Fracture porosity calculation method and system based on two-dimensional nuclear magnetic resonance logging

Abstract

The invention discloses a fracture porosity calculation method and system based on two-dimensional nuclear magnetic resonance logging, and the calculation method comprises the following steps: a, carrying out the logging of a drilling well of a target area, obtaining the logging parameters related to the fracture development degree, and enabling the logging parameters related to the fracture development degree to comprise a two-dimensional nuclear magnetic resonance relaxation spectrum; b, analyzing and testing the core of the target area to obtain parameters related to a pore structure; c, a joint calibration method based on constant-speed mercury injection-rock core nuclear magnetic resonance, a joint calibration method based on casting body sheet-rock core nuclear magnetic resonance and a two-dimensional nuclear magnetic resonance logging response method of a crack centralized development section are used, and a crack-pore signal boundary value alpha is obtained; and step d, intercepting the two-dimensional nuclear magnetic resonance logging relaxation spectrum by using the fracture-pore signal boundary value alpha to obtain the fracture porosity. The method effectively solves the problems of low precision and high uncertainty of conventional logging calculation of the fracture porosity and relativity and multiplicity of solutions of imaging logging calculation of the fracture porosity.

Description

TECHNICAL FIELD

[0001] The application relates to the technical field of oil and gas well logging interpretation and reservoir evaluation, and particularly relates to a fracture porosity calculation method and system based on two-dimensional nuclear magnetic resonance logging. BACKGROUND

[0002] For a reservoir, fractures play an important role in reservoir formation and natural gas exploitation. On the one hand, as an important part of the "fault-fracture-sand" transport (fault transport, fracture transport and sand transport), fractures provide a high-speed channel for the migration of natural gas in the reservoir formation process, reduce the dynamic loss in the reservoir formation process, and improve the migration distance of natural gas. Generally, the reservoir has a high degree of natural gas filling at the fracture development position. On the other hand, when the gas reservoir is developed, the fractures provide a high-permeability channel for the flow of natural gas, and can significantly reduce the difficulty of sand fracturing reconstruction. Generally, the gas reservoir has high productivity at the fracture development position. Therefore, fractures can play an important role in both reservoir formation and development.

[0003] The development degree of fractures can be obtained by logging. Generally, when fractures develop around the well, there will be a relatively obvious response on the imaging logging, and the resistivity and acoustic wave curves will also change to different degrees with the difference in fracture size and occurrence. Therefore, the qualitative identification of fractures is relatively easy to achieve. However, for fracture-pore reservoirs and pore-fracture reservoirs, it is necessary to quantitatively analyze the influence of fracture development on the reservoir pore space and then calculate the fracture porosity. The above-mentioned qualitative identification method often has certain limitations:

[0004] 1) The resistivity, acoustic wave and other conventional logging curves have many influencing factors, among which lithology, physical properties and wellbore conditions are the most important influencing factors, and the fracture porosity has a relatively small influence. In addition, the above logging methods only have relatively obvious qualitative characteristics for fractures with medium and low angles and large opening degrees, and it is difficult to cause obvious changes in the resistivity and acoustic wave curves for fractures with high angles or relatively small opening degrees. Therefore, it is difficult to achieve satisfactory fracture porosity calculation accuracy by using the above logging curves;

[0005] 2) Imaging logging is an effective method for identifying fractures due to its high resolution characteristics. Different occurrences and different opening degrees of fractures are displayed as different bending degrees and different color depths of sine lines on the imaging logging graph. Therefore, imaging logging has the ability to quantitatively analyze fractures. However, when calculating the fracture porosity, imaging logging often has the following problems:

[0006] ①The conversion relationship between porosity and imaging logging resistivity depends on rock-electricity parameters m and n, which are closely related to formation temperature and pressure, but it is difficult to simulate the real formation temperature and pressure in the current laboratory; ②The resolution of imaging logging (centimeter level) is lower than the opening degree of the fracture under formation conditions (micron-millimeter level), which leads to the fact that the resistivity of the fracture position is often affected by the surrounding rock; ③In addition to the response to the fracture, the imaging logging is also sensitive to induced fractures, wellbore collapse, and falling blocks, and the low-resistance effect caused by the above phenomena will also increase the porosity, leading to the fact that the fracture porosity calculated by using the imaging logging deviates from the true value. SUMMARY

[0007] The purpose of the present application is to overcome the problems of low precision and high uncertainty when calculating the fracture porosity by using conventional logging such as resistivity and acoustic wave, and the problems of relativity and multiple solutions when calculating the fracture porosity by using imaging logging, and to provide a fracture porosity calculation method and system based on two-dimensional nuclear magnetic resonance logging.

[0008] In order to achieve the above-mentioned purpose of the application, the present application provides the following technical solutions:

[0009] A fracture porosity calculation method based on two-dimensional nuclear magnetic resonance logging, comprising the following steps: step a. logging the drilling of a target area to obtain logging parameters related to the fracture development degree, wherein the logging parameters related to the fracture development degree comprise two-dimensional nuclear magnetic resonance relaxation spectrum; step b. analyzing and testing the core of the target area to obtain parameters related to the pore structure; step c. using a joint calibration method based on constant-speed mercury injection-core nuclear magnetic resonance, a joint calibration method based on cast thin section-core nuclear magnetic resonance, and a two-dimensional nuclear magnetic resonance logging response method for fracture-concentrated development section, to obtain a fracture-pore signal demarcation value alpha; and step d. using the fracture-pore signal demarcation value alpha to intercept the two-dimensional nuclear magnetic resonance logging relaxation spectrum to obtain the fracture porosity.

[0010] Optionally, the step a. comprises the following steps:

[0011] Performing imaging logging to obtain the fracture development position; and performing two-dimensional nuclear magnetic resonance logging to obtain the two-dimensional nuclear magnetic resonance relaxation spectrum.

[0012] Optionally, the step b. comprises the following steps:

[0013] Performing core nuclear magnetic resonance experiment to obtain T2 distribution; performing core constant-speed mercury injection experiment to obtain core pore radius distribution; and performing cast thin section experiment to obtain thin section pore type.

[0014] Optionally, the joint calibration method based on constant-speed mercury injection-core nuclear magnetic resonance comprises the following steps:

[0015] Step c11. Calculate the average value of the peak values ​​of the pore radius distribution of all core samples; select core samples whose peak values ​​of the pore radius distribution of a single core are greater than the average value of the peak values ​​of the pore radius distribution of all core samples as the calibration cores for the joint calibration method based on constant-rate mercury intrusion porosimetry and core nuclear magnetic resonance; Step c12. Calculate the T2 distribution of each calibration core for the joint calibration method based on constant-rate mercury intrusion porosimetry and core nuclear magnetic resonance to obtain the upper limit of the T2 value of the pores of a single core sample for the joint calibration method based on constant-rate mercury intrusion porosimetry and core nuclear magnetic resonance. Step c13. For each The upper limit α1 of the pore signal T2 obtained by taking the average value is obtained by the joint calibration method based on constant rate mercury intrusion injection and core nuclear magnetic resonance.

[0016] Optionally, the joint calibration method based on cast thin section-core nuclear magnetic resonance includes the following steps:

[0017] Step c21. Select core samples with well-developed mold pores and intergranular porosity as the calibration cores for the joint calibration method based on cast thin section-core NMR; Step c22. Statistically analyze the T2 distribution of each calibration core obtained by the joint calibration method based on cast thin section-core NMR to obtain the upper limit of T2 of the pores in a single core sample using the joint calibration method based on cast thin section-core NMR. Step c23. For each The upper limit α2 of the pore signal T2 based on the joint calibration method of cast thin section-core nuclear magnetic resonance is obtained by taking the average value.

[0018] Optionally, the and / or the aforementioned The T2 value is the quantile value when the cumulative frequency of T2 distribution in the core reaches 95%.

[0019] Optionally, the two-dimensional nuclear magnetic resonance logging response method for fracture-concentrated development sections includes the following steps:

[0020] Step c31. Select the fracture concentration zone determined by the imaging logging as the calibration zone for the two-dimensional nuclear magnetic resonance logging response method of the fracture concentration zone; Step c32. Take the left boundary of the first signal concentration area on the upper right side of the relaxation spectrum of the two-dimensional nuclear magnetic resonance logging response method of the fracture concentration zone as the lower limit of the fracture signal T2 of a single well section. Step c33. For each The lower limit α3 of the fracture signal T2 of the two-dimensional nuclear magnetic resonance logging response method in the fracture-concentrated development section is obtained by taking the average value.

[0021] Optionally, the method for calculating the crack-pore signal boundary value α is as follows:

[0022]

[0023] In the formula, alpha is a crack-pore signal demarcation value, ms; alpha 1 is a pore signal T2 upper limit determined using a joint calibration method based on constant-speed mercury injection-core nuclear magnetic resonance, ms; alpha 2 is a pore signal T2 upper limit determined using a joint calibration method based on cast slice-core nuclear magnetic resonance, ms; and alpha 3 is a crack signal T2 lower limit determined using a two-dimensional nuclear magnetic resonance logging response method for a crack-concentrated development section, ms.

[0024] Optionally, the step d includes the following steps:

[0025] Summing up the amount of all signals with T2> alpha in the two-dimensional nuclear magnetic resonance relaxation spectrum, and the sum is the crack porosity:

[0026]

[0027] In the formula, alpha is a crack-pore signal demarcation value, ms; T is a crack porosity, %; alpha is a crack-pore signal demarcation value, ms; T 2max is a two-dimensional nuclear magnetic resonance logging instrument transverse relaxation time measurement upper limit, ms; T 1max is a two-dimensional nuclear magnetic resonance logging instrument longitudinal relaxation time measurement upper limit, ms; T 1min is a two-dimensional nuclear magnetic resonance logging instrument longitudinal relaxation time measurement lower limit, ms; P ij is an interval porosity value of the i-th sampling interval in the transverse direction and the j-th sampling interval in the longitudinal direction in the two-dimensional nuclear magnetic resonance relaxation spectrum, %.

[0028] A crack porosity calculation system based on two-dimensional nuclear magnetic resonance logging, comprising at least one processor and a memory in communication connection with the at least one processor; the memory stores instructions executable by the at least one processor, and the instructions are executed by the at least one processor to enable the at least one processor to execute the crack porosity calculation method based on two-dimensional nuclear magnetic resonance logging described above.

[0029] Compared with the prior art, the present application has the following beneficial effects:

[0030] 1. The crack porosity calculation method based on two-dimensional nuclear magnetic resonance logging provided by the present application uses two-dimensional nuclear magnetic resonance logging which is less affected by the rock skeleton, avoids the shortcomings of conventional logging and imaging logging which are greatly affected by mineral composition and wellbore conditions, and lays a method foundation for accurate calculation of crack porosity.

[0031] 2. The crack porosity calculation method based on two-dimensional nuclear magnetic resonance logging provided by the present application is based on two-dimensional nuclear magnetic resonance logging which can reflect the pore structure, maximally differentiates the logging response difference between pores and cracks, and lays a theoretical foundation for accurate calculation of crack porosity.

[0032] 3. The fracture porosity calculation method based on two-dimensional nuclear magnetic resonance logging provided by the present application uses a plurality of core analysis and testing means to preferably select calibration cores with relatively developed pores, and the mathematical statistics method used makes the upper limit of the pore signal T2 more reliable and the fracture-pore decomposition value more explicit, thereby improving the accuracy of fracture porosity calculation.

[0033] 4. The fracture porosity calculation system based on two-dimensional nuclear magnetic resonance logging provided by the present application is based on two-dimensional nuclear magnetic resonance logging, avoids the disadvantage that conventional logging and imaging logging are greatly affected by mineral composition and wellbore conditions, effectively solves the problems of low accuracy and high uncertainty of fracture porosity calculation by conventional logging; uses a plurality of core analysis and testing means to preferably select calibration cores with relatively developed pores, and the mathematical statistics method used makes the upper limit of the pore signal T2 more reliable and the fracture-pore decomposition value more explicit, thereby improving the accuracy of fracture porosity calculation, and effectively solving the problems of relativity and multiple solutions of fracture porosity calculation by imaging logging. BRIEF DESCRIPTION OF DRAWINGS

[0034] Figure 1 The fracture porosity calculation method flowchart based on two-dimensional nuclear magnetic resonance logging provided by the present application;

[0035] Figure 2 The fracture porosity calculation method flowchart based on two-dimensional nuclear magnetic resonance logging provided for Example 1;

[0036] Figure 3 The pore radius distribution graph of 13 cores obtained by constant-rate mercury injection experiment in Example 1;

[0037] Figure 4 The nuclear magnetic resonance T2 spectrum of 6 calibration cores determined by constant-rate mercury injection experiment in Example 1;

[0038] Figure 5 The single-core pore T2 upper limit of No. 1 calibration core determined by constant-rate mercury injection experiment in Example 1 Determination method schematic diagram;

[0039] Figure 6a The thin section photo of No. 7 calibration core with developed mold hole determined by cast thin section experiment in Example 1;

[0040] Figure 6b The pore T2 upper limit of No. 7 calibration core with developed mold hole determined by cast thin section experiment in Example 1 Determination method schematic diagram;

[0041] Figure 7a The thin section photo of No. 8 calibration core with developed intergranular pore determined by cast thin section experiment in Example 1;

[0042] Figure 7b T2 upper limit of the pore of the No. 8 calibration core for the development of the intergranular pore determined by the cast thin section experiment in Example 1 Schematic diagram of the determination method;

[0043] Figure 8a Imaging logging response graph of the No. 4 well section determined by the method of using the two-dimensional nuclear magnetic resonance logging response of the fracture development section in Example 1;

[0044] Figure 8b Schematic diagram of the positioning method of the T2 lower limit a3 of the fracture signal of the No. 4 well section determined by the method of using the two-dimensional nuclear magnetic resonance logging response of the fracture development section in Example 1.

[0045] Figure 9 Schematic diagram of the fracture scale of the plug-like core in Example 3;

[0046] Figure 10a Schematic diagram of the influence of the well wall drop block on the calibration when the fracture porosity is calibrated by using the prior art in Example 3;

[0047] Figure 10b Schematic diagram of the influence of the drilling-induced fracture on the calibration when the fracture porosity is calibrated by using the prior art in Example 3;

[0048] Figure 10c Schematic diagram of the influence of the carbon drop block on the calibration when the fracture porosity is calibrated by using the prior art in Example 3;

[0049] Figure 11 Comparison graph of the fracture porosity calculation results of the target well section by using the prior art and the method of Example 1 in Example 3;

[0050] Figure 12a Imaging logging graph of the 4635m-4638m well section in Example 3;

[0051] Figure 12b Two-dimensional nuclear magnetic resonance relaxation spectrum of the 4635m-4638m well section in Example 3;

[0052] Figure 13a Imaging logging graph of the 4759m-4762m well section in Example 3;

[0053] Figure 13b Two-dimensional nuclear magnetic resonance relaxation spectrum of the 4759m-4762m well section in Example 3. DETAILED DESCRIPTION

[0054] The application will be further described in connection with test examples and specific embodiments. However, it should not be understood that the scope of the above-mentioned subject matter of the application is limited to the following examples, and any technology realized based on the content of the application belongs to the scope of the application.

[0055] (1) Conventional logging: mainly refers to the logging methods that are measured in the engineering of exploration and development well logging, evaluation well logging and development well logging, that is, the so-called "nine curves" series - natural gamma, natural potential, caliper three lithology curves, shallow, medium and deep three resistivity curves, acoustic, neutron and density three porosity curves; (2) Nuclear magnetic resonance (NMR) logging: a method for measuring the free precession of hydrogen nuclei in the earth's magnetic field; (3) T2: transverse relaxation time.

[0056] Example 1

[0057] As Figure 1 A flowchart of a fracture porosity calculation method based on two-dimensional nuclear magnetic resonance logging is shown. Specifically, as shown in Figure 2 The steps include the following: step a. logging the drilling in the target area to obtain the logging parameters related to the fracture development degree. Specifically, the logging parameters related to the fracture development degree here include the fracture development position obtained by imaging logging; the two-dimensional nuclear magnetic resonance relaxation spectrum obtained by two-dimensional nuclear magnetic resonance logging;

[0058] The main advantage of two-dimensional nuclear magnetic resonance logging is that the response is not affected by the rock skeleton or is less affected by the rock skeleton, and the pore structure of the reservoir can be characterized. Generally speaking, the size of the reservoir space scale is positively correlated with the nuclear magnetic resonance T2 value, and the larger the scale, the higher the T2 value. Since there is a significant difference between the size of the fracture and the size of the pore, the fracture has an independent distribution range on the two-dimensional nuclear magnetic resonance relaxation spectrum, usually in the first signal concentration area on the right upper side of the relaxation spectrum, and has good identification. Based on this feature, the specific range of the fracture signal on the relaxation spectrum can be determined using the core-logging calibration method, and then the signal amount can be extracted and calculated to complete the calculation of the fracture porosity.

[0059] In this embodiment, the purpose of imaging logging is not to directly calculate the fracture porosity, but to calibrate the fracture development position, so as to prepare for the positioning of the fracture concentrated development section in step c.

[0060] Step b. Analyze the core of the target area to obtain parameters related to the pore structure; specifically, step b is to perform core nuclear magnetic resonance experiment to obtain T2 distribution; the purpose of this step is to determine the T2 distribution of the calibration sample, and to provide data basis for determining the upper limit T2 value of the pore based on the mathematical statistics method. It should be noted that the core nuclear magnetic resonance T2 and the logging nuclear magnetic resonance T2 are the same physical quantity, and the upper limit T2 value of the pore obtained by core calibration can be directly transplanted to logging.

[0061] Core constant rate mercury injection experiment is conducted to obtain core pore radius distribution; casting thin section experiment is conducted to obtain thin section pore type. Core casting thin section experiment and constant rate mercury injection experiment are mainly to obtain core pore radius distribution through these two experimental methods, so as to select the sample with relatively developed pore as the calibration sample in all cores. The above can obtain the parameters related to pore structure, that is, T2 distribution, core pore radius distribution and thin section pore type.

[0062] Step c. Using the logging parameters related to fracture development degree and the parameters related to pore structure obtained in steps a and b, the fracture-pore signal demarcation value a is obtained by using the combined calibration method based on constant rate mercury injection-core nuclear magnetic resonance, the combined calibration method based on casting thin section-core nuclear magnetic resonance and the fracture-concentrated development segment two-dimensional nuclear magnetic resonance logging response method. Specifically, the combined calibration method based on constant rate mercury injection-core nuclear magnetic resonance includes the following steps: step c11. The average value of the peak values of all core pore radius distributions is calculated; the core with a single core pore radius distribution peak value greater than the average value is selected as the calibration core of this method; step c12. The T2 distribution of each calibration core in this method is calculated to obtain the upper limit of the single core pore T2 of this method Step c13. The T2 distribution of each calibration core in this method is calculated to obtain the upper limit of the single core pore T2 of this method The arithmetic mean value is obtained to obtain the upper limit of the pore signal T2 of this method a1.

[0063] Further, The value of the core T2 distribution cumulative frequency reaches 95% when the fractile T2 value is reached. For the reservoir, due to the existence of heterogeneity, the physical properties of the core samples obtained at different depths may differ significantly, and the combined calibration method of constant rate mercury injection-core nuclear magnetic resonance is mainly to explore the maximum possible size of the pore radius, so the core with poor physical properties is not significant for this research, and therefore the core analysis test means is needed to find the core with poor physical properties and to be removed, and the core with good physical properties is reserved as the calibration core. Constant rate mercury injection experiment is an effective method to achieve this purpose, which can distinguish the throat from the pore to obtain a static curve reflecting only the pore radius distribution, and by comparing the pore radius distribution curves of different cores, the purpose of "removing the core with poor physical properties and reserving the core with good physical properties" can be well achieved.

[0064] For this embodiment, 13 cores are selected for constant rate mercury injection experiment (the basic data and experimental results of the 13 cores are shown in Table 1), such as Figure 3The pore radius distribution curve of each core is obtained, the peak value of the pore radius of each core is read, and the average value of the peak values of the 13 cores is calculated as 129.2 μm; the core with a peak value less than the value is rejected as a core with poor physical properties, and the core with a peak value greater than the value is retained as a core with good physical properties, that is, the "calibration core" in step c11.

[0065] The peak value is mainly used because the peak value is the main scale of the pore radius of the core and is representative of the physical properties of the whole core. The average value of the peak values of the multiple cores is mainly used as the cutoff value of the "bisection" method because the average value of the peak values of the multiple cores can represent the average physical properties of the whole reservoir, and the cores with less average reservoir contribution capacity are rejected, which focuses the main statistics on the cores with large pore sizes, and helps to improve the accuracy of the upper limit T2 calculation.

[0066] Table 1: Basic data and experimental results of 13 cores

[0067]

[0068]

[0069] According to the above principle, the calibration cores with a peak value of the pore radius greater than the average peak value are selected, as shown in Table 1, and the numbers are 1, 2, 5, 6, 10, and 12. Figure 4 The T2 distribution of the calibration cores obtained by the core NMR experiment is shown, and the quantile point of the cumulative frequency of 95% is used as the upper limit of the pore T2 of the single core of the method (data shown in Table 1, as Figure 5 No. 1 core position example). The cumulative frequency of 95% is used as the quantile point because the core T2 distribution usually has certain inversion non-convergence phenomenon or the phenomenon of wide T2 spectrum caused by small inversion regularization coefficient, and a small amount of signal at the right end is not included in the effective signal range. The 95% quantile point can retain the main T2 signal while effectively removing a small amount of noise signal caused by the above reasons, which has a positive significance for improving the accuracy of calibration.

[0070] The average value of the 6 calibration cores is used The upper limit of the pore signal T2 of the example based on the combined calibration method of constant-rate mercury injection-core NMR is a1=154 ms. The average value is used because it can reflect the general characteristics of the upper limit of the pore signal T2 of the reservoir in the study area. Specifically, the combined calibration method based on the casting slice-core NMR includes the following steps: step c21. Select the core with developed mold pores and intergranular pores as the calibration core of the method; step c22. Statistically obtain the T2 distribution of each calibration core of the method to obtain the upper limit of the pore T2 of the single core Step c23. Calculate the arithmetic mean value to obtain the upper limit a2 of the pore signal T2 of the method. Step c23. Calculate the arithmetic mean value to obtain the upper limit a2 of the pore signal T2 of the method.

[0071] Further, The value of the core T2 distribution cumulative frequency reaches 95% T2 quantile. The difference between the combined calibration method based on the casting slice-core NMR and the aforementioned “combined calibration method based on constant-rate mercury injection-core NMR” is that the casting slice data is used to select calibration cores with better physical properties. The casting slice refers to a slice made after a colloid with color different from the particles and not chemically reacting with the matrix particles is injected into the pore space. Such a slice is easier to observe the types and sizes of various pore spaces under a microscope, and is more intuitive than the aforementioned constant-rate mercury method. For tight sandstone, the main pore spaces include intergranular pores, intragranular dissolved pores, mold pores, clay mineral intercrystalline pores, and throat, etc. Among them, the sizes of the intergranular pores and the mold pores are usually larger than those of other types of pores, so the casting slice is selected under a microscope, and the slice with developed intergranular pores and mold pores is selected, and the core thereof is the calibration core. Table 2 shows the parameters and selection of 12 cores used in this step.

[0072] Table 2: Basic data and experimental result statistics of 12 cores

[0073]

[0074] Figure 6a 、 Figure 6b 、 Figure 7a 、 Figure 7b Table 2 shows the parameters and selection of 12 cores used in this step. Figure 6a 、 Figure 7a The core casting slice under the microscope, Figure 6b 、 Figure 7b is the determination method of the core T2 and the upper limit of the pore T2. The upper limit of the pore T2 of the single core in the combined calibration method based on the casting slice-core NMR The method is basically the same as the aforementioned joint calibration method based on constant-rate mercury injection-core nuclear magnetic resonance (also obtained by truncation of the T2 distribution at the 95% quantile of the cumulative frequency). Then obtain each core sample. (The average value), which will not be elaborated further.

[0075] The upper limit of the pore T2 value, α2 = 174 ms, was obtained based on the combined calibration method of cast thin section-core NMR. It should be noted that using constant-rate mercury intrusion porosimetry (CIP) and optimizing the core calibration from a mathematical and statistical perspective offers the advantage of greater accuracy, but it lacks intuitiveness. In contrast, the cast thin section method allows direct observation of different pore space types, and while its accuracy is slightly lower than CIP, it is more intuitive. The two methods complement each other; therefore, when calculating the fracture-pore signal boundary value α later, the average value of α1 and α2 can be used as the upper limit of the pore signal T2.

[0076] Specifically, the two-dimensional nuclear magnetic resonance logging response method for fracture-concentrated development sections includes the following steps: Step c31. Select the fracture-concentrated development section determined by imaging logging as the calibration section of this method; Step c32. Take the left boundary of the first signal concentration area on the upper right side of the two-dimensional nuclear magnetic resonance logging relaxation spectrum of the calibration section as the lower limit of the fracture signal T2 of a single section. Step c33. For each By taking the arithmetic mean, the lower limit α3 of the crack signal T2 can be obtained by this method.

[0077] Since imaging logging is an important standard for determining the qualitative development degree of fractures, the fracture concentration zones identified using imaging logging will inevitably show corresponding fracture responses in 2D NMR logging. Typically, the scale of fractures (micrometers to millimeters) is larger than the scale of pores and throats (nanometers to micrometers), therefore, they usually appear as the first concentrated signal region on the upper right side of the 2D NMR relaxation spectrum. Compared to one-dimensional NMR core analysis, 2D NMR logging T2–T1 spectrum inversion usually uses a larger regularization coefficient to highlight the concentrated signal characteristics. The signal typically does not exhibit inversion non-convergence or over-broadening characteristics; therefore, the left boundary can be directly taken as the lower limit of the fracture signal T2 at that depth, without the need to use the 95% quantile.

[0078] Table 3 shows the lower limit values ​​of fracture signal T2 for nine fracture-concentrated sections in the target area. The average value α3 = 210 ms, which is taken as the lower limit value α3 of fracture signal T2 for the two-dimensional nuclear magnetic resonance logging response method in the fracture-concentrated sections. Figure 8a , Figure 8b The table shows well section 4 in section 3. A schematic diagram of the determination process shows that, as determined by imaging logging, this well section is a region with concentrated fracture development. Figure 8a This is the imaging logging response map of the fractured section. Figure 8bFor this depth segment The positioning method is illustrated. The left boundary T2 value of the first signal on the upper right side of this well section is 202ms, therefore this well section...

[0079] Table 3. Statistical table of T2 lower limit results for fractures in 9 well sections

[0080]

[0081] Furthermore, the calculation method for the crack-pore signal boundary value α is as follows:

[0082]

[0083] In the formula, α is the fracture-pore signal boundary value, in ms; α1 is the upper limit of pore signal T2 determined by the joint calibration method based on constant-rate mercury injection-core nuclear magnetic resonance, in ms; α2 is the upper limit of pore signal T2 determined by the joint calibration method based on cast thin section-core nuclear magnetic resonance, in ms; α3 is the lower limit of fracture signal T2 determined by the two-dimensional nuclear magnetic resonance logging response method for fracture-concentrated development sections, in ms. α1 and α2 are the upper limits of pore signal T2, and α3 is the lower limit of fracture signal T2. Since there is a significant scale difference between pores and fractures, generally speaking, α1≈α2≤α3. Therefore, the first two are averaged to obtain the average value of the upper limit of pore signal T2, and then this value is averaged with α3 to obtain the fracture-pore signal boundary value α. For this embodiment, based on the aforementioned values ​​of α1, α2, and α3, the fracture-pore signal boundary value α is calculated to be 187 ms.

[0084] Step d. Use the fracture-pore signal boundary value α to extract the two-dimensional nuclear magnetic resonance (NMR) logging relaxation spectrum to obtain the fracture porosity. Specifically, step d includes the following steps: sum all signal quantities with T2 > α in the two-dimensional NMR relaxation spectrum; the summation result is the fracture porosity.

[0085]

[0086] In the formula, α represents crack porosity, in %; α is the crack-pore signal boundary value, in ms; T 2max The upper limit for measuring the lateral relaxation time of two-dimensional nuclear magnetic resonance logging instruments, in milliseconds (ms); T 1max The upper limit for measuring the longitudinal relaxation time of a two-dimensional nuclear magnetic resonance logging instrument, in milliseconds (ms); T 1min The lower limit for longitudinal relaxation time measurement of two-dimensional nuclear magnetic resonance logging instruments, in milliseconds (ms); P ij Let be the interval porosity value of the i-th horizontal and j-th vertical sampling interval in the two-dimensional nuclear magnetic resonance relaxation spectrum, %.

[0087] According to the definition of the crack-pore signal demarcation value a in the foregoing steps, it can be known that the signal on the left side of the relaxation spectrum is the pore, throat, clay water, and natural gas signal, and the signal on the right side is the crack signal. Therefore, the signal amount of all sampling intervals on the right side is summed, that is, the signal amount of all T2> a in the two-dimensional nuclear magnetic resonance relaxation spectrum is summed, and the crack porosity can be obtained.

[0088] The crack porosity calculation method based on two-dimensional nuclear magnetic resonance logging provided in the embodiment can be understood that the step a and the step b can be performed in sequence or synchronously, and the order of the step a and the step b can be exchanged. The method uses the two-dimensional nuclear magnetic resonance logging which is less affected by the rock skeleton, avoids the disadvantage that the conventional logging and the imaging logging are greatly affected by the mineral composition and the wellbore condition, and lays a method foundation for accurate calculation of the crack porosity. The method is based on the two-dimensional nuclear magnetic resonance logging which can reflect the pore structure, maximally differentiates the logging response difference between the pores and the cracks, and lays a theoretical foundation for accurate calculation of the crack porosity. The method uses various core analysis and testing means to select the calibration core with relatively developed pores, and uses the mathematical statistics method to make the upper limit of the pore signal T2 more reliable and the crack-pore decomposition value more clear, and thus the accuracy of the crack porosity calculation is improved.

[0089] Embodiment 2

[0090] The embodiment provides a crack porosity calculation system based on two-dimensional nuclear magnetic resonance logging, which comprises at least one processor and a memory in communication connection with the at least one processor. The memory stores instructions executable by the at least one processor, and the instructions are executed by the at least one processor to enable the at least one processor to execute the crack porosity calculation method based on two-dimensional nuclear magnetic resonance logging provided in the embodiment 1.

[0091] The crack porosity calculation system based on two-dimensional nuclear magnetic resonance logging provided in the embodiment avoids the disadvantage that the conventional logging and the imaging logging are greatly affected by the mineral composition and the wellbore condition, effectively solves the problems of low accuracy and high uncertainty of the conventional logging in calculating the crack porosity, uses various core analysis and testing means to select the calibration core with relatively developed pores, and uses the mathematical statistics method to make the upper limit of the pore signal T2 more reliable and the crack-pore decomposition value more clear, and thus the accuracy of the crack porosity calculation is improved, and the problems of relativity and multi-solution in calculating the crack porosity by the imaging logging are effectively solved.

[0092] Embodiment 3

[0093] The present embodiment takes a certain tight sandstone reservoir of the Xujiahe Formation in the Xinchang structural belt of the Sichuan Basin as an example, and uses the fracture porosity calculation methods based on two-dimensional nuclear magnetic resonance logging provided by the prior art and embodiment 1 to carry out research on fracture porosity calculation, which is specifically described as follows.

[0094] For example, Chinese invention patent No. CN114185108A discloses a fracture porosity determination method, a storage medium and a computer device. Or Chinese invention patent No. CN113971351A discloses a fracture porosity determination method and device. In summary, the main technical principle of the prior art is that the dual lateral resistivity of the fracture development section is obviously different due to different mud invasion degrees. Generally, the dual lateral resistivity of the fracture development section has a large difference, and the relationship between the dual lateral resistivity difference and the fracture porosity is established to obtain the calculation formula of the fracture porosity.

[0095] However, this type of technology has a series of problems, resulting in poor actual operability. The most important problem is that the fracture porosity lacks calibration when the original modeling is performed. The usual practice of the prior art is to use the core fracture porosity or the imaging logging fracture porosity as the fracture porosity label used when modeling, and then to fit to obtain the calculation formula. However, the above-mentioned method of obtaining the fracture porosity has problems: first, the full-diameter core fracture porosity cannot be used as the fracture porosity because the full-diameter core is taken to the ground after experiencing pressure release, and the fracture porosity measured under the ground condition (normal pressure) deviates completely from the fracture porosity under the original formation condition (tens of megapascals pressure); second, the piston core fracture porosity cannot be used as the fracture porosity because the observable fractures of the piston core are microfractures (for example Figure 9 The display is a typical microfracture on a core slice, which is usually nanometer-micrometer in size), not the micron-millimeter level of fractures that are significant for reservoir development, and the former has a porosity that is obviously lower than the latter. The real fracture development section cannot obtain piston core that can be used to measure the fracture porosity; furthermore, the imaging logging fracture porosity also cannot be used as the fracture porosity because the imaging logging fracture porosity is also indirectly calculated through a model, and the accuracy of the calculation is obviously affected by the surrounding rock, matrix properties, and shale bands. At the same time, induced fractures, wellbore sloughing, and the like also increase the imaging logging fracture porosity value, making it significantly distorted (for example Figure 10a is a schematic diagram of the influence of a "false fracture" on calibration, Figure 10a specifically shows the distortion of the fracture porosity caused by the wellbore sloughing between the two shear fractures. The sloughing section presents a low resistivity value in 360° around the well, and thus presents a large fracture porosity; Figure 10b is a schematic diagram of the influence of another "false fracture" on calibration, Figure 10bSpecifically, it was demonstrated that the presence of vertical induced seams significantly increased the true value of crack porosity; Figure 10c This is a schematic diagram illustrating the impact of another type of "false crack" on calibration. Figure 10c (A schematic diagram illustrating the higher fracture porosity caused by carbon debris shedding is shown). Another issue is that fracture porosity is not the only major factor causing the difference in resistivity between the two sides; wellbore conditions, drilling fluid density, soaking time, and matrix properties also affect this difference. Due to the numerous influencing factors, it is usually impossible to rule out the impact of conditions other than fractures on the difference in resistivity between the two sides.

[0096] In this embodiment, a commonly used method for determining fracture porosity in existing technologies is used as a comparative example. The fracture porosity of core or imaging logging is statistically analyzed, and the deep and shallow lateral resistivity values ​​of the response depth range are read to establish the relationship between fracture porosity and lateral resistivity, thus obtaining the calculation formula for fracture porosity using existing methods. Table 4 shows the statistically analyzed correspondence.

[0097] For different regions, based on the actual situation, the relationship between fracture porosity and lateral resistivity is established using commonly used existing methods for determining fracture porosity. For example, for region A, the model used is:

[0098]

[0099] In the formula, denoted as crack porosity (%); RD as deep lateral resistivity (Ω·m); RS as shallow lateral resistivity (Ω·m); a, b, and c are dimensionless coefficients. It should be noted that while the specific models used in this embodiment may differ for different regions, they are all within the technical framework of existing methods.

[0100] Table 4. Correspondence between crack porosity label values ​​and bilateral lateral resistivity

[0101]

[0102] Figure 11The calculation results of the fracture porosity determination method provided by the prior art and the method provided in Embodiment 1 are shown in the figure, in which the rightmost column of tadpoles is the qualitative fracture development determined by the imaging logging, and the more concentrated the tadpoles, the more developed the fractures. There are 7 fracture development segments in the well section, which are indicated by numbers ①-⑦. The third column from the right (the left scale value is 1% and the right scale value is 0) contains the fracture porosities calculated by using the prior art and the method provided in Embodiment 1. The fracture porosities calculated by using the prior art (the dotted line in the curve named FRACTURE_PHIE_RDRS in the column) do not match the fracture development segments with concentrated tadpoles at the high-value positions except for the local ① segment and the ④ segment. The solid line FRACTURE_PHIE_NMR shown in the right-filled form is the fracture porosity calculated by using the fracture porosity calculation method based on the two-dimensional nuclear magnetic resonance logging provided in Embodiment 1. The peak value of the curve has a good positive correlation with the density of the tadpole shape, which indicates that the fracture porosity calculated by the method has high reliability and obvious advantages compared with the prior art.

[0103] To further illustrate the limitations of the prior art, the ratio of the deep and shallow lateral resistivity curves is compared with the fracture porosities calculated by the fracture porosity determination method of the prior art. Figure 11 The second column from the right is the solid line RDRSRATIO, which is the ratio of the deep lateral resistivity RD and the shallow lateral resistivity RS. It is generally believed that the fracture development segment has a higher RD / RS ratio due to the influence of the mud filtrate invasion, and the prior art is based on this to calculate the fracture porosity. However, as can be seen from the figure, except for 4610-4620m, the high-value positions of RD / RS of other segments are located in the non-fracture development segments (such as 4752-4762m), and the RD / RS values of many fracture development segments are not high (such as 4630-4640m and 4700-4708m), which indicates that the high-value of RD / RS is neither a sufficient nor a necessary condition for the fracture development, and the fracture development segment can also have a lower RD / RS value (for example Figure 12a 、 Figure 12b , 4635-4638m, in which Figure 12a is the imaging logging figure, and a plurality of sinusoidal dark lines representing fractures are developed, Figure 12b is the two-dimensional nuclear magnetic resonance relaxation spectrum, and the fracture signal is strong at the arrow position, but the RD / RS is low, and the fracture can also be underdeveloped at the high-value position of RD / RS (such as Figure 13a 、 Figure 13b , 4759-4762m, in which Figure 13a is the imaging logging figure, and only the bottom arrow position has two fracture developments, and the remaining wide sinusoidal bands are shale bands, which are not fracture responses, Figure 13bFor two-dimensional nuclear magnetic resonance relaxation spectrum, the crack position signal is weak, but RD / RS is high. This shows that the RD / RS ratio cannot represent the crack development degree, and the existing crack porosity calculation technology has problems in the reliability of the principle.

[0104] In contrast, the crack porosity calculation method based on two-dimensional nuclear magnetic resonance logging provided in Embodiment 1 uses a method based on two-dimensional nuclear magnetic resonance logging which is not affected by the skeleton and can distinguish fluid components according to the pore structure, and the calculated crack porosity is not affected by factors such as wellbore conditions, matrix properties, and surrounding rock, matches well with the qualitative development characteristics of the cracks characterized by imaging logging, and the result has high reliability.

[0105] The above is only a preferred embodiment of the present application, and is not used to limit the present application, and any modification, equivalent replacement and improvement made within the spirit and principle of the present application shall be included in the protection scope of the present application.

Claims

1. A method for fracture porosity calculation based on two-dimensional nuclear magnetic resonance well logging, characterized in that, The method comprises the following steps: Step a. Logging the well in the target area to obtain a fracture development related logging parameter, which comprises a two-dimensional nuclear magnetic resonance relaxation spectrum; Step b. Analyzing the core in the target area to obtain a pore structure related parameter; Step c. Using a constant speed mercury injection-core nuclear magnetic resonance combined calibration method, a cast body slice-core nuclear magnetic resonance combined calibration method, and a fracture concentrated development section two-dimensional nuclear magnetic resonance logging response method to obtain a fracture-pore signal demarcation value α; Step d. Using the fracture-pore signal demarcation value α to intercept the two-dimensional nuclear magnetic resonance logging relaxation spectrum to obtain a fracture porosity.

2. The method of claim 1, wherein, The step a comprises the following steps: Performing an imaging logging to obtain a fracture development position; and performing a two-dimensional nuclear magnetic resonance logging to obtain the two-dimensional nuclear magnetic resonance relaxation spectrum.

3. The method of claim 1, wherein, The step b comprises the following steps: Performing a core nuclear magnetic resonance experiment to obtain a T2 distribution; Performing a core constant speed mercury injection experiment to obtain a core pore radius distribution; Performing a cast body slice experiment to obtain a slice pore type.

4. The method of claim 3, wherein, The constant speed mercury injection-core nuclear magnetic resonance combined calibration method comprises the following steps: Step c11. Statistically obtaining an average value of all core pore radius distribution peak values; and selecting a core with a core pore radius distribution peak value greater than the average value of all core pore radius distribution peak values as a calibration core of the constant speed mercury injection-core nuclear magnetic resonance combined calibration method; Step c12. Statistics the T2 distribution of each calibration core based on the constant-rate mercury injection-core NMR combined calibration method to obtain the upper limit of the single block core pore T2 based on the constant-rate mercury injection-core NMR combined calibration method Step c13. For each of the obtained porosity signals T2, the upper limit a1 of the porosity signal T2 based on the combined calibration method of constant-rate mercury injection - core NMR is obtained by taking the average of the upper limits a1 of the porosity signal T2 based on the combined calibration method of constant-rate mercury injection - core NMR for the respective porosity signals T2. Taking the average, the upper limit a1 of the porosity signal T2 5. The method of claim 4, wherein, The cast body slice-core nuclear magnetic resonance combined calibration method comprises the following steps: Step c21. Selecting a core with a mold hole and intergranular pore development as a calibration core of the cast body slice-core nuclear magnetic resonance combined calibration method; Step c22. Statistics the T2 distribution of each calibrated core by the cast thin section-core NMR combined calibration method to obtain the upper limit of the single block core pore T2 by the cast thin section-core NMR combined calibration method Step c23. For each of the N2 values of the parameter T2, the following is calculated: The upper limit a2 of the pore signal T2 based on the combined calibration of the casting thin sections - core NMR is obtained by averaging.

6. The method of claim 5, wherein, The and / or the is the quantile T2 value for the core T2 distribution at 95% cumulative frequency.

7. The method of claim 2, wherein, The fracture concentrated development section two-dimensional nuclear magnetic resonance logging response method comprises the following steps: Step c31. Selecting a fracture concentrated development section determined by the imaging logging as a calibration well section of the fracture concentrated development section two-dimensional nuclear magnetic resonance logging response method; Step c32. The left boundary of the first signal cluster area on the upper right side of the 2D NMR logging relaxation spectrum of the calibration well section of the fracture concentration development section 2D NMR logging response method is taken as the lower limit of the single well section fracture signal T2 Step c33. For each The lower limit a3 of the fracture signal T2 of the two-dimensional nuclear magnetic resonance logging response method in the fracture-concentrated development section is obtained by taking the average value.

8. The method of claim 1, wherein, The calculation method of the fracture-pore signal demarcation value α is as follows: In the formula, α is a fracture-pore signal demarcation value, ms; α1 is a pore signal T2 upper limit determined by using the constant speed mercury injection-core nuclear magnetic resonance combined calibration method, ms; α2 is a pore signal T2 upper limit determined by using the cast body slice-core nuclear magnetic resonance combined calibration method, ms; α3 is a fracture signal T2 lower limit determined by using the fracture concentrated development section two-dimensional nuclear magnetic resonance logging response method, ms.

9. The method of claim 2, wherein, The step d comprises the following steps: Summing all signal amounts with T2>α in the two-dimensional nuclear magnetic resonance relaxation spectrum, and the summation result is the fracture porosity: wherein is the fracture porosity, %; α is a fracture-pore signal demarcation value, ms; T 2max to measure the upper limit of the transverse relaxation time for a two-dimensional nuclear magnetic resonance logging instrument, ms; T 1max To measure the upper limit of the longitudinal relaxation time of the two-dimensional nuclear magnetic resonance logging instrument, ms; T 1min to measure the lower limit of the longitudinal relaxation time for a two-dimensional nuclear magnetic resonance logging instrument, ms; P ij Pij is the interval porosity value, % for the i-th sampling interval in the transverse direction and the j-th sampling interval in the longitudinal direction in the two-dimensional nuclear magnetic resonance relaxation spectrum.

10. A system for fracture porosity calculation based on two-dimensional nuclear magnetic resonance well logging, characterized in that, The system comprises at least one processor, and a memory connected in communication with the at least one processor; The memory stores instructions executable by the at least one processor, and the instructions are executed by the at least one processor to enable the at least one processor to execute the fracture porosity calculation method based on the two-dimensional nuclear magnetic resonance logging according to any one of claims 1 to 9.

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