A calibration method and application of nuclear magnetic fluid signal conversion relationship based on shale

Abstract

The present invention provides a calibration method and application for the conversion relationship of nuclear magnetic fluid signals using shale as a carrier, which belongs to the field of unconventional oil and gas exploration and development technology. The method includes pre-treating shale samples and saturating the shale samples with fluid; centrifuging and drying the saturated shale, and performing T2 spectrum testing using nuclear magnetic resonance equipment at different stages of the treatment; and establishing a conversion relationship between oil and water fluids in the shale by comparing the fluid attenuation in the shale pores at different stages with the difference in T2 spectrum signals. The mass change caused by fluid loss in the sealed coring shale is used as the verification basis for the conversion relationship to ensure the reliability of the method. The above operation is then repeated using crude oil of different maturity and formation water of different salinity to obtain the calibration conversion relationship of crude oil of different maturity and formation water of different salinity, thereby revealing their change patterns and improving the accuracy and scientific nature of nuclear magnetic resonance technology in evaluating shale fluids.

Description

Technical Field

[0001] The present invention relates to a calibration method and application of a nuclear magnetic fluid signal conversion relationship using shale as a carrier, belonging to the technical field of unconventional oil and gas exploration and development. Background Art

[0002] The porosity and oil content of shale oil reservoirs are key parameters for determining reserves and selecting "sweet spot" areas. Although a variety of technical approaches are currently available for evaluating shale porosity and oil content, these methods are limited by their principles and the specific characteristics of shale, resulting in different characterization results with varying strengths and weaknesses, and difficult to match. Nuclear magnetic resonance (NMR) technology has been widely used to characterize reservoir pores and fluid distribution. It primarily relies on the NMR phenomenon of hydrogen atoms in fluids, linking NMR signal intensity to the volume of fluid within the shale. By quantifying shale pore fluids, it enables accurate evaluation of key parameters such as shale porosity and oil content. Therefore, the calibration relationship, serving as a "bridge" for converting NMR signals to fluid volume, is directly related to the accuracy and precision of quantification of shale pore fluids. Previous researchers have generally used known volumes of water / D₂O as standard samples to quantify conversion relationships. However, the hydrogen content of different fluid components in shale inevitably varies, making conversion relationships based on single-fluid calibration difficult to universally apply to the quantification of complex fluid components in shale. Other researchers have proposed using n-dodecane and water as calibration fluids to establish oil-water conversion relationships in shale, respectively. This was further improved by using crude oil and formation water produced from shale core wells. They also found significant differences in conversion coefficients for crude oils of varying maturity and formation waters of varying salinity. Furthermore, previous fluid conversion relationships have relied on calibration of free-state fluids, whereas fluids in shale are located in nano- to micron-scale pores. Furthermore, it is unknown whether hydrogen-containing components in shale, such as clay minerals and organic matter, affect the conversion relationships. Therefore, it is urgent to establish fluid conversion relationships within the confines of nanopores in shale.

[0003] Through the above analysis, the conversion relationship is the key to the calculation of fluid volume from nuclear magnetic resonance signals. The problems and defects of the existing technology are as follows:

[0004] (1) The application scope of the conversion relationship of a single calibration fluid is limited. The conversion relationships mentioned in many previous patent documents are all saturated fluids such as n-dodecane and deionized water. Their conversion relationships are relatively fixed and are only related to the frequency and test parameters of different nuclear magnetic resonance equipment. However, with the application of closed coring technology, original fluids such as crude oil and formation water are retained in the core pores. This provides convenience for the evaluation of shale oil content and saturation, but also puts forward higher requirements for the conversion relationship of different fluids. In addition, due to the large differences in the maturity and composition of crude oil produced in different work areas and different well locations, it is urgent to determine the calibration conversion relationship and change law of crude oils of different maturity and formation waters of different salinity. This is of great significance for the porosity and oil content evaluation of closed coring shale.

[0005] (2) Existing calibration conversion relationships mostly rely on pure fluid calibration, which is inconsistent with the actual occurrence environment of fluids in shale pores. In the past, the establishment of fluid conversion relationships all relied on the calibration of free-state fluids. The general method is to measure the nuclear magnetic resonance signal of a certain amount (mass / volume) of fluid and establish a conversion relationship based on this. However, due to the extremely complex occurrence characteristics of different fluids in shale and the large differences in the relaxation mechanisms of fluids in different types of pores, it is still unknown whether hydrogen-containing components such as clay minerals and organic matter in shale have an impact on the conversion relationship.

[0006] The difficulty and significance of solving the above technical problems:

[0007] The application of nuclear magnetic resonance (NMR) technology in the oil and gas sector relies heavily on the accuracy of calibration conversion coefficients, a major cause of calculation errors. However, this area has received relatively little attention. While calibration of pure fluids is convenient and rapid, the accuracy of these conversion coefficients remains to be verified. Therefore, a highly accurate and widely applicable calibration method for shale pore fluids is urgently needed. The significance of this study lies in aligning the fluid occurrence environment during conversion coefficient calibration with the actual shale as closely as possible, simulating the fluid attenuation process in shale. By combining the sample signal variation revealed by NMR T2 spectra with the mass variation measured by a 1 / 10,000 balance, a fluid calibration conversion relationship based on shale was established. Furthermore, the variability of this conversion relationship for crude oils of varying maturity and formation waters of varying salinity was explored, and calibration coefficients for the crude oil and formation water conversion relationships were established, thereby reducing the difficulty of obtaining these conversion relationships. This proposed method is expected to significantly improve the accuracy and precision of NMR evaluation of shale pore fluids and could serve as an important technical support for the application of NMR technology in the oil and gas sector. Summary of the Invention

[0008] In response to the shortcomings of the existing technology, the present invention provides a method for establishing an oil-water nuclear magnetic resonance calibration conversion relationship using shale as a carrier. This method improves the defect that the pure fluid used in the traditional calibration conversion relationship establishment process does not match the actual shale fluid occurrence characteristics, and further reveals the variation law of the calibration conversion coefficients of crude oil and formation water in shale.

[0009] The technical solutions of the present invention are as follows:

[0010] A method for calibrating the conversion relationship of nuclear magnetic fluid signals using shale as a carrier specifically comprises the following steps:

[0011] Step 1, preparation of shale samples;

[0012] Step 2: washing the prepared shale sample with oil and drying it;

[0013] Step 3, performing nuclear magnetic T2 spectrum testing on the shale after oil washing;

[0014] Step 4: pressurizing the washed shale to saturate it with crude oil and formation water;

[0015] Step 5, performing a nuclear magnetic T2 spectrum test on the saturated shale;

[0016] Step 6, centrifuging and drying the saturated shale and then performing a nuclear magnetic resonance T2 spectrum test;

[0017] Step 7, calculation of NMR calibration conversion coefficient;

[0018] Step 8: Verify the accuracy of the calibration conversion relationship;

[0019] Step 9, revealing the law of calibration conversion relationship;

[0020] Step 10: Calibration coefficient establishment.

[0021] Furthermore, the above step 1 includes: cutting the same shale sample (with consistent characteristics) into standard blocks or plugs, the sample is required to be complete and without obvious cracks, the number of prepared pieces is 2, the sample diameter is less than 2.5 cm, the length is less than 5 cm, and the weight is 15 g to 20 g; the two samples prepared from the same shale have similar characteristics.

[0022] Furthermore, the above step 2 includes placing the prepared sample in a core rapid oil washing instrument, using a mixed solvent with a volume ratio of dichloromethane: acetone = 3:1 as the oil washing solvent, the oil washing temperature is 85°C, the pressure is 0.2 MPa, and the oil washing time is 15 days. After the oil washing is completed, the sample is placed at 110°C for drying to obtain a shale sample after oil washing, and weighed using a 1 / 10,000 balance.

[0023] Furthermore, the above step 3 includes selecting a MicroMR20-025V low-field nuclear magnetic resonance device produced by Suzhou Newmai, with a main frequency of 20 MHz, a magnet strength of 0.5 T, and a coil diameter of 25 mm; T2 spectrum testing uses a CPMG sequence; and performing a nuclear magnetic T2 spectrum test on the shale sample after oil washing, which is regarded as the basement signal of the shale sample.

[0024] Furthermore, the above-mentioned step 4 includes first vacuuming the two prepared shale samples, and then using a core saturation device to saturate the two samples with crude oil and formation water fluid respectively, with a saturation pressure of 15 MPa. When the pressure reading of the saturation device tends to be stable, it is considered to be fully saturated.

[0025] Furthermore, the above step 5 includes taking out the saturated shale, wiping off the saturated fluid attached to the surface, weighing it, and performing nuclear magnetic resonance T2 spectrum testing to extract its nuclear magnetic resonance signal quantity.

[0026] Furthermore, the above step 6 includes centrifuging the shale at a speed of 8000 r / min and a centrifugal time of 2 hours, performing a nuclear magnetic resonance T2 spectrum test and weighing after centrifugation; then drying the centrifuged shale at a drying temperature of 110°C and a drying time of 6 hours; and performing a nuclear magnetic resonance T2 spectrum test and weighing after drying.

[0027] Furthermore, the above step 7 includes defining the nuclear magnetic signal of the unit mass calibration fluid as the calibration conversion coefficient k. The calibration conversion process for crude oil and formation water fluids is the same, and the formula is as follows:

[0028] ΔS i =S i+1 -S i (i=0,1,2)(1)

[0029] Δm i =m i+1 -m i (i=0,1,2)(2)

[0030]

[0031] Where, S0 is the signal amount of the shale nuclear magnetic T2 spectrum after oil washing, au; S1 is the signal amount of the shale nuclear magnetic T2 spectrum after saturation, au; S2 is the signal amount of the shale nuclear magnetic T2 spectrum after centrifugation, au; S3 is the signal amount of the shale nuclear magnetic T2 spectrum after drying, au; m0 is the mass of the shale sample after oil washing, mg; m1 is the mass of the shale sample after saturation, mg; m2 is the mass of the shale sample after centrifugation, mg; and m3 is the mass of the shale sample after drying, mg.

[0032] Furthermore, the above-mentioned step 8 includes using the mass change caused by fluid loss in the sealed coring shale as a basis for verifying the conversion relationship. The oil and water fluids in the sealed coring sample will be rapidly lost in the natural environment, which is reflected as a change in the oil and water signal amount in the nuclear magnetic resonance spectrum. In addition, the mass of the sample displayed by the 1 / 10,000 balance will also decay. On the one hand, the above-mentioned calibration conversion coefficient is applied, combined with the signal amount in the nuclear magnetic resonance T2 spectrum to calculate the oil and water loss mass at different placement times. On the other hand, the 1 / 10,000 balance is used to record the change in sample mass during the loss process, thereby verifying the accuracy of the calibration conversion relationship. If the error range is less than 5%, the conversion relationship is considered valid.

[0033] Furthermore, the above-mentioned step 9 includes selecting crude oils of different maturity and formation waters of different salinity as saturated solutions and repeating the process of steps 4 to 7, statistically analyzing the changing trends of the calibration conversion coefficients of crude oil and formation water with maturity and salinity, and obtaining the changing patterns of the calibration conversion coefficients of crude oil and formation water in shale.

[0034] Furthermore, the above step 10 includes normalizing the conversion relationship between crude oils of different maturity and different mineralized formation waters using the distilled water conversion relationship as a baseline. We define f o With f w is the calibration coefficient for crude oils of different maturity and formation waters of different salinity, and the formula is as follows:

[0035] f o =0.5283*ln(Ro)+1.0868(4)

[0036] f w =-0.0004*S w +0.999(5)

[0037] Where Ro is the maturity of shale oil, %; S w is the formation water salinity, kppm;

[0038] Once the maturity of shale oil in a certain area is known, the conversion relationship between crude oil and formation water can be calculated using the distilled water conversion relationship and the calibration coefficient. The formula is as follows:

[0039] k o =f o *k b (6)

[0040] k w =f w *k b (7)

[0041] Where k o is the conversion coefficient of crude oil with different maturity, au / g; k w is the conversion coefficient of formation water with different salinity, au / g; k b is the conversion factor for distilled water calibration, au / g.

[0042] A computer-readable storage medium stores a program thereon, which, when executed by a processor, implements the steps of the above-mentioned method for calibrating the conversion relationship of nuclear magnetic fluid signals using shale as a carrier.

[0043] An electronic device includes a memory, a processor, and a program stored in the memory and executable on the processor. When the processor executes the program, the steps of the calibration method for the conversion relationship of nuclear magnetic fluid signals using shale as a carrier are implemented.

[0044] The beneficial effects of the present invention are:

[0045] Different from the traditional pure fluid calibration method, the present invention proposes a calibration method under nanopore confinement using shale samples as carriers. This method restores the occurrence characteristics of the calibration fluid, and the calibration process is completely consistent with the actual sample test environment and parameters. The obtained calibration results are more accurate and reliable, further improving the accuracy and scientific nature of nuclear magnetic resonance technology in evaluating shale fluids.

[0046] The present invention is different from the previous conversion relationship established based on a fixed fluid (dodecane / distilled water). It uses crude oil and formation water produced from shale oil wells as calibration fluids. By collecting crude oils of different maturity and formation waters of different salinity, it establishes the law of change of the conversion relationship with maturity and salinity. Taking distilled water as the baseline, it determines the conversion relationship calibration coefficients of crude oils of different maturity and formation waters of different salinity. This greatly broadens the application scope of the conversion coefficients and facilitates the work of other scholars in the calibration of conversion relationships in different work areas. BRIEF DESCRIPTION OF THE DRAWINGS

[0047] Figure 1 This is a flow chart of the present invention;

[0048] Figure 2 Figure 2 shows the changes in the NMR T2 spectrum during the shale self-calibration process (taking sample A as an example); (a) shows the changes in the NMR T2 spectrum of sample A1 after oil washing, saturation with crude oil, centrifugation, and drying; (b) shows the changes in the NMR T2 spectrum of sample A2 after oil washing, saturation with formation water, centrifugation, and drying.

[0049] Figure 3 This is the calibration conversion relationship diagram of the shale self-calibration method; (a) is the case of saturated crude oil; (b) is the case of saturated formation water;

[0050] Figure 4 The T1-T2 spectra of sealed coring shale at different placement times; (a)(b)(c)(d)(e)(f)(h)(i) are different placement times;

[0051] Figure 5 The following is a diagram verifying the accuracy of the calibration conversion coefficient; (a) shows the oil-water fluid and mass attenuation law in the pores of the sealed coring shale; (b) shows the comparison between the mass loss obtained based on the conversion relationship and the mass loss detected by a 1 / 10,000 balance;

[0052] Figure 6 is the calibration conversion coefficient between crude oil and formation water, where (a) is the case of crude oil with different maturity; (b) is the case of formation water with different salinity;

[0053] Figure 7 is the calibration coefficient for crude oil and formation water, where (a) is the case of crude oil with different maturity; (b) is the case of formation water with different salinity. DETAILED DESCRIPTION

[0054] The present invention will be further described below with reference to embodiments and accompanying drawings, but is not limited thereto.

[0055] Example 1:

[0056] The present invention mainly proposes a calibration method for the conversion relationship of nuclear magnetic fluid signals using shale as a carrier. The present invention is further described below with reference to the accompanying drawings and examples. In this example, two shale samples from the Shahejie Formation in the Dongying Depression, numbered A and B, were selected for the experiment.

[0057] Step 1: Use wire cutting equipment to prepare block plug samples of shale samples A and B. The sample diameter is required to be less than 2.5 cm, the length is less than 5 cm, and the weight is 15 g to 20 g; the sample is divided into two shale parts, numbered A1, A2, B1, and B2.

[0058] Step 2: The prepared sample was washed with oil and dried under the same conditions. The sample was placed in a core rapid oil washer using a mixed solvent of dichloromethane and acetone in a volume ratio of 3:1. The washing temperature was 85°C, the pressure was 0.2 MPa, and the washing time was 15 days. After washing, the shale sample was dried at 110°C to obtain a dry sample. The sample was weighed using a 1 / 10,000 balance.

[0059] In step 3, NMR T2 spectra were performed on the washed shale samples A1, A2, B1, and B2, respectively. A MicroMR20-025V low-field NMR instrument, manufactured by Suzhou Newmai, was used. The NMR test equipment had a main frequency of 20 MHz, a magnet strength of 0.5 T, and a coil diameter of 25 mm. The T2 spectrum was tested using a CPMG sequence. The NMR T2 spectra of the washed shale samples were analyzed and considered the basement signal. The NMR test parameters are shown in Table 1.

[0060] Table 1 NMR test parameters of shale samples

[0061]

[0062] In step 4, the prepared shale samples were vacuumed, and then the washed samples A1 and B1 were saturated with crude oil using a core saturation device, and A2 and B2 were saturated with formation water. The saturation pressure was 15 MPa and the saturation time was 48 h. During the saturation process, the pressure needed to be maintained manually until the pressure reading of the saturation device tended to be stable, which was considered to be complete saturation.

[0063] In step 5, the excess fluid on the surface of the shale samples A1, A2, B1, and B2 after saturation was wiped off, and then weighed. Nuclear magnetic resonance T2 spectrum tests were performed on each of the shale samples. The test parameters were consistent with those in Table 1, and the nuclear magnetic resonance signal quantities were extracted.

[0064] Step 6: Centrifuge and dry the saturated shale sample at a centrifugal speed of 8000 r / min for 2 hours. After centrifugation, perform nuclear magnetic T2 spectrum test and weigh the sample. Then dry the centrifuged shale at a drying temperature of 110°C for 6 hours. After drying, perform nuclear magnetic T2 spectrum test and weigh the sample. Figure 2 .

[0065] Step 7: The signal amount and mass change of the nuclear magnetic T2 spectrum of the shale sample obtained in the above step are statistically analyzed, as shown in Table 2.

[0066] Table 2 Changes in sample NMR T2 spectrum signal and mass during shale self-calibration

[0067]

[0068] The nuclear magnetic signal of the unit mass calibration fluid is defined as the calibration conversion coefficient k. The calibration conversion process of crude oil and formation water fluids is the same, and the formula is as follows:

[0069] ΔS i =S i+1 -S i (i=0,1,2)(1)

[0070] Δm i =m i+1 -m i (i=0,1,2)(2)

[0071]

[0072] Where, S0 is the signal amount of the shale nuclear magnetic T2 spectrum after oil washing, au; S1 is the signal amount of the shale nuclear magnetic T2 spectrum after saturation, au; S2 is the signal amount of the shale nuclear magnetic T2 spectrum after centrifugation, au; S3 is the signal amount of the shale nuclear magnetic T2 spectrum after drying, au; m0 is the mass of the shale sample after oil washing, mg; m1 is the mass of the shale sample after saturation, mg; m2 is the mass of the shale sample after centrifugation, mg; and m3 is the mass of the shale sample after drying, mg.

[0073] According to the above formula, the calibration conversion relationship is established as follows: Figure 3 shown.

[0074] Step 8: The mass change caused by fluid loss in the sealed cored shale is used as the basis for verifying the conversion relationship, such as Figure 4As shown, the oil and water fluids in the sealed core sample will rapidly dissipate in the natural environment, which is reflected in the change of oil and water signal in the nuclear magnetic spectrum. In addition, the mass of the sample displayed by the 1 / 10,000 balance will also decay. On the one hand, the above calibration conversion coefficient is applied, combined with the signal in the nuclear magnetic T2 spectrum to calculate the mass of oil and water lost at different placement times. On the other hand, the 1 / 10,000 balance is used to record the change of sample mass during the loss process, so as to verify the accuracy of the calibration conversion relationship. The conversion relationship is considered valid if the error range is less than 5%. Figure 5 As shown, the two are basically consistent, indicating that the fluid calibration coefficient established by the method disclosed in the present invention has high accuracy.

[0075] Step 9: Using crude oils of different maturity and formation waters of different salinity as saturated fluids, repeat the above calibration steps. The NMR T2 spectra of crude oils of different maturity and formation waters of different salinity are as follows: Figure 6 As shown, in order to expand the application scope of the method disclosed in the present invention, the conversion ratio of the conversion relationship between shale of different maturity and formation water of different salinity is established with distilled water as the reference line. Figure 7 As shown in the figure, it shows that the crude oil conversion coefficient gradually increases with the maturity, and the formation water conversion coefficient gradually decreases with the salinity.

[0076] Step 10: Using the distilled water conversion relationship as the baseline, normalize the conversion relationship between crude oils of different maturity and different mineralized formation waters. We use the distilled water calibration conversion coefficient as the baseline and define f o With f w is the calibration coefficient for crude oils of different maturity and formation waters of different salinity, and the formula is as follows:

[0077] f o =0.5283*ln(Ro)+1.0868(4)

[0078] f w =-0.0004*S w +0.999(5)

[0079] Where Ro is the maturity of shale oil, %; S w is the formation water salinity, kppm;

[0080] Once the maturity of shale oil in a certain area is known, the conversion relationship between crude oil and formation water can be calculated using the distilled water conversion relationship and calibration coefficient, greatly reducing the difficulty of obtaining the conversion relationship of shale fluids in different regions. The formula is as follows:

[0081] k o =f o *k b (6)

[0082] k w =fw *k b (7)

[0083] Where k o is the conversion coefficient of crude oil with different maturity, au / g; k w is the conversion coefficient of formation water with different salinity, au / g; k b is the conversion factor for distilled water calibration, au / g.

[0084] Example 2:

[0085] An electronic device includes a memory, a processor, and a program stored in the memory and executable on the processor. When the processor executes the program, the steps of the method for calibrating the conversion relationship of nuclear magnetic fluid signals using shale as a carrier as described in Example 1 are implemented.

Claims

1. A method for calibrating the conversion relationship of nuclear magnetic fluid signals using shale as a carrier, characterized in that: The following steps are involved: Step 1, preparation of shale samples; Step 2: washing the prepared shale sample with oil and drying it; Step 3, performing nuclear magnetic T2 spectrum testing on the shale after oil washing; Step 4: pressurizing the washed shale to saturate it with crude oil and formation water; Step 5: Take out the saturated shale, wipe off the saturated fluid attached to the surface, weigh it, and perform nuclear magnetic resonance T2 spectrum test on the saturated shale to extract its nuclear magnetic resonance signal; Step 6, centrifuging and drying the saturated shale and then performing a nuclear magnetic resonance T2 spectrum test; Step 7, calculating the NMR calibration conversion coefficient using the obtained NMR T2 spectrum signal and sample mass; Step 8: Verify the accuracy of the calibration conversion relationship. The mass change caused by fluid loss in the sealed coring shale is used as the verification basis for the conversion relationship. The oil and water fluids in the sealed coring sample will be rapidly lost in the natural environment, which is reflected as the change of oil and water signal in the nuclear magnetic spectrum. In addition, the mass of the sample displayed by the 1 / 10,000 balance will also decay. On the one hand, the above calibration conversion coefficient is applied, combined with the signal amount in the nuclear magnetic T2 spectrum to calculate the oil and water loss mass at different placement times. On the other hand, the 1 / 10,000 balance is used to record the change of sample mass during the loss process, so as to verify the accuracy of the calibration conversion relationship. Step 9: Revealing the law of calibration conversion relationship: Select crude oils of different maturity and formation waters of different salinity as saturated solutions and repeat the process from Step 4 to Step 7. Statistically analyze the changing trend of crude oil and formation water calibration conversion coefficients with maturity and salinity to obtain the changing law of crude oil and formation water calibration conversion coefficients in shale. Step 10: Establish the calibration coefficient. Using the distilled water calibration conversion coefficient as the baseline, define the calibration coefficients for crude oils of different maturity and formation waters of different salinities. Once the maturity of shale oil in a certain area is known, the conversion relationship between crude oil and formation water can be calculated based on the distilled water conversion relationship and the calibration coefficient.

2. The calibration method for the nuclear magnetic fluid signal conversion relationship using shale as a carrier according to claim 1 is characterized in that: The above step 1 includes: cutting the same shale sample into standard blocks or plugs, preparing two pieces, with a sample diameter of less than 2.5 cm, a length of less than 5 cm, and a weight of 15 g to 20 g.

3. The calibration method for the nuclear magnetic fluid signal conversion relationship using shale as a carrier according to claim 1 is characterized in that: The above step 2 includes placing the prepared sample in a core rapid oil washing instrument, using a mixed solvent with a volume ratio of dichloromethane: acetone = 3:1 as the oil washing solvent, the oil washing temperature is 85°C, the pressure is 0.2 MPa, and the oil washing time is 15 days. After the oil washing is completed, the sample is placed at 110°C for drying to obtain a shale sample after oil washing, and weighed using a 1 / 10,000 balance.

4. The calibration method for the nuclear magnetic fluid signal conversion relationship using shale as a carrier according to claim 1 is characterized in that: The above step 3 includes selecting the MicroMR20-025V low-field nuclear magnetic resonance equipment produced by Suzhou Newmai, with a main frequency of 20 MHz, a magnet strength of 0.5 T, and a coil diameter of 25 mm; T2 spectrum testing uses a CPMG sequence; and performing a nuclear magnetic T2 spectrum test on the shale sample after oil washing, which is regarded as the basement signal of the shale sample.

5. The calibration method of nuclear magnetic fluid signal conversion relationship using shale as a carrier according to claim 1 is characterized in that: The above step 4 includes first vacuuming the two prepared shale samples, and then using a core saturation device to saturate the two samples with crude oil and formation water fluid respectively. The saturation pressure is 15 MPa. When the pressure reading of the saturation device is stable, it is considered to be fully saturated.

6. The calibration method for the nuclear magnetic fluid signal conversion relationship using shale as a carrier according to claim 1 is characterized in that: The above step 6 includes centrifuging the shale at a speed of 8000 r / min for 2 hours, performing a nuclear magnetic resonance (NMR) T2 spectrum test and weighing the shale after centrifugation; then drying the centrifuged shale at a temperature of 110° C. for 6 hours; and then performing a nuclear magnetic resonance (NMR) T2 spectrum test and weighing the shale after drying.

7. The method for calibrating the conversion relationship of nuclear magnetic fluid signals using shale as a carrier according to claim 1 is characterized in that: The above step 7 includes defining the nuclear magnetic signal of the unit mass calibration fluid as the calibration conversion coefficient k. The calibration conversion process of crude oil and formation water fluid is the same, and the formula is as follows: （1） （2） （3） Where, S0 is the signal amount of the shale nuclear magnetic T2 spectrum after oil washing, au; S1 is the signal amount of the shale nuclear magnetic T2 spectrum after saturation, au; S2 is the signal amount of the shale nuclear magnetic T2 spectrum after centrifugation, au; S3 is the signal amount of the shale nuclear magnetic T2 spectrum after drying, au; m0 is the mass of the shale sample after oil washing, mg; m1 is the mass of the shale sample after saturation, mg; m2 is the mass of the shale sample after centrifugation, mg; and m3 is the mass of the shale sample after drying, mg.

8. The method for calibrating the conversion relationship of nuclear magnetic fluid signals using shale as a carrier according to claim 1 is characterized in that: In step 8 above, the quality data obtained from the two aspects are compared. If the error range is less than 5%, the conversion relationship is considered valid.

9. The method for calibrating the conversion relationship of nuclear magnetic fluid signals using shale as a carrier according to claim 1 is characterized in that: The above step 10 includes normalizing the conversion relationship between crude oils of different maturity and different mineralized formation waters with the distilled water conversion relationship as the baseline, and defining the conversion coefficient of distilled water as the baseline. f o and f w is the calibration coefficient for crude oils of different maturity and formation waters of different salinity, and the formula is as follows: f o =0.5283*ln( Ro )+1.0868 （4） f w = -0.0004* S w +0.999 （5） Where, Ro is the maturity of shale oil, %; S w is the formation water salinity, kppm; Once the maturity of shale oil in a certain area is known, the conversion relationship between crude oil and formation water can be calculated using the distilled water conversion relationship and the calibration coefficient. The formula is as follows: k o = f o * k b （6） k w = f w * k b （7） Where, k o is the conversion coefficient of crude oil with different maturity, au / g; k w is the conversion coefficient of formation water with different salinity, au / g; k b is the conversion factor for distilled water calibration, au / g.

10. An electronic device, characterized in that: The method comprises a memory, a processor and a program stored in the memory and executable on the processor. When the processor executes the program, the steps of the method for calibrating the conversion relationship of nuclear magnetic fluid signals using shale as a carrier as claimed in claim 1 are implemented.

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