Physical simulation experiment device and method for fracturing and huff and puff oil production in low-permeability oil reservoir

Abstract

This invention discloses a physical simulation experimental device and method for fracturing and huff-and-puff oil production in low-permeability reservoirs, comprising an injection system, a core holding system, an oil-water collection system, and a water system. The injection system is sequentially connected to the core holding system and the water system, and the oil-water collection system is connected to the core holding system. The water system includes a long, thin tube, a water reservoir, and a third pressure gauge. The inlet end of the long, thin tube is connected to the core holding system, and a fifteenth valve is installed between the inlet end of the long, thin tube and the core holding system. The outlet end of the long, thin tube is connected to the water reservoir, and a third pressure gauge is installed on the water reservoir. The device of this invention ensures that the injected fracturing fluid can pass through the entire core pores, effectively simulating the in-situ fracturing oil production process. The method of this invention ensures that only the liquid phase exists in the core pores, accurately simulating the two-phase flow characteristics of oil and water in the reservoir, and the experimental results are accurate and reliable.

Description

Technical Field

[0001] This invention relates to the field of oilfield development, and in particular to a physical simulation experimental device and method for fracturing and churn-up oil production in low-permeability reservoirs. Background Technology

[0002] The successful application of horizontal well fracturing and flow-through technology has opened up broad prospects for the industrial development of low-permeability reservoirs such as tight and shale oilfields. The in-situ fracturing production process is essentially a fracturing fluid flow-through process, including three stages: injection, well shut-in, and flowback production. After fracturing creates a fracture, the fracturing fluid in the fracture is forced into the matrix pores under pressure differential. The depth to which the fracturing fluid penetrates the matrix is ​​a decisive factor in the oil production efficiency during the flowback stage. Only when the fracturing fluid penetrates a sufficiently long distance into the matrix, after well shut-in and flowback, the pressure within the fracture decreases. Due to elastic compression and elastic expansion of the fluid, the oil and fracturing fluid under high pressure are released from the matrix into the fracture, and then flow from the fracture into the wellbore.

[0003] In actual low-permeability reservoir fracturing and huff-and-puff production processes, only gases that are easily soluble in oil, such as methane and ethane, exist in the pores of the formation. Although there is a vacuuming step in the experimental core, due to the limitations of the vacuum equipment, residual air still exists in the pores inside the core. When the fluid flows, the presence of air bubbles will produce the Jamin effect, which hinders the movement of oil and water, which is inconsistent with the actual formation conditions.

[0004] Meanwhile, the formation contains a large volume of oil and water, which can generate considerable compressibility under applied pressure. This allows the fracturing fluid to penetrate deep into the matrix, enabling prolonged oil flowback. However, in laboratory experiments studying fracturing and huff-and-puff oil production, the limited size of conventional low-permeability cores used in the lab results in a small volume of fluid within the core and its pores, limiting compressibility. Under experimental pressure, the fracturing fluid can only penetrate a short distance to the fracture-matrix interface, contacting only a small amount of oil within the matrix pores. Consequently, even less oil is recovered during flowback.

[0005] Due to the presence of air in the pores and the small amount of fluid compression in the pores, it is difficult to obtain accurate results from physical simulation tests of fracturing fluid huff and puff production in low-permeability reservoirs, making it impossible to provide effective guidance and reference for field production. Summary of the Invention

[0006] The purpose of this invention is to overcome the shortcomings of the prior art and provide a physical simulation experimental device and method for fracturing and guzzling oil production in low-permeability reservoirs. This device can increase the compression of the fluid in the experiment, ensuring that the injected fracturing fluid can pass through the entire core pores and be smoothly returned. This method can remove the air present in the pores, so that there are only water and oil phases in the pores, which can more accurately simulate the physical properties of the oil layer and effectively restore the fracturing and oil production process in the field.

[0007] To achieve the above objectives, the present invention adopts the following technical solution:

[0008] In a first aspect, the present invention discloses a physical simulation experimental device for fracturing and huff-and-puff oil production in low-permeability reservoirs, comprising an injection system, a core holding system, an oil-water collection system, and a water system; the injection system is sequentially connected to the core holding system and the water system, and the core holding system is also connected to the oil-water collection system;

[0009] The water system includes a long thin tube, a water reservoir, and a third pressure gauge;

[0010] The inlet end of the long thin tube is connected to the core clamping system, and a fifteenth valve is provided between the inlet end of the long thin tube and the core clamping system; the outlet end of the long thin tube is connected to the water storage device; and a third pressure gauge is provided on the water storage device.

[0011] In one possible design, the volume of the long, thin tube is greater than the sum of the volumes of the third pressure gauge and the water reservoir.

[0012] In one possible design, the physical simulation experimental device for fracturing and churn-up oil production in low-permeability reservoirs also includes a first pressure gauge and a four-way valve. The injection system, one end of the core clamping system, the oil-water collection system, and the first pressure gauge are connected through the four-way valve, and the other end of the core clamping system is connected to the water system.

[0013] In one possible design, the injection system includes a gas cylinder, an injection pump, an intermediate gas storage container, an intermediate water storage container, an intermediate oil storage container, and an intermediate fracturing fluid storage container.

[0014] Each of the gas storage intermediate container, water storage intermediate container, oil storage intermediate container, and fracturing fluid storage intermediate container is equipped with a piston. The gas storage intermediate container, water storage intermediate container, oil storage intermediate container, and fracturing fluid storage intermediate container are connected in parallel to form an intermediate container group. The inlet end of the intermediate container group is connected to an injection pump. A third valve, a fourth valve, a fifth valve, and a sixth valve are respectively provided between the gas storage intermediate container, water storage intermediate container, oil storage intermediate container, fracturing fluid storage intermediate container and the injection pump. The outlet end of the intermediate container group is connected to a four-way valve. A second valve, a seventh valve, an eighth valve, and a ninth valve are respectively provided between the gas storage intermediate container, water storage intermediate container, oil storage intermediate container, fracturing fluid storage intermediate container and the four-way valve.

[0015] The gas storage intermediate container is also connected to the gas cylinder at one end near the second valve, and a first valve is provided between the gas storage intermediate container and the gas cylinder.

[0016] In one possible design, the core clamping system includes a capillary, a core clamp, a first hand-cranked pump, a safety bottle, a vacuum pump, a second hand-cranked pump, and a back pressure valve.

[0017] One end of the capillary tube is connected to the four-way valve, an eleventh valve is provided between the capillary tube and the four-way valve, and the other end of the capillary tube is connected to the inlet end of the core holder.

[0018] The outlet end of the core holder is connected to the inlet end of the back pressure valve, and a fourteenth valve is provided between the outlet end of the core holder and the inlet end of the back pressure valve; a liquid metering device is provided below the outlet end of the back pressure valve; a back pressure control interface is provided on the back pressure valve, and the back pressure control interface is connected to the second hand pump; a seventeenth valve and a fourth pressure gauge are provided sequentially between the back pressure control interface and the second hand pump.

[0019] The outlet end of the core holder is also connected to a vacuum pump via a safety bottle, and a thirteenth valve is provided between the outlet end of the core holder and the safety bottle; the outlet end of the core holder is also connected to the fifteenth valve;

[0020] The core holder is provided with a radial confining pressure interface, which is connected to the first hand-cranked pump. A twelfth valve and a second pressure gauge are sequentially provided between the radial confining pressure interface and the first hand-cranked pump.

[0021] In one possible design, the oil-water collection system includes a transparent hose and a graduated plate;

[0022] The inlet end of the transparent hose is connected to the four-way valve, and a sixteenth valve is provided between the inlet end of the transparent hose and the four-way valve; the outlet end of the transparent hose is connected to the atmosphere; and a scale plate is provided on one side of the transparent hose.

[0023] In one possible design, the eleventh valve, capillary tube, core holder, twelfth valve, thirteenth valve, fourteenth valve, fifteenth valve, long thin tube, water reservoir, and third pressure gauge are all placed in a constant temperature device.

[0024] Secondly, this invention discloses a physical simulation experimental method for fracturing and huff-and-puff oil production in low-permeability reservoirs, comprising the following steps:

[0025] S1, Core Saturated Fluid:

[0026] First, load the core into the core holder, and fill the long thin tube, water reservoir, and third pressure gauge and the pipelines between them with water phase; fill the water reservoir near the seventh valve with water phase; fill the oil reservoir near the eighth valve with oil phase; fill the fracturing fluid reservoir near the ninth valve with fracturing fluid; connect all pipelines and close all valves;

[0027] Open the twelfth valve, set the confining pressure on the core using the first hand-cranked pump, and then close the twelfth valve; open the thirteenth valve, turn on the vacuum pump to evacuate the core, and then close the thirteenth valve.

[0028] Open the first valve, and the gas in the gas cylinder enters the gas storage intermediate container, causing the piston of the gas storage intermediate container to be pushed to the end close to the third valve, and close the first valve; open the second valve, the third valve and the eleventh valve, start the injection pump, push the piston of the gas storage intermediate container to the end away from the third valve, pressurize the core with saturated gas, and close all valves;

[0029] Open the thirteenth valve, turn on the vacuum pump to evacuate the core again, and then close the thirteenth valve.

[0030] Open the seventeenth valve, set the back pressure P1 to the back pressure valve using the second hand pump, and then close the seventeenth valve;

[0031] Open the fourth, seventh, eleventh, and fourteenth valves, start the injection pump and adjust it to constant pressure mode, push the piston of the intermediate water storage container towards the end near the seventh valve to saturate the core with water phase; open the fifteenth valve and continue to saturate the core with water phase through the injection pump until the reading of the third pressure gauge is the formation pressure, then close the injection pump and all valves;

[0032] Open the fifth, eighth, eleventh, and fourteenth valves, turn on the injection pump and adjust it to constant pressure mode, push the piston of the intermediate oil storage container towards the end near the eighth valve, and saturate the core with oil phase;

[0033] The outflow rates of water and oil phases at the outlet of the back pressure valve are calculated using a liquid metering device, and the saturation of bound water in the core is calculated.

[0034] S2, Core aging:

[0035] Close all valves, adjust the thermostat to the set temperature, and let it stand for 3-5 days;

[0036] S3, Injection Phase:

[0037] Open the sixth, ninth, eleventh and fifteenth valves, turn on the injection pump and adjust it to constant speed mode, push the piston of the fracturing fluid intermediate container towards the end near the ninth valve, inject fracturing fluid into the core until the reading of the third pressure gauge reaches the set pressure P2 (P2>P1), then stop the injection;

[0038] S4, Well-sealing stage:

[0039] Close all valves and let stand for 5-15 days;

[0040] S5, Return Phase:

[0041] By opening valves 11, 15, and 16, and reading the flow distance of the oil and water phases in the transparent hose at different times, the amount of oil and water discharged at different times can be calculated to obtain the fracturing huff and puff oil production effect and pattern of low-permeability reservoirs.

[0042] S6. Change the type of core, the type of fracturing fluid, and the set value of P2, and repeat steps S1-S5 to obtain the fracturing huff and puff oil production effect and regularity of low-permeability reservoirs under different conditions.

[0043] In one possible design, in step S3, the volume of fracturing fluid injected does not exceed the volume of the long, thin tube.

[0044] In one possible design, the gas in the gas cylinder is .

[0045] Thirdly, this invention also discloses the application of a physical simulation experimental method for fracturing and huffing-and-puff oil production in low-permeability reservoirs in the exploitation of low-permeability reservoirs.

[0046] The beneficial effects of this invention are as follows:

[0047] In current simulations of fracturing and huff-and-puff oil production in low-permeability reservoirs, on the one hand, due to limitations in vacuum equipment, residual air remains in the pores of the artificial core after sequentially saturating the water and oil phases. This results in the presence of three phases (oil, gas, and water) within the pores. During oil-water flow, the presence of air bubbles generates the Jamin effect, hindering the flow of the water and oil phases. This contradicts the fact that actual formation cores contain only dissolved gases readily soluble in oil, such as methane and ethane. On the other hand, in actual oil displacement operations, the injection of fracturing fluid into the formation is also a process of pressurizing the fluid within the formation pores. Although the compressibility of the fluid is relatively low, the large volume and numerous pores within the formation, along with the large amount of fluid within those pores, mean that the cumulative compression of the fluid within the formation is not negligible. Therefore, fracturing fluid can be injected into the formation and enter the matrix through fractures. In the experiment, because the fluid volume in the pores of the rock core is very small, only a few milliliters, when the fracturing fluid is injected, the fracturing fluid can only enter the rock core inlet face a very small distance. It is impossible to simulate the long distance that the fracturing fluid enters into the rock matrix in the oil field, let alone simulate the subsequent seepage and displacement process.

[0048] In the simulation experimental apparatus of this invention, a water reservoir connected behind the core can simulate a large volume of fluids (crude oil and formation water) within the formation. On one hand, after the fracturing fluid is injected, the water in the reservoir can generate significant pressure inside the core, ensuring that the injected fracturing fluid can penetrate the entire core pore. On the other hand, it ensures that the oil phase ejected from the core due to the injection of fracturing fluid can return to the core during flowback, simulating the fracturing fluid being flowback through the release of formation pressure. This effectively replicates the in-situ fracturing oil production process, thereby obtaining more accurate and reliable experimental results.

[0049] The experimental apparatus of this invention calculates the oil and water production rate by reading the flow distance of the produced fluid in a transparent flexible tube, which improves the measurement accuracy, reduces the evaporation of the produced fluid, and further ensures the accuracy of the experimental data.

[0050] In the simulation experiment method of this invention, saturated oil is added after vacuuming. The process can remove residual air from the small pores and blind end throats of the core. What it replaced was the formation water in the subsequent pressurized saturation simulation. Under high pressure, it will dissolve in simulated formation water, containing dissolved substances. The aqueous phase is displaced from the core by subsequent aqueous phases, ensuring that only the aqueous phase exists in the core pores, thus simulating a single-phase flow of formation water. After subsequent saturation with the oil phase, the core exhibits a two-phase flow of oil and water, more accurately simulating the physical properties of the oil reservoir and obtaining accurate and reliable experimental results.

[0051] In this invention Its function differs from that of supercritical fluid commonly used in oil fields. They are As an oil displacement agent, it is injected into the formation during the oil displacement process to displace the oil. This invention, in simulating formation saturation of core samples, aims to saturate the core with both aqueous and oil phases while ensuring the core pores are free of air, making the saturated core more closely resemble the actual state of the formation. Therefore, saturated oil is added after vacuuming. The steps utilize the large diffusion coefficient of the gas. The air in the rock core was replaced, and then... Its water-soluble properties allow for better handling of core samples when the sample is saturated with water. It dissolves in water, and when the core is saturated with oil phase, the dissolved... The water phase is displaced to ensure that there is no air in the core pores, only the oil and water phases.

[0052] The device of the present invention has a simple structure and a straightforward method. It can effectively reproduce the on-site fracturing oil production process, and the results are accurate, providing effective guidance and reference for on-site production. Attached Figure Description

[0053] To more clearly illustrate the technical solutions in the embodiments of this application, the accompanying drawings used in the description of the embodiments will be briefly introduced below. Obviously, the accompanying drawings described below are only some embodiments of this application. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0054] Figure 1 This is a schematic diagram of the physical simulation experimental device for fracturing and huffing-and-puff oil production in low-permeability reservoirs provided in an embodiment of the present invention.

[0055] Figure 2 This is a schematic diagram of the cumulative liquid output of core A provided in this application embodiment at different flowback times under P2=20MPa.

[0056] Figure 3 This is a schematic diagram of the cumulative oil yield of core A provided in this application embodiment at different flowback times under P2=20MPa.

[0057] Figure 4 This is a schematic diagram of the cumulative oil yield of core A provided in this application embodiment, under different return flow rates at P2=20MPa;

[0058] Figure 5 This is a schematic diagram of the cumulative liquid output of core B provided in this application at different flowback times under P2=17MPa.

[0059] Figure 6 This is a schematic diagram of the cumulative oil yield of core B provided in this application, under different flowback times at P2=17MPa.

[0060] Figure 7 This is a schematic diagram of the cumulative oil yield of core B provided in this application embodiment, under different return flow rates at P2=17MPa.

[0061] Among them, 1. Gas cylinder, 2. Injection pump, 3. Gas storage intermediate container, 4. Water storage intermediate container, 5. Oil storage intermediate container, 6. Fracturing fluid storage intermediate container, 7. Capillary tube, 8. Core, 9. Core holder, 10. First hand-cranked pump, 11. Safety bottle, 12. Vacuum pump, 13. Long thin tube, 14. Water reservoir, 15. Transparent flexible tube, 16. Scale plate, 17. Back pressure valve, 18. Second hand-cranked pump, 19. Liquid metering device, 20. Four-way valve, 21. Thermostat, 101. First pressure gauge, 102. Second pressure gauge, 103. Third pressure gauge, 104. Fourth pressure gauge, 201. First valve, 202. Second valve, 203. Third valve, 204. Fourth valve, 205. Fifth valve, 206. Sixth valve, 207. Seventh valve, 208. Eighth valve, 209. Ninth valve, 211. Eleventh valve, 212. Twelfth valve, 213. Thirteenth valve, 214. Fourteenth valve, 215. Fifteenth valve, 216. Sixteenth valve.

[0062] The accompanying drawings illustrate specific embodiments of this application, which will be described in more detail below. These drawings and descriptions are not intended to limit the scope of the concept in any way, but rather to illustrate the concept of this application to those skilled in the art through reference to particular embodiments. Detailed Implementation

[0063] Horizontal well fracturing technology holds a significant position in the development of low-permeability reservoirs due to its high recovery rate and efficiency. In actual reservoirs, the large volume of oil and water within the formation allows for considerable compressibility under applied pressure, enabling fracturing fluid to penetrate deep into the matrix and subsequently flow back oil over extended periods. However, current laboratory research experiments suffer from limitations. The limited size of conventional low-permeability cores and the small fluid volume within the core and its pores result in limited compressibility. Under experimental pressure, the fracturing fluid can only penetrate a short distance to the fracture-matrix interface, failing to reach the deeper matrix and only contacting a small amount of oil within the matrix pores. This does not achieve the effect of water penetrating beyond the oil layer, leading to minimal oil recovery during flowback. Furthermore, the limited fluid recovery from low-permeability core experiments results in significant errors in current measurement methods, making accurate results difficult to obtain. Therefore, current laboratory physical simulation experiments of fracturing and pump-back production in low-permeability reservoirs neither effectively reflect the field fracturing process nor provide effective guidance and reference for field production.

[0064] An embodiment of the present invention provides a physical simulation experimental device for fracturing and huff-and-puff oil production in a low-permeability reservoir, comprising an injection system, a core holding system, an oil-water collection system, and a water system; the injection system is sequentially connected to the core holding system and the water system, and the core holding system is also connected to the oil-water collection system;

[0065] The water system includes a long thin tube 13, a water reservoir 14, and a third pressure gauge 103;

[0066] The inlet end of the long thin tube 13 is connected to the core clamping system, and a fifteenth valve 215 is provided between the inlet end of the long thin tube 13 and the core clamping system; the outlet end of the long thin tube 13 is connected to the water storage device 14; a third pressure gauge 103 is provided on the water storage device 14.

[0067] It should be noted that, typically, during simulated fracturing fluid injection, only the fluid within the core pores is compressed, and this volume is only a few milliliters. Experiments or calculations based on fluid compressibility coefficients show that the amount of fluid compressed in the pores during pressurized injection is very small. This makes it difficult for the fracturing fluid to penetrate the core matrix from the fractures. Even if it does penetrate, it is only within a very small distance at the core inlet face. A large portion of the crude oil within the core remains untouched by the fracturing fluid and therefore will not be recovered during flowback. This approach fails to simulate the real process of fracturing fluid penetrating a long distance into the rock matrix and performing infiltration and oil displacement in an oilfield. This embodiment simulates a large volume of fluid (crude oil and formation water) within the formation by connecting a large volume of water to the rear end of the core. During fracturing fluid injection, the fracturing fluid exerts a force on the core in the direction of injection. The large volume of water behind the core, under external pressure, exerts a force on the core opposite to the direction of fracturing fluid injection. This opposing force ensures that the injected fracturing fluid penetrates the entire core. During flowback, the fracturing fluid contacts as much crude oil as possible within the core pores, facilitating oil displacement through percolation. Simultaneously, calculations ensure that the oil ejected from the core by the injected fracturing fluid can return to the core during flowback and then be further discharged through the release of formation pressure. This effectively simulates the in-situ fracturing oil production process, leading to more accurate and reliable experimental results.

[0068] In one possible design, the volume of the long thin tube 13 is greater than the sum of the volumes of the third pressure gauge 103 and the water reservoir 14.

[0069] It should be noted that under high pressure, the volume of the long thin tube 13 is greater than the sum of the compressed volumes of the water in the water reservoir 14 and the third pressure gauge 103, ensuring that during the fracturing fluid injection stage, the oil pushed out by the fracturing fluid is in the long thin tube 13 and will not enter the water reservoir 14.

[0070] Optional, the long, thin tube has an inner diameter of 1.5 mm.

[0071] In one possible design, the physical simulation experimental device for fracturing and churn-up oil production in low-permeability reservoirs also includes a first pressure gauge 101 and a four-way valve 20. The injection system, one end of the core clamping system, the oil-water collection system and the first pressure gauge 101 are connected through the four-way valve 20, and the other end of the core clamping system is connected to the water system.

[0072] In one possible design, the injection system includes a gas cylinder 1, an injection pump 2, an intermediate gas storage container 3, an intermediate water storage container 4, an intermediate oil storage container 5, and an intermediate fracturing fluid storage container 6.

[0073] Pistons are installed in the intermediate gas storage container 3, intermediate water storage container 4, intermediate oil storage container 5, and intermediate fracturing fluid storage container 6. The intermediate gas storage container 3, intermediate water storage container 4, intermediate oil storage container 5, and intermediate fracturing fluid storage container 6 are connected in parallel to form an intermediate container group. The inlet end of the intermediate container group is connected to the injection pump 2. A third valve 203, a fourth valve 204, a fifth valve 205, and a sixth valve 206 are respectively installed between the intermediate gas storage container 3, intermediate water storage container 4, intermediate oil storage container 5, intermediate fracturing fluid storage container 6 and the injection pump 2. The outlet end of the intermediate container group is connected to a four-way valve 20. A second valve 202, a seventh valve 207, an eighth valve 208, and a ninth valve 209 are respectively installed between the intermediate gas storage container 3, intermediate water storage container 4, intermediate oil storage container 5, intermediate fracturing fluid storage container 6 and the four-way valve 20.

[0074] The gas storage intermediate container 3 is also connected to the gas cylinder 1 at one end near the second valve 202, and a first valve 201 is provided between the gas storage intermediate container 3 and the gas cylinder 1.

[0075] In one possible design, the core clamping system includes a capillary tube 7, a core clamp 9, a first hand-cranked pump 10, a safety bottle 11, a vacuum pump 12, a second hand-cranked pump 18, and a back pressure valve 17.

[0076] One end of the capillary tube 7 is connected to the four-way valve 20, and an eleventh valve 211 is provided between the capillary tube 7 and the four-way valve 20. The other end of the capillary tube 7 is connected to the inlet end of the core holder 9.

[0077] The outlet end of the core holder 9 is connected to the inlet end of the back pressure valve 17. A fourteenth valve 214 is provided between the outlet end of the core holder 9 and the inlet end of the back pressure valve 17. A liquid metering device 19 is provided below the outlet end of the back pressure valve 17. A back pressure control interface is provided on the back pressure valve 17. The back pressure control interface is connected to the second hand pump 18. A seventeenth valve 217 and a fourth pressure gauge 104 are provided sequentially between the back pressure control interface and the second hand pump 18.

[0078] The outlet end of the core holder 9 is also connected to the vacuum pump 12 via the safety bottle 11. A thirteenth valve 213 is provided between the outlet end of the core holder 9 and the safety bottle 11. The outlet end of the core holder 9 is also connected to the water system.

[0079] The core holder 9 is provided with a radial confining pressure interface, which is connected to the first hand-cranked pump 10. A twelfth valve 212 and a second pressure gauge 102 are sequentially provided between the radial confining pressure interface and the first hand-cranked pump 10.

[0080] Optionally, the liquid metering device 19 is a graduated cylinder.

[0081] It is understandable that the liquid metering device measures the final total amount of oil and water output, and does not involve the measurement of the oil and water output process.

[0082] Optional, the capillary tube 7 has an inner diameter of 0.875 mm.

[0083] It should be noted that capillary 7 is a simulated crack.

[0084] In one possible design, the oil-water collection system includes a transparent hose 15 and a scale plate 16; the inlet end of the transparent hose 15 is connected to a four-way valve 20, and a sixteenth valve 216 is provided between the inlet end of the transparent hose 15 and the four-way valve 20; the outlet end of the transparent hose 15 is connected to the atmosphere; and a scale plate 16 is provided on one side of the transparent hose 15.

[0085] It should be noted that for the measurement of produced fluid from low-permeability cores, existing technologies mainly use high-precision graduated cylinders. However, low-permeability cores have small pore volumes, low oil recovery rates, and very little fluid output per unit time during the flowback phase. Furthermore, there is a stage where oil and water co-exist. Although high-precision graduated cylinders are used, the minimum measurement volume is still limited. The volume of oil and water recovered during the backflow process is orders of magnitude smaller than the current minimum measurement volume, making it difficult to distinguish the individual volumes of the oil and water discharged simultaneously, resulting in poor accuracy of the graduated cylinder measurement. Furthermore, the backflow phase is lengthy, and the evaporation of the oil and water recovered fluids in the graduated cylinder under high-temperature conditions further increases experimental error. This embodiment calculates the oil and water recovered volume by reading the flow distance of the recovered fluid in the transparent flexible tube 15, with an error of only 2 ml, significantly improving the measurement accuracy during the oil and water backflow process. Simultaneously, the evaporation of the oil and water recovered fluids in the transparent flexible tube 15 effectively reduces the amount of evaporation, further ensuring the accuracy of the experimental data.

[0086] Optionally, the length of the transparent flexible tube 15 is less than the range of the scale plate 16.

[0087] Optional, transparent flexible tube 15, inner diameter 1.5mm, minimum measuring volume .

[0088] Optionally, the minimum measuring distance of the scale plate 16 is 1 mm.

[0089] In one possible design, the eleventh valve 211, capillary tube 7, core holder 9, twelfth valve 212, thirteenth valve 213, fourteenth valve 214, fifteenth valve 215, long thin tube 13, water reservoir 14, and third pressure gauge 103 are all placed in the constant temperature device 21.

[0090] Optionally, the temperature control device 21 is a temperature control chamber.

[0091] This invention also provides a physical simulation experimental method for fracturing and huff-and-puff oil production in low-permeability reservoirs, comprising the following steps:

[0092] S1, Core Saturated Fluid:

[0093] First, load core 8 into core holder 9. Fill the long thin tube 13, water reservoir 14, and third pressure gauge 103 and the pipelines between them with water phase. Fill the water reservoir 4 with water phase at the end near the seventh valve 207. Fill the oil reservoir 5 with oil phase at the end near the eighth valve 208. Fill the fracturing fluid reservoir 6 with fracturing fluid at the end near the ninth valve 209. Connect all pipelines and close all valves.

[0094] Open the twelfth valve 212, set the confining pressure for core 8 using the first hand-cranked pump 10, and close the twelfth valve 212; open the thirteenth valve 213, turn on the vacuum pump 12 to evacuate the inside of core 8, and close the thirteenth valve 213.

[0095] Open the first valve 201, and the gas in the gas cylinder 1 enters the gas storage intermediate container 3, pushing the piston of the gas storage intermediate container 3 to the end close to the third valve 203, and close the first valve 201; open the second valve 202, the third valve 203 and the eleventh valve 211, start the injection pump 2, push the piston of the gas storage intermediate container 3 to the end away from the third valve 203, pressurize the core 8 with saturated gas, and close all valves;

[0096] Open the thirteenth valve 213, turn on the vacuum pump 12 to evacuate the inside of core 8 again, and close the thirteenth valve 213;

[0097] Open the seventeenth valve 217, set the back pressure P1 to the back pressure valve 17 through the second hand pump 18, and close the seventeenth valve 217;

[0098] Open the fourth valve 204, the seventh valve 207, the eleventh valve 211, and the fourteenth valve 214. Turn on the injection pump 2 and adjust it to constant pressure mode. Push the piston of the intermediate water storage container 4 towards the end near the seventh valve 207 to saturate the water phase in the core 8. Open the fifteenth valve 215 and continue to saturate the water phase in the core 8 through the injection pump 2 until the reading of the third pressure gauge 103 is the formation pressure. Then close the injection pump 2 and all valves.

[0099] Open the fifth valve 205, the eighth valve 208, the eleventh valve 211 and the fourteenth valve 214, turn on the injection pump 2 and adjust it to constant pressure mode, push the piston of the intermediate oil storage container 5 towards the end near the eighth valve 208 to saturate the oil phase of the core 8;

[0100] The output of the aqueous and oil phases is calculated using the liquid metering device 19, and the saturation of bound water in the core is calculated.

[0101] S2, Core aging:

[0102] Close all valves, adjust the thermostat 21 to the set temperature, and let it stand for 3-5 days;

[0103] S3, Injection Phase:

[0104] Open the sixth valve 206, the ninth valve 209, the eleventh valve 211 and the fifteenth valve 215, turn on the injection pump 2 and adjust it to constant speed mode, push the piston of the intermediate container 6 for storing fracturing fluid towards the end near the ninth valve 209, inject fracturing fluid into the core 8 until the reading of the third pressure gauge 103 reaches the set pressure P2 (P2>P1), then stop the injection;

[0105] S4, Well-sealing stage:

[0106] Close all valves and let stand for 5-15 days;

[0107] S5, Return Phase:

[0108] Open the eleventh valve 211, the fifteenth valve 215 and the sixteenth valve 216, and by reading the flow distance of the oil and water phases in the transparent hose 15 at different times, calculate the amount of oil and water discharged at different times, and obtain the fracturing huff and puff oil production effect and law of low-permeability reservoirs.

[0109] S6. Change the core type, fracturing fluid type, and P2 setting, and repeat the steps. The effects and patterns of fracturing and huff-and-puff oil production in low-permeability reservoirs under different conditions were obtained.

[0110] It should be noted that for indoor simulation of saturated fluid in low-permeability cores, the conventional method for core saturation in existing oil recovery technologies involves immediately saturating the core with simulated formation water or crude oil after vacuuming, without an intermediate CO2 saturation process. Because the pores in low-permeability cores are extremely small, the vacuuming process cannot completely remove the air from the core. Furthermore, due to the limited solubility of air in water, saturated simulated formation water cannot enter the blind end pore throats to replace the gas. Therefore, after saturating the simulated formation water, gas remains in the tiny pore throats within the core, causing the flow to change from a single-phase liquid flow to a two-phase gas-liquid flow. Subsequent saturation with crude oil further transforms the flow into a more complex three-phase oil-water-gas flow, altering the reservoir properties originally intended to simulate two-phase oil-water flow. Consequently, experimental results obtained based on this method contain significant errors and may even be erroneous.

[0111] In the S1 core saturation fluid step of this embodiment, after vacuuming, saturated CO2 is added. Because CO2 is miscible with air, continued vacuuming replaces the residual air in the small pores and blind throats of the core with CO2. After pressurizing and saturating the simulated formation water, because CO2 has good solubility in water, the residual CO2 in the small pores and blind throats of the core dissolves in the simulated formation water under high pressure. The simulated formation water containing dissolved CO2 is then displaced from the core by the subsequent simulated formation water, ensuring that only simulated formation water exists in the core pores, i.e., a single-phase flow of simulated formation water. After subsequent saturation with crude oil, the core exhibits a two-phase flow of oil and water, more accurately simulating the physical properties of the oil reservoir and thus obtaining accurate and reliable experimental results.

[0112] It should be noted that in the S1 core saturation fluid step of this embodiment, the water phase saturation of core 8 is carried out using a partial saturation method. Core 8 is first fully saturated with water before the water system is pressurized for saturation. This is because core 8 is in a vacuum state before being saturated with water. If saturation is carried out simultaneously, water from the water system will be drawn back into core 8, affecting the vacuum pressurization saturation of core 8 and resulting in insufficient water saturation of core 8.

[0113] In one possible design, in step S3, the volume of fracturing fluid injected does not exceed the volume of the long, thin tube 13.

[0114] Understandably, the crude oil driven out by fracturing fluid in capillary tube 7 and core 8 remains in long thin tube 13 and does not enter water reservoir 14.

[0115] In one possible design, the gas in the cylinder is .

[0116] Thirdly, this invention also discloses the application of a simulation experiment method for fracturing and huffing-and-puff oil production in low-permeability reservoirs in the exploitation of low-permeability reservoirs.

[0117] The present invention will be further described below through specific embodiments.

[0118] Unless otherwise specified, the experimental methods used in the following specific embodiments are all conventional methods.

[0119] Unless otherwise specified, all operations described in the following specific embodiments are performed under standard conditions or conditions recommended by the manufacturer. Raw materials whose manufacturers and specifications are not specified are all commercially available products.

[0120] In the following specific embodiments: the gas phase is The oil phase was simulated oil (hexadecane), analytical grade; the aqueous phase and fracturing fluid were both simulated formation water, with a salinity of [missing information]. Composed of NaCl, KCl, 、 and Preparation, concentrations are respectively , , , , NaCl, KCl, 、 and All samples were of analytical grade; core A and core B were artificial low-permeability cores.

[0121] This embodiment adopts Figure 1 The physical simulation experimental device for fracturing and huffing-and-puff oil production in low-permeability reservoirs includes an injection system, a core holding system, an oil-water collection system, a water system, and a first pressure gauge 101; one end of the injection system and the core holding system, the oil-water collection system, and the water system are connected through a four-way valve 20; the other end of the core holding system is connected to the water system.

[0122] The injection system includes a gas cylinder 1, an injection pump 2, an intermediate gas storage container 3, an intermediate water storage container 4, an intermediate oil storage container 5, and an intermediate fracturing fluid storage container 6.

[0123] Pistons are installed in the intermediate gas storage container 3, intermediate water storage container 4, intermediate oil storage container 5, and intermediate fracturing fluid storage container 6. The intermediate gas storage container 3, intermediate water storage container 4, intermediate oil storage container 5, and intermediate fracturing fluid storage container 6 are connected in parallel to form an intermediate container group. The inlet end of the intermediate container group is connected to the injection pump 2. A third valve 203, a fourth valve 204, a fifth valve 205, and a sixth valve 206 are respectively installed between the intermediate gas storage container 3, intermediate water storage container 4, intermediate oil storage container 5, intermediate fracturing fluid storage container 6 and the injection pump 2. The outlet end of the intermediate container group is connected to a four-way valve 20. A second valve 202, a seventh valve 207, an eighth valve 208, and a ninth valve 209 are respectively installed between the intermediate gas storage container 3, intermediate water storage container 4, intermediate oil storage container 5, intermediate fracturing fluid storage container 6 and the four-way valve 20.

[0124] The gas storage intermediate container 3 is also connected to the gas cylinder 1 at one end near the second valve 202, and a first valve 201 is provided between the gas storage intermediate container 3 and the gas cylinder 1.

[0125] The core clamping system includes a capillary tube 7, a core clamp 9, a first hand-cranked pump 10, a safety bottle 11, a vacuum pump 12, a second hand-cranked pump 18, and a back pressure valve 17.

[0126] The capillary tube 7 has an inner diameter of 0.875 mm and a length of 15 cm. One end of the capillary tube 7 is connected to the four-way valve 20. An eleventh valve 211 is provided between the capillary tube 7 and the four-way valve 20. The other end of the capillary tube 7 is connected to the inlet end of the core holder 9.

[0127] The outlet end of the core holder 9 is connected to the inlet end of the back pressure valve 17. A fourteenth valve 214 is provided between the outlet end of the core holder 9 and the inlet end of the back pressure valve 17. A measuring cylinder is provided below the outlet end of the back pressure valve 17. A back pressure control interface is provided on the back pressure valve 17. The back pressure control interface is connected to the second hand pump 18. A seventeenth valve 217 and a fourth pressure gauge 104 are provided between the back pressure control interface and the second hand pump 18 in sequence.

[0128] The outlet end of the core holder 9 is also connected to the vacuum pump 12 via the safety bottle 11. A thirteenth valve 213 is provided between the outlet end of the core holder 9 and the safety bottle 11. The outlet end of the core holder 9 is also connected to the water system.

[0129] The core holder 9 is provided with a radial confining pressure interface, which is connected to the first hand-cranked pump 10. A twelfth valve 212 and a second pressure gauge 102 are sequentially provided between the radial confining pressure interface and the first hand-cranked pump 10.

[0130] The oil-water collection system includes a transparent flexible tube 15 and a graduated plate 16. The inlet end of the transparent flexible tube 15 is connected to a four-way valve 20, and a sixteenth valve 216 is located between the inlet end of the transparent flexible tube 15 and the four-way valve 20. The outlet end of the transparent flexible tube 15 is connected to the atmosphere. A graduated plate 16 is installed on one side of the transparent flexible tube 15. The inner diameter of the transparent flexible tube 15 is 1.5 mm, and the minimum measuring volume is... The minimum measuring distance of the scale plate 16 is 1 mm, and the length of the transparent flexible tube 15 is less than the measuring range of the scale plate 16.

[0131] The water system includes a long thin tube 13, a water reservoir 14, and a third pressure gauge 103;

[0132] The inlet end of the long thin tube 13 is connected to the outlet end of the core holder, and a fifteenth valve 215 is provided between the inlet end of the long thin tube 13 and the outlet end of the core holder; the outlet end of the long thin tube 13 is connected to the water storage device 14; a third pressure gauge 103 is provided on the water storage device 14.

[0133] The volume of the long thin tube 13 is greater than the sum of the volumes of the third pressure gauge 103 and the water reservoir 14.

[0134] The eleventh valve 211, capillary tube 7, core holder 9, twelfth valve 212, thirteenth valve 213, fourteenth valve 214, fifteenth valve 215, long thin tube 13, water reservoir 14, and third pressure gauge 103 are all placed in a constant temperature chamber.

[0135] A physical simulation experimental method for fracturing and huff-and-puff oil production in low-permeability reservoirs includes the following steps:

[0136] S1, Core Saturated Fluid:

[0137] First, core A (material: artificial sandstone, length 6.34cm, cross-sectional diameter 2.5cm, permeability...) was prepared. Simulated formation water (with a porosity of 6.4%) is loaded into the core holder 9. Simulated formation water is then loaded into the long thin tube 13, the water reservoir 14, the third pressure gauge 103, and the pipelines between them. Simulated formation water is then loaded into the water storage intermediate container 4 near the seventh valve 207. Simulated oil is then loaded into the oil storage intermediate container 5 near the eighth valve 208. Fracturing fluid is then loaded into the fracturing fluid storage intermediate container 6 near the ninth valve 209. All pipelines are connected and all valves are closed.

[0138] Open the twelfth valve 212, set the confining pressure for core A using the first hand-cranked pump 10, and close the twelfth valve 212; open the thirteenth valve 213, turn on the vacuum pump 12 to evacuate the inside of core A for 10 hours, and close the thirteenth valve 213.

[0139] Open the first valve 201, and the gas cylinder 1 Enter the gas storage intermediate container 3, push the piston of the gas storage intermediate container 3 to the end close to the third valve 203, and close the first valve 201; open the second valve 202, the third valve 203 and the eleventh valve 211, start the injection pump 2, push the piston of the gas storage intermediate container 3 away from the third valve 203, pressurize the core A with saturated gas at 6MPa for 10h, and close all valves;

[0140] Open the thirteenth valve 213, turn on the vacuum pump 12 to evacuate the inside of core 8 again for 10 hours, and then close the thirteenth valve 213.

[0141] Open the seventeenth valve 217, set the back pressure P1 (P1=10MPa) to the back pressure valve 17 through the second hand pump 18, and close the seventeenth valve 217;

[0142] Open the fourth valve 204, the seventh valve 207, the eleventh valve 211, and the fourteenth valve 214. Turn on the injection pump 2 and adjust it to constant pressure mode. Push the piston of the intermediate water storage container 4 towards the end near the seventh valve 207 to saturate the core A with water phase for 24 hours. Open the fifteenth valve 215 and continue to saturate the core A with water phase through the injection pump 2 until the reading of the third pressure gauge 103 is 10 MPa. Then close the injection pump 2 and all valves.

[0143] Open the fifth valve 205, the eighth valve 208, the eleventh valve 211 and the fourteenth valve 214, turn on the injection pump 2 and adjust it to constant pressure mode, push the piston of the oil storage intermediate container 5 towards the end near the eighth valve 208, saturate the core A with oil phase until no oil is discharged from the outlet of the back pressure valve 17.

[0144] The liquid flow rate of the water phase and oil phase at the outlet of the back pressure valve 17 is calculated using the liquid metering device 19, and the core bound water saturation is calculated.

[0145] The calculation process is as follows:

[0146] Core pore volume ;

[0147] Water output from rock core That is, the volume of saturated oil in the core is 1.22 ml;

[0148] Core bound water volume ;

[0149] Core bound water saturation = Core bound water volume Core pore volume =0.77 / 1.99 100% = 38.7%.

[0150] Where V is the core volume, ml; PV is the core pore volume, ml; denoted as core porosity (%), r as core cross-sectional radius (cm), and L as core length (cm). The volume of bound water in the core is in ml. The core bound water saturation is expressed as %.

[0151] S2, Core aging:

[0152] Close all valves, adjust the thermostat 21 to 50°C, and let it stand for 3 days;

[0153] S3, Injection Phase:

[0154] Open valves 206, 209, 211, and 215. Turn on injection pump 2 and set it to constant speed mode. Push the piston of the intermediate container 6 for fracturing fluid storage towards the end near valve 209 to inject fracturing fluid into core A until the reading of the third pressure gauge 103 reaches the set pressure P2 (P2=20MPa) (P2>P1). Stop injection.

[0155] S4, Well-sealing stage:

[0156] Close all valves and let stand for 5 days;

[0157] S5, Return Phase:

[0158] Open valves 11, 211, 215, and 216. Calculate the amount of oil and water discharged at different times by reading the flow distances of the returned oil and water phases within the transparent hose 15. Figures 2 to 4 The effects and patterns of fracturing and huff-and-puff oil production in low-permeability reservoirs were obtained.

[0159] S6. Replacing core A with permeability is... Core B (material: artificial sandstone, length: 5.78cm, cross-sectional diameter: 2.5cm, porosity: 10.7%), when P2 pressure is set to 17MPa, repeat steps S1-S5 to obtain the fracturing and huff-and-puff oil production effect of low-permeability reservoir, such as... Figures 5 to 7 As shown.

[0160] Field fracturing results show that there is a relatively long oil production process during the fracturing flowback stage. Reservoirs with better physical properties have higher flowback rates, and increasing the injection pressure is beneficial to improving the later flowback rate. Similar results were obtained through testing using the method of this invention. Furthermore, this invention also obtained oil production data for different flowback times and volumes, providing strong theoretical support for practical field applications.

[0161] The experimental apparatus of this invention solves the problem of insufficient fluid volume in the prior art: In the prior art, when simulating fracturing fluid injection, only the fluid in the core pores is compressed, and the volume of this fluid is only a few milliliters. According to experiments or calculations of the fluid compressibility coefficient, the amount of fluid compressed in the pores during pressurized injection is very small. This makes it difficult for the fracturing fluid to enter the core matrix from the fracture. Even if it does enter, it is only within a very small distance at the core inlet end face. A large part of the crude oil in the core cannot be affected by the fracturing fluid and therefore will not be extracted during flowback. Obviously, it cannot simulate the process of fracturing fluid entering the rock matrix a long distance and carrying out infiltration and oil displacement in an oil field.

[0162] In this invention, when the system pressure is P1, the volume of water in the water reservoir 14 is V1. After fracturing fluid is injected under pressure and the system pressure rises to P2, the water in the water reservoir 14 is compressed, and its volume becomes V2. This refers to the compressible volume of the water body; the pore volume of core 8 is PV. To allow the fracturing fluid to penetrate deeper into the core, the compressible volume must be guaranteed. The volume of water in the reservoir 14 is greater than the pore volume PV. This invention uses a large-volume water reservoir 14 connected to the rear end of the core to simulate a large volume of fluid (crude oil and formation water) within the formation. During fracturing fluid injection, the large volume of water in the reservoir 14 behind the core 8 generates a significant compressed volume under external pressure. This compressed volume ensures that the injected fracturing fluid penetrates the entire pore structure of the core 8. During flowback, the fracturing fluid in the pores can contact as much crude oil as possible within the core 8, enabling oil displacement through percolation. Simultaneously, calculations ensure that the oil ejected by the injected fracturing fluid within the core 8 can return to the core 8 during flowback, and then be further discharged through the release of formation pressure, thus more realistically simulating the formation flowback process. This invention introduces a water system, which allows fracturing fluid to enter the rock matrix more fully from the fractures and travel a greater distance within the matrix. This enables more oil to be discharged during the flowback stage through percolation. This solves the problems of poor fracturing fluid injection and low injection volume caused by insufficient core pore volume in existing technologies. At the same time, it effectively simulates the in-situ fracturing oil production process, thus obtaining more accurate and reliable experimental results.

[0163] The experimental apparatus of this invention solves the problems of inaccurate and large-error metering of produced fluid in existing technologies. For metering produced fluid from low-permeability core samples, existing technologies mainly use high-precision graduated cylinders. Although high-precision graduated cylinders are used, the minimum measuring volume is still... The volume of fluid produced during the flowback phase is very small, less than the current minimum measurable volume. During the co-emergence of oil and water, it is even more difficult to distinguish the individual volumes of the oil and water. Furthermore, the relatively long flowback phase and the high-temperature evaporation of the produced fluid in the measuring cylinder further increase experimental errors. Low-permeability cores have small pore volumes and low oil recovery rates; when oil and water emerge simultaneously, their individual volumes are even smaller, meaning any measurement error can lead to significantly inaccurate experimental results. This invention calculates the oil and water production volume by reading the flow distance of the produced fluid in the transparent flexible tube 15, with an error of only [missing information]. This significantly improves measurement accuracy. Simultaneously, the evaporation of the oil-water produced fluid is effectively reduced within the transparent tubing 15, further ensuring the accuracy of the experimental data.

[0164] The experimental method of this invention also solves the problem of insufficient core saturation fluid in existing technologies. For indoor simulation of saturation fluid in low-permeability cores, conventional methods for saturating cores in oil recovery involve immediately saturating the cores with simulated formation water or crude oil after vacuuming, without any intermediate saturation. The process is complex. Because the pores in low-permeability cores are extremely small, the vacuuming process cannot completely remove the air from the core. Simultaneously, due to the limited solubility of air in water, saturated simulated formation water cannot enter the blind end pore throats to replace the gas. Therefore, after saturating simulated formation water, gas remains in the tiny pore throats within the core, causing the flow to change from a single-phase liquid to a two-phase gas-liquid flow. Subsequent saturation with crude oil further transforms this into a more complex three-phase oil-water-gas flow, altering the reservoir properties that were originally intended to simulate two-phase oil-water flow. Consequently, the experimental results obtained based on this process contain significant errors or even inaccuracies. In this invention, saturated simulated formation water is added after vacuuming... The process, because It is miscible with air; after further vacuuming, the residual air in the fine pores and blind end throats of the core is... Replaced. After pressurizing and saturating simulated formation water, because It has good solubility in water, and the residue in the fine pores and blind end throats of the core is present. Under high pressure, it will dissolve in simulated formation water, containing dissolved substances. The simulated formation water is displaced from the core by subsequent simulated formation water, ensuring that only simulated formation water exists in the core pores, i.e., a single-phase flow of simulated formation water. After subsequent saturation with crude oil, the core exhibits a two-phase flow of oil and water, more accurately simulating the physical properties of the oil reservoir and thus obtaining accurate and reliable experimental results.

[0165] The above embodiments are only used to illustrate the technical solutions of the present invention, and are not intended to limit it. Although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some of the technical features. Such modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the scope of the technical solutions of the embodiments of the present invention.

Claims

1. A physical simulation experiment device for fracturing and huff and puff oil production in low permeability oil reservoirs, characterized in that, It includes an injection system, a core holding system, an oil-water collection system, and a water system; the injection system is connected in sequence to the core holding system and the water system, and the core holding system is also connected to the oil-water collection system; The water system includes a long thin tube (13), a water reservoir (14), and a third pressure gauge (103). The inlet end of the long thin tube (13) is connected to the core clamping system, and a fifteenth valve (215) is provided between the inlet end of the long thin tube (13) and the core clamping system; the outlet end of the long thin tube (13) is connected to the water storage device (14); a third pressure gauge (103) is provided on the water storage device (14); The volume of the long thin tube (13) is greater than the sum of the volumes of the third pressure gauge (103) and the water reservoir (14); The device also includes a first pressure gauge (101) and a four-way valve (20). The injection system, one end of the core clamping system, the oil-water collection system and the first pressure gauge (101) are connected through the four-way valve (20). The other end of the core clamping system is connected to the water system. The injection system includes a gas cylinder (1), an injection pump (2), a gas storage intermediate container (3), a water storage intermediate container (4), an oil storage intermediate container (5), and a fracturing fluid storage intermediate container (6). Pistons are provided in the gas storage intermediate container (3), water storage intermediate container (4), oil storage intermediate container (5), and fracturing fluid storage intermediate container (6); the gas storage intermediate container (3), water storage intermediate container (4), oil storage intermediate container (5), and fracturing fluid storage intermediate container (6) are connected in parallel to form an intermediate container group, the inlet end of the intermediate container group is connected to the injection pump (2), and the gas storage intermediate container (3), water storage intermediate container (4), oil storage intermediate container (5), and fracturing fluid storage intermediate container (6) are connected to the injection pump (2). A third valve (203), a fourth valve (204), a fifth valve (205), and a sixth valve (206) are respectively provided between the pumps (2); the outlet end of the intermediate container group is connected to the four-way valve (20); a second valve (202), a seventh valve (207), an eighth valve (208), and a ninth valve (209) are respectively provided between the gas storage intermediate container (3), the water storage intermediate container (4), the oil storage intermediate container (5), the fracturing fluid storage intermediate container (6), and the four-way valve (20); The gas storage intermediate container (3) is also connected to the gas cylinder (1) at one end near the second valve (202), and a first valve (201) is provided between the gas storage intermediate container (3) and the gas cylinder (1). The core clamping system includes a capillary tube (7), a core clamp (9), a first hand pump (10), a safety bottle (11), a vacuum pump (12), a second hand pump (18), and a back pressure valve (17). One end of the capillary tube (7) is connected to the four-way valve (20), and an eleventh valve (211) is provided between the capillary tube (7) and the four-way valve (20). The other end of the capillary tube (7) is connected to the inlet end of the core holder (9). The outlet end of the core holder (9) is connected to the inlet end of the back pressure valve (17), and a fourteenth valve (214) is provided between the outlet end of the core holder (9) and the inlet end of the back pressure valve (17); a liquid metering device (19) is provided below the outlet end of the back pressure valve (17); a back pressure control interface is provided on the back pressure valve (17), and the back pressure control interface is connected to the second hand pump (18). A seventeenth valve and a fourth pressure gauge (104) are provided sequentially between the back pressure control interface and the second hand pump (18). The outlet end of the core holder (9) is also connected to the vacuum pump (12) via a safety bottle (11), and a thirteenth valve (213) is provided between the outlet end of the core holder (9) and the safety bottle (11); the outlet end of the core holder (9) is also connected to the fifteenth valve (215). The core holder (9) is provided with a radial confining pressure interface, which is connected to the first hand pump (10). A twelfth valve (212) and a second pressure gauge (102) are provided between the radial confining pressure interface and the first hand pump (10).

2. The physical simulation experimental device for fracturing and huff-and-puff oil production in low-permeability reservoirs as described in claim 1, characterized in that, The oil-water collection system includes a transparent hose (15) and a scale plate (16). The inlet end of the transparent hose (15) is connected to the four-way valve (20), and a sixteenth valve (216) is provided between the inlet end of the transparent hose (15) and the four-way valve (20); the outlet end of the transparent hose (15) is connected to the atmosphere; a scale plate (16) is provided on one side of the transparent hose (15).

3. The physical simulation experimental device for fracturing and huff-and-puff oil production in low-permeability reservoirs as described in claim 1, characterized in that, The eleventh valve (211), capillary tube (7), core holder (9), twelfth valve (212), thirteenth valve (213), fourteenth valve (214), fifteenth valve (215), long thin tube (13), water reservoir (14) and third pressure gauge (103) are all placed in the constant temperature device (21).

4. A physical simulation experimental method for fracturing and huff-and-puff oil production in low-permeability reservoirs, employing the physical simulation experimental apparatus for fracturing and huff-and-puff oil production in low-permeability reservoirs as described in any one of claims 2 or 3, characterized in that, Includes the following steps: S1, Core Saturated Fluid: First, the core is loaded into the core holder (9), and the long thin tube (13), water reservoir (14), and third pressure gauge (103) and the pipeline between them are filled with water phase; water phase is loaded into the end of the water storage intermediate container (4) near the seventh valve (207); oil phase is loaded into the end of the oil storage intermediate container (5) near the eighth valve (208); fracturing fluid is loaded into the end of the fracturing fluid storage intermediate container (6) near the ninth valve (209); all pipelines are connected and all valves are closed; Open the twelfth valve (212), set the confining pressure of the core using the first hand pump (10), and close the twelfth valve (212); open the thirteenth valve (213), turn on the vacuum pump (12) to evacuate the core, and close the thirteenth valve (213). Open the first valve (201), and the gas in the gas cylinder (1) enters the gas storage intermediate container (3), causing the piston of the gas storage intermediate container (3) to be pushed to the end close to the third valve (203), and close the first valve (201); open the second valve (202), the third valve (203) and the eleventh valve (211), start the injection pump (2), push the piston of the gas storage intermediate container (3) away from the third valve (203), pressurize the core with saturated gas, and close all valves; Open the thirteenth valve (213), turn on the vacuum pump (12) to evacuate the core again, and close the thirteenth valve (213). Open the seventeenth valve, set the back pressure P1 to the back pressure valve (17) through the second hand pump (18), and close the seventeenth valve; Open the fourth valve (204), the seventh valve (207), the eleventh valve (211), and the fourteenth valve (214), turn on the injection pump (2) and adjust it to constant pressure mode, push the piston of the intermediate water storage container (4) towards the end near the seventh valve (207) to saturate the core with water phase; open the fifteenth valve (215) and continue to saturate the core with water phase through the injection pump (2) until the reading of the third pressure gauge (103) is the formation pressure, then close the injection pump (2) and all valves; Open the fifth valve (205), the eighth valve (208), the eleventh valve (211) and the fourteenth valve (214), turn on the injection pump (2) and adjust it to constant pressure mode, push the piston of the oil storage intermediate container (5) towards the end close to the eighth valve (208) to saturate the core with oil phase; The liquid output of water and oil phases at the outlet of back pressure valve (17) is calculated using liquid metering device (19), and the core bound water saturation is calculated. S2, Core aging: Close all valves, adjust the thermostat (21) to the set temperature, and let it stand for 3 to 5 days; S3, Injection Phase: Open the sixth valve (206), the ninth valve (209), the eleventh valve (211) and the fifteenth valve (215), turn on the injection pump (2) and adjust it to constant speed mode, push the piston of the intermediate container for storing fracturing fluid towards the end near the ninth valve (209), inject fracturing fluid into the core until the reading of the third pressure gauge (103) reaches the set pressure P2 (P2>P1), and stop the injection; S4, Well-sealing stage: Close all valves and let stand for 5-15 days; S5, Return Phase: Open the eleventh valve (211), the fifteenth valve (215) and the sixteenth valve, and calculate the amount of oil and water discharged at different times by reading the flow distance of the oil and water phases in the transparent hose (15) at different times, so as to obtain the fracturing and huff-and-puff oil production effect and law of low-permeability reservoirs. S6. Change the type of core, the type of fracturing fluid, and the set value of P2, and repeat steps S1-S5 to obtain the fracturing huff and puff oil production effect and regularity of low-permeability reservoirs under different conditions.

5. The physical simulation experiment method for fracturing and huff and puff oil production of low-permeability oil reservoirs according to claim 4, characterized in that, In step S3, the injection volume of fracturing fluid does not exceed the volume of the long thin tube (13).

6. The physical simulation experimental method for fracturing and huff-and-puff oil production in low-permeability reservoirs as described in claim 5, characterized in that, The gas in the gas cylinder (1) is CO2.

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