A physical simulation method for post-fracturing flowback of tight oil reservoirs

Abstract

The present invention discloses a physical simulation method for post - fracturing flow - back of tight oil reservoirs. The oil - water two - phase seepage area formed during the shut - in process after fracturing of tight oil reservoirs is divided into a filtration loss area and an imbibition area. On this basis, a filtration loss core and an imbibition core are respectively constructed. Then, the two cores are connected in series to carry out an oil - displacing water experiment to simulate the post - fracturing flow - back process. With the help of nuclear magnetic resonance on - line monitoring technology, the quantitative characterization of the oil - water distribution characteristics in the pores of the imbibition core and the filtration loss core is realized. The present invention effectively simulates the entire physical process from shut - in to flow - back. The experimental results obtained by using this method can analyze the microscopic oil - water distribution law in the pores of the core during the flow - back process and optimize the flow - back pressure.

Description

Technical Field

[0001] The present invention relates to the technical field of enhanced oil recovery in tight oil reservoirs, and specifically relates to a physical simulation method for post-fracturing flowback in tight oil reservoirs. Background Art

[0002] China is rich in tight oil resources, which are widely distributed in the Junggar Basin, Ordos Basin, Sichuan Basin, Songliao Basin, etc. The tight oil resources in the main basins are 80 - 10 billion tons, making them important replacement resources. Large-scale fracturing has become an important means of enhancing production and transformation for such reservoirs, that is, adopting large-scale horizontal well staged fracturing transformation technology to "inject millions of cubic meters of water" and then "break the reservoir" to form a complex fracture network, shortening the seepage distance between fractures and the matrix to achieve the effect of enhanced production and transformation. After that, the well is shut in for a period of time, and the fracturing fluid is not directly flowed back. Instead, the amount of retained fracturing fluid is increased, and through the imbibition effect, the crude oil in the matrix is displaced and enters the fractures. Finally, the fracturing fluid is flowed back, and the flowback process will directly affect the production enhancement effect.

[0003] At present, there is relatively little research on the flowback law after fracturing of unconventional reservoirs at home and abroad. Most are based on statistical analysis results, and only single influencing factors are considered. In addition, referring to the contradictory relationship between the production and flowback rate after multi-stage fracturing in shale gas reservoirs, it is found that: (1) The more developed the natural fractures are, the more complex the fracture network formed after fracturing is, the lower the flowback rate of gas wells is, and the higher the gas production is; (2) The stronger the capillary imbibition effect of the reservoir shale is, the lower the flowback rate of gas wells is, and the higher the single-well productivity is. Therefore, it is recommended not to blindly pursue a high flowback rate. The main reason for this phenomenon is the unclear understanding of the flowback system. Therefore, it is necessary to study the flowback law after fracturing of tight oil reservoirs to guide the optimization of flowback parameters.

[0004] During the process of horizontal well staged fracturing transformation, a large amount of fracturing fluid needs to be injected. After the pump is stopped, a large amount of fracturing fluid enters the matrix from the fractures through the filtration effect, forming a two-phase seepage zone, namely a two-phase seepage zone dominated by the filtration effect (pressure difference effect) and accompanied by the imbibition effect (capillary force effect) and a two-phase seepage zone dominated by the imbibition effect (as Figure 2 shown). Correspondingly, according to the curve of the bottom-hole pressure changing with time (as Figure 3 shown), the shut-in process can be divided into a pressure decreasing stage dominated by the filtration effect and accompanied by the imbibition effect (i.e., the imbibition filtration stage) and a pressure stable stage dominated by the imbibition effect (i.e., the pressure-bearing imbibition stage). To study the flowback law after fracturing, it is necessary to comprehensively consider the oil-water displacement process occurring in the filtration zone and the pressure-bearing imbibition zone. However, in the existing research on the flowback law, whether it is numerical simulation or physical simulation, the influence caused by the shut-in process is not considered, especially the lack of a physical simulation experimental method for flowback after fracturing that can simulate the shut-in process at the core scale. Summary of the Invention

[0005] The present invention provides a physical simulation method for the post - fracturing flow - back of tight oil reservoirs in order to understand the post - fracturing flow - back law of tight oil reservoirs. This physical simulation method comprehensively considers the well - shut - in process after fracturing (including two stages of filtration and imbibition), and is at the core - scale. With the help of low - field nuclear magnetic resonance online monitoring technology, it analyzes the microscopic oil - water distribution law in the pores of tight sandstone cores during the flow - back process and the reasons for fracturing fluid retention, and optimizes the flow - back pressure.

[0006] In order to achieve the above - mentioned objectives, the present invention adopts the following technical solutions:

[0007] A physical simulation method for the post - fracturing flow - back of tight oil reservoirs includes the following steps:

[0008] Calibrate the nuclear magnetic resonance signal using aviation kerosene samples to establish the relationship between the cumulative signal amplitude of the T2 spectrum and the mass of kerosene.

[0009] Take two tight sandstone plug samples for oil - washing and drying, and then conduct vacuum - pumping and pressure - saturated oil, and test the T2 spectrum of the core samples after saturated oil.

[0010] Conduct a constant - pressure water - flooding experiment on one of the core samples after saturated oil, measure the T2 spectrum of the core sample at regular intervals, and construct a filtration core.

[0011] Conduct a pressure - maintained imbibition experiment on the other core sample after saturated oil, measure the T2 spectrum of the core sample at regular intervals, and construct an imbibition core.

[0012] Connect the filtration core and the imbibition core in series and conduct a constant - pressure oil - flooding experiment to simulate the flow - back process; measure the total T2 spectrum of the series - connected cores at regular intervals, and at the same time measure the T2 spectra of the filtration core and the imbibition core respectively, and calculate the flow - back rate.

[0013] The present invention comprehensively considers the oil - water distribution characteristics in the filtration zone and the imbibition zone during the well - shut - in process after fracturing, effectively simulates the entire physical process of tight oil reservoirs from well - shut - in after fracturing to flow - back, and with the help of nuclear magnetic resonance technology, quantitatively characterizes the oil - water distribution law in the pores of tight cores in different regions during the flow - back process, and optimizes the flow - back pressure. The experimental results obtained by using the physical simulation method of the present invention can enhance the understanding of the physical process of the post - fracturing flow - back of tight oil reservoirs, explain the reasons for fracturing fluid retention, and provide a theoretical basis for optimizing the flow - back pressure, and can be popularized and applied in the field of improving oil recovery by fracturing and reforming unconventional reservoirs.

[0014] According to the physical simulation method of the present invention, preferably, the step of calculating the flow - back rate includes calculating the flow - back rates of the filtration core and the imbibition core respectively after flow - back, and calculating the total flow - back rate of the filtration core and the imbibition core after flow - back;

[0015] The flow - back rate is calculated by the following formula:

[0016]

[0017] wherein, R represents the backflow rate, %; ΣA 返排前 , ΣA 返排后 and ΣA 饱和油 respectively represent the cumulative signal amplitudes of the T2 spectrum measured before and after backflow and in the saturated oil state, a.u.

[0018] The fluid-loss core and the imbibition core are connected in series, and a constant-pressure oil displacement experiment is carried out to simulate the backflow process; the total T2 spectrum of the series-connected cores is measured at regular intervals, and the T2 spectra of the fluid-loss core and the imbibition core are measured respectively at the same time, and the backflow rate is calculated. In this step, the T2 spectra of the fluid-loss core and the imbibition core are measured respectively at regular intervals by taking out the cores and measuring the T2 spectra separately, and then the two cores are connected in series and the experiment continues. When calculating the total backflow rate of the fluid-loss core and the imbibition core after backflow, the total T2 spectrum of the series-connected cores measured is used.

[0019] According to the physical simulation method of the present invention, preferably, after the fluid-loss core undergoes a constant-pressure water flooding experiment and the imbibition core undergoes a pressure-assisted imbibition experiment, the oil-phase distribution ratio in the pores of each core is obtained from the respective T2 spectra in combination with the relationship between the cumulative signal amplitude of the T2 spectrum and the mass of kerosene; and then the water saturation of the fluid-loss core and the imbibition core is calculated respectively, which is the water saturation before backflow for each of them.

[0020] The water saturation is the volume of water in the pores of the core divided by the total pore volume. In this experiment, the total pore volume is calculated from the amount of oil measured by nuclear magnetic resonance (obtained by combining the relationship between the cumulative signal amplitude of the T2 spectrum and the mass of kerosene), and the water volume is the total volume minus the volume of the displaced oil (i.e., the difference between the nuclear magnetic resonance signal amplitude of the saturated oil sample and the nuclear magnetic resonance signal amplitude measured during the displacement or imbibition experiment).

[0021] According to the physical simulation method of the present invention, preferably, in the step of calibrating the nuclear magnetic resonance signal using an aviation kerosene sample, the aviation kerosene sample is contained in a chromatographic bottle without hydrogen proton signals.

[0022] According to the physical simulation method of the present invention, preferably, the two tight sandstone plug samples are taken from the same horizon and have similar physical properties.

[0023] According to the physical simulation method of the present invention, preferably, in the constant-pressure water flooding experiment, a 2% KCl deuterated aqueous solution without hydrogen proton signals is continuously injected into the inlet end of the core sample after saturation with a constant pressure, the outlet pressure is atmospheric pressure, the T2 spectrum of the core sample is measured at regular intervals, and the corresponding water saturation of the core is calculated until water appears at the outlet end, and the displacement experiment is stopped.

[0024] According to the physical simulation method of the present invention, preferably, the pressure - assisted imbibition experiment is carried out using a pressure - assisted imbibition experimental device. The core sample saturated with oil and 2% KCl deuterium aqueous solution without hydrogen proton signal are simultaneously placed in a piston - type intermediate container. Distilled water is continuously injected into the bottom of the intermediate container until a set pressure value is reached, and the pressure in the intermediate container is kept constant. The T2 spectrum of the core sample is measured at regular intervals until the reduction amount of the cumulative signal amplitude of the T2 spectrum is less than 3%, and then the pressure - assisted imbibition experiment is stopped.

[0025] According to the physical simulation method of the present invention, preferably, when the filtrate - loss core and the imbibition core are connected in series, the imbibition core is close to the inlet end.

[0026] According to the physical simulation method of the present invention, preferably, in the constant - pressure oil - displacing - water experiment, aviation kerosene is continuously injected at a constant pressure at the inlet end, and the outlet pressure is atmospheric pressure.

[0027] According to the physical simulation method of the present invention, preferably, the constant pressure at the inlet end in the constant - pressure oil - displacing - water experiment is changed to different pressure values, and the constant - pressure oil - displacing - water experiment is repeated to obtain the flow - back rates under different flow - back pressures, so as to optimize the flow - back pressure.

[0028] According to the physical simulation method of the present invention, preferably, the constant - pressure water - displacing - oil experiment, the pressure - assisted imbibition experiment and the constant - pressure oil - displacing - water experiment are all completed in a high - temperature and high - pressure displacement - nuclear magnetic resonance scanning integrated experimental device.

[0029] With the aid of a high - temperature and high - pressure displacement - nuclear magnetic resonance scanning integrated experimental device, the present invention accurately describes the distribution law of fluids in pores. The signal measured by nuclear magnetic resonance is the superposition of hydrogen - nucleus signals in pores. The signal intensity is mainly related to the number of hydrogen nuclei in rock pores, reflecting the porosity information of the rock. The measured nuclear magnetic resonance signal can be mathematically fitted to obtain the nuclear magnetic resonance T2 spectrum, which reflects the fluid distribution inside the core. In a uniformly distributed magnetic field, without considering the influence of diffusion relaxation and free relaxation (which can be ignored compared with the influence of surface relaxation), the following relationship can be established between the transverse relaxation time T2 and the pore radius:

[0030]

[0031] In the formula, T2 is the relaxation time, ms; ρ is the surface relaxation rate, μm / s; S is the surface area of the core, cm 2 ; V is the pore volume, cm 3 ; R is the pore radius, cm; C is a constant. C = 1, 2, 3 are used for the flat - plate model, capillary - bundle model and spherical model respectively. Here, the capillary - bundle model is selected, that is, C = 2. At the same time, it can be seen that the transverse relaxation time T2 is positively correlated with the pore radius, that is, the larger the pore radius, the longer the transverse relaxation time.

[0032] The beneficial effects of the present invention include:

[0033] The present invention innovatively divides the oil-water two-phase seepage zone formed during the soaking period after fracturing of a tight oil reservoir into a filtration loss zone and an imbibition zone; on this basis, a filtration loss core and an imbibition core are respectively constructed, and by conducting a constant-pressure oil displacement experiment on the series-connected cores, the backflow process after fracturing is effectively simulated. The experimental results obtained using this method can analyze the microscopic oil-water distribution law in the core pores during the backflow process and optimize the backflow pressure. Description of the Drawings

[0034] Figure 1 It is a flowchart of the physical simulation method for post-fracture backflow of a tight oil reservoir in an embodiment of the present invention.

[0035] Figure 2 It is a schematic diagram of the two-phase seepage region during the soaking period after fracturing.

[0036] Figure 3 It is a schematic diagram of the bottom-hole pressure change.

[0037] Figure 4 It is the calibration result of the kerosene mass and the nuclear magnetic resonance signal in an embodiment of the present invention.

[0038] Figure 5 It is a schematic diagram of the high-temperature and high-pressure displacement - nuclear magnetic resonance scanning integrated experimental device in an embodiment of the present invention.

[0039] Figure 6a It is the T2 spectrum of core sample A11 before backflow in an embodiment of the present invention.

[0040] Figure 6b It is the oil-phase distribution ratio diagram of core sample A11 before backflow in an embodiment of the present invention.

[0041] Figure 7 It is a schematic diagram of the pressure-assisted imbibition experimental device in an embodiment of the present invention.

[0042] Figure 8a It is the T2 spectrum of core sample B11 before backflow in an embodiment of the present invention.

[0043] Figure 8b It is the oil-phase distribution ratio diagram of core sample B11 before backflow in an embodiment of the present invention.

[0044] Figure 9a It is the T2 spectrum of the series-connected backflow of core samples A11 and B11 in an embodiment of the present invention.

[0045] Figure 9b It is the oil-phase distribution ratio diagram of the series-connected backflow of core samples A11 and B11 in an embodiment of the present invention.

[0046] Figure 10aThis is the T2 spectrum diagram of core sample A11 after backflow in the embodiment of the present invention.

[0047] Figure 10b This is the oil phase distribution ratio diagram of core sample A11 after backflow in the embodiment of the present invention.

[0048] Figure 11a This is the T2 spectrum diagram of core sample B11 after backflow in the embodiment of the present invention.

[0049] Figure 11b This is the oil phase distribution ratio diagram of core sample B11 after backflow in the embodiment of the present invention.

[0050] Figure 12 This is the relationship curve between the backflow rate and the backflow pressure in the embodiment of the present invention.

[0051] Explanation of reference numerals:

[0052] 1 - air compressor, 2 - ISCO pump, 3 - intermediate container, 4 - core holder, 5 - back pressure pump, 6 - low-field nuclear magnetic resonance real-time monitoring device, 7 - confining pressure pump, 8 - back pressure valve, 91 / 92 / 93 / 94 - pressure gauge, 10 - precision electronic balance, 11 - data acquisition system, 12 - pneumatic valve, 13 - piston container, 14 - first chamber, 15 - second chamber, 16 - core sample. Detailed implementation manners

[0053] To more clearly illustrate the present invention, the present invention will be further described below in conjunction with preferred embodiments. Those skilled in the art should understand that the content specifically described below is illustrative rather than restrictive, and should not be used to limit the protection scope of the present invention.

[0054] In the present invention, the principle is as follows: the oil-water two-phase seepage zone formed during the shut-in process after fracturing of the tight oil reservoir is divided into a filtration loss zone and an imbibition zone; on this basis, a filtration loss core and an imbibition core are respectively constructed; then, the two cores are connected in series to carry out an oil displacement experiment to simulate the backflow process after fracturing. With the help of nuclear magnetic resonance online monitoring technology, the quantitative characterization of the oil-water distribution characteristics in the pores of the imbibition core and the filtration loss core is realized. The present invention effectively simulates the entire physical process from shut-in to backflow, and the experimental results obtained by using this method can analyze the microscopic oil-water distribution law in the pores of the core during the backflow process and optimize the backflow pressure.

[0055] As Figure 1 shown, the embodiment of the present invention provides a physical simulation method for backflow after fracturing of a tight oil reservoir, and the method includes:

[0056] S101: Calibrate the nuclear magnetic resonance signal by filling a chromatographic vial without hydrogen proton signal with a certain mass of aviation kerosene sample, and establish the conversion relationship between the cumulative signal amplitude of the T2 spectrum (representing the cumulative integral area of the T2 spectrum) of nuclear magnetic resonance test and the kerosene mass.

[0057] S102: Select two tight sandstone plug samples from the same horizon with similar physical properties. After washing with oil and drying, evacuate and pressurize to saturate with oil, and use a high-temperature and high-pressure displacement - nuclear magnetic resonance scanning integrated experimental device to test the T2 spectrum of the saturated oil core sample.

[0058] S103: Construct a filtrate loss core: Select a saturated oil core sample and place it in a high-temperature and high-pressure displacement - nuclear magnetic resonance scanning integrated experimental device. Continuously inject aviation kerosene at a constant pressure at the inlet end, with the outlet pressure being atmospheric pressure. Measure the T2 spectrum of the core sample at regular intervals, calculate the corresponding water saturation of the core, and stop the displacement experiment until water appears at the outlet end.

[0059] S104: Construct an imbibition core: Select a saturated oil core sample and place it in a piston-type intermediate container together with deuterium water. Continuously inject distilled water at the bottom of the intermediate container until the set pressure value is reached, keep the pressure in the intermediate container constant, measure the T2 spectrum of the core sample at regular intervals until the reduction amount of the cumulative signal amplitude of the T2 spectrum is less than 3%, and stop the pressure-bearing imbibition experiment.

[0060] S105: Connect the filtrate loss core and the imbibition core in series, with the imbibition core close to the inlet end. Continuously inject aviation kerosene at a constant pressure at the inlet end, with the outlet pressure being atmospheric pressure. Measure the T2 spectrum of the series-connected cores at regular intervals. At the same time, measure the T2 spectra of the filtrate loss core and the imbibition core, and calculate the backflow rate.

[0061] Figure 5 FIG. is a schematic diagram of the high-temperature and high-pressure displacement - nuclear magnetic resonance scanning integrated experimental device in the embodiment of the present invention, including an air compressor 1, an ISCO pump 2, an intermediate container 3, a core holder 4, and a back pressure pump 5 connected in sequence; the core holder 4 is placed in a low-field nuclear magnetic resonance real-time monitoring device 6. The core holder 4 is also provided with an confining pressure pump 7. A back pressure valve 8 and a pressure gauge 93 are arranged on the pipeline connecting the core holder 4 and the back pressure pump 5, and a precision electronic balance 10 is connected in parallel, and is signal-connected to a data acquisition system 11. A pneumatic valve 12 is arranged between the air compressor 1 and the ISCO pump 2, a pressure gauge 92 is arranged on the pipeline between the intermediate container 3 and the core holder 4, and a pressure gauge 91 is arranged on the pipeline between the core holder 4 and the confining pressure pump 7.

[0062] Figure 7Schematic diagram of the pressure - assisted imbibition experimental device in the embodiments of the present invention, including an air compressor 1, an ISCO pump 2, and a piston container 13 connected in sequence; the piston in the piston container 13 divides its chamber into a first chamber 14 and a second chamber 15. The first chamber 14 is connected to the ISCO pump 2, and the core sample 16 is placed in the second chamber 15. A pressure gauge 94 is connected outside the second chamber 15, and a pneumatic valve 12 is arranged between the air compressor 1 and the ISCO pump 2. Specific embodiment

[0064] Using the method of the present invention, tight sandstone samples from the Yuan 284 block of the Chang 6 formation in the Huaqing Oilfield of the Ordos Basin are selected for physical simulation experiments of post - fracturing flow - back, to analyze the microscopic oil - water distribution law in pores and optimize the flow - back pressure.

[0065] 1) Select two tight sandstone samples from the Yuan 284 block of the Chang 6 formation in the Huaqing Oilfield of the Ordos Basin. The coring depth is 2070.50 - 2070.90 m. The main mineral components are quartz (29.1%), feldspar (45.6%), dolomite (10.7%), and clay minerals (13.1%). Among them, the types of clay minerals are mainly chlorite (48.5%) and illite - smectite mixed layer (39.3%), and the content of illite (12.2%) is relatively low.

[0066] 2) Use a chromatographic vial without hydrogen proton signal to fill with a certain mass of aviation kerosene sample to calibrate the nuclear magnetic signal, and establish the conversion relationship between the cumulative signal amplitude (ΣA i , that is, representing the cumulative integral area of the T2 spectrum) of the T2 spectrum measured by nuclear magnetic resonance and the mass (m) of kerosene, as shown in Figure 4 shown.

[0067] 3) After washing the two cores (using the solvent extraction method of toluene and ethanol for 30 days) and drying (in a sealed oven at 105 °C for 2 days), perform vacuum pumping and pressure - assisted oil saturation, and use a MacroMR12 - 150H - I low - field nuclear magnetic resonance analyzer to measure the T2 spectrum of the oil - saturated core samples.

[0068] 4) Construct a filter - loss core:

[0069] Place one of the oil - saturated core samples in a high - temperature and high - pressure displacement - nuclear magnetic resonance scanning integrated experimental device (such as Figure 5In the core holder of the device shown, the confining pressure was increased to 2 MPa; at the inlet end, a 2% KCl deuterium aqueous solution without hydrogen proton signal was continuously injected at a constant flow rate of 0.02 mL / min for evacuation to ensure that there was no air in the pipeline until the inlet pressure reached 1 MPa and the outlet pressure was atmospheric pressure, and then constant pressure displacement at 1 MPa was maintained; the confining pressure adopted a pressure tracking mode, always keeping the confining pressure 2 MPa higher than the inlet pressure; the nuclear magnetic signal was monitored every 30 - 60 min until water appeared at the outlet end of the core and displacement continued, and the oil phase distribution result in the pores before backflow of the filtrate loss core was determined according to the measured T2 spectrum (as Figure 6a shown) (as Figure 6b shown).

[0070] It can be seen that after 12 hours of displacement, in the pore size ranges of 100 - 100 ms, 10 - 100 ms, 1 - 10 ms, and 0.1 - 1 ms, the mass fractions of the oil phase decreased by 7.32%, 17.97%, 18.22%, and 6.13% respectively, and the water saturation before backflow of the filtrate loss core was 46.29%.

[0071] 5) Construct the imbibition core:

[0072] Another oil-saturated core sample and 100 mL of 2% KCl deuterium aqueous solution without hydrogen proton signal were placed in a piston-type intermediate container (as Figure 7 shown). The upstream and downstream valves of the intermediate container were opened, and then distilled water was continuously injected into the bottom of the intermediate container at a constant flow rate of 10 mL / min through an ISCO high-pressure and high-precision piston pump until liquid flowed out from the two-way valve upstream; the two-way valve upstream was closed, and the ISCO high-pressure and high-precision piston pump was switched to the constant pressure working mode to keep the pressure in the intermediate container at 5 MPa; the core sample was taken out at the set moment, and after drying the surface of the core with cotton yarn, the T2 spectrum of the core sample was measured (as Figure 8a shown) until the reduction amount of the cumulative integral area of the T2 spectrum was less than 3%, and the pressure-assisted imbibition experiment was stopped to obtain the oil phase distribution result in the pores before backflow of the imbibition core (as Figure 8b shown).

[0073] It can be seen that for core sample B11, in the pore size ranges of 100 - 100 ms, 10 - 100 ms, 1 - 10 ms, and 0.1 - 1 ms, the mass fractions of the oil phase decreased by 3.47%, 11.94%, 19.38%, and 0.39% respectively, and the water saturation before backflow of the imbibition core was 45.20%.

[0074] 6) Connect the filtrate loss core and the imbibition core in series, with the imbibition core near the inlet end; continuously inject aviation kerosene at a constant flow rate of 0.02 mL / min at the inlet end for evacuation to ensure there is no air in the pipeline, and the outlet end pressure is atmospheric pressure; the confining pressure adopts a pressure tracking mode, always keeping the confining pressure 2 MPa higher than the inlet pressure. After complete evacuation, displace at a constant pressure of 1 MPa at the inlet end; measure the total nuclear magnetic T2 spectrum of the series-connected cores every 30 - 60 minutes (as shown in Figure 9a ), as well as the individual T2 spectra of the imbibition core and the filtrate loss core (as shown in Figure 10a , Figure 11a ); finally, obtain the oil phase distribution results in the pores of the series-connected cores after flowback (as shown in Figure 9b ), as well as the individual oil phase distribution results of the imbibition core and the filtrate loss core (as shown in Figure 10b , Figure 11b ), and calculate the corresponding water saturation and flowback rate according to the following formula:

[0075]

[0076] In the formula, R represents the flowback rate, %; ΣA 返排前 , ΣA 返排后 and ΣA 饱和油 represent the cumulative signal amplitudes of the T2 spectra measured before and after flowback and in the oil-saturated state, respectively, in a.u.

[0077] It can be seen that after 24 hours of flowback, obvious differences in the T2 spectrum only appear in the imbibition core. The flowback rate of the core in the filtrate loss part (20.37%) is lower than that of the core in the imbibition part (26.46%). Obvious differences in the T2 spectrum only appear in the imbibition core. In addition, due to its poor physical properties and slow pressure conduction, the flowback effect of the filtrate loss core is weaker than that of the imbibition core. And during the entire flowback process, since the tight sandstone core is water-wet, capillary force becomes a resistance during flowback. Therefore, the change range of the T2 spectrum is mainly from 10 - 1000 ms, and there is almost no obvious change in the pore space from 1 - 10 ms. And within the pore scale ranges of 100 - 100 ms, 10 - 100 ms, 1 - 10 ms, and 0.1 - 1 ms, the overall oil phase mass fractions of the series-connected cores increase by 1.50%, 2.52%, and 1.51% respectively. The overall water saturation rises by 9.25%, and the flowback rate is 20.61%.

[0078] 7) Increase the displacement pressures in step 6) to 2 MPa, 4 MPa, and 6 MPa respectively, and repeat step 6) to obtain the flowback rates under different flowback pressures (as shown in Figure 12 ).

[0079] It can be seen that as the backflow pressure increases, the backflow rate gradually increases and then tends to be stable, and the critical backflow pressure is 4 MPa.

[0080] This method effectively simulates the post-fracture backflow process, and the experimental results obtained can analyze the distribution law of oil and water in the core pores during the backflow process, rather than optimizing the backflow pressure.

[0081] The present invention innovatively divides the oil-water two-phase seepage zone formed during the shut-in process after fracturing of tight oil reservoirs into a filtration loss zone and an imbibition zone. On this basis, a filtration loss core and an imbibition core are respectively constructed, and through the constant-pressure oil displacement experiment on the series-connected cores, the post-fracture backflow process is effectively simulated. The experimental results obtained by using this method can analyze the microscopic oil-water distribution law in the core pores during the backflow process and optimize the backflow pressure.

[0082] Obviously, the above-mentioned embodiments of the present invention are merely examples for clearly explaining the present invention, rather than limiting the implementation manners of the present invention. For those of ordinary skill in the art, other different forms of changes or modifications can be made on the basis of the above description. It is impossible to list all the implementation manners here. Any obvious changes or modifications derived from the technical solutions of the present invention are still within the protection scope of the present invention.

Claims

1. A physical simulation method for post-fracture flowback of tight oil reservoirs, characterized in that, The physical simulation method includes the following steps: Calibrate the nuclear magnetic signal using an aviation kerosene sample, and establish the relationship between the cumulative signal amplitude of the T2 spectrum and the kerosene mass; Take two dense sandstone plug samples for oil washing and drying, then perform vacuum pumping and pressurized oil saturation, and test the T2 spectrum of the core samples after oil saturation; Conduct a constant-pressure water flooding experiment on one of the core samples after oil saturation, measure the T2 spectrum of the core sample at regular intervals, and construct a filtrate loss core; Carry out a pressure-infiltration experiment on the other core sample after oil saturation, measure the T2 spectrum of the core sample at regular intervals, and construct an infiltration core; Connect the filtrate loss core and the infiltration core in series, and conduct a constant-pressure oil flooding experiment to simulate the backflow process; measure the total T2 spectrum of the series-connected cores at regular intervals, and at the same time measure the T2 spectra of the filtrate loss core and the infiltration core respectively, and calculate the backflow rate; The steps of calculating the backflow rate include calculating the backflow rates of the filtrate loss core and the infiltration core respectively after backflow, and calculating the total backflow rate of the filtrate loss core and the infiltration core after backflow; The backflow rate is calculated by the following formula: where R represents the flowback rate, %; ΣA 返排前， ΣA 返排后 and ΣA 饱和油 respectively represent the cumulative signal amplitudes of the T2 spectrum measured before and after flowback and in the saturated oil state, a.u.

2. The physical simulation method according to claim 1, wherein After the constant-pressure water flooding experiment on the filtrate loss core and the pressure-infiltration experiment on the infiltration core, the oil phase distribution ratio in the pores of each core is obtained from the respective T2 spectra in combination with the relationship between the cumulative signal amplitude of the T2 spectrum and the kerosene mass; furthermore, calculate the water saturation of the filtrate loss core and the infiltration core respectively, which is the water saturation before backflow.

3. The physical simulation method according to claim 1, characterized in that, In the step of calibrating the nuclear magnetic signal using an aviation kerosene sample, the aviation kerosene sample is contained in a chromatographic bottle without hydrogen proton signals.

4. The physical simulation method according to claim 1, characterized in that, The two dense sandstone plug samples are taken from the same layer and have similar physical property parameters.

5. The physical simulation method according to claim 1, wherein In the constant-pressure water flooding experiment, a 2% KCl deuterium aqueous solution without hydrogen proton signals is continuously injected into the inlet end of the core sample after oil saturation at a constant pressure, the outlet pressure is atmospheric pressure, the T2 spectrum of the core sample is measured at regular intervals, and the corresponding water saturation of the core is calculated until water appears at the outlet end, and the displacement experiment is stopped.

6. The physical simulation method according to claim 1, wherein The pressure-infiltration experiment is carried out using a pressure-infiltration experiment device. The core sample after oil saturation and a 2% KCl deuterium aqueous solution without hydrogen proton signals are placed in a piston-type intermediate container at the same time. Distilled water is continuously injected into the bottom of the intermediate container until the set pressure value is reached, and the pressure in the intermediate container is kept unchanged. The T2 spectrum of the core sample is measured at regular intervals until the reduction amount of the cumulative signal amplitude of the T2 spectrum is less than 3%, and the pressure-infiltration experiment is stopped.

7. The physical simulation method according to claim 1, characterized in that, When the filtrate loss core and the infiltration core are connected in series, the infiltration core is close to the inlet end.

8. The physical simulation method according to claim 7, wherein In the constant-pressure oil flooding experiment, aviation kerosene is continuously injected into the inlet end at a constant pressure, and the outlet pressure is atmospheric pressure.

9. The physical simulation method according to claim 8, characterized in that, Change the constant pressure at the inlet end in the constant-pressure oil flooding experiment to different pressure values, repeat the constant-pressure oil flooding experiment, and obtain the backflow rates under different backflow pressures to optimize the backflow pressure.

10. The physical simulation method according to any one of claims 1-9, characterized in that, The constant-pressure water flooding experiment, the pressure-infiltration experiment, and the constant-pressure oil flooding experiment are all completed in a high-temperature and high-pressure displacement-nuclear magnetic resonance scanning integrated experimental device.

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