A relative isochronous logging and seismic calibration method

Abstract

This invention relates to the field of oil and gas exploration and development technology, and discloses a relative isochronous logging and seismic calibration method. The calibration of the top and bottom of marker layers uses a unified calibration method based on the average velocity of multiple wells. The velocity volume is corrected for errors according to the spatial distribution characteristics of the stratigraphic layers, ultimately resulting in very small calibration errors for both surface strata and seismic interpretation layers, and the results exhibit a normal distribution. During the calibration process, no stretching or compression is applied to individual well curves, ensuring a reasonable velocity trend, no distortion segments, and a velocity model that more closely approximates the true velocity. This invention is primarily aimed at calibrating thin sand layers in continental clastic sedimentary rocks in my country, characterized by thin thickness, rapid lateral variation, and unstable distribution. It is particularly effective for small-layer correlation in development areas and for connectivity studies such as water injection.

Description

Technical Field

[0001] This invention relates to the field of oil and gas exploration and development technology, and more particularly to the field of intelligent processing and interpretation technology, specifically a relative isochronous logging and seismic calibration method. Background Technology

[0002] Stratigraphic calibration, or well-seismic hybrid calibration, combines well logging information in the depth domain with seismic information in the time domain to determine the correspondence between seismic reflection phase axes and stratigraphic interfaces and reservoir development characteristics. Besides being influenced by factors such as wavelet frequency and type, it is also affected by stratigraphic density, seismic wave propagation speed within the stratigraphy, and stratigraphic development patterns. Calibration of geological bodies with greater thickness, distinct characteristics, and relatively stable distribution within the study area is relatively simple and generally does not result in errors. However, calibrating thin sand layers with rapid lateral variations and unstable distribution in continental clastic sedimentary rocks in my country can sometimes be very difficult in practical work.

[0003] Currently, the industry uses three well-seismic calibration methods for marker layers and thicker reservoirs: average velocity calibration, VSP (vertical seismic profile) calibration, and sonic synthetic seismic record calibration. There is no method for accurate calibration of transversely homogeneous, thin, interbedded reservoirs. Summary of the Invention

[0004] To overcome the shortcomings of existing technologies, this invention solves the problems of excessive calibration errors in transversely homogeneous thin interbedded reservoirs and poor well-seismic correlation between interlayer layers. On the one hand, it improves the accuracy of thin interbedded reservoir calibration; on the other hand, the calibration is free from artificial stretching and compression, resulting in a distortion-free velocity model that can be directly used for variable velocity mapping.

[0005] The objective of this invention is achieved through the following technical solutions and steps:

[0006] A relative isochronous logging and seismic calibration method includes the following steps:

[0007] (1) Generally, a set of formations located at or near the top of the reservoir is selected as the top marker layer for well-seismic calibration, and the calibration is carried out from top to bottom;

[0008] (2) By interpreting the two-way travel time corresponding to the geological stratification depth and the top marker layer, the average velocity of multiple wells at the marker layer position is obtained. This average velocity is used to convert the time-depth relationship of the top marker layer of the target segment. Then, the top marker layer is preliminarily calibrated using this time-depth relationship and the error between each well logging stratum and the seismic marker layer is calculated. Based on the error, the velocity volume is trend-corrected according to the spatial distribution characteristics of the strata. Finally, the calibration error of the well stratification and the seismic interpretation layer is very small and the result is normally distributed, thus completing the calibration of the top marker layer.

[0009] (3) After the top marker layer is calibrated and the layer is flattened, the average velocity between the top marker layer and the next marker layer is obtained by using the sonic logging curve. Based on the time-depth relationship obtained by this average velocity, the next marker layer is calibrated. The calibration error is still corrected by the error trend surface. By correcting layer by layer, the calibration of multiple marker layers is achieved.

[0010] (4) After completing the calibration of the marker layer, we obtain multiple sets of time-depth relationships at the top and bottom or inside of the reservoir. Based on these time-depth relationships, we produce a synthetic seismic record and complete the calibration of the thin sand layer inside the reservoir.

[0011] (5) In actual production research, the acoustic velocity logging curve and density logging curve are multiplied to obtain the wave impedance curve. The wave impedance curve is then converted into the reflection coefficient, and then convolved with the seismic wavelet to obtain the well-side synthetic record. By comparing the wave groups with the original seismic traces near the well, the final well-seismic calibration in the time domain and depth domain is completed.

[0012] Compared with the prior art, the beneficial effects of the present invention are as follows:

[0013] The calibration of the top and bottom of the marker layer adopts a unified calibration method based on the average velocity of multiple wells. The velocity volume is trend-corrected according to the spatial distribution characteristics of the stratigraphic layers based on the error, so that the calibration error of the surface strata and the seismic interpretation layer is very small and the result is normally distributed.

[0014] During the calibration process, no stretching or compression is applied to the curve of a single well, ensuring a reasonable velocity trend, no distortion segments, and a velocity model that is closer to the real velocity.

[0015] The calibration of thin sand layers with thin thickness, rapid lateral variation, and unstable distribution in terrestrial clastic sedimentary rocks in my country, especially the correlation of small layers in development areas and the study of connectivity such as water injection, has a very good effect. Attached Figure Description

[0016] To more clearly illustrate the technical solutions in this invention or related technologies, the accompanying drawings used in the description of the embodiments or related technologies will be briefly introduced below. Obviously, the accompanying drawings described below are some embodiments of this invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0017] Figure 1 This is a flowchart of the relative isochronous logging and seismic calibration technology provided in the embodiments of the present invention;

[0018] Figure 2This is a mean velocity map of the overlying strata above the marker layer calculated using well stratification and seismic interpretation horizons. H1 is the marker layer selected on the seismic data volume, t is the two-way travel time of each well at the H1 horizon, D is the stratification depth of each well at the H1 horizon, and the mean velocity of the strata above the H1 horizon is:

[0019] Va=,i=1,2,3,···,n. (3)

[0020] Va is the average velocity of the upper strata of the H1 layer;

[0021] Figure 3 The top marker layer was initially calibrated by replacing the interlayer velocity of the overlying formation with Va, and the calibration results had some errors.

[0022] Figure 4 The error is corrected once or multiple times according to the spatial distribution characteristics of the strata. Then the top layer is calibrated. If the calibration error is small and shows a normal distribution, the calibration of the top marker layer of the reservoir is basically completed. Finally, the logging layers and seismic interpretation layers are aligned manually to eliminate the subtle differences caused by logging instrument deformation and seismic imaging reference surface.

[0023] Figure 5 After the top marker layer is calibrated, the layers and interpretation layers are leveled to unify the marker layers onto a standard plane, which facilitates the calibration of the next marker layer.

[0024] Figure 6 It uses acoustic wave curves to calculate and replace the interlayer average velocity map;

[0025] Figure 7 It is an acoustic logging curve, and the final fine-tuning of the calibration is made using the comprehensive wavelet synthesis record;

[0026] Figure 8 It is a top-level error plane distribution diagram of the top average velocity calibration;

[0027] Figure 9 This is the top-level error profile of the average velocity calibration.

[0028] Figure 10 This is a comparison chart of four methods for calculating trend velocity grids;

[0029] Figure 11 This is the T1 calibration error diagram after the least squares trend correction speed;

[0030] Figure 12 This is a reconstruction of the paleogeography of the first section of the Qinghai sedimentary rock and an amplitude attribute map of the top layer of the first section of the Qinghai sedimentary rock.

[0031] Figure 13 It is a reflection feature map of the upper and lower sections of the target layer on the seismic profile. Specific implementation methods

[0032] To make the technical means and objectives of this invention easier to understand, the invention is further described below in conjunction with specific embodiments. Unless otherwise specified, the experimental methods used in the following embodiments are conventional methods.

[0033] Example 1

[0034] The Qianshaokou and Quantou Formations in the southern Songliao Basin are primarily composed of interbedded fine-grained clastic sandstone and mudstone, consisting of fluvial and deltaic facies deposits. The Yaojia and Nenjiang Formations exhibit an abrupt transition from mudstone to sandstone at their lithological interface, reflected in well logging curves as a jump from high to low values. Seismically, this manifests as a stable wave impedance reflection interface (T1), traceable and comparable across the entire region. Therefore, T1 was selected as the top marker layer for this well-seismic calibration. During the study, if the overall thickness distribution of the target formation is relatively stable, selecting only two marker layers—one at the top and one at the bottom—is sufficient to control and complete the calibration of the internal thin sand layers. Conversely, selecting as many marker layers as possible is preferable. The Qingshankou Formation, the target formation of this invention, has a relatively stable distribution within the study area, with an overall thickness of approximately 600 meters. Therefore, in addition to selecting the top marker layer, this invention also chose T2*, relatively close to the lower interface of the target formation, as the transition layer for calibration. T2 is the bottom of the Qingshankou Formation, but the response characteristics of the T2 layer on the seismic profile are not obvious. T2* is similar to T1 in terms of geology, well logging and seismicity, and both have stable interfaces.

[0035] First, based on a detailed interpretation of T1, the average velocity of the overlying formation in multiple wells was calculated by using the two-way travel time at the read well points and the depth corresponding to the logging strata. Then, this average velocity was used to calibrate all wells in the work area. The calibration results show that the error is relatively large and has a certain trend.

[0036] We employ the four methods described above—least squares, Laplace iteration, distance-weighted, and spline interpolation—to correct the error trend fitting, with the following results: Figure 9 As shown in the figure, spline interpolation has the most abrupt changes and the worst interpolation effect; the Laplace iteration method and distance-weighted method interpolate abruptly at individual large points and also have poor effects; while the quadratic surface method has a smooth transition between error points and the best interpolation effect. Based on the results, we finally adopted the least squares method to correct the error trend of the layer velocity ( Figure 10 Then, T1 was calibrated, and the calibration results showed small errors and a normal distribution. Figure 11 The calibration quality control of the top marker layer of the target layer was qualified. Finally, the T1 layer on the well logging and the T1 layer on the seismic imaging were manually aligned to eliminate the minor differences caused by the deformation of the well logging instrument and the seismic imaging reference surface.

[0037] The seismic profile shows that the target layer in the study area is divided by T2*, with two sets of reflections above and below it having different characteristics. Therefore, the average velocity of the calibration well needs to be calculated in two segments. Furthermore, because the study area has two sets of source materials distributed east and west, with different directions, and is divided by the central fault zone in the middle, the average velocity between the eastern and western sections differs significantly. Therefore, the study area is divided into eastern and western parts along this fault zone and calibrated separately. Figure 12 , 13 )

[0038] After completing the T1 calibration and flattening along the layers, the sonic logging curves of the wells involved in the calibration (see...) Figure 6 The average interlayer velocity between T1 and T2* was calculated. Using this average velocity, the time-depth relationship was further obtained, and the calibration process for T1 was repeated, segment by segment, to calibrate T2*. After the bottom layer T2 was calibrated, the calibration results were quality controlled, with the error generally kept within 5 meters.

[0039] After T1 and T2* are calibrated, the final step is to create a synthetic record and compare it with the waveforms of the seismic traces from the wellbore to complete the calibration of the thin sand layers between the marker layers. For the main target layer, a combined wavelet is obtained through well-seismic co-calculation. Using the previously obtained time-depth relationship, this invention calibrates the synthetic record for each well separately. Fine adjustments are made based on the waveform correspondence between the synthetic record and the original seismic trace, aligning the synthetic record of each well with the seismic trace to the most reasonable position. Then, error quality control is performed on the calibration positions of the top, bottom, and intermediate thin layers. If the error is around 2 meters, the quality control conditions are met, and the calibration work is complete.

[0040] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention, and not to limit them; although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some of the technical features; and these modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the embodiments of the present invention.

Claims

1. A relative isochronous logging and seismic calibration method, characterized in that, Includes the following steps: (1) Select a set of formations located at or near the top of the reservoir as the top marker layer for well-seismic calibration, and calibrate from top to bottom; (2) By interpreting the two-way travel time corresponding to the geological stratification depth and the top marker layer, the average velocity of multiple wells at the marker layer position is obtained. This average velocity is used to convert the time-depth relationship of the top marker layer of the target segment. Then, the top marker layer is initially calibrated using this time-depth relationship and the error between each well logging stratification and the seismic marker layer is calculated. Based on the error, the velocity volume is trend-corrected according to the spatial distribution characteristics of the strata. Finally, the calibration error of the well stratification and the seismic interpretation layer is very small and the result is normally distributed, thus completing the calibration of the top marker layer. (3) After the top marker layer is calibrated and the layer is flattened, the average velocity between the top marker layer and the next marker layer is obtained by using the sonic logging curve. Based on the time-depth relationship obtained by this average velocity, the next marker layer is calibrated. The calibration error is still corrected by the error trend surface. By correcting layer by layer, multiple marker layers are calibrated. (4) After completing the calibration of the marker layer, obtain multiple sets of time-depth relationships at the top and bottom or inside of the reservoir. Based on these time-depth relationships, create a synthetic seismic record and complete the calibration of the thin sand layer inside the reservoir. The specific calculation method of the time-depth relationship is as follows: After completing the T1 calibration and flattening along the layer, use the sonic logging curve of the well participating in the calibration to obtain the interlayer average velocity between T1 and T2*. Use the average velocity to further obtain the time-depth relationship and repeat the T1 calibration process to calibrate T2* in sections. After the bottom T2 is calibrated, the calibration results are quality controlled and the error is basically controlled within 5 meters. (5) In actual production research, the wave impedance curve is obtained by multiplying the sonic velocity logging curve and the density logging curve. The wave impedance curve is then converted into the reflection coefficient, and then convolved with the seismic wavelet to obtain the well-side synthetic record. By comparing the wave group with the original seismic trace at the well, the final well-seismic calibration in the time domain and depth domain is completed.

2. The relative isochronous logging and seismic calibration method according to claim 1, characterized in that, The top marker layer mentioned in step (1) is selected as a jump interface from high to low value on the well logging curve, and a stable wave impedance reflection interface T1 on the seismic surface.

3. The relative isochronous logging and seismic calibration method according to claim 1, characterized in that, In step (1), based on the selected top marker layer, T2*, which is relatively close to the low interface of the target segment, can also be selected as the transition layer for calibration.

4. The relative isochronous logging and seismic calibration method according to claim 1, characterized in that, The methods for trend correction in step (2) and trend surface correction in step (3) are least squares, Laplace iteration, distance weighting, and spline interpolation.

5. The relative isochronous logging and seismic calibration method according to claim 1, characterized in that, The error of the final well-seismic calibration in step (5) is within 2 meters.

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