SY/T 10020-1998 Technical Guide for Offshore 2D Seismic Data Processing
Some standard content:
ICS75.020
Registration No.: 1890--1998
Offshore oil and gas industry standard of the People's Republic of China SY/T10020—1998
Technical Guide for Marine 2-D Seismic Data Processing1998-06-07 Issued
Implementation on 1998-10-01
Issued by China National Offshore Oil Corporation
SY/T 10020—1998
Policy Statement
2 Original data.
3 Data processing
Pre-delivery depth migration
Processing results and data archiving
SY/T10020—1998
This standard is formulated based on the development of offshore secondary seismic data processing technology and the experience of foreign companies in processing offshore data, in accordance with the requirements of (B\T1.「一1993, and with reference to the enterprise standard Q/CXGC.T103.03-1995. Compared with Q/CC.T103.031995, in addition to adding the subsection and the foreword, major changes have been made in the content and structure, which are mainly reflected in the following aspects: First, the two-dimensional pre-selection depth migration has been added; second, the "data processing contract" has been deleted; first, the requirements for users have been deleted. Requirements; Fourth, some chapters and articles have been revised and supplemented; for example, the original Chapter 5 is divided into two parts according to the content attributes: the data processing part is one chapter, and the relevant results part is another chapter; Fifth, the positioning data is treated as an independent chapter. This standard basically reflects the technical requirements for offshore two-dimensional geophysical data processing in Guangdong. This standard shall be implemented from October 1, 1998. This standard is proposed and managed by China National Offshore Oil Corporation. Drafting unit of this standard: China National Offshore Oil Corporation: The main drafters of this standard: Ou Shouquan, Lin Jiwu, Zhang Yang. The chief reviewer of this standard: Zhang Zhenping.
Policy Statement
Offshore oil and natural gas industry standard publications only address general issues. When it comes to specific situations, national and local laws and regulations should be consulted. Laws and regulations.
Offshore oil and gas industry standards publications do not undertake to provide users, manufacturers or suppliers with advance notice and training on health, safety and hazard prevention for their employees and other on-site operators, nor do they assume any responsibilities under national and local regulations. The content of any offshore oil and gas industry standards publication cannot be interpreted, implicitly or otherwise, as granting any right to manufacture, sell or use any method, equipment or product involving patent rights, nor does it assume liability for any person who infringes patent rights. Generally, offshore oil and gas industry standards are reviewed and revised, or re-identified or revoked at least every five years. Sometimes, this review cycle can be extended by one year, but not more than two years. Therefore, from the date of publication, the publication The validity period shall not exceed five years unless the validity period is extended by authorization. The status of publications can be obtained from the Secretariat of the Offshore Oil and Gas Industry Standardization Technical Committee (Tel. 010-64610022-7875, mailing address: Standardization Office, Offshore Oil Production Research Center, Box 235, Beijing, 101149) or the Offshore Oil and Gas Industry Standardization Technical Committee (Tel. 010-64665361, mailing address: Offshore Oil Science and Technology Office, 25th Floor, Dongjingxin Building, Sanyuanqiao, Beijing, 100027).
The purpose of publishing offshore oil and gas industry standards is to promote proven and good engineering technologies and operating practices. It is not intended to eliminate the need to make correct judgments on when and where to apply these technologies and practices. The formulation and publication of offshore oil and gas industry standards are not intended to restrict anyone from adopting any other technologies and practices in any way. This standard is available for use by anyone who wishes to adopt it. The Offshore Oil and Gas Industry Standardization Technical Committee and its authorized issuing units have made unremitting efforts to ensure the accuracy and reliability of the data contained therein. However, the Offshore Oil and Gas Industry Standardization Technical Committee and its authorized issuing units do not represent, guarantee or warrant the standards they publish, and hereby expressly state that they do not assume any obligation or responsibility for any loss or damage caused by the use of these standards, for the use of standards that may conflict with any national or local regulations, and for the consequences of infringement of any patent rights caused by the use of these standards.
Technical Guide for Marine 2-DSeismic Data Processing
This specification specifies the technical requirements for offshore 2-DSeismic data processing. This specification applies to offshore 2-DSeismic data processing. 2 Original data
All original data should be prepared before processing 2-DSeismic data. 2.1 Seismic instrument recording shift report
Main contents include:
Construction area:
Ship number, team number, construction date:
Survey line number;
Construction direction:
Tape reel number:
Water depth;
Cable feather angle:
Wind speed, wave height:
Gun number and record number should be written neatly and clearly. If the gun number and record number do not correspond, a clear note should be made. Recording factors, including instrument type, recording format, sampling rate, recording length, recording density SY/T10020-1998
Excitation factors, including shot point spacing, excitation method, total airgun capacity, airgun working pressure, source sinking depth, delay time; Receiving factors, including cable track number, track spacing, offset distance near source track number, cable sinking depth: Construction system configuration diagram:
Remarks;
Operator signature.
2.2 Observation system diagram.
2.3 Seismic data tape
Seismic data tape is a field data tape or a copy tape after the field tape is converted into a format. The label should indicate: area name, survey line number, tape number, start and end file number, start and end shot number, recording format, recording length and sampling rate, etc. 2.4 Seismic wavelet.
3 Positioning data
3.1 Survey line location map.
3.2 Intersection table of survey lines in the work area or shot point coordinate data in UKOOA format. Approved by China National Offshore Oil Corporation on June 7, 1998 and implemented on October 1, 1998
4 Data processing
4.1 Main items and technical requirements of data processing 4.1.1 Data format conversion and resampling
SY/T10020-1998
4.1.1.1 Data format conversion is to convert the input data into data used by the processing system 4.1.1.2 Resampling should remove aliasing
4.1.2 Bad shot, channel editing and pre-selection denoising
Delete abnormal shots, avoidance and wild values, eliminate noise that affects the selection effect, and improve the signal-to-noise ratio. 4.1.3 Define the observation system
Determine the positions of shot points and wave picking points according to the acquisition situation, and the position of the common center point is correct. 4.1.4 Amplitude compensation
Eliminate the attenuation of the amplitude of seismic waves during propagation. 4.1.5 Source wavelet deconvolution
Shape the source wavelet to improve the resolution of seismic records. 4.1.6 Deconvolution
Attenuate multiple waves and shrink seismic wavelets to improve resolution. 4.1.7 Static correction
4.1.7.1 The source instrument delay correction, the cable and source correction to the sea level. 4.1.7.2 The data collected by the submarine cable should be processed by residual static correction. When calculating the residual static correction, the window is selected on the layer with strong reflection and good continuity. The quality of the profile after residual static correction is not lower than that before static correction: 4.1.8 Velocity analysis
4.1.8,1 Select the density of velocity analysis points according to the formation dip angle, at least one per kilometer, the larger the dip angle, the larger the density. 4.1.8.2 Select the appropriate number of common center point gathers. Generally, the larger the inclination angle, the fewer the gathers, the lower the signal-to-noise ratio of the seismic signal, and the more gathers there are, the more accurate the prediction speed.
4.1.8.3
4.1.8.4 Combined with the initial section, considering the changes in geological structure, the velocity is picked up accurately. 4.1.9 Dip Move Correction (DMO)
LMO eliminates the influence of the inclination angle on the velocity. The IDMO generates gathers and performs DMO velocity analysis. The velocity of the inclined stratum should be reduced, otherwise the cause should be found.
4.1.10 Dynamic Correction and Delivery
4.1.10.1 Make the selected velocity do normal time differential dynamic correction (VM0) selection. The cutting parameters are required to be combined, and the near track should be retained for the towed cable acquisition data.
4.1.10,2 The quality of the delivery section should be better than the previous delivery section, 4.110.3IDMO channel set selection should have a higher signal-to-noise ratio, and NMO channel addition is preferred in multi-angle reflection simultaneous imaging. 4.1.11 Eliminate multiple waves
On the premise of retaining and highlighting secondary reflection waves, try to weaken and eliminate multiple waves4.1.12 Post-transmission time migration
4.1.12.1 The effective wave of the result profile after migration is reasonably returned, and the breakpoint and section are clear4.1.12.2 To improve the processing effect, velocity smoothing and inlay channel addition can be performed. 4.1.12.3 When the signal-to-noise ratio of the transmission surface is relatively low, post-transmission denoising is performed4.1.13 Improve signal-to-noise ratio and resolution
After improving the signal-to-noise ratio, the signal-to-noise ratio of the profile is improved; after improving the resolution, the resolution is improved, and the signal-to-noise ratio cannot be significantly reduced. 4.1.14 Determine the relationship between positioning data and shot point position. Clarify the relationship between the geographical location determined by the shot number in the seismic track header and the positioning data: 2
4.1.15 Filtering
SY/T10020—1998
Use the frequency scanning method to determine the filtering time window and frequency range. 4.1.16 Amplitude equalization
After amplitude equalization processing, the characteristics of the effective reflection phase axis wave group are clear: 4.1.17 Intermediate results display
The display direction and display parameters should be consistent
4.2 Processing test
4.2.1 Test processing flow
The processing flow consists of a series of processing modules. The following factors should be considered when selecting the processing flow: a) underground geological conditions and exploration targets: b) location of the work area and construction conditions; () quality of original data; d) previous processing experience.
4.2.2 Test items
4.2.2.1 Mandatory items
Contents include:
a) Amplitude compensation;
b) Pre-send deconvolution;
) Send addition;
d) Offset;
|) Amplitude equalization:
f) Filtering:
|) Display,
4.2.2.2 Optional items
Contents include:
a) Removal:
b) Pre-send and post-send deconvolution:
c) Source wavelet deconvolution;
e) Pre-send and post-send frequency compensation to improve resolution:
e) Multiple wave removal:
4.2.3 Test method requirements
For the test items, use a single parameter change to process, according to 2.1 Select items and processing parameters according to the processing effect. 4.3 Quality control of batch processing
4.3.1 Batch processing flow
The batch processing flow is determined according to 4.2:
4.3.2 Quality control
4.3.2.1 Data format conversion
Internal package:
a) Display single shot and single channel according to the actual processing, and determine bad shot, bad channel and lost shot and channel; b) The rate of lost shot and channel is not more than 1%, and the continuous lost shot is not more than 2 shots. If this limit is exceeded, it must be proved that it is an input belt problem. 4.3.2.2 Observation system
Define the observation system, batch common center point gather: 4.3.2.3 Static correction
SY/T10020-1998
Check the static correction value and the selected sections before and after static correction. 4.3.2.4 Velocity analysis
Contents include:
a) Check velocity point correction gathers;
b) Other velocity rationality check methods.
5 Pre-stack depth migration
5.1 Original data
The same as the offshore 2D data processing. bzxz.net
5.1.1 Data processing
Same as 4.1.1~4.1.8, 4.1.11.
5.1.2 Establishing layer model
Use the post-selection time migration section for geological interpretation (velocity layer interpretation). 5.1.3 Establishing initial velocity model
The Dix formula can be used to convert the selected acceleration into layer velocity. 5.1.4 Tomography of velocity model
Use the velocity model for tomography inversion. 5.1.5 Residual velocity analysis
Carry out velocity analysis layer by layer from shallow to deep, flatten the common reflection point (CRP) gathers, and generate a new velocity model. 5.1.6 Migration
Use the velocity model to perform pre-selected depth migration and multiple iterations. If you are still not satisfied after multiple iterations, you can repeat 5.1.3~5.1.6 until you are satisfied.
5.2 Test items
In addition to being consistent with the content of two-dimensional processing, it should also include: a) the depth sampling rate calculated based on the time and layer velocity of the target layer; b) the migration aperture calculated based on the maximum time difference of the maximum time of the profile. 5.3 Batch processing and quality control
Same as 4.3.1~4.3.2
6 Processing results and data archiving
6.1 Result profile display
6.1.1 Result medium.
6.1.2 The section top shall display the shot number, velocity parameters of the velocity analysis point, intersection with other survey lines, and water depth. 6.1.3 Time scales shall be noted on both sides of the section.
6.1.4 The header
The content shall include:
a) User name;
Work area name, survey line name, section type:
Field acquisition parameters;
Basic processing flow and main processing parameters; d)
Display direction, vertical and horizontal scales, and polarity of processed data recording. 6.2 Submission of results
The submitted results should include:
a) SEG-Y format result band;
Result profile;
SY/T10020-1998
Velocity spectrum bound in book and velocity data recorded in ASCII code: Processing report:
1) Geological tasks and processing requirements;
Processing workload and start and end dates;
Original data quality analysis
Processing process design and parameter test analysis; 4)
Processing process and effect analysis;
Problems encountered in processing and solutions
Existing problems and suggestions;
Result band list.
6.3 Archived data
Mainly include:
Selected and offset SEG-Y format data bands and corresponding lists; a)
Velocity spectrum and velocity data recorded in ASCI code; film display result profile;
Processing report.1 Batch processing flow
Batch processing flow is determined according to 4.2:
4.3.2 Quality control
4.3.2.1 Data format conversion
Inner package:
a) Display single shot and single channel according to actual processing, determine bad shot, bad channel and lost shot and channel; b) The rate of lost shot and channel is not more than 1%, and the continuous lost shot is not more than 2 shots. If it exceeds this limit, it must be proved that it is an input belt problem. 4.3.2.2 Observation system
Define the observation system and batch common center point channel gather: 4.3.2.3 Static correction
SY/T10020-1998
Check the static correction value and the selected sections before and after static correction. 4.3.2.4 Velocity analysis
Contents include:
a) Check velocity point correction gathers;
b) Other velocity rationality check methods.
5 Pre-stack depth migration
5.1 Original data
The same as the offshore 2D data processing.
5.1.1 Data processing
Same as 4.1.1~4.1.8, 4.1.11.
5.1.2 Establishing layer model
Use the post-selection time migration section for geological interpretation (velocity layer interpretation). 5.1.3 Establishing initial velocity model
The Dix formula can be used to convert the selected acceleration into layer velocity. 5.1.4 Tomography of velocity model
Use the velocity model for tomography inversion. 5.1.5 Residual velocity analysis
Carry out velocity analysis layer by layer from shallow to deep, flatten the common reflection point (CRP) gathers, and generate a new velocity model. 5.1.6 Migration
Use the velocity model to perform pre-selected depth migration and multiple iterations. If you are still not satisfied after multiple iterations, you can repeat 5.1.3~5.1.6 until you are satisfied.
5.2 Test items
In addition to being consistent with the content of two-dimensional processing, it should also include: a) the depth sampling rate calculated based on the time and layer velocity of the target layer; b) the migration aperture calculated based on the maximum time difference of the maximum time of the profile. 5.3 Batch processing and quality control
Same as 4.3.1~4.3.2
6 Processing results and data archiving
6.1 Result profile display
6.1.1 Result medium.
6.1.2 The section top shall display the shot number, velocity parameters of the velocity analysis point, intersection with other survey lines, and water depth. 6.1.3 Time scales shall be noted on both sides of the section.
6.1.4 The header
The content shall include:
a) User name;
Work area name, survey line name, section type:
Field acquisition parameters;
Basic processing flow and main processing parameters; d)
Display direction, vertical and horizontal scales, and polarity of processed data recording. 6.2 Submission of results
The submitted results should include:
a) SEG-Y format result band;
Result profile;
SY/T10020-1998
Velocity spectrum bound in book and velocity data recorded in ASCII code: Processing report:
1) Geological tasks and processing requirements;
Processing workload and start and end dates;
Original data quality analysis
Processing process design and parameter test analysis; 4)
Processing process and effect analysis;
Problems encountered in processing and solutions
Existing problems and suggestions;
Result band list.
6.3 Archived data
Mainly include:
Selected and offset SEG-Y format data bands and corresponding lists; a)
Velocity spectrum and velocity data recorded in ASCI code; film display result profile;
Processing report.1 Batch processing flow
Batch processing flow is determined according to 4.2:
4.3.2 Quality control
4.3.2.1 Data format conversion
Inner package:
a) Display single shot and single channel according to actual processing, determine bad shot, bad channel and lost shot and channel; b) The rate of lost shot and channel is not more than 1%, and the continuous lost shot is not more than 2 shots. If it exceeds this limit, it must be proved that it is an input belt problem. 4.3.2.2 Observation system
Define the observation system and batch common center point channel gather: 4.3.2.3 Static correction
SY/T10020-1998
Check the static correction value and the selected sections before and after static correction. 4.3.2.4 Velocity analysis
Contents include:
a) Check velocity point correction gathers;
b) Other velocity rationality check methods.
5 Pre-stack depth migration
5.1 Original data
The same as the offshore 2D data processing.
5.1.1 Data processing
Same as 4.1.1~4.1.8, 4.1.11.
5.1.2 Establishing layer model
Use the post-selection time migration section for geological interpretation (velocity layer interpretation). 5.1.3 Establishing initial velocity model
The Dix formula can be used to convert the selected acceleration into layer velocity. 5.1.4 Tomography of velocity model
Use the velocity model for tomography inversion. 5.1.5 Residual velocity analysis
Carry out velocity analysis layer by layer from shallow to deep, flatten the common reflection point (CRP) gathers, and generate a new velocity model. 5.1.6 Migration
Use the velocity model to perform pre-selected depth migration and multiple iterations. If you are still not satisfied after multiple iterations, you can repeat 5.1.3~5.1.6 until you are satisfied.
5.2 Test items
In addition to being consistent with the content of two-dimensional processing, it should also include: a) the depth sampling rate calculated based on the time and layer velocity of the target layer; b) the migration aperture calculated based on the maximum time difference of the maximum time of the profile. 5.3 Batch processing and quality control
Same as 4.3.1~4.3.2
6 Processing results and data archiving
6.1 Result profile display
6.1.1 Result medium.
6.1.2 The section top shall display the shot number, velocity parameters of the velocity analysis point, intersection with other survey lines, and water depth. 6.1.3 Time scales shall be noted on both sides of the section.
6.1.4 The header
The content shall include:
a) User name;
Work area name, survey line name, section type:
Field acquisition parameters;
Basic processing flow and main processing parameters; d)
Display direction, vertical and horizontal scales, and polarity of processed data recording. 6.2 Submission of results
The submitted results should include:
a) SEG-Y format result band;
Result profile;
SY/T10020-1998
Velocity spectrum bound in book and velocity data recorded in ASCII code: Processing report:
1) Geological tasks and processing requirements;
Processing workload and start and end dates;
Original data quality analysis
Processing process design and parameter test analysis; 4)
Processing process and effect analysis;
Problems encountered in processing and solutions
Existing problems and suggestions;
Result band list.
6.3 Archived data
Mainly include:
Selected and offset SEG-Y format data bands and corresponding lists; a)
Velocity spectrum and velocity data recorded in ASCI code; film display result profile;
Processing report.
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