer-usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0079] The present invention is described with reference to the flowcharts and / or block diagrams of methods, apparatuses (systems), and computer program products according to embodiments of the present invention. It should be understood that each flow and / or block in the flowcharts and / or block diagrams, as well as the combination of flows and / or blocks in the flowcharts and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to the processor of a general-purpose computer, a special-purpose computer, an embedded processor, or other programmable data processing devices to generate a machine, such that the instructions executed by the processor of the computer or other programmable data processing devices produce a means for implementing the functions specified in the Figure 1 one or more flows and / or blocks Figure 1 one or more blocks.

[0080] These computer program instructions can also be stored in a computer-readable memory that can direct a computer or other programmable data processing device to work in a specific manner, such that the instructions stored in the computer-readable memory produce a manufactured article including an instruction means that implements the functions specified in the Figure 1 one or more flows and / or blocks Figure 1 one or more blocks.

[0081] These computer program instructions can also be loaded onto a computer or other programmable data processing device, such that a series of operational steps are executed on the computer or other programmable device to generate a computer-implemented process, and thus the instructions executed on the computer or other programmable device provide steps for implementing the functions specified in the Figure 1 one or more flows and / or blocks Figure 1 one or more blocks.

[0082] Specific embodiments are applied in the present invention to elaborate on the principles and implementation manners of the present invention. The descriptions of the above embodiments are only used to help understand the method and its core idea of the present invention; at the same time, for those of ordinary skill in the art, based on the idea of the present invention, there will be changes in the specific implementation manners and application scopes. In summary, the content of this specification should not be construed as a limitation to the present invention.

Claims

1. A method for detecting the solid content rate of fracturing flowback fluid, characterized in that, The method includes: Sampling the fracturing flowback fluid to be measured to obtain a multiphase flow sample, and performing four-phase separation on oil, gas, water, and solids in the multiphase flow sample; Performing nuclear magnetic resonance on pure water, water, and oil in the multiphase flow sample respectively to obtain the first amplitude values of the corresponding free decay signals, and using the first amplitude values to determine the hydrogen indices corresponding to water and oil in the multiphase flow sample; Applying a diffusion editing pulse sequence to water and oil in the multiphase flow sample to obtain the diffusion coefficients corresponding to water and oil in the multiphase flow sample; Using the first antenna and the second antenna of the multiphase flow nuclear magnetic resonance flowmeter to respectively perform pulse emission on the continuously flowing fracturing flowback fluid to be measured, collecting the echo signals corresponding to the first antenna and the second antenna, and determining the solid content rate of the fracturing flowback fluid to be measured according to the echo signals, hydrogen index, and diffusion coefficient; The first antenna and the second antenna are respectively placed in two uniform gradient magnetic field regions generated by the nuclear magnetic resonance probe of the multiphase flow nuclear magnetic resonance flowmeter; Among them, using the first antenna and the second antenna of the multiphase flow nuclear magnetic resonance flowmeter to respectively perform pulse emission on the fracturing flowback fluid to be measured and collecting the echo signals corresponding to the first antenna and the second antenna includes: Connecting the fracturing flowback fluid to be measured to the fluid pipe of the multiphase flow nuclear magnetic resonance flowmeter to make the fracturing flowback fluid to be measured flow continuously under the probe of the multiphase flow nuclear magnetic resonance flowmeter, using the second antenna of the multiphase flow nuclear magnetic resonance flowmeter to emit a pulse sequence to the fracturing flowback fluid to be measured, collecting the second echo signal, and determining the flow rate of the fracturing flowback fluid to be measured according to the attenuation rate of the second echo signal; wherein, the second echo signal includes the second first amplitude value and the amplitude value M2(2τ1 + 2nτ) of the (n - 1)th echo signal; Using the first antenna of the multiphase flow nuclear magnetic resonance flowmeter to emit a 90-degree pulse to the fracturing flowback fluid to be measured and collecting the first echo signal, and the first echo signal includes the first first amplitude value; Among them, the first first amplitude value M1(v / L1) satisfies formula (1), the second first amplitude value M2(v / L2) satisfies formula (2), and the amplitude value M2(2τ1 + 2nτ) of the (n - 1)th echo signal satisfies formula (3): where, T 1,水 and T 1,油 are the transverse relaxation times of water and oil respectively. The only unknowns in Equations (1) and (2) are S 油 and S 水 , and the others are known values; where, T 2,水 , T 2,油 are the transverse relaxation times of water and oil respectively, γ is the gyromagnetic ratio, which is a fixed value, τ1 is the half echo spacing time of the first window of the pulse sequence, τ is the half echo spacing time of other echoes, M 0,油 , M 0,气 and M 0,水 are the first amplitudes of the free induction decay (FID) signals corresponding to oil, gas and water respectively, D 油 , D 气 and D 水 are the diffusion coefficients of oil, gas and water respectively, G is the magnetic field gradient of the multiphase flow nuclear magnetic resonance flowmeter, and the only unknown in Equation (3) is S 气 ; Among them, determining the solid content rate of the fracturing flowback fluid to be measured according to the echo signals, hydrogen index, and diffusion coefficient includes: Determining the water content rate and oil content rate in the fracturing flowback fluid to be measured based on formula (1) and formula (2) according to the flow rate, first first amplitude value, second first amplitude value of the fracturing flowback fluid to be measured, and the first amplitude values and hydrogen indices of the free decay signals corresponding to water and oil in the multiphase flow sample; Determining the gas content rate and solid content rate in the fracturing flowback fluid to be measured based on formula (3) and formula (4) according to the second echo signal, and the diffusion coefficients, water content rate, and oil content rate corresponding to water, oil, and gas in the multiphase flow sample, wherein: S 水 +S 油 +S 气 +S 固 = 1(4) Among them, S 油 , S 水 , S 气 and S 固 are the phase contents of oil, water, gas and solid, i.e. oil content, water content, gas content and solid content. Combining equations (3) and (4) to obtain S 气 , S 固 .

2. The method according to claim 1, characterized in that, The method further includes: evaluating the fracturing effect in the petroleum fracturing project by using the solid content rate of the fracturing flowback fluid to be measured.

3. The method according to claim 1, characterized in that, The four-phase separation of oil, gas, water and solids in the multiphase flow sample includes: using a static method or a centrifugation technique to perform four-phase separation of oil, gas, water and solids in the multiphase flow sample.

4. The method according to claim 1, wherein The obtaining of the initial amplitudes of the corresponding free decay signals by performing nuclear magnetic resonance on pure water and water and oil in the multiphase flow sample respectively includes: Putting pure water and water and oil in the multiphase flow sample into a test container respectively; wherein, the inner diameter and outer diameter of the test container are the same as the inner diameter and outer diameter of the fluid tube of the multiphase flow nuclear magnetic resonance flowmeter, and the length of the test container is greater than the lengths of the first antenna and the second antenna of the multiphase flow nuclear magnetic resonance flowmeter; Placing the test container in the detection area of the multiphase flow nuclear magnetic resonance flowmeter, and measuring the initial amplitudes of the corresponding free decay signals of pure water and water and oil in the multiphase flow sample.

5. The method according to claim 4, characterized in that The determining of the hydrogen indices corresponding to water and oil in the multiphase flow sample by using the initial amplitudes includes: Determining the hydrogen index of water in the multiphase flow sample according to the ratio of the initial amplitude of the free decay signal of water in the multiphase flow sample to the initial amplitude of the free decay signal of pure water; Determining the hydrogen index of oil in the multiphase flow sample according to the ratio of the initial amplitude of the free decay signal of oil in the multiphase flow sample to the initial amplitude of the free decay signal of pure water.

6. The method according to claim 1, wherein The method further includes: measuring the pressure inside the tube by using a pressure gauge in the fluid tube of the multiphase flow nuclear magnetic resonance flowmeter, and determining the hydrogen index and diffusion coefficient of gas in the multiphase flow sample according to the pressure inside the tube.

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