A method for determining the oil displacement effect of nanofluids in low-permeability reservoirs

Abstract

This invention provides a method for determining the oil displacement effect of nanofluids in low-permeability reservoirs, relating to the field of petroleum extraction technology. The invention includes providing a core sample from a low-permeability reservoir and determining the particle size of nanoparticles in the target nanofluid; performing high-pressure mercury injection testing and nuclear magnetic resonance (NMR) measurements on the core sample to obtain a pore throat radius-distribution frequency relationship curve and a first T2 image, respectively; and comparing these two to obtain a pore throat radius-relaxation time relationship curve; conducting displacement experiments (oil flooding, first water flooding, nanofluid flooding, and second water flooding) on ​​the core sample and performing NMR measurements to obtain various T2 images; observing or calculating the area enclosed by the curve and relaxation time in each image, and combining this with the pore throat radius-relaxation time relationship curve, to obtain the oil displacement effect of the nanofluid on different pore sizes in the reservoir. This invention uses characteristic parameters of the reservoir core before and after nanofluid injection to determine the oil displacement effect of the nanofluid system, providing important guidance for formulating strategies to improve the recovery effect of low-permeability reservoirs.

Description

Technical Field

[0001] This invention relates to the field of petroleum extraction technology, and in particular to a method for determining the oil displacement effect of nanofluids in low-permeability reservoirs. Background Technology

[0002] Low-permeability reservoirs are a key area of ​​oil exploration and development worldwide, possessing enormous resource potential and promising prospects. These reservoirs exhibit complex pore structures, containing micropores of various sizes, leading to challenges such as high injection pressure and insufficient injection volume during water injection development. Reservoir stimulation techniques reduce fluid flow resistance by enlarging the effective pore size, achieving drag reduction. However, this approach is costly and causes irreversible damage to the reservoir. Hydrophobic nanoparticle adsorption drag reduction technology within the micropores of the reservoir is an emerging enhanced oil recovery (EOR) technology for depressurization and increased injection in low-permeability reservoirs. On one hand, nanoparticles, under the influence of microscopic forces, can arrange themselves in an orderly manner on the rock wall to form a hydrophobic adsorption layer, reducing the effective flow area of ​​the fluid. On the other hand, the strong hydrophobicity of the nanoparticle adsorption layer facilitates water slippage on the pore wall, reducing injection pressure and improving recovery efficiency. Therefore, a compatibility between nanoparticle size and the pore radius of low-permeability reservoirs is essential.

[0003] Existing techniques have enabled multi-scale, multi-dimensional characterization of reservoir pore structure, verifying to some extent that hydrophobic nanoparticles can enter the micropores of low-permeability reservoirs with the injected fluid, adsorbing onto the micropore walls and generating a water flow slip effect, thus reducing seepage resistance. This explains the pressure reduction and enhanced injection effect of nanofluid injection in low-permeability reservoirs. However, the presence of micropores at various scales can lead to water flow slip effects in large pores and physical blockage in ultra-micropores. Whether the adsorption of hydrophobic nanoparticles can expand the effective pore radius and reduce seepage resistance is crucial for improving oil recovery in low-permeability reservoirs. Current techniques and research methods have not yet provided a method to determine the oil displacement effect of nanofluids in low-permeability reservoirs. Summary of the Invention

[0004] In view of this, the purpose of this invention is to provide a method for determining the oil displacement effect of nanofluids in low-permeability reservoirs. The method provided by this invention can determine the oil displacement effect of nanofluids in low-permeability reservoirs, which is of great significance for optimizing the oil recovery effect of nanofluids in low-permeability reservoirs and formulating development plans.

[0005] To achieve the above-mentioned objectives, the present invention provides the following technical solution:

[0006] This invention provides a method for determining the oil displacement effect of nanofluids in low-permeability reservoirs, comprising the following steps:

[0007] Provide core samples from low-permeability reservoirs to determine the particle size of nanoparticles in the target nanofluid;

[0008] High-pressure mercury intrusion testing was performed on the core to obtain the core pore throat radius-distribution frequency relationship curve;

[0009] Nuclear magnetic resonance (NMR) measurements were performed on the wet core sample to obtain the first T2 image;

[0010] The pore throat radius-distribution frequency relationship curve of the core is compared with the first T2 image to obtain the pore throat radius-relaxation time relationship curve; the comparison is to perform linear fitting with the maximum value of the pore throat radius in the core pore throat radius-distribution frequency relationship curve corresponding to the maximum value of the relaxation time in the first T2 image, and the minimum value of the pore throat radius in the core pore throat radius-distribution frequency relationship curve corresponding to the minimum value of the relaxation time in the first T2 image;

[0011] The core was subjected to a displacement experiment, which included sequentially performing oil flooding, first water flooding, nanofluid flooding and second water flooding on the core. After the oil flooding, first water flooding and second water flooding, the core was subjected to nuclear magnetic resonance measurement to obtain a second T2 image, a third T2 image and a fourth T2 image.

[0012] By observing or calculating the areas enclosed by the curves and relaxation times in the second, third, and fourth T2 images, respectively, we 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. Substituting the relaxation time corresponding to the region with the largest absolute value of the difference into the pore throat radius-relaxation time relationship curve, we obtain the corresponding pore throat radius value, that is, the target nanofluid has the best reservoir oil displacement effect for that pore throat radius.

[0013] Preferably, the permeability of the low-permeability reservoir is (10~80)×10⁻⁶. -3 μm 2 The porosity is 10~25%.

[0014] Preferably, the target nanofluid comprises water and hydrophobic nanoparticles.

[0015] Preferably, the method for performing high-pressure mercury intrusion porosimetry on the core is as follows:

[0016] Mercury was injected into the core under different injection pressures, and the injection pressure value and the corresponding mercury volume were recorded after the pressure stabilized.

[0017] The injection pressure is equated to the capillary pressure corresponding to the mercury-accessible pore space, and the capillary radius corresponding to the capillary pressure is equated to the core pore throat radius. The mercury saturation-capillary pressure curve is obtained. Then, the distribution frequency corresponding to different pore throat radius ranges is calculated by combining the mercury-accessible volume under different injection pressures, and the core pore throat radius-distribution frequency relationship curve is obtained.

[0018] Preferably, the method for obtaining a wet sample of the core is as follows: the core is vacuumed and then saturated with deionized water.

[0019] Preferably, the oil flooding involves continuously injecting crude oil into the core and stopping the injection when the water flow at the outlet reaches zero.

[0020] Preferably, the first water drive involves injecting water into the core after oil flooding, and stopping the injection when the water content at the outlet reaches 98%.

[0021] Preferably, the nanofluid drive involves injecting the target nanofluid into the core after the first water flood, and stopping the injection when the water content at the outlet reaches 99%.

[0022] Preferably, the second water drive involves injecting water into the core into which the target nanofluid is injected, and stopping the injection when the water content at the outlet reaches 100%.

[0023] Preferably, the injection rates of the crude oil, the target nanofluid, and the water during the first and second water flooding are 0.1 mL / min.

[0024] This invention provides a method for determining the oil displacement effect of nanofluids in low-permeability reservoirs and its relationship with reservoir adaptation. The method includes providing a core sample from a low-permeability reservoir and determining the particle size of nanoparticles in the target nanofluid; obtaining the pore throat radius-relaxation time relationship curve of the core sample; conducting displacement experiments on the core sample and obtaining the changes in fluid distribution before and after nanofluid injection using nuclear magnetic resonance (NMR); finally, based on the pore throat distribution-relaxation time relationship curve of the core sample obtained before nanofluid injection and the T2 image obtained after nanofluid injection, the oil displacement effect of the nanofluid within the core pores is determined. This invention uses characteristic parameters of the reservoir core before and after nanofluid injection to determine the effect of the nanofluid system on the mobilization of residual oil in pores of different sizes, thereby clarifying the effect of nanoparticle size on improving oil recovery for different core pore sizes. This has significant guiding significance for formulating strategies to further improve oil recovery in low-permeability reservoirs. Attached Figure Description

[0025] Figure 1 The graph shows the results of the high-pressure mercury intrusion test (mercury saturation-capillary pressure curve).

[0026] Figure 2 The graph shows the results of high-pressure mercury intrusion testing (core pore throat radius-distribution frequency relationship curve).

[0027] Figure 3 The figures show the results of nuclear magnetic resonance testing and high-pressure mercury intrusion testing of the core after it was saturated with water in Example 1.

[0028] Figure 4The graph shows the relationship between T2 relaxation time and pore size in Example 1 (pore throat radius - relaxation time relationship curve).

[0029] Figure 5 The NMR test results are for nanoparticles with a particle size of 20 nm at different displacement stages.

[0030] Figure 6 The NMR results are for different displacement stages of 50 nm nanoparticles. Detailed Implementation

[0031] This invention provides a method for determining the oil displacement effect of nanofluids in low-permeability reservoirs, comprising the following steps:

[0032] Provide core samples from low-permeability reservoirs to determine the particle size of nanoparticles in the target nanofluid;

[0033] High-pressure mercury intrusion testing was performed on the core to obtain the core pore throat radius-distribution frequency relationship curve;

[0034] Nuclear magnetic resonance (NMR) measurements were performed on the wet core sample to obtain the first T2 image;

[0035] The pore throat radius-distribution frequency relationship curve of the core is compared with the first T2 image to obtain the pore throat radius-relaxation time relationship curve; the comparison is to perform linear fitting with the maximum value of the pore throat radius in the core pore throat radius-distribution frequency relationship curve corresponding to the maximum value of the relaxation time in the first T2 image, and the minimum value of the pore throat radius in the core pore throat radius-distribution frequency relationship curve corresponding to the minimum value of the relaxation time in the first T2 image;

[0036] The core was subjected to a displacement experiment, which included sequentially performing oil flooding, first water flooding, nanofluid flooding and second water flooding on the core. After the oil flooding, first water flooding and second water flooding, the core was subjected to nuclear magnetic resonance measurement to obtain a second T2 image, a third T2 image and a fourth T2 image.

[0037] By observing or calculating the areas enclosed by the curves and relaxation times in the second, third, and fourth T2 images, respectively, we 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. Substituting the relaxation time corresponding to the region with the largest absolute value of the difference into the pore throat radius-relaxation time relationship curve, we obtain the corresponding pore throat radius value, that is, the target nanofluid has the best reservoir oil displacement effect for that pore throat radius.

[0038] This invention provides core samples from low-permeability oil reservoirs to determine the particle size of nanoparticles in a target nanofluid.

[0039] In this invention, the core samples taken in each step are from the same target block.

[0040] In this invention, the permeability of the low-permeability reservoir is preferably (10~80)×10⁻⁶. -3 μm 2 It can be (10~20)×10 -3 μm 2 The porosity is preferably 10~25%, and can be 15~24%.

[0041] In this invention, the target nanofluid preferably comprises water and hydrophobic nanoparticles. This invention does not have specific requirements for the hydrophobic nanoparticles; any hydrophobic nanoparticles well-known to those skilled in the art, such as hydrophobically modified nano-SiO2, can be used. In this invention, the particle size of the nanoparticles in the target nanofluid can be determined by dynamic light scattering or Zeta potential.

[0042] This invention involves high-pressure mercury intrusion testing on rock cores to obtain a curve showing the relationship between the pore throat radius and the distribution frequency of the rock core.

[0043] Preferably, the core sample is pretreated before being placed in the core chamber of a mercury intrusion porosimeter for high-pressure mercury intrusion testing to determine the distribution pattern of different pore sizes within the core. The pretreatment method is preferably to sequentially wash the core sample with toluene and then dry it. In this invention, the high-pressure mercury intrusion testing method is preferably:

[0044] Mercury was injected into the pretreated core under different injection pressures. After the pressure stabilized, the injection pressure value and the corresponding mercury injection volume were recorded.

[0045] The injection pressure is equated to the capillary pressure corresponding to the mercury-accessible pore space, and the capillary radius corresponding to the capillary pressure is equated to the core pore throat radius. The mercury saturation-capillary pressure curve is obtained. Then, the distribution frequency corresponding to different pore throat radius ranges is calculated by combining the mercury-accessible volume under different injection pressures, and the core pore throat radius-distribution frequency relationship curve is obtained.

[0046] In this invention, the preferred specific operation of injecting mercury into the pretreated core under different injection pressures is as follows: inject mercury into the pretreated core under a set pressure, record the pressure value and the volume of mercury injected after the pressure stabilizes, increase the injection pressure, and repeat the above operation.

[0047] This invention performs nuclear magnetic resonance (NMR) measurements on wet core samples to obtain a first T2 image.

[0048] In this invention, the preferred method for obtaining wet core samples is to vacuum the core and then saturate it with deionized water. Nuclear magnetic resonance (NMR) measurements require wet samples, as the rock sample skeleton does not generate NMR signals. Therefore, whether core, cuttings, or wellbore cores are taken, sampling must be performed under wet conditions, and the samples should be kept moist before NMR measurements.

[0049] In this invention, the preferred method for nuclear magnetic resonance (NMR) measurement is as follows: the wet sample of the core is placed into a magnetic probe, the resonance frequency is adjusted, a T2 image pulse sequence is selected, system parameters and acquisition parameters are set, and T2 images with different relaxation times (i.e., the first T2 image) are acquired. In this invention, the characteristic images of movable fluids in the core are obtained through NMR measurement.

[0050] After obtaining the core pore throat radius-distribution frequency relationship curve and the first T2 image, the present invention compares the core pore throat radius-distribution frequency relationship curve with the first T2 image to obtain the pore throat radius-relaxation time relationship curve (i.e., the transformation relationship curve between the core pore size distribution and relaxation time).

[0051] In this invention, the benchmarking method is as follows: the maximum value of the pore throat radius in the core pore throat radius-distribution frequency relationship curve corresponds to the maximum value of the relaxation time in the first T2 image, and the minimum value of the pore throat radius in the core pore throat radius-distribution frequency relationship curve corresponds to the minimum value of the relaxation time in the first T2 image, and linear fitting is performed.

[0052] After obtaining the pore throat radius-relaxation time relationship curve, the present invention conducts a displacement experiment on the core. The displacement experiment includes sequentially subjecting the core to oil flooding, first water flooding, nanofluid flooding, and second water flooding. After the oil flooding, first water flooding, and second water flooding, the core is subjected to nuclear magnetic resonance measurements to obtain a second T2 image, a third T2 image, and a fourth T2 image.

[0053] In this invention, the oil flooding is preferably performed by continuously injecting crude oil into the core, stopping the injection when the water flow at the outlet reaches 0. In this invention, the first water flooding involves injecting water into the core after oil flooding, stopping the injection when the water cut at the outlet reaches 98%. In this invention, the nanofluid flooding involves injecting the target nanofluid into the core after the first water flooding, stopping the injection when the water cut at the outlet reaches 99%. In this invention, the second water flooding involves injecting water into the core after injecting the target nanofluid, stopping the injection when the water cut at the outlet reaches 100%. In this invention, the injection rates of the crude oil, the target nanofluid, and the water during the first and second water flooding are preferably 0.1 mL / min.

[0054] In this embodiment of the invention, the specific operation of the displacement experiment is as follows:

[0055] (1) Check the airtightness of the device and perform vacuum treatment on the core;

[0056] (2) Oil flooding (model saturated oil): Crude oil was continuously injected into the model at a rate of 0.1 mL / min until the water output from the model was 0. The total water output during the entire process was recorded. The original oil saturation (above 70%) was estimated from the measured values. The constant temperature chamber was set to 45℃, and the model was placed in it for constant temperature maturation for 3 days (to simulate the real formation environment and the effect of crude oil utilization).

[0057] (3) First water drive: Water is injected at a rate of 0.1 mL / min. The pressure change of the system is recorded in real time, and the oil production and water production at the outlet are recorded. Water drive is stopped when the water cut reaches 98%. The corresponding water drive recovery rate is calculated by measuring the values.

[0058] (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. The pressure change of the system is recorded in real time. When the water content reaches 99%, the injection is stopped, and the oil production and water production at the outlet are recorded. The corresponding total recovery rate is calculated by measuring the values.

[0059] (5) Second water drive: Water is injected at a displacement rate of 0.1 mL / min. After the model end is fully water-bearing, the pressure change of the system is recorded, and the oil production and water production at the outlet are recorded. When the water cut reaches 100%, the injection is stopped, and the corresponding water drive recovery rate is calculated by measuring the values.

[0060] (6) According to the experimental plan, repeat the above operation for different nanofluids and record the required experimental data.

[0061] In this invention, nuclear magnetic resonance (NMR) measurements are performed on the core samples after 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 this invention, NMR measurements can be directly performed on the core samples after oil flooding, the first water flooding, and the second water flooding; the operation method for the NMR measurement is the same as the above-described NMR measurement method and will not be repeated here. In this invention, the NMR measurement obtains the characteristic image of the movable fluid flow in the core sample after nanofluid injection. Because subsequent water flooding (i.e., the second water flooding) after nanofluid injection can further enhance the oil displacement effect of nanofluid flooding, this invention uses the T2 image measured after the second water flooding, i.e., the fourth T2 image, to represent the characteristic image of the movable fluid flow in the core sample after nanofluid injection.

[0062] After obtaining the second, third, and fourth T2 images, the areas enclosed by the curves and relaxation times in the second, third, and fourth T2 images 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 region with the largest 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 reservoir oil displacement effect for this pore throat radius.

[0063] When fluid flows through the pore throats of a rock 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 relaxation time in the T2 image reflects the volume of fluid in the pores, as shown in Equation (1):

[0064] Equation (1),

[0065] In equation (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 an experimental constant.

[0066] In this 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 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 nanoparticles. The calculation of ΔV is shown in equation (2):

[0067] Equation (2),

[0068] In equation (2), V1 is the volume of the first water-driven fluid, V2 is the volume of the second water-driven fluid, S2 is the area enclosed by the second water-driven T2 signal curve and the relaxation time, S1 is the area enclosed by the first water-driven T2 signal curve and the relaxation time, and α is an experimental constant.

[0069] The fluid amplification η can be calculated using equation (3).

[0070] Equation (3).

[0071] Therefore, the larger the absolute value of the difference between the third area and the second area, the better the mobilization effect of the nanofluid on the fluid (i.e., oil) within the pore throat, meaning the better the oil displacement effect of the target nanofluid. If the third T2 image and the fourth T2 image overlap or show little change, it indicates that there is essentially no effect on the fluid within that pore size, meaning the fluid is not mobilized. Substituting the relaxation time corresponding to the region with the largest absolute value of the difference into the pore throat radius-relaxation time relationship curve yields the corresponding pore throat radius value, indicating that the target nanofluid has the best reservoir oil displacement effect for that pore throat radius.

[0072] This invention determines the oil displacement effect of nanofluid based on the microscopic characterization results of core pores and the changes in fluid characteristic distribution after nanofluid injection.

[0073] The method for determining the oil recovery effect of nanofluids in low-permeability reservoirs provided by this invention determines the enhanced oil recovery 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, it combines the results of nuclear magnetic resonance and high-pressure mercury injection tests to clarify the matching relationship between nanoparticles and pore size. This is of great significance for optimizing the enhanced oil recovery effect of nanofluids in low-permeability reservoirs and formulating development plans.

[0074] 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 will be described in detail below with reference to examples, but these should not be construed as limiting the scope of protection of the present invention.

[0075] Example 1

[0076] In this embodiment, a typical core well S in a low-permeability oil reservoir block was selected as the research object. The nanoparticles used in the experiment were hydrophobic modified nano-SiO2 with particle sizes of 20nm and 50nm respectively.

[0077] (1) Obtain initial core characteristic parameters (permeability and porosity), which are used to determine the reservoir type and characterize the reservoir's permeability characteristics;

[0078] The method for obtaining initial core characteristic parameters is as follows: the core is dried and subjected to gas permeability testing to obtain initial values ​​of permeability and porosity. The basic parameters of the core used are shown in Table 1.

[0079] Table 1 Basic parameters of the core

[0080]

[0081] According to bridging theory, nanofluid particles can only migrate within the pore throats of reservoir rocks when the particle size of the injected displacing fluid is ≤1 / 7 of the average pore throat diameter of the reservoir. Calculations show that under these experimental conditions, the nanoparticle size in all experimental schemes satisfies ≤1 / 7 of the average pore throat diameter of the reservoir. Therefore, nanoparticles can migrate within the pore throats during the experiment.

[0082] (2) High-pressure mercury intrusion porosimetry was used to test natural cores from low-permeability reservoirs. The testing method was as follows:

[0083] ① The experimental core rock was washed with toluene and then dried;

[0084] ② Load the core into the core chamber of the mercury intrusion porosimeter, inject mercury at the set pressure, record the pressure value and the volume of mercury injected after the pressure stabilizes, increase the injection pressure, and repeat the above experimental data recording.

[0085] ③ Equivalent the injection pressure to the capillary pressure corresponding to the mercury-accessible pore space, and the capillary radius corresponding to the capillary pressure to the core pore throat radius. By continuously increasing the injection pressure, a capillary pressure curve can be obtained. Combined with the mercury-accessible volume, the distribution frequency corresponding to different pore throat radius ranges can be calculated, and the core pore throat radius-distribution frequency relationship curve can be obtained.

[0086] The results of the high-pressure mercury intrusion test are as follows: Figure 1 and Figure 2 As shown, where, Figure 1 This is a graph showing the results of a high-pressure mercury intrusion test (mercury saturation-capillary pressure curve). Figure 2 This is a graph showing the results of high-pressure mercury intrusion testing (core pore throat radius-distribution frequency relationship curve).

[0087] (3) Obtain the microscopic pore structure of the core of the target block. Based on the results of high-pressure mercury intrusion porosimetry and nuclear magnetic resonance testing of the core, achieve pore size distribution-relaxation time calibration of the core, specifically as follows:

[0088] ① Inject deionized water into the core to saturate it:

[0089] The core was dried in a 65℃ oven for 4 hours. After drying, the core was vacuumed and saturated with deionized water. The specific operation for saturating with deionized water was as follows: the core was loaded into the core holder, the confining pressure was set to 4MPa and kept constant; the temperature chamber was heated to 45℃, 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 end remained constant.

[0090] ② Perform nuclear magnetic resonance (NMR) testing on the core sample in a saturated water state to obtain the T2 spectrum of the core sample in the saturated state; specifically, NMR measurement requires wet sample measurement, as the rock sample skeleton does not generate NMR signals. Therefore, whether it is core, cuttings, or wellbore core sampling, sampling is required under wet conditions, and the rock sample should be moistened before NMR measurement after extraction; Perform NMR measurement on the core sample after saturation with deionized water in ① to obtain a mobile fluid image: Place the prepared core sample after saturation 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;

[0091] ③ The distribution of pore throat radius obtained from high-pressure mercury intrusion testing and the T2 image obtained from nuclear magnetic resonance testing (e.g.) Figure 3 (as shown) 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, with 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 relaxation time in the T2 image is linearly fitted to obtain the corresponding T2 relaxation time and pore throat distribution relationship, i.e., the pore throat radius-relaxation time relationship curve, as shown in the figure. Figure 4 As shown.

[0092] (4) Using a 0.1 wt% hydrophobically modified nano-SiO2 aqueous solution as the nanofluid, displacement experiments were conducted on core samples to obtain the ability of the nanofluid to enhance oil recovery in low-permeability / ultra-low-permeability cores, i.e., the oil displacement effect. The steps are as follows (the experiment was conducted in a 45℃ constant temperature chamber):

[0093] ① Check the airtightness of the device and perform vacuum treatment on the core;

[0094] ② Saturated oil flooding (model saturated oil): Crude oil is continuously injected into the model at a rate of 0.1 mL / min until the water output from the model reaches 0. The total water output during the entire process is recorded. The original oil saturation (above 70%) is estimated from the measured values. The constant temperature chamber is set to 45℃, and the model is placed in it for constant temperature maturation for 3 days.

[0095] ③ First water drive: Water is injected at a rate of 0.1 mL / min, and the pressure change of the system is recorded in real time. The oil production and water production at the outlet are also recorded. Water drive is stopped when the water cut reaches 98%. The corresponding water drive recovery rate is calculated from the measured values.

[0096] ④ Nanofluid flooding: When the water cut of the water flooding system is greater than 98%, the nanofluid flooding system is injected at a displacement rate of 0.1 mL / min. The pressure change of the system is recorded in real time. When the water cut reaches 99%, the injection is stopped, and the oil production and water production at the outlet are recorded. The corresponding total recovery rate is calculated from the measured values.

[0097] ⑤ Second water drive: Water is injected at a displacement rate of 0.1 mL / min. After the model end is fully water-bearing, the pressure change of the system is recorded, as well as the oil production and water production at the outlet. When the water cut reaches 100%, the injection is stopped, and the corresponding water drive recovery rate is calculated from the measured values.

[0098] Nuclear magnetic resonance measurements were performed on the core samples after saturated oil flooding, first water flooding, and second water flooding to obtain the corresponding T2 images.

[0099] By comparing the T2 images measured by nuclear magnetic resonance before and after nanofluid injection, the distribution of fluid in the pore volume can be obtained, thus revealing the mobilization of residual oil by nanoparticles within different pore sizes. Experimental results are as follows: Figure 5 and Figure 6 As shown, Figure 5 The NMR results are for different displacement stages of nanoparticles with a particle size of 20 nm. Figure 6 The NMR results are for different displacement stages of 50 nm nanoparticles. Figure 5 and Figure 6 In the text, the T2 image corresponding to "nanofluid flooding" is the T2 image measured after the second water flooding, meaning that 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 rates were 41.3% and 40.8%, respectively.

[0100] The area enclosed by the nuclear magnetic resonance (NMR) test results of the fluid core before and after nanoparticle injection represents the increase in fluid volume within the pores after the nanofluid's action. Combining the pore throat radius-relaxation time relationship curve determined in (3), the fluid mobilization effect of nanofluid injection on pores of different sizes can be obtained through the correspondence between T2 relaxation time and pore throat size. Specifically, substituting the relaxation time corresponding to the region with the largest absolute value of the difference between the curve and the relaxation time in the T2 images obtained before and after nanoparticle injection into the pore throat radius-relaxation time relationship curve yields the corresponding pore throat radius value, indicating that the nanofluid has the best reservoir displacement effect for this pore throat radius.

[0101] The enhanced oil recovery (EOR) effects of nanoparticles of different sizes were similar, all around 40%. However, the NMR results for 20 nm and 50 nm nanoparticles were significant. With 20 nm nanoparticles, the mobilization of remaining oil was mainly improved within the 3–6 ms relaxation time range, i.e., pore sizes of 100–200 nm. For 50 nm nanoparticles, fluid mobilization was mainly concentrated within the 7–15 ms relaxation time range, i.e., mobilization of remaining oil within the pore throat range of 250–500 nm. The results indicate that the ratio of nanoparticles to pore radius of 20–40% yields the best effect on mobilizing remaining oil in nanopores.

[0102] The above description is merely a preferred embodiment of the present invention and is not intended to limit the present invention in any way. It should be noted that those skilled in the art can make various improvements and modifications without departing from the principles of the present invention, and these improvements and modifications should 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, Includes the following steps: Provide core samples from low-permeability reservoirs to determine the particle size of nanoparticles in the target nanofluid; High-pressure mercury intrusion testing was performed on the core to obtain the core pore throat radius-distribution frequency relationship curve; Nuclear magnetic resonance (NMR) measurements were performed on the wet core sample to obtain the first T2 image; The pore throat radius-distribution frequency relationship curve of the core is compared with the first T2 image to obtain the pore throat radius-relaxation time relationship curve; the comparison is to perform linear fitting with the maximum value of the pore throat radius in the core pore throat radius-distribution frequency relationship curve corresponding to the maximum value of the relaxation time in the first T2 image, and the minimum value of the pore throat radius in the core pore throat radius-distribution frequency relationship curve corresponding to the minimum value of the relaxation time in the first T2 image; The core was subjected to a displacement experiment, which included sequentially performing oil flooding, first water flooding, nanofluid flooding and second water flooding on the core. After the oil flooding, first water flooding and second water flooding, the core was subjected to nuclear magnetic resonance measurement to obtain a second T2 image, a third T2 image and a fourth T2 image. By observing or calculating the areas enclosed by the curves and relaxation times in the second, third, and fourth T2 images, respectively, we 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. Substituting the relaxation time corresponding to the region with the largest absolute value of the difference into the pore throat radius-relaxation time relationship curve, we obtain the corresponding pore throat radius value, that is, the target nanofluid has the best reservoir oil displacement effect for that 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 comprises water and hydrophobic nanoparticles.

4. The method according to claim 1, characterized in that, The method for performing high-pressure mercury intrusion testing on the core sample is as follows: Mercury was injected into the core under different injection pressures, and the injection pressure value and the corresponding mercury volume were recorded after the pressure stabilized. The injection pressure is equated to the capillary pressure corresponding to the mercury-accessible pore space, and the capillary radius corresponding to the capillary pressure is equated to the core pore throat radius. The mercury saturation-capillary pressure curve is obtained. Then, the distribution frequency corresponding to different pore throat radius ranges is calculated by combining the mercury-accessible volume under different injection pressures, and the core pore throat radius-distribution frequency relationship curve is obtained.

5. The method according to claim 1, characterized in that, The method for obtaining wet samples of the core is as follows: the core is vacuumed and then saturated with deionized water.

6. The method according to claim 1, characterized in that, The oil flooding process involves continuously injecting crude oil into the core and stopping the injection when the water flow at the outlet reaches zero.

7. The method according to claim 1, characterized in that, The first water drive involves injecting water into the core after oil flooding, and stopping the injection when the water cut at the outlet reaches 98%.

8. The method according to claim 1, characterized in that, The nanofluid drive involves injecting the target nanofluid into the core after the first water flood, and stopping the injection when the water content at the outlet reaches 99%.

9. The method according to claim 1, characterized in that, The second water drive involves injecting water into the core into which the target nanofluid is injected, and stopping the injection 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.

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