A method for constructing multi-scale capillary force curves of deep shale based on nuclear magnetic resonance T2 spectroscopy

Abstract

This invention discloses a method for constructing multi-scale capillary force curves of deep shale based on nuclear magnetic resonance (NMR) T2 spectra, relating to the field of oil and gas field development technology. The method includes the following steps: S1, obtaining the initial T2 spectrum of deep shale under saturated water conditions using an online NMR displacement experimental system; S2, obtaining the displacement pressure, water saturation, and residual water T2 spectra of deep shale under multiple displacement pressure differentials using the same online NMR displacement experimental system; S3, dividing the deep shale into multiple segments based on the results of S1 and S2, combined with pore throat and fracture sizes; S4, establishing a nonlinear mapping model and continuity constraints for each segment, and fitting the nonlinear mapping model of each segment using the results of S2 to obtain a fitted model; S5, inverting the initial T2 spectrum based on the fitted model to obtain a continuous capillary force curve. This invention, based on an online NMR displacement system, can quickly and accurately obtain the capillary force curves of deep shale.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field development technology, specifically to a method for constructing multi-scale capillary force curves of deep shale based on nuclear magnetic resonance T2 spectra. Background Technology

[0002] With the deepening exploration and development of unconventional oil and gas, deep shale oil and gas has become an important mainstay of energy production. Deep shale reservoirs possess an extremely complex pore-fracture network system, spanning nanopores (such as kerogen organic pores), micropores (such as intercrystalline pores in clay minerals), and macroscopic natural microfractures. Simultaneously, their wettability exhibits strong mixed heterogeneity; inorganic pores are typically strongly hydrophilic, while organic pores are hydrophobic. In the development of deep shale gas, capillary force is the core kinetic parameter controlling the microscopic fluid transport mechanism and the macroscopic gas-water two-phase distribution. Therefore, obtaining high-precision capillary force curves at multiple scales is of great significance for reservoir evaluation, fracture network quality assessment, and optimization of drainage and production systems.

[0003] Currently, the experimental methods for obtaining core capillary force curves mainly have the following significant technical bottlenecks and defects: (1) High-pressure mercury intrusion porosimetry (MICP): Mercury intrusion porosimetry is currently the most widely used method for characterizing pore throats. However, deep shale has nanoscale pore throats, and the mercury intrusion pressure usually needs to reach 100~200MPa or even higher. Under such extreme hydrostatic pressure, the fragile bedding planes, clay mineral skeletons and natural microcracks inside the shale are prone to compaction closure or rupture, resulting in serious distortion of the measured pore volume and capillary force data. In addition, mercury, as a strongly non-wetting liquid metal, cannot simulate the real gas-liquid two-phase flow and occurrence state of the formation, nor can it reflect the hydration expansion or flow-rock interaction mechanism of the shale matrix in a real fluid environment; (2) Semi-permeable septum method and centrifugation method: Although the semi-permeable septum method can simulate real fluids, it is limited by the upper limit of the displacement pressure of the clay plate (not exceeding 2~3MPa), and cannot overcome the capillary resistance of the nanopores of deep shale, so it cannot obtain a complete capillary force curve. Centrifugation faces the risk of mechanical fracturing of shale cores at extremely high rotation speeds. However, at lower rotation speeds, it is extremely difficult for the fluid in nanopores to achieve distribution equilibrium, resulting in long testing cycles and low accuracy. (3) Conventional nuclear magnetic resonance (NMR): Due to its non-destructive testing characteristics, NMR technology is widely used to characterize the microstructure and flow patterns of unconventional reservoir cores. However, conventional NMR core analysis methods are generally based on the assumption of a single pore model, using a fixed linear conversion constant to directly convert the T2 relaxation time into pore radius or capillary force. However, due to the multi-scale media development characteristics of deep shale, the contact angle and surface relaxation mechanism of fluids in multi-scale media differ significantly. Using a conventional single-constant linear mapping model, the conversion coefficient of large pores is forcibly applied to micro-nano pores, completely ignoring the differences in shale microstructure and physical properties from a mathematical and physical perspective. This leads to a large error in the calculation of capillary force, making it impossible to accurately assess the seepage, retention, and backflow patterns of fracturing fluid in deep shale. In summary, there is currently a lack of a capillary force curve testing and construction method that can realistically simulate the multiphase flow environment and accurately describe the multi-scale development characteristics of deep shale without damaging the complex original structure of deep shale. Summary of the Invention

[0004] To address at least one of the aforementioned problems, this invention proposes a method for constructing multi-scale capillary force curves of deep shale based on nuclear magnetic resonance T2 spectra.

[0005] The technical solution of this invention to solve the above problems is as follows: A method for constructing multi-scale capillary force curves of deep shale based on nuclear magnetic resonance T2 spectroscopy, comprising: S1. Based on the online nuclear magnetic displacement experimental system, the initial T2 spectrum of deep shale under saturated water state was obtained; S2. Based on the online nuclear magnetic displacement experimental system, the displacement pressure, water saturation and residual water T2 spectrum of deep shale under different displacement pressure differentials at multiple levels were obtained. S3. Based on the results of S1 and S2, and combined with the pore throat and fracture size, the deep shale is divided into multiple sections; S4. For any segment, establish a nonlinear mapping model and continuity constraints. Combine the results of S2 to fit the nonlinear mapping model of any segment to obtain the fitted model. S5. Based on the fitted model, the initial T2 spectrum is inverted to obtain the continuous capillary force curve.

[0006] The beneficial effects of this invention are as follows: 1. This invention is based on an online nuclear magnetic resonance displacement system. Under real formation overburden conditions, it uses real formation fluids as the displacement medium and relies on nuclear magnetic resonance signals to achieve non-destructive acquisition of core saturation. This eliminates the destructive effect of high-pressure injection on the core structure, avoids micro-fluid measurement errors, and the obtained physical verification data more realistically reflects the flow-rock interaction mechanism under in-situ conditions of deep shale.

[0007] 2. This invention pioneered a piecewise nonlinear mapping model, which can accurately describe the capillary resistance experienced by fluid flow in media of different scales. It eliminates the systematic error of conventional single conversion coefficient algorithms in calculating capillary forces in micro-nano pores, and significantly improves the accuracy of capillary force calculation.

[0008] 3. After completing the parameter calibration and optimal parameter iterative solution of the core sample of the target block, the method provided by this invention can quickly and in batches calculate and obtain the high-precision capillary force curve of the block, thereby clarifying the multi-scale media seepage and drainage law of deep shale, and providing low-cost, high-efficiency and high-precision basic data support for the formulation of post-compression drainage system and dynamic simulation analysis of deep shale. Attached Figure Description

[0009] Figure 1 This is a flowchart of the method in this embodiment; Figure 2 This is the initial T2 spectrum for this embodiment; Figure 3 The residual water T2 spectrum is shown in this embodiment when the displacement pressure difference is 0.5 MPa. Figure 4 The residual water T2 spectrum in this embodiment is shown when the displacement pressure difference is 1 MPa. Figure 5 The residual water T2 spectrum in this embodiment is given when the displacement pressure difference is 10 MPa. Figure 6 The residual water T2 spectrum in this embodiment is given when the displacement pressure difference is 20 MPa. Figure 7The residual water T2 spectrum in this embodiment is for a displacement pressure difference of 40 MPa; Figure 8 The residual water T2 spectrum in this embodiment is given when the displacement pressure difference is 50 MPa. Figure 9 The residual water T2 spectrum in this embodiment is shown when the displacement pressure difference is 60 MPa. Figure 10 Capillary force curves for wells H1 and H2; Figure 11 Pore ​​pressure cloud map of well H1 on day 1 of simmering; Figure 12 Pore ​​pressure cloud map of well H1 on the second day after it was sealed; Figure 13 Pore ​​pressure cloud map of well H1 on the 3rd day after well stagnation; Figure 14 Pore ​​pressure cloud map of well H1 on the 4th day after it was sealed; Figure 15 Pore ​​pressure cloud map of well H1 on day 5 after suffocation; Figure 16 This is a diagram showing the affected area during the suffocation process of well H1; Figure 17 Pore ​​pressure cloud map of well H2 on day 1 of simmering; Figure 18 Pore ​​pressure cloud map of well H2 on the second day after well stagnation; Figure 19 Pore ​​pressure cloud map of well H2 on the 3rd day after well stagnation; Figure 20 Pore ​​pressure cloud map of well H2 on the 4th day of simmering; Figure 21 Pore ​​pressure cloud map of well H2 on day 5 of simmering; Figure 22 Pore ​​pressure cloud map of well H2 on day 6 of simmering; Figure 23 Pore ​​pressure cloud map of well H2 on day 7 after suffocation; Figure 24 This is a diagram showing the affected area during the sump-drying process of well H2; Figure 25 Daily oil production charts for wells H1 and H2; Figure 26 This is a graph showing the cumulative oil production of wells H1 and H2. Detailed Implementation

[0010] The specific embodiments of the present invention will be clearly and completely described below with reference to examples. Obviously, the described examples are only some embodiments of the present invention, and not all embodiments.

[0011] In the following embodiments, deep shale refers to shale buried at a depth of more than 3,500 meters. Compared with conventional shale (shale buried at a depth of less than 3,500 meters), deep shale has more complex geological conditions, more changes in geostress, and higher reservoir temperature.

[0012] like Figure 1 As shown, a method for constructing multi-scale capillary force curves of deep shale based on nuclear magnetic resonance T2 spectra includes the following steps: S1. Based on the online nuclear magnetic displacement experimental system, the initial T2 spectrum of deep shale under saturated water state was obtained; The online nuclear magnetic resonance (NMR) displacement experimental system is a commonly used experimental system in this field. It includes a displacement unit, an NMR analyzer, an imaging unit, and an NMR displacement probe. The NMR analyzer applies an external magnetic field to the displacement unit. The NMR displacement probe is located within the displacement unit and detects changes in the magnetic field. The imaging unit generates images based on the detection results from the NMR analyzer and the NMR displacement probe. It is a mature commercial product and can be purchased from the market. In this embodiment, the online NMR displacement experimental system used is model spec-rc035.

[0013] Similar to conventional displacement devices, the displacement unit in this embodiment includes a displacement pump, a core holder, a backpressure valve, and pipelines and valves connecting these components in sequence. The inlet and outlet ends of the core holder are typically equipped with pressure sensors / differential pressure sensors. The outlet end of the backpressure valve is usually equipped with a metering device to measure the produced gas / liquid from the core holder. Different metering devices, such as graduated cylinders, scales, or gas meters, can be used for different operating conditions. A confining pressure pump is also included to provide confining pressure to the core holder. In some cases, an intermediate container is provided between the displacement pump and the core holder to prevent direct contact between the displacement pump and the displacement fluid. In other cases, a vacuum pump is installed at the outlet end of the core holder to evacuate the core inside the holder, allowing for better water saturation.

[0014] In actual operation, the deep shale is first saturated with water. After the saturation is completed, the initial T2 spectrum of the deep shale is obtained by analyzing it with a nuclear magnetic resonance analyzer and its auxiliary components (imaging unit, nuclear magnetic resonance displacement probe).

[0015] In this embodiment, the obtained deep shale has a diameter of 25.4 mm, a length of 50 mm, a gas porosity of 3.8%, a matrix permeability of 0.0015 mD, and a total organic carbon content of 4.2 wt%. During the experiment, under a pressure of 30 MPa, it was saturated with a 2 wt% potassium chloride aqueous solution for 72 h. After saturation, the echo interval of the nuclear magnetic resonance analyzer was set to 0.1 ms to obtain its initial T2 spectrum, as shown below. Figure 2 As shown, the total integral area of ​​the initial T2 spectrum is recorded. A 0 = 15420.

[0016] S2. Based on the online nuclear magnetic displacement experimental system, the displacement pressure, water saturation and residual water T2 spectrum of deep shale under different displacement pressure differentials at multiple levels were obtained. In this step, for multiple different displacement pressure differentials, the maximum can be set based on actual engineering experience: the maximum displacement pressure differential requires the shale capillary force close to the block, which can be estimated based on previous development results of the block, mercury injection test results, etc.; or it can be calculated based on the Young-Laplace equation and combined with the pore size of the multi-scale medium in deep shale.

[0017] The number of displacement pressure differential stages and the magnitude of adjacent displacement pressure differential stages can be set as follows: The number of displacement pressure differential stages should be at least 5. Theoretically, the more displacement pressure differential stages, the better. However, more displacement pressure differential stages will lead to a longer test time. Furthermore, the inventors have found that when the number of stages is greater than 10, its impact on the final capillary force curve result is relatively small. Therefore, the number of displacement pressure differential stages can be set to 5 to 10, such as 5, 6, 7, 8, 9, 10, etc.

[0018] Based on the set multi-level displacement pressure difference, the minimum displacement pressure difference is selected, and the non-wetting phase fluid of the deep shale saturated with water is injected into the deep shale according to the set displacement pressure difference. Nuclear magnetic resonance scanning is continuously performed during the displacement process. When the residual water T2 spectrum obtained by the scanning remains stable, the displacement pressure difference at this time is used as the displacement pressure, and the residual water T2 spectrum at this time is recorded. Based on the residual water T2 spectrum and the initial T2 spectrum, the water saturation at this time is calculated. Gradually increase the displacement pressure differential and repeat the above operation until all displacement pressure differentials have been tested.

[0019] When calculating water saturation, the T2 spectrum is first integrated to obtain the integration area. A k Then, based on the integrated area of ​​the residual water T2 spectrum and the integrated area of ​​the initial T2 spectrum, the water saturation under this displacement pressure difference condition is calculated: S w = A k / A 0*100%, S w Indicates water saturation.

[0020] In this embodiment, the displacement pressure difference is set to 7 levels, namely 0.5 MPa, 1 MPa, 10 MPa, 20 MPa, 40 MPa, 50 MPa, and 60 MPa, for a total of 7 levels. The final T2 spectrum is as follows. Figures 3-9 As shown, where, Figure 3 The T2 spectrum is for a displacement pressure difference of 0.5 MPa. Figure 4 The T2 spectrum is for a displacement pressure difference of 1 MPa; Figure 5 The T2 spectrum is for a displacement pressure difference of 10 MPa; Figure 6 The T2 spectrum is for a displacement pressure difference of 20 MPa; Figure 7 The T2 spectrum is for a displacement pressure difference of 40 MPa; Figure 8 The T2 spectrum is for a displacement pressure difference of 50 MPa; Figure 9 The T2 spectrum is for a displacement pressure difference of 60 MPa.

[0021] S3. Based on the results of S1 and S2, and combined with the pore throat and fracture size, the deep shale is divided into multiple sections; Based on the peaks and troughs in the initial T2 spectrum in S1, deep shale is divided into microfracture segments, macroporous segments, mesoporous segments, and micro / nanoporous segments. In actual operation, those skilled in the art can arbitrarily select multiple segments according to the actual situation, rather than dividing all deep shale into these four segments.

[0022] In this embodiment, the initial T2 spectrum is divided into three segments: segment one is the microcrack segment: T2∈(10ms, 1000ms], with a cutoff value of 10ms; segment two is the mesoporous segment: T2∈(1ms, 10ms], with a cutoff value of 1ms; segment three is the micro / nanopore segment: T2∈(0.01ms, 1ms], with a cutoff value of 0.01ms; T2 represents the transverse relaxation time.

[0023] S4. For any segment, establish a nonlinear mapping model and continuity constraints. Combine the results of S2 to fit the nonlinear mapping model of any segment to obtain the fitted model. In this step, the nonlinear mapping model is: In the formula, This represents the capillary force in the k-th segment; and These represent the flow-rock interaction coefficient and the morphological index, respectively. The specific derivation process for the nonlinear mapping model is as follows: According to the classical theory of capillary force in porous media, the capillary force on the fluid inside a porous medium... P c It follows the Young-Laplace equation: in, σ This refers to the interfacial tension between formation fluids. θ The wetting contact angle between the fluid and the inner wall of the pore. r For pore or throat radius, the transverse relaxation time T 2. Controlled by surface relaxation mechanism: in, ρ 2 represents the transverse relaxation rate of the rock skeleton surface. F s The shape factor is 3 for spherical pores and 2 for columnar channels, from which the pore radius can be obtained. r and T The relationship is: Combining the two equations above, we obtain the conventional one. P c and T The mathematical relationship of 2 is: For conventional homogeneous hydrophilic rocks θ and ρ 2 is usually considered a constant, that is P c =C / T 2, where C is a constant. However, deep shale is composed of a mixture of strongly hydrophilic inorganic minerals and strongly hydrophobic kerogen organic matter. As the pore size decreases, the proportion of organic pores increases sharply, and the rock surface transforms from strongly hydrophilic to neutral or even hydrophobic. Simultaneously, the surface relaxation rates of different mineral components vary. ρ The differences can reach several orders of magnitude. Therefore, in the complex multi-scale medium of deep shale, the comprehensive parameter 2 σ cos θ / ρ 2 F s No longer a constant, but an aperture r (or T 2) Nonlinear function. Considering the fractal geometry of shale pore surfaces, this embodiment introduces a morphological index. Flow-rock interaction coefficient A piecewise nonlinear mapping equation is constructed to address the multi-scale development characteristics of deep shale. For the first... k In the pore section, the capillary force calculation model is defined as a power law form: .

[0024] The continuity constraint for the above model is mainly due to the fact that, in this embodiment, the deep shale is divided into multiple segments, and these segments are continuous. At the relaxation time boundary between the k-th and k+1-th segments, the calculated capillary forces must be equal, i.e.: In the formula, This represents the T2 spectrum cutoff boundary value for the k-th and k+1-th segments.

[0025] Due to the aforementioned continuity constraints, when fitting the above nonlinear mapping model, k +1 section Can be migrated from the section and This representation reduces the dimensionality of unknowns in the subsequent nonlinear mapping model, thereby greatly reducing the fitting difficulty and fitting time.

[0026] Subsequently, the above nonlinear mapping model was fitted using the least squares method, and the specific fitting process is shown below: Randomly generate a set and The exhaust pressure in S2 is used as the capillary force and substituted into the nonlinear mapping model to obtain the T2 cutoff value corresponding to the exhaust pressure; in this process, a set of and This means that for each segment, a set of parameters needs to be generated; for example, if there are 3 segments, then a set of parameters is needed. and Include , , , , and There are a total of 6 parameters.

[0027] In the formula, T 2,cutoff ( P ci ) indicates the exhaust pressure P ci The corresponding T2 cutoff value.

[0028] Using the initial T2 spectrum, the signal within the T2 cutoff value is integrated to calculate the theoretical residual water signal quantity. This theoretical residual water signal quantity is then divided by the total signal quantity of the initial T2 spectrum to obtain the set of... and Fitting residual water saturation under control; In the formula, Indicates the residual water saturation; This indicates that the area integral is performed on the T2 curve.

[0029] Using the minimum residual water saturation and the minimum water saturation in S2 as the objective function, the least squares method is used to... and Adjustments are made until the upper limit of iteration is reached or the objective function is less than the threshold, then the result is output. and And used as parameters for the fitted model.

[0030] The objective function is as follows: In the formula, E represents the objective function value; S w,exp ( Pci ) represents the water saturation calculated in S2; n represents the order of the displacement pressure difference.

[0031] In this step, the final globally optimal parameters are: a 1 = 22.73 a 2 = 8.62, a 3 = 8.62 b 1 = 0.57 b 2 = 0.149, b 3 = 0.149.

[0032] S5. Based on the fitted model, the initial T2 spectrum is inverted to obtain the continuous capillary force curve.

[0033] Substituting the initial T2 spectrum into the fitted model, we obtain 7 point values. These 7 point values ​​are then fitted into a smooth curve, which yields a capillary force curve.

[0034] The capillary force curve obtained in this step is as follows: Figure 10 As shown.

[0035] The multi-scale capillary force curve constructed in this embodiment of the invention can be directly used to guide fracturing operations and post-fracturing drainage operations in deep shale gas horizontal wells. The specific field operation steps are as follows: (1) Before fracturing, extract deep shale cores from the target block and construct the capillary force curve of the block using the method of this embodiment; (2) Inspect the fracturing truck equipment to ensure that the pipelines are unobstructed, and start the high-pressure pump to test the pressure bearing capacity of the equipment above the wellhead valve and the ground pipelines; (3) Start the fracturing truck and squeeze the optimized pre-fracturing fluid and proppant fluid into the formation in sequence according to the design requirements. The rock is broken up and the proppant is filled into the formation microfractures using the proppant fluid. Then, the proppant fluid in the wellbore is pushed into the formation using the displacement fluid. (4) After the fracturing is completed and the pump is stopped, close the wellhead main valve and enter the well-closing stage. Input the capillary force curve into the gas reservoir numerical simulator or self-priming model to calculate the sweep range or self-priming depth of the fracturing fluid driven by the capillary force. Based on this, determine the optimal well-closing time for the well and avoid insufficient gas-liquid replacement due to too short a well-closing time, or severe hydration of clay and damage to the reservoir due to too long a time. (5) After the well is closed, the well is opened to release water and drain.

[0036] To illustrate the effectiveness of the method in the embodiments of the present invention, specific test examples are given below.

[0037] Two adjacent horizontal wells, H1 and H2, in a deep shale oil block showed high similarity in geological development characteristics based on well logging data. Core samples were taken from both wells, and two deep shale samples, S1 and S2, were prepared. The capillary force curve of deep shale sample S1 was obtained using the method described in this invention, and the capillary force curve of deep shale sample S2 was obtained using mercury intrusion porosimetry. The final results are shown below. Figure 10 .

[0038] from Figure 10 It can be seen that, at any water saturation level, the capillary force obtained by the method of the present invention is greater than that obtained by the mercury intrusion porosimetry.

[0039] The two capillary force curves were read into the shale oil seepage simulator to carry out reservoir numerical simulation in order to optimize the well shut-in time.

[0040] Simulation results show that after fracturing and simmering for 5 days, the pressure swept volume of well H1 reached stability, as shown in the pressure field diagram. Figures 11-15 As shown in the figure, the pressure wave range changes with the well shut-in time. Figure 16 As shown in the figure, the fracturing fluid was fully absorbed into the shale oil matrix, and the well shut-in process ended. After fracturing, well H2 was shut-in for 7 days, and the pressure-sweeped volume reached stability. The pressure field diagram is shown below. Figures 17-23 As shown in the figure, the pressure wave range changes with the well shut-in time. Figure 24 As shown, the fracturing fluid was fully absorbed into the shale oil matrix, and the well shut-in process ended.

[0041] The daily and cumulative oil production statistics for the two wells are as follows: Figure 25 and Figure 26 As shown. From Figure 25 It can be seen that when the production time exceeds 1200 days, the daily oil production of well H1 is much higher than that of well H2; from Figure 26It can be seen that when the number of production days is greater than 400, the cumulative oil production of well H1 is greater than that of well H2. When the number of production days is greater than 1100, the cumulative oil production of well H1 is significantly higher than that of well H2. Moreover, as the number of production days continues to increase, the cumulative oil production of well H1 increases even more.

[0042] It is evident that the daily and cumulative oil production of well H1 is significantly greater than that of well H2. Furthermore, when both wells have been producing for 1600 days, the cumulative oil production of well H1 is 14.8% higher than that of well H2.

[0043] The above test results demonstrate that the capillary force curve obtained by the method in this embodiment of the invention can more accurately guide the optimization of shale oil post-pressurization drainage and production systems.

[0044] The present invention has been disclosed above with preferred embodiments. However, those skilled in the art should understand that these embodiments are only for describing the present invention and should not be construed as limiting the scope of the present invention. Further improvements can be made without departing from the principles of the present invention, and these improvements should also be considered within the scope of protection of the present invention.

Claims

1. A method for constructing a multi-scale capillary pressure curve of deep shale based on a T2 spectrum of nuclear magnetic resonance, characterized in that, The method comprises the following steps: S1, obtaining an initial T2 spectrum of deep shale in a saturated water state based on an online nuclear magnetic displacement experiment system; S2, obtaining displacement pressure, water saturation and residual water T2 spectrum of deep shale under multi-stage different displacement pressure conditions based on the online nuclear magnetic displacement experiment system; S3, dividing the deep shale into multiple sections based on the results of S1 and S2 in combination with pore throat and fracture size; S4, establishing a non-linear mapping model and a continuity constraint condition for each section, fitting the non-linear mapping model of each section to obtain a fitted model based on the results of S2; S5, inverting the initial T2 spectrum based on the fitted model to obtain a continuous capillary force curve.

2. The method of claim 1, wherein, The online nuclear magnetic displacement experiment system comprises a displacement unit, a nuclear magnetic resonance analyzer, an imaging unit and a nuclear magnetic resonance displacement probe, the nuclear magnetic resonance analyzer is used to apply an external magnetic field to the displacement unit, the nuclear magnetic resonance displacement probe is arranged in the displacement unit and detects the change of the magnetic field, and the imaging unit generates an image based on the detection results of the nuclear magnetic resonance analyzer and the nuclear magnetic resonance displacement probe.

3. The method of claim 1, wherein, In S2, the following steps are included: Based on the set multi-stage different displacement pressure, the smallest displacement pressure is selected, the non-wetting phase fluid of the deep shale is injected into the saturated water deep shale according to the set displacement pressure, the nuclear magnetic resonance scanning is continuously performed during the displacement process, when the residual water T2 spectrum form obtained by scanning is maintained stable, the displacement pressure at this time is taken as the displacement pressure, and the residual water T2 spectrum at this time is recorded, and the water saturation at this time is calculated based on the residual water T2 spectrum and the initial T2 spectrum; The displacement pressure is increased in sequence, and the above operation is repeated until the test of all displacement pressures is completed.

4. The method of claim 1, wherein, In S3, the sections are at least two of microfracture section, macropore section, mesopore section and micro-nanopore section.

5. The method of claim 1, wherein, In S4, the non-linear mapping model is , where represents the capillary force of the kth segment; and respectively represent the flow-rock interaction coefficient and the shape index; and the continuity constraint is that the calculated capillary forces at the boundaries of the two segments of the vector are equal.

6. The method of claim 5, wherein, In S4, the fitting method comprises the following steps: a set of random numbers is generated and The displacement pressure in S2 is taken as capillary force, and the T2 cutoff value corresponding to the displacement pressure is obtained by substituting the displacement pressure into the nonlinear mapping model. Theoretical residual water signal amount is calculated by integrating the signal within the T2 cutoff value using the initial T2 spectrum, and dividing the theoretical residual water signal amount by the total signal amount of the initial T2 spectrum to obtain the group and Fitted residual water saturation under the control of With the residual water saturation and the water saturation minimum in S2 in the objective function, the least square method is used to adjust the parameters of the model and until the upper limit of iteration is reached or the objective function is less than the threshold value, and the and are output as the parameters of the fitted model.

7. The method of claim 1, wherein, In S5, the following steps are included: the initial T2 spectrum is substituted into the fitted model for calculation, and a capillary force curve is drawn according to the calculation result.

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