Method for determining nanofluid oil displacement effect of low-permeability reservoir

Abstract

The invention provides a method for determining a nanofluid oil displacement effect of a low-permeability reservoir, and relates to the technical field of oil exploitation. The method comprises the following steps: providing a core of a low-permeability reservoir, and measuring the particle size of nanoparticles in a target nanofluid; performing high-pressure mercury injection test and nuclear magnetic resonance measurement on the rock core to respectively obtain a rock core pore throat radius-distribution frequency relation curve and a first T2 image, and performing benchmarking on the two images to obtain a pore throat radius-relaxation time relation curve; carrying out displacement experiments (oil displacement, first water displacement, nanofluid displacement and second water displacement) on the rock core, and carrying out nuclear magnetic resonance measurement to obtain T2 images; and observing or calculating the area enclosed by the curve and the relaxation time in each image, and combining with a pore throat radius-relaxation time relation curve to obtain the oil displacement effect of the nanofluid on different pores of the oil reservoir. The oil displacement effect of the nanometer system is determined according to the characteristic parameters of the reservoir core before and after the nanometer fluid is injected, and the method has important guiding significance for formulating a scheme for improving the recovery effect of the low-permeability oil reservoir.

Description

Technical Field

[0001] The present invention relates to the technical field of oil extraction, and in particular to a method for determining the oil displacement effect of nanofluids in low-permeability oil reservoirs. Background Art

[0002] Low-permeability reservoirs are a key area of ​​oil exploration and development worldwide, offering enormous resource potential and promising prospects. Low-permeability reservoirs have complex pore structures, containing micropores of varying sizes. Waterflooding can lead to high injection pressures and insufficient water volumes. Reservoir modification techniques reduce fluid flow resistance by expanding the effective pore size. However, this approach is costly and causes irreversible damage to the reservoir. Drag reduction technology using hydrophobic nanoparticles adsorbed within reservoir micropores is an emerging technology for enhancing oil recovery (ERR) in low-permeability reservoirs by reducing pressure and increasing injection volume. Nanoparticles, under the influence of microscopic forces, form an orderly arrangement on the rock surface, forming a hydrophobic adsorption layer that reduces the effective flow area. Furthermore, the strong hydrophobicity of the nanoparticle adsorption layer facilitates water slip along the pore walls, reducing injection pressure and improving oil recovery. Therefore, there is a necessary compatibility between nanoparticle size and pore radius in low-permeability reservoirs.

[0003] Existing technologies enable cross-scale, multi-dimensional characterization of reservoir pore structure. This has demonstrated, to a certain extent, that hydrophobic nanoparticles can enter the micropores of low-permeability reservoirs along with the injected fluid, adsorbing on the micropore walls to create a water slip effect, reducing flow resistance and explaining why nanofluid injection produces a pressure-reducing and injection-enhancing effect in low-permeability reservoirs. However, micropores of varying scales can lead to water slip within macropores and physical blockage within ultramicropores. Whether hydrophobic nanoparticle adsorption can expand the effective pore radius and reduce flow resistance is crucial for improving oil recovery in low-permeability reservoirs. Existing technologies and research methods have yet to provide a method for determining the oil recovery effectiveness of nanofluids in low-permeability reservoirs. Summary of the Invention

[0004] In light of this, the present invention aims to provide a method for determining the effectiveness of nanofluid flooding in low-permeability reservoirs. This method, capable of determining the effectiveness of nanofluid flooding in low-permeability reservoirs, is of great significance for optimizing the recovery efficiency of nanofluids in low-permeability reservoirs and formulating development plans.

[0005] In order to achieve the above-mentioned object of the invention, the present invention provides the following technical solutions: The present invention provides a method for determining the oil displacement effect of nanofluids in low permeability reservoirs, comprising the following steps: Providing cores from low permeability reservoirs to measure the particle size of nanoparticles in target nanofluids; The core is subjected to high-pressure mercury injection testing to obtain the core pore throat radius-distribution frequency relationship curve; The wet sample of the core is subjected to nuclear magnetic resonance measurement to obtain a first T2 image; The core pore throat radius-distribution frequency relationship curve is aligned with the first T2 image to obtain a pore throat radius-relaxation time relationship curve; the alignment is to correspond the maximum value of the pore throat radius in the core pore throat radius-distribution frequency relationship curve to the maximum value of the relaxation time in the first T2 image, and to correspond the minimum value of the pore throat radius in the core pore throat radius-distribution frequency relationship curve to the minimum value of the relaxation time in the first T2 image, and perform linear fitting; Performing a displacement experiment on the core, the displacement experiment comprising sequentially performing oil flooding, a first water flooding, a nanofluid flooding, and a second water flooding on the core, and performing nuclear magnetic resonance measurements on the core after the oil flooding, the first water flooding, and the second water flooding to obtain a second T2 image, a third T2 image, and a fourth T2 image; The areas enclosed by the curves and the relaxation times in the second T2 image, the third T2 image, and the fourth T2 image are observed or calculated respectively to obtain the first area, the second area, and the third area. The larger the absolute value of the difference between the third area and the second area, the better the oil displacement effect of the target nanofluid. The relaxation time corresponding to the area with the maximum absolute value of the difference is substituted into the pore throat radius-relaxation time relationship curve to obtain the corresponding pore throat radius value, that is, the target nanofluid has the best oil displacement effect on the reservoir of the pore throat radius.

[0006] Preferably, the permeability of the low permeability reservoir is (10~80)×10 -3 μm 2 , the porosity is 10~25%.

[0007] Preferably, the target nanofluid comprises water and hydrophobic nanoparticles.

[0008] Preferably, the method of performing high-pressure mercury injection testing on the core is: Mercury was injected into the core at different injection pressures. After the pressure stabilized, the injection pressure and the corresponding mercury injection volume were recorded. The injection pressure is equated to the capillary pressure corresponding to the pore space accessible to mercury injection, and the capillary radius corresponding to the capillary pressure is equated to the core pore throat radius to obtain a mercury saturation-capillary pressure curve. The distribution frequencies corresponding to different pore throat radius intervals are then calculated based on the mercury injection volume under different injection pressures to obtain the core pore throat radius-distribution frequency relationship curve.

[0009] Preferably, the wet sample of the core is obtained by vacuuming the core and then saturating it with deionized water.

[0010] Preferably, the oil flooding is to continuously inject crude oil into the core, and stop the injection when the water output at the outlet is zero.

[0011] Preferably, the first water flooding is to inject water into the core after oil flooding, and the injection is stopped when the water content at the outlet reaches 98%.

[0012] Preferably, the nanofluid flooding is to inject the target nanofluid into the core after the first water flooding, and the injection is stopped when the water content at the outlet reaches 99%.

[0013] Preferably, the second water flooding is to inject water into the core into which the target nanofluid is injected, and the injection is stopped when the water content at the outlet reaches 100%.

[0014] Preferably, the injection rates of the crude oil, the target nanofluid, and the water during the first water flooding and the second water flooding are 0.1 mL / min, respectively.

[0015] The present invention provides a method for determining the relationship between the oil recovery effect of nanofluids in low-permeability reservoirs and reservoir adaptability. The method comprises providing a core from a low-permeability reservoir and measuring the particle size of nanoparticles in a target nanofluid; obtaining a pore throat radius-relaxation time curve for the core; conducting a displacement experiment on the core to obtain the changing characteristics of the fluid distribution before and after nanofluid injection using nuclear magnetic resonance; and finally, determining the oil recovery effect of the nanofluid within the core pores based on the pore throat distribution-relaxation time curve obtained before nanofluid injection and the T2 image obtained after nanofluid injection. The present invention uses characteristic parameters of the reservoir core before and after nanofluid injection to determine the effect of nanofluid system oil recovery on the remaining oil in pores of different sizes, thereby clarifying the effect of nanoparticle size on the recovery efficiency of different core pore sizes. This method has important guiding significance for the development of plans to further improve the recovery effect of low-permeability reservoirs. BRIEF DESCRIPTION OF THE DRAWINGS

[0016] Figure 1 This is the result of high-pressure mercury injection testing (mercury saturation-capillary pressure curve); Figure 2 This is the result of high-pressure mercury injection testing (core pore throat radius-distribution frequency relationship curve); Figure 3 The results of the nuclear magnetic resonance test and high-pressure mercury injection test after the core was saturated with water in Example 1 are shown; Figure 4 The graph showing the relationship between T2 relaxation time and pore size in Example 1 (pore throat radius-relaxation time curve); Figure 5 The results of nuclear magnetic resonance testing of nanoparticles with a particle size of 20 nm at different displacement stages; Figure 6 These are the nuclear magnetic resonance test results of nanoparticles with a particle size of 50 nm at different displacement stages. DETAILED DESCRIPTION

[0017] The present invention provides a method for determining the oil displacement effect of nanofluids in low permeability reservoirs, comprising the following steps: Providing cores from low permeability reservoirs to measure the particle size of nanoparticles in target nanofluids; The core is subjected to high-pressure mercury injection testing to obtain the core pore throat radius-distribution frequency relationship curve; The wet sample of the core is subjected to nuclear magnetic resonance measurement to obtain a first T2 image; The core pore throat radius-distribution frequency relationship curve is aligned with the first T2 image to obtain a pore throat radius-relaxation time relationship curve; the alignment is to correspond the maximum value of the pore throat radius in the core pore throat radius-distribution frequency relationship curve to the maximum value of the relaxation time in the first T2 image, and to correspond the minimum value of the pore throat radius in the core pore throat radius-distribution frequency relationship curve to the minimum value of the relaxation time in the first T2 image, and perform linear fitting; Performing a displacement experiment on the core, the displacement experiment comprising sequentially performing oil flooding, a first water flooding, a nanofluid flooding, and a second water flooding on the core, and performing nuclear magnetic resonance measurements on the core after the oil flooding, the first water flooding, and the second water flooding to obtain a second T2 image, a third T2 image, and a fourth T2 image; The areas enclosed by the curves and the relaxation times in the second T2 image, the third T2 image, and the fourth T2 image are observed or calculated respectively to obtain the first area, the second area, and the third area. The larger the absolute value of the difference between the third area and the second area, the better the oil displacement effect of the target nanofluid. The relaxation time corresponding to the area with the maximum absolute value of the difference is substituted into the pore throat radius-relaxation time relationship curve to obtain the corresponding pore throat radius value, that is, the target nanofluid has the best oil displacement effect on the reservoir of the pore throat radius.

[0018] The present invention provides a core of a low-permeability oil reservoir and measures the particle size of nanoparticles in a target nanofluid.

[0019] In the present invention, the cores in each step are cores taken from the same target block.

[0020] In the present invention, the permeability of the low permeability reservoir is preferably (10~80)×10 -3 μm 2 , which can be (10~20)×10 -3 μm 2 The porosity is preferably 10-25%, and can be 15-24%.

[0021] In the present invention, the target nanofluid preferably comprises water and hydrophobic nanoparticles. The present invention has no particular requirements for the hydrophobic nanoparticles; any hydrophobic nanoparticles known to those skilled in the art, such as hydrophobically modified nano-SiO2, can be used. In the present invention, the particle size of the nanoparticles in the target nanofluid can be measured by dynamic light scattering or zeta potential.

[0022] The present invention conducts a high-pressure mercury injection test on the rock core to obtain a rock core pore throat radius-distribution frequency relationship curve.

[0023] The present invention preferably pre-treats the core and then places it into a mercury intrusion instrument core chamber for high-pressure mercury injection testing to determine the distribution pattern of different pore sizes in the core; the pre-treatment method is preferably: washing the core with toluene oil and drying it in sequence. In the present invention, the high-pressure mercury injection testing method is preferably: Mercury was injected into the pretreated core at different injection pressures. After the pressure stabilized, the injection pressure and the corresponding mercury injection volume were recorded. The injection pressure is equated to the capillary pressure corresponding to the pore space accessible to mercury injection, and the capillary radius corresponding to the capillary pressure is equated to the core pore throat radius to obtain a mercury saturation-capillary pressure curve. The distribution frequencies corresponding to different pore throat radius intervals are then calculated based on the mercury injection volume under different injection pressures to obtain the core pore throat radius-distribution frequency relationship curve.

[0024] In the present invention, the specific operation of injecting mercury into the pretreated core at different injection pressures is preferably: injecting mercury into the pretreated core at a set pressure, recording the pressure value and mercury injection volume after the pressure stabilizes, increasing the injection pressure, and repeating the above operation.

[0025] The present invention performs nuclear magnetic resonance measurement on a wet sample of the core to obtain a first T2 image.

[0026] In the present invention, the wet core sample is preferably obtained by evacuating the core and then saturating it with deionized water. Nuclear magnetic resonance (NMR) measurements require wet samples. The rock sample skeleton does not produce an NMR signal. Therefore, whether it is core, cuttings, or sidewall coring, wet sampling is required. After removal, the rock sample should be moisturized before NMR measurement.

[0027] In the present invention, the NMR measurement method preferably includes placing the wet core sample into a magnetic probe, adjusting the resonance frequency, selecting a T2 Image pulse sequence, setting system and acquisition parameters, and acquiring T2 images (i.e., first T2 images) at different relaxation times. In the present invention, the NMR measurement provides a characteristic image of the mobile fluid in the core.

[0028] After obtaining the core pore throat radius-distribution frequency relationship curve and the first T2 image, the present invention aligns the core pore throat radius-distribution frequency relationship curve with the first T2 image to obtain a pore throat radius-relaxation time relationship curve (i.e., a conversion relationship curve between the pore size distribution of the core and the relaxation time).

[0029] In the present invention, the calibration method is: linear fitting is performed by corresponding the maximum value of the pore throat radius in the core pore throat radius-distribution frequency relationship curve to the maximum value of the relaxation time in the first T2 image, and corresponding the minimum value of the pore throat radius in the core pore throat radius-distribution frequency relationship curve to the minimum value of the relaxation time in the first T2 image.

[0030] After obtaining the pore throat radius-relaxation time relationship curve, the present invention conducts a displacement experiment on the core, wherein the displacement experiment includes sequentially performing oil drive, first water drive, nanofluid drive, and second water drive on the core. After the oil drive, first water drive, and second water drive, nuclear magnetic resonance measurements are performed on the core to obtain a second T2 image, a third T2 image, and a fourth T2 image.

[0031] In the present invention, the oil drive is preferably to continuously inject crude oil into the core, and the injection is stopped when the water output at the outlet is 0. In the present invention, the first water drive is to inject water into the core after the oil drive, and the injection is stopped when the water content at the outlet reaches 98%. In the present invention, the nanofluid drive is to inject the target nanofluid into the core after the first water drive, and the injection is stopped when the water content at the outlet reaches 99%. In the present invention, the second water drive is to inject water into the core injected with the target nanofluid, and the injection is stopped when the water content at the outlet reaches 100%. In the present invention, the injection rates of the crude oil, the target nanofluid, and the water during the first and second water drives are preferably 0.1 mL / min, respectively.

[0032] In the embodiment of the present invention, the specific operation of the displacement experiment is: (1) Check the air tightness of the device and vacuum the core; (2) Oil flooding (model saturated with oil): Crude oil was continuously injected into the model at a rate of 0.1 mL / min. The injection was stopped when the water output of the model reached 0. The total water output during the entire process was recorded, and the original oil saturation (above 70%) was estimated based on the measured value. The model was placed in a thermostat set to 45°C and kept in the thermostat for 3 days (to simulate the actual formation environment and the effect of crude oil production). (3) First water flooding: water was injected at a rate of 0.1 mL / min, and the pressure change of the system was recorded in real time. The oil production and water production at the outlet were also recorded. The injection was stopped when the water cut reached 98%, and the corresponding water flooding recovery factor was calculated based on the measured values. (4) Nanofluid flooding: When the water content of the water flooding system is greater than 98%, the nanofluid flooding system is injected at a displacement rate of 0.1 mL / min, and the pressure change of the system is recorded in real time. When the water content reaches 99%, the injection is stopped, and the oil and water production at the outlet are recorded. The corresponding total recovery factor is calculated based on the measured values; (5) Second water flooding: water was injected at a displacement rate of 0.1 mL / min. When the end of the model was fully water-filled, the pressure change of the system was recorded, and the oil and water production at the outlet were recorded. When the water content reached 100%, the injection was stopped, and the corresponding water flooding recovery factor was calculated based on the measured values. (6) Repeat the above steps for different nanofluids according to the experimental plan and record the required experimental data.

[0033] In the present invention, nuclear magnetic resonance measurements are performed on the core after the oil flooding, the first water flooding, and the second water flooding, respectively, to obtain a second T2 image, a third T2 image, and a fourth T2 image. In the present invention, nuclear magnetic resonance measurements can be performed directly on the core after the oil flooding, the first water flooding, and the second water flooding; the operating method of the nuclear magnetic resonance measurement is the same as the operating method of the nuclear magnetic resonance measurement described above and will not be repeated here. In the present invention, the nuclear magnetic resonance measurement is used to obtain a characteristic image of the flow of the movable fluid in the core after the nanofluid is injected. Because subsequent water flooding (i.e., the second water flooding) after the injection of the nanofluid can further enhance the oil displacement effect of the nanofluid flooding, the present invention uses the T2 image measured after the second water flooding, i.e., the fourth T2 image, to represent the characteristic image of the flow of the movable fluid in the core after the nanofluid is injected.

[0034] After obtaining the second T2 image, the third T2 image, and the fourth T2 image, the areas enclosed by the curves and the relaxation times in the second T2 image, the third T2 image, and the fourth T2 image are respectively observed or calculated to obtain the first area, the second area, and the third area. The larger the absolute value of the difference between the third area and the second area, the better the oil displacement effect of the target nanofluid. The relaxation time corresponding to the area with the maximum absolute value of the difference is substituted into the pore throat radius-relaxation time relationship curve to obtain the corresponding pore throat radius value, that is, the target nanofluid has the best oil displacement effect on the reservoir of the pore throat radius.

[0035] When fluid flows in the pore throats of a core under different conditions, the proportion of movable fluid in pores of different sizes can be obtained. The area enclosed by the T2 signal curve and the relaxation time in the T2 image reflects the volume of the fluid in the pore, and the relationship is shown in Equation (1): Formula (1), In formula (1), V0 represents the volume of movable fluid in the pore, S(T2) represents the area enclosed by the T2 signal curve and the relaxation time, and α is the experimental constant.

[0036] In the present invention, the absolute value of the difference between the third area and the second area, that is, the absolute value of the difference between the T2 signal curve obtained before and after the injection of the nanofluid and the area enclosed by the relaxation time, is the change in fluid volume, that is, the absolute value of the change in fluid volume ΔV after the injection of the nanoparticles. ΔV is calculated as shown in formula (2): Formula (2), In formula (2), V1 is the volume of the first water flooding fluid, V2 is the volume of the second water flooding fluid, S2 is the area enclosed by the second water flooding T2 signal curve and the relaxation time, S1 is the area enclosed by the first water flooding T2 signal curve and the relaxation time, and α is the experimental constant.

[0037] The fluid amplification η can be calculated by formula (3): Formula (3).

[0038] Therefore, the greater the absolute value of the difference between the third and second areas, the greater the nanofluid's effectiveness in mobilizing the fluid (i.e., oil) within the pore throats, i.e., the greater the oil displacement efficiency of the target nanofluid. If the third and fourth T2 images overlap or remain essentially unchanged, this indicates that the fluid within that pore size has had virtually no effect, meaning the fluid is not being mobilized. Substituting the relaxation time corresponding to the region with the maximum absolute value of the difference into the pore throat radius-relaxation time curve yields the corresponding pore throat radius value, indicating that the target nanofluid has the best oil displacement efficiency for the reservoir with that pore throat radius.

[0039] The present invention determines the nanofluid oil displacement effect based on the microscopic characterization results of the core pores and the changes in fluid characteristic distribution after the nanofluid is injected.

[0040] The method provided by the present invention for determining the oil displacement effect of nanofluids in low-permeability reservoirs determines the recovery enhancement effect of the core based on the flow characteristics of the fluid in the pores before and after the nanofluid is injected into the core. At the same time, combined with the results of nuclear magnetic resonance and high-pressure mercury injection tests, the matching relationship between nanoparticles and pore size is clarified, which is of great significance for optimizing the recovery enhancement effect of nanofluids in low-permeability reservoirs and formulating development plans.

[0041] To further illustrate the present invention, the method for determining the oil displacement effect of nanofluids in low permeability reservoirs provided by the present invention is described in detail below with reference to examples, but they should not be construed as limiting the scope of protection of the present invention.

[0042] Example 1 In this example, a typical coring well S in a low permeability oil reservoir block was selected as the research object. The nanoparticles used in the experiment were hydrophobically modified nano-SiO2 with particle sizes of 20 nm and 50 nm, respectively.

[0043] (1) Obtaining initial core characteristic parameters (permeability and porosity), which are used to determine the reservoir type and characterize the permeability characteristics of the reservoir; The method for obtaining the initial core characteristic parameters is to dry the core and perform a gas permeability test to obtain the initial values ​​of the core's permeability and porosity. The basic parameters of the core used are shown in Table 1.

[0044] Table 1 Basic parameters of core

[0045] According to bridging theory, nanofluid particles can migrate within the pore throats of reservoir rocks only when the particle size of the injected displacement fluid is ≤1 / 7 times the average reservoir pore throat diameter. Calculations show that under these experimental conditions, the nanoparticle size in all experimental schemes meets the requirement of ≤1 / 7 times the average reservoir pore throat diameter. Therefore, nanoparticle migration within pore throats is possible in this experiment.

[0046] (2) Use high-pressure mercury intrusion instrument to test the natural core of low permeability reservoir. The test method is: ① Wash the experimental core rock with toluene and then dry it; ② Place the core into the core chamber of the mercury intrusion instrument and inject mercury at the set pressure. After the pressure stabilizes, record the pressure value and the volume of mercury injected. Increase the injection pressure and repeat the above experimental data recording. ③ The injection pressure is equated with the capillary pressure corresponding to the pore space where mercury can enter, and the capillary radius corresponding to the capillary pressure is equated with the core pore throat radius. The capillary pressure curve can be obtained by continuously increasing the injection pressure. Combined with the mercury injection volume, the distribution frequency corresponding to different pore throat radius intervals can be calculated to obtain the core pore throat radius-distribution frequency relationship curve.

[0047] The results of high-pressure mercury injection experiments are as follows Figure 1 and Figure 2 As shown, Figure 1 This is the result of high-pressure mercury injection test (mercury saturation-capillary pressure curve). Figure 2 This is the result of high-pressure mercury injection testing (core pore throat radius-distribution frequency relationship curve).

[0048] (3) Obtain the microscopic pore structure of the core in the target area and realize the pore size distribution-relaxation time benchmarking of the core based on the high-pressure mercury injection and nuclear magnetic resonance test results of the core, specifically: ① Inject deionized water into the core to saturate the core: The core was dried in a 65°C oven for 4 hours. The dried core was then vacuumed and saturated with deionized water. The specific operation of saturating the core with deionized water was as follows: the core was placed in a core holder, and the confining pressure was set to 4 MPa and kept constant. The temperature of the thermostat was raised to 45°C, and deionized water was injected at a constant rate of 0.1 mL / min. The real-time pressure data was monitored and the pressure of the system after different PV numbers were injected was recorded until the pressure at the outlet remained constant. ② Perform nuclear magnetic resonance testing on the core in a water-saturated state to obtain the T2 spectrum of the core in the saturated state; specifically, nuclear magnetic resonance measurement requires measurement of wet samples. The rock sample skeleton does not generate nuclear magnetic resonance signals. Therefore, whether it is cores, cuttings, or well wall coring, sampling is required to be done under wet sample conditions. After the rock sample is taken out, it should be moisturized before nuclear magnetic resonance measurement; perform nuclear magnetic resonance measurement on the core saturated with deionized water in ① to obtain a moving fluid image: place the prepared core saturated with deionized water into the magnet probe, adjust the resonance frequency, select the T2 Image pulse sequence, set the system parameters and acquisition parameters, and obtain T2 images with different relaxation times, such as Figure 3 As shown; ③Compare the pore throat radius distribution obtained from high pressure mercury injection test with the T2 image obtained from nuclear magnetic resonance test (such as Figure 3 as shown) for benchmarking (with Figure 2 The maximum value of the pore throat radius in the pore throat radius-distribution frequency relationship curve of the core corresponds to Figure 3 The maximum relaxation time in the T2 image, Figure 2 The minimum value of the pore throat radius in the pore throat radius-distribution frequency relationship curve of the core corresponds to Figure 3 The minimum value of relaxation time in the T2 image is linearly fitted), and the corresponding T2 relaxation time and pore throat distribution relationship is obtained, that is, the pore throat radius-relaxation time relationship curve, as shown in Figure 4 shown.

[0049] (4) Using a 0.1 wt% hydrophobically modified nano-SiO2 aqueous solution as a nanofluid, a core displacement experiment was conducted to determine the nanofluid's ability to enhance oil recovery in low / ultra-low permeability cores, i.e., its oil displacement effect. The steps are as follows (the experiment was conducted in a 45°C constant temperature chamber): ① Check the air tightness of the device and vacuum the core; ② Saturated oil flooding (model saturated with oil): Crude oil was continuously injected into the model at a rate of 0.1 mL / min. Injection was stopped when the water output from the model reached zero. The total water output during the entire process was recorded, and the initial oil saturation (above 70%) was estimated from the measured value. The model was placed in a thermostat set to 45°C and aged at this temperature for 3 days. ③ First water flooding: Water was injected at a rate of 0.1 mL / min, and the pressure changes of the system were recorded in real time. The oil and water production at the outlet were also recorded. Injection was stopped when the water cut reached 98%, and the corresponding water flooding recovery factor was calculated based on the measured values. ④ Nanofluid flooding: When the water content of the water flooding system is greater than 98%, the nanofluid flooding system is injected at a displacement rate of 0.1 mL / min, and the pressure changes of the system are recorded in real time. When the water content reaches 99%, the injection is stopped, and the oil and water production at the outlet are recorded. The corresponding total recovery factor is calculated based on the measured values. ⑤ Second water flooding: Water is injected at a displacement rate of 0.1 mL / min. When the end of the model is fully water-filled, the pressure change of the system is recorded, and the oil and water production at the outlet are recorded. When the water cut reaches 100%, the injection is stopped and the corresponding water flooding recovery factor is calculated based on the measured values. Among them, nuclear magnetic resonance measurements were performed on the cores after saturated oil flooding, first water flooding and second water flooding, and corresponding T2 images were obtained.

[0050] By comparing the T2 images measured by nuclear magnetic resonance before and after the injection of nanofluid, the distribution of fluid in the pore volume can be obtained, and then the mobilization of residual oil in different pore sizes by nanoparticles can be obtained. Figure 5 and Figure 6 As shown, Figure 5 The results of nuclear magnetic resonance testing of nanoparticles with a particle size of 20 nm at different displacement stages are shown below. Figure 6 These are the nuclear magnetic resonance test results of nanoparticles with a particle size of 50 nm at different displacement stages. Figure 5 and Figure 6 In the NMR test, the T2 image corresponding to "nanofluid flooding" is the T2 image measured after the second water flooding. This means the T2 image measured after the second water flooding represents the T2 image measured after nanofluid injection. When 20nm and 50nm nanoparticles were injected into the core, the core recovery factors were 41.3% and 40.8%, respectively.

[0051] The area enclosed by the curve of the nuclear magnetic resonance test results of the fluid core before and after the injection of nanoparticles is the increase in the fluid in the pore after the action of the nanofluid. Combined with the pore throat radius-relaxation time relationship curve determined in (3), the corresponding relationship between T2 relaxation time and pore throat size can be used to obtain the effect of nanofluid injection on the fluid in pores of different sizes. Specifically, the relaxation time corresponding to the area with the maximum absolute value of the difference between the curve and the area enclosed by the relaxation time in the T2 image obtained before and after the injection of nanoparticles is substituted into the pore throat radius-relaxation time relationship curve to obtain the corresponding pore throat radius value, that is, the nanofluid has the best oil recovery effect on the reservoir with this pore throat radius.

[0052] Nanoparticles of varying particle sizes achieved similar enhanced oil recovery (ERR) results, all around 40%. However, the NMR results were significantly different between 20nm and 50nm nanoparticles. The 20nm particle size primarily enhanced residual oil mobilization within the 3-6ms relaxation time range, corresponding to pore sizes of 100-200nm. For 50nm nanoparticles, fluid mobilization was primarily concentrated within the 7-15ms relaxation time range, primarily mobilizing residual oil within pore throats of 250-500nm. The results indicate that a nanoparticle-to-pore radius ratio of 20-40% achieves the best results for residual oil mobilization in nanopores.

[0053] The above description is merely a preferred embodiment of the present invention and does not constitute any limitation thereto. It should be noted that those skilled in the art may make various improvements and modifications without departing from the principles of the present invention, and such improvements and modifications shall also be considered within the scope of protection of the present invention.

Claims

1. A method for determining the oil displacement effect of nanofluids in low permeability reservoirs, characterized in that: The following steps are involved: Providing cores from low permeability reservoirs to measure the particle size of nanoparticles in target nanofluids; The core is subjected to high-pressure mercury injection testing to obtain the core pore throat radius-distribution frequency relationship curve; The wet sample of the core is subjected to nuclear magnetic resonance measurement to obtain a first T2 image; The core pore throat radius-distribution frequency relationship curve is aligned with the first T2 image to obtain a pore throat radius-relaxation time relationship curve; the alignment is to correspond the maximum value of the pore throat radius in the core pore throat radius-distribution frequency relationship curve to the maximum value of the relaxation time in the first T2 image, and to correspond the minimum value of the pore throat radius in the core pore throat radius-distribution frequency relationship curve to the minimum value of the relaxation time in the first T2 image, and perform linear fitting; Performing a displacement experiment on the core, the displacement experiment comprising sequentially performing oil flooding, a first water flooding, a nanofluid flooding, and a second water flooding on the core, and performing nuclear magnetic resonance measurements on the core after the oil flooding, the first water flooding, and the second water flooding to obtain a second T2 image, a third T2 image, and a fourth T2 image; The areas enclosed by the curves and the relaxation times in the second T2 image, the third T2 image, and the fourth T2 image are observed or calculated respectively to obtain the first area, the second area, and the third area. The larger the absolute value of the difference between the third area and the second area, the better the oil displacement effect of the target nanofluid. The relaxation time corresponding to the area with the maximum absolute value of the difference is substituted into the pore throat radius-relaxation time relationship curve to obtain the corresponding pore throat radius value, that is, the target nanofluid has the best oil displacement effect on the reservoir of the pore throat radius.

2. The method according to claim 1, characterized in that The permeability of the low permeability reservoir is (10~80)×10 -3 μm 2 , the porosity is 10~25%.

3. The method according to claim 1, characterized in that The target nanofluid includes water and hydrophobic nanoparticles.

4. The method according to claim 1, wherein The method of performing high-pressure mercury injection testing on the core is as follows: Mercury was injected into the core at different injection pressures. After the pressure stabilized, the injection pressure and the corresponding mercury injection volume were recorded. The injection pressure is equated to the capillary pressure corresponding to the pore space accessible to mercury injection, and the capillary radius corresponding to the capillary pressure is equated to the core pore throat radius to obtain a mercury saturation-capillary pressure curve. The distribution frequencies corresponding to different pore throat radius intervals are then calculated based on the mercury injection volume under different injection pressures to obtain the core pore throat radius-distribution frequency relationship curve.

5. The method according to claim 1, wherein The wet sample of the core is obtained by vacuuming the core and then saturating it with deionized water.

6. The method according to claim 1, characterized in that The oil flooding is to continuously inject crude oil into the core and stop the injection when the water output at the outlet reaches 0.

7. The method according to claim 1, characterized in that The first water flooding is to inject water into the core after oil flooding, and stop the injection when the water content at the outlet reaches 98%.

8. The method according to claim 1, characterized in that The nanofluid flooding is to inject the target nanofluid into the core after the first water flooding, and the injection is stopped when the water content at the outlet reaches 99%.

9. The method according to claim 1, characterized in that The second water flooding is to inject water into the core into which the target nanofluid is injected, and the injection is stopped when the water content at the outlet reaches 100%.

10. The method according to any one of claims 6 to 9, characterized in that The injection rates of crude oil, target nanofluid, and water during the first and second water flooding were 0.1 mL / min, respectively.

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