CN112578457A - Optical fiber borehole earthquake monitoring method for carbon dioxide driven coal bed gas - Google Patents
Optical fiber borehole earthquake monitoring method for carbon dioxide driven coal bed gas Download PDFInfo
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- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 title claims abstract description 86
- 229910002092 carbon dioxide Inorganic materials 0.000 title claims abstract description 43
- 239000001569 carbon dioxide Substances 0.000 title claims abstract description 43
- 238000000034 method Methods 0.000 title claims abstract description 40
- 239000003245 coal Substances 0.000 title claims abstract description 25
- 239000013307 optical fiber Substances 0.000 title claims abstract description 24
- 238000012544 monitoring process Methods 0.000 title claims abstract description 23
- 238000012545 processing Methods 0.000 claims abstract description 58
- 238000003384 imaging method Methods 0.000 claims abstract description 31
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 claims abstract description 16
- 230000000694 effects Effects 0.000 claims abstract description 11
- 230000005284 excitation Effects 0.000 claims description 34
- 238000006467 substitution reaction Methods 0.000 claims description 21
- 238000004458 analytical method Methods 0.000 claims description 15
- 238000004364 calculation method Methods 0.000 claims description 12
- 238000012937 correction Methods 0.000 claims description 9
- 230000002159 abnormal effect Effects 0.000 claims description 6
- 238000002347 injection Methods 0.000 claims description 4
- 239000007924 injection Substances 0.000 claims description 4
- 239000004568 cement Substances 0.000 claims description 3
- 230000008859 change Effects 0.000 claims description 3
- 238000013461 design Methods 0.000 claims description 3
- 238000001514 detection method Methods 0.000 claims description 3
- 238000009826 distribution Methods 0.000 claims description 3
- 238000012067 mathematical method Methods 0.000 claims description 3
- 230000008569 process Effects 0.000 claims description 3
- 230000001932 seasonal effect Effects 0.000 claims description 3
- 238000000605 extraction Methods 0.000 claims description 2
- 238000013508 migration Methods 0.000 abstract description 7
- 230000005012 migration Effects 0.000 abstract description 7
- 239000000835 fiber Substances 0.000 description 5
- 238000005516 engineering process Methods 0.000 description 3
- 238000011160 research Methods 0.000 description 3
- 238000004519 manufacturing process Methods 0.000 description 2
- 230000004075 alteration Effects 0.000 description 1
- 230000009286 beneficial effect Effects 0.000 description 1
- 230000007547 defect Effects 0.000 description 1
- 238000011161 development Methods 0.000 description 1
- 230000004044 response Effects 0.000 description 1
- 238000005070 sampling Methods 0.000 description 1
- 238000003860 storage Methods 0.000 description 1
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
- G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
-
- G01V1/01—
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
- G01V1/28—Processing seismic data, e.g. analysis, for interpretation, for correction
- G01V1/30—Analysis
- G01V1/306—Analysis for determining physical properties of the subsurface, e.g. impedance, porosity or attenuation profiles
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
- G01V1/28—Processing seismic data, e.g. analysis, for interpretation, for correction
- G01V1/34—Displaying seismic recordings or visualisation of seismic data or attributes
- G01V1/345—Visualisation of seismic data or attributes, e.g. in 3D cubes
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
- G01V1/28—Processing seismic data, e.g. analysis, for interpretation, for correction
- G01V1/36—Effecting static or dynamic corrections on records, e.g. correcting spread; Correlating seismic signals; Eliminating effects of unwanted energy
- G01V1/362—Effecting static or dynamic corrections; Stacking
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V2210/00—Details of seismic processing or analysis
- G01V2210/50—Corrections or adjustments related to wave propagation
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V2210/00—Details of seismic processing or analysis
- G01V2210/60—Analysis
- G01V2210/62—Physical property of subsurface
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V2210/00—Details of seismic processing or analysis
- G01V2210/70—Other details related to processing
- G01V2210/74—Visualisation of seismic data
Abstract
The invention discloses an optical fiber borehole earthquake monitoring method for carbon dioxide driven coal bed gas, which comprises the following steps: s1, collecting seismic data in the time-lapse well; s2, processing the seismic data in the time shift well; s3, performing difference imaging on the time-shifting well seismic data to obtain the velocity difference of seismic wave propagation and the well seismic data difference imaging result; and S4, analyzing the carbon dioxide driving effect, and analyzing the carbon dioxide driving effect by using the seismic wave propagation velocity difference and the well seismic data difference imaging result obtained in the step S3 to obtain a final prediction result. The method solves the problem of consistency in acquisition, processing and interpretation of the time-lapse seismic data, and provides reliable technical support for coal bed methane migration and alternative condition monitoring.
Description
Technical Field
The invention belongs to seismic data acquisition, processing and interpretation technologies in geophysical exploration, relates to an injection-production monitoring technology of carbon dioxide driven coal bed gas, belongs to the geophysical category in a time-shifting well, and particularly relates to an optical fiber borehole seismic monitoring method of carbon dioxide driven coal bed gas.
Background
Time-lapse or four-dimensional seismic is the proven most effective method for carbon dioxide storage and carbon dioxide-driven reservoir monitoring, but it is costly and has low economic benefits. In addition, the migration and replacement of the carbon dioxide-driven coal bed gas are difficult to monitor, the mode of 'gas-driven gas' and 'gas replacement gas' has very weak influence on seismic response, and a seismic observation method with better consistency and higher precision is needed, so that how to carry out an economic and effective monitoring method or integrate and innovate a plurality of methods into an economic and effective monitoring technical system is a key scientific problem to be solved urgently.
With the gradual maturity of the distributed optical fiber sensing (DAS) technology in recent years, borehole seismic data with higher spatial sampling rate and better consistency can be obtained, preconditions are provided for carbon dioxide-driven coal bed methane migration and alternative condition monitoring, and positive significance is provided for research in aspects such as coal bed methane exploration and development.
Disclosure of Invention
The invention aims to overcome the defects of the prior art, provides a method for monitoring migration and substitution conditions of coal bed gas by using carbon dioxide, solves the problem of consistency in acquisition, processing and explanation of time-lapse seismic data, and provides reliable technical support for monitoring migration and substitution conditions of coal bed gas.
The purpose of the invention is realized by the following technical scheme: an optical fiber borehole earthquake monitoring method for carbon dioxide driven coal bed gas comprises the following steps:
s1, collecting seismic data in the time-lapse well;
s2, processing the seismic data in the time shift well;
s3, performing difference imaging on the time-shifting well seismic data to obtain the velocity difference of seismic wave propagation and the well seismic data difference imaging result;
and S4, analyzing the carbon dioxide driving effect, and analyzing the carbon dioxide driving effect by using the seismic wave propagation velocity difference and the well seismic data difference imaging result obtained in the step S3 to obtain a final prediction result.
Further, the specific implementation method of step S1 is as follows: acquiring seismic data in the time-lapse well by utilizing the existing excitation and receiving equipment with the best consistency; the method comprises the following substeps:
s11, determining a consistency acquisition observation system: designing a seismic data acquisition observation system in a time-shifting well with two or more periods by using the existing observation system design method and software;
the time-lapse borehole seismic refers to multiple-period seismic data recorded in a borehole;
s12, determination of excitation point positions and excitation parameters: measuring and selecting an excitation point position with stable excitation environment, exciting seismic data by using a controllable seismic source, and requiring that the types of the seismic source of multiple periods are strictly consistent with excitation parameters;
the stable excitation point position is an excitation point position which has stable surface lithology, is convenient to transport and is not influenced greatly by seasonal changes and human activities;
the vibroseis excitation is to perform excitation operation on the selected point by using a vibroseis vehicle;
s13, determination of receiving mode and receiving parameter: recording seismic data in a well by adopting a receiving mode of arranging distributed optical fibers outside a sleeve, wherein the distance between the distributed optical fibers is not more than 1 m;
the receiving mode of arranging the distributed optical fiber outside the casing is that the distributed optical fiber is arranged outside the casing of the well and is cemented by cement.
Further, the specific implementation method of step S2 is as follows:
s21, determining consistency of the processing flow, and establishing a time-shifting borehole seismic consistency processing flow as a standard flow for processing the multi-period borehole seismic data;
the consistency processing flow refers to a well seismic data processing flow with improved consistency requirements, and is established according to the technical specification SYT 7450-2019 for well seismic data processing and interpretation;
excitation point consistency processing is not included in the consistency processing flow, and the step can change the data amplitude distribution relation of the time-lapse earthquake;
s22, determining consistency of processing parameters, and selecting consistency processing parameters to process time-lapse borehole seismic data according to a consistency processing flow;
s23, residual difference correction with the first arrival as a standard, and residual amplitude difference correction with the first arrival amplitude as a standard is carried out on the consistency processing result;
the first arrival refers to a direct down-going wave of a borehole seismic and is the most stable wave field in borehole seismic data;
and the residual amplitude difference correction refers to a method for eliminating the residual difference of the time shift data by using a mathematical method, and the selected first arrival wave is the upper part of well section data of the gas flooding operation.
Further, the specific implementation method of step S3 is as follows:
s31, calculating the velocity difference of seismic wave propagation, picking up the time-depth relation of first arrival waves by using the seismic data acquired in the step S1, calculating to obtain the seismic wave velocity, carrying out quotient calculation on the seismic wave velocity at the same depth, and defining the calculation result as seismic velocity difference data;
and S32, carrying out data amplitude difference imaging processing, namely obtaining imaging results of multiple periods by using the processed data of the multiple periods obtained in the step S2 according to the seismic wave velocity by adopting the conventional borehole seismic imaging method, and carrying out subtraction calculation to obtain difference imaging processing for time shift analysis.
The subtraction calculation refers to subtracting seismic data with the same size.
Further, the specific implementation method of step S4 is as follows:
s41, estimation and analysis of driving substitution conditions: estimating the driving substitution condition by using the velocity difference result of seismic wave propagation obtained in the step S3, specifically, estimating the velocity difference result, and defining that the velocity difference is less than 1% as a low substitution rate, 1% to 3% as a medium substitution rate and more than 3% as a high substitution rate according to an empirical injection-production ratio of 5: 1;
s42, detection and analysis of driving edges: predicting to obtain a carbon dioxide driving front analysis result by using the well seismic data difference imaging result obtained in the step S3;
the carbon dioxide-driven front edge is used for identifying an abnormal area in differential imaging and reading the maximum transverse distance which can be reached by the abnormal area.
The invention has the beneficial effects that: the invention provides a method for monitoring migration and substitution conditions of coal bed gas by using carbon dioxide, which solves the problem of consistency in acquisition, processing and explanation of time-lapse seismic data and provides reliable technical support for monitoring migration and substitution conditions of coal bed gas.
Drawings
FIG. 1 is a flow chart of a fiber optic borehole seismic monitoring method of the present invention;
FIG. 2 is a flow chart of the present invention for acquiring seismic data in a time-lapse well;
FIG. 3 is a flow chart of the present invention for processing seismic data in a time-lapse well;
FIG. 4 is a flow chart of the present invention for differentially imaging seismic data in a time-lapse well;
FIG. 5 is a flow chart of the carbon dioxide driven effectiveness analysis performed in the present invention;
FIG. 6 is a graph of fiber optic borehole seismic model data prior to carbon dioxide actuation in this example;
FIG. 7 is a graph of seismic model data in a fiber optic well after carbon dioxide actuation in this example;
FIG. 8 is a difference seismic data before and after carbon dioxide actuation in this example;
fig. 9 is a comparison (right) of the difference result (left) after driving and the initial model in the present embodiment.
Detailed Description
The technical scheme of the invention is further explained by combining the attached drawings.
As shown in FIG. 1, the optical fiber borehole earthquake monitoring method for carbon dioxide-driven coal bed methane comprises the following steps:
s1, collecting seismic data in the time-lapse well; the specific implementation method comprises the following steps: acquiring seismic data in the time-lapse well by utilizing the existing excitation and receiving equipment with the best consistency, as shown in figure 2; the method comprises the following substeps:
s11, determining a consistency acquisition observation system: designing a seismic data acquisition observation system in a time-shifting well with two or more periods by using the existing observation system design method and software;
the time-lapse borehole seismic refers to multiple-period seismic data recorded in a borehole;
optionally, the two-stage or multi-stage time-shifting borehole seismic data acquisition observation system can acquire data in stages or continuously, and the acquisition mode depends on the field requirement of coal bed gas monitoring.
S12, determination of excitation point positions and excitation parameters: measuring and selecting an excitation point position with stable excitation environment, exciting seismic data by using a controllable seismic source, and requiring that the types of the seismic source of multiple periods are strictly consistent with excitation parameters;
the stable excitation point position is an excitation point position which has stable surface lithology, is convenient to transport and is not influenced greatly by seasonal changes and human activities;
the vibroseis excitation is to use a vibroseis vehicle to carry out excitation operation at a selected point, and the output consistency of the vibroseis is widely accepted in the industry, so that the vibroseis is the best excitation mode for seismic research in the current time-shifting well;
s13, determination of receiving mode and receiving parameter: recording borehole seismic data by adopting a receiving mode of arranging a distributed optical fiber outside a sleeve, wherein the distance between the distributed optical fibers is not more than 1m, and the recording parameters of multiple periods are required to be strictly consistent;
the receiving mode of arranging the distributed optical fiber outside the casing is to arrange the distributed optical fiber outside the casing of the well and fix the well by using cement, which is the best data receiving and recording mode for seismic research in the current time-shifting well.
S2, processing the seismic data in the time shift well; as shown in fig. 3, the specific implementation method is as follows:
s21, determining consistency of the processing flow, and establishing a time-shifting borehole seismic consistency processing flow as a standard flow for processing the multi-period borehole seismic data;
the consistency processing flow refers to a well seismic data processing flow with improved consistency requirements, and is established according to the technical specification SYT 7450-2019 for well seismic data processing and interpretation;
excitation point consistency processing is not included in the consistency processing flow, and the step can change the data amplitude distribution relation of the time-lapse earthquake;
s22, determining consistency of processing parameters, and selecting consistency processing parameters to process time-lapse borehole seismic data according to a consistency processing flow;
the consistency processing parameters comprise various parameters such as time window length, participating channel number, compensation parameters and the like involved in the processing steps, so that processing personnel are required to fully know the used software, and processing differences caused by parameter changes in the module are prevented.
S23, residual difference correction with the first arrival as a standard, residual amplitude difference correction with the first arrival amplitude as a standard is carried out on the consistency processing result, and the consistency of the data in the processing is further improved;
the first arrival refers to a direct down-going wave of a borehole seismic and is the most stable wave field in borehole seismic data;
and the residual amplitude difference correction refers to a method for eliminating the residual difference of the time shift data by using a mathematical method, and the selected first arrival wave is the upper part of well section data of the gas flooding operation.
S3, carrying out difference imaging on the time-shifting borehole seismic data subjected to consistency processing and obtained in the step S2 to obtain the seismic wave propagation speed difference and borehole seismic data difference imaging results; as shown in fig. 4, the specific implementation method is as follows:
s31, calculating the velocity difference of seismic wave propagation, picking up the time-depth relation of first arrival waves by using the seismic data acquired in the step S1, calculating to obtain the seismic wave velocity, carrying out quotient calculation on the seismic wave velocity at the same depth, and defining the calculation result as seismic velocity difference data;
and S32, carrying out data amplitude difference imaging processing, namely obtaining imaging results of multiple periods by using the processed data of the multiple periods obtained in the step S2 according to the seismic wave velocity by adopting the conventional borehole seismic imaging method, and carrying out subtraction calculation to obtain difference imaging processing for time shift analysis.
The subtraction calculation, which is to subtract seismic data of the same size, is a common method for time-lapse seismic processing, but needs to be careful to ensure consistency of frequency, amplitude and phase.
S4, analyzing the carbon dioxide driving effect, and analyzing the carbon dioxide driving effect by using the seismic wave propagation velocity difference and the well seismic data difference imaging result obtained in the step S3 to obtain a final prediction result;
as shown in fig. 5, the specific implementation method is as follows:
s41, estimation and analysis of driving substitution conditions: estimating the driving substitution condition by using the velocity difference result of seismic wave propagation obtained in the step S3, specifically, estimating the velocity difference result, extracting 1-square coal bed gas according to an empirical injection-extraction ratio of 5:1, needing 5-square carbon dioxide injection, calculating seismic velocity difference data after the carbon dioxide injection, and quantitatively estimating the substitution rate of the coal bed gas according to the seismic velocity difference, wherein the velocity difference is defined as a low substitution rate when the velocity difference is less than 1%, a medium substitution rate when the velocity difference is 1-3% and a high substitution rate when the velocity difference is more than 3%;
s42, detection and analysis of driving edges: performing seismic difference imaging by using the borehole seismic data obtained in the step S3, and predicting a carbon dioxide-driven front analysis result based on the result;
the analysis of the carbon dioxide driving front edge refers to identifying an abnormal area in which the absolute value of the amplitude of vibration appearing in the difference imaging is obviously higher than that of background data, and the maximum transverse distance which can be reached by reading the abnormal area is the driving front edge.
FIG. 6 is a graph of seismic model data in a fiber optic well before carbon dioxide actuation in this example, where the abscissa is depth in m; the ordinate is time in ms. FIG. 7 is a graph of seismic model data in a fiber optic well after carbon dioxide actuation in this example, with depth on the abscissa in m; the ordinate is time in ms. FIG. 8 is differential seismic data before and after carbon dioxide actuation for this embodiment, where the abscissa is depth in m; the ordinate is time in ms. FIG. 9 is a comparison of the post-drive aberration results (left) and the initial model (right) in this example, where the abscissa is the CDP track number, dimensionless; the ordinate is depth in m.
It will be appreciated by those of ordinary skill in the art that the embodiments described herein are intended to assist the reader in understanding the principles of the invention and are to be construed as being without limitation to such specifically recited embodiments and examples. Those skilled in the art can make various other specific changes and combinations based on the teachings of the present invention without departing from the spirit of the invention, and these changes and combinations are within the scope of the invention.
Claims (5)
1. An optical fiber borehole earthquake monitoring method for carbon dioxide driven coal bed gas is characterized by comprising the following steps:
s1, collecting seismic data in the time-lapse well;
s2, processing the seismic data in the time shift well;
s3, performing difference imaging on the time-shifting well seismic data to obtain the velocity difference of seismic wave propagation and the well seismic data difference imaging result;
and S4, analyzing the carbon dioxide driving effect, and analyzing the carbon dioxide driving effect by using the seismic wave propagation velocity difference and the well seismic data difference imaging result obtained in the step S3 to obtain a final prediction result.
2. The optical fiber borehole seismic monitoring method for carbon dioxide-driven coal bed methane according to claim 1, wherein the step S1 is realized by: acquiring seismic data in the time-lapse well by utilizing the existing excitation and receiving equipment with the best consistency; the method comprises the following substeps:
s11, determining a consistency acquisition observation system: designing a seismic data acquisition observation system in a time-shifting well with two or more periods by using the existing observation system design method and software;
the time-lapse borehole seismic refers to multiple-period seismic data recorded in a borehole;
s12, determination of excitation point positions and excitation parameters: measuring and selecting an excitation point position with stable excitation environment, exciting seismic data by using a controllable seismic source, and requiring that the types of the seismic source of multiple periods are strictly consistent with excitation parameters;
the stable excitation point position is an excitation point position which has stable surface lithology, is convenient to transport and is not influenced greatly by seasonal changes and human activities;
the vibroseis excitation is to perform excitation operation on the selected point by using a vibroseis vehicle;
s13, determination of receiving mode and receiving parameter: recording seismic data in a well by adopting a receiving mode of arranging distributed optical fibers outside a sleeve, wherein the distance between the distributed optical fibers is not more than 1 m;
the receiving mode of arranging the distributed optical fiber outside the casing is that the distributed optical fiber is arranged outside the casing of the well and is cemented by cement.
3. The optical fiber borehole seismic monitoring method for carbon dioxide-driven coal bed methane according to claim 1, wherein the step S2 is realized by:
s21, determining consistency of the processing flow, and establishing a time-shifting borehole seismic consistency processing flow as a standard flow for processing the multi-period borehole seismic data;
the consistency processing flow refers to a well seismic data processing flow with improved consistency requirements, and is established according to the technical specification SYT 7450-2019 for well seismic data processing and interpretation;
excitation point consistency processing is not included in the consistency processing flow, and the step can change the data amplitude distribution relation of the time-lapse earthquake;
s22, determining consistency of processing parameters, and selecting consistency processing parameters to process time-lapse borehole seismic data according to a consistency processing flow;
s23, residual difference correction with the first arrival as a standard, and residual amplitude difference correction with the first arrival amplitude as a standard is carried out on the consistency processing result;
the first arrival refers to a direct down-going wave of a borehole seismic and is the most stable wave field in borehole seismic data;
and the residual amplitude difference correction refers to a method for eliminating the residual difference of the time shift data by using a mathematical method, and the selected first arrival wave is the upper part of well section data of the gas flooding operation.
4. The optical fiber borehole seismic monitoring method for carbon dioxide-driven coal bed methane according to claim 1, wherein the step S3 is realized by:
s31, calculating the velocity difference of seismic wave propagation, picking up the time-depth relation of first arrival waves by using the seismic data acquired in the step S1, calculating to obtain the seismic wave velocity, carrying out quotient calculation on the seismic wave velocity at the same depth, and defining the calculation result as seismic velocity difference data;
and S32, carrying out data amplitude difference imaging processing, namely obtaining imaging results of multiple periods by using the processed data of the multiple periods obtained in the step S2 according to the seismic wave velocity by adopting the conventional borehole seismic imaging method, and carrying out subtraction calculation to obtain difference imaging processing for time shift analysis.
The subtraction calculation refers to subtracting seismic data with the same size.
5. The optical fiber borehole seismic monitoring method for carbon dioxide-driven coal bed methane according to claim 1, wherein the step S4 is realized by:
s41, estimation and analysis of driving substitution conditions: estimating the driving substitution condition by using the velocity difference result of seismic wave propagation obtained in the step S3, specifically, estimating the velocity difference result, extracting 1-square coal bed gas according to an empirical injection-extraction ratio of 5:1, needing 5-square carbon dioxide injection, calculating seismic velocity difference data after the carbon dioxide injection, and quantitatively estimating the substitution rate of the coal bed gas according to the seismic velocity difference, wherein the velocity difference is defined as a low substitution rate when the velocity difference is less than 1%, a medium substitution rate when the velocity difference is 1-3% and a high substitution rate when the velocity difference is more than 3%;
s42, detection and analysis of driving edges: performing seismic difference imaging by using the borehole seismic data obtained in the step S3, and predicting a carbon dioxide-driven front analysis result based on the result;
the analysis of the carbon dioxide driving front edge refers to identifying an abnormal area in which the absolute value of the amplitude of vibration appearing in the difference imaging is obviously higher than that of background data, and the maximum transverse distance which can be reached by reading the abnormal area is the driving front edge.
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