Method for determining reasonable soaking time for shale oil / gas well

Abstract

Provided in the embodiments of the present description is a method for determining a reasonable soaking time for a shale oil / gas well. The determination method uses a shale oil / gas well reasonable soaking time testing apparatus to carry out testing experiments, and comprises: selecting a rock core sample; measuring to obtain the porosity of the rock core sample; simulating the in-reservoir state of a first rock core sample; injecting methane and reaching the reservoir pore pressure; injecting a simulated fracturing fluid into a rock core clamping holder; measuring the resistivity change curve of the first rock core sample; measuring and obtaining the pressure attenuation half-life of a first pressure sensor until an inflection point appears on the resistivity change curve of the first rock core sample; obtaining the experiment durations under which the first rock core sample and a second rock core sample have the shortest pressure attenuation half-life; obtaining the time points at which the first rock core sample and the second rock core sample exhibit maximum rock core nuclear magnetic signal change amplitude; after sorting, obtaining a soaking time at the rock core scale; and obtaining a soaking time for the shale oil / gas well.

Description

A method for determining the reasonable soaking time of shale oil / gas wells

[0001] Cross-references

[0002] This application claims priority to Chinese application No. 202311520005.2 filed on November 15, 2023, the entire contents of which are incorporated herein by reference. Technical Field

[0003] The present invention relates to the technical field of oil and gas development, and in particular to a method for determining a reasonable shut-in time for a shale oil / gas well. Background Art

[0004] Horizontal well and staged fracturing technologies are effective means of achieving efficient shale oil and gas development. Large quantities of fracturing fluid are required during hydraulic fracturing. However, due to the extremely dense shale reservoirs, the reservoir porosity and permeability are primarily composed of micro- and nano-scale pores and fractures. The reservoirs have low porosity and permeability, are characterized by well-developed lamellation, and contain high clay mineral content, resulting in a low flowback rate for the fracturing fluid.

[0005] In shale oil / gas well production practice and indoor research, it was found that after the hydraulic fracturing transformation of the production well was completed and the well was shut down for a certain period of time, the initial production was higher than that of the well without shutting down, resulting in the phenomenon of "low return rate and initial high production".

[0006] Therefore, a method for determining the reasonable shut-in time of shale oil / gas wells that is simple in logic, accurate and reliable is needed.

[0007] Summary of the Invention

[0008] One or more embodiments of the present specification provide a method for determining a reasonable shut-in time of a shale gas well. The method uses a shale gas well reasonable shut-in time testing device for testing, the shale gas well reasonable shut-in time testing device comprising an online nuclear magnetic resonance tester, a core holder arranged on the online nuclear magnetic resonance tester, a resistivity tester connected to the core holder, a methane gas cylinder connected to the inlet of the core holder, a simulated fracturing fluid injection pump connected to the inlet of the core holder, a nitrogen gas cylinder connected to the inlet of the core holder, a first pressure sensor connected to the inlet of the core holder, a vacuum pump connected to the core holder, a confining pressure pump connected to the core holder, and a pressure relief valve connected to the inlet of the core holder. A second pressure sensor connected to the core holder, a throttle valve connected to the outlet of the methane cylinder, a first valve connected to the outlet of the throttle valve, a third valve connected to the outlet of the first valve, a fifth valve connected to the outlet of the core holder, and a computer control system electrically connected to the first pressure sensor, the second pressure sensor and the core holder, respectively. A core sample to be tested is placed in the core holder. The resistivity tester detects the resistivity of the core sample to be tested in the core holder. The online nuclear magnetic resonance tester and the core holder are placed in a constant temperature chamber.The method for determining the reasonable soaking time of a shale gas well comprises the following steps: step S1, respectively selecting several first core samples with natural cracks on the surface and second core samples without natural cracks on the surface; washing the first core sample and the second core sample with salt, washing the oil and drying; measuring the length and diameter of the first core sample and the second core sample, and obtaining the volume of the first core sample and the second core sample; respectively measuring and obtaining the porosity Φ0 of the first core sample and the second core sample; step S2, presetting the temperature in the constant temperature chamber to the temperature of the reservoir where the first core sample and the second core sample are located, placing the first core sample in the core holder, starting the confining pressure pump, and applying core confining pressure to the first core sample in the core holder; and evacuating the core holder using the vacuum pump. , simulate the state of the first core sample in the reservoir; step S3, use the methane gas cylinder to inject methane into the first core sample in the core holder until the pore pressure of the reservoir is reached, and maintain the pressure for 4 days; step S4, start the simulated fracturing fluid injection pump, and inject simulated fracturing fluid into the core holder; close the third valve; step S5, start the resistivity tester, measure the resistivity change curve of the first core sample; at the same time, use the pressure decay method to continuously measure and obtain the half-life of the pressure decay of the first pressure sensor until the resistivity change curve of the first core sample has an inflection point; step S6, replace the first core sample in the core holder with the second core sample, repeat steps S2 to S5; respectively calculate the experimental time t for the shortest pressure decay half-life of the first core sample. 1f The experimental duration t at which the shortest pressure decay half-life occurs in the second core sample 1m During the period from the injection of the simulated fracturing fluid in step S4 to the occurrence of an inflection point in the resistivity change curve in step S5, the online nuclear magnetic resonance tester is used to continuously monitor the methane nuclear magnetic signals of the first core sample and the second core sample, and the time point t at which the core nuclear magnetic resonance signal of the first core sample has the largest change amplitude is obtained. 2f The time point t at which the core nuclear magnetic signal of the second core sample changes the most is 2m Step S7, the experimental time t of the shortest pressure decay half-life of the first core sample 1f , the experimental duration t of the shortest pressure decay half-life of the second core sample 1m , the time point t at which the core nuclear magnetic signal of the first core sample changes the most 2f The time point t at which the core nuclear magnetic signal of the second core sample changes the most is 2mSort the arrays and take the two middle arrays after sorting as the time endpoints. The values ​​in the time endpoints are the soaking time t at the core scale. c Step S8, according to the soaking time t under the core scale c Calculate the shut-in time t of shale gas well R , which is expressed as: Wherein, V2 represents the total volume of reservoir reformed by hydraulic fracturing; V3 represents the total volume of sand-filled fractures formed in the reservoir after hydraulic fracturing; V c represents the volume of simulated fracturing fluid pumped in to establish the target water saturation of the core; V1 represents the volume of the first core sample or the second core sample; V f Indicates the volume of fracturing fluid pumped in during on-site hydraulic fracturing construction; Φ m It represents the reservoir porosity after removing hydraulic fractures in the total hydraulic fracturing stimulation area. BRIEF DESCRIPTION OF THE DRAWINGS

[0009] This specification will be further described in the form of exemplary embodiments, which will be described in detail with reference to the accompanying drawings. These embodiments are not limiting, and in these embodiments, like numbers represent like structures, wherein:

[0010] FIG1 is a schematic structural diagram of a device for testing a reasonable soaking time of a shale gas well according to some embodiments of this specification;

[0011] FIG2 is a schematic diagram of a device for testing a reasonable soaking time of a shale oil well according to some embodiments of this specification; and

[0012] FIG3 is a graph showing the relationship between core resistivity change and soaking time during an experiment according to some embodiments of this specification. DETAILED DESCRIPTION

[0013] To more clearly illustrate the technical solutions of the embodiments of this specification, the following briefly describes the drawings required for describing the embodiments. Obviously, the drawings described below are merely examples or embodiments of this specification. Those skilled in the art can apply this specification to other similar scenarios based on these drawings without inventive effort. Unless otherwise apparent from the context or otherwise noted, the same reference numerals in the figures represent the same structure or operation.

[0014] It should be understood that the terms "system," "device," "unit," and / or "module" used herein are a method for distinguishing different components, elements, parts, portions, or assemblies at different levels. However, if other terms can achieve the same purpose, the terms may be replaced by other expressions.

[0015] Figure 1 is a schematic diagram of a device for testing the reasonable shut-in time of a shale gas well, according to some embodiments of this specification. It should be noted that the dotted area in Figure 1 represents the space within the constant-temperature chamber. Furthermore, the dashed lines represent the electrical connections between the first and second pressure sensors 6 and 19 and the computer control system 21. The double-dotted long dashed line represents the nuclear magnetic resonance region.

[0016] The shale gas well reasonable soaking time testing device is used to determine the optimal soaking time under reservoir temperature and pressure conditions, and taking into account the influence of methane adsorbed gas on the imbibition behavior of fracturing fluid, through indoor experimental equipment and methods.

[0017] In some embodiments, as shown in FIG1 , a shale gas well reasonable soaking time testing device includes an online nuclear magnetic resonance tester 9, a core holder 12 arranged on the online nuclear magnetic resonance tester 9, a resistivity tester 7 connected to the core holder 12, a methane gas cylinder 1 connected to the inlet of the core holder 12, a simulated fracturing fluid injection pump 14 connected to the inlet of the core holder 12, a nitrogen gas cylinder 4 connected to the inlet of the core holder 12, a first pressure sensor 6 connected to the inlet of the core holder 12, a vacuum pump 17 connected to the core holder 12, a confining pressure pump 18 connected to the core holder 12, and a pressure relief valve 19 connected to the inlet of the core holder 12. A second pressure sensor 19 connected to the methane cylinder 12, a throttle valve 2 connected to the outlet of the methane cylinder 1, a first valve 3 connected to the outlet of the throttle valve 2, a third valve 10 connected to the outlet of the first valve 3, a fifth valve 13 connected to the outlet of the core holder 12, and a computer control system 21 electrically connected to the first pressure sensor 6, the second pressure sensor 19 and the core holder 12, respectively. A core sample to be tested is placed in the core holder 12, a resistivity tester 7 detects the resistivity of the core sample to be tested in the core holder 12, and the online nuclear magnetic resonance tester 9 and the core holder 12 are arranged in a constant temperature chamber 16.

[0018] The online nuclear magnetic resonance tester 9 refers to a device for monitoring nuclear magnetic signals, for example, for monitoring methane nuclear magnetic signals. In some embodiments, the online nuclear magnetic resonance tester 9 can be configured to monitor the methane nuclear magnetic signals of the first core sample and the second core sample. For more information about the first core sample and the second core sample, please refer to the relevant description below. In some embodiments, the online nuclear magnetic resonance tester 9 can be set in a constant temperature chamber 16. The constant temperature chamber 16 refers to a device for providing a stable temperature environment. In some embodiments, the constant temperature chamber 16 can be an enclosed space with an internal temperature constant within a preset temperature range. The preset temperature range can be determined based on manual experience. For more information about the constant temperature chamber 16, please refer to the relevant content below.

[0019] The core holder 12 is a device for placing a core sample. In some embodiments, the core holder 12 can hold a core sample to be tested. For example, the core holder 12 can hold a first core sample and a second core sample. In some embodiments, the core holder 12 can be mounted on an online nuclear magnetic resonance tester 9. In some embodiments, the core holder 12 can be placed in a constant temperature chamber 16.

[0020] The resistivity tester 7 is a device for measuring resistivity. In some embodiments, the resistivity tester 7 can be connected to the core holder 12. In some embodiments, the resistivity tester 7 can be configured to detect the resistivity of a core sample to be tested in the core holder 12. For example, the resistivity tester 7 can measure the resistivity curve of a first core sample.

[0021] The methane cylinder 1 is a device for storing and transporting methane gas. For example, the methane cylinder 1 can be configured to inject methane into a first core sample. In some embodiments, the methane cylinder 1 is connected to an inlet of a core holder 12.

[0022] The simulated fracturing fluid injection pump 14 is a device for injecting simulated fracturing fluid. For example, the simulated fracturing fluid injection pump 14 can be configured to inject simulated fracturing fluid into the core holder 12. In some embodiments, the simulated fracturing fluid injection pump 14 can be connected to an inlet of the core holder 12.

[0023] A simulated fracturing fluid is a fluid used to simulate the actual fracturing process on a core sample. In some embodiments, the simulated fracturing fluid may include a base fluid, such as deionized water. In some embodiments, the simulated fracturing fluid may include a thickener, such as guar gum. In some embodiments, the simulated fracturing fluid may include a crosslinker, such as boric acid. In some embodiments, the simulated fracturing fluid may include a breaker, such as ammonium persulfate.

[0024] The nitrogen cylinder 4 is a device for storing and transporting high-pressure nitrogen. In some embodiments, the nitrogen cylinder 4 can be configured to be connected to an inlet of the core holder 12.

[0025] The first pressure sensor 6 is a device for collecting pressure data. In some embodiments, the first pressure sensor 6 can be used to collect pressure data within the core holder 12. In some embodiments, as shown in FIG1 , the first pressure sensor 6 can be configured to be connected to the core holder 12.

[0026] The vacuum pump 17 is a device used for vacuuming. In some embodiments, the vacuum pump 17 can be configured to evacuate the core holder 12 to simulate the state of the core sample in a reservoir. A reservoir refers to a subsurface rock formation capable of storing and producing oil and gas. In some embodiments, as shown in FIG1 , the vacuum pump 17 can be configured to be connected to the core holder 12.

[0027] Confining pressure pump 18 is a device used to apply confining pressure to the core. In some embodiments, confining pressure pump 18 can be configured to apply confining pressure to the core sample. Confining pressure refers to external pressure applied to the core sample to simulate the actual pressure environment of the reservoir. In some embodiments, as shown in Figure 1, confining pressure pump 18 can be configured to be connected to core holder 12.

[0028] The second pressure sensor 19 is a device for collecting pressure data. In some embodiments, as shown in FIG1 , the second pressure sensor 19 can be configured to be connected to the core holder 12 .

[0029] The throttle valve 2 is a valve used to adjust the flow rate and pressure of the methane cylinder 1. In some embodiments, as shown in FIG1 , the throttle valve 2 can be configured to be connected to the outlet of the methane cylinder 1 and to the inlet of the first valve 3. In some embodiments, the throttle valve 2 can be used to adjust the methane flow rate of the methane cylinder 1.

[0030] The first valve 3 is a valve for adjusting the flow rate and pressure of the methane cylinder 1. In some embodiments, the first valve 3 can be configured to be connected to the outlet of the throttle valve 2. For example, as shown in FIG1 , the inlet of the first valve 3 is connected to the outlet of the throttle valve 2.

[0031] The third valve 10 is a valve for regulating the flow of gas and fluid into the core holder 12. In some embodiments, as shown in FIG1 , the third valve 10 can be configured to connect to the outlet of the first valve 3 and the outlet of the sixth valve 15.

[0032] The fifth valve 13 is a valve for regulating the outflow of gas and fluid in the core holder 12. In some embodiments, as shown in FIG1 , the fifth valve 13 can be configured to be connected to an outlet of the core holder 12.

[0033] The computer control system 21 is a device used to process and store data related to the shale gas well reasonable shut-in time test device. For example, the computer control system 21 can obtain temperature data collected by a temperature sensor, pressure data collected by a pressure monitoring device, and analysis results generated by an image analysis device. In some embodiments, the computer control system 21 can be connected to the first pressure sensor 6, the second pressure sensor 19, and the core holder 12.

[0034] In some embodiments, as shown in Figure 1 , a second valve 5 , a buffer container 8 , and a fourth valve 11 are connected in series between the nitrogen cylinder 4 and the core holder 12 . The second valve 5 is a device for controlling the flow of nitrogen into the core holder 12 . The fourth valve 11 is a device for controlling the flow of nitrogen into the core holder 12 . The buffer container 8 is a device for temporarily storing nitrogen. In some embodiments, as shown in Figure 1 , the inlet and outlet of the buffer container 8 can be connected to the outlet of the second valve 5 and the inlet of the fourth valve 11 , respectively.

[0035] By configuring the second valve and the fourth valve, the speed at which nitrogen enters the core holder can be adjusted; the pressure fluctuation when nitrogen flows into the core holder can be reduced by the buffer container, thereby ensuring that nitrogen is injected into the core holder more smoothly.

[0036] In some embodiments, a sixth valve 15 is disposed between the simulated fracturing fluid injection pump 14 and the third valve 10. The sixth valve 15 is a device for regulating the outflow of the simulated fracturing fluid. In some embodiments, the inlet of the sixth valve 15 can be connected to the simulated fracturing fluid injection pump 14, and the outlet of the sixth valve 15 can be connected to the inlet of the third valve 10.

[0037] By configuring the sixth valve, the flow rate and rate of the simulated fracturing fluid injected into the core sample can be adjusted, making the simulated reservoir conditions more realistic.

[0038] In some embodiments, the confining pressure pump 18 is provided with a seventh valve 20. The seventh valve 20 is a device for adjusting the core confining pressure applied by the confining pressure pump 18. In some embodiments, the inlet of the seventh valve 20 can be connected to the confining pressure pump 18.

[0039] By configuring the seventh valve, the core confining pressure applied by the confining pressure pump can be adjusted, so that the simulated core confining pressure can be more consistent with the actual scenario.

[0040] In some embodiments, the shale gas well reasonable shut-in time testing device further includes a processor. In some embodiments, the processor may be provided within the computer control system 21 or integrated within other devices within the shale gas well reasonable shut-in time testing device. In some embodiments, the processor may be communicatively coupled to various devices within the shale gas well reasonable shut-in time testing device, for example, the processor may be communicatively coupled to the online nuclear magnetic resonance tester 9, the resistivity tester 7, the first pressure sensor 6, and the second pressure sensor 19.

[0041] In some embodiments, the processor can be a computer, a user console, a single processor, a group of processors, etc. The group of processors can be centralized or distributed. In some embodiments, the processor can be implemented on a cloud platform. For example, the cloud platform can include one or any combination of a private cloud, a public cloud, a hybrid cloud, etc.

[0042] In some embodiments, the shale gas well reasonable soaking time testing device further includes an automatic scrubbing device. The automatic scrubbing device is a device used to clean core samples. In some embodiments, the automatic scrubbing device can be configured to perform operations such as salt washing, oil washing, and drying on the core samples. Salt washing removes residual salt from the core sample. Oil washing removes oil contaminants from the surface and pores of the core sample. Drying removes moisture from the core sample, leaving it dry.

[0043] In some embodiments, the automated brush scrubber may include a core holding assembly, a rotating assembly, and a cleaning brush.

[0044] A core holding assembly is a device used to hold a core sample. For example, a core holding assembly may include adjustable clamps that can be adjusted to the size and shape of the core sample.

[0045] The rotation assembly refers to a device for driving the core sample and / or cleaning brush to rotate. In some embodiments, the rotation assembly may include a power source, such as a pneumatic motor or an electric motor. In some embodiments, the rotation assembly may include a transmission mechanism, such as a conveyor belt or a coupling. For example only, the power source may drive the rotation assembly to rotate, and the transmission mechanism may transmit the rotational force to the core sample and / or cleaning brush.

[0046] A cleaning brush is a device used to remove dirt and impurities from the surface of a core sample. In some embodiments, the bristles of the cleaning brush can be made of a highly elastic, wear-resistant material, such as nylon or polyester. In some embodiments, the cleaning brush can be mounted on a rotating assembly to contact the core sample through rotation, thereby improving cleaning efficiency.

[0047] In some embodiments, the constant temperature chamber 16 may include a temperature control device, a temperature sensor, and an audible and visual alarm.

[0048] The temperature control device refers to a device for adjusting the temperature of the constant temperature chamber 16. In some embodiments, the temperature control device can adjust the temperature of the internal environment of the constant temperature chamber 16 to maintain a constant indoor temperature, thereby ensuring the accuracy of the test.

[0049] In some embodiments, the temperature control device may include a heating element and a cooling fan. The heating element is a device used to increase the temperature of the internal environment of constant temperature chamber 16, such as a resistance wire or an electric heating tube. The cooling fan is a device used to reduce the temperature of the internal environment of constant temperature chamber 16, such as a fan.

[0050] A temperature sensor is a device used to collect temperature data. In some embodiments, the temperature sensor can be configured to collect temperature data from the internal environment of constant temperature chamber 16. For example, the temperature sensor can collect temperature data at a preset collection frequency to obtain time-series temperature data. The preset collection frequency can be preset based on human experience.

[0051] In some embodiments, the temperature sensor can be configured to be in communication with the computer control system 21. In some embodiments, the temperature sensor can upload the collected temperature data to the computer control system 21.

[0052] The sound and light alarm refers to a device for issuing a warning. In certain embodiments, the sound and light alarm can issue a sound warning and / or a light warning. In certain embodiments, the sound and light alarm can be configured on the outer wall of the constant temperature room 16. In certain embodiments, the sound and light alarm can be configured to be communicated with the processor in the computer control system 21.

[0053] For more information about sound and light alarms, please refer to the relevant content below.

[0054] In some embodiments, the constant temperature chamber 16 may further include a concentration monitoring device. The concentration monitoring device refers to a device for monitoring gas concentration. In some embodiments, the concentration monitoring device may be configured to collect methane gas concentration data within the constant temperature chamber 16.

[0055] In some embodiments, the concentration monitoring device may include a methane gas sensor, etc. The gas sensor refers to a sensor for sensing methane gas in the air, such as an electrochemical sensor, a catalytic combustion sensor, an infrared sensor, etc.

[0056] In some embodiments, the concentration monitoring device may be configured to communicate with a processor in the computer control system 21. In some embodiments, the concentration monitoring device may upload the collected methane gas concentration data to the computer control system 21.

[0057] In some embodiments, the core holder 12 may further include a pressure monitoring device. In some embodiments, the pressure monitoring device may be disposed within the core holder 12. A pressure monitoring device is a device for monitoring pressure. In some embodiments, the pressure monitoring device may be configured to monitor gas pressure within the core holder 12, for example, to monitor methane gas pressure data.

[0058] In some embodiments, the pressure monitoring device may be configured to communicate with a processor in the computer control system 21 .

[0059] In some embodiments, the shale gas well reasonable shut-in time testing device further includes a camera and an image analysis device. In some embodiments, the camera can be communicatively connected to the image analysis device. In some embodiments, both the camera and the image analysis device can be configured to be communicatively connected to a processor in the computer control system 21.

[0060] A photographing device refers to a device for collecting image data. In some embodiments, the photographing device may be configured to collect an apparent image of a core sample. For example, the photographing device may capture an image and / or video of the core sample. An apparent image of a core sample refers to a visual image of the outer surface of the core sample. In some embodiments, the collected image data may be transmitted to an image analysis device and / or processor.

[0061] An image analysis device is a device used to analyze images. In some embodiments, the image analysis device can generate analysis results (e.g., fracture distribution information, etc.) based on the apparent image of the core sample. In some embodiments, the image analysis device can send the analysis results to a processor.

[0062] For more information about the camera, image analysis device, and crack distribution information, please refer to the relevant description below.

[0063] In some embodiments of the present specification, a shale gas well reasonable shut-in time testing device can be used to more realistically simulate the state changes of core samples in the reservoir, making the experimental results closer to the actual situation; by collecting a variety of data from core samples, data support can be provided for evaluating the reasonable shut-in time.

[0064] FIG2 is a schematic structural diagram of a device for testing a reasonable soaking time of a shale oil well according to some embodiments of this specification.

[0065] In some embodiments, as shown in Figure 2, a shale oil well reasonable shut-in time testing device includes a methane cylinder 1, a throttle valve 2, a first valve 3, a nitrogen cylinder 4, a second valve 5, a first pressure sensor 6, a resistivity tester 7, a buffer container 8, an online nuclear magnetic resonance tester 9, a third valve 10, a fourth valve 11, a core clamp 12, a fifth valve 13, a simulated fracturing fluid injection pump 14, a sixth valve 15, a constant temperature chamber 16, a vacuum pump 17, a confining pressure pump 18, a second pressure sensor 1, a seventh valve 201, a computer control system 21 and a simulated crude oil injection pump 22. Among them, the methane cylinder 1, the throttle valve 2, the first valve 3, the nitrogen cylinder 4, the second valve 5, the first pressure sensor 6, the resistivity tester 7, the buffer container 8, the online nuclear magnetic resonance tester 9, the third valve 10, the fourth valve 11, the core clamp 12, the fifth valve 13, the simulated fracturing fluid injection pump 14, the sixth valve 15, the constant temperature chamber 16, the vacuum pump 17, the confining pressure pump 18, the second pressure sensor 1, the seventh valve 201 and the computer control system 21 have the same or similar structures and functions as those in Figure 1 and are not repeated here.

[0066] The simulated crude oil injection pump 22 is used to inject simulated crude oil. In some embodiments, the simulated crude oil injection pump 22 is connected to the inlet of the core holder 12 and is used to inject simulated crude oil into the core sample in the core holder 12 until the reservoir pore pressure is reached. Simulated crude oil refers to a fluid used to simulate reservoir crude oil.

[0067] The shale oil well reasonable soaking time test device can realistically simulate the state changes of core samples in the reservoir for shale oil wells, making the experimental results closer to the actual situation; by collecting a variety of data from core samples, it can provide data support for evaluating the reasonable soaking time.

[0068] In some embodiments, the method for determining the reasonable shut-in time for a shale gas well can be tested using a shale gas well reasonable shut-in time testing device. In some embodiments, the method for determining the reasonable shut-in time for a shale gas well can be executed by a computer control system 21. It should be noted that the determination of the reasonable shut-in time for a shale oil well can be performed using a method similar to the method for determining the reasonable shut-in time for a shale gas well described below, which uses a shale oil well reasonable shut-in time testing device for testing. See the description below for details.

[0069] Step S1, respectively selecting several first core samples with natural cracks on their surfaces and second core samples without natural cracks on their surfaces; washing the first core samples and the second core samples with salt and oil, and drying them; measuring the length and diameter of the first core samples and the second core samples, and obtaining the volumes of the first core samples and the second core samples; respectively measuring and obtaining the porosity Φ0 of the first core samples and the second core samples.

[0070] In some embodiments, the computer control system 21 can control the automatic scrubbing device to scrub salt, scrub oil, and dry the first core sample and the second core sample. For example, the processor of the computer control system 21 can generate a scrubbing instruction and send the scrubbing instruction to the automatic scrubbing device, thereby instructing the automatic scrubbing device to scrub salt, scrub oil, and dry the first core sample and the second core sample.

[0071] In some embodiments, the computer control system 21 may control the measurement assembly to measure the length and diameter of the core sample. For example, the measurement assembly may send the measured length and diameter of the first core sample and the length and diameter of the second core sample to the processor of the computer control system 21.

[0072] In some embodiments, the processor of the computer control system 21 can calculate and generate the volumes of the core samples based on the lengths and diameters of the first and second core samples. For example, the processor can calculate the volumes of the first and second core samples using a geometric formula (e.g., a cylinder volume formula) based on the lengths and diameters of the first and second core samples.

[0073] In some embodiments, the computer control system 21 can control the measurement assembly to measure and obtain the porosity Φ0 of the first core sample and the second core sample, respectively. For example, the computer control system 21 can measure the porosity of the first core sample and the second core sample, respectively, using a porosity tester.

[0074] The measurement assembly refers to a device used to measure the dimensions of a core sample. In some embodiments, the measurement assembly can measure the length, diameter, porosity, etc. of the core sample. For example, the measurement assembly can include a vernier caliper, a laser rangefinder, a porosity tester, etc. In some embodiments, the measurement assembly can be communicatively connected to a processor in the computer control system 21.

[0075] In step S2, the temperature in the constant temperature chamber 16 is preset to the temperature of the reservoir where the first core sample and the second core sample are located, the first core sample is placed in the core holder 12, the confining pressure pump 18 is started, and the core confining pressure is applied to the first core sample in the core holder 12; the core holder 12 is evacuated using the vacuum pump 17 to simulate the state of the first core sample in the reservoir.

[0076] In some embodiments, the computer control system 21 can preset the temperature in the constant temperature chamber 16 to the temperature of the reservoir where the first core sample and the second core sample are located by controlling the temperature control device.

[0077] In some embodiments, the computer control system 21 may control the confining pressure pump 18 to apply core confining pressure to the first core sample in the core holder 12. For example, the processor of the computer control system 21 may generate a pressure application instruction and send the pressure application instruction to the confining pressure pump 18. After receiving the pressure application instruction, the confining pressure pump 18 may apply the core confining pressure.

[0078] In some embodiments, the computer control system 21 may evacuate the core holder 12 via the vacuum pump 17 to simulate the state of the first core sample in the reservoir. For example, the processor of the computer control system 21 may generate a vacuum instruction and send the vacuum instruction to the vacuum pump 17. After receiving the vacuum instruction, the vacuum pump 17 may evacuate the core holder 12.

[0079] Step S3: inject methane into the first core sample in the core holder 12 using the methane gas cylinder 1 until the pore pressure of the reservoir is reached, and maintain the pressure for 4 days.

[0080] In some embodiments, the computer control system 21 can control the methane cylinder 1 to inject methane into the first core sample in the core holder 12. For example, as shown in FIG1 , the processor of the computer control system 21 can open the throttle valve 2 to allow the methane cylinder 1 to input methane into the core holder 12.

[0081] It will be appreciated that while step S3 above is specific to shale gas wells, for shale oil wells, computer control system 21 can control simulated crude oil injection pump 22 to inject simulated crude oil into the first core sample in core holder 12 until the reservoir pore pressure is reached, and then maintain the pressure for four days. For shale oil wells, the determination of a reasonable soaking time, except for step S3, is similar to that for shale gas wells.

[0082] Step S4 , starting the simulated fracturing fluid injection pump 14 and injecting the simulated fracturing fluid into the core holder 12 ; closing the third valve 10 .

[0083] In some embodiments, the computer control system 21 can control the simulated fracturing fluid injection pump 14 to inject the simulated fracturing fluid into the core holder 12. For example, as shown in FIG1 , the processor of the computer control system 21 can open the sixth valve 15 and the third valve 10 to allow the simulated fracturing fluid to flow from the outlet of the simulated fracturing fluid injection pump 14 to the core holder 12. After the injection is completed, the processor can close the third valve 10 to stop the injection of the simulated fracturing fluid into the core holder 12.

[0084] Step S5, start the resistivity tester 7 to measure the resistivity change curve of the first core sample; at the same time, use the pressure decay method to continuously measure and obtain the half-life of the pressure decay of the first pressure sensor 6 until the resistivity change curve of the first core sample has an inflection point.

[0085] In some embodiments, the computer control system 21 may measure the resistivity change curve of the core sample using the resistivity tester 7. For example, the processor of the computer control system 21 may generate an instruction to start a resistivity test and send the instruction to the resistivity tester 7. After receiving the instruction, the resistivity tester 7 may measure the resistivity change curve of the core sample (e.g., the first core sample and the second core sample).

[0086] In some embodiments, the computer control system 21 can determine the half-life of the pressure decay of the first pressure sensor 6 by various methods. For example, the processor can measure the half-life of the pressure decay of the first pressure sensor 6 by a pressure decay method until the resistivity change curve of the first core sample reaches an inflection point.

[0087] Step S6: Replace the first core sample in the core holder 12 with the second core sample, and repeat steps 210 to 250; respectively calculate the experimental time t at which the shortest pressure decay half-life of the first core sample occurs. 1f The experimental duration t of the shortest pressure decay half-life of the second core sample 1m .

[0088] During the period from the injection of the simulated fracturing fluid in step S4 to the inflection point of the resistivity change curve in step S5, the methane nuclear magnetic resonance signal of the first core sample and the second core sample is continuously monitored by the online nuclear magnetic resonance tester 9, and the time point t at which the core nuclear magnetic resonance signal of the first core sample has the largest change amplitude is obtained. 2f The time point t at which the core NMR signal of the second core sample has the largest change amplitude 2m .

[0089] Step S7: the experimental time t of the shortest pressure decay half-life of the first core sample 1f , the experimental duration t when the second core sample has the shortest pressure decay half-life 1m , the time point t when the core NMR signal of the first core sample changes the most 2f The time point t at which the core NMR signal of the second core sample has the largest change amplitude 2m Sort the arrays and take the two middle arrays as the time endpoints. The values ​​in the time endpoints are the soaking time t at the core scale. c .

[0090] In some embodiments, the computer control system 21 can set the experimental time t of the shortest pressure decay half-life of the first core sample to 1f The corresponding endpoint time point t 1f, the experimental duration t when the second core sample has the shortest pressure decay half-life 1m The corresponding endpoint time point t 1f , the time point t when the core NMR signal of the first core sample changes the most 2f The time point t at which the core NMR signal of the second core sample has the largest change amplitude 2m In some embodiments, the processor can take the two middle arrays after sorting as time endpoints based on the sorting results, and set the values ​​in the time endpoints as the soaking time t at the core scale. c .

[0091] Step S8, based on the soaking time t at the core scale c Calculate the shut-in time t of shale gas well R .

[0092] In some embodiments, the computer control system 21 can be based on the soak time t at the core scale. c , various methods are used to determine the shut-in time t of shale gas wells R For example, the processor of the computer control system 21 can determine the shut-in time t of the shale gas well based on the following formula (1): R :

[0093] Wherein, V2 in formula (1) represents the total volume of the reservoir transformed by hydraulic fracturing, V3 represents the total volume of sand-filled cracks formed in the reservoir after hydraulic fracturing, and V c represents the volume of simulated fracturing fluid pumped into the core to establish the target water saturation, V1 represents the volume of the core sample (e.g., the first core sample or the second core sample, etc.), and V f Indicates the volume of fracturing fluid pumped in during on-site hydraulic fracturing construction, Φ m It represents the reservoir porosity after removing hydraulic fractures in the total hydraulic fracturing stimulation area.

[0094] In some embodiments, the computer control system 21 can determine the volume of the simulated fracturing fluid injected in step S4 by various methods. For example, the processor of the computer control system 21 can determine V by the following formulas (2) and (3): c : V c =S w V1Φ0 (2) S w =(V f -V3Φ f ) / [(V2-V3)Φ m ] (3)

[0095] Among them, S w Indicates the target water saturation of the first core sample and / or the second core sample, Φ f Indicates the porosity of hydraulically saturated fractures. The target water saturation of a core sample refers to the proportion of the pore space occupied by water, such as a percentage. Hydraulically saturated fractures are fractures created by simulating the compression of fracturing fluid into the core sample.

[0096] The following describes a method for determining a reasonable soaking time for a shale gas well as an example. The method includes the following steps:

[0097] Step S1: Select downhole cores from a shale gas well in a certain block, that is, select several first core samples with natural cracks on the surface and second core samples without natural cracks on the surface; wash the first core samples and the second core samples with salt and oil, and dry them; measure the length of the first core sample and the second core sample to be 5 cm and the diameter to be 2.5 cm, and calculate the volume of the first core sample and the second core sample V1 = 24.5 cm 3 In this embodiment, the porosity Φ0 of the first core sample and the second core sample is measured to be 5%.

[0098] In step S2, the temperature in the constant temperature chamber is preset to 339 K, the reservoir temperature where the first and second core samples are located. The first core sample is then placed in the core holder 12, and the confining pressure pump 18 is activated to apply a confining pressure to the first core sample in the core holder 12. The confining pressure applied by the confining pressure pump 18 is equal to the in situ effective stress of 16.3 MPa. The core holder 12 is then evacuated using the vacuum pump 17 to simulate the conditions of the first core sample in the reservoir.

[0099] Step S3: inject methane into the first core sample in the core holder 12 using the methane gas cylinder 1 until the reservoir pore pressure is reached, and maintain the pressure for 4 days.

[0100] Step S4: Start the simulated fracturing fluid injection pump 14 and inject 0.614 cm of simulated fracturing fluid into the core holder 12. 3 The simulated fracturing fluid is MnCl2, and the mass fraction of MnCl2 in the aqueous solution is 5%.

[0101] After the simulated fracturing fluid is injected, the third valve 10 is closed.

[0102] Step S5, start the resistivity tester to measure the resistivity change curve of the first core sample; at the same time, use the pressure decay method to continuously measure and obtain the half-life of the pressure decay of the first pressure sensor until the resistivity change curve of the first core sample has an inflection point.

[0103] FIG3 is a graph showing the relationship between core resistivity change and soaking time during the experiment according to some embodiments of this specification. As shown in FIG3, ρ i is the resistivity of the core at soaking time i; ρ max is the maximum resistivity of the core during the soaking time; at the same time, the pressure decay method is used to continuously measure and obtain the half-life of the pressure decay of the first pressure sensor, that is, after the last pressure decay reaches half-life, the next pressure decay half-life monitoring is immediately started until the core resistivity shows an obvious inflection point.

[0104] Step S6: Replace the first core sample in the core holder 12 with the second core sample, and repeat steps S2 to S5; respectively calculate the experimental duration t of the shortest pressure decay half-life of the first core sample and the second core sample. 1f =105min and t 1m =135min.

[0105] During the period from the injection of the simulated fracturing fluid in step S4 to the occurrence of an inflection point in the resistivity change curve in step S5, the methane nuclear magnetic resonance signal of the first core sample and the second core sample is continuously monitored using the online nuclear magnetic resonance tester 9, and the time point t at which the core nuclear magnetic resonance signal of the first core sample and the second core sample has the largest change amplitude is obtained. 2f =78min and t 2m =112min.

[0106] Step S7: the experimental time t of the shortest pressure decay half-life of the first core sample 1f , the experimental duration t when the second core sample has the shortest pressure decay half-life 1m , the time point t when the core NMR signal of the first core sample changes the most 2f The time point t at which the core NMR signal of the second core sample has the largest change amplitude 2m Sort the arrays and take the two middle arrays after sorting as the time endpoints. The values ​​in the time endpoints are the soaking time t at the core scale. c , which is between the interval [105min, 112min].

[0107] Step S8, based on the soaking time t at the core scale c Obtain the shut-in time t of shale gas well R , that is, calculate t at the core scale 1f =105min and t 2m =112min corresponding to the gas reservoir scale t 1R = 3.2 days and t 2R = 3.5 days, which is a reasonable shut-in time t for high production of shale gas wells. R Between the interval [3.2 days, 3.5 days].

[0108] In some embodiments of the present specification, a methane gas cylinder, a simulated crude oil injection pump, a resistivity tester, an online nuclear magnetic resonance tester, a core holder, a simulated fracturing fluid injection pump, a constant temperature chamber, a vacuum pump, a confining pressure pump and a computer control system are set, and the first core sample and the second core sample are fully saturated with methane gas (for shale gas wells) or simulated crude oil (for shale oil wells), and then a certain amount of simulated fracturing fluid is injected into the core, and the change in the core resistivity under different soaking times is measured, and the change in the gas fluid transmission capacity in the core is tested by a pressure decay experiment, and the methane in the core is monitored by online nuclear magnetic resonance (for shale oil wells). The study evaluated the impact of shut-in time on core permeability and the production capacity of matrix methane (for shale gas wells) or simulated crude oil (for shale oil wells). Ultimately, the optimal shut-in time for high and stable shale oil / gas well production was determined, providing a basis for efficient shale oil / gas well development. The experimental duration at which the shortest pressure decay half-life occurred for the first and second core samples, as well as the time point at which the core nuclear magnetic resonance (NMR) signal amplitude of the first and second core samples changed the most, was determined. The experimental duration at which the shortest pressure decay half-life occurred indicates the time point at which the core permeability was greatest. The time point at which the NMR signal amplitude changed the most indicates the time point at which the core permeability was greatest. The purpose and benefit of the present invention adopting the intermediate value between the two are: within this time period, the strongest core seepage capacity and the optimal utilization capacity of matrix methane (for shale gas wells) or simulated crude oil (for shale oil wells) are taken into account simultaneously; several first core samples with natural cracks on the surface and second core samples without natural cracks on the surface are used and tested separately. Among them, during the on-site soaking period, the process of fracturing fluid infiltration from hydraulic fractures to natural cracks and matrix blocks mainly occurs. Therefore, the use of core samples with and without natural cracks takes into account the actual conditions on site, namely: natural cracks and shale matrix blocks.

[0109] In some embodiments, the method for determining a reasonable shut-in time for a shale oil / gas well further includes: in response to the monitored temperature in the constant temperature chamber 16 exceeding a dangerous temperature threshold, issuing a first alarm through an audible and visual alarm, the time of issuing the first alarm including the time range of the sample placement time and the sample replacement time; and, in response to reaching the sample replacement time, generating an estimated cooling time period; and blocking the constant temperature chamber 16 and the core clamp 12 within the estimated cooling time period.

[0110] The monitored temperature refers to the actual temperature inside the constant temperature chamber 16. For example, a temperature sensor collects temperature data of the internal environment of the constant temperature chamber 16.

[0111] In some embodiments, after the temperature within the constant temperature chamber is preset to the reservoir temperature where the first and second core samples are located in step S2, the computer control system 21 may control the temperature control device to adjust the temperature according to the preset temperature so that the temperature within the constant temperature chamber 16 reaches the reservoir temperature where the first and second core samples are located. For example, if the temperature within the constant temperature chamber 16 is lower than the reservoir temperature where the first and second core samples are located, the constant temperature chamber 16 is heated by the heating component until the monitored temperature detected by the temperature sensor reaches the reservoir temperature; otherwise, the constant temperature chamber 16 is cooled by the cooling fan until the monitored temperature detected by the temperature sensor reaches the reservoir temperature where the first and second core samples are located.

[0112] In some embodiments, in response to a temperature difference between the monitored temperature in the constant temperature chamber detected by the temperature sensor and a preset temperature exceeding a preset difference, the computer control system 21 may control the temperature control device to perform temperature control. The preset difference may be set by a technician based on experience. For example, the preset difference may be the maximum fluctuation value of the reservoir temperature where the first core sample and the second core sample are located.

[0113] The dangerous temperature threshold refers to the minimum temperature value that poses a safety risk to the human body. For example, the lowest temperature that may cause burns to human skin. In some embodiments, the dangerous temperature threshold can be set based on prior experience.

[0114] The first alarm is used to warn of the possibility of high temperature burns, such as light alarms, voice alarms, etc.

[0115] In some embodiments, the first alarm can be issued via an audible and visual alarm. The audible and visual alarm can include a flashing light and a speaker. For example, when the monitored temperature exceeds a dangerous temperature threshold, the computer control system can control the flashing light in the audible and visual alarm to emit a specific color (e.g., red) and play a voice prompt such as "Temperature is too high, please prevent burns" through the speaker, thereby issuing the first alarm.

[0116] The sample placement time refers to the preset time for placing the first and second core samples into the core holder 12. The sample replacement time refers to the preset time for replacing the core sample. The time range encompassing the sample placement time and sample replacement time refers to the period before and after the sample placement time and sample replacement time. The size of this time range can be preset by a technician. It is understood that when testers place or replace samples, it is difficult to precisely follow the prescribed sample placement and replacement times, and some advances or delays may occur. Therefore, technicians can set the size of this time range based on the fluctuation range of the actual sample placement and sample replacement times in historical data.

[0117] In some embodiments, if the monitored temperature is higher than the dangerous temperature threshold, the computer control system 21 may issue a first alarm within the range of the sample placement time and the sample replacement time to provide safety reminders to personnel performing sample placement and sample replacement to avoid burns.

[0118] The estimated cooling time period refers to a pre-estimated time period for cooling the constant temperature chamber 16. For example, the time period for cooling the constant temperature chamber 16 by turning on the cooling fan in the temperature control device.

[0119] In some embodiments, the computer control system 21 can calculate the current temperature change rate based on the most recent monitored temperatures at two adjacent time points; calculate the cooling time required for the current monitored temperature to drop to the dangerous temperature threshold based on the difference between the current monitored temperature and the dangerous temperature threshold, and the current temperature change rate; and calculate an estimated cooling time period based on the cooling time period and the current time point, where the current monitored temperature is the most recently measured temperature by the temperature sensor. For example, if the temperatures at the most recent two adjacent time points are 90°C at 10:10 and 86°C at 10:12, the current temperature change rate is 2°C per minute; assuming the dangerous temperature threshold is 50°C, the time required to cool from the current 86°C (i.e., the monitored temperature measured at 10:12) to the dangerous temperature threshold of 50°C is (86°C - 50°C) ÷ 2°C / minute = 18 minutes, and the estimated cooling time period is 18 minutes after the current time point, i.e., 10:12 to 10:30.

[0120] In some embodiments, the computer control system 21 can calculate the latest estimated cooling period based on the most recent monitored temperatures at two adjacent time points in real time and update the estimated cooling period. For example, the computer control system 21 can display the estimated cooling period on a screen and, when a new estimated cooling period is calculated in real time, replace the original estimated cooling period with the new estimated cooling period for dynamic updating.

[0121] In some embodiments, the computer control system 21 may lock the constant temperature chamber 16 and the core holder 12 during the estimated temperature drop period to prevent the tester from being burned when replacing the core sample.

[0122] In some embodiments, in response to the temperature change rate being lower than a preset change threshold, the computer control system may further turn on the cooling fan of the temperature control device to cool the constant temperature chamber to accelerate the cooling speed of the constant temperature chamber.

[0123] The preset change threshold refers to the minimum acceptable rate of temperature change. In some embodiments, the preset change threshold can be set by the tester based on test requirements. For example, the tester can calculate the minimum acceptable rate of temperature drop based on the preset constant temperature chamber temperature and the dangerous temperature threshold, as well as the maximum temperature drop duration that does not affect the test results, to use as the preset change threshold.

[0124] In some embodiments, the computer control system 21 can determine the temperature change rate based on the monitored temperature; determine the temperature warning time point based on the temperature change rate, and generate a temperature warning based on the temperature warning time point to notify the user of the temperature warning time point; in response to the monitored temperature reaching the preset temperature in step S2, generate a pressurization control instruction and send it to the first valve 3; the first valve 3 automatically opens based on the pressurization control instruction to inject methane into the first core sample in the core clamp 12.

[0125] The temperature warning time point refers to the moment when the temperature reaches the dangerous temperature threshold.

[0126] In some embodiments, the computer control system 21 can calculate the temperature warning time point based on the temperature change rate, the monitored temperature, and the dangerous temperature threshold. For example, the current temperature change rate is 4°C per minute, the current monitored temperature is 20°C, and the dangerous temperature threshold is 50°C. The time required to reach the dangerous temperature threshold is (50°C-20°C) ÷ 4°C / minute = 7.5 minutes, and the temperature warning time point is 7.5 minutes later. For another example, the computer control system 21 can establish a temperature change rate table based on the historical temperature change rate. The table includes parameters such as the ambient temperature, the monitored temperature, the power of the heating component in the historical operating data of the test device, and the corresponding historical temperature warning time points; the computer control system 21 can search the temperature change rate table based on the current monitored temperature to determine the temperature warning time point.

[0127] A temperature warning is a warning that alerts the user when a dangerous temperature threshold has been reached. For example, a temperature warning may include displaying the temperature warning time point to the user on the screen.

[0128] In some embodiments, the computer control system 21 may generate a warning instruction for displaying a temperature warning time point, and display the temperature warning time point to the user through a screen based on the warning instruction, so as to issue a temperature warning.

[0129] In some embodiments, the computer control system 21 can calculate the temperature change rate in real time based on the latest monitored temperature; calculate the temperature warning time point based on the latest calculated temperature change rate; and issue a new temperature warning based on the latest temperature warning time point to display the temperature warning time point to the user in real time.

[0130] The pressurization control instruction is an instruction for controlling the pressurization of the core holder 12. In some embodiments, the computer control system 21 may generate an opening instruction and send it to the first valve 3 when the monitored temperature reaches the preset temperature in step S2, thereby controlling the opening of the first valve 3 to inject methane into the first core sample in the core holder 12.

[0131] In some embodiments of this specification, by calculating the temperature warning time and notifying the user, the first valve is automatically opened to inject methane when the temperature reaches a preset temperature, thereby improving the convenience and efficiency of the experimental operation and ensuring the safety of the experiment.

[0132] In some embodiments of the present specification, the core holder and the constant temperature chamber are closed when the temperature reaches a dangerous temperature threshold, thereby preventing burns caused by the test personnel's operation under high temperature conditions and improving the safety of the experiment.

[0133] In some embodiments, in response to the methane gas concentration in the constant temperature chamber 16 reaching a concentration threshold and / or the gas pressure in the core holder 12 reaching a pressure threshold, the computer control system 21 may issue a second alarm through an audible and visual alarm; and adjust the methane flow through the throttle valve 2, or close the first valve 3.

[0134] It is understandable that during the process of injecting methane into the core holder 12, as the gas pressure in the core holder 12 gradually increases, a small amount of methane leakage may occur at the pipeline interface, valve and other locations, resulting in a small amount of methane gas in the constant temperature chamber.

[0135] The concentration threshold refers to the maximum methane concentration that can be tolerated in a constant temperature room.

[0136] In some embodiments, the concentration threshold may be preset by the tester based on experience. For example, the tester may use the lowest methane concentration that may endanger the tester or the equipment as the concentration threshold.

[0137] The pressure threshold refers to the maximum gas pressure value that can be accepted in the core holder. In some embodiments, the pressure threshold may include the pore pressure value of the reservoir where the first core sample and the second core sample are located.

[0138] In some embodiments, multiple concentration thresholds and pressure thresholds may be provided. For example, the lowest methane concentration that could endanger test personnel or equipment may be used as the maximum concentration threshold, the reservoir pore pressure value where the first core sample and the second core sample are located may be used as the maximum pressure threshold, and multiple concentration thresholds and pressure thresholds less than the maximum concentration threshold may be provided.

[0139] The second alarm is an alarm used to remind that the methane gas concentration or gas pressure is too high.

[0140] In some embodiments, the second alarm may be issued by an audible and visual alarm. For example, when the monitored temperature exceeds a dangerous temperature threshold, the computer control system 21 may control the flashlight in the audible and visual alarm to emit a specific color (e.g., blue) and play a voice prompt such as "methane leak" or "gas pressure too high" through a speaker, thereby issuing the second alarm.

[0141] In some embodiments, when the methane gas concentration in the constant temperature chamber 16 reaches different concentration thresholds or the gas pressure in the core holder reaches different pressure thresholds, the computer control system 21 can issue a second alarm of different degrees. The higher the concentration threshold or pressure threshold reached, the greater the intensity of the second alarm. The intensity of the second alarm refers to the strength of the warning issued by the sound and light alarm. For example, when the lowest concentration threshold or the lowest pressure threshold is reached, the sound and light alarm can issue a second alarm through a relatively mild light color and a relatively gentle voice reminder; when the highest concentration threshold or the highest pressure threshold is reached, the sound and light alarm can issue a second alarm through the most conspicuous light color and the most urgent voice reminder (such as a continuous loud warning reminder, etc.).

[0142] In some embodiments, the computer control system 21 can adjust the methane gas flow rate based on different concentration thresholds or pressure thresholds reached. For example, the higher the concentration threshold or pressure threshold reached, the greater the reduction in the methane gas flow rate. When the highest concentration threshold or pressure threshold is reached, the first valve is closed.

[0143] In some embodiments, the computer control system 21 can issue a pressure warning through an audible and visual alarm in response to the pressure change data meeting a preset condition; and adjust the methane gas flow through a throttle valve.

[0144] Pressure change data refers to data used to characterize changes in gas pressure. For example, pressure change data may include the rate of change of gas pressure, the difference between gas pressure and reservoir pore pressure of a core sample, etc.

[0145] Preset conditions refer to preset gas pressure-related judgment conditions. For example, the preset conditions may include the pressure change rate being less than a preset change threshold. The preset change threshold can be set by the tester as needed.

[0146] In some embodiments, different testing phases correspond to different preset conditions. For example, during the process of injecting methane gas to bring the gas pressure in the core holder to the reservoir pore pressure of the core sample, the preset condition may include a pressure change rate that is less than the theoretical change rate corresponding to the injection rate displayed by the throttle valve. For another example, during the pressure maintenance phase, the preset condition may include a continuously increasing difference between the gas pressure and the reservoir pore pressure of the core sample.

[0147] The theoretical rate of change refers to the theoretical rate of change of gas pressure when methane gas is injected at the displayed injection rate. In some embodiments, the theoretical rate of change can be calculated based on the injection rate and the volume of the core holder using a physical relationship. For example, if the injection rate is 5 L / min, the increase in gas pressure in the core holder caused by each 5 L increase in gas can be calculated based on the volume, thereby obtaining the theoretical rate of change corresponding to the injection rate.

[0148] The continuously increasing difference between the gas pressure and the reservoir pore pressure of the core sample may include: the continuously increasing difference between the gas pressure and the reservoir pore pressure monitored within a preset sampling period of N pressure monitoring devices. The sampling period refers to the time interval between two consecutive gas pressure measurements by the pressure sensor.

[0149] In some embodiments, if the pressure change rate of the gas pressure is less than a preset change threshold, the injection rate of the methane gas is increased through the throttle valve to improve the test efficiency.

[0150] In some embodiments, if the corresponding preset conditions mentioned above are met during the injection of methane gas, the computer control system 21 can control the sound and light alarm to issue a pressure warning to remind the test personnel to check the equipment and devices, and at the same time control the throttle valve to adjust the flow rate of methane gas to 0 or close the first valve to avoid further leakage of methane gas.

[0151] In some embodiments, if the corresponding preset conditions are met during the pressure holding stage, the computer control system 21 may issue a pressure warning to remind the tester to check the equipment and devices.

[0152] In some embodiments of the present specification, an alarm is issued and the flow rate of methane gas is adjusted based on the methane gas concentration in the constant temperature chamber and the gas pressure in the core holder, thereby improving the efficiency of the test and the safety of the test process.

[0153] In some embodiments, the computer control system 21 can also capture the first sample image and the second sample image based on a photographing device; input the first sample image and the second sample image into an image analysis device to generate crack distribution information; and screen the first core sample and the second core sample based on the crack distribution information.

[0154] The first sample image refers to an image of the first core sample. The second sample image refers to an image of the second core sample. In some embodiments, the first sample image and the second sample image may respectively include at least two images of side surfaces of the first core sample and the second core sample, where the side surfaces refer to side surfaces of the cylindrical first core sample and the second core sample.

[0155] The fracture distribution information refers to the distribution of fractures on the first core sample and the second core sample. In some embodiments, the fracture distribution information may include information such as the length, width, and position of the fractures.

[0156] In some embodiments, the image analysis device can determine the fracture distribution information in a variety of ways. For example, the image analysis device can compare each first sample image / second sample image with a standard sample image without fractures, identify lines that exist in the first sample image / second sample image but not in the standard sample image as fractures, and calculate the length, width, and location of the fractures as the fracture distribution information corresponding to the first core sample / second core sample. The location of the fracture can be represented by the coordinates of the starting point, midpoint, and end point of the fracture.

[0157] In some embodiments, the image analysis device can also determine fracture distribution information using a core image model. In some embodiments, the core image model can be a machine learning model, such as a convolutional neural network (CNN). In some embodiments, the image analysis device can input one first sample image or one second sample image along with a standard sample image into the core image model for processing to obtain fracture distribution information.

[0158] The input of the core image model may include a core sample image and a standard core image, and the output of the core image model may include fracture distribution information, wherein the standard core image may be an image of a core sample without fractures.

[0159] In some embodiments, the core image model can be trained using a large number of first samples with first labels to obtain an initial core image model. The first samples include a large number of images of real core samples with or without fractures obtained from historical data; the first labels are information about the actual fracture distribution corresponding to the first samples. The first labels are manually annotated, for example, based on the number and location of natural fractures in the first samples.

[0160] In some embodiments, the computer control system 21 can also process the first sample image and the second sample image into grayscale images respectively, and input the grayscale images into an image analysis device; the image analysis device determines the crack distribution information based on the grayscale image and the standard grayscale image.

[0161] The standard grayscale image is a grayscale image obtained by processing the standard core image. In some embodiments, the image processing device may determine fracture distribution information based on a comparative analysis of the grayscale image and the standard grayscale image. For another example, the image processing device may input the grayscale image and the standard grayscale image into the aforementioned core image model to obtain fracture distribution information.

[0162] In some embodiments of the present specification, by processing the first sample image and the second sample image into grayscale images and determining the crack distribution information based on the grayscale images, the difficulty of analyzing the image by the image analysis device can be reduced and the efficiency and accuracy of determining the crack distribution information can be improved.

[0163] In some embodiments, the computer control system 21 can obtain historical fracture distribution information with inaccurate test results in historical data; cluster the historical fracture distribution information based on the fracture positions in the historical fracture distribution information to obtain multiple clusters, each cluster including at least one historical fracture distribution information, and the clustering method can include hierarchical clustering algorithm, synthetic clustering and other clustering methods that do not require pre-setting the number of clusters; the first core sample and the second core sample corresponding to the fracture distribution information whose distance to the cluster center of at least one cluster is less than a preset distance threshold are screened out.

[0164] In some embodiments, the distance between the crack distribution information and the cluster center may be calculated based on the distance between the crack position in the crack distribution information and the crack position in the cluster center.

[0165] In some embodiments, different clusters may correspond to different preset distance thresholds, and the preset distance thresholds corresponding to different clusters may be determined based on the amount of historical crack distribution information in the different clusters; the more historical crack distribution information in a cluster, the larger the corresponding preset distance threshold. Among them, n is the number of historical crack distribution information in the cluster, L is the maximum distance between the historical crack distribution information in the cluster with the least number of historical crack distribution information and the cluster center, and N is the number of historical crack distribution information in the cluster with the least number of historical crack distribution information.

[0166] It can be understood that the historical fracture distribution information is the fracture distribution information corresponding to the core samples with inaccurate test results in the historical data. The more historical fracture distribution information there is in the cluster, the greater the possibility that the core samples corresponding to the historical fracture distribution information in the cluster are inaccurate in the historical test, and the stricter the requirements for the first core sample and the second core sample corresponding to similar fracture distribution information during screening.

[0167] In some embodiments of the present specification, the first sample image and the second sample image are analyzed by an image processing device to determine the crack distribution information and the first core sample and the second core sample are screened, so that the first core sample and the second core sample whose test results may be inaccurate can be eliminated in advance, thereby improving the accuracy of the test results.

[0168] In some embodiments, the computer control system 21 can also evaluate the reliability of the soaking time corresponding to different first core samples and second core samples based on the monitored temperature and gas pressure in the core holder 12; in response to the reliability being lower than the reliability threshold, the first core sample and / or the second core sample are reselected to execute the aforementioned method for determining the reasonable soaking time of shale oil / gas wells.

[0169] Reliability refers to the numerical value that represents the rationality of the soaking time.

[0170] In some embodiments, the computer control system 21 can count the maximum temperature fluctuation of the monitored temperature relative to the preset temperature, and the maximum pressure fluctuation of the gas pressure relative to the reservoir pore pressure; based on the maximum temperature fluctuation and the maximum pressure fluctuation, the reliability of the soaking time is determined. The maximum temperature fluctuation refers to the maximum value of the difference between multiple monitored temperatures and the preset temperature during the test; the maximum pressure fluctuation refers to the maximum value of the difference between the gas pressure and the reservoir pore pressure during the pressure maintenance process. In some embodiments, the greater the maximum temperature fluctuation and the maximum pressure fluctuation, the lower the reliability of the soaking time. Just as an example, Where ΔT is the maximum temperature fluctuation, T is the preset temperature, ΔF is the maximum pressure fluctuation, and F is the reservoir pore pressure.

[0171] In some embodiments, the reliability threshold may be determined based on historical test records. For example, the computer control system 21 may calculate the historically reliable average of the first and second core samples corresponding to the inaccurate soaking times obtained through historical testing as the reliability threshold.

[0172] In some embodiments, the computer control system 21 may also determine the reliability of the soaking time through a soaking model based on the monitored temperature, gas pressure, and fracture distribution information.

[0173] In some embodiments, the soaking model may include a machine learning model, such as a long short-term memory network (LSTM).

[0174] In some embodiments, the input of the soaking model may include a monitoring temperature sequence, a pressure data sequence, and fracture distribution information; and the output may include the reliability of the soaking time.

[0175] The monitoring temperature sequence refers to a sequence of multiple monitoring temperatures in the constant temperature chamber 16 arranged in time during the test process; the pressure data sequence refers to a sequence of multiple gas pressures in the core holder 12 arranged in time during the pressure holding process.

[0176] In some embodiments, the soaking model can be obtained by training an initial soaking model based on a soaking training dataset constructed from a large number of second samples with second labels.

[0177] In some embodiments, the second sample can be obtained based on historical data. For example, historical monitoring temperature sequences, historical pressure data sequences, and fracture distribution information from the first and / or second core samples in the historical data can be used as the second sample. In some embodiments, the second label can be determined based on the actual rationality of the historical soak time corresponding to the second sample. If the rationality of the historical soak time is reasonable, the second label is 1; if the rationality of the historical soak time is unreasonable, the second label is 0. The rationality of the historical soak time can be determined based on the difference between multiple historical soak times obtained by testing the first and second core samples of the same shale oil and gas well. For example, if the mean of the multiple historical soak times obtained by testing the first and second core samples of the same shale oil and gas well exceeds a preset difference, the historical soak time is determined to be unreasonable. The preset difference is determined by the tester based on prior knowledge, such as the accuracy of the soak time. The second label can be manually annotated.

[0178] In some embodiments, the computer control system 21 can select one or more second samples from the well-sealing training dataset, input the one or more second samples into the initial well-sealing model, and obtain model prediction outputs corresponding to the one or more second samples. The computer control system 21 substitutes the model prediction outputs corresponding to the one or more second samples and the second labels of the one or more second samples into a predefined loss function formula to calculate the value of the loss function. Based on the value of the loss function, the model parameters in the initial well-sealing model are reversely updated. The model parameter update can be performed using a variety of methods, such as gradient descent. When an iteration termination condition is met, the iteration ends, resulting in a trained well-sealing model.

[0179] In some embodiments of the present specification, the reliability of the soaking time is determined by the soaking model, and the objective laws between the monitoring temperature series, pressure data series and the reliability of the soaking time can be learned through a machine learning model in a large number of soaking samples, so as to more accurately evaluate the rationality of the soaking time obtained by the test.

[0180] In some embodiments of the present specification, the reliability of the soaking time is evaluated by monitoring the temperature and gas pressure. When the reliability is low, the first core sample and the second core sample are re-selected for testing to ensure the rationality of the final soaking time.

[0181] While the basic concepts have been described above, it will be apparent to those skilled in the art that the detailed disclosure is merely illustrative and does not limit this specification. Although not explicitly stated herein, various modifications, improvements, and revisions to this specification may be made by those skilled in the art. Such modifications, improvements, and revisions are suggested in this specification and remain within the spirit and scope of the exemplary embodiments of this specification.

[0182] In addition, unless expressly stated in the claims, the order of the processing elements and sequences, the use of alphanumeric characters, or the use of other names described in this specification are not intended to limit the order of the processes and methods of this specification. Although the above disclosure discusses some of the invention embodiments currently considered useful through various examples, it should be understood that such details are for illustrative purposes only, and the appended claims are not limited to the disclosed embodiments. On the contrary, the claims are intended to cover all modifications and equivalent combinations that are consistent with the spirit and scope of the embodiments of this specification. For example, although the system components described above can be implemented by hardware devices, they can also be implemented only by software solutions, such as installing the described system on an existing server or mobile device.

[0183] Each patent, patent application, patent application publication, and other materials, such as articles, books, specifications, publications, and documents, cited in this specification is hereby incorporated by reference in its entirety. This includes application history documents that are inconsistent with or conflict with the content of this specification, as well as documents (currently or subsequently attached to this specification) that limit the broadest scope of the claims of this specification. It should be noted that if the descriptions, definitions, and / or terminology used in the accompanying materials are inconsistent or conflicting with the content of this specification, the descriptions, definitions, and / or terminology used in this specification will control.

[0184] Finally, it should be understood that the embodiments described in this specification are intended only to illustrate the principles of the embodiments of this specification. Other variations may also fall within the scope of this specification. Therefore, by way of example and not limitation, alternative configurations of the embodiments of this specification may be considered consistent with the teachings of this specification. Accordingly, the embodiments of this specification are not limited to the embodiments explicitly described and illustrated in this specification.

Claims

1. A method for determining a reasonable shut-in time of a shale gas well, which uses a shale gas well reasonable shut-in time testing device to conduct a test, characterized in that: The shale gas well reasonable soaking time testing device comprises an online nuclear magnetic resonance tester, a core holder arranged on the online nuclear magnetic resonance tester, a resistivity tester connected to the core holder, a methane gas cylinder connected to the inlet of the core holder, a simulated fracturing fluid injection pump connected to the inlet of the core holder, a nitrogen gas cylinder connected to the inlet of the core holder, a first pressure sensor connected to the inlet of the core holder, a vacuum pump connected to the core holder, a confining pressure pump connected to the core holder, and a second pressure sensor connected to the inlet of the core holder. A sensor, a throttle valve connected to the outlet of the methane cylinder, a first valve connected to the outlet of the throttle valve, a third valve connected to the outlet of the first valve, a fifth valve connected to the outlet of the core holder, and a computer control system electrically connected to the first pressure sensor, the second pressure sensor and the core holder, respectively; a core sample to be tested is placed in the core holder, the resistivity tester detects the resistivity of the core sample to be tested in the core holder, and the online nuclear magnetic resonance tester and the core holder are arranged in a constant temperature chamber; The method for determining a reasonable shut-in time of a shale gas well comprises the following steps: Step S1, respectively selecting a plurality of first core samples with natural cracks on the surface and a plurality of second core samples without natural cracks on the surface; washing the first core samples and the second core samples with salt, oil and drying; measuring the length and diameter of the first core samples and the second core samples, and obtaining the volumes of the first core samples and the second core samples; respectively measuring and obtaining the porosity Φ0 of the first core samples and the second core samples; Step S2, presetting the temperature in the constant temperature chamber to the temperature of the reservoir where the first core sample and the second core sample are located, placing the first core sample in the core holder, starting the confining pressure pump, and applying core confining pressure to the first core sample in the core holder; using the vacuum pump to evacuate the core holder to simulate the state of the first core sample in the reservoir; Step S3, injecting methane into the first core sample in the core holder using the methane gas cylinder until the pore pressure of the reservoir is reached, and maintaining the pressure for 4 days; Step S4, starting the simulated fracturing fluid injection pump and injecting simulated fracturing fluid into the core holder; closing the third valve; Step S5, starting the resistivity tester to measure the resistivity change curve of the first core sample; at the same time, continuously measuring and obtaining the half-life of the pressure decay of the first pressure sensor using the pressure decay method until an inflection point appears in the resistivity change curve of the first core sample; Step S6, replacing the first core sample in the core holder with the second core sample, repeating steps S2 to S5; respectively obtaining the experimental time t of the first core sample at which the shortest pressure decay half-life occurs. 1f and the experimental duration t of the shortest pressure decay half-life of the second core sample 1m ; During the period from the injection of the simulated fracturing fluid in step S4 to the occurrence of an inflection point in the resistivity change curve in step S5, the online nuclear magnetic resonance tester is used to continuously monitor the methane nuclear magnetic resonance signals of the first core sample and the second core sample, and the time point t at which the core nuclear magnetic resonance signal of the first core sample has the largest change amplitude is obtained. 2f and the time point t at which the core nuclear magnetic signal of the second core sample has the largest change amplitude 2m ; Step S7, the experimental time t of the shortest pressure decay half-life of the first core sample 1f , the experimental duration t of the shortest pressure decay half-life of the second core sample 1m , the time point t at which the core nuclear magnetic resonance signal of the first core sample has the largest change amplitude 2f and the time point t at which the core nuclear magnetic signal of the second core sample has the largest change amplitude 2m The two middle arrays after sorting are taken as time endpoints. The values ​​in the time endpoints are the soaking time t at the core scale. c ; Step S8, according to the soaking time t at the core scale c Calculate the shut-in time t of shale gas well R , which is expressed as: Wherein, V2 represents the total transformation volume of the reservoir by hydraulic fracturing; V3 represents the total volume of sand-filled fractures formed in the reservoir after hydraulic fracturing; V c represents the volume of simulated fracturing fluid pumped in to establish the target water saturation of the core; V1 represents the volume of the first core sample or the second core sample; V f Indicates the volume of fracturing fluid pumped in during on-site hydraulic fracturing construction; Φ m It represents the reservoir porosity after removing hydraulic fractures in the total hydraulic fracturing transformation area.

2. The determination method according to claim 1, characterized in that: A second valve, a buffer container and a fourth valve are connected in series between the nitrogen bottle and the core clamp.

3. The determination method according to claim 1, characterized in that: A sixth valve is provided between the simulated fracturing fluid injection pump and the third valve.

4. The determination method according to claim 1, characterized in that: The confining pressure pump is provided with a seventh valve.

5. The determination method according to claim 1, characterized in that: In step S4, the volume of the injected simulated fracturing fluid is expressed as: V c =S w V1Φ0 S w =(V f -V3Φ f ) / [(V2-V3)Φ m ] Among them, S w represents the target water saturation of the first core sample and / or the second core sample; Φ f Indicates the porosity of hydraulically sanded fractures.

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