Method for visually and quantitatively characterizing pore fluid distribution of shale oil reservoir

Abstract

The invention relates to the technical field of shale oil and gas exploration and development, in particular to a method for visually and quantitatively characterizing shale oil reservoir pore fluid distribution, which comprises the following steps: drilling a plunger sample from a full-diameter closed core, partially grinding into powder, drying, and carrying out a low-temperature nitrogen and carbon dioxide adsorption experiment to obtain a specific surface area and a pore volume; preparing the remaining plunger sample into a standard sample, and performing two-dimensional nuclear magnetic resonance scanning in different states to obtain a fluid distribution map; comparing signal changes to identify fluid components and drawing a distribution map; calculating the pore diameter by utilizing adsorption experiment data and the T2 geometric mean value, drawing a pore diameter distribution diagram and determining a pore diameter distribution interval of fluid components; and finally, calculating the saturation of the fluid. According to the method, a method for simultaneous measurement of carbon dioxide adsorption, nitrogen adsorption and two-dimensional nuclear magnetic resonance is provided, and the quantitative relation between the T1-T2 two-dimensional nuclear magnetic resonance spectrum and the pore size distribution of the shale is determined, so that the characterization of the pore size distribution of the multi-type pore fluid of the shale is realized.

Description

Technical Field

[0001] The present invention relates to the technical field of shale oil and gas exploration and development, and specifically relates to a method for visually and quantitatively characterizing the pore fluid distribution in shale oil reservoirs. Background Art

[0002] In the field of oil and gas exploration, accurately evaluating the characteristics of shale oil reservoirs is crucial for the effective development of oil and gas resources. Compared with conventional reservoirs and tight sandstone reservoirs, shale oil reservoirs exhibit more complex mineral compositions and structural patterns. This complexity makes the pore structure of shale oil reservoirs more variable and the fluid distribution in the pores more diverse, thus posing great challenges to reservoir reserve estimation and resource development. Under the current technical background, how to accurately characterize the distribution characteristics of fluids in shale pores has become a key problem in shale oil reservoir evaluation.

[0003] To address this challenge, various technical means have been applied to the evaluation of shale oil reservoirs. Among them, T 1 -T 2 Two-dimensional nuclear magnetic resonance scanning technology has been widely used in the evaluation of low-porosity and low-permeability reservoirs because it can qualitatively identify solid organic matter and pore fluids quickly, non-destructively, and intuitively. However, there are large errors in quantitatively characterizing the pore size distribution range of multi-type fluids by this technology. The main reason is that it is difficult to accurately establish the correspondence between the nuclear magnetic resonance relaxation time and the pore size in saturated porous media.

[0004] In addition, field emission scanning electron microscopy technology can observe the oil-bearing property of shale under low vacuum conditions. However, since the sample must be dried before observation, this limits it to roughly observing the oil film on the mineral surface and the oil droplets in the pores, and it cannot effectively characterize the fluid distribution in shale samples under the occurrence state of multi-fluid components.

[0005] Currently, for the quantitative characterization of the pore fluid distribution in shale oil reservoirs, the nuclear magnetic resonance T 2 spectrum cut-off value method is mostly used. This method measures the one-dimensional nuclear magnetic resonance T 2 spectrum of shale samples before and after restoring the oil-water state respectively, identifies the T 2 relaxation time boundaries of multi-type pore fluids, and uses the pore radius distribution obtained by high-pressure mercury injection or gas adsorption to calibrate the T 2 spectrum distribution. The conversion between the relaxation time and the pore radius is achieved through a conversion coefficient. However, the accuracy of this method is limited by the complexity of the shale pore throat structure, and due to the pore shielding effect, the pore radius distribution and the T 2 spectrum distribution often do not match well, resulting in discrete conversion coefficients, and further making the calculation of pore fluid distribution inaccurate and unable to effectively measure the fluid distribution characteristics of different pore types.

[0006] In summary, although various technical means have been applied to the evaluation of shale oil reservoirs, there are still problems to be solved urgently in quantitatively and visually characterizing the pore size distribution characteristics of multiple types of fluids. The present invention aims to provide a new solution to overcome the limitations of the prior art and achieve accurate characterization of the pore fluid distribution in shale oil reservoirs. Summary of the Invention

[0007] To solve the above problems, the present invention provides a method for visually and quantitatively characterizing the pore fluid distribution in shale oil reservoirs, which is used for To achieve the above object, the technical solution of the present invention is as follows: A method for visually and quantitatively characterizing the pore fluid distribution in shale oil reservoirs includes the following steps: Step 1: Horizontally drill a plug sample from a full-diameter sealed core, take a part of the plug sample and grind it into powder. After drying the powder, carry out low-temperature nitrogen and carbon dioxide adsorption experiments to obtain the specific surface area and pore volume of the shale oil reservoir sample. Step 2: Prepare the remaining plug samples into standard plug samples, and perform two-dimensional nuclear magnetic resonance scans on them in the original state, oil-washed and dried state, water-saturated state, water-saturated and centrifuged state, oil-saturated state, and oil-saturated and centrifuged state respectively to obtain two-dimensional nuclear magnetic resonance fluid distribution maps of the shale oil reservoir samples in each state. Step 3: Compare the signal changes in the two-dimensional nuclear magnetic resonance fluid distribution maps of the shale oil reservoir samples in each state in Step 2, identify the two-dimensional nuclear magnetic resonance fluid components in the shale oil reservoir, and draw a two-dimensional nuclear magnetic resonance fluid distribution map of the shale oil reservoir. Step 4: Use the specific surface area and pore volume of the shale oil reservoir sample obtained from the low-temperature nitrogen and carbon dioxide adsorption experiments and the geometric mean value of T in the horizontal direction of the two-dimensional nuclear magnetic resonance spectrum of the shale oil reservoir sample to calculate the pore diameter corresponding to the T 2 distribution point. 2 Step 5: Based on the corresponding relationship between the T 2 distribution point and the pore diameter, draw a two-dimensional nuclear magnetic resonance fluid pore diameter distribution map of the shale oil reservoir to determine the pore diameter distribution range of each fluid component. Step 6: Calculate the fluid saturation of the shale oil reservoir sample.

[0008] Furthermore, the specific surface area is calculated according to the BET equation: ; In the formula, W is the adsorption amount under the relative pressure, cm 3 ; is the monolayer saturated adsorption amount per unit mass of the sample, cm 3 ; is the relative partial pressure of the gas; C is the BET constant; Select An odd number of data points within the range and the adsorption amount W at the corresponding relative pressure are substituted into the BET equation to calculate the slope as , and the intercept as When , the pore specific surface area S = 4.353 ; The pore volume is calculated according to the equivalent volume principle: ; In the formula, V is the pore volume, cm 3 / g; is the maximum gas adsorption amount, cm 3 ; Pa is the standard atmospheric pressure, 106 Pa; R is the gas constant, J / (mol·K), with a value of 8.314; T is the temperature, K.

[0009] Furthermore, in step two, the number of scans of the IR-CPMG sequence for two-dimensional nuclear magnetic resonance scanning is 64, the minimum inversion time is 0.1 ms, the maximum inversion time is 2 s, and the echo spacing is 0.08 ms.

[0010] Furthermore, the standard plunger sample in the original state: A standard plunger sample with a diameter of 25 mm and a length of 35 mm is processed from an anhydrous wire-cut standard plunger sample and immediately wax-sealed to ensure no fluid loss during the process; The standard plunger sample in the washed oil and dry state: The standard plunger sample is washed with oil and salt and then dried at 85 °C for 72 hours; The standard plunger sample in the saturated water state: After the standard plunger sample of the dried sample is evacuated in a high-pressure container equipped with a core, deionized water is injected into the container at a high pressure of 30 MPa and maintained for 24 hours; The standard plunger sample in the saturated water and centrifuged state: The standard plunger sample is centrifuged at a speed of 9000 r / min for 2 hours by a high-speed centrifuge; The standard plunger sample in the saturated oil state: After the standard plunger sample is dried at 85 °C for 72 hours, it is evacuated in a high-pressure container equipped with a core and then aviation kerosene is injected into the container at a high pressure of 35 MPa and maintained for 24 hours; The standard plunger sample in the saturated oil and centrifuged state: It is obtained by centrifuging at a speed of 9000 r / min for 2 hours by a high-speed centrifuge.

[0011] Furthermore, calculate the pore diameter corresponding to the T 2 distribution point: According to the nuclear magnetic resonance relaxation mechanism, the transverse relaxation time is expressed as: ; In the formula, T 2 is the transverse relaxation time, ms; is the surface relaxation rate, μm / ms; V is the pore volume, cm 3 / g; S is the specific surface area of pores, m 2 / g; is the pore shape factor, with a value of 2; Adopt T 2 The geometric mean value of the T 2LM represents T 2 distribution: ; In the formula, φ i is the corresponding nuclear magnetic resonance porosity component, %; φ NMR nuclear magnetic resonance porosity, %; From the above formula, it can be obtained that: ; In the formula, is the pore diameter corresponding to each T 2 distribution point, nm; is the i-th nuclear magnetic resonance transverse relaxation time, ms; is T 2 geometric mean value, ms.

[0012] Furthermore, convert the abscissa T2 relaxation time of the two-dimensional nuclear magnetic resonance spectrum into pore size, draw the two-dimensional nuclear magnetic fluid pore size distribution map of the shale oil reservoir, and use the projection of the signal response area of each type of fluid in the two-dimensional nuclear magnetic fluid pore size distribution map on the abscissa to determine the pore size distribution interval of each type of pore fluid.

[0013] Furthermore, calculate the fluid saturation of the shale oil reservoir sample: Carry out large-field scanning electron microscope observation on the shale oil reservoir sample after nuclear magnetic resonance scanning and measure the pore size of each pore in the field of view. According to the fluid pore size distribution parameters, use ImageJ software to color-mark the pores containing different fluid types, restore the distribution characteristics of different fluid components, and calculate the area ratio of the colors of each pore in the field of view.

[0014] The above-mentioned scheme has the following beneficial effects: 1. In the present invention, aiming at the problem that the pore fluid pore size distribution in the shale oil reservoir is difficult to accurately calibrate due to the development of mainly nano-pores and the complex pore throat structure, a method of combined measurement of carbon dioxide adsorption, nitrogen adsorption and two-dimensional nuclear magnetic resonance is proposed to determine the quantitative relationship between the T 1 -T 2 two-dimensional nuclear magnetic resonance spectrum and the shale pore size distribution, so as to realize the characterization of the pore size distribution of multiple types of pore fluids in the shale.

[0015] 2. In the present invention, based on the T 1 -T 2The fluid identification result of the two-dimensional nuclear magnetic resonance spectrum avoids the problem of fluid signal overlap in the coexistence of oil and water and the coexistence of multiple oil-water occurrence states, and solves the difficulty of identifying fluids using the cut-off value method in shale reservoir evaluation.

[0016] 3. In the present invention, considering the calibration of T through the conversion coefficient of high-pressure mercury intrusion testing 2 Based on the limitation of the pore size distribution of the nuclear magnetic resonance spectrum, on the basis of calculating the surface relaxation strength of the core by nitrogen adsorption to restore the pore size distribution of nuclear magnetic resonance, for the first time, the combined means of carbon dioxide adsorption and nitrogen adsorption are used to accurately establish the 2 correlation between the relaxation time and the pore size distribution, establish a two-dimensional nuclear magnetic fluid pore size distribution map of shale oil reservoirs, and quantitatively characterize the pore size distribution intervals of each fluid component.

[0017] 4. In the present invention, by using the method combining two-dimensional nuclear magnetic resonance and scanning electron microscopy, the two-dimensional nuclear magnetic fluid pore size distribution results are used for scanning electron microscopy observation and image processing to restore the fluid-containing characteristics of each pore, and realize the visual quantitative characterization of the distribution laws of multiple types of fluids in shale oil reservoirs. This method has broad application prospects.

[0018] The additional aspects and advantages of the present invention will be partly given in the following description, partly will become obvious from the following description, or will be understood through the practice of the present invention. Brief Description of the Drawings

[0019] Figure 1 The flowchart of the embodiment of the present invention is shown; Figure 2 For the shale oil reservoir sample in the original state, T 1 -T 2 Two-dimensional nuclear magnetic resonance spectrum; Figure 3 For the shale oil reservoir sample in the state of washed oil and dried, T 1 -T 2 Two-dimensional nuclear magnetic resonance spectrum; Figure 4 For the shale oil reservoir sample in the saturated water state, T 1 -T 2 Two-dimensional nuclear magnetic resonance spectrum; Figure 5 For the shale oil reservoir sample in the saturated water and centrifuged state, T 1 -T 2 Two-dimensional nuclear magnetic resonance spectrum; Figure 6 For the shale oil reservoir sample in the saturated oil state, T 1 -T 2 Two-dimensional nuclear magnetic resonance spectrum; Figure 7 For the shale oil reservoir sample in the saturated oil and centrifuged state, T 1 -T2 Two-dimensional nuclear magnetic resonance spectrum; Figure 8 The following figure shows the volume percentage results of the pore size distribution calculated by the DET model and T 2 in the co-measurement of carbon dioxide adsorption and nitrogen adsorption in the embodiment; Figure 9 The following figure shows the T 1 -T 2 schematic diagram of the two-dimensional nuclear magnetic fluid pore size distribution map; Figure 10 The following figure shows the distribution diagrams of different fluid components of the shale oil reservoir samples in the embodiment. Detailed implementation manners

[0020] The technical solutions of the present invention will be clearly and completely described below with reference to the accompanying drawings. Apparently, the described embodiments are some, but not all, of the embodiments of the present invention. All other embodiments obtained by those of ordinary skill in the art without creative efforts based on the embodiments of the present invention belong to the scope of protection of the present invention.

[0021] The following is a further detailed description through specific implementation manners: As shown in the Figure 1 accompanying drawings, a method for visually and quantitatively characterizing the pore fluid distribution of a shale oil reservoir includes the following steps: Step 1: Horizontally drill a plug sample from a full-diameter sealed core, take a part of the plug sample and grind it into powder. After drying the powder, carry out low-temperature nitrogen and carbon dioxide adsorption experiments to obtain the specific surface area and pore volume of the shale oil reservoir sample.

[0022] In one embodiment, the specific method steps of Step 1 are as follows: Taking the shale oil reservoir sample selected from the second member of the Funing Formation in the Qintong Sag of the Subei Basin as an example, the sample burial depth is 3974.91 m. The reservoir space was identified at the micro-nano scale by using a scanning electron microscope. The results show that the reservoir space is mainly composed of nano-pores, and mainly developed organic pores, intercrystalline pores, intergranular pores and intragranular dissolved pores.

[0023] Drill experimental samples parallel to the bedding direction from a fresh full-diameter sealed core wrapped with wax and plastic wrap. Use wire cutting to prepare a standard plug sample with a diameter of 25 mm and a length of 35 mm and wax-seal it as a two-dimensional nuclear magnetic resonance receiving sample. Grind the cut part to 80 mesh to make 2 gas adsorption test samples. After drying at 70 °C at low temperature, carry out carbon dioxide and nitrogen adsorption tests to obtain the specific surface area and pore volume of the original sample, as follows:

[0024] The specific surface area is calculated according to the BET equation: ; Wherein, W is the adsorption amount under relative pressure, cm 3 ; is the monolayer saturation adsorption amount of the sample per unit mass, cm 3 ; is the relative partial pressure of the gas; C is the BET constant; Select An odd number of data points within the range and the adsorption amount W at the corresponding relative pressure are substituted into the BET equation to calculate the slope as , and the intercept is When value, then the pore specific surface area S = 4.353 ; The pore volume is calculated according to the equivalent volume principle: ; Wherein, V is the pore volume, cm 3 / g; is the maximum adsorption amount of the gas, cm 3 ; Pa is the standard atmospheric pressure, 106 Pa; R is the gas constant, J / (mol·K), with a value of 8.314; T is the temperature, K.

[0025] The test results are shown in Table 1 as follows: Table 1 Low-temperature gas adsorption test results

[0026] Step 2: Prepare the remaining plunger samples into standard plunger samples, and perform two-dimensional nuclear magnetic resonance scans in the original state, washed oil and dried state, water-saturated state, water-saturated and centrifuged state, oil-saturated state, and oil-saturated and centrifuged state respectively to obtain the two-dimensional nuclear magnetic resonance fluid distribution maps of the shale oil reservoir samples in each state.

[0027] In one embodiment, the specific method steps of Step 2 are as follows: 1. After receiving the sample (original state), remove the wax seal and conduct T 1 -T 2 Two-dimensional nuclear magnetic resonance scan, the nuclear magnetic resonance frequency is 23.08 MHz, the magnetic field strength is 0.5 T, the IR-CPMG sequence is used, the number of scans is 64 times, the number of echoes is 5000, the minimum inversion time is 0.1 ms, the maximum inversion time is 2 s, and the echo interval is 0.08 ms. Obtain the T 1 -T 2 Two-dimensional nuclear magnetic resonance map of the original sample.

[0028] 2. Place the original samples after testing in an oil-washing instrument and wash the oil with a mixed solution of petroleum ether and methanol (volume ratio 2:1) at 80 °C and 0.25 Mpa for 15 days. After the oil washing, there is no fluorescence reaction of crude oil under fluorescence irradiation. After drying at 85 °C for 72 hours, perform T 1 -T 2 two-dimensional nuclear magnetic resonance scanning on the dried oil-washed samples to obtain the T 1 -T 2 two-dimensional nuclear magnetic resonance spectrum.

[0029] 3. Place the dried oil-washed samples in a vacuum pressure saturation instrument, evacuate the air in the pores for 3 hours, then inject deionized water into the container at a high pressure of 30 MPa and maintain for 24 hours to obtain saturated water samples, and perform T 1 -T 2 two-dimensional nuclear magnetic resonance scanning on the dried oil-washed samples to obtain the T 1 -T 2 two-dimensional nuclear magnetic resonance spectrum.

[0030] 4. Place the saturated water samples in a high-speed centrifuge and centrifuge at a speed of 9000 r / min (centrifugal force of 3.5 Mpa) for 2 hours (after continuously increasing the speed and centrifugation time, the mass of the rock samples did not change) to obtain saturated water centrifuged samples, and perform T 1 -T 2 two-dimensional nuclear magnetic resonance scanning on the dried oil-washed samples to obtain the T 1 -T 2 two-dimensional nuclear magnetic resonance spectrum.

[0031] 5. Dry the saturated water centrifuged samples at 85 °C for 72 hours, and place them in a vacuum pressure saturation instrument again to evacuate the air in the pores for 3 hours, then inject aviation kerosene into the container at a high pressure of 35 MPa and maintain for 24 hours to obtain saturated oil samples, and perform T 1 -T 2 two-dimensional nuclear magnetic resonance scanning. Obtain the T 1 -T 2 two-dimensional nuclear magnetic resonance spectrum.

[0032] 6. Place the saturated oil samples in a high-speed centrifuge and centrifuge at a speed of 9000 r / min (centrifugal force of 3.5 Mpa) for 2 hours (after continuously increasing the speed and centrifugation time, the mass of the rock samples did not change) to obtain saturated oil centrifuged samples, and perform T 1 -T 2 two-dimensional nuclear magnetic resonance scanning to obtain the T 1 -T 2 two-dimensional nuclear magnetic resonance spectrum.

[0033] When performing two-dimensional nuclear magnetic resonance scanning on the standard plunger samples in the above-mentioned various states, the number of scans of the IR-CPMG sequence is 64, the minimum inversion time is 0.1 ms, the maximum inversion time is 2 s, and the echo spacing is 0.08 ms.

[0034] Step 3: Compare the signal changes in the two-dimensional nuclear magnetic resonance fluid distribution maps of the shale oil reservoir samples in each state in Step 2, identify the two-dimensional nuclear magnetic resonance fluid components of the shale oil reservoir, and draw the two-dimensional nuclear magnetic resonance fluid distribution map of the shale oil reservoir.

[0035] In one embodiment, the specific method steps of Step 3 are as follows: As Figure 2 shown, the original sample has weak signal responses in five regions A, B, C, D, and E; after the sample is washed with oil and dried, the signals in regions B, C, D, and E disappear. As Figure 3 shown, it shows that these four regions are fluid signal regions, while region A (T 2 = 0.02 ms to 0.07 ms, T 1 / T 2 > 100) is the solid organic matter response region; in the T 1 -T 2 two-dimensional nuclear magnetic resonance map of the water-saturated state, strong signal amplitudes appear in regions B (T 2 = 0.27 ms to 0.88 ms, 1 <T 1 / T 2 < 10) and C (T 2 = 0.46 ms to 1.02 ms, 1 <T 1 / T 2 < 10) as Figure 4 shown; after the water-saturated sample is centrifuged, the signal response intensity in region C decreases as Figure 5 shown, indicating that this region is the mobile water signal region, and region B is the bound water signal region; from the T 1 -T 2 two-dimensional nuclear magnetic resonance map in the oil-saturated state, it can be seen that strong signal amplitudes appear in regions D (T 2 = 0.43 ms to 1.73 ms, 10 <T 1 / T 2 < 100) and E (T 2 = 1.73 ms to 8.05 ms, 10 <T 1 / T 2 < 100) as Figure 6 shown; after the oil-saturated sample is centrifuged, the signal in region E disappears as Figure 7 shown, indicating that region D is the bound oil signal response region and region E is the mobile oil signal region.

[0036] Step 4: Obtain the specific surface area and pore volume of the shale oil reservoir sample through low-temperature nitrogen and carbon dioxide adsorption experiments, and calculate the pore diameter corresponding to the distribution point of the transverse middle T of the two-dimensional nuclear magnetic resonance spectrum of the shale oil reservoir sample 2 by calculating the geometric mean of T 2 corresponding to the distribution point

[0037] In one embodiment, the specific method steps of Step 4 are as follows: According to the nuclear magnetic resonance relaxation mechanism, the transverse relaxation time can be expressed as: ; where T 2 is the transverse relaxation time, ms; ρ 2 is the surface relaxation rate, μm / ms; Fs is the pore shape factor. Since the pore shape of shale is mostly between parallel plate-shaped pores and ink bottle-shaped pores, F S is taken as 2, and Equation (3) can be simplified to: ; Adopt the geometric mean T 2 of the T 2LM value to represent the T 2 distribution: ; where φ i is the corresponding nuclear magnetic resonance porosity component, %; φ NMR is the nuclear magnetic resonance porosity, %. Substitute T 2LM , S and V into Equation (3) to obtain , and substitute it into Equation (4) to get: ; where r i is the pore diameter corresponding to each T 2 distribution point, nm; T 2i is the i-th nuclear magnetic resonance transverse relaxation time, ms; V is the pore volume, cm 3 / g; T 2LM is the geometric mean of T 2 , ms; S is the pore specific surface area, m 2 / g; Use Equation (5) to obtain T 2LM = 0.1588 ms and ρ 2 = 13.585 μm / ms for the shale oil reservoir sample selected from the second member of the Funing Formation in the Qintong Sag of the Subei Basin. Substitute it into Equation (6) to get: ; Verify the pore diameter distribution calculated by the DFT model with the pore diameter distribution result calculated by the T 2 spectrum, judge the pore diameter distribution range of the overlapping part between the two, solve the nuclear magnetic resonance porosity within this range and calculate the volume ratio of pores of different sizes respectively. The results are as Figure 8 shown. Take T2 The pore size distribution calculated by spectrum calculation is compared with the gas adsorption pore size distribution result calculated by the DFT model, and the two are in good agreement, which verifies the rationality of this method.

[0038] Step Five: Based on T 2 According to the corresponding relationship between the distribution points and the pore sizes, draw the two-dimensional nuclear magnetic fluid pore size distribution map of the shale oil reservoir, and determine the pore size distribution intervals of each fluid component.

[0039] In one embodiment, the specific method steps of Step Five are as follows: Combined with Figure 9 and Figure 10 As shown, convert the abscissa T 1 -T 2 of the two-dimensional nuclear magnetic resonance spectrum into pore size, draw the T 2 -T 1 two-dimensional nuclear magnetic fluid pore size distribution map of the shale oil reservoir, and use the projection of the signal response area of each type of fluid on the abscissa in the T 2 -T 1 -T 2 two-dimensional nuclear magnetic fluid pore size distribution map of the shale oil reservoir to determine the pore size distribution ranges of each type of pore fluid. The results are shown in Table 2: Table 2 Pore size distribution ranges of each type of pore fluid (component) .

[0040] Step Six: Calculate the fluid saturation of the shale oil reservoir sample.

[0041] In one embodiment, the specific method steps of Step Six are as follows: Carry out large-field scanning electron microscope observation on the sample after nuclear magnetic scanning and measure the pore sizes of each pore in the field of view. According to the pore fluid pore size distribution parameters, use ImageJ software to color-label the pores containing different fluid types, restore the distribution characteristics of different fluid components, and calculate the fluid saturation of the shale sample by calculating the area ratio of the colors of each pore in the field of view. The results are shown in Table 3: Table 3 Saturations of each type of pore fluid (component) .

[0042] Obviously, the above embodiments are only examples for clear illustration and are not limitations on the implementation manners. For those of ordinary skill in the art, other different forms of changes or modifications can be made based on the above description. It is not necessary and impossible to enumerate all the implementation manners here. And the obvious changes or modifications derived therefrom are still within the protection scope of the present invention.

Claims

1. A method for visually and quantitatively characterizing the distribution of pore fluid in a shale oil reservoir, characterized in that: The steps include: Step 1: Drill a plug sample horizontally from a full-diameter sealed core, grind part of the plug sample into powder, dry the powder, and conduct low-temperature nitrogen and carbon dioxide adsorption experiments to obtain the specific surface area and pore volume of the shale oil reservoir sample; Step 2: Prepare the remaining plunger samples into standard plunger samples, and perform two-dimensional nuclear magnetic resonance scanning in the original state, oil-washed dry state, water-saturated state, water-saturated centrifugal state, oil-saturated state and oil-saturated centrifugal state, respectively, to obtain the two-dimensional nuclear magnetic resonance fluid distribution map of the shale oil reservoir sample in each state; Step 3: Compare the signal changes in the two-dimensional nuclear magnetic resonance fluid distribution map of the shale oil reservoir sample under various conditions in step 2, identify the two-dimensional nuclear magnetic fluid components of the shale oil reservoir, and draw a two-dimensional nuclear magnetic fluid distribution map of the shale oil reservoir; Step 4: Calculate the pore size corresponding to the T2 distribution point by using the geometric mean value of T2 in the horizontal direction of the two-dimensional nuclear magnetic resonance spectrum of the shale oil reservoir sample and the specific surface area and pore volume of the shale oil reservoir sample obtained by low-temperature nitrogen and carbon dioxide adsorption experiments; Step 5: Based on the correspondence between T2 distribution points and pore size, draw a two-dimensional nuclear magnetic fluid pore size distribution map of shale oil reservoirs to determine the pore size distribution range of each fluid component; Step 6: Calculate the fluid saturation of the shale oil reservoir sample.

2. The method for visually and quantitatively characterizing the distribution of pore fluid in shale oil reservoirs according to claim 1 is characterized in that: The specific surface area is calculated according to the BET equation: ; Where W is the adsorption amount under relative pressure, cm 3 ; is the saturated adsorption capacity of the sample monolayer per unit mass, cm 3 ; is the relative partial pressure of gas; C is the BET constant; Select The odd number of data points in the range and the adsorption amount W under the corresponding relative pressure are substituted into the BET equation, and the slope is calculated as , the intercept is of value, then the pore specific surface area S=4.353 ; The pore volume is calculated according to the equivalent volume principle: ; Where V is the pore volume, cm 3 / g; is the maximum adsorption capacity of gas, cm 3 ; Pa is standard atmospheric pressure, 106 Pa; R is the gas constant, J ( / mol·K), with a value of 8.314; T is temperature, K.

3. The method for visually and quantitatively characterizing the distribution of pore fluid in shale oil reservoirs according to claim 1, characterized in that: In step 2, the IR-CPMG sequence of the two-dimensional MRI scan had a scan number of 64, a minimum inversion time of 0.1 ms, a maximum inversion time of 2 s, and an echo interval of 0.08 ms.

4. The method for visually and quantitatively characterizing the distribution of pore fluid in shale oil reservoirs according to claim 1, characterized in that: Standard plunger sample in original state: The standard plunger sample is processed into a cylindrical standard plunger sample with a diameter of 25mm and a length of 35mm by using waterless cutting, and wax-sealed immediately to ensure that there is no fluid loss during the process; Standard plunger sample in oil-washed and dried state: the standard plunger sample is washed with oil and salt, and then dried at 85℃ for 72 hours; Standard plunger sample in saturated state: The standard plunger sample is dried and vacuumed in a high-pressure container containing a core, and then deionized water is injected into the container at a high pressure of 30 MPa and maintained for 24 hours. Standard plunger sample in water-saturated centrifugal state: The standard plunger sample is obtained by centrifuging at 9000r / min for 2 hours in a high-speed centrifuge; Standard plunger sample in oil-saturated state: The standard plunger sample is dried at 85℃ for 72 hours, and then the high-pressure container containing the core is evacuated and aviation kerosene is injected into the container at a high pressure of 35 MPa for 24 hours to obtain the standard plunger sample; Standard plunger sample in oil-saturated centrifugal state: obtained by centrifugation in a high-speed centrifuge at 9000r / min for 2 hours.

5. The method for visually and quantitatively characterizing the distribution of pore fluid in shale oil reservoirs according to claim 1, characterized in that: Calculate the aperture corresponding to the T2 distribution point: According to the NMR relaxation mechanism, the transverse relaxation time is expressed as: ; Where, T2 is the transverse relaxation time, ms; is the surface relaxation rate, μm / ms; V is the pore volume, cm 3 / g; S is the pore specific surface area, m 2 / g; is the pore shape factor, which takes a value of 2; The geometric mean T2 value was used. 2LM Represents T2 distribution: ; In the formula, φ i is the corresponding NMR porosity component, %;φ NMR NMR porosity, %; From the above formula, we can get: ; In the formula, is the pore size corresponding to each T2 distribution point, nm; is the i-th NMR transverse relaxation time, ms; is the geometric mean of T2, ms.

6. The method for visually and quantitatively characterizing the distribution of pore fluid in shale oil reservoirs according to claim 1, characterized in that: The T2 relaxation time of the horizontal axis of the two-dimensional nuclear magnetic resonance spectrum is converted into pore size, and a two-dimensional nuclear magnetic fluid pore size distribution map of shale oil reservoirs is drawn. The pore size distribution range of each type of porous fluid is determined by the projection of the signal response area of ​​each type of fluid in the two-dimensional nuclear magnetic fluid pore size distribution map on the horizontal axis.

7. The method for visually and quantitatively characterizing the distribution of pore fluid in shale oil reservoirs according to claim 1, characterized in that: Calculate the fluid saturation of a shale oil reservoir sample: A wide-field scanning electron microscope was used to observe the shale oil reservoir samples after NMR scanning, and the pore sizes of each pore in the field of view were measured. The pores containing different fluid types were color-coded using ImageJ software according to the fluid pore size distribution parameters, the distribution characteristics of different fluid components were restored, and the area proportion of each pore color in the field of view was calculated.

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