A shale oil reservoir in-situ pore oil-water distribution nuclear magnetic resonance testing method

Abstract

A shale oil reservoir in-situ pore oil-water distribution nuclear magnetic resonance testing method. Mainly solve the problem that the existing testing method cannot effectively restore the shale oil reservoir in-situ pore oil-water distribution and quantitative evaluation. The method comprises the following steps: S1, testing the original state of the shale core sample in the receiving state nuclear magnetic resonance T1-T2 spectrum; S2, testing the shale T1-T2 spectrum of the water state; establishing the shale T1-T2 spectrum pore water signal amplitude scale equation; S3, testing the shale T1-T2 spectrum of the oil-water state; S4, testing the shale T1-T2 spectrum of the oil-washing dry state; S5, testing the shale T1-T2 spectrum of the saturated oil state, calibrating the pore oil signal amplitude scale equation; quantitatively calculating the content and distribution of shale in-situ pore oil and water. The method determines the occurrence state, content and distribution of shale oil reservoir in-situ pore oil and water through reasonable test process design, and improves the calculation precision of shale oil reservoir parameters.

Description

Technical fields:

[0001] This invention relates to the field of seismic exploration technology, and in particular to a nuclear magnetic resonance method for in-situ testing of oil-water distribution in shale oil reservoirs. Background technology:

[0002] Reserve calculation is a crucial step in shale oil development. Currently, commonly used methods primarily rely on rock pyrolysis or chloroform extraction for oil content calculations. However, light hydrocarbon losses occur during shale coring, transportation, and sample preparation, with higher reservoir properties leading to greater losses. This makes it difficult for currently used uniform correction coefficients to accurately and effectively reflect the in-situ oil content of shale. Furthermore, current correction methods mainly calculate the total oil content of shale, failing to differentiate the oil content of shale in different states. Currently, only free oil is considered the most recoverable portion of shale oil. A uniform correction coefficient may underestimate the oil content of shale oil-bearing zones with optimal reservoir properties and hinder the effective evaluation of recoverable portions of shale oil, thus affecting the accurate calculation of shale oil reserves and the assessment of recoverability.

[0003] According to literature review, to date, domestic and international studies have mainly focused on shale testing in the receiving state or saturated with oil and water. There is a lack of research on the distribution of oil and water in shale pores in the in-situ state, and effective experimental testing and analysis methods have not yet been established. Summary of the Invention:

[0004] This invention addresses the problem that existing testing methods cannot effectively recover and quantitatively evaluate the in-situ pore oil and water distribution and content in shale oil reservoirs. Instead, it provides a nuclear magnetic resonance (NMR) testing method for in-situ pore oil and water distribution in shale oil reservoirs. This method, through a rationally designed testing procedure, determines the occurrence state, content, and distribution of oil and water in the in-situ pores of shale oil reservoirs, thereby improving the accuracy of shale oil reservoir parameter calculations.

[0005] The present invention solves its problem through the following technical solution: A nuclear magnetic resonance testing method for in-situ pore oil-water distribution in shale oil reservoirs, comprising the following steps:

[0006] Step 1: For the shale core sample in the received state, test its original state nuclear magnetic resonance T1-T2 spectrum;

[0007] Step 2: For the received shale core samples, perform shale pore water recovery to obtain shale samples with recovered water; test the T1-T2 spectrum of the shale in the recovered water state; establish the amplitude calibration equation for the pore water signal in the shale T1-T2 spectrum;

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

[0009] Step 4: Process the shale samples that have recovered oil and water, obtain shale samples in the washed and dried state, and test the T1-T2 spectrum of the washed and dried shale samples;

[0010] Step 5: Process the washed and dried shale samples to obtain saturated oil shale samples, test the T1-T2 spectrum of saturated oil shale, and calibrate the pore oil signal amplitude calibration equation.

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

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

[0013] Furthermore, the method for processing the shale sample with restored water in step 2 is as follows: the sample is placed in an environment with a relative humidity of 98% formed by using a saturated K2SO4 solution to balance the water, restore the in-situ pore water distribution, and obtain the shale sample with restored water.

[0014] During the water equilibration process, the sample mass is recorded. When the difference between two adjacent sample masses is less than 0.01g, the shale water recovery is considered complete.

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

[0016] Based on the T1-T2 spectrum of shale under restored water conditions, the pore water signal amplitude and absorbed water volume before and after shale restoration were obtained. A linear trend line was fitted using a scatter plot of pore water and its signal amplitude to establish a calibration equation for the pore water signal amplitude in the T1-T2 spectrum of shale. Based on this established calibration equation, k was calculated. w :

[0017] Based on the obtained k w Establish the equation for the amplitude calibration of pore water signal in the T1-T2 spectrum of shale;

[0018] Furthermore, the equation for the amplitude calibration of the pore water signal in the shale T1-T2 spectrum is as follows:

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

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

[0021] Furthermore, the processing method for the shale sample with restored oil and water in step 3 is as follows: the shale sample with restored water is vacuum-pressurized and saturated with light oil for 30 minutes and pressurized at 10 MPa for 24 hours to restore the shale pore oil and obtain the shale sample with restored oil and water.

[0022] Furthermore, step 3 involves extracting the signal amplitudes of shale pore water, adsorbed oil, bound oil, and movable oil after oil-water recovery.

[0023] By testing the T1-T2 spectrum of shale in the restored oil-water state, and utilizing the characteristics that the signal amplitude and distribution position of oil and water in different states in the pores are different in the T1-T2 spectrum, the signal amplitudes of pore water, adsorbed oil, bound oil and movable oil in the restored shale can be extracted.

[0024] Furthermore, step 4 involves processing the shale sample to recover oil and water, and obtaining a washed and dried shale sample as follows:

[0025] Shale samples with restored oil and water were washed with a mixed solution of dichloromethane and acetone at 0.2 MPa and 80 °C for 7 days, followed by drying at 110 °C for 24 hours to obtain shale samples in the washed and dried state; the volume ratio of dichloromethane to acetone in the mixed solution was 3:1.

[0026] Furthermore, step 5 involves processing the washed and dried shale samples to obtain saturated oil shale samples, as follows:

[0027] A vacuum pressure saturator was used to saturate shale samples in the washed and dried state. The samples were vacuumed for 6 hours and then pressurized at 10 MPa for 24 hours to obtain saturated oil shale samples.

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

[0029] Based on the T1-T2 spectrum of shale in saturated oil state, the amplitude of pore oil signal and the amount of saturated oil before and after saturation were obtained. Using the scatter plot of pore oil and its signal amplitude, a linear trend line was fitted to establish the calibrated equation of pore oil signal amplitude.

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

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

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

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

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

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

[0036] Based on step 3, the amplitudes of signals for pore water, adsorbed oil, bound oil, and movable oil in the shale after oil and water recovery were obtained.

[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 pore oil and water in shale can be quantitatively calculated.

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

[0039] The present invention provides a method for testing and evaluating in-situ pore oil and water in shale oil reservoirs. This method solves the problem of effectively recovering and quantitatively evaluating the in-situ pore oil and water distribution in shale oil reservoirs using existing techniques, improves the calculation accuracy of shale oil reservoir parameters, and enables accurate evaluation of the content and distribution of pore oil and water in shale. Evaluation results show that this method can accurately calculate the content of pore water, adsorbed oil, bound oil, and movable oil in shale, thus improving the accuracy of in-situ pore fluid evaluation in shale.

[0040] This invention restores lost pore water and light oil in shale oil reservoirs by balancing water and saturating light oil. This method, based on the accurate restoration of in-situ pore water and oil in shale, improves the accuracy of in-situ pore water and oil assessment in shale oil reservoirs, thereby enabling more accurate calculation of shale oil reserves.

[0041] This invention, through a rationally designed testing process, determines the occurrence, content, and distribution of in-situ pore oil and water in shale oil reservoirs, improves the accuracy of shale oil reservoir parameter calculations, and eliminates the impact of shale light oil and water loss during coring, transportation, and sample preparation on the accuracy of shale oil content evaluation. Attached image description:

[0042] Appendix Figure 1 This is a flowchart of the nuclear magnetic resonance testing method for in-situ pore oil-water distribution in shale oil reservoirs according to the present invention;

[0043] Appendix Figure 2 The attached diagram shows the distribution of T1-T2 nuclear magnetic resonance spectra of shale cores under different conditions according to embodiments of the present invention. Figure 3 The above is an example of extracting pore oil and water signal amplitude diagrams from the T1-T2 spectra of shale after oil and water recovery in this embodiment of the invention (au indicates dimensionless).

[0044] Appendix Figure 4 This is a scatter plot of pore water and its signal amplitude according to an embodiment of the present invention;

[0045] Appendix Figure 5 This is a scatter plot of the pore oil and its signal amplitude according to an embodiment of the present invention;

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

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

[0048] This invention provides a nuclear magnetic resonance (NMR) method for in-situ pore oil-water distribution testing in shale oil reservoirs, comprising the following steps:

[0049] Step 1: For the shale core sample in its received state, test its original nuclear magnetic resonance (NMR) T1-T2 spectrum; to accurately test the distribution of oil and water in shale pores, the echo interval (T1-T2) during NMR testing is adjusted. E It should be less than 0.1ms.

[0050] Step 2: For the received shale core samples, perform shale pore water recovery to obtain shale samples with recovered water; test the T1-T2 spectrum of the shale in the recovered water state; establish the amplitude calibration equation for the pore water signal in the shale T1-T2 spectrum;

[0051] The method for processing the shale sample with restored water is as follows: the sample is placed in an environment with a relative humidity of 98% (saturated K2SO4 solution) to balance the water and restore the original pore water distribution, thus obtaining the shale sample with restored water; the sample mass is recorded during the water balancing process, and the shale restoration is considered complete when the difference between two adjacent sample masses is less than 0.01g.

[0052] Based on the T1-T2 spectrum of shale under restored water conditions, the amplitude of pore water signals and the amount of water absorbed before and after the restoration of shale water were obtained, and an equation for the amplitude calibration of pore water signals in the T1-T2 spectrum of shale was established. Based on the established equation for the amplitude calibration of pore water signals in the T1-T2 spectrum of shale, k was obtained. w :

[0053] The equation for the amplitude calibration of the pore water signal in the T1-T2 spectrum of the shale is as follows:

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

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

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

[0057] The shale samples with restored water were subjected to a vacuum pressure saturator. The vacuum was applied for 30 minutes, and the pressure was increased to 10 MPa to saturate light oil for 24 hours to restore the shale pore oil and obtain shale samples with restored oil and water.

[0058] By testing the T1-T2 spectrum of shale in the restored oil-water state, and utilizing the characteristics that the signal amplitude and distribution position of oil and water in different states in the pores are different in the T1-T2 spectrum, the signal amplitudes of pore water, adsorbed oil, bound oil and movable oil in the restored shale can be extracted.

[0059] Step 4: Process the shale samples that have recovered oil and water, obtain shale samples in the washed and dried state, and test the T1-T2 spectrum of the washed and dried shale samples;

[0060] Shale samples with restored oil and water were washed with a mixture of dichloromethane and acetone (volume ratio 3:1) at 0.2 MPa and 80℃ for 7 days, followed by drying at 110℃ for 24 hours to obtain shale samples in the washed and dried state.

[0061] Step 5: Process the washed and dried shale samples to obtain saturated oil shale samples, test the T1-T2 spectrum of saturated oil shale, and calibrate the pore oil signal amplitude calibration equation.

[0062] A vacuum pressure saturator was used to saturate shale samples in the washed and dried state. The samples were vacuumed for 6 hours and then pressurized at 10 MPa for 24 hours to obtain saturated oil shale samples.

[0063] Based on the T1-T2 test spectrum, an equation for the amplitude calibration of the pore oil signal was established, and k was obtained. o ;

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

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

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

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

[0068] Based on step 3, the amplitudes of signals for pore water, adsorbed oil, bound oil, and movable oil in the shale after oil and water recovery were obtained.

[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 pore oil and water in shale can be quantitatively calculated.

[0070] Example 1

[0071] like Figure 1 As shown in the figure, this invention provides a method for in-situ pore oil-water distribution testing in shale oil reservoirs using nuclear magnetic resonance (NMR). The oil and water T1-T2 spectrum distributions for steps 1 to 5 of the shale oil reservoir testing process are shown in the attached figure. Figure 2 As shown. (Attached) Figure 2 In the diagram, A indicates capillary bound water (pore water); B, C, and D represent adsorbed oil, bound oil, and mobile oil, respectively, i.e., pore oil; F, G, and H represent (quasi-)solid hydrogen nucleus signals, namely clay bound water (adsorbed water, structural water), asphaltene, and kerogen, respectively. Figure 2 It includes 5 images: taking core sample No. 57 from well GY18 as an example, among which:

[0072] Figure 2 a represents the reception status diagram for GY18-57-1;

[0073] Figure 2 b is GY18-57-2, which is the state diagram of balanced water (restoration water);

[0074] Figure 2 c represents the state diagram of balanced water + saturated oil (restored oil-water balance) for GY18-57-3;

[0075] Figure 2 d represents the drying state diagram of the wash oil (GY18-57-4).

[0076] Figure 2 e is GY18-57-6, which is a diagram showing the state of washing oil drying + equilibrium water.

[0077] Twelve shale cores from the GY18 shale oil reservoir were selected and subjected to nuclear magnetic resonance (NMR) tests in the following states: receiving state, balanced water, balanced water + saturated light oil (hereinafter referred to as restored oil-water), washed oil drying, and saturated oil. The corresponding T1-T2 spectra were obtained, and the signal amplitudes of oil and water in the pores were extracted.

[0078] Taking core sample No. 57 from well GY18 as an example, after water restoration, as shown in the attached... Figure 2 As shown in b, with the attached Figure 2 Compared to the received 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 changes in the shale oil distribution. A scatter plot is constructed using the amount of absorbed water and the amplitude of the pore water signal, yielding the pore water calibration equation (see appendix). Figure 4 ). As attached Figure 2 As shown in c, with the attached Figure 2 Compared to the initial receiving state, after the oil-water recovery, the capillary bound water signal increased, the adsorbed oil changed little, and the bound oil and movable oil signals increased, indicating that after the core was taken from the in-situ formation, more pore water, bound oil, and movable oil escaped. (See attached image.) Figure 2 As shown in e, with appendix Figure 2 Compared to washed and dried oil, the signal amplitude of saturated oil-state shale pore oil (adsorbed oil, bound oil, and movable oil) significantly increased. Based on the signal amplitude change and saturated oil quantity, a scatter plot was constructed to obtain the pore oil calibration equation (see appendix). Figure 5 ).

[0079] From the appendix Figure 2 The signal amplitude variations in different regions of the T1-T2 spectrum show that the T1-T2 spectrum obtained from nuclear magnetic resonance (NMR) testing can effectively indicate the distribution of pore fluids in shale. The in-situ pore oil and water distribution characteristics of shale can be obtained using the T1-T2 spectrum after oil and water recovery. The signal amplitudes of bound water, adsorbed oil, bound oil, and movable oil in the pore capillaries of 12 shale cores were quantitatively extracted after oil and water recovery (see Appendix). Figure 3 That is, to obtain the A of the in-situ pores. o and A w k is obtained by combining the equations of the oil and water signal amplitude calibration lines (Formula 2 and Formula 1). o and k w This allows for the quantitative calculation of the in-situ pore oil and water content in shale (see appendix). Figure 6 ).

Claims

1. A nuclear magnetic resonance (NMR) method for in-situ testing of oil-water distribution in shale oil reservoirs, characterized in that: Includes the following steps: Step 1: For the shale core sample in the received state, test its original state nuclear magnetic resonance T1-T2 spectrum; Step 2: For the received shale core samples, perform shale pore water recovery to obtain shale samples with recovered water; test the T1-T2 spectrum of the shale in the recovered water state; establish the amplitude calibration equation for the pore water signal in the shale T1-T2 spectrum; The method for processing shale samples with restored water is as follows: the sample is placed in an environment with a relative humidity of 98% formed by using a saturated K2SO4 solution to balance the water, restore the original pore water distribution, and obtain shale samples with restored water. During the water equilibration process, the sample mass is recorded. When the difference between two adjacent sample masses is less than 0.01g, the shale water recovery is considered complete. The method for establishing the amplitude calibration equation for pore water signals in shale T1-T2 spectra is as follows: Based on the T1-T2 spectrum of shale under restored water conditions, the amplitude of pore water signals and the amount of water absorbed before and after the restoration of shale water were obtained. Using a scatter plot of pore water and its signal amplitude, a linear trend line was fitted to establish an equation for the amplitude calibration of pore water signals in the T1-T2 spectrum of shale. Based on this equation, the following results were obtained: k w : Based on the obtained k w Establish the equation for the amplitude calibration of pore water signal in the T1-T2 spectrum of shale; The equation for the amplitude calibration of the pore water signal in the T1-T2 spectrum of the shale is as follows: （1） In the formula: m w Indicates the amount of water absorbed, in grams; A w The amplitude of the pore water signal in the T1-T2 spectrum is dimensionless. k w The amplitude conversion coefficient of the pore water T1-T2 spectrum signal; Step 3: Recover the shale sample containing water and the shale vented pore oil to obtain a shale sample containing recovered oil and water; test the T1-T2 spectrum of the shale in the recovered oil and water state; extract the signal amplitudes of pore water, adsorbed oil, bound oil and movable oil in the shale after oil and water recovery; Step 4: Process the shale samples that have recovered oil and water, obtain shale samples in the washed and dried state, and test the T1-T2 spectrum of the washed and dried shale. The method for processing shale samples that have recovered oil and water, and obtaining shale samples in a washed and dried state, is as follows: Shale samples with restored oil and water were washed with a mixed solution of dichloromethane and acetone at 0.2 MPa and 80 °C for 7 days, followed by drying at 110 °C for 24 hours to obtain shale samples in the washed and dried state; the volume ratio of dichloromethane to acetone in the mixed solution was 3:

1. Step 5: Process the washed and dried shale samples to obtain saturated oil shale samples, test the T1-T2 spectrum of saturated oil shale, and calibrate the pore oil signal amplitude calibration equation. The method for calibrating the amplitude calibration equation of pore oil signal by testing the T1-T2 spectrum of saturated oil-state shale is as follows: Based on the T1-T2 spectrum of shale in saturated oil state, the amplitude of pore oil signal and the amount of saturated oil before and after saturation were obtained. Using the scatter plot of pore oil and its signal amplitude, a linear trend line was fitted to establish the calibrated equation of pore oil signal amplitude. Based on the established equation for the amplitude calibration line of the pore oil signal, the following is obtained: k o ; Based on the obtained k o Establish the equation for the calibration of the pore oil signal amplitude calibrator; The equation for the pore oil signal amplitude calibration is: （2） In the formula, m o This indicates the amount of saturated oil, in grams. A o The amplitude of the pore oil signal in the T1-T2 spectrum is dimensionless. k o The amplitude conversion coefficient of the T1-T2 spectrum signal of the pore oil; Step 6: Quantitatively calculate the content and distribution of in-situ pore oil and water in shale.

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

3. The nuclear magnetic resonance testing method for in-situ pore oil-water distribution in shale oil reservoirs according to claim 1, characterized in that: Step 3: The method for processing shale samples to restore oil and water is as follows: The shale samples to restore water are vacuum-pressurized and saturated with light oil for 30 minutes and pressurized at 10 MPa for 24 hours to restore the shale pore oil and obtain shale samples to restore oil and water.

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

5. The nuclear magnetic resonance testing method for in-situ pore oil-water distribution in shale oil reservoirs according to claim 1, characterized in that: Step 5 involves processing the washed and dried shale samples to obtain saturated oil shale samples. A vacuum pressure saturator was used to saturate shale samples in the washed and dried state. The samples were vacuumed for 6 hours and then pressurized at 10 MPa for 24 hours to obtain saturated oil shale samples.

6. The nuclear magnetic resonance testing method for in-situ pore oil-water distribution in shale oil reservoirs according to claim 1, characterized in that: The method for quantitatively calculating the content and distribution of in-situ pore oil and water in shale in step 6 is as follows: Based on step 3, the amplitudes of signals for pore water, adsorbed oil, bound oil, and movable oil in the shale after oil and water recovery were obtained. 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 pore oil and water in shale can be quantitatively calculated.

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