Simulation device and method for forced imbibition of shale

Abstract

The invention discloses a device and a method for simulating forced shale imbibition. The method comprises the following steps: putting a rock sample embedded into a horizontal well simulation pipe into an experiment cabin; the experiment module is heated by a heating device to reach a preset formation temperature and is stabilized; injecting simulated oil into the experiment cabin at a preset injection speed by using an injection system until the injection pressure reaches the preset formation pressure and is stable; injecting fracturing fluid into the experiment module by using an injection system until the injection pressure reaches the preset pressure and is stable, and recording the pressure by using a pressure monitoring system at intervals of preset time; a new rock sample embedded into the horizontal well simulation pipe is replaced, and stratum environment simulation is executed; and injecting fracturing fluid into the experiment module by using an injection system under the preset fracture forming pressure until the injection pressure is reduced and stable at the preset fracture initiation pressure, and executing forced imbibition simulation. The influence of formation pressure, formation temperature, artificial horizontal fractures and fracturing fluid injection pressure on shale forced imbibition is comprehensively considered, and the forced imbibition rule under the real formation condition is reflected.

Description

Technical Field

[0001] The present invention relates to the field of oil and natural gas development, and in particular to a shale forced imbibition simulation device and method. Background Art

[0002] Currently, shale oil reservoir development has gradually become a global energy focus. Shale reservoirs typically exhibit low porosity, low permeability, and integrated source and reservoir characteristics. This creates significant resistance to fluid flow, making it difficult for shale oil to achieve stable, natural industrial production. In recent years, large-scale horizontal well fracturing technology has become a cost-effective means of developing shale oil reservoirs. However, the fracturing fluid flowback rate during shale reservoir fracturing is extremely low, with large amounts of fracturing fluid remaining in the reservoir. This has led to increased production capacity in some wells after periods of shut-in, resulting in a phenomenon known as "low flowback, high production," which has attracted widespread attention from industry insiders.

[0003] Shale has a complex composition and unique microstructure, particularly high clay content, with well-developed clay pores and bedding. Water imbibition has a unique impact on the microstructure, thus affecting shale gas well productivity. Low fracturing fluid flowback rates during hydraulic fracturing are often attributed to a number of factors, primarily the strong imbibition effect of the fracturing fluid within the reservoir. Therefore, it is crucial to understand the mechanisms of forced imbibition in shale. Imbibition can be categorized as spontaneous and pressurized. Spontaneous imbibition occurs when a wetting fluid displaces a non-wetting fluid from the rock pores through capillary forces in the absence of external pressure. Forced imbibition occurs when the imbibition displacement occurs under an external pressure differential. In the initial stages of hydraulic fracturing in shale reservoirs, high pressure and capillary forces within the fractures cause the fracturing fluid to penetrate into the matrix. This phase is generally considered forced imbibition. After large-scale fracturing in shale reservoirs, the pressure patterns and oil production patterns during the forced imbibition phase remain unclear. Therefore, accurately simulating the forced imbibition process using laboratory experimental methods is crucial. Summary of the Invention

[0004] The present invention provides a simulation device and method for forced shale imbibition, which comprehensively considers factors such as formation pressure, formation temperature, artificial horizontal fractures, and fracturing fluid injection pressure to provide a simulation method and device that can accurately reflect the forced shale imbibition law.

[0005] The technical solution of the present invention is:

[0006] In a first aspect, an embodiment of the present application provides a method for simulating forced imbibition of shale, comprising:

[0007] Formation environment simulation: placing a rock sample embedded in a horizontal well simulation tube into the experimental chamber, connecting a pressure monitoring system to the rock sample embedded in the horizontal well simulation tube, and connecting the horizontal well simulation tube to the injection system;

[0008] The experimental chamber is heated by a heating device to reach a preset formation temperature and stabilize it;

[0009] Using the injection system to inject simulated oil into the experimental chamber through the horizontal well simulation pipe at a preset injection rate until the injection pressure reaches a preset formation pressure and stabilizes, and recording the injection time of the simulated oil;

[0010] Forced imbibition simulation: using the injection system to inject fracturing fluid into the experimental chamber through the horizontal well simulation pipe until the injection pressure reaches a preset pressure and stabilizes, and using the pressure monitoring system to record the pressure of the rock sample embedded in the horizontal well simulation pipe at preset intervals;

[0011] Replace the rock sample embedded in the horizontal well simulation tube with a new one and re-execute the formation environment simulation process;

[0012] The injection system is used to inject fracturing fluid into the experimental chamber through the horizontal well simulation pipe at a preset fracture creation pressure to create fractures, until the injection pressure decreases and stabilizes at the preset fracture initiation pressure, and the above-mentioned forced imbibition simulation process is executed again.

[0013] In one or some optional implementations of the embodiment of the present application, after performing the forced imbibition simulation, the method further includes:

[0014] Connecting the production system to the experimental chamber so that the fracturing fluid in the experimental chamber is discharged back into the production system;

[0015] The volume of crude oil in the fracturing fluid collected by the recovery system is measured, and the degree of recovery is calculated.

[0016] In one or some optional implementations of the embodiment of the present application, the recovery degree is calculated by the following formula:

[0017]

[0018] Where: R is the degree of recovery; V orp v is the volume of crude oil in the fracturing fluid that is discharged; o is the preset injection speed of the simulated oil; t is the injection time of the simulated oil.

[0019] In one or some optional implementations of the embodiments of the present application, the rock sample embedded in the horizontal well simulation tube is prepared by the following method:

[0020] According to the density and diameter of the perforations on the horizontal well during the on-site perforation process, holes are opened in the horizontal simulation pipe in equal proportion according to the ratio of the horizontal well to the length of the horizontal simulation pipe;

[0021] According to the position of the on-site horizontal well in the shale reservoir and the ratio of the depth of the shale reservoir to the height of the rock sample, the horizontal simulation tube is embedded into the rock sample in equal proportion.

[0022] In a second aspect, an embodiment of the present application further provides a shale forced imbibition simulation device, which is applied to the simulation method described in the first aspect, and includes an experimental chamber, a rock sample embedded in a horizontal well simulation pipe, an injection system, a pressure monitoring system, and a heating device;

[0023] The experimental chamber is used to accommodate the rock sample embedded in the horizontal well simulation tube;

[0024] The heating device is provided outside the experimental chamber and is used to heat the experimental chamber to a preset formation temperature and stabilize it;

[0025] The injection system is arranged outside the experimental chamber and can be communicated with the horizontal well simulation pipe, and is used to inject simulated oil into the experimental chamber through the horizontal well simulation pipe at a preset injection rate until the injection pressure reaches a preset formation pressure and stabilizes, inject fracturing fluid into the experimental chamber through the horizontal well simulation pipe until the injection pressure reaches a preset pressure and stabilizes, and, when it is necessary to create fractures in the rock sample embedded in the horizontal well simulation pipe, inject fracturing fluid into the experimental chamber at a preset fracture creation pressure through the horizontal well simulation pipe to create fractures until the injection pressure decreases below a preset fracture initiation pressure and stabilizes;

[0026] The pressure monitoring system can be connected to the rock sample embedded in the horizontal well simulation pipe, and is used to record the pressure of the rock sample embedded in the horizontal well simulation pipe at preset time intervals after the injection system injects fracturing fluid into the experimental chamber through the horizontal well simulation pipe until the injection pressure reaches a preset pressure and stabilizes.

[0027] In one or some optional implementations of the embodiment of the present application, the injection system includes a constant speed and constant pressure pump and an intermediate container;

[0028] The intermediate container is in communication with the horizontal well simulation pipe;

[0029] The intermediate container is used to contain the simulated oil or the fracturing fluid;

[0030] The constant speed and constant pressure pump is used to control the injection pressure of the simulated oil or the fracturing fluid.

[0031] In one or some optional implementations of the embodiment of the present application, the experimental cabin includes closed side panels, a removable top panel and a removable bottom panel;

[0032] The removable top panel and the removable bottom panel are both detachably connected to the closed side panels;

[0033] Pressure measuring points are symmetrically provided on the removable top plate and the removable bottom plate;

[0034] The pressure monitoring system passes through the pressure measuring point and can abut against the rock sample embedded in the horizontal well simulation pipe.

[0035] In one or some optional implementations of the embodiment of the present application, the pressure monitoring system includes a pressure sensor and a pressure sensitive element connected to the pressure sensor;

[0036] The pressure sensitive element passes through the pressure measuring point and can abut against the rock sample embedded in the horizontal well simulation pipe.

[0037] One or some optional implementations of the embodiment of the present application further include a production system;

[0038] The production system may be in communication with the experimental chamber, and is used to collect the fracturing fluid discharged from the experimental chamber and measure the volume of crude oil in the fracturing fluid.

[0039] In one or some optional implementations of the embodiment of the present application, the production system includes a produced liquid collector and a reverse discharge end valve connected;

[0040] The produced fluid collector can be in communication with the experimental chamber, and is used to collect the backflow fracturing fluid and measure the volume of crude oil in the fracturing fluid;

[0041] The reverse discharge end valve is used to switch the connection or isolation state between the produced liquid collector and the experimental chamber.

[0042] The beneficial effects of the above technical solutions provided by the embodiments of the present application include at least:

[0043] The embodiment of the present application provides a simulation method for forced imbibition of shale, which heats the experimental chamber by a heating device to reach a preset formation temperature and stabilize it, so as to simulate the formation temperature and restore the real formation temperature; an injection system is used to inject simulated oil into the experimental chamber through a horizontal well simulation pipe at a preset injection rate until the injection pressure reaches a preset formation pressure and stabilizes, so as to simulate the formation pressure and restore the real formation pressure; an injection system is used to inject fracturing fluid into the experimental chamber through a horizontal well simulation pipe, and the injection system controls the injection pressure when injecting the fracturing fluid so that the injection pressure reaches a preset pressure and stabilizes; an injection system is used to inject fracturing fluid into the experimental chamber through a horizontal well simulation pipe at a preset fracture-making pressure to create fractures; and the influence of factors such as formation pressure, formation temperature, artificial horizontal fractures, and fracturing fluid injection pressure on the forced imbibition process of shale is comprehensively considered. Compared with the existing technology, it can better reflect the forced imbibition law under real formation conditions, and the results are more real and reliable.

[0044] During the forced imbibition simulation process, an injection system is used to inject fracturing fluid into the experimental chamber through the horizontal well simulation tube until the injection pressure reaches the preset pressure and stabilizes. The rock sample embedded in the horizontal well simulation tube is then forced to imbibe. At the same time, a pressure monitoring system is used to record the pressure of the rock sample embedded in the horizontal well simulation tube at preset intervals, thereby realizing physical simulation research on the multiple processes of "fracturing, well soaking, and imbibition" in shale reservoirs. Simulation can be performed according to the actual different production modes of different oil fields, thereby enhancing the applicability of this simulation method.

[0045] Other features and advantages of the present application will be described in the following description, and in part will become apparent from the description, or will be understood by practicing the present invention. The purposes and other advantages of the present application can be realized and obtained by the structures particularly pointed out in the written description, claims, and drawings.

[0046] The technical solution of the present application is further described in detail below through the accompanying drawings and examples. BRIEF DESCRIPTION OF THE DRAWINGS

[0047] The accompanying drawings are used to provide a further understanding of the present application and constitute a part of the specification. Together with the embodiments of the present application, they are used to explain the present application and do not constitute a limitation of the present application. In the accompanying drawings:

[0048] Figure 1 A schematic diagram of a shale forced imbibition simulation device provided by the present invention;

[0049] Figure 2 Schematic diagram of reservoir simulation without and with fractures according to the present invention;

[0050] Figure 3 This is the pressure field distribution diagram of the simulated fracture-free reservoir after different forced imbibition times in the present invention;

[0051] Figure 4 This is a diagram showing the pressure field distribution of a fractured reservoir simulated by the present invention after different forced imbibition times;

[0052] Figure 5 A schematic flow chart of the shale forced imbibition simulation method provided by the present invention;

[0053] Description of reference numerals:

[0054] 1. Bracket; 2. Experimental chamber; 3. Heating device; 4. Constant-speed and constant-pressure pump; 5. Outlet valve; 6. Intermediate container; 7. Inner cavity of intermediate container; 8. Inlet valve; 9. Pressure gauge; 10. Backflow valve; 11. Back-pressure valve; 12. Produced fluid collector; 13. Pressure sensor; 14. Computer; 15. Rock sample embedded in horizontal well simulation pipe; 1-1. Pressure measuring point; 1-2. Horizontal well simulation pipe; 1-3. Inner cavity of experimental chamber; 1-4. Fracture. DETAILED DESCRIPTION

[0055] In the following description, specific details such as specific system structures and techniques are provided for purposes of illustration rather than limitation to facilitate a thorough understanding of the embodiments of the present application. However, it will be apparent to those skilled in the art that the present application may be implemented in other embodiments without these specific details. In other cases, detailed descriptions of well-known systems, devices, circuits, and methods are omitted to avoid obscuring the description of the present application with unnecessary detail.

[0056] It should be understood that when used in the present specification and the appended claims, the term "comprising" indicates the presence of described features, integers, steps, operations, elements and / or components, but does not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components and / or collections thereof.

[0057] It will also be understood that the term "and / or" used in this specification and the appended claims refers to and includes any and all possible combinations of one or more of the associated listed items.

[0058] As used in this specification and the appended claims, the term "if" can be interpreted as "when" or "upon" or "in response to determining" or "in response to detecting," depending on the context. Similarly, the phrase "if it is determined" or "if [described condition or event] is detected" can be interpreted as meaning "upon determination" or "in response to determining" or "upon detection of [described condition or event]" or "in response to detecting [described condition or event]," depending on the context.

[0059] In addition, in the description of the present application specification and the appended claims, the terms "first", "second", "third", etc. are only used to distinguish the descriptions and cannot be understood as indicating or implying relative importance.

[0060] References to "one embodiment" or "some embodiments" in this specification mean that a particular feature, structure, or characteristic described in conjunction with that embodiment is included in one or more embodiments of the present application. Thus, phrases such as "in one embodiment," "in some embodiments," "in other embodiments," and "in other embodiments" appearing in various places in this specification do not necessarily refer to the same embodiment, but rather mean "one or more but not all embodiments," unless otherwise specifically emphasized. The terms "including," "comprising," "having," and variations thereof all mean "including but not limited to," unless otherwise specifically emphasized.

[0061] It should be understood that the size of the serial numbers of the steps in the following embodiments does not mean the order of execution. The execution order of each process should be determined by its function and internal logic, and should not constitute any limitation on the implementation process of the embodiments of this application.

[0062] The inventors have found that the existing methods for studying shale imbibition laws mainly include the following:

[0063] Chen Yang et al. (Chen Yang, Han Dawei, Lu Xiangguo, et al. Experimental study on the effect of fracture morphology of network fracturing on imbibition recovery in low-permeability reservoirs [J]. Daqing Petroleum Geology and Development, 2017, 36(4):123-127) used the fluid properties and geological characteristics of the Fuyu reservoir outside Daqing as the simulation object and conducted an experiment on the effect of fracture length and number of network fracturing on imbibition recovery in a simulation model. This method takes into account factors such as fluid properties and geological characteristics, but the simulation numerical solution has many assumptions and the simulation results have large errors. The three-dimensional physical model can more realistically reflect the forced imbibition law and the simulation results are more realistic.

[0064] Wang Qingguo et al. (Wang Qingguo, Wang Tingting, Chen Yang, et al. Static imbibition oil recovery effect and its influencing factors in the Fuyu oil layer in Daqing [J]. Oilfield Chemistry, 2018, 35(2): 308-312) conducted a study on the imbibition oil recovery effect and its influencing factors through a three-dimensional physical model experiment. They studied the effects of different surfactants on the imbibition oil recovery effect in tight oil reservoirs outside Daqing. This method studied the effects of pore surface wettability and fluid interfacial tension on spontaneous imbibition, but did not consider the effects of formation temperature, formation pressure, and pressure difference during well soaking on the imbibition process during the actual reservoir imbibition process.

[0065] Guo Jianchun et al. (Guo Jianchun, Tao Liang, Hu Kejian, et al. Experimental study on the imbibition behavior of water in shale reservoirs [J]. Acta Petrolei Sinica, 2022, 43(9): 1295-1304) studied the Longmaxi Formation shale in the southern Sichuan Basin. They independently developed a shale imbibition experimental device that takes into account reservoir temperature and pressure conditions. They also combined low-field nuclear magnetic resonance technology to achieve online monitoring of the migration and distribution of fluids in shale pores. This method takes into account the effects of formation temperature and formation pressure, but still studies the spontaneous imbibition between shale and fracturing fluid, and does not consider the forced imbibition of fracturing fluids under the pressure differential during the well soaking process.

[0066] None of the above research methods comprehensively consider the influence of factors such as formation temperature, formation pressure, fracturing fluid injection pressure, and artificial horizontal fractures on the forced imbibition law of shale, making it difficult to clarify the pressure change law of the actual formation during the forced imbibition process.

[0067] Therefore, in response to the above problems, the inventors have conducted research and development and made this application, providing a simulation device and method for forced imbibition of shale, so as to carry out three-dimensional physical simulation experiments of forced imbibition of shale under real formation conditions, realize the multi-process physical simulation of "fracturing, well shut-in, and imbibition" of shale reservoirs, and provide a theoretical basis for understanding the forced imbibition law of fracturing fluid after fracturing of shale oil reservoirs.

[0068] In order to illustrate the technical solution of the present application, specific embodiments are provided below.

[0069] This embodiment provides a shale forced imbibition simulation device, referring to Figure 1 and Figure 2 This apparatus includes an experimental chamber 2, a rock sample 15 embedded in a horizontal well simulation tube, an injection system (not shown), a pressure monitoring system (not shown), and a heating device 3. The experimental chamber 2 is used to accommodate the rock sample 15 embedded in the horizontal well simulation tube. Specifically, the rock sample 15 embedded in the horizontal well simulation tube is placed in the experimental chamber cavity 1-3. The heating device 3 is located outside the experimental chamber 2. The heating device 3 provides a sealed environment and accommodates the experimental chamber 2. It also has the function of heating the experimental chamber 2 and maintaining a constant temperature. Specifically, the heating device 3 heats the experimental chamber 2 to a preset formation temperature and stabilizes it to restore the actual formation temperature. The heating device 3 can refer to devices such as muffle furnaces, resistance furnaces, and induction furnaces in the prior art. The pressure monitoring system can be connected to the rock sample 15 embedded in the horizontal well simulation tube. After the injection system injects fracturing fluid into the experimental chamber 2 through the horizontal well simulation tube 1-2 and the injection pressure reaches a preset pressure and stabilizes, it records the pressure of the rock sample at preset intervals.

[0070] The injection system is arranged outside the experimental chamber 2, specifically outside the heating device 3, and can be connected to the horizontal well simulation pipe 1-2. When in use, the injection system can inject simulated oil or fracturing fluid into the experimental chamber 2 through the horizontal well simulation pipe 1-2, and can control the injection rate and injection pressure to achieve different simulation scenarios. When formation pressure simulation is required, the injection system can inject simulated oil into the experimental chamber 2 at a preset injection rate until the injection pressure reaches and stabilizes to the preset formation pressure to restore the real pressure of the formation. Alternatively, when forced imbibition simulation is required, fracturing fluid is injected into the experimental chamber 2 through the horizontal well simulation pipe 1-2 until the injection pressure reaches the preset pressure (i.e., the instantaneous shut-in bottom hole pressure after on-site hydraulic fracturing) and stabilizes to restore the real pressure during shale reservoir fracturing. Alternatively, when it is necessary to create fractures in the rock sample to simulate on-site fracture creation, fracturing fluid is injected into the experimental chamber 2 through the horizontal well simulation pipe 1-2 at a preset fracture creation pressure (i.e., exceeding the formation fracture pressure) to create fractures until the injection pressure decreases and stabilizes at the preset fracture initiation pressure.

[0071] In a specific embodiment, referring to Figure 1The injection system includes a constant speed and constant pressure pump 4, an outlet valve 5, an intermediate container 6 and an inlet valve 8 connected in sequence via a first pipeline (not shown in the figure). The constant speed and constant pressure pump 4 is used to control the injection pressure of the simulated oil or fracturing fluid, and by controlling the injection pressure, the above-mentioned formation pressure simulation, forced imbibition simulation and fracture creation can be achieved. The outlet valve 5 is used to switch the state of connection or disconnection between the constant speed and constant pressure pump 4 and the intermediate container 6. The intermediate container 6 is connected to the horizontal well simulation pipe 1-2, and the intermediate container 6 is provided with an intermediate container inner cavity 7 for accommodating fracturing fluid or simulated oil. At the same time, an inlet valve 8 is set between the intermediate container 6 and the horizontal well simulation pipe 1-2, and the inlet valve 8 is used to switch the state of connection or disconnection between the intermediate container 6 and the horizontal well simulation pipe 1-2.

[0072] In a specific embodiment, referring to Figure 1 The experimental chamber 2 includes closed side panels (not shown), a removable top panel (not shown), and a removable bottom panel (not shown). The removable top panel and the removable bottom panel are both detachably connected to the closed side panels. Pressure measuring points 1-1 are symmetrically arranged on the removable top panel and the removable bottom panel. The pressure monitoring system passes through the pressure measuring points 1-1 and can contact the rock sample 15 embedded in the horizontal well simulation pipe. The pressure measuring points 1-1 are preferably evenly distributed on the removable top panel and the removable bottom panel, so that the pressure monitoring system can monitor the pressure of the rock sample 15 embedded in the horizontal well simulation pipe at different positions and at different times, thereby understanding the pressure changes of the rock sample 15 embedded in the horizontal well simulation pipe. At the same time, the number of pressure measuring points 1-1 can be adjusted according to the size of the rock sample 15 embedded in the horizontal well simulation tube. For example, when the size of the rock sample 15 embedded in the horizontal well simulation tube is large, the number of pressure measuring points 1-1 should be increased so that the monitoring range of the pressure monitoring system can ensure that it covers the entire rock sample 15 embedded in the horizontal well simulation tube, avoiding the omission of pressure monitoring areas and affecting the experimental results of forced imbibition simulation. Figure 1 and Figure 2 For a 20-cm-long rock sample 15 embedded in a horizontal well simulation tube, an embodiment is presented for arranging 16 pressure measuring points 1-1. To facilitate support and fixation of the experimental chamber 2, the chamber 2 can be connected to a bracket 1. This bracket 1 ensures that, when the chamber 2 is placed within the heating device 3, sufficient space remains between the pressure measuring points 1-1 on the removable base plate and the heating device 3, facilitating access of the pressure monitoring system to the pressure measuring points 1-1.

[0073] In a specific embodiment, referring to Figure 1The pressure monitoring system includes a pressure sensor 13 and a pressure sensitive element (not shown in the figure) connected to the pressure sensor 13. The pressure sensitive element passes through the pressure measuring point 1-1 and can abut against the rock sample 15 embedded in the horizontal well simulation pipe. The pressure sensor 13 can refer to the device in the prior art that can convert pressure into an electrical signal, such as a strain gauge pressure sensor, a piezoresistive pressure sensor, a capacitive pressure sensor, etc. When in use, the pressure of the rock sample 15 embedded in the horizontal well simulation pipe is detected by the pressure sensitive element, and the pressure is transmitted to the pressure sensor 13. The pressure sensor 13 converts the pressure into a corresponding electrical signal to obtain the measured pressure result. The detection results of the pressure sensor 13 and the pressure sensitive element are fast and highly accurate, so as to obtain the experimental results of the forced imbibition simulation with high accuracy. The pressure sensor 13 can be connected to the computer 14, and the pressure measured in real time by the pressure sensor 13 is transmitted to the computer 14 to facilitate the subsequent processing of pressure and time data, such as drawing. Figure 3 and Figure 4 The pressure field distribution diagram is shown.

[0074] In a specific embodiment, referring to Figure 1 The simulation device also includes a production system, which can be connected to the experimental chamber 2. After the forced imbibition simulation is performed, the production system is connected to the experimental chamber 2 to simulate the process of "depletion mining" of the shale reservoir. The crude oil forced to be imbibed by the rock sample 15 embedded in the horizontal well simulation pipe is driven into the fracture 1-4. Water is continuously injected into the fracture 1-4 to bring the forced imbibition crude oil out of the experimental chamber 2. The production system is used to collect the fracturing fluid discharged from the experimental chamber 2, measure the volume of crude oil in the fracturing fluid, and calculate the recovery degree according to the following formula (1), providing a theoretical basis for understanding the oil production law after fracturing of shale oil reservoirs:

[0075]

[0076] Where: R is the degree of recovery, dimensionless; V orp is the volume of crude oil in the backflow fracturing fluid, cm 3 ;v o is the preset injection speed of the simulated oil, cm 3 / min; t is the injection time of simulated oil, min.

[0077] In a specific embodiment, referring to Figure 1The production system includes a produced fluid collector 12 and a reverse discharge valve 10 connected via a second pipeline (not shown in the figure). The produced fluid collector 12 can be connected to the experimental chamber 2 to collect the reversed fracturing fluid and measure the volume of crude oil in the fracturing fluid. The produced fluid collector 12 can adopt an oil-water separator with a metering function in the prior art to separate the water phase and crude oil in the fracturing fluid to accurately measure the volume of crude oil. According to the volume of crude oil obtained, it is substituted into formula (1) to calculate the degree of production. The reverse discharge valve 10 is used to switch the connection or isolation state of the produced fluid collector 12 and the experimental chamber 2, and is easy to use. A back-pressure valve 11 can be set between the produced fluid collector 12 and the reverse-discharge end valve 10. Under normal circumstances, the back-pressure valve 11 is in a closed state to maintain a stable pressure. When the pressure exceeds the preset safety range, the back-pressure valve 11 will automatically open and release the excess load by overflow, thereby preventing the pressure from continuing to rise, so as to ensure the pressure balance of the entire production system, provide protection and adjustment functions, and avoid the second pipeline from rupturing due to insufficient pressure-bearing capacity under high pressure, resulting in overflow of the reverse-discharged fracturing fluid, affecting the measurement results of crude oil, making the calculated recovery degree less accurate, and unable to obtain the accurate oil production pattern after shale oil reservoir fracturing.

[0078] Based on the same inventive concept, this embodiment also provides a simulation method for forced imbibition of shale, which can use the above simulation device, see Figure 5 , the simulation method includes:

[0079] S1. Formation environment simulation: Place the rock sample embedded in the horizontal well simulation tube into the experimental chamber, connect the pressure monitoring system to the rock sample embedded in the horizontal well simulation tube, and connect the horizontal well simulation tube to the injection system.

[0080] In step S1, the preparation of the rock sample embedded in the horizontal well simulation tube can refer to the following method. First, the downhole rock or surface outcrop in the study area is drilled and cored to obtain the core. The drilling and coring method can be a conventional coring method or a pressure coring method, which is not limited here. The basic physical properties of the core, such as permeability and porosity, are measured. The permeability can be measured by the mercury injection method, the osmotic pressure difference method, the permeation test method and other methods of the existing technology. The porosity can be measured by the contact method and adsorption method and other methods of the existing technology. Then, the obtained core is made into a rock sample suitable for the size of the experimental chamber. Here, the specific size of the rock sample is not limited. It is preferred to use a rock sample with a length of 20 cm. The size of the experimental chamber is adaptively selected. Compared with small-scale rock samples, forced imbibition simulation is carried out on large-scale rock samples, which can better clarify the pressure change law of the actual formation during the forced imbibition process. Next, a horizontal well was simulated using a horizontal dummy tube. Based on the density and diameter of the perforations in the horizontal well during field perforation, holes were drilled in the horizontal dummy tube in proportion to the length of the horizontal well and the length of the horizontal dummy tube, simulating the perforation sizes during actual perforation operations. Finally, based on the location of the field horizontal well in the shale reservoir and the ratio of the shale reservoir depth to the rock sample height, the horizontal dummy tube was embedded in the rock sample in proportion to the horizontal well's position in the shale reservoir. This ensured that the prepared rock sample embedded with the horizontal well dummy tube provided a three-dimensional model that closely matched the actual shale reservoir.

[0081] S2. Heat the experimental chamber through the heating device to reach the preset formation temperature and stabilize it.

[0082] In step S2, the heating device can heat the experimental chamber to reach a preset formation temperature (specifically, refer to the actual formation temperature of the study area) and stabilize it, so that the rock sample embedded in the horizontal well simulation tube contained in the experimental chamber always maintains the preset formation temperature, that is, in the subsequent forced infiltration simulation process, the rock sample embedded in the horizontal well simulation tube is always at the preset formation temperature to restore the real formation temperature, thereby solving the problem in the existing technology that the important factor of formation temperature is ignored and affects the forced infiltration law of shale, so that the results of the subsequent forced infiltration simulation are more in line with the actual situation, with high authenticity and strong reliability.

[0083] S3. Use the injection system to inject simulated oil into the experimental chamber through the horizontal well simulation pipe at a preset injection rate until the injection pressure reaches the preset formation pressure and stabilizes, and record the injection time of the simulated oil.

[0084] In step S3, the injection system injects simulated oil into the experimental chamber through the horizontal simulation pipe at a preset injection speed. Here, the preset injection speed is preferably 0.1 cm 3 / min, to avoid excessive injection speed that may damage the rock sample embedded in the horizontal well simulation tube and affect the results of subsequent forced imbibition simulation, until the injection pressure reaches the preset formation pressure (for details, please refer to the actual formation pressure in the study area), then stop the injection of simulated oil and record the injection time of the simulated oil. Through the above-mentioned injection of simulated oil, the rock sample embedded in the horizontal well simulation tube is always at the preset formation pressure during the subsequent forced imbibition simulation process to restore the actual formation pressure, thereby solving the problem of ignoring the influence of formation pressure, an important factor, on the forced imbibition law of shale in the existing technology, making the results of the subsequent forced imbibition simulation more in line with the actual situation and more realistic and reliable.

[0085] S4. Forced imbibition simulation: The injection system is used to inject fracturing fluid into the experimental chamber through the horizontal well simulation tube until the injection pressure reaches the preset pressure and stabilizes. The pressure of the rock sample embedded in the horizontal well simulation tube is recorded at preset intervals using the pressure monitoring system.

[0086] In step S4, the preset pressure can be determined based on the instantaneous shut-in bottomhole pressure after the on-site fracturing operation in the study area. The injection system is used to inject fracturing fluid into the experimental chamber through the horizontal well simulation pipe, and the injection pressure of the fracturing fluid is controlled to reach the preset pressure. This solves the problem of ignoring the influence of the fracturing fluid injection pressure on the forced imbibition law of shale in the existing technology, so that the results of the subsequent forced imbibition simulation are more in line with the actual situation and the results are more real and reliable.

[0087] When the injection pressure of the above-mentioned fracturing fluid stabilizes at the preset pressure, the injection of the fracturing fluid is stopped. At this time, the rock sample embedded in the horizontal well simulation pipe begins to undergo forced imbibition and the well is shut down. At the same time, the pressure monitoring system is used to record the pressure at different positions of the rock sample embedded in the horizontal well simulation pipe at preset intervals (preferably 1 minute). Of course, in the actual forced imbibition process, in the initial stage of forced imbibition of the rock sample embedded in the horizontal well simulation pipe, the pressure changes greatly. The above-mentioned preset time is set to 1 minute. In the later stage of forced imbibition of the rock sample embedded in the horizontal well simulation pipe, in the near-wellbore area (i.e., the area close to the horizontal simulation pipe), when the pressure change is 1% or less, the above-mentioned preset time can be appropriately extended to 60 minutes. The test time is set to 180 minutes. See Figure 2 and Figure 3 , the horizontal simulation tube is set horizontally on the left side of the rock sample, refer to Figure 3 It can be found that when the rock sample embedded in the horizontal well simulation pipe is not fractured, that is, the forced imbibition of the reservoir without fractures is simulated, a large pressure is generated only around the wellbore (i.e., around the horizontal simulation pipe), and the pressure is difficult to spread away from the horizontal simulation pipe. After the well is shut down for 180 minutes, the wellbore pressure and the formation pressure ( Figure 3The formation pressure in the wellbore is basically the same as 15.56 MPa, and the soak pressure equilibration time is relatively short. Different preset pressures affect the fluid mobility in the formation, which in turn affects the flow characteristics of the oil-water phase during forced imbibition and the oil-water distribution near the wellbore during soaking. Properly increasing the preset pressure can better diffuse the fracturing fluid into the pores and fractures where the crude oil resides, improving the forced imbibition effect of shale oil. However, excessively high preset pressures can also damage and deform the reservoir rock, undermining the integrity of the reservoir and hindering the forced imbibition effect of the fracturing fluid.

[0088] In step S4, by controlling the injection pressure of the fracturing fluid, the prior art addresses the issue of ignoring the influence of fracturing fluid injection pressure on the forced imbibition pattern of shale. This makes the subsequent forced imbibition simulation results more realistic and reliable, and more accurate. Furthermore, step S4 also enables multi-process physical simulation of shale reservoirs, including fracturing, soaking, and imbibition, making this embodiment more practical.

[0089] After executing step S4, the production system is connected to the experimental chamber so that the fracturing fluid in the experimental chamber is discharged back to the production system to simulate the process of "depletion production" of the shale reservoir. The volume of crude oil in the fracturing fluid collected by the production system is measured, and the degree of recovery is calculated according to the above formula (1), providing a theoretical basis for understanding the oil production law after fracturing of shale oil reservoirs.

[0090] S5. Replace the rock sample embedded in the horizontal well simulation tube with a new one and re-execute the formation environment simulation process.

[0091] S6. Use the injection system to inject fracturing fluid into the experimental chamber through the horizontal well simulation pipe at a preset fracture creation pressure to create fractures until the injection pressure decreases and stabilizes at the preset fracture initiation pressure, and re-execute the above forced imbibition simulation process.

[0092] In step S6, the injection pressure is determined according to the bottom hole pressure during fracturing expansion with reference to the relevant parameters of the on-site artificial fracturing operation in the study area. The preset fracturing pressure should exceed the formation fracture pressure. The injection system is used to inject fracturing fluid into the experimental chamber through the horizontal well simulation pipe at the preset fracturing pressure to create fractures. When the injection pressure drops rapidly at the preset fracturing pressure and gradually recovers and reaches stability, it indicates that the rock sample has cracked and the crack expansion is stable, indicating that the fracturing is completed. Here, the preset fracturing pressure is determined according to the physical properties of the rock sample, such as the bottom hole pressure during on-site fracturing.

[0093] The simulation method for forced imbibition of shale provided in this embodiment is based on rock samples from actual formations and realizes physical simulation research on multiple processes of "fracturing, well shut-in, imbibition, and depletion production" in shale reservoirs. It can be simulated according to the actual different production modes of different oil fields, thereby enhancing the scope of application of this example and making it more practical. It can realize large-scale rock sample forced imbibition simulation experiments, comprehensively considering the influence of factors such as formation pressure, formation temperature, artificial horizontal fractures, and fracturing fluid injection pressure on the pressure distribution and oil production pattern during shale forced imbibition, and better reflecting the forced imbibition pattern under real formation conditions. At the same time, by real-time monitoring of the pressure at different positions of the rock sample, it is possible to truly reflect and quantitatively test the pressure distribution of the shale reservoir during different forced imbibition times. Based on the pressure data, a pressure field distribution map of the shale reservoir can be drawn, clearly showing the changing pattern of formation pressure during forced imbibition, which plays an important guiding role in understanding the forced imbibition process under real formation conditions.

[0094] For example, a forced imbibition simulation is performed based on a shale sample collected from a shale well in an oil field. Figure 1-Figure 5 , as follows:

[0095] (1) Testing basic physical properties: Based on the core collected from a certain reservoir section of an oil field, the basic physical property parameters of the core are measured;

[0096] (2) Simulating shale reservoirs and setting horizontal wells: The above-mentioned cores were made into 20 cm long cube rock samples to simulate actual reservoirs. According to the relevant perforation parameters of the horizontal wells (density and diameter of perforations) in the field perforation process, horizontal well simulation tubes 1-2 were prepared. According to the position of the field horizontal wells in the shale reservoir, the horizontal well simulation tubes 1-2 were embedded in the rock samples to obtain rock samples 15 embedded in the horizontal well simulation tubes. The rock samples 15 embedded in the horizontal well simulation tubes were placed in the inner cavity 1-3 of the experimental chamber. The pressure sensitive element was connected to the rock sample 15 embedded in the horizontal well simulation tubes through the pressure measuring point 1-1. The horizontal well simulation tubes 1-2 were connected to the injection system.

[0097] (3) Providing formation temperature and formation pressure: Place the experimental chamber 2 in the adding device, set the preset formation temperature to 60°C, use the heating device 3 to heat the experimental chamber 2 to 60°C and stabilize it, place the simulated oil in the inner cavity 7 of the intermediate container, and pump the constant speed and constant pressure pump 4 at 5cm 3 Inject simulated oil into the experimental chamber 2 at a rate of 1 / min until the injection pressure reaches 15.56 MPa (i.e., the preset formation pressure) and stabilizes. Then, close the inlet valve 8 and the constant-speed and constant-pressure pump 4, stop injecting simulated oil, and record the injection time as 163 min.

[0098] (4) Prepare fracturing fluid: The fracturing fluid is mainly water, with a salinity of 1000 mg / L and a water type of CaCl2, and replace the liquid in the inner cavity 7 of the intermediate container with the fracturing fluid;

[0099] (5) Injecting fracturing fluid: Based on the instantaneous bottom hole pressure after hydraulic fracturing on site (the value is 20.23 MPa), the preset pressure is 20.23 MPa, and the fracturing fluid is injected through the horizontal well simulation pipe 1-2 using a constant speed constant pressure pump 4. After the injection pressure reaches 20.23 MPa and stabilizes, the inlet end valve 8 is closed, and the rock sample 15 embedded in the horizontal well simulation pipe begins forced imbibition;

[0100] (6) Recording pressure at different times: In the initial stage of forced imbibition, the pressure data is recorded once every 1 minute by the multi-point pressure sensor 13. In the later stage of forced imbibition, the pressure data is recorded once every 60 minutes by the multi-point pressure sensor 13. The entire test process takes 180 minutes. The pressure data at different forced imbibition times are obtained and plotted as shown in the figure. Figure 3 As shown in the pressure field distribution diagram, the forced imbibition process ends;

[0101] (7) Backflow of fracturing fluid: Open the backflow valve and measure the volume of crude oil in the backflow fracturing fluid through the produced fluid collector 12 to be 0.13 cm3. The recovery degree is calculated by formula (1) to be 0.016%;

[0102] (8) Replace the rock sample and repeat steps (1)-(3). Refer to the relevant parameters of artificial fracture creation on site and determine the preset fracture creation pressure as 23.34 MPa according to the bottom hole pressure during fracturing expansion. Create fractures by constant speed and constant pressure pump 4. When the injection pressure drops rapidly and gradually returns to a stable state, the fracture creation is completed. Repeat steps (4)-(7) to obtain pressure data under different forced imbibition times and draw the following diagram: Figure 4 The pressure field distribution diagram shown in the figure shows that the volume of crude oil in the backflow fracturing fluid is 53.56 cm 3 The calculated recovery rate is 6.57%.

[0103] Reference Figure 3 , the experimental results of rock sample 15 embedded in the horizontal well simulation pipe without fracture were analyzed. It was found that only a large pressure was generated around the wellbore (i.e., the horizontal simulation pipe), and the pressure was difficult to propagate to the distant formation. After 180 minutes of soaking, the wellbore pressure was basically the same as the preset formation pressure (value of 15.56MPa), and the soaking pressure balance time was relatively short. Figure 4, the experimental results of rock sample 15 embedded in the horizontal well simulation pipe with fracture creation were analyzed. There was a large range of high pressure around the wellbore, and the crude oil that was forcibly sucked out entered the fractures 1-4 and was produced. This can be supported by the recovery rate. The recovery rate of rock sample 15 embedded in the horizontal well simulation pipe after fracture creation was 411 times that of rock sample 15 embedded in the horizontal well simulation pipe without fracture creation. In addition, the range of pressure propagation became larger. After 180 minutes of well shut-in, the pressure near the wellbore was still higher than the preset formation pressure, and the well shut-in pressure balance time was relatively long.

[0104] Finally, it is necessary to point out that this embodiment is only a preferred embodiment of the present invention and does not limit the present invention in any way, nor is it limited to the form disclosed herein. Without departing from the scope of the technical solution of the present invention, the technical content disclosed above can be used to make some changes or modifications to equivalent embodiments with equivalent changes. Based on the embodiments in this application, all other embodiments obtained by ordinary technicians in this field without making creative work are within the scope of protection of this application.

Claims

1. A method for simulating forced imbibition of shale, characterized in that: include: Formation environment simulation: placing a rock sample embedded in a horizontal well simulation tube into the experimental chamber, connecting a pressure monitoring system to the rock sample embedded in the horizontal well simulation tube, and connecting the horizontal well simulation tube to the injection system; The experimental chamber is heated by a heating device to reach a preset formation temperature and stabilize it; Using the injection system to inject simulated oil into the experimental chamber through the horizontal well simulation pipe at a preset injection rate until the injection pressure reaches a preset formation pressure and stabilizes, and recording the injection time of the simulated oil; Forced imbibition simulation: using the injection system to inject fracturing fluid into the experimental chamber through the horizontal well simulation pipe until the injection pressure reaches a preset pressure and stabilizes, and using the pressure monitoring system to record the pressure of the rock sample embedded in the horizontal well simulation pipe at preset intervals; Replace the rock sample embedded in the horizontal well simulation tube with a new one and re-execute the formation environment simulation process; The injection system is used to inject fracturing fluid into the experimental chamber through the horizontal well simulation pipe at a preset fracture creation pressure to create fractures, until the injection pressure decreases and stabilizes at the preset fracture initiation pressure, and the above-mentioned forced imbibition simulation process is executed again.

2. The simulation method according to claim 1, wherein: After performing forced imbibition simulation, also includes: Connecting the production system to the experimental chamber so that the fracturing fluid in the experimental chamber is discharged back into the production system; The volume of crude oil in the fracturing fluid collected by the recovery system is measured, and the degree of recovery is calculated.

3. The simulation method according to claim 2, wherein: The recovery degree is calculated by the following formula: Where: R is the degree of recovery; V orp v is the volume of crude oil in the fracturing fluid that is discharged; o is the preset injection speed of the simulated oil; t is the injection time of the simulated oil.

4. The simulation method according to claim 1, wherein: The rock sample embedded in the horizontal well simulation pipe is prepared by the following method: According to the density and diameter of the perforations on the horizontal well during the on-site perforation process, holes are opened in the horizontal simulation pipe in equal proportion according to the ratio of the horizontal well to the length of the horizontal simulation pipe; According to the position of the on-site horizontal well in the shale reservoir and the ratio of the depth of the shale reservoir to the height of the rock sample, the horizontal simulation tube is embedded into the rock sample in equal proportion.

5. A shale forced imbibition simulation device, characterized in that: The simulation method according to any one of claims 1 to 4 comprises an experimental chamber, a rock sample embedded in a horizontal well simulation pipe, an injection system, a pressure monitoring system and a heating device; The experimental chamber is used to accommodate the rock sample embedded in the horizontal well simulation tube; The heating device is provided outside the experimental chamber and is used to heat the experimental chamber to a preset formation temperature and stabilize it; The injection system is arranged outside the experimental chamber and can be communicated with the horizontal well simulation pipe, and is used to inject simulated oil into the experimental chamber through the horizontal well simulation pipe at a preset injection rate until the injection pressure reaches a preset formation pressure and stabilizes, inject fracturing fluid into the experimental chamber through the horizontal well simulation pipe until the injection pressure reaches a preset pressure and stabilizes, and, when it is necessary to create fractures in the rock sample embedded in the horizontal well simulation pipe, inject fracturing fluid into the experimental chamber at a preset fracture creation pressure through the horizontal well simulation pipe to create fractures until the injection pressure decreases below a preset fracture initiation pressure and stabilizes; The pressure monitoring system can be connected to the rock sample embedded in the horizontal well simulation pipe, and is used to record the pressure of the rock sample embedded in the horizontal well simulation pipe at preset time intervals after the injection system injects fracturing fluid into the experimental chamber through the horizontal well simulation pipe until the injection pressure reaches a preset pressure and stabilizes.

6. The simulation device according to claim 5, wherein: The injection system includes a constant speed and constant pressure pump and an intermediate container; The intermediate container is in communication with the horizontal well simulation pipe; The intermediate container is used to contain the simulated oil or the fracturing fluid; The constant speed and constant pressure pump is used to control the injection pressure of the simulated oil or the fracturing fluid.

7. The simulation device according to claim 5, wherein: The experimental cabin includes closed side panels, a removable top panel and a removable bottom panel; The removable top panel and the removable bottom panel are both detachably connected to the closed side panels; Pressure measuring points are symmetrically provided on the removable top plate and the removable bottom plate; The pressure monitoring system passes through the pressure measuring point and can abut against the rock sample embedded in the horizontal well simulation pipe.

8. The simulation device according to claim 7, wherein: The pressure monitoring system includes a pressure sensor and a pressure sensitive element connected to the pressure sensor; The pressure sensitive element passes through the pressure measuring point and can abut against the rock sample embedded in the horizontal well simulation pipe.

9. The simulation device according to claim 5, wherein: It also includes extraction systems; The production system may be in communication with the experimental chamber, and is used to collect the fracturing fluid discharged from the experimental chamber and measure the volume of crude oil in the fracturing fluid.

10. The simulation device according to claim 9, wherein The production system includes a connected produced liquid collector and a reverse discharge end valve; The produced fluid collector can be in communication with the experimental chamber, and is used to collect the backflow fracturing fluid and measure the volume of crude oil in the fracturing fluid; The reverse discharge end valve is used to switch the connection or isolation state between the produced liquid collector and the experimental chamber.

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