A device and method for determining the limit of shale imbibition depth and well killing time

Abstract

This invention provides an apparatus and method for determining the shale's ultimate adsorption depth and well shut-in time. The apparatus includes a non-magnetic core holder, a confining pressure pump, an upstream gas tank, an adsorption pump, a backpressure pump, a venting pipeline, a nuclear magnetic resonance (NMR) magnet, and a nuclear magnetic resonance (NMR) analyzer. This invention integrates a high-temperature, high-pressure online NMR and adsorption depth testing device with an in-situ permeability testing device. It can simultaneously determine the shale's ultimate adsorption depth and in-situ permeability changes, and, combined with productivity index calculations, determine the optimal well shut-in time after shale oil and gas well pressure testing, providing guidance for field operations.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas field development technology, specifically relating to a device and method for determining the ultimate permeability depth of shale and the well shut-in time. Background Technology

[0002] The efficient development of shale oil and gas reservoirs is of great significance for ensuring my country's energy security and promoting increased oil and gas reserves and production. One of the characteristics of shale reservoirs is the significant permeability of shale. The permeability mechanism mainly includes pressure difference, capillary force, clay hydration, and chemical osmotic pressure. Permeability has both positive and negative effects. The positive effect is the generation of hydration-induced microfractures, which enhances seepage capacity and redistributes the saturation field, alleviating water lock. The negative effect is that clay hydration blocks pores, impairing seepage capacity.

[0003] Following shale fracturing, well shut-in is often employed to promote permeation. Most researchers believe well shut-in is beneficial in shale fracturing, while some argue it is detrimental. Currently, there is no unified consensus on the method for determining the optimal well shut-in time. For example, Liang Tianbo et al., based on tight core displacement experiments, suggest that well shut-in is not recommended for tight reservoirs, as it may delay water-lock release and impair productivity. Qiao Runwei et al., based on numerical simulation studies, believe that well shut-in cannot alleviate overall reservoir water-lock damage; if the optimization goal is to eliminate fracture water-lock damage, they recommend a shut-in time of 20–30 days.

[0004] Chinese invention patent CN111879674A proposes a testing device and method for determining a reasonable well shut-in time based on shale permeability, which determines the shut-in time after pressure testing based on changes in shale permeability. Chinese invention patent CN117993310A proposes a method for determining the shut-in time based on the pressure boundary line movement rate and the gas-water ratio change rate within the wellbore, derived from numerical simulation results. However, current methods for determining the shut-in time do not consider the shale's ultimate permeability depth and the impact of permeability on mitigating water lock and improving seepage flow. Furthermore, experimental equipment for testing the shale's ultimate permeability depth and in-situ permeability is currently lacking.

[0005] Therefore, proposing a device and method for determining the ultimate seepage depth of shale and the shut-in time, and further providing guidance for field operations, has become an urgent problem to be solved by those skilled in the art. Summary of the Invention

[0006] The purpose of this invention is to solve the problems existing in the prior art and to provide an apparatus and method for determining the shale limit absorption depth and well shut-in time. It fully considers the influence of the shale limit absorption depth on alleviating water lock and improving seepage capacity, integrates high-temperature and high-pressure online nuclear magnetic resonance and in-situ permeability testing device to determine the shale limit absorption depth and in-situ permeability changes, and combines the production capacity index calculation to determine the optimal well shut-in time after shale oil and gas well pressure.

[0007] One of the objectives of this invention is to provide a device for determining the ultimate permeability depth and well shut-in time of shale, comprising:

[0008] A non-magnetic core holder is used to be fitted over and hold a shale core; the non-magnetic core holder is equipped with a non-magnetic high-temperature module.

[0009] A confining pressure pump is connected to the inner circumferential surface of the non-magnetic core holder;

[0010] An upstream gas tank is used to connect to the inlet end face of the shale core.

[0011] A seepage pump is used to connect to the inlet end face of the shale core.

[0012] A back pressure pump is used to connect to the outlet end face of the shale core.

[0013] A venting pipeline is used to connect to the outlet end face of the shale core.

[0014] The nuclear magnetic resonance magnet is sleeved on the outside of the non-magnetic core holder and connected to the nuclear magnetic resonance analyzer and the non-magnetic core holder respectively.

[0015] In a preferred embodiment of the present invention

[0016] The inner circumferential surface of the non-magnetic core holder is provided with an annular channel; the annular channel is connected to the confining pressure pump; and / or

[0017] The non-magnetic core holder has a first side channel on its first inner surface; the first side channel is connected to the seepage pump; and / or

[0018] The second inner side of the non-magnetic core holder is provided with a second side channel; the second side channel is connected to the back pressure pump.

[0019] In a preferred embodiment of the present invention

[0020] The non-magnetic core holder is connected to the confining pressure pump via a confining pressure pipeline, on which a confining pressure pump valve and / or a confining pressure sensor are provided; and / or

[0021] The upstream gas tank is connected to the inlet face of the shale core via a connecting pipeline. An upstream gas phase valve and / or an upstream pressure sensor are installed on the connecting pipeline; and / or

[0022] The percolation pump is connected to the inlet face of the shale core via a percolation pipeline. A percolation pump valve and / or a percolation pressure sensor are installed on the percolation pipeline; and / or

[0023] The back pressure pump is connected to the outlet face of the shale core via a back pressure pipeline, and a back pressure pump valve is provided on the back pressure pipeline; and / or

[0024] A vent valve is installed on the vent pipeline;

[0025] Preferably, an outlet pipeline is provided at the junction of the back pressure pipeline and the seepage pipeline, and the outlet pipeline is connected to the outlet end face of the shale core; a downstream pressure sensor is provided on the outlet pipeline;

[0026] More preferably, the upstream gas tank is also connected to a gas supply source.

[0027] In a preferred embodiment of the present invention

[0028] The non-magnetic high-temperature module is also connected to a heating device; and / or

[0029] The non-magnetic core holder is also equipped with a temperature sensor, which is connected to the non-magnetic high-temperature module.

[0030] In a preferred embodiment of the present invention, the inner circumferential surface of the non-magnetic core holder is provided with a rubber inner sleeve.

[0031] The second objective of this invention is to provide a method for determining the ultimate permeability depth and well shut-in time of shale, comprising the following steps:

[0032] S1: The apparatus described in one of the objectives of this invention determines the first post-pressure well-closing time;

[0033] S2: Determine the second post-pressure well shut-in time based on the production capacity index;

[0034] S3: Determine the optimized shale well-closing time based on the first and second post-compression closing times; take the larger of the two post-compression closing times as the optimized shale well-closing time.

[0035] In a preferred embodiment of the present invention, step S1 includes:

[0036] S11: Collect data, including formation temperature, formation pressure, and bottom hole pressure of the shale reservoir when the pump is shut down during on-site fracturing operations;

[0037] S12: Fixing shale cores using the device described in one of the objectives of this invention;

[0038] S13: Simulates formation temperature, formation pressure, and bottom hole pressure during pump shutdown in shale reservoirs;

[0039] S14, Acquire relaxation time spectrum, constant gradient stratigraphic spectrum and nuclear magnetic resonance imaging of shale cores;

[0040] S15: In-situ permeability test;

[0041] S16: Repeat S14 and S15 to determine the shale's ultimate adsorption depth and permeability equilibrium time, and determine the adsorption depth equilibrium time based on the shale's ultimate adsorption depth.

[0042] S17: Determine the first post-pressure well shut-in time based on the seepage depth equilibrium time and permeability equilibrium time.

[0043] In a preferred embodiment of the present invention

[0044] In step S13, confining pressure is applied to the circumference of the shale core using a confining pressure pump until the circumferential confining pressure value of the shale core equals the formation pressure in S11; the non-magnetic high-temperature module is heated until its temperature equals the formation temperature in S11; back pressure is applied to the outlet end face of the shale core using a back pressure pump until its back pressure value equals the formation pressure; and a percolation fluid is pumped into the inlet end face of the shale core using a percolation pump until its percolation pressure value equals the bottom hole pressure when the pump is stopped during on-site fracturing operations; and / or,

[0045] In step S15, the outlet face of the shale core is restored to atmospheric pressure; gas is injected into the upstream gas tank, and after the upstream gas tank is full of gas, the pressure values ​​of the connecting pipeline and the outlet pipeline are collected; the seepage and backpressure of the shale core are repeated; and / or,

[0046] In step S16, based on the constant gradient stratigraphic pattern and NMR imaging of the shale core, the ultimate adsorption depth of the shale is determined; the equilibrium time of the adsorption depth is determined based on the ultimate adsorption depth; an in-situ permeability variation curve is plotted based on the infiltration time and permeability; and the permeability equilibrium time is obtained based on the in-situ permeability variation curve; and / or,

[0047] In step S17, when the permeability equilibrium time is the first permeability equilibrium time, the larger value between the first permeability equilibrium time and the permeation depth equilibrium time is taken as the first post-pressure well shut-in time; when the permeability equilibrium time is the second permeability equilibrium time, the permeation depth equilibrium time is taken as the first post-pressure well shut-in time; when the permeability equilibrium time is the third permeability equilibrium time, the third permeability equilibrium time is taken as the first post-pressure well shut-in time; when the permeability equilibrium time is the fourth permeability equilibrium time, the fourth permeability equilibrium time is taken as the first post-pressure well shut-in time.

[0048] In a preferred embodiment of the present invention, step S2 includes:

[0049] S21: Collect on-site parameters;

[0050] S22: The production capacity index is obtained based on on-site parameters;

[0051] S23: Plot the capacity index curve based on the penetration time and capacity index, and obtain the second post-pressure well shut-in time based on the capacity index curve.

[0052] In a preferred embodiment of the present invention

[0053] In step S21, the field parameters include: the designed fracture height, the spacing of microfractures in the shale core observed by the permeation test, the hydraulic fracture width, the vertical permeability of the formation, the horizontal permeability of the formation, the viscosity of the fluid, the compressibility coefficient of the fluid, the amount of fracturing fluid used, the designed half-fracture length, the designed number of hydraulic fractures, the surface tension of the formation, the contact angle of the formation, the water saturation of the formation, the rate of decrease in bottom hole pressure during well shut-in, the bottom hole pressure during well shut-in, and the bottom hole pressure when the pump is stopped during fracturing operations; and / or

[0054] In step S22, the capacity index is calculated using equations (1) to (3).

[0055]

[0056] In the formula, F is the production capacity index; H f Design joint height for on-site fracturing; w c L represents the average width of the microcracks. z h represents the depth of horizontal microcracks after in-situ hydraulic fracturing. f The spacing of microfractures in shale cores observed by infiltration experiments; w f The width of the hydraulic fracture; k v k represents the vertical permeability of the formation at the site. f The horizontal permeability of the formation at the site; μ f c represents the viscosity of the fluid in the field. f V is the compressibility coefficient of the fluid in the field. f This refers to the amount of fracturing fluid used in the field; L x Design half-fracturing length for on-site fracturing; n f The number of hydraulic fractures to be designed for on-site fracturing; σ f θ represents the surface tension of the formation at the site; θ represents the contact angle of the formation at the site; S w This represents the water saturation level of the formation at the site. P represents the rate of decrease in bottom hole pressure during well shut-in. si P is the bottom hole pressure when the pump is shut down during on-site fracturing operations; t is the bottom hole pressure during the on-site well shut-in period; and / or

[0057] In step S23, a production capacity index curve is plotted based on the infiltration time and the production capacity index, and the infiltration time corresponding to the inflection point of the production capacity index curve is taken as the second post-pressure well shut-in time.

[0058] Compared with the prior art, the beneficial effects of the present invention are:

[0059] 1. The device for determining the shale ultimate permeability depth and well shut-in time of the present invention integrates a high-temperature and high-pressure online nuclear magnetic resonance and permeability depth testing device and an in-situ permeability testing device. It can simultaneously determine the shale ultimate permeability depth and in-situ permeability changes, and combined with the production capacity index calculation, determine the optimal well shut-in time after shale oil and gas well pressure, providing guidance for field operations.

[0060] 2. The method for determining the shale ultimate adsorption depth and well shut-in time of this invention achieves the purpose of considering adsorption depth by testing the shale ultimate adsorption depth; through in-situ permeability testing, the degree to which adsorption alleviates water lock and improves seepage capacity can be evaluated. Based on this, combined with the production capacity index calculation, the final shale well shut-in time can simultaneously satisfy the balance of adsorption depth and the improvement of production capacity after well shut-in, and also take into account the permeability balance. Attached Figure Description

[0061] Figure 1 This is a schematic diagram of the device for determining the shale limit permeability depth and well shut-in time in this invention;

[0062] Figure 2 The amplitude of the relaxation time spectrum signal of the shale core in this invention;

[0063] Figure 3 This is a constant gradient stratigraphic map of shale cores in this invention;

[0064] Figure 4 This is an NMR image of a specific layer of shale core in this invention;

[0065] Figure 5 This is an in-situ permeability change curve of one embodiment of the present invention;

[0066] Figure 6 This is an in-situ permeability change curve of one embodiment of the present invention;

[0067] Figure 7 This is an in-situ permeability change curve of one embodiment of the present invention;

[0068] Figure 8 This is an in-situ permeability change curve of one embodiment of the present invention;

[0069] Figure 9 This is the capacity index curve in this invention;

[0070] In the diagram, 1-Gas supply source, 2-Upstream gas tank, 3-Upstream gas phase valve, 4-Upstream pressure sensor, 5-Connecting pipeline, 6-Heater, 7-Temperature sensor, 8-NMR magnet, 9-Non-magnetic high-temperature module, 10-Downstream pressure sensor, 11-Vent valve, 12-Back pressure pump valve, 13-Back pressure pump, 14-NMR analyzer, 15-Shale core, 16-Non-magnetic core holder, 17-Containing pressure sensor, 18-Containing pressure pump valve, 19-Containing pressure pump, 20-Permeation pressure sensor, 21-Permeation pump valve, 22-Permeation pump. Detailed Implementation

[0071] The present invention will now be described in further detail with reference to the accompanying drawings:

[0072] Example 1

[0073] like Figure 1 As shown, this invention provides a device for determining the ultimate shale seepage depth and well shut-in time, specifically including: a gas supply source 1, an upstream gas tank 2, an upstream gas phase valve 3, an upstream pressure sensor 4, a connecting pipeline 5, a heater 6, a temperature sensor 7, a nuclear magnetic resonance magnet 8, a non-magnetic high-temperature module 9, a downstream pressure sensor 10, a vent valve 11, a back pressure pump valve 12, a back pressure pump 13, a nuclear magnetic resonance analyzer 14, a shale core 15, a non-magnetic core holder 16, a confining pressure sensor 17, a confining pressure pump valve 18, a confining pressure pump 19, a seepage pressure sensor 20, a seepage pump valve 21, and a seepage pump 22. It should be noted that... Figure 1 Both the shale core 15 and the non-magnetic core holder 16 are sectional views.

[0074] The apparatus for determining the ultimate permeability depth and well shut-in time of shale is described in detail below. A non-magnetic core holder 16 includes a clamping element, the inner circumferential surface of which matches the outer circumferential surface of the shale core 15. The non-magnetic core holder 16 is preferably an annular clamping element (comprising a circumferential surface and two side surfaces), and an example of an annular non-magnetic core holder 16 will be described below. The annular clamping element has an inner circumferential surface, which, together with the two side surfaces, is used to mount the shale core 15. Specifically, the inner diameter of the non-magnetic core holder 16 is slightly larger than the outer diameter of the shale core 15, thereby achieving the clamping effect on the shale core 15. The distance between the two side surfaces of the non-magnetic core holder 16 is slightly larger than the distance between the two side surfaces of the shale core 15, thereby achieving the clamping effect on the shale core 15. More preferably, the inner circumferential surface of the non-magnetic core holder 16 is provided with a rubber inner sleeve.

[0075] The inner circumferential surface of the non-magnetic core holder 16 is provided with an annular channel; the annular channel is connected to the confining pressure pump 19; the first inner side of the non-magnetic core holder 16 is provided with a first side channel; the first side channel is connected to the seepage pump 22; the second inner side of the non-magnetic core holder 16 is provided with a second side channel; the second side channel is connected to the back pressure pump 13. It should be noted that the "first inner side" here refers to the side opposite to the inlet end face of the shale core 15, and the "second inner side" here refers to the side opposite to the outlet end face of the shale core 15. Furthermore, the annular channel, the first side channel, and the second side channel are all located within the non-magnetic core holder 16.

[0076] Specifically, in this embodiment, as mentioned above, "the inner diameter of the non-magnetic core holder 16 is slightly larger than the outer diameter of the shale core 15." The inner circumferential surface of the non-magnetic core holder 16 is provided with an annular channel, which is located outside the rubber inner sleeve. As mentioned above, "the distance between the two sides of the non-magnetic core holder 16 is slightly larger than the distance between the two sides of the shale core 15." The first inner side of the non-magnetic core holder 16 is provided with a first side channel; the second inner side of the non-magnetic core holder 16 is provided with a second side channel. The first side channel, the second side channel, and the annular channel are not interconnected. Fluid can be injected into the first side channel, the second side channel, and the annular channel, as will be explained in detail below.

[0077] In a preferred embodiment of the present invention, the non-magnetic core holder 16 is equipped with a non-magnetic high-temperature module 9 to control the temperature of the non-magnetic core holder 16 and transfer its temperature to the shale core 15 to simulate the formation temperature of the shale reservoir. It should be noted that the non-magnetic high-temperature module 9 can be connected to a heater 6, which is located on the outside of the non-magnetic core holder 16. More preferably, the non-magnetic core holder 16 also includes a temperature sensor 7, which is connected to the non-magnetic high-temperature module 9 to detect the temperature of the non-magnetic core holder 16 in real time. This allows for more precise temperature control of the non-magnetic core holder 16 by adjusting the heater 6. The temperature sensor 7 can be located on the outer circumferential surface of the non-magnetic core holder 16 or inside the non-magnetic core holder 16. Preferably, the temperature sensor 7 is located inside the non-magnetic core holder 16, thereby more accurately testing the internal temperature of the non-magnetic core holder 16.

[0078] In a specific embodiment, the non-magnetic core holder 16 is connected to the confining pressure pump 19 via a confining pressure pipeline. Specifically, in this embodiment, the annular channel on the inner circumferential surface of the non-magnetic core holder 16 is connected to the confining pressure pump 19 via the confining pressure pipeline, so as to apply confining pressure to the shale core 15 circumferentially through the non-magnetic core holder 16 to simulate the formation pressure of the shale reservoir. It should be noted that the confining pressure pump 19 pumps out confining pressure fluid, which is pumped into the annular channel on the inner circumferential surface of the non-magnetic core holder 16 via the confining pressure pipeline; as the confining pressure fluid enters, the rubber inner sleeve on the inner circumferential surface of the non-magnetic core holder 16 is gradually pressurized, thereby applying confining pressure to the shale core 15 circumferentially. Preferably, a confining pressure pump valve 18 is provided on the confining pressure pipeline to control whether the confining pressure pump 19 applies confining pressure to the circumference of the shale core 15; a confining pressure sensor 17 is provided on the confining pressure pipeline to monitor the confining pressure applied by the confining pressure pump 19 to the shale core 15 in real time.

[0079] In this specific embodiment, the shale core 15 is a cylindrical structure, with its circumferential surface in contact with the non-magnetic core holder 16. The remaining two surfaces are named the inlet end face and the outlet end face, respectively. The inlet end face is connected to the inlet pipeline, and the outlet end face is connected to the outlet pipeline. It should be noted that the inlet pipeline of the shale core 15 inlet end face and the outlet pipeline of the shale core 15 outlet end face are not connected. The inlet face of the shale core 15 is connected to the upstream gas tank 2 and the percolation pump 22, respectively. Preferably, the inlet face of the shale core 15 is connected to the upstream gas tank 2 and the percolation pump 22 via an inlet pipeline, that is, one end of the inlet pipeline is connected to the inlet face of the shale core 15. Specifically, in this embodiment, one end of the inlet pipeline is connected to the first side channel of the non-magnetic core holder 16, and the other end is connected to the upstream gas tank 2 and the percolation pump 22, respectively. More preferably, the inlet face of the shale core 15 is connected to the upstream gas tank 2 via an inlet pipeline and a connecting pipeline 5, and the inlet face of the shale core 15 is connected to the percolation pump 22 via an inlet pipeline and a percolation pipeline.

[0080] In a preferred embodiment of the present invention, an upstream gas phase valve 3 is provided on the connecting pipeline 5 to control whether the upstream gas tank 2 is connected to the inlet pipeline; an upstream pressure sensor 4 is provided on the connecting pipeline 5 to monitor the pressure in the connecting pipeline 5 in real time. More preferably, the upstream gas tank 2 is connected to the gas supply source 1 so that gas in the gas supply source 1 enters the upstream gas tank 2. In another preferred embodiment of the present invention, a percolation pump valve 21 is provided on the percolation pipeline to control whether the percolation pump 22 is connected to the inlet pipeline; a percolation pressure sensor 20 is provided on the percolation pipeline to monitor the pressure in the percolation pipeline in real time.

[0081] The outlet end face of the shale core 15 is connected to the venting pipeline and the backpressure pipeline, respectively, and the other end of the backpressure pipeline is connected to the backpressure pump 13. Preferably, the outlet end face of the shale core 15 is connected to the venting pipeline and the backpressure pipeline in sequence via the second side channel and the outlet pipeline, respectively. That is, one end of the outlet pipeline is connected to the second side channel of the non-magnetic core holder 16, and the other end is connected to the venting pipeline and the backpressure pipeline, respectively.

[0082] In a preferred embodiment of the present invention, a vent valve 11 is provided on the vent pipeline to control whether the outlet pipeline is connected to the vent pipeline; a back pressure pump valve 12 is provided on the back pressure pipeline to control whether the outlet pipeline is connected to the back pressure pipeline; and a downstream pressure sensor 10 is provided on the outlet pipeline to monitor the pressure in the outlet pipeline in real time.

[0083] The device for determining the shale's ultimate permeability depth and well stagnation time also includes a nuclear magnetic resonance (NMR) magnet 8 and a nuclear magnetic resonance (NMR) analyzer 14. The NMR magnet 8 is tubular, and the non-magnetic core holder 16 is disposed inside the NMR magnet 8. The inner circumferential surface of the NMR magnet 8 is connected to the outer surface of the non-magnetic core holder 16. The NMR magnet 8 is also connected to the NMR analyzer 14, allowing the NMR analyzer 14 to test the relaxation time spectrum, constant gradient stratigraphic spectrum, and NMR imaging of the shale core 15. Specifically, in this embodiment, one end of the NMR magnet 8 is connected to the outer circumferential surface of the non-magnetic core holder 16, and the other end is connected to the NMR analyzer 14.

[0084] Example 2

[0085] like Figures 2-9 As shown, the present invention provides a method for determining the shale limit absorption depth and well shut-in time. This method is based on the apparatus for determining the shale limit absorption depth and well shut-in time in Example 1, and specifically includes the following steps:

[0086] S1: Determining the shale's ultimate permeability depth and the first post-compression shut-in time T1 based on the apparatus of Example 1.

[0087] S11: Collect data.

[0088] Collect formation temperature, formation pressure, and bottom hole pressure of shale reservoirs when pumps are shut down during on-site fracturing operations.

[0089] S12: Fixed shale core 15.

[0090] Shale core 15 of the target layer of the shale reservoir is taken, dried to constant weight, and then installed in non-magnetic core holder 16.

[0091] S13: Simulates formation temperature, formation pressure, and bottom hole pressure during pump shutdown in shale reservoirs.

[0092] ① Open the confining pressure pump valve 18, and apply confining pressure to the circumference of the shale core 15 through the confining pressure pump 19; observe the confining pressure sensor 17 until the confining pressure value displayed is equal to the formation pressure in S11. It should be noted that after the confining pressure sensor 17 reaches the preset pressure, it is not necessary to turn off the confining pressure pump 19. The confining pressure pump 19 is always in the open state so that the circumferential confining pressure of the shale core 15 is always maintained at the preset pressure (i.e., the formation pressure in S11).

[0093] ② Heat the non-magnetic high-temperature module 9 using heater 6 and observe the temperature sensor 7 until the heating temperature displayed by the sensor equals the formation temperature in S11. It should be noted that after the temperature sensor 7 reaches the preset pressure, it is not necessary to turn off heater 6. Heater 6 remains on to keep the temperature of the shale non-magnetic high-temperature module 9 at the preset temperature (i.e., the formation temperature in S11).

[0094] ③ Open the back pressure pump valve 12, and apply back pressure to the outlet face of the shale core 15 through the back pressure pump 13; observe the downstream pressure sensor 10 until the back pressure value it displays is equal to the formation pressure. It should be noted that after the downstream pressure sensor 10 reaches the preset pressure, it is not necessary to turn off the back pressure pump 13. The back pressure pump 13 is always in the open state so that the pressure at the outlet face of the shale core 15 is always maintained at the preset pressure (i.e., formation pressure).

[0095] ④ Open the seepage pump valve 21 and pump seepage fluid into the inlet face of the shale core 15 through the seepage pump 22. Part of the seepage fluid will remain in the inlet pipeline outside the inlet face of the shale core 15, while some fluid will enter the first side channel and directly contact the inlet face of the shale core 15. Observe the seepage pressure sensor 20 until the displayed seepage pressure value equals the bottom hole pressure when the pump is stopped during on-site fracturing operations. It should be noted that after the seepage pressure sensor 20 reaches the preset pressure, it is not necessary to shut down the seepage pump 22. The seepage pump 22 remains open to ensure that the pressure at the inlet face of the shale core 15 is always maintained at the preset pressure (i.e., the bottom hole pressure when the pump is stopped during on-site fracturing operations).

[0096] S14 acquires relaxation time maps, constant gradient tomography maps, and nuclear magnetic resonance imaging (NMR) images.

[0097] At the initial moment of infiltration (i.e., when all steps ①②③④ in S13 reach the preset pressure or preset temperature), the nuclear magnetic resonance (NMR) analyzer 14 is turned on to test the relaxation time spectrum, constant gradient stratigraphic spectrum, and NMR imaging of the shale core 15. Specifically, the NMR analyzer 14 is turned on, and it acquires the relaxation time spectrum of the shale core 15 online in real time. At regular intervals, the online real-time acquisition of the relaxation time spectrum of the shale core 15 is stopped, and the constant gradient stratigraphic spectrum and NMR imaging of the shale core 15 are tested. After the test is completed, the acquisition of the relaxation time spectrum is immediately resumed, and this cycle is repeated.

[0098] It should be noted that, firstly, the time interval for data acquisition by the NMR analyzer 14 needs to be determined based on the on-site rock strata conditions, and no specific limitation is made here. Secondly, the relaxation time spectrum is automatically acquired online in real time by the NMR analyzer 14 without human intervention; however, the constant gradient layer selection spectrum and NMR imaging require human intervention. Specifically, the online real-time acquisition of the relaxation time spectrum of the shale core 15 should be stopped first. Then, after setting the test parameters according to the characteristics of the shale core 15, the constant gradient layer selection spectrum and NMR imaging are tested. When testing the constant gradient layer selection spectrum, the tuning frequencies of different layers need to be manually adjusted to the set values. Third, the relaxation time spectrum, constant gradient stratigraphic spectrum, and nuclear magnetic resonance imaging of shale core 15 were tested using a nuclear magnetic resonance analyzer 14, all of which are existing technologies. The method for testing the relaxation time spectrum is described in the literature "Study on Spontaneous Immersion Process of Shale Based on Nuclear Magnetic Resonance Technology", the method for testing the constant gradient stratigraphic spectrum is described in the literature "Study on the Intrusion Depth of Fracturing Fluid Immersion in the Matrix Pore of Shale Oil Reservoir in Da'anzhai Section, Central Sichuan", and the method for testing the nuclear magnetic resonance imaging is described in the literature "Nuclear Magnetic Resonance Experiment on Factors Affecting the Recovery Rate of Shale Oil by Carbon Dioxide Injection".

[0099] S15: In-situ permeability test.

[0100] Close the seepage pump valve 21 and the backpressure pump valve 12, and open the vent valve 11. At this time, the outlet end face of the shale core 15 returns to atmospheric pressure. It should be noted that the inlet end face of the shale core 15 does not return to atmospheric pressure at this time.

[0101] Gas is injected into upstream gas tank 2 through gas supply source 1. After upstream gas tank 2 is filled with gas, its pressure value is measured and upstream gas phase valve 3 is opened. The gas in upstream gas tank 2 enters the connecting pipeline 5, and then the gas passes through shale core 15 to reach the downstream. Upstream pressure sensor 4 is observed. When the pressure value of upstream pressure sensor 4 drops to 85% of the full pressure of upstream gas tank 2, the values ​​of upstream pressure sensor 4 and downstream pressure sensor 10 are collected. Based on the pressure records at different times, the in-situ permeability is obtained using the pressure drop method. The specific method is described in section 7.3 of GB / T 34533-2023, and will not be repeated here. When the pressure value of upstream pressure sensor 4 drops to 30% of the full pressure of upstream gas tank 2, the measurement is stopped. Upstream gas phase valve 3 and vent valve 11 are closed, and permeation pump valve 21 and backpressure pump valve 12 are opened to restart the permeation and backpressure of shale core 15.

[0102] S16: Repeat S14 and S15 to determine the shale's ultimate adsorption depth, adsorption depth equilibrium time Th, and permeability equilibrium. time.

[0103] Repeat steps S14 and S15, alternating between data acquisition by the NMR analyzer in S14 and in-situ permeability testing in S15, until the relaxation time spectrum signal amplitude (e.g., Figure 2 As shown in the figure, the constant gradient selection pattern does not change significantly over time, at which point the percolation experiment ends.

[0104] Determination of the shale's ultimate adsorption depth and the equilibrium time Th: Based on the relationship between the signal peak values ​​of each layer and time in the constant gradient stratigraphic map of shale core 15, and the relationship between signal imaging and location in the NMR imaging, the shale's ultimate adsorption depth is determined. Specifically, as follows... Figure 3 As shown, in the constant gradient stratigraphic plot, the horizontal axis represents the axial position of shale core 15, the zero point of the horizontal axis represents the position of the core inlet face, and the vertical axis represents the signal peak value. Analyzing the horizontal axis from the inlet face to the outlet face, when the signal quantity of a certain layer changes very little throughout the entire percolation process (e.g., less than 10%), and its value is reflected in the nuclear magnetic resonance imaging (NMR) image (e.g., ... Figure 4 If the seepage signal of the layer shown is very small, then the distance between the corresponding position of the layer and the inlet end face is taken as the shale limit seepage depth, and the seepage time corresponding to the shale limit seepage depth is taken as the seepage depth equilibrium time Th.

[0105] Determining the permeability equilibrium time: Plot an in-situ permeability curve, with the horizontal axis representing absorption time and the vertical axis representing permeability. Determine the permeability equilibrium time based on the plotted in-situ permeability curve. When the in-situ permeability gradually increases with absorption time (e.g., ... Figure 5 As shown), the inflection time corresponding to the inflection point of the in-situ permeability change curve is taken as the first permeability equilibrium time Tp1; when the in-situ permeability gradually decreases with the inflection time (as shown), Figure 6 As shown), the inflection time corresponding to the inflection point of the in-situ permeability change curve is taken as the second permeability equilibrium time Tp2. When the in-situ permeability first increases and then decreases with the permeation time (e.g. Figure 7 As shown), the absorption time corresponding to the maximum value of the in-situ permeability change curve is taken as the third permeability equilibrium time Tp3; when the in-situ permeability first decreases and then increases with absorption time (as shown in the figure), Figure 8 As shown in the figure, the infiltration time corresponding to the inflection point of the curve when the in-situ permeability change curve increases is taken as the fourth permeability equilibrium time Tp4.

[0106] S17: Determine the first post-pressure well shut-in time T1 based on the seepage depth equilibrium time Th and the permeability equilibrium time.

[0107] When the permeability equilibrium time is the first permeability equilibrium time Tp1, the larger value of the first permeability equilibrium time Tp1 and the seepage depth equilibrium time Th is taken as the first post-compression well shut-in time T1; when the permeability equilibrium time is the second permeability equilibrium time Tp2, well shut-in can be chosen not to be done on site. Considering the seepage depth equilibrium, the seepage depth equilibrium time Th is taken as the first post-compression well shut-in time T1. This setting is mainly to consider that seepage can alleviate water lock in the local location of shale core 15; when the permeability equilibrium time is the third permeability equilibrium time Tp3, the third permeability equilibrium time Tp3 is taken as the first post-compression well shut-in time T1; when the permeability equilibrium time is the fourth permeability equilibrium time Tp4, the fourth permeability equilibrium time Tp4 is taken as the first post-compression well shut-in time T1.

[0108] S2: Determine the second post-pressure shut-in time T2 based on the production capacity index F.

[0109] S21: Collect on-site parameters.

[0110] In one specific embodiment of the present invention, the field parameters include: the designed fracture height for field fracturing, the spacing of microfractures in shale core 15 observed by the permeation test, the width of the hydraulic fracture, the vertical permeability of the formation, the horizontal permeability of the formation, the viscosity of the fluid, the compressibility coefficient of the fluid, the amount of fracturing fluid used, the designed half-fracture length for field fracturing, the number of designed hydraulic fractures for field fracturing, the surface tension of the formation, the contact angle of the formation, the water saturation of the formation, the rate of decrease in bottom hole pressure during well shut-in, the bottom hole pressure during well shut-in, and the bottom hole pressure when the pump is stopped during field fracturing operations.

[0111] S22: The capacity index F is obtained based on the on-site parameters.

[0112] Using the field parameters collected in step S21, the production capacity index F is calculated. Specifically, it is obtained through the formula...

[0113] The capacity index F is calculated from equation (1) to equation (3).

[0114]

[0115]

[0116] In the formula, F is the capacity index, which is dimensionless; H f Design fracture height for on-site fracturing, m; w c L represents the average width of the microcracks, in meters (m). z The depth of horizontal microcracks after in-situ fracturing, in meters (m); h f The distance between microfractures in shale core 15 observed by the permeation experiment is shown in meters (m). f The width of the hydraulic fracture is in meters (m); k v The vertical permeability of the formation at the site is given by mD and k. f The horizontal permeability of the formation at the site is expressed in mD and μ. f Here, c represents the viscosity of the fluid in the field, in mPa·s; f The compressibility coefficient of the fluid in the field is given in MPa. -1 V f This refers to the amount of fracturing fluid used on-site, in m. 3 L x Design the half-fracturing length for in-situ fracturing, m; n f The number of hydraulic fractures designed for on-site fracturing is given; σ f θ represents the surface tension of the formation at the site, in N / m; θ represents the contact angle of the formation at the site, in °; S w The value represents the water saturation of the formation at the site, as a decimal. P represents the rate of decrease in bottom hole pressure during well shut-in, expressed in MPa / d. si P is the bottom hole pressure when the pump is shut down during on-site fracturing operations, in MPa; P is the bottom hole pressure during the on-site well shut-in period, in MPa; t is the seepage time during the on-site well shut-in period, in days.

[0117] It should be noted that only the rate of decrease in bottom hole pressure during the on-site well shut-in period is considered. The parameters P, the bottom pressure during the well blockage, need to be collected every time at the preset seepage time, while other parameters only need to be collected once.

[0118] S23: Plot the production capacity index curve to obtain the second post-pressure well shut-in time T2.

[0119] Plot the production capacity index F on the vertical axis and the infiltration time t on the horizontal axis to form a production capacity index curve. The infiltration time corresponding to the inflection point of the curve is taken as the second post-pressure well sealing time T2. The term "inflection point" will be explained in detail below. On the production capacity index curve, compare the slopes of the two curve segments before and after a certain point. If the larger slope is more than twice the smaller slope, then that point is the inflection point.

[0120] S3: Determine the optimized shale post-compression shut-in time based on the first post-compression shut-in time T1 and the second post-compression shut-in time T2.

[0121] The larger of the first post-compression well shut-in time T1 and the second post-compression well shut-in time T2 is used as the optimized shale post-compression well shut-in time. The first post-compression well shut-in time T1 is determined from two aspects: the seepage-absorption balance and permeability change during the shut-in period. The second post-compression well shut-in time T2 is determined from the perspective of post-shut-in productivity change. Using the larger of the two post-compression well shut-in times T1 and T2 as the optimized shale post-compression well shut-in time ensures that the final shale post-compression well shut-in time simultaneously satisfies the balance of seepage depth and the improvement of post-shut-in productivity, while also taking into account permeability balance.

[0122] The method for determining the shale's ultimate adsorption depth and well-closing time in this invention, on the one hand, achieves the purpose of considering adsorption depth by obtaining the shale's ultimate adsorption depth through testing. Specifically, the shale's ultimate adsorption depth obtained through testing can be further used to obtain the adsorption depth equilibrium time Th. During the post-compression well-closing period, reaching the "adsorption depth equilibrium time Th" will cause the adsorption fluid saturation to redistribute in the formation, which helps to alleviate water lock in the near-wellbore zone. On the other hand, the method for determining the shale's ultimate adsorption depth and well-closing time in this invention can evaluate the degree to which adsorption alleviates water lock and improves seepage capacity through in-situ permeability testing. Specifically, if the tested in-situ permeability increases, it indicates that adsorption has alleviated water lock and improved seepage capacity; while if the tested in-situ permeability decreases, it indicates that although adsorption has alleviated water lock in a local location of the shale core 15, it has damaged the overall seepage capacity.

[0123] Experimental Example 1

[0124] Taking the X8 shale gas well in the Sichuan Basin as an example, the device for determining the shale's ultimate permeability depth and well shut-in time in Example 1 was used to optimize the well shut-in time after pressure and determine the well shut-in time after pressure.

[0125] S1: Determining the shale's ultimate permeability depth and the first post-compression shut-in time T1 based on the apparatus of Example 1.

[0126] S11: Collect data.

[0127] The formation temperature of the shale reservoir in well X8 was 70℃, the formation pressure was 30MPa, and the bottom hole pressure was 45MPa when the pump was stopped during on-site fracturing operations.

[0128] S12: Fixed shale core 15.

[0129] Shale core 15 from the target layer of the shale reservoir in well X8 was taken. It was a standard columnar core with a length of 5 cm and a diameter of 2.54 cm. After drying the shale core 15 to constant weight at 105℃, the shale core 15 was installed in the non-magnetic core holder 16.

[0130] S13: Simulates formation temperature, formation pressure, and bottom hole pressure during pump shutdown in shale reservoirs.

[0131] ① Open the confining pressure pump valve 18 and apply confining pressure to the circumference of the shale core 15 through the confining pressure pump 19; observe the confining pressure sensor 17 until the confining pressure value displayed is equal to the formation pressure in S11, that is, the confining pressure value is equal to the formation pressure of 30MPa.

[0132] ② Heat the non-magnetic high-temperature module 9 through heater 6 and observe the temperature sensor 7 until the heating temperature displayed by it is equal to the formation temperature in S11, that is, the heating temperature is equal to the formation temperature of 70℃.

[0133] ③ Open the seepage pump valve 21 and pump the seepage fluid into the inlet face of the shale core 15 through the seepage pump 22. The seepage fluid is the fracturing fluid used in the X8 well. Observe the seepage pressure sensor 20 until the seepage pressure value it displays is equal to the bottom hole pressure when the pump is stopped during the fracturing operation, that is, the seepage pressure value is equal to the bottom hole pressure of 45MPa when the pump is stopped during the fracturing operation.

[0134] ④ Open the back pressure pump valve 12 and apply back pressure to the outlet end face of the shale core 15 through the back pressure pump 13. Observe the downstream pressure sensor 10 until the back pressure value it displays is equal to the formation pressure, that is, the back pressure value is equal to the formation pressure of 30MPa.

[0135] S14 acquires relaxation time maps, constant gradient tomography maps, and nuclear magnetic resonance imaging (NMR) images.

[0136] At the initial moment of infiltration, the nuclear magnetic resonance (NMR) analyzer 14 was activated to test the relaxation time spectrum, constant gradient stratigraphic spectrum, and NMR imaging of the shale core 15. Specifically, the NMR analyzer 14 was activated to acquire the relaxation time spectrum of the shale core 15 online in real time. At regular intervals, the online real-time acquisition of the relaxation time spectrum of the shale core 15 was stopped, and the constant gradient stratigraphic spectrum and NMR imaging of the shale core 15 were tested. It should be noted that the acquisition time of the relaxation time spectrum by the NMR analyzer 14 in this experimental example is as follows: Figure 2 As shown, this is merely an illustrative example and does not constitute a limitation of the present invention.

[0137] S15: In-situ permeability test.

[0138] Close the permeation pump valve 21 and the backpressure pump valve 12, and open the vent valve 11. Inject helium gas into the upstream gas tank 2 through the gas supply source 1. After the upstream gas tank 2 is full, test its pressure value and open the upstream gas phase valve 3, allowing the gas in the upstream gas tank 2 to enter the connecting pipeline 5. Observe the upstream pressure sensor 4. When the pressure value of the upstream pressure sensor 4 drops to 85% of the full pressure of the upstream gas tank 2, start collecting the values ​​of the upstream pressure sensor 4 and the downstream pressure sensor 10. Based on the pressure records at different times, apply the pressure drop method to obtain the in-situ permeability. Close the upstream gas phase valve 3 and the vent valve 11, and open the permeation pump valve 21 and the backpressure pump valve 12 to restart the permeation of the shale core 15.

[0139] S16: Repeat S14 and S15 to determine the shale's ultimate adsorption depth, adsorption depth equilibrium time Th, and permeability equilibrium. time.

[0140] Repeat steps S14 and S15, alternating between data acquisition using the NMR analyzer in S14 and in-situ permeability testing in S15, until the relaxation time spectrum signal amplitude and the constant gradient layer selection spectrum show essentially no change over time, at which point the permeation experiment is terminated. Specifically, in this experimental example, as... Figure 2 As shown, the relaxation time spectrum signal amplitude and Figure 3 The constant gradient selection pattern remained essentially unchanged over approximately 14 days of infiltration; therefore, the infiltration experiment was terminated after 14 days of infiltration.

[0141] Determination of the shale's ultimate adsorption depth and the adsorption depth equilibrium time Th: The ultimate adsorption depth of shale is determined based on the relationship between the signal peak value of each layer and time in the constant gradient stratigraphic map of shale core 15, and the relationship between signal imaging and position in the NMR image. In the constant gradient stratigraphic map, the horizontal axis represents the axial position of shale core 15, the zero point of the horizontal axis represents the position of the core inlet face, and the vertical axis represents the signal peak value. Analyzing from the inlet face to the outlet face on the horizontal axis, when the signal quantity of a certain layer changes very little during the entire adsorption process (e.g., less than 10%), and the adsorption signal quantity of that layer in the NMR image is very small, the distance between the corresponding position of that layer and the inlet face is taken as the ultimate adsorption depth of shale. The adsorption time corresponding to reaching the ultimate adsorption depth of shale is the adsorption depth equilibrium time Th.

[0142] Specifically, in this experimental example, such as Figure 3 As shown, in the constant gradient stratigraphic pattern of the shale core 15 of well X8, the signal intensity of the layer located 41 mm from the core inlet face changes by 9.2% throughout the entire permeation process, which is less than 10%. Figure 4 This shows an NMR image of the layer 41 mm from the inlet face of shale core 15. Figure 4The NMR image of this layer shows a very dark color, indicating a very small amount of seepage signal. Therefore, the location corresponding to this layer (41 mm from the inlet face of shale core 15) is taken as the shale's limiting seepage depth, resulting in a limiting seepage depth of 41 mm. The corresponding time, 12 days, is the seepage depth equilibrium time Th. Therefore, the limiting seepage depth of the shale is determined to be 41 mm, and the seepage depth equilibrium time Th is 12 days.

[0143] Determination of permeability equilibrium time: Plot the in-situ permeability variation curve, with the horizontal axis representing the absorption time and the vertical axis representing permeability, to determine the permeability equilibrium time. Specifically, in this experimental example, the in-situ permeability variation curve of shale core 15 from well X8 is as follows: Figure 5 As shown, by Figure 5 It can be seen that the in-situ permeability gradually increases with the absorption time. The inflection point of the in-situ permeability change curve corresponds to an absorption time of 10 days, so this is taken as the first permeability equilibrium time Tp1. Therefore, the first permeability equilibrium time Tp1 is determined to be 10 days.

[0144] S17: Determine the first post-pressure well shut-in time T1 based on the seepage depth equilibrium time Th and the permeability equilibrium time.

[0145] When the permeability equilibrium time is the first permeability equilibrium time Tp1, the larger value of the first permeability equilibrium time Tp1 and the permeation depth equilibrium time Th is taken as the first post-compression shut-in time T1. Specifically, in this experimental example, the permeability equilibrium time of well X8 is the first permeability equilibrium time Tp1, and the larger value of the first permeability equilibrium time Tp1 (10d) and the permeation depth equilibrium time Th (12d) is taken as the first post-compression shut-in time T1. Therefore, the first post-compression shut-in time T1 of well X8 is determined to be 12d.

[0146] S2: Determine the second post-pressure shut-in time T2 based on the production capacity index F.

[0147] S21: Collect on-site parameters.

[0148] Field parameters were collected from Well X8, including: a designed fracture height of 30m, a microfracture spacing of 0.005m observed in the shale core 15 during the permeation test, a hydraulic fracture width of 0.006m, a vertical permeability of 0.002mD, a horizontal permeability of 0.02mD, a fluid viscosity of 3mPa·s, and a fluid compressibility of 0.0004MPa. -1 67,000 m³ of fracturing fluid was used on site. 3The design parameters for the on-site fracturing are as follows: half-fracture length 220m, number of hydraulic fractures 190, formation surface tension 0.06N / m, formation contact angle 60°, formation water saturation 0.3, bottom hole pressure reduction rate during well shut-in period -0.5MPa / d, bottom hole pressure during well shut-in period 38MPa, and bottom hole pressure when pump is stopped during on-site fracturing operation 46MPa.

[0149] S22: The capacity index F is obtained based on the on-site parameters.

[0150] The production capacity index F is calculated using the field parameters collected in step S21. Specifically, the production capacity index F is calculated using equations (1) to (3).

[0151]

[0152] In the formula, F is the capacity index, which is dimensionless; H f Design fracture height for on-site fracturing, m; w c L represents the average width of the microcracks, in meters (m). z The depth of horizontal microcracks after in-situ fracturing, in meters (m); h f The distance between microfractures in shale core 15 observed by the permeation experiment is shown in meters (m). f The width of the hydraulic fracture is in meters (m); k v The vertical permeability of the formation at the site is given by mD and k. f The horizontal permeability of the formation at the site is expressed in mD and μ. f Here, c represents the viscosity of the fluid in the field, in mPa·s; f The compressibility coefficient of the fluid in the field is given in MPa. -1 V f This refers to the amount of fracturing fluid used on-site, in m. 3 L x Design the half-fracturing length for in-situ fracturing, m; n f The number of hydraulic fractures designed for on-site fracturing is given; σ f θ represents the surface tension of the formation at the site, in N / m; θ represents the contact angle of the formation at the site, in °; S w The value represents the water saturation of the formation at the site, as a decimal. P represents the rate of decrease in bottom hole pressure during well shut-in, expressed in MPa / d. si P is the bottom hole pressure when the pump is shut down during on-site fracturing operations, in MPa; P is the bottom hole pressure during the on-site well shut-in period, in MPa; t is the seepage time during the on-site well shut-in period, in days.

[0153] S23: Plot the production capacity index curve to obtain the second post-pressure well shut-in time T2.

[0154] Plot the productivity index F on the vertical axis and the absorption time on the horizontal axis to obtain the productivity index curve. The absorption time corresponding to the inflection point of the curve is taken as the second post-compression shut-in time T2. Specifically, in this experimental example, the productivity index curve of well X8 is as follows: Figure 9 As shown, the seepage time of 13 days corresponding to the inflection point of the curve is taken as the second post-pressure sealing time T2. Therefore, the second post-pressure sealing time T2 of well X8 is determined to be 13 days.

[0155] S3: Determine the optimized shale post-compression shut-in time based on the first post-compression shut-in time T1 and the second post-compression shut-in time T2.

[0156] The larger of the first post-compression shut-in time T1 and the second post-compression shut-in time T2 is taken as the optimized shale post-compression shut-in time. Specifically, in this experimental example, the larger of the first post-compression shut-in time T1 (12 days) and the second post-compression shut-in time T2 (13 days) for well X8 is 13 days, therefore it is taken as the optimized shale post-compression shut-in time for well X8. In summary, the shut-in time for well X8 is determined to be 13 days.

[0157] In the description of this invention, it should be noted that, unless otherwise explicitly specified and limited, the terms "connected" and "linked" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral connection; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium. Those skilled in the art can understand the specific meaning of the above terms in this invention according to the specific circumstances.

[0158] In the description of this invention, unless otherwise stated, the terms "upper," "lower," "left," "right," "inner," "outer," etc., indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings. They are used only for the convenience of describing this invention and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, they should not be construed as limitations on this invention.

[0159] The above technical solution is only one embodiment of the present invention. For those skilled in the art, based on the principles disclosed in the present invention, it is easy to make various types of improvements or modifications, and not limited to the technical solutions described in the specific embodiments of the present invention. Therefore, the foregoing description is only a preferred option and is not restrictive.

Claims

1. A device for determining the ultimate permeability depth and well shut-in time of shale, characterized in that, include A non-magnetic core holder is used to be fitted over and hold a shale core; the non-magnetic core holder is equipped with a non-magnetic high-temperature module. A confining pressure pump is connected to the inner circumferential surface of the non-magnetic core holder; An upstream gas tank is used to connect to the inlet end face of the shale core. A seepage pump is used to connect to the inlet end face of the shale core. A back pressure pump is used to connect to the outlet end face of the shale core. A venting pipeline is used to connect to the outlet end face of the shale core. The nuclear magnetic resonance magnet is sleeved on the outside of the non-magnetic core holder and connected to the nuclear magnetic resonance analyzer and the non-magnetic core holder respectively.

2. The apparatus according to claim 1, characterized in that, The inner circumferential surface of the non-magnetic core holder is provided with an annular channel; the annular channel is connected to the confining pressure pump; and / or The non-magnetic core holder has a first side channel on its first inner surface; the first side channel is connected to the seepage pump; and / or The second inner side of the non-magnetic core holder is provided with a second side channel; the second side channel is connected to the back pressure pump.

3. The apparatus according to claim 1, characterized in that, The non-magnetic core holder is connected to the confining pressure pump via a confining pressure pipeline, on which a confining pressure pump valve and / or a confining pressure sensor are provided; and / or The upstream gas tank is connected to the inlet face of the shale core via a connecting pipeline. An upstream gas phase valve and / or an upstream pressure sensor are installed on the connecting pipeline; and / or The percolation pump is connected to the inlet face of the shale core via a percolation pipeline. A percolation pump valve and / or a percolation pressure sensor are installed on the percolation pipeline; and / or The back pressure pump is connected to the outlet face of the shale core via a back pressure pipeline, and a back pressure pump valve is provided on the back pressure pipeline; and / or A vent valve is installed on the vent pipeline; Preferably, an outlet pipeline is provided at the junction of the back pressure pipeline and the seepage pipeline, and the outlet pipeline is connected to the outlet end face of the shale core; a downstream pressure sensor is provided on the outlet pipeline; More preferably, the upstream gas tank is also connected to a gas supply source.

4. The apparatus according to claim 1, characterized in that, The non-magnetic high-temperature module is also connected to a heating device; and / or The non-magnetic core holder is also equipped with a temperature sensor, which is connected to the non-magnetic high-temperature module.

5. The apparatus according to claim 1, characterized in that, The inner circumferential surface of the non-magnetic core holder is provided with a rubber inner sleeve.

6. A method for determining the ultimate permeability depth and well shut-in time of shale, characterized in that, Includes the following steps: S1: Determine the first post-pressure well-clogging time based on the apparatus of any one of claims 1 to 5; S2: Determine the second post-pressure well shut-in time based on the production capacity index; S3: Determine the optimized shale well-closing time based on the first and second post-compression closing times; take the larger of the two post-compression closing times as the optimized shale well-closing time.

7. The method according to claim 6, characterized in that, Step S1 includes: S11: Collect data, including formation temperature, formation pressure, and bottom hole pressure of the shale reservoir when the pump is shut down during on-site fracturing operations; S12: Fix the shale core using the device described in any one of claims 1 to 5; S13: Simulates formation temperature, formation pressure, and bottom hole pressure during pump shutdown in shale reservoirs; S14, Acquire relaxation time spectrum, constant gradient stratigraphic spectrum and nuclear magnetic resonance imaging of shale cores; S15: In-situ permeability test; S16: Repeat S14 and S15 to determine the shale's ultimate adsorption depth and permeability equilibrium time, and determine the adsorption depth equilibrium time based on the shale's ultimate adsorption depth. S17: Determine the first post-pressure well shut-in time based on the seepage depth equilibrium time and permeability equilibrium time.

8. The method according to claim 6, characterized in that, In step S13, confining pressure is applied to the circumference of the shale core using a confining pressure pump until the circumferential confining pressure value of the shale core equals the formation pressure in S11; the non-magnetic high-temperature module is heated until its temperature equals the formation temperature in S11; back pressure is applied to the outlet end face of the shale core using a back pressure pump until its back pressure value equals the formation pressure; and a percolation fluid is pumped into the inlet end face of the shale core using a percolation pump until its percolation pressure value equals the bottom hole pressure when the pump is stopped during on-site fracturing operations; and / or, In step S15, the outlet end face of the shale core is restored to normal pressure; gas is injected into the upstream gas tank, and after the upstream gas tank is filled with gas, the pressure values ​​of the connecting pipeline and the outlet pipeline are collected; the seepage and backpressure of the shale core are repeated. And / or, In step S16, the shale's ultimate adsorption depth is determined based on the constant gradient stratigraphic pattern and nuclear magnetic resonance imaging of the shale core, and the adsorption depth equilibrium time is determined based on the shale's ultimate adsorption depth. Based on the infiltration time and permeability, an in-situ permeability change curve is plotted, and the permeability equilibrium time is obtained based on the in-situ permeability change curve. And / or, In step S17, when the permeability equilibrium time is the first permeability equilibrium time, the larger value between the first permeability equilibrium time and the permeation depth equilibrium time is taken as the first post-pressure well shut-in time; when the permeability equilibrium time is the second permeability equilibrium time, the permeation depth equilibrium time is taken as the first post-pressure well shut-in time; when the permeability equilibrium time is the third permeability equilibrium time, the third permeability equilibrium time is taken as the first post-pressure well shut-in time; when the permeability equilibrium time is the fourth permeability equilibrium time, the fourth permeability equilibrium time is taken as the first post-pressure well shut-in time.

9. The method according to claim 6, characterized in that, Step S2 includes: S21: Collect on-site parameters; S22: The production capacity index is obtained based on on-site parameters; S23: Plot the capacity index curve based on the penetration time and capacity index, and obtain the second post-pressure well shut-in time based on the capacity index curve.

10. The method according to claim 9, characterized in that, In step S21, the field parameters include: the designed fracture height, the spacing of microfractures in the shale core observed by the permeation test, the hydraulic fracture width, the vertical permeability of the formation, the horizontal permeability of the formation, the viscosity of the fluid, the compressibility coefficient of the fluid, the amount of fracturing fluid used, the designed half-fracture length, the designed number of hydraulic fractures, the surface tension of the formation, the contact angle of the formation, the water saturation of the formation, the rate of decrease in bottom hole pressure during well shut-in, the bottom hole pressure during well shut-in, and the bottom hole pressure when the pump is stopped during fracturing operations; and / or In step S22, the capacity index is calculated using equations (1) to (3). In the formula, F is the production capacity index; H f Design joint height for on-site fracturing; w c L represents the average width of the microcracks. z h represents the depth of horizontal microcracks after in-situ hydraulic fracturing. f The spacing of microfractures in shale cores observed by infiltration experiments; w f The width of the hydraulic fracture; k v k represents the vertical permeability of the formation at the site. f The horizontal permeability of the formation at the site; μ f c represents the viscosity of the fluid in the field. f V is the compressibility coefficient of the fluid in the field. f This refers to the amount of fracturing fluid used in the field; L x Design half-fracturing length for on-site fracturing; n f The number of hydraulic fractures to be designed for on-site fracturing; σ f The surface tension of the formation at the site; θ is the contact angle of the formation at the site; S w The water saturation of the formation at the site; P represents the rate of decrease in bottom hole pressure during well shut-in. si P is the bottom hole pressure when the pump is shut down during on-site fracturing operations; t is the bottom hole pressure during the on-site well shut-in period; and / or In step S23, a production capacity index curve is plotted based on the infiltration time and the production capacity index, and the infiltration time corresponding to the inflection point of the production capacity index curve is taken as the second post-pressure well shut-in time.

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