CN114624273A - Method for detecting solid content of fracturing flowback fluid - Google Patents

Method for detecting solid content of fracturing flowback fluid Download PDF

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CN114624273A
CN114624273A CN202011445815.2A CN202011445815A CN114624273A CN 114624273 A CN114624273 A CN 114624273A CN 202011445815 A CN202011445815 A CN 202011445815A CN 114624273 A CN114624273 A CN 114624273A
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water
oil
multiphase flow
fracturing
flow
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邓峰
陈冠宏
陈诗雯
张建军
王梦颖
熊春明
雷群
陶冶
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Petrochina Co Ltd
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    • G01N24/00—Investigating or analyzing materials by the use of nuclear magnetic resonance, electron paramagnetic resonance or other spin effects
    • G01N24/08—Investigating or analyzing materials by the use of nuclear magnetic resonance, electron paramagnetic resonance or other spin effects by using nuclear magnetic resonance
    • G01N24/082—Measurement of solid, liquid or gas content
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    • G01N13/00—Investigating surface or boundary effects, e.g. wetting power; Investigating diffusion effects; Analysing materials by determining surface, boundary, or diffusion effects
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
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Abstract

A method for detecting the solid content of fracturing flow-back fluid, comprising the following steps: sampling the fracturing flow-back fluid to be tested to obtain a multiphase flow sample, and performing four-phase separation on oil, gas, water and solids in the multiphase flow sample; respectively carrying out nuclear magnetic resonance on the purified water, the water and the oil to obtain first amplitude values of corresponding free attenuation signals, and determining hydrogen-containing indexes corresponding to the water and the oil by using the first amplitude values; applying a diffusion editing pulse sequence to the water and the oil to obtain diffusion coefficients corresponding to the water and the oil; the method comprises the steps of utilizing a first antenna and a second antenna of a multiphase flow nuclear magnetic resonance flowmeter to respectively carry out pulse transmission on fracturing flow-back fluid to be detected, collecting corresponding echo signals, and determining the solid content of the fracturing flow-back fluid to be detected according to the echo signals, the hydrogen-containing index and the diffusion coefficient. The method utilizes the nuclear magnetic resonance technology, does not depend on nuclear magnetic resonance spectrum in the whole process, realizes the measurement of the four-phase content of the fracturing flow-back fluid, accurately determines the solid content of the fracturing flow-back fluid, and realizes the efficient, environment-friendly and safe on-line detection.

Description

Method for detecting solid content of fracturing flowback fluid
Technical Field
The invention relates to the technical field of fracturing flowback fluid detection, in particular to a method for detecting solid content of fracturing flowback fluid.
Background
In petroleum fracturing engineering, real-time flow and phase content detection of the flowback fluid is an effective means for evaluating the fracturing effect. The flowback fluid is formed by mixing 4 different components of crude oil, fracturing fluid, natural gas, sand and the like. In addition, the flow-back liquid always keeps a high-speed continuous flowing state, and the flow-back liquid needs to be detected on line, which brings great difficulty to the quantitative detection of the relative content.
In the existing detection mode, after sampling the multiphase flow of a pipeline, a natural sedimentation or centrifugation mode is adopted, and the measurement is carried out after layering is realized based on the density difference of each component. The disadvantages of such methods are quite obvious: (1) sampling after the fluid flow state needs to be blocked (construction is hindered); (2) the detected sample is discarded to cause pollution; (3) time is required from sampling to laboratory detection, so that detection data lag is caused, and efficiency is low; (4) in the sampling process, due to the change of the temperature and the pressure of the sample, the physical parameters of the sample can be changed, and the measurement result cannot reflect the real data of the fluid in the pipeline.
The application of the nuclear magnetic resonance technology in the aspect of quantitative detection of the complex fluid is mature, and the nuclear magnetic resonance technology is distinguished because the nuclear magnetic resonance technology has the advantages of accuracy, greenness, safety and the like compared with other technologies, but the current nuclear magnetic resonance detection technology of the complex fluid also depends on sampling measurement, namely cannot be used for online measurement of the flowing fluid. The nuclear magnetic resonance phase content measuring method for oil-gas-water three-phase flow is proposed before, but a large amount of solid phase exists in fracturing flow-back fluid, and the amount of the solid phase is one of important indexes for evaluating sand carrying performance of the fracturing fluid and cannot be ignored. Therefore, the detection technology for the phase content of the oil, gas, water and solid four-phase flow is urgently needed.
Disclosure of Invention
The embodiment of the invention mainly aims to provide a method for detecting the solid content of fracturing flow-back fluid, which is used for measuring the content of each phase of oil, gas, water and solid contained in the fracturing flow-back fluid and accurately determining the solid content of the fracturing flow-back fluid.
In order to achieve the above object, an embodiment of the present invention provides a method for detecting a solid content of a fracturing flow-back fluid, where the method includes:
sampling the fracturing flow-back fluid to be tested to obtain a multiphase flow sample, and carrying out four-phase separation on oil, gas, water and solids in the multiphase flow sample;
respectively carrying out nuclear magnetic resonance on the purified water and the oil in the multiphase flow sample to obtain a first amplitude of a corresponding free attenuation signal, and determining a hydrogen-containing index corresponding to the water and the oil in the multiphase flow sample by using the first amplitude;
applying a diffusion editing pulse sequence to the water and the oil in the multiphase flow sample to obtain a diffusion coefficient corresponding to the water and the oil in the multiphase flow sample;
the method comprises the steps of utilizing a first antenna and a second antenna of a multiphase flow nuclear magnetic resonance flowmeter to respectively carry out pulse transmission on fracturing flow-back fluid to be detected, collecting echo signals corresponding to the first antenna and the second antenna, and determining the solid content of the fracturing flow-back fluid to be detected according to the echo signals, the hydrogen-containing index and the diffusion coefficient.
Optionally, in an embodiment of the present invention, the method further includes: and (4) evaluating the fracturing effect in the petroleum fracturing engineering by utilizing the solid content of the fracturing flowback fluid to be tested.
Optionally, in an embodiment of the present invention, the four-phase separating oil, gas, water, and solids in the multiphase flow sample includes: and performing four-phase separation on oil, gas, water and solid in the multiphase flow sample by using a standing mode or a centrifugal technology.
Optionally, in an embodiment of the present invention, the performing nuclear magnetic resonance on the water and the oil in the purified water and the multiphase flow sample respectively to obtain the first amplitudes of the corresponding free decay signals includes: respectively putting the purified water and the oil in the multiphase flow sample into a testing container; the inner diameter and the outer diameter of the test container are the same as those of a fluid pipe of the multiphase flow nuclear magnetic resonance flowmeter, and the length of the test container is larger than those of the first antenna and the second antenna of the multiphase flow nuclear magnetic resonance flowmeter; and placing the test container in a detection area of the multiphase flow nuclear magnetic resonance flowmeter, and measuring to obtain the first amplitude values of free attenuation signals corresponding to water and oil in the purified water and the multiphase flow sample.
Optionally, in an embodiment of the present invention, the determining the hydrogen index corresponding to water and oil in the multiphase flow sample by using the first amplitude value includes: determining the hydrogen-containing index of the water in the multiphase flow sample according to the ratio of the first amplitude of the free attenuation signal of the water in the multiphase flow sample to the first amplitude of the free attenuation signal of the purified water; and determining the hydrogen-containing index of the oil in the multiphase flow sample according to the ratio of the first amplitude of the free attenuation signal of the oil in the multiphase flow sample to the first amplitude of the free attenuation signal of the purified water.
Optionally, in an embodiment of the present invention, the method further includes: measuring the pressure in a pipe by using a pressure gauge in a fluid pipe of the multiphase flow nuclear magnetic resonance flowmeter, and determining the hydrogen-containing index and the diffusion coefficient of the gas in the multiphase flow sample according to the pressure in the pipe.
Optionally, in an embodiment of the present invention, the performing pulse transmission on the fracturing flow-back fluid to be measured by using the first antenna and the second antenna of the multiphase flow nuclear magnetic resonance flowmeter respectively, and acquiring the echo signals corresponding to the first antenna and the second antenna includes: connecting the fracturing flow-back fluid to be detected into a fluid pipe of the multiphase flow nuclear magnetic resonance flowmeter so that the fracturing flow-back fluid to be detected continuously flows under a probe of the multiphase flow nuclear magnetic resonance flowmeter, transmitting a pulse sequence to the fracturing flow-back fluid to be detected by using a second antenna of the multiphase flow nuclear magnetic resonance flowmeter, acquiring a second echo signal, and determining the flow rate of the fracturing flow-back fluid to be detected according to the attenuation rate of the second echo signal; wherein the second echo signal comprises a second first amplitude value; the method comprises the steps of transmitting 90-degree pulses to fracturing flowback fluid to be tested by utilizing a first antenna of a multiphase flow nuclear magnetic resonance flowmeter, and collecting first echo signals, wherein the first echo signals comprise first amplitude values.
Optionally, in an embodiment of the present invention, the determining the solid content of the fracturing flow-back fluid to be tested according to the echo signal, the hydrogen content index, and the diffusion coefficient includes: determining the water content and the oil content of the fracturing flow-back fluid to be detected according to the flow rate, the first amplitude and the second amplitude of the fracturing flow-back fluid to be detected, and the first amplitude and the hydrogen-containing index of a free attenuation signal corresponding to water and oil in the multiphase flow sample; and determining the gas content and the solid content in the fracturing flowback fluid to be tested according to the second echo signal and the diffusion coefficient, the water content and the oil content of the multiphase flow sample corresponding to water, oil and gas.
The nuclear magnetic resonance technology is used for measuring the solid content of the fracturing flow-back fluid, the whole process does not depend on the nuclear magnetic resonance spectrum, the measurement of the content of each phase of oil, gas, water and solid contained in the fracturing flow-back fluid is realized, the solid content of the fracturing flow-back fluid is accurately determined, and the efficient, environment-friendly and safe online detection is realized.
Drawings
In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings used in the description of the embodiments will be briefly introduced below, and it is obvious that the drawings in the following description are only some embodiments of the present invention, and it is obvious for those skilled in the art that other drawings can be obtained based on these drawings without creative efforts.
Fig. 1 is a flowchart of a method for detecting a solid content of a fracturing flow-back fluid according to an embodiment of the present invention;
FIG. 2 is a flow chart of determining a first amplitude of a free running decay signal in an embodiment of the present invention;
FIG. 3 is a flow chart of acquiring echo signals according to an embodiment of the present invention;
FIG. 4 is a flow chart of determining the solid content rate in an embodiment of the present invention;
FIG. 5 is a flow chart of the detection of the solid content of the fracturing flow-back fluid in an embodiment of the present invention;
FIG. 6 is a schematic diagram of a static magnetic field including dual uniform gradient magnetic fields and a dual antenna configuration in an embodiment of the present invention;
fig. 7 is a schematic diagram of a pulse sequence transmitted by antenna a2 in an embodiment of the present invention.
Detailed Description
The embodiment of the invention provides a method for detecting the solid content of fracturing flow-back fluid, which is suitable for laboratories and engineering application fields relating to the online measurement of the content of solid-containing oil-gas multiphase flow components.
The technical solutions in the embodiments of the present invention will be clearly and completely described below with reference to the drawings in the embodiments of the present invention, and it is obvious that the described embodiments are only a part of the embodiments of the present invention, and not all of the embodiments. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present invention.
At present, the multiphase flow phase content technology relates to an online detection scheme aiming at the phase content of oil-gas-water three-phase flow, and the phase content is mainly detected aiming at the relaxation time difference or diffusion coefficient difference of each component of the three-phase flow, but the four-phase flow containing solid phase such as formation sand cannot be measured. In addition, the prior art can only be applied to oil extraction engineering, detects multiphase flow of produced fluid under a well, but cannot be applied to the field of fracturing engineering.
Aiming at the practical problem that the nuclear magnetic resonance technology can not be applied to the flow measurement of the component content of the mixed fluid of 3 phases or above, the quantitative evaluation of the component content of different fluids is realized based on the difference of the magnetization speeds of the components of different fluids, the relaxation information of the fluid to be measured does not need to be collected, and the measurement speed is high (the measurement period is less than 10 milliseconds).
Fig. 1 is a flowchart of a method for detecting a solid content of a fracturing flow-back fluid according to an embodiment of the present invention, where the method includes:
step S1, sampling the fracturing flow-back fluid to be tested to obtain a multiphase flow sample, and performing four-phase separation on oil, gas, water and solid in the multiphase flow sample.
The fracturing flow-back fluid to be tested belongs to multiphase flow, the fracturing flow-back fluid to be tested is sampled, then oil, gas, water and solid are separated in a standing or centrifugal mode, and the gas in the fracturing flow-back fluid to be tested is natural gas.
Step S2, performing nuclear magnetic resonance on the purified water and the water and oil in the multiphase flow sample respectively to obtain corresponding first amplitude values of the free attenuation signals, and determining the hydrogen-containing index corresponding to the water and the oil in the multiphase flow sample by using the first amplitude values.
The method comprises the steps of performing nuclear magnetic resonance on water and oil in purified water and a multiphase flow sample by using a multiphase flow nuclear magnetic resonance flowmeter, and measuring a first amplitude of a free attenuation (FID) signal (the FID signal is a continuously attenuated signal, and the maximum amplitude of the signal at the beginning of re-attenuation is the first amplitude). Furthermore, the ratio of the first amplitude of the FID of the oil and water sample to the first amplitude of the FID of the pure water reagent is the hydrogen index of the oil and water.
Step S3, a diffusion editing pulse sequence is applied to the water and the oil in the multiphase flow sample, and the diffusion coefficient corresponding to the water and the oil in the multiphase flow sample is obtained.
Wherein, a Diffusion editing (Diffusion editing) pulse sequence is applied to oil and water samples in the multiphase flow sample, and the Diffusion coefficients of the oil and the water are obtained by measurement.
And step S4, respectively carrying out pulse emission on the fracturing flow-back fluid to be detected by using a first antenna and a second antenna of the multiphase flow nuclear magnetic resonance flowmeter, collecting echo signals corresponding to the first antenna and the second antenna, and determining the solid content of the fracturing flow-back fluid to be detected according to the echo signals, the hydrogen-containing index and the diffusion coefficient.
As shown in fig. 6, the multiphase flow nuclear magnetic resonance flowmeter includes a magnet structure including two uniform gradient magnetic fields and a dual-solenoid antenna structure. The static magnetic field generated by the nuclear magnetic resonance probe of the multiphase flow nuclear magnetic resonance flowmeter has two uniform gradient magnetic field areas (with the same magnetic field gradient G), and the detection double antennas are respectively arranged in the two uniform gradient magnetic field areas.
Further, the multiphase flow nmr flowmeter needs to be calibrated when the instrument is shipped: the method comprises the steps of introducing pure water fluid with a fixed flow velocity v' into a fluid pipe of the nuclear magnetic resonance flowmeter, and determining the effective length L of a magnet through the amplitude of FID signals collected by a first antenna A1 and a second antenna A21And L2. Specifically, the method can be determined according to the following equation.
Figure BDA0002831095420000051
In the above formula only L1,2Is an unknown number, L1,2Is referred to as L1And L2。
And connecting the nuclear magnetic resonance multiphase flowmeter to a fluid manifold to be measured, and enabling the fluid to pass through the probe under the condition of continuous flow. First a flow rate measurement is made. The second antenna A2 transmits the pulse sequence shown in FIG. 7, and collects echo train (including FID first amplitude M)2(v/L2) Flow velocity v is measured by the echo train decay rate according to methods associated with existing nuclear magnetic resonance flowmeters.
The first antenna A1 emits 90-degree pulse and collects the first amplitude M of the FID signal1(v/L1) And the first amplitude M of the FID signal collected by the previous second antenna A22(v/L2)：
Figure BDA0002831095420000052
Figure BDA0002831095420000053
Wherein, T1, water、T1, oilThe transverse relaxation times of water and oil, respectively, the unknowns in equations (1) and (2) being S aloneOil、SWater (W)Others are known numbers. The amplitude M of the acquired (n-1) th echo signal is obtained by the pulse sequence transmitted by the second antenna A22(2τ1+2nτ)：
Figure BDA0002831095420000061
Wherein, T2, water、T2, oilTransverse relaxation times of water and oil respectively, gamma is the gyromagnetic ratio, is a fixed value, tau1Is the half-echo interval of the first window of the pulse sequence, τ is the half-echo interval of the other echoes, M0, oil、M0, qiAnd M0, waterFirst amplitude of free decay (FID) signal, D, corresponding to oil, gas and water, respectivelyOil、DQi (Qi)And DWater (W)The diffusion coefficients of oil, gas and water are respectively, and G is the magnetic field gradient of the multiphase flow nuclear magnetic resonance flowmeter.
Furthermore, the echo amplitude M is generally known once the composition of the natural gas has been determined0, qiAnd the determination of the composition relies on sampling measurements at the oilfield site.
Since most of the solid phase has no nuclear magnetic resonance response, the solid phase component is not contained in the formula (3). In addition, since SOil、SWater (W)Can be obtained from the following formulas (1) and (2), and the unknown number in the formula (3) is only SQi (Qi). And because only 4 components of oil, gas, water and solid exist in the tube, the formula (4) is always true,
Swater (W)+SOil+SQi (Qi)+SFixing device＝1 (4)
Wherein S isOil、SWater (W)、SQi (Qi)And SFixing deviceThe S is obtained by sequentially obtaining the oil content, the water content, the gas content and the solid content which are the phase contents of oil, water, gas and solid, namely the oil content, the water content, the gas content and the solid content, and combining the vertical type (3) and the vertical type (4)Qi (Qi)、SFixing device。
As an embodiment of the invention, the method further comprises: and (4) evaluating the fracturing effect in the petroleum fracturing engineering by utilizing the solid content of the fracturing flowback fluid to be tested.
The solid phase content can not be directly measured in the prior art, the adopted method is to accurately measure the contents of oil, water and gas, namely S oil, S water and S gas, and then the solid phase content is deduced by using the formula (4).
As an embodiment of the present invention, the four-phase separation of oil, gas, water and solids in the multiphase flow sample comprises: and performing four-phase separation on oil, gas, water and solid in the multiphase flow sample by using a standing mode or a centrifugal technology.
As an embodiment of the present invention, as shown in fig. 2, the obtaining of the first amplitude of the corresponding free decay signal by performing the nmr on the water and the oil in the pure water and the multiphase flow sample respectively includes:
step S21, respectively putting the purified water and the water and oil in the multiphase flow sample into a testing container; the inner diameter and the outer diameter of the test container are the same as those of the fluid pipe of the multiphase flow nuclear magnetic resonance flowmeter, and the length of the test container is larger than those of the first antenna and the second antenna of the multiphase flow nuclear magnetic resonance flowmeter.
The method comprises the following steps of preparing 3 test containers, wherein the inner diameter and the outer diameter of each test container are the same as the inner diameter and the outer diameter of a fluid pipe of the multiphase flow nuclear magnetic resonance flowmeter, and the length of each test container is larger than the length of an antenna of the multiphase flow nuclear magnetic resonance flowmeter. 2 single-phase fluids (oil, water) were loaded into 2 test vessels, respectively, and a pure water reagent was loaded into the other test vessel.
And step S22, placing the test container in a detection area of the multiphase flow nuclear magnetic resonance flowmeter, and measuring to obtain the first amplitude values of free attenuation signals corresponding to water and oil in the purified water and the multiphase flow sample.
Wherein, 3 test containers are respectively arranged in a detection area of the multiphase flow nuclear magnetic resonance flowmeter, and the first amplitude of a corresponding free attenuation (FID) signal is measured. The ratio of the first amplitude of the FID of the oil and the water to the first amplitude of the FID of the pure water reagent is the hydrogen index of the oil and the water. The hydrogen index of the natural gas is in direct proportion to the pressure in the pipe, can be obtained by looking up a table, and can be used for installing a pressure gauge in a nuclear magnetic resonance pipeline and reading 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 found by looking up a table.
In this embodiment, determining the hydrogen index corresponding to water and oil in the multiphase flow sample by using the first amplitude value includes:
determining the hydrogen-containing index of the water in the multiphase flow sample according to the ratio of the first amplitude of the free attenuation signal of the water in the multiphase flow sample to the first amplitude of the free attenuation signal of the purified water;
and determining the hydrogen-containing index of the oil in the multiphase flow sample according to the ratio of the first amplitude of the free attenuation signal of the oil in the multiphase flow sample to the first amplitude of the free attenuation signal of the purified water.
As an embodiment of the invention, the method further comprises: measuring the pressure in a pipe by using a pressure gauge in a fluid pipe of the multiphase flow nuclear magnetic resonance flowmeter, and determining the hydrogen-containing index and the diffusion coefficient of the gas in the multiphase flow sample according to the pressure in the pipe.
In this embodiment, as shown in fig. 3, the performing pulse transmission on the fracturing flow-back fluid to be measured by using the first antenna and the second antenna of the multiphase flow nuclear magnetic resonance flowmeter, and acquiring the echo signals corresponding to the first antenna and the second antenna includes:
step S31, connecting the fracturing flow-back fluid to be tested into a fluid pipe of the multiphase flow nuclear magnetic resonance flowmeter so that the fracturing flow-back fluid to be tested continuously flows under a probe of the multiphase flow nuclear magnetic resonance flowmeter, transmitting a pulse sequence to the fracturing flow-back fluid to be tested by using a second antenna of the multiphase flow nuclear magnetic resonance flowmeter, collecting a second echo signal, and determining the flow rate of the fracturing flow-back fluid to be tested according to the attenuation rate of the second echo signal; wherein the second echo signal comprises a second first amplitude value;
step S32, a first antenna of the multiphase flow nuclear magnetic resonance flowmeter is used for emitting 90-degree pulses to the fracturing flow-back fluid to be tested, and a first echo signal is collected and comprises a first amplitude value.
In this embodiment, as shown in fig. 4, determining the solid content of the fracturing flow-back fluid to be tested according to the echo signal, the hydrogen content index, and the diffusion coefficient includes:
step S41, determining the water content and the oil content of the fracturing flow-back fluid to be detected according to the flow rate, the first amplitude and the second amplitude of the fracturing flow-back fluid to be detected, and the first amplitude and the hydrogen-containing index of a free attenuation signal corresponding to water and oil in the multiphase flow sample;
and step S42, determining the gas content and the solid content in the fracturing flowback fluid to be tested according to the second echo signal and the diffusion coefficient, the water content and the oil content of the multiphase flow sample corresponding to water, oil and gas.
As shown in fig. 5, which is a flow chart of detecting the solid content of the fracturing flow-back fluid in an embodiment of the present invention, a multiphase flow is sampled, and then oil, gas, water and solid are separated by standing, centrifuging or settling in a separation tank. Preparing 3 test containers, wherein the inner diameter and the outer diameter of each test container are the same as the inner diameter and the outer diameter of the fluid pipe of the nuclear magnetic resonance multiphase flowmeter, and the length of each test container is larger than the length of the antenna of the nuclear magnetic resonance multiphase flowmeter. 2 single-phase fluids (oil, water) were loaded into 2 test vessels, respectively, and a pure water reagent was loaded into the other test vessel. Respectively loading 3 test containers into nuclear magnetic resonance multiphase flowmeter detection regions, and measuring amplitude of free attenuation (FID) signal to obtain M0, oil、M0, water. The ratio of the first amplitude of FID of the oil and water sample to the first amplitude of FID of the pure water reagent is the hydrogen index HI of the oil and waterOil、HIWater (W). HI of natural gasQi (Qi)The pressure in the pipe is directly proportional to the pressure in the pipe and can be obtained by looking up a table, and for the reason, the nuclear magnetic resonance pipeline needs to be provided with a pressure gauge to read the pressure in the pipe in real time.
Then, a Diffusion editing (Diffusion Ecoding) pulse sequence is applied to the oil and water samples, and the Diffusion coefficients D of the oil and the water are measuredOil、DWater (W). Diffusion coefficient of natural gas DQi (Qi)Proportional to the pressure in the tube, again by table lookup.
In addition, a calibration experiment needs to be completed when the instrument is delivered from a factory: pure water fluid at a constant flow velocity v' is introduced into a fluid pipe of a nuclear magnetic resonance flowmeter via an antenna A1 anddetermining the effective length L of the magnet by the amplitude of the FID signal collected by A21And L2。
And connecting the nuclear magnetic resonance multiphase flowmeter to a fluid manifold to be measured, and enabling the fluid to pass through the probe under the condition of continuous flow. First a flow rate measurement is made. Antenna a2 transmits the pulse sequence shown in fig. 7, collects the echo train (including the FID first amplitude value), and measures the flow velocity v by the echo train decay rate according to methods related to existing nuclear magnetic resonance flowmeters.
Antenna a1 transmits a 90 pulse, collects the first amplitude of the FID signal, and the first amplitude of the FID signal previously collected by antenna a 2. The amplitude of the n-1 th echo signal is acquired by the pulse sequence transmitted by the antenna A2. Since most solid phases are not NMR responsive, S is boundOil、SWater (W)、SQi (Qi)And SFixing deviceCan be obtained from the relationship ofOil、SWater (W)、SQi (Qi)And SFixing deviceThe specific process is described with reference to the formulae (1) to (3).
The nuclear magnetic resonance technology is used for measuring the solid content of the fracturing flow-back fluid, the whole process does not depend on the nuclear magnetic resonance spectrum, the measurement of the content of each phase of oil, gas, water and solid contained in the fracturing flow-back fluid is realized, the solid content of the fracturing flow-back fluid is accurately determined, and the efficient, environment-friendly and safe online detection is realized.
As will be appreciated by one skilled in the art, 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 has been 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 flow diagrams and/or block diagrams, and combinations of flows and/or blocks in the flow diagrams 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.
The principle and the implementation mode of the invention are explained by applying specific embodiments in the invention, and the description of the embodiments is only used for helping to understand the method and the core idea of the invention; meanwhile, for a person skilled in the art, according to the idea of the present invention, there may be variations in the specific embodiments and the application scope, and in summary, the content of the present specification should not be construed as a limitation to the present invention.

Claims (8)

1. A method for detecting the solid content of fracturing flow-back fluid is characterized by comprising the following steps:
sampling the fracturing flow-back fluid to be tested to obtain a multiphase flow sample, and carrying out four-phase separation on oil, gas, water and solids in the multiphase flow sample;
respectively carrying out nuclear magnetic resonance on the purified water and the oil in the multiphase flow sample to obtain a first amplitude of a corresponding free attenuation signal, and determining a hydrogen-containing index corresponding to the water and the oil in the multiphase flow sample by using the first amplitude;
applying a diffusion editing pulse sequence to the water and the oil in the multiphase flow sample to obtain a diffusion coefficient corresponding to the water and the oil in the multiphase flow sample;
the method comprises the steps of utilizing a first antenna and a second antenna of a multiphase flow nuclear magnetic resonance flowmeter to respectively carry out pulse transmission on fracturing flow-back fluid to be detected, collecting echo signals corresponding to the first antenna and the second antenna, and determining the solid content of the fracturing flow-back fluid to be detected according to the echo signals, the hydrogen-containing index and the diffusion coefficient.
2. The method of claim 1, further comprising: and (4) evaluating the fracturing effect in the petroleum fracturing engineering by utilizing the solid content of the fracturing flowback fluid to be tested.
3. The method of claim 1, wherein the four-phase separating oil, gas, water, and solids in the multiphase flow sample comprises: and performing four-phase separation on oil, gas, water and solid in the multiphase flow sample by using a standing mode or a centrifugal technology.
4. The method of claim 1, wherein performing nmr on the water and oil in the pure water and the multiphase flow sample to obtain corresponding first amplitudes of the free decay signals comprises:
respectively putting the purified water and the oil in the multiphase flow sample into a testing container; the inner diameter and the outer diameter of the test container are the same as those of a fluid pipe of the multiphase flow nuclear magnetic resonance flowmeter, and the length of the test container is larger than those of the first antenna and the second antenna of the multiphase flow nuclear magnetic resonance flowmeter;
and placing the test container in a detection area of the multiphase flow nuclear magnetic resonance flowmeter, and measuring to obtain the first amplitude values of free attenuation signals corresponding to water and oil in the purified water and the multiphase flow sample.
5. The method of claim 4, wherein the determining the hydrogen index corresponding to water and oil in the multiphase flow sample using the initial amplitude value comprises:
determining the hydrogen-containing index of the water in the multiphase flow sample according to the ratio of the first amplitude of the free attenuation signal of the water in the multiphase flow sample to the first amplitude of the free attenuation signal of the purified water;
and determining the hydrogen-containing index of the oil in the multiphase flow sample according to the ratio of the first amplitude of the free attenuation signal of the oil in the multiphase flow sample to the first amplitude of the free attenuation signal of the purified water.
6. The method of claim 1, further comprising: measuring the pressure in a pipe by using a pressure gauge in a fluid pipe of the multiphase flow nuclear magnetic resonance flowmeter, and determining the hydrogen-containing index and the diffusion coefficient of the gas in the multiphase flow sample according to the pressure in the pipe.
7. The method of claim 6, wherein the step of respectively performing pulse transmission on the fracturing flow-back fluid to be tested by using a first antenna and a second antenna of the multiphase flow nuclear magnetic resonance flowmeter, and the step of collecting echo signals corresponding to the first antenna and the second antenna comprises:
connecting the fracturing flow-back fluid to be detected into a fluid pipe of the multiphase flow nuclear magnetic resonance flowmeter so that the fracturing flow-back fluid to be detected continuously flows under a probe of the multiphase flow nuclear magnetic resonance flowmeter, transmitting a pulse sequence to the fracturing flow-back fluid to be detected by using a second antenna of the multiphase flow nuclear magnetic resonance flowmeter, acquiring a second echo signal, and determining the flow rate of the fracturing flow-back fluid to be detected according to the attenuation rate of the second echo signal; wherein the second echo signal comprises a second first amplitude value;
the method comprises the steps of transmitting 90-degree pulses to fracturing flowback fluid to be tested by utilizing a first antenna of a multiphase flow nuclear magnetic resonance flowmeter, and collecting first echo signals, wherein the first echo signals comprise first amplitude values.
8. The method of claim 7, wherein the determining the solid content of the fracturing flow-back fluid to be tested according to the echo signal, the hydrogen index and the diffusion coefficient comprises:
determining the water content and the oil content of the fracturing flow-back fluid to be detected according to the flow rate, the first amplitude and the second amplitude of the fracturing flow-back fluid to be detected, and the first amplitude and the hydrogen-containing index of a free attenuation signal corresponding to water and oil in the multiphase flow sample;
and determining the gas content and the solid content in the fracturing flowback fluid to be tested according to the second echo signal and the diffusion coefficient, the water content and the oil content of the multiphase flow sample corresponding to water, oil and gas.
CN202011445815.2A 2020-12-11 2020-12-11 Method for detecting solid content of fracturing flowback fluid Pending CN114624273A (en)

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