Stratum oiliness prediction method, device, equipment and medium

Abstract

The invention discloses a stratum oiliness prediction method and device, equipment and a medium. The stratum oiliness prediction method comprises the steps that the relation between the ratio of the stratum longitudinal wave speed to the stratum volume density and the oil saturation is obtained based on logging information; obtaining the ratio of the longitudinal wave velocity of the stratum at each position to the stratum volume density based on the seismic data; and based on the relationship between the ratio of the longitudinal wave velocity to the volume density of the stratum and the oil saturation and the ratio of the longitudinal wave velocity to the volume density of the stratum at each position, determining the oiliness result of the stratum at each position. According to the method, the oiliness of the stratum at each position can be accurately predicted, and the oil layer type of the stratum at the oil-bearing position can be further judged.

Description

Technical Field

[0001] The invention relates to the technical field of oil reservoir exploration, and in particular to a method, device, equipment and medium for predicting stratum oil content. Background Art

[0002] Seismic data is a reflection of the acoustic impedance of the formation, and the acoustic impedance can be expressed as the product of velocity and density. When the formation contains oil, its longitudinal wave velocity and volume density will decrease to a certain extent, and its relatively low impedance is an indicator of oil content in the formation. However, in addition to changes in formation fluids, factors that cause the decrease in formation impedance include lithology, pore pressure and many other factors. Therefore, low impedance alone cannot determine the oil content of the formation. At the same time, the oil content of the formation can be determined through logging data, but logging data can only obtain the oil content of the formation at a certain position (logging position), and cannot obtain the oil content of the formation at all positions.

[0003] Based on this, there is still room for further improvement in the existing technology. Summary of the invention

[0004] The main purpose of the present invention is to provide a method, device, equipment and medium for predicting the oil content of a formation, so as to solve the problem that the oil content of a formation at each position cannot be accurately predicted by seismic data or well logging data alone.

[0005] According to one aspect of the present invention, a method for predicting formation oil content is provided, comprising:

[0006] The relationship between the ratio of the formation's compressional wave velocity to the formation's bulk density and the oil saturation is obtained based on well logging data;

[0007] Based on seismic data, the ratio of the longitudinal wave velocity of the stratum at each position to the stratum volume density is obtained;

[0008] The oil content of the formation at each location is determined based on the relationship between the ratio of the P-wave velocity to the volume density of the formation and the oil saturation and the ratio of the P-wave velocity to the volume density of the formation at each location.

[0009] According to one embodiment of the present invention, the relationship between the ratio of the P-wave velocity to the volume density of the formation and the oil saturation is obtained based on the well logging data, including:

[0010] Obtain the relationship between the oil saturation of the formation and its depth based on well logging data;

[0011] Based on the logging data, the relationship between the ratio of the formation's P-wave velocity and the formation's volume density and its depth is obtained;

[0012] Based on the relationship between the variation of the oil saturation of the formation with depth and the variation of the ratio of the P-wave velocity to the formation volume density with depth, the relationship between the ratio of the P-wave velocity to the formation volume density and the oil saturation is obtained.

[0013] According to one embodiment of the present invention, obtaining the ratio of the longitudinal wave velocity of the formation at each position to the formation volume density based on seismic data includes:

[0014] Decompose the pre-stack gathers in seismic data into P-wave velocity component, S-wave velocity component and formation density component;

[0015] Inverting the P-wave velocity of the formation at each position based on the P-wave velocity component;

[0016] Inverting the formation volume density at each position of the formation based on the formation density component;

[0017] Based on the formation P-wave velocity and the formation volume density at each position of the formation, the ratio of the P-wave velocity at each position of the formation to the formation volume density is obtained.

[0018] According to one embodiment of the present invention, based on the relationship between the ratio of the formation compressional wave velocity to the formation volume density and the oil saturation and the ratio of the formation compressional wave velocity to the formation volume density at each position, the oil content of the formation at each position is determined, including:

[0019] Based on the relationship between the ratio of the formation compressional wave velocity to the formation volume density and the oil saturation, a first threshold value of the ratio of the formation compressional wave velocity to the formation volume density is obtained;

[0020] The relationship between the ratio of the longitudinal wave velocity to the formation volume density at each position and the first threshold is compared; if the ratio of the longitudinal wave velocity to the formation volume density at a certain position is greater than or equal to the first threshold, it is determined that the formation contains oil at that position; otherwise, it is determined that the formation does not contain oil at that position.

[0021] According to one embodiment of the present invention, it also includes:

[0022] If a stratum is determined to be an oil layer at a certain location, the type of the oil layer at the location is determined based on the seismic data to be tight oil or shale oil.

[0023] According to one embodiment of the present invention, determining based on seismic data whether the oil layer type of the stratum at the location includes tight oil or shale oil includes:

[0024] Obtaining the longitudinal wave velocity of the formation at the location based on seismic data;

[0025] If the longitudinal wave velocity of the formation at this position is greater than or equal to the second threshold, it is determined that tight oil exists in the formation at this position; otherwise, it is determined that shale oil exists in the formation at this position.

[0026] According to one embodiment of the present invention, determining based on seismic data whether the oil layer type of the stratum at the location includes tight oil or shale oil includes:

[0027] Obtaining the volume density of the stratum at the location based on seismic data;

[0028] If the formation volume density at the position is greater than or equal to the third threshold, it is determined that there is tight oil in the formation at the position; otherwise, it is determined that there is shale oil in the formation at the position.

[0029] According to another aspect of the present invention, a formation oil content prediction device is provided, comprising:

[0030] A first acquisition module is configured to acquire the relationship between the ratio of the longitudinal wave velocity of the formation to the volume density of the formation and the oil saturation based on the well logging data;

[0031] A second acquisition module is configured to acquire the ratio of the longitudinal wave velocity of the formation at each position to the formation volume density based on the seismic data;

[0032] The determination module is configured to determine the oil content of the formation at each position based on the relationship between the ratio of the P-wave velocity to the volume density of the formation and the oil saturation and the ratio of the P-wave velocity to the volume density of the formation at each position.

[0033] According to another aspect of the present invention, a computer device is provided, comprising:

[0034] at least one processor; and

[0035] A memory, wherein the memory stores a computer program that can be run on the processor, wherein the processor implements the method described in any of the above embodiments when executing the program.

[0036] According to another aspect of the present invention, a computer-readable storage medium is provided, on which a computer program is stored, wherein the computer program implements the method described in any of the above embodiments when executed by a processor.

[0037] In the method for predicting oil content in formations according to an embodiment of the present invention, the two key parameters of the longitudinal wave velocity and the volume density of the formation are used to organically link the well logging data and the seismic data, and a standard template is established between the ratio of the longitudinal wave velocity to the volume density in the well logging data and the oil content. The ratio of the longitudinal wave velocity to the volume density of the formation at each position is obtained through the seismic data and combined with the standard template, so that the oil content of the formation at each position can be accurately predicted. In addition, the type of oil layer at the oil-bearing position of the formation can be further determined through the seismic data. BRIEF DESCRIPTION OF THE DRAWINGS

[0038] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings required for use in the embodiments or the description of the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying creative work.

[0039] Figure 1 A flow chart showing a method for predicting formation oil content according to an embodiment of the present invention;

[0040] Figure 2 Show Figure 1 Flow chart of step S1 in FIG.

[0041] Figure 3 A graph showing the relationship between the longitudinal wave velocity, volume density and their ratio and depth according to an embodiment of the present invention;

[0042] Figure 4 Show Figure 1 Flow chart of step S2;

[0043] Figure 5 Show Figure 1 Flow chart of step S3;

[0044] Figure 6 A schematic diagram showing a method for distinguishing tight oil from shale oil according to an embodiment of the present invention is shown;

[0045] Figure 7 A schematic diagram showing a formation oil content prediction device according to an embodiment of the present invention. DETAILED DESCRIPTION

[0046] In order to make the objectives, technical solutions and advantages of the present invention more clearly understood, the embodiments of the present invention are further described in detail below in combination with specific embodiments and with reference to the accompanying drawings.

[0047] It should be noted that all expressions using "first" and "second" in the embodiments of the present invention are for distinguishing two non-identical entities with the same name or non-identical parameters. It can be seen that "first" and "second" are only for the convenience of expression and should not be understood as limitations on the embodiments of the present invention. The subsequent embodiments will not explain this one by one.

[0048] Figure 1 A flow chart of a method for predicting formation oil content according to an embodiment of the present invention is shown as follows: Figure 1 As shown, the formation oil content prediction method includes the following steps:

[0049] S1, the relationship between the ratio of the P-wave velocity to the formation volume density and the oil saturation obtained based on the well logging data;

[0050] S2, based on seismic data, obtains the ratio of the P-wave velocity at each position of the formation to the formation volume density;

[0051] S3, based on the relationship between the ratio of the P-wave velocity to the volume density of the formation and the oil saturation and the ratio of the P-wave velocity to the volume density of the formation at each position, the oil content of the formation at each position is determined.

[0052] In an embodiment of the present invention, the well logging data and the seismic data are organically linked through the two key parameters of the formation's P-wave velocity and the formation's volume density, thereby laying a foundation for the prediction of the formation's oil content. A standard template is established between the relationship between the P-wave velocity and volume density ratio in the well logging data and the oil content, thereby greatly improving the credibility of the prediction of the formation's oil content. By obtaining the P-wave velocity and the formation's volume density ratio at each location through seismic data and combining it with the standard template, the oil content of the formation at each location can be accurately predicted.

[0053] The inventor of the present application realizes that: according to the rock physics model, the formation velocity is equal to the square root of the ratio of the formation elastic parameter to the bulk density. The same formation has the same skeleton parameters. Since both oil and water have the characteristic of being incompressible, the velocity of the compression wave (longitudinal wave) does not change much for pores containing oil or water. However, when the fluid in the pore changes from water to oil, the formation bulk density will decrease significantly. Therefore, the oil content of the formation can be predicted by the ratio of the longitudinal wave velocity of the formation to the formation bulk density.

[0054] In the technical scheme of the present invention, the characteristics that the difference in P-wave velocity between oil layers and water layers is small while the difference in formation volume density is large are utilized, and the relationship between the ratio of P-wave velocity to formation volume density and oil saturation of the formation is obtained based on logging data. The ratio of P-wave velocity to formation volume density of the formation at various positions is obtained based on seismic data, and the ratio at various positions is substituted into the relationship between the ratio and oil saturation, thereby obtaining the oil content results of the formation at various positions, thereby improving the accuracy of oil content interpretation through seismic data.

[0055] In some embodiments, reference Figure 2 , step S1 further comprises:

[0056] S11, based on the logging data, obtain the relationship between the oil saturation of the formation and the depth; the relationship between the oil saturation of the formation and the depth can be obtained by methods in the prior art such as resistivity method, C / O spectrum logging method, neutron lifetime logging method, etc.;

[0057] S12, based on the logging data, obtain the relationship between the ratio of the P-wave velocity of the formation and the volume density of the formation and the depth; the P-wave velocity and the volume density of the formation can be obtained by interpreting the logging data, which is a prior art; for example, the following can be obtained: Figure 3 The relationship between the longitudinal wave velocity Vp, the volume density Dn and the ratio Vp / Dn and the depth is shown;

[0058] S13, based on the relationship between the variation of the oil saturation of the formation with depth and the relationship between the variation of the ratio of the P-wave velocity to the formation volume density with depth, obtain the relationship between the ratio of the P-wave velocity to the formation volume density and the oil saturation.

[0059] In some embodiments, reference Figure 4 , step S2 further comprises:

[0060] S21, decompose the pre-stack gathers in the seismic data into P-wave velocity components, S-wave velocity components and formation density components, thereby eliminating the mutual interference between the components and improving the accuracy of the interpretation results;

[0061] S22, inverting the P-wave velocity of the formation at each position based on the P-wave velocity component;

[0062] S23, inverting the formation volume density at each position of the formation based on the formation density component;

[0063] S24, based on the formation P-wave velocity and the formation volume density at each position of the formation, obtaining the ratio of the formation P-wave velocity at each position to the formation volume density.

[0064] In some embodiments, reference Figure 5 , step S3 further comprises:

[0065] S31, based on the relationship between the ratio of the formation P-wave velocity to the formation volume density and the oil saturation, a first threshold value of the ratio of the formation P-wave velocity to the formation volume density is obtained; based on the relationship, it can be determined that when the ratio of the formation P-wave velocity to the formation volume density is higher than a certain value, the formation contains oil to a greater extent, and the value is used as the first threshold value; the value of the first threshold value may be different for different regions, for example, in some embodiments, the first threshold value may be about 1.7 to 1.8;

[0066] S32, comparing the ratio of the longitudinal wave velocity to the formation volume density at each position with the first threshold value; if the ratio of the longitudinal wave velocity to the formation volume density at a certain position is greater than or equal to the first threshold value, it is determined that the formation contains oil at that position; otherwise, it is determined that the formation does not contain oil at that position.

[0067] In some embodiments, the method further includes step S4: if the stratum at a certain location is determined to be an oil layer, determining based on seismic data whether the oil layer type of the stratum at the location includes tight oil or shale oil.

[0068] In some embodiments, the determining, based on seismic data, whether the oil layer type of the formation at the location is tight oil or shale oil comprises:

[0069] Obtaining the longitudinal wave velocity of the formation at the location based on seismic data;

[0070] If the longitudinal wave velocity of the formation at this position is greater than or equal to the second threshold, it is determined that tight oil exists in the formation at this position; otherwise, it is determined that shale oil exists in the formation at this position; the value of the second threshold can be determined in combination with actual exploration data and experience. Figure 6 A schematic diagram of a method for determining tight oil and shale oil according to an embodiment of the present invention is shown, as shown in FIG. Figure 6 As shown, the oil content can be determined based on the ratio of longitudinal wave velocity to volume density Vp / Dn being greater than 1.8, and the presence of tight oil can be determined based on the longitudinal wave velocity Vp being greater than or equal to 4500 m / s, and the presence of shale oil can be determined based on the longitudinal wave velocity Vp being less than 4500 m / s.

[0071] In some embodiments, the determining, based on seismic data, whether the oil layer type of the formation at the location is tight oil or shale oil comprises:

[0072] Obtaining the volume density of the stratum at the location based on seismic data;

[0073] If the formation volume density at this position is greater than or equal to the third threshold, it is determined that there is tight oil in the formation at this position; otherwise, it is determined that there is shale oil in the formation at this position; the value of the third threshold can be determined in combination with actual exploration data and experience.

[0074] In some embodiments, the determination results of the above two methods for determining tight oil and shale oil may be combined for comprehensive analysis to ultimately obtain prediction results that are consistent with the actual situation of the formation.

[0075] refer to Figure 7 The present invention also provides a formation oil content prediction device 100, comprising:

[0076] The first acquisition module 110 is configured to acquire the relationship between the ratio of the longitudinal wave velocity to the volume density of the formation and the oil saturation based on the well logging data;

[0077] The second acquisition module 120 is configured to acquire the ratio of the longitudinal wave velocity of the formation at each position to the formation volume density based on the seismic data;

[0078] The determination module 130 is configured to determine the oil content of the formation at each position based on the relationship between the ratio of the P-wave velocity to the volume density of the formation and the oil saturation and the ratio of the P-wave velocity to the volume density of the formation at each position.

[0079] In some embodiments, the first acquisition module 110 is configured to:

[0080] Obtain the relationship between the oil saturation of the formation and its depth based on well logging data;

[0081] Based on the logging data, the relationship between the ratio of the formation's P-wave velocity and the formation's volume density and its depth is obtained;

[0082] Based on the relationship between the variation of the oil saturation of the formation with depth and the variation of the ratio of the P-wave velocity to the formation volume density with depth, the relationship between the ratio of the P-wave velocity to the formation volume density and the oil saturation is obtained.

[0083] In some embodiments, the second acquisition module 120 is configured as follows:

[0084] Decompose the pre-stack gathers in seismic data into P-wave velocity component, S-wave velocity component and formation density component;

[0085] Inverting the P-wave velocity of the formation at each position based on the P-wave velocity component;

[0086] Inverting the formation volume density at each position of the formation based on the formation density component;

[0087] Based on the formation P-wave velocity and the formation volume density at each position of the formation, the ratio of the P-wave velocity at each position of the formation to the formation volume density is obtained.

[0088] In some embodiments, the determination module 130 is configured to:

[0089] Based on the relationship between the ratio of the formation compressional wave velocity to the formation volume density and the oil saturation, a first threshold value of the ratio of the formation compressional wave velocity to the formation volume density is obtained;

[0090] The relationship between the ratio of the longitudinal wave velocity to the formation volume density at each position and the first threshold is compared; if the ratio of the longitudinal wave velocity to the formation volume density at a certain position is greater than or equal to the first threshold, it is determined that the formation contains oil at that position; otherwise, it is determined that the formation does not contain oil at that position.

[0091] In some embodiments, the formation oil content prediction device 100 further includes a judgment module configured to judge whether the oil layer type of the formation at the oil-bearing position includes tight oil or shale oil based on seismic data.

[0092] In some embodiments, the judgment module is configured to: obtain the longitudinal wave velocity of the formation at the oil-bearing position based on seismic data; if the longitudinal wave velocity of the formation at the oil-bearing position is greater than or equal to a second threshold, it is determined that there is tight oil in the formation at this position; otherwise, it is determined that there is shale oil in the formation at this position.

[0093] In some embodiments, the judgment module is configured to: obtain the formation volume density of the formation at the oil-bearing location based on seismic data; if the formation volume density of the formation at the oil-bearing location is greater than or equal to a third threshold value, it is determined that there is tight oil in the formation at this location; otherwise, it is determined that there is shale oil in the formation at this location.

[0094] The present invention further proposes a computer device, comprising: at least one processor; and a memory, wherein the memory stores a computer program that can be run on the processor, and when the processor executes the program, the method described in any of the above embodiments is implemented.

[0095] The present invention further provides a computer-readable storage medium on which a computer program is stored. When the computer program is executed by a processor, the method described in any of the above embodiments is implemented.

[0096] In summary, the technical solution provided by the present invention utilizes the characteristics that the difference in P-wave velocity between oil layers and water layers is small while the difference in formation volume density is large. The relationship between the ratio of the P-wave velocity to the formation volume density and the oil saturation is obtained based on logging data. The ratio of the P-wave velocity to the formation volume density at various positions is obtained based on seismic data, thereby obtaining the oil content results of the formation at various positions, which can improve the accuracy of oil content interpretation through seismic data.

[0097] It should be noted that a person skilled in the art can understand that all or part of the processes in the above-mentioned embodiment methods can be implemented by instructing related hardware through a computer program, and the program can be stored in a computer-readable storage medium. When the program is executed, it can include the processes of the embodiments of the above-mentioned methods.

[0098] Furthermore, it should be appreciated that the computer-readable storage medium (eg, memory) herein may be either a volatile memory or a nonvolatile memory, or may include both volatile and nonvolatile memory.

[0099] A person skilled in the art should understand that the discussion of any of the above embodiments is only exemplary and is not intended to imply that the scope of the disclosure of the embodiments of the present invention (including the claims) is limited to these examples; under the concept of the embodiments of the present invention, the technical features in the above embodiments or different embodiments can also be combined, and there are many other changes in different aspects of the embodiments of the present invention as described above, which are not provided in detail for the sake of simplicity. Therefore, any omissions, modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the embodiments of the present invention should be included in the protection scope of the embodiments of the present invention.

Claims

1. A method for predicting formation oil content, characterized in that: include: The relationship between the ratio of the formation's compressional wave velocity to the formation's bulk density and the oil saturation is obtained based on well logging data; Based on seismic data, the ratio of the longitudinal wave velocity of the stratum at each position to the stratum volume density is obtained; The oil content of the formation at each location is determined based on the relationship between the ratio of the P-wave velocity to the volume density of the formation and the oil saturation and the ratio of the P-wave velocity to the volume density of the formation at each location.

2. The method according to claim 1, characterized in that The relationship between the ratio of the formation's compressional wave velocity to the formation's volume density and the oil saturation is obtained based on well logging data, including: Obtain the relationship between the oil saturation of the formation and its depth based on well logging data; Based on the logging data, the relationship between the ratio of the formation's P-wave velocity and the formation's volume density and its depth is obtained; Based on the relationship between the variation of the oil saturation of the formation with depth and the variation of the ratio of the P-wave velocity to the formation volume density with depth, the relationship between the ratio of the P-wave velocity to the formation volume density and the oil saturation is obtained.

3. The method according to claim 1, characterized in that Based on seismic data, the ratio of the longitudinal wave velocity and the volume density of the formation at each position is obtained, including: Decompose the pre-stack gathers in seismic data into P-wave velocity component, S-wave velocity component and formation density component; Inverting the P-wave velocity of the formation at each position based on the P-wave velocity component; Inverting the formation volume density at each position of the formation based on the formation density component; Based on the formation P-wave velocity and the formation volume density at each position of the formation, the ratio of the P-wave velocity at each position of the formation to the formation volume density is obtained.

4. The method according to claim 1, characterized in that: Based on the relationship between the ratio of the formation P-wave velocity to the formation volume density and the oil saturation and the ratio of the formation P-wave velocity to the formation volume density at each position, the oil content of the formation at each position is determined, including: Based on the relationship between the ratio of the formation compressional wave velocity to the formation volume density and the oil saturation, a first threshold value of the ratio of the formation compressional wave velocity to the formation volume density is obtained; The relationship between the ratio of the longitudinal wave velocity to the formation volume density at each position and the first threshold is compared; if the ratio of the longitudinal wave velocity to the formation volume density at a certain position is greater than or equal to the first threshold, it is determined that the formation contains oil at that position; otherwise, it is determined that the formation does not contain oil at that position.

5. The method according to claim 1, characterized in that Also includes: If a stratum is determined to be an oil layer at a certain location, the type of the oil layer at the location is determined based on the seismic data to be tight oil or shale oil.

6. The method according to claim 5, characterized in that The determining based on seismic data whether the oil layer type of the stratum at the location is tight oil or shale oil includes: Obtaining the longitudinal wave velocity of the formation at the location based on seismic data; If the longitudinal wave velocity of the formation at this position is greater than or equal to the second threshold, it is determined that tight oil exists in the formation at this position; otherwise, it is determined that shale oil exists in the formation at this position.

7. The method according to claim 5, characterized in that The determining based on seismic data whether the oil layer type of the stratum at the location is tight oil or shale oil includes: Obtaining the volume density of the stratum at the location based on seismic data; If the formation volume density at the position is greater than or equal to the third threshold, it is determined that there is tight oil in the formation at the position; otherwise, it is determined that there is shale oil in the formation at the position.

8. A formation oil content prediction device, characterized in that: include: A first acquisition module is configured to acquire the relationship between the ratio of the longitudinal wave velocity of the formation to the volume density of the formation and the oil saturation based on the well logging data; A second acquisition module is configured to acquire the ratio of the longitudinal wave velocity of the formation at each position to the formation volume density based on the seismic data; The determination module is configured to determine the oil content of the formation at each position based on the relationship between the ratio of the P-wave velocity to the volume density of the formation and the oil saturation and the ratio of the P-wave velocity to the volume density of the formation at each position.

9. A computer device comprising: at least one processor; as well as A memory storing a computer program executable on the processor, wherein the processor implements the method according to any one of claims 1 to 7 when executing the program.

10. A computer-readable storage medium having a computer program stored thereon, characterized in that: When the computer program is executed by a processor, the method according to any one of claims 1 to 7 is implemented.

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