Shale oil reservoir in-situ pore oil-water distribution nuclear magnetic resonance test method

Abstract

The invention discloses a nuclear magnetic resonance testing method for in-situ pore oil-water distribution of a shale oil reservoir. The method mainly solves the problem that an existing testing method cannot effectively recover shale oil reservoir in-situ pore oil-water distribution and cannot achieve quantitative evaluation. The method comprises the following steps: S1, testing a nuclear magnetic resonance T1-T2 spectrum of an original state of a shale core sample in a receiving state; s2, recovering a water state shale T1-T2 spectrum for the test; establishing a shale T1-T2 spectrum pore water signal amplitude marking equation; s3, testing a T1-T2 spectrum of the shale in the recovered oil-water state; s4, testing a shale T1-T2 spectrum in a dry state of washing oil; s5, a saturated oil state shale T1-T2 spectrum is tested, and a pore oil signal amplitude marking equation is calibrated; and quantitatively calculating the content and distribution of shale in-situ pore oil and water. According to the method, the occurrence state, content and distribution of in-situ pore oil and water of the shale oil reservoir are determined through reasonable test process design, and the parameter calculation precision of the shale oil reservoir is improved.

Description

Technical field:

[0001] The present invention relates to the technical field of seismic survey, and in particular to a nuclear magnetic resonance testing method for in-situ pore oil-water distribution in a shale oil reservoir. Background technology:

[0002] Reserve calculation is an important part of shale oil development. The commonly used methods are mainly based on the calculation of oil content by rock pyrolysis or chloroform extraction. However, there is light hydrocarbon loss in the process of coring, transportation and sample preparation, and the better the reservoir properties of shale, the greater the loss, making it difficult for the currently used unified correction coefficient to accurately and effectively reflect the in-situ oil content of shale. In addition, the commonly used correction method mainly calculates the total oil content of shale, and it is difficult to distinguish the content of shale oil in different states. Currently, only free oil is the most recoverable part of shale oil. The unified correction coefficient may lead to underestimation of the oil content of shale oil layers with the best reservoir properties, and it is difficult to effectively evaluate the recoverable part of shale oil, which in turn affects the accurate calculation of shale oil reserves and the evaluation of recoverability.

[0003] According to literature retrieval, so far, domestic and foreign research has mainly focused on testing shale in a receiving state or saturated with oil and water. There is little research on the distribution of oil and water in shale pores in an in-situ state, and an effective experimental testing and analysis method has not yet been established. Summary of the invention:

[0004] The present invention aims to solve the problem that the existing testing methods in the background technology cannot effectively restore the in-situ pore oil and water distribution and quantitative evaluation of the content of shale oil reservoirs, and provide a shale oil reservoir in-situ pore oil and water distribution nuclear magnetic resonance testing method. The shale oil reservoir in-situ pore oil and water distribution nuclear magnetic resonance testing method determines the occurrence state, content and distribution of in-situ pore oil and water in the shale oil reservoir through a reasonable test process design, and improves the calculation accuracy of shale oil reservoir parameters.

[0005] The present invention solves the problem through the following technical solution: The shale oil reservoir in-situ pore oil-water distribution nuclear magnetic resonance testing method comprises the following steps:

[0006] Step 1: for the shale core sample in the receiving state, testing the nuclear magnetic resonance T1-T2 spectrum of the original state;

[0007] Step 2: Perform shale pore water recovery on the shale core sample in the receiving state to obtain a shale sample with restored water; test the T1-T2 spectrum of the shale in the restored water state; and establish a pore water signal amplitude calibration equation for the shale T1-T2 spectrum;

[0008] Step 3: Recover the shale pore oil from the shale sample with restored water to obtain a shale sample with restored oil and water; test the T1-T2 spectrum of the shale in the restored oil and water state; extract the signal amplitudes of the shale pore water, adsorbed oil, bound oil and movable oil after the oil and water are restored;

[0009] Step 4: Process the shale sample after oil and water recovery, obtain the shale sample in the oil-washed and dried state, and test the T1-T2 spectrum of the shale in the oil-washed and dried state;

[0010] Step 5: Process the shale sample in the oil-washed dry state, obtain the shale sample in the oil-saturated state, test the T1-T2 spectrum of the shale in the oil-saturated state, and calibrate the amplitude calibration equation of the pore oil signal;

[0011] Step 6: Quantitatively calculate the content and distribution of in-situ pore oil and water in shale.

[0012] Furthermore, in the step 1, the echo interval (TE) during the nuclear magnetic resonance test is less than 0.1 ms.

[0013] Furthermore, the method for processing the shale sample for water recovery in step 2 is: placing the sample in an environment with a relative humidity of 98% formed by a saturated K2SO4 solution to balance water, restore the original pore water distribution, and obtain the shale sample for water recovery;

[0014] The sample mass was recorded during the water balance process. When the mass difference between two consecutive samples was less than 0.01 g, the shale water recovery was considered complete.

[0015] Furthermore, in step 2, the method for establishing the amplitude marking equation of the pore water signal of the shale T1-T2 spectrum is:

[0016] Based on the test of the T1-T2 spectrum of shale in the state of water recovery, the pore water signal amplitude and the amount of water absorbed before and after the shale water recovery are obtained. The linear trend line is fitted using the scatter plot of pore water and its signal amplitude, and the pore water signal amplitude marking equation of the shale T1-T2 spectrum is established; based on the establishment of the pore water signal amplitude marking equation of the shale T1-T2 spectrum, k is obtained. w :

[0017] Based on the obtained k w , establish the amplitude marking equation of pore water signal in shale T1-T2 spectrum;

[0018] Furthermore, the amplitude marking equation of the pore water signal of the shale T1-T2 spectrum is:

[0019] m w =k w A w (1)

[0020] Where: m w Indicates the amount of water absorbed, g; A wrepresents the amplitude of the pore water signal in the T1-T2 spectrum, dimensionless; k w is the pore water T1-T2 spectrum signal amplitude conversion coefficient.

[0021] Furthermore, the processing method of the shale sample for recovering oil and water in step 3 is: the shale sample for recovering water is subjected to vacuum pressure saturation instrument, vacuumed for 30 minutes, pressurized to 10 MPa for 24 hours to saturate the light oil, recover the shale diffused pore oil, and obtain the shale sample for recovering oil and water.

[0022] Furthermore, the method for extracting the signal amplitudes of shale pore water, adsorbed oil, bound oil and movable oil after oil and water recovery in step 3 is:

[0023] By testing the T1-T2 spectrum of shale in the restored oil-water state, the signal amplitudes of pore water, adsorbed oil, bound oil and movable oil in the shale after oil-water restoration can be extracted by utilizing the different signal amplitudes and distribution positions of oil and water in different states in the pores in the T1-T2 spectrum.

[0024] Furthermore, in step 4, the method for processing the shale sample after oil and water recovery to obtain the shale sample in the oil-washed dry state is:

[0025] The shale sample for oil-water recovery was washed with oil at 0.2 MPa and 80°C for 7 days using a mixed solution of dichloromethane and acetone, and then dried at 110°C for 24 hours to obtain a shale sample in an oil-washed dry state; the volume ratio of dichloromethane to acetone in the mixed solution was 3:1.

[0026] Furthermore, in step 5, the method for processing the shale sample in the oil-washed dry state to obtain the shale sample in the oil-saturated state is as follows:

[0027] A vacuum pressure saturation instrument was used on the shale samples in the oil-washed dry state. The samples were vacuumed for 6 hours and pressurized to 10 MPa for 24 hours to obtain shale samples in the oil-saturated state.

[0028] Furthermore, in step 5, the method for testing the T1-T2 spectrum of shale in the oil-saturated state and calibrating the amplitude calibration equation of the pore oil signal is:

[0029] Based on the T1-T2 spectrum of the tested shale in the oil-saturated state, the pore oil signal amplitude and saturated oil volume before and after the shale is saturated with oil are obtained. The linear trend line is fitted using the scatter plot of the pore oil and its signal amplitude, and the pore oil signal amplitude marking equation is established.

[0030] Based on the calibration equation of pore oil signal amplitude, k is obtained. o ;

[0031] Based on the obtained k o , establish the calibration equation for the amplitude of pore oil signal;

[0032] The pore oil signal amplitude calibration equation is:

[0033] m o =k o A o (2)

[0034] In the formula, m o Indicates the amount of saturated oil, g; A o represents the amplitude of the pore oil signal in the T1-T2 spectrum, dimensionless; k o is the conversion coefficient of the pore oil T1-T2 spectrum signal amplitude.

[0035] Furthermore, the method for quantitatively calculating the content and distribution of shale in-situ pore oil and water in step 6 is:

[0036] Based on step 3, the signal amplitudes of shale pore water, adsorbed oil, bound oil and movable oil after oil and water recovery are extracted;

[0037] By combining the pore water signal amplitude calibration equation established in step 2 and the pore oil signal amplitude calibration equation established in step 4, the weight of oil and water in the pores can be calculated, and the content and distribution of in-situ pore oil and water in shale can be quantitatively calculated.

[0038] Compared with the above background technology, the present invention has the following beneficial effects:

[0039] The test and evaluation method for characterizing in-situ pore oil and water in shale oil reservoirs of the present invention solves the problem of effectively restoring the in-situ pore oil and water distribution and quantitative evaluation of shale oil reservoirs in the existing technical methods, improves the calculation accuracy of shale oil reservoir parameters, and can achieve accurate evaluation of shale pore oil and water content and distribution. The evaluation results show that the method can accurately calculate the content of shale pore water, adsorbed oil, bound oil and movable oil, and improve the evaluation accuracy of in-situ pore fluid in shale.

[0040] The present invention recovers the lost pore water and light oil in the shale oil reservoir by balancing water and saturating light oil. The method improves the evaluation accuracy of the in-situ pore oil and water of the shale oil reservoir on the basis of accurately recovering the in-situ pore oil and water of the shale oil reservoir, and further accurately calculates the shale oil reserves.

[0041] The present invention determines the occurrence state, content and distribution of in-situ pore oil and water in shale oil reservoirs through reasonable test process design, improves the calculation accuracy of shale oil reservoir parameters, and eliminates the influence of shale light oil and water loss on the evaluation accuracy of shale oil content during coring, transportation and sample preparation. Description of the drawings:

[0042] Attached Figure 1 This is a flow chart of the in-situ pore oil-water distribution nuclear magnetic resonance testing method of shale oil reservoirs of the present invention;

[0043] Attached Figure 2 Attached is the distribution diagram of the nuclear magnetic resonance T1-T2 spectrum of the shale core under different conditions in the embodiment of the present invention; Figure 3 This is the amplitude diagram of pore oil and water signals extracted from the T1-T2 spectrum of shale after oil and water recovery in an embodiment of the present invention (au represents dimensionless);

[0044] Attached Figure 4 A scatter diagram of pore water and its signal amplitude in an embodiment of the present invention;

[0045] Attached Figure 5 This is a scatter diagram of pore oil and its signal amplitude in an embodiment of the present invention;

[0046] Attached Figure 6 This is a distribution diagram of oil and water content in shale pores in the in-situ state according to an embodiment of the present invention. Specific implementation method:

[0047] In order to make the objectives, technical solutions and advantages of the present invention more clear, the embodiments of the present invention will be further described in detail below with reference to the accompanying drawings.

[0048] The present invention provides a shale oil reservoir in-situ pore oil-water distribution nuclear magnetic resonance testing method, comprising the following steps:

[0049] Step 1: For the shale core sample in the receiving state, test its original state NMR T1-T2 spectrum; in order to accurately test the distribution of oil and water in shale pores, the echo interval (T E ) should be less than 0.1ms.

[0050] Step 2: Perform shale pore water recovery on the shale core sample in the receiving state to obtain a shale sample with restored water; test the T1-T2 spectrum of the shale in the restored water state; and establish a pore water signal amplitude calibration equation for the shale T1-T2 spectrum;

[0051] The processing method of the shale sample for water recovery is as follows: placing the sample in environmental balancing water with a relative humidity of 98% (saturated K2SO4 solution) to restore the original pore water distribution and obtain the shale sample for water recovery; recording the sample mass during the water balancing process, and when the difference between the mass of two adjacent samples is less than 0.01g, it is considered that the shale water recovery is completed;

[0052] Based on the test of the shale T1-T2 spectrum of water recovery state, the pore water signal amplitude and absorbed water volume before and after the shale water recovery are obtained, and the pore water signal amplitude marking equation of the shale T1-T2 spectrum is established; based on the establishment of the shale T1-T2 spectrum pore water signal amplitude marking equation, k is obtained. w :

[0053] The amplitude marking equation of the pore water signal of the shale T1-T2 spectrum is:

[0054] m w =k w A w (1)

[0055] Where: m w Indicates the amount of water absorbed, g; A w represents the amplitude of the pore water signal in the T1-T2 spectrum, dimensionless; k w is the pore water T1-T2 spectrum signal amplitude conversion coefficient.

[0056] Step 3: Recover the shale pore oil from the shale sample with restored water to obtain a shale sample with restored oil and water; test the T1-T2 spectrum of the shale in the restored oil and water state; extract the signal amplitudes of the shale pore water, adsorbed oil, bound oil and movable oil after the oil and water are restored;

[0057] The shale sample for water recovery was evacuated for 30 minutes using a vacuum pressure saturation instrument and pressurized to 10 MPa for 24 hours to saturate the light oil to recover the pore oil in the shale and obtain the shale sample for oil and water recovery.

[0058] By testing the T1-T2 spectrum of shale in the restored oil-water state, the signal amplitudes of pore water, adsorbed oil, bound oil and movable oil in the shale after oil-water restoration can be extracted by utilizing the different signal amplitudes and distribution positions of oil and water in different states in the pores in the T1-T2 spectrum.

[0059] Step 4: Process the shale sample after oil and water recovery, obtain the shale sample in the oil-washed and dried state, and test the T1-T2 spectrum of the shale in the oil-washed and dried state;

[0060] The shale samples for oil-water recovery were washed with a mixed solution of dichloromethane and acetone (volume ratio 3:1) at 0.2 MPa and 80°C for 7 days, and then dried at 110°C for 24 hours to obtain shale samples in an oil-washed and dry state.

[0061] Step 5: Process the shale sample in the oil-washed dry state, obtain the shale sample in the oil-saturated state, test the T1-T2 spectrum of the shale in the oil-saturated state, and calibrate the amplitude calibration equation of the pore oil signal;

[0062] A vacuum pressure saturation instrument was used on the shale samples in the oil-washed dry state. The samples were vacuumed for 6 hours and pressurized to 10 MPa for 24 hours to obtain shale samples in the oil-saturated state.

[0063] Based on the test T1-T2 spectrum, the calibration equation for the pore oil signal amplitude is established to obtain k o ;

[0064] The calibration equation for the pore oil signal amplitude is:

[0065] m o =k o Ao (2)

[0066] In the formula, m o Indicates the amount of saturated oil, g; A o represents the amplitude of the pore oil signal in the T1-T2 spectrum, dimensionless; k o is the conversion coefficient of the pore oil T1-T2 spectrum signal amplitude.

[0067] Step 6: quantitatively calculate the content and distribution of shale in-situ pore oil and water;

[0068] Based on step 3, the signal amplitudes of shale pore water, adsorbed oil, bound oil and movable oil after oil and water recovery are extracted;

[0069] By combining the pore water signal amplitude calibration equation established in step 2 and the pore oil signal amplitude calibration equation established in step 4, the weight of oil and water in the pores can be calculated, and the content and distribution of in-situ pore oil and water in shale can be quantitatively calculated.

[0070] Example 1

[0071] like Figure 1 As shown, the embodiment of the present invention provides a shale oil reservoir in-situ pore oil and water distribution nuclear magnetic resonance testing method. The oil and water T1-T2 spectrum distribution of steps 1 to 5 of the shale oil reservoir testing process is shown in the attached Figure 2 Attached Figure 2 A indicates capillary bound water (pore water); B, C and D represent adsorbed oil, bound oil and movable oil, i.e. pore oil, respectively; F, G and H represent (quasi) solid hydrogen nucleus signals, namely clay bound water (adsorbed water, structural water), asphaltene and kerogen, respectively. Figure 2 There are 5 pictures in it: Take the core No. 57 of GY18 well as an example, among which:

[0072] Figure 2 a is the receiving state diagram of GY18-57-1;

[0073] Figure 2 b is the state diagram of GY18-57-2 as equilibrium water (recovery water);

[0074] Figure 2 c is the state diagram of GY18-57-3 as balanced water + saturated oil (restored oil and water);

[0075] Figure 2 d is the drying state diagram of GY18-57-4 for washing oil;

[0076] Figure 2 e is the state diagram of GY18-57-6 for oil washing and drying + equilibrium water.

[0077] Twelve shale cores from the shale oil reservoir GY18 well were selected and nuclear magnetic resonance tests were carried out in the receiving state, balanced water, balanced water + saturated light oil (hereinafter referred to as recovered oil and water), oil washed and dried, and saturated with oil, respectively, to obtain the corresponding T1-T2 spectra, and extract the signal amplitudes of oil and water in the pores.

[0078] Taking the core No. 57 of Well GY18 as an example, after water recovery, the Figure 2 b, and the attached Figure 2 Compared with the receiving state in Figure a, the capillary bound water signal increases, the bound oil signal decreases, and the adsorbed oil signal increases. The entry of pore water causes the distribution of shale oil to change. A scatter plot is established using the amount of absorbed water and the amplitude of the pore water signal to obtain the pore water marking equation (see Appendix Figure 4 ). Figure 2 c, and the attached Figure 2 Compared with the receiving state of a, after the oil and water are restored, the capillary bound water signal increases, the adsorbed oil changes slightly, and the bound oil and movable oil signals increase, that is, after the core is taken out from the in-situ formation, more pore water, bound oil and movable oil escape. Figure 2 e, and the attached Figure 2 Compared with the oil washing and drying, the signal amplitude of shale pore oil (adsorbed oil, bound oil, and movable oil) in the saturated oil state increases significantly. A scatter plot is established based on the signal amplitude change and the saturated oil volume to obtain the pore oil marking equation (see Appendix Figure 5 ).

[0079] By the attached Figure 2 The signal amplitude changes in each area of ​​the T1-T2 spectrum in the figure show that the T1-T2 spectrum obtained by NMR testing can effectively indicate the distribution of shale pore fluids. The T1-T2 spectrum after oil and water recovery can be used to obtain the distribution characteristics of oil and water in the shale pores. The signal amplitudes of capillary bound water, adsorbed oil, bound oil and movable oil in 12 shale cores after oil and water recovery were quantitatively extracted (see Appendix Figure 3 ), that is, the A of the in-situ pores is obtained o and A w , k is obtained by combining the oil and water signal amplitude marking equations (Formula 2, Formula 1) o and k w , the content of oil and water in the shale in-situ pores can be quantitatively calculated (see Appendix Figure 6 ).

Claims

1. A method for testing the in-situ pore oil-water distribution in a shale oil reservoir by nuclear magnetic resonance, characterized in that: The following steps are involved: Step 1: for the shale core sample in the receiving state, testing the nuclear magnetic resonance T1-T2 spectrum of the original state; Step 2: Perform shale pore water recovery on the shale core sample in the receiving state to obtain a shale sample with restored water; test the T1-T2 spectrum of the shale in the restored water state; and establish a pore water signal amplitude calibration equation for the shale T1-T2 spectrum; Step 3: Recover the shale pore oil from the shale sample with restored water to obtain a shale sample with restored oil and water; test the T1-T2 spectrum of the shale in the restored oil and water state; extract the signal amplitudes of the shale pore water, adsorbed oil, bound oil and movable oil after the oil and water are restored; Step 4: Process the shale sample after oil and water recovery, obtain the shale sample in the oil-washed and dried state, and test the T1-T2 spectrum of the shale in the oil-washed and dried state; Step 5: Process the shale sample in the oil-washed dry state, obtain the shale sample in the oil-saturated state, test the T1-T2 spectrum of the shale in the oil-saturated state, and calibrate the amplitude calibration equation of the pore oil signal; Step 6: Quantitatively calculate the content and distribution of in-situ pore oil and water in shale.

2. The shale oil reservoir in-situ pore oil-water distribution nuclear magnetic resonance testing method according to claim 1, characterized in that: In the step 1, the echo interval during the nuclear magnetic resonance test is less than 0.1 ms.

3. The shale oil reservoir in-situ pore oil-water distribution nuclear magnetic resonance testing method according to claim 1, characterized in that: The method for processing the shale sample for water recovery in step 2 is: placing the sample in an environment with a relative humidity of 98% formed by a saturated K2SO4 solution to balance water, restore the original pore water distribution, and obtain the shale sample for water recovery; The sample mass was recorded during the water balance process. When the mass difference between two consecutive samples was less than 0.01 g, the shale water recovery was considered complete.

4. The shale oil reservoir in-situ pore oil-water distribution nuclear magnetic resonance testing method according to claim 1, characterized in that: Step 2 The method for establishing the amplitude marking equation of the pore water signal of the shale T1-T2 spectrum is as follows: Based on the test of the T1-T2 spectrum of shale in the state of water recovery, the pore water signal amplitude and the amount of water absorbed before and after the shale water recovery are obtained. The linear trend line is fitted using the scatter plot of pore water and its signal amplitude, and the pore water signal amplitude marking equation of the shale T1-T2 spectrum is established; based on the establishment of the pore water signal amplitude marking equation of the shale T1-T2 spectrum, k is obtained. w : Based on the obtained k w , establish the amplitude marking equation of pore water signal in shale T1-T2 spectrum; Furthermore, the amplitude marking equation of the pore water signal of the shale T1-T2 spectrum is: m w =k w A w (1) Where: m w Indicates the amount of water absorbed, g; A w represents the amplitude of the pore water signal in the T1-T2 spectrum, dimensionless; k w is the pore water T1-T2 spectrum signal amplitude conversion coefficient.

5. The shale oil reservoir in-situ pore oil-water distribution nuclear magnetic resonance testing method according to claim 1, characterized in that: Step 3: The processing method of the shale sample for oil and water recovery is as follows: the shale sample for water recovery is subjected to vacuum pressure saturation instrument, vacuumed for 30 minutes, pressurized to 10 MPa to saturate with light oil for 24 hours, and recovered the shale pore oil to obtain the shale sample for oil and water recovery.

6. The method for testing the in-situ pore oil-water distribution in shale oil reservoirs by nuclear magnetic resonance according to claim 1, characterized in that: Step 3: The method for extracting the signal amplitudes of shale pore water, adsorbed oil, bound oil and movable oil after oil and water recovery is: By testing the T1-T2 spectrum of shale in the restored oil-water state, the signal amplitudes of pore water, adsorbed oil, bound oil and movable oil in the shale after oil-water restoration can be extracted by utilizing the different signal amplitudes and distribution positions of oil and water in different states in the pores in the T1-T2 spectrum.

7. The shale oil reservoir in-situ pore oil-water distribution nuclear magnetic resonance testing method according to claim 1, characterized in that: The method for processing the shale sample after oil and water recovery in step 4 to obtain the shale sample in the oil-washed dry state is as follows: The shale sample for oil-water recovery was washed with oil at 0.2 MPa and 80°C for 7 days using a mixed solution of dichloromethane and acetone, and then dried at 110°C for 24 hours to obtain a shale sample in an oil-washed dry state; the volume ratio of dichloromethane to acetone in the mixed solution was 3:

1.

8. The method for testing the in-situ pore oil-water distribution in shale oil reservoirs by nuclear magnetic resonance according to claim 1, characterized in that: Step 5: Processing the shale sample in the oil-washed dry state to obtain the shale sample in the oil-saturated state is as follows: A vacuum pressure saturation instrument was used on the shale samples in the oil-washed dry state. The samples were vacuumed for 6 hours and pressurized to 10 MPa for 24 hours to obtain shale samples in the oil-saturated state.

9. The method for testing the in-situ pore oil-water distribution in shale oil reservoirs by nuclear magnetic resonance according to claim 1, characterized in that: In step 5, the method for testing the T1-T2 spectrum of shale in the oil-saturated state and calibrating the amplitude calibration equation of the pore oil signal is: Based on the T1-T2 spectrum of the tested shale in the oil-saturated state, the pore oil signal amplitude and saturated oil volume before and after the shale is saturated with oil are obtained. The linear trend line is fitted using the scatter plot of the pore oil and its signal amplitude, and the pore oil signal amplitude marking equation is established. Based on the calibration equation of pore oil signal amplitude, k is obtained. o ; Based on the obtained k o , establish the calibration equation for the amplitude of pore oil signal; The pore oil signal amplitude marking equation is: m o =k o A o (2) In the formula, m o Indicates the amount of saturated oil, g; A o represents the amplitude of the pore oil signal in the T1-T2 spectrum, dimensionless; k o is the conversion coefficient of the pore oil T1-T2 spectrum signal amplitude.

10. The method for testing the in-situ pore oil-water distribution in shale oil reservoirs by nuclear magnetic resonance according to claim 1, characterized in that: The method for quantitatively calculating the content and distribution of shale in-situ pore oil and water in step 6 is: Based on step 3, the signal amplitudes of shale pore water, adsorbed oil, bound oil and movable oil after oil and water recovery are extracted; By combining the pore water signal amplitude calibration equation established in step 2 and the pore oil signal amplitude calibration equation established in step 4, the weight of oil and water in the pores can be calculated, and the content and distribution of in-situ pore oil and water in shale can be quantitatively calculated.

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