Calibration method for nuclear magnetic fluid signal conversion relation with shale as carrier and application

Abstract

The invention provides a calibration method for a nuclear magnetic fluid signal conversion relation with shale as a carrier and application, and belongs to the technical field of unconventional oil-gas exploration and development. The method comprises the steps that shale samples are pretreated, and fluid saturation is conducted on the shale samples; the saturated shale is subjected to centrifugation and drying treatment, and T2 spectrogram testing is carried out by adopting nuclear magnetic resonance equipment in different treatment stages; and the conversion relation of the oil-water fluid in the shale is established by comparing the attenuation amount of the fluid in the shale pores at different stages with the T2 spectrogram signal difference value. The mass change caused by fluid loss in the closed coring shale is used as the verification basis of the conversion relation, and the reliability of the method is ensured. And then crude oil with different maturity degrees and formation water fluids with different mineralization degrees are adopted to repeat the operation, the calibration conversion relation of the crude oil with different maturity degrees and the formation water with different mineralization degrees is obtained, then the change rule of the calibration conversion relation is disclosed, and the accuracy and scientificity of the nuclear magnetic resonance technology in the aspect of shale fluid evaluation are improved.

Description

Technical Field

[0001] The 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 reserves and "sweet spot" selection. Although there are many technical means that can be applied to the evaluation of shale porosity and oil content, they are limited by the principles of the methods and the particularity of shale. The characterization effects of different methods have their own advantages and disadvantages and are difficult to match each other. Nuclear magnetic resonance technology has been widely used in characterizing reservoir pores and fluid occurrence. It mainly relies on the nuclear magnetic resonance phenomenon of hydrogen atoms in the fluid, and links the intensity of the nuclear magnetic resonance signal with the volume of fluid inside the shale. By quantifying the shale pore fluid, the key parameters of shale porosity, oil content and other key parameters can be accurately evaluated. Therefore, the calibration relationship, as a "bridge" for the conversion of nuclear magnetic resonance signals and fluid volume, is directly related to the accuracy and precision of shale pore fluid quantification. Previous researchers generally used known volumes of water / D2O as standard samples to quantify conversion relationships. However, the hydrogen content of different fluid components in shale must be different, and the conversion relationship calibrated by a single fluid is difficult to be used for the quantification of complex fluid components in shale. Some scholars have also proposed using n-dodecane and water as calibration fluids to establish the conversion relationship between oil and water in shale, and then further improved the use of crude oil and formation water produced in shale core wells. At the same time, it was found that the conversion coefficients of crude oil with different maturity and formation water with different mineralization were also significantly different. In addition, the establishment of fluid conversion relationships in the past all relied on the calibration of free-state fluids, while the fluids in shale are all present in nano- to micron-scale pores, and it is still unknown whether the hydrogen-containing components such as clay minerals and organic matter in shale have an impact on the conversion relationship. Therefore, it is urgent to establish a fluid calibration conversion relationship under the confinement of nanopores in shale.

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

[0004] (1) The conversion relationship of a single calibration fluid is limited in scope of application. The conversion relationships mentioned in many previous patent documents are all saturated fluids such as n-dodecane and deionized water. The conversion relationship is relatively fixed and is only related to the frequency and test parameters of different nuclear magnetic resonance equipment. However, with the application of closed coring technology, the 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 water of different mineralization. This is of great significance for the porosity and oil content evaluation of shale in closed coring.

[0005] (2) The existing calibration conversion relationships are mostly based 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 establish conversion relationships based on the measurement of nuclear magnetic resonance signals of quantitative (mass / volume) fluids. 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 technology in the oil and gas field depends greatly on the accuracy of the calibration conversion coefficient, which is also the main reason for the calculation error. However, there is little attention paid to this aspect at present. Although the calibration of pure fluid is convenient and fast, the accuracy of its conversion coefficient still needs to be verified. It is urgent to explore a shale pore fluid calibration method with high precision and wide application range. The significance of this study is to maximize the closeness of the fluid occurrence environment in the calibration process of the conversion coefficient to the real shale, simulate the fluid attenuation process in the shale, combine the sample signal quantity change shown in the nuclear magnetic T2 spectrum and the mass change of one ten-thousandth of the balance weighing, establish the fluid calibration conversion relationship with shale as the carrier, and then explore the change law of the conversion relationship between crude oil of different maturity and formation water of different mineralization, establish the calibration coefficient of the conversion relationship between crude oil and formation water, so as to reduce the difficulty of obtaining the conversion relationship. The proposed method is expected to greatly improve the accuracy and precision of nuclear magnetic resonance technology in evaluating shale pore fluids, and can serve as an important technical support for the application of nuclear magnetic resonance technology in the oil and gas field. Summary of the invention

[0008] In view of the shortcomings of the prior art, the present invention provides a method for establishing an oil-water nuclear magnetic resonance calibration conversion relationship using shale as a carrier, which 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 solution of the present invention is as follows:

[0010] A method for calibrating a nuclear magnetic fluid signal conversion relationship 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 a nuclear magnetic resonance T2 spectrum test on the shale after oil washing;

[0014] Step 4, pressurizing the washed shale to saturate the crude oil and formation water fluids respectively;

[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 conducting a nuclear magnetic resonance T2 spectrum test;

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

[0018] Step 8, verifying 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 the same characteristics) into standard blocks or plugs, the sample is required to be complete without obvious cracks, the number of prepared pieces is 2, the sample diameter is <2.5cm, the length is <5cm, and the weight is 15g to 20g; 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 0.2MPa, 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 one-tenth of a balance.

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

[0024] Furthermore, the above step 4 includes firstly vacuuming the two 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 tests 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 centrifuging time of 2 h, performing a nuclear magnetic resonance T2 spectrum test and weighing after centrifugation; then drying the shale after centrifugation at a drying temperature of 110° C. and a drying time of 6 h; 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 of crude oil and formation water fluid is consistent, 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] Wherein, S0 is the signal amount of shale NMR T2 spectrum after oil washing, au; S1 is the signal amount of shale NMR T2 spectrum after saturation, au; S2 is the signal amount of shale NMR T2 spectrum after centrifugation, au; S3 is the signal amount of shale NMR T2 spectrum after drying, au; m0 is the mass of shale sample after oil washing, mg; m1 is the mass of shale sample after saturation, mg; m2 is the mass of shale sample after centrifugation, mg; m3 is the mass of shale sample after drying, mg.

[0032] Furthermore, the above step 8 includes using the mass change caused by fluid loss in the closed coring shale as a basis for verifying the conversion relationship. The oil and water fluids inside the closed coring sample will be rapidly lost in the natural environment, which is reflected as the change of oil and water signal quantity in the nuclear magnetic resonance spectrum. In addition, the mass of the sample shown by the one-tenth of a ten-thousandth balance will also decay. On the one hand, the above-mentioned calibration conversion coefficient is applied, combined with the signal quantity in the nuclear magnetic resonance T2 spectrum to calculate the oil and water loss mass at different placement times. On the other hand, the one-tenth of a ten-thousandth 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%.

[0033] Furthermore, the above step 9 includes selecting crude oils of different maturity and formation waters of different salinity as saturated solutions to repeat the processes 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 rules 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 with the distilled water conversion relationship as a baseline. We define f o With f w The calibration coefficients for crude oils of different maturity and formation waters of different salinity are 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 mineralization of formation water, kppm;

[0038] When 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 calibration coefficient. The formula is as follows:

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

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

[0041] In the formula, 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, which, when executed by a processor, implements the steps in the calibration method of a nuclear magnetic fluid signal conversion relationship using shale as a carrier as described above.

[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 in the calibration method of the nuclear magnetic fluid signal conversion relationship using shale as a carrier are implemented as described above.

[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 with 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 scientificity of nuclear magnetic resonance technology in evaluating shale fluids.

[0046] The present invention is different from the previous conversion relationship establishment of fixed fluid (dodecane / distilled water). The crude oil and formation water produced by shale oil wells are used as calibration fluids. By collecting crude oils of different maturity and formation waters of different salinity, the change law of the conversion relationship with maturity and salinity is established. Taking distilled water as the baseline, the conversion relationship calibration coefficients of crude oils of different maturity and formation waters of different salinity are determined. This greatly broadens the application scope of the conversion coefficient and provides convenience for other scholars in the calibration of conversion relationships in different work areas. BRIEF DESCRIPTION OF THE DRAWINGS

[0047] Figure 1 The present invention studies the flow chart;

[0048] Figure 2 Figure 1 is a diagram showing changes in the NMR T2 spectrum during the shale self-calibration process (taking sample A as an example); (a) shows changes in the NMR T2 spectrum of sample A1 after oil washing, saturation with crude oil, centrifugation and drying, and (b) shows 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 figure is a verification diagram of the accuracy of the calibration conversion coefficient; (a) is the oil-water fluid and mass attenuation law in the pores of the closed coring shale; (b) is the comparison between the mass loss obtained based on the conversion relationship and the mass loss detected by the 1 / 10,000 balance;

[0052] Figure 6 is the calibration conversion coefficient of 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 by way of embodiments in conjunction with the accompanying drawings, but is not limited thereto.

[0055] Embodiment 1:

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

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

[0058] Step 2: Wash and dry the prepared sample under the same conditions. Place the prepared sample in a core rapid oil washing instrument. The washing solvent is a mixed solvent of dichloromethane: acetone = 3:1 by volume. The washing temperature is 85°C, the pressure is 0.2MPa, the washing time is 15 days, and the shale dry sample is obtained after drying at 110°C after washing. Use a 1 / 10,000 balance for weighing.

[0059] Step 3, perform nuclear magnetic T2 spectrum test on shales A1, A2, B1, and B2 after oil washing, respectively, using the MicroMR20-025V low-field nuclear magnetic resonance equipment produced by Suzhou Newmai, with a main frequency of 20MHz, a magnet strength of 0.5T, and a coil diameter of 25mm; T2 spectrum test uses CPMG sequence; perform nuclear magnetic T2 spectrum test on shale samples after oil washing, and regard it as the base signal of shale samples. The nuclear magnetic test parameters are shown in Table 1.

[0060] Table 1 Parameters of shale sample NMR test

[0061]

[0062] Step 4, the prepared shale samples are vacuumed, and then the washed samples A1 and B1 are saturated with crude oil using a core saturation device, and A2 and B2 are saturated with formation water. The saturation pressure is 15 MPa and the saturation time is 48 h. The pressure needs to be maintained manually during the saturation process until the pressure indication of the saturation device tends to be stable, which is considered to be complete saturation.

[0063] Step 5: wipe off the excess fluid on the surface of the shale samples A1, A2, B1, and B2 after saturation, weigh them, and perform nuclear magnetic resonance T2 spectrum tests respectively. The test parameters are consistent with Table 1, and the nuclear magnetic resonance signal is extracted.

[0064] Step 6, centrifuge and dry the saturated shale sample at a centrifugal speed of 8000r / min and a centrifugal time of 2h. After centrifugation, perform a nuclear magnetic resonance T2 spectrum test and weigh the sample. Then dry the centrifuged shale at a drying temperature of 110°C and a drying time of 6h. After drying, perform a nuclear magnetic resonance T2 spectrum test and weigh the sample. During the treatment process, perform a nuclear magnetic resonance T2 spectrum test and weigh the sample. Figure 2 .

[0065] Step 7, statistically analyze the signal quantity and mass change of the nuclear magnetic resonance T2 spectrum of the shale sample obtained in the above step, 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 fluid 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] Wherein, S0 is the signal amount of shale NMR T2 spectrum after oil washing, au; S1 is the signal amount of shale NMR T2 spectrum after saturation, au; S2 is the signal amount of shale NMR T2 spectrum after centrifugation, au; S3 is the signal amount of shale NMR T2 spectrum after drying, au; m0 is the mass of shale sample after oil washing, mg; m1 is the mass of shale sample after saturation, mg; m2 is the mass of shale sample after centrifugation, mg; m3 is the mass of 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, using the mass change caused by fluid loss in the sealed coring shale as the basis for verifying the conversion relationship, such as Figure 4As shown, the oil and water fluid inside the closed 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 shown 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 a higher 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 improve the application scope of the method disclosed in the present invention, the conversion ratio of the conversion relationship between shale with different maturity and formation water with different mineralization is established with distilled water as the reference line. Figure 7 As shown, 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 (i.e., distilled water) conversion relationship as the baseline, normalize the conversion relationship between crude oils of different maturities and different mineralized formation waters. We use the distilled water calibration conversion coefficient as the baseline and define f o With f w The calibration coefficients for crude oils of different maturity and formation waters of different salinity are 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 mineralization of formation water, kppm;

[0080] When 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 calibration coefficient, which greatly reduces 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] In the formula, 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] Embodiment 2:

[0085] An electronic device comprises a memory, a processor and a program stored in the memory and executable on the processor, wherein when the processor executes the program, the steps in the calibration method of a nuclear magnetic fluid signal conversion relationship using shale as a carrier as described in Example 1 are implemented.

Claims

1. A calibration method for 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 a nuclear magnetic resonance T2 spectrum test on the shale after oil washing; Step 4, pressurizing the washed shale to saturate the crude oil and formation water fluids respectively; Step 5, taking out the saturated shale, wiping off the saturated fluid attached to the surface, weighing it, and performing nuclear magnetic resonance T2 spectrum tests on the saturated shale to extract its nuclear magnetic resonance signal; Step 6, centrifuging and drying the saturated shale and then conducting a nuclear magnetic resonance T2 spectrum test; Step 7, calculating the NMR calibration conversion coefficient using the obtained NMR T2 spectrum signal and the sample mass; Step 8, calibration conversion relationship accuracy verification; the mass change caused by fluid loss in the closed coring shale is used as the verification basis for the conversion relationship. The oil and water fluids in the closed coring sample will be rapidly lost 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 shown by the one-ten-thousandth 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 oil and water loss mass at different placement times. On the other hand, the one-ten-thousandth 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: selecting crude oils of different maturity and formation waters of different salinity as saturated solutions to repeat the process of steps 4 to 7, statistically analyzing the changing trend of calibration conversion coefficients of crude oil and formation water with maturity and salinity, and obtaining the changing law of calibration conversion coefficients of crude oil and formation water in shale; Step 10, calibration coefficient establishment, using the distilled water calibration conversion coefficient as the baseline, defines 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 of nuclear magnetic fluid signal conversion relationship using shale as 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 2 pieces, with a sample diameter of <2.5 cm, a length of <5 cm, and a weight of 15 g to 20 g.

3. The calibration method of nuclear magnetic fluid signal conversion relationship using shale as 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 0.2MPa, 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 one-tenth of a balance.

4. The calibration method of nuclear magnetic fluid signal conversion relationship using shale as 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, the main frequency of the nuclear magnetic resonance test equipment is 20MHz, the magnet strength is 0.5T, and the coil diameter is 25mm; the T2 spectrum test adopts the CPMG sequence; the nuclear magnetic T2 spectrum test is performed 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 carrier according to claim 1 is characterized in that: The above step 4 includes firstly vacuuming the two 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 is stable, it is considered to be fully saturated.

6. The calibration method of nuclear magnetic fluid signal conversion relationship using shale as carrier according to claim 1 is characterized in that: The above step 6 includes centrifuging the shale at a speed of 8000 r / min and a centrifuging time of 2 h, and 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 h; and performing a nuclear magnetic resonance T2 spectrum test and weighing after drying.

7. The calibration method of nuclear magnetic fluid signal conversion relationship using shale as 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 consistent, and the formula is as follows: ΔS i =S i+1 -S i (i=0,1,2)(1) Δm i =m i+1 -m i (i=0,1,2)(2) Wherein, S0 is the signal amount of shale NMR T2 spectrum after oil washing, au; S1 is the signal amount of shale NMR T2 spectrum after saturation, au; S2 is the signal amount of shale NMR T2 spectrum after centrifugation, au; S3 is the signal amount of shale NMR T2 spectrum after drying, au; m0 is the mass of shale sample after oil washing, mg; m1 is the mass of shale sample after saturation, mg; m2 is the mass of shale sample after centrifugation, mg; m3 is the mass of shale sample after drying, mg.

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

9. The calibration method of nuclear magnetic fluid signal conversion relationship using shale as 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 f o With f w The calibration coefficients for crude oils of different maturity and formation waters of different salinity are 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 mineralization of formation water, kppm; When 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 calibration coefficient. The formula is as follows: k o =f o *k b (6) k w =f w *k b (7) In the formula, 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 mineralization degrees, au / g; k b is the conversion factor for distilled water calibration, au / g.

10. An electronic device comprising a memory, a processor, and a program stored in the memory and executable on the processor, wherein when the processor executes the program, the steps in the method for calibrating the conversion relationship of nuclear magnetic fluid signals using shale as a carrier as described in any one of claims 1 to 9 are implemented.

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