Fracturing proppant flowback physical model and simulation method for oil and gas reservoir development

Abstract

The application discloses an oil and gas reservoir development fracturing proppant flowback physical model and a simulation method. The model comprises a fracturing physical simulation system, an imaging system and a collection weighing system; the fracturing physical simulation system comprises an ISCO plunger double pump, an intermediate container, a confining pressure pump, a core holder and a simulated rock sample; the imaging system comprises a macro lens camera, a plurality of PIV lasers and a terminal device; the simulated rock sample is in a cylindrical shape and comprises sapphire glass and a real core; the sapphire glass and the real core are both in a semi-cylindrical shape; the plurality of PIV lasers and the macro lens camera are arranged in the sapphire glass respectively; the plurality of PIV lasers are uniformly distributed on two sides of the macro lens camera; and an outlet pipeline of the core holder is connected with the collection weighing system. The model can obtain the migration track and real-time velocity distribution of the proppant, and obtain the relationship between the flowback velocity and the proppant migration, thereby being favorable for the optimization decision of the fracturing fluid flowback velocity and the guidance of the oil reservoir fracturing production.

Description

Technical Field

[0001] This invention relates to the field of oil and gas reservoir development technology, and in particular to a physical model and simulation method for the flowback of proppant in oil and gas reservoir fracturing. Background Technology

[0002] As the application of fracturing technology in oil and gas field stimulation and high water-cut late-stage production enhancement continues to expand, the post-fracturing fluid flowback process has become a crucial factor restricting fracturing effectiveness. The proper control of the fracturing fluid flowback rate directly affects the conductivity and long-term production capacity of artificial fractures: if the flowback rate is too fast, it may cause a large amount of proppant backflow, exacerbating the risk of fracture closure, and even leading to sand accumulation at the bottom of the well, burying the producing formation, or eroding surface equipment, severely impacting testing and production efficiency; if the flowback rate is too slow, fracturing fluid will remain in the formation, causing secondary damage. Therefore, accurately characterizing the proppant flowback pattern and selecting the optimal flowback rate corresponding to the critical sand production point is crucial for the success of fracturing operations. Summary of the Invention

[0003] To enrich the product range of physical models for proppant flowback in oil and gas reservoir development and increase the selection space for physical simulation methods of proppant flowback in oil and gas reservoir development, this invention provides a physical model and simulation method for proppant flowback in oil and gas reservoir development.

[0004] In a first aspect, embodiments of the present invention provide a physical model for the flowback of proppant in oil and gas reservoir development, including a fracturing physical simulation system, an imaging system, and a collection and weighing system;

[0005] The fracturing physical simulation system includes an ISCO plunger dual pump, an intermediate container, a confining pressure pump, a core holder, and a simulated rock sample; the ISCO plunger dual pump, the intermediate container, and the core holder are connected in sequence; the confining pressure pump is connected to the confining pressure chamber of the core holder; the core holder is used to hold the simulated rock sample; and the intermediate container is used to hold fracturing fluid.

[0006] The imaging system includes a macro camera, multiple PIV lasers, and a terminal device; the terminal device is signal-connected to the multiple PIV lasers and the macro camera respectively.

[0007] The simulated rock sample is cylindrical and consists of a sapphire glass and a real rock core bonded together at the top and bottom. Both the sapphire glass and the real rock core are semi-cylindrical.

[0008] The plurality of PIV lasers and the macro camera are respectively disposed inside the sapphire glass and located directly above the real rock core;

[0009] The multiple PIV lasers are evenly distributed on both sides of the macro camera;

[0010] The outlet pipeline of the core holder is connected to the collection and weighing system.

[0011] In one or more optional embodiments, a sealed mounting cavity is provided inside the sapphire glass, and the macro camera and the plurality of PIV lasers are all disposed inside the mounting cavity.

[0012] In one or more alternative embodiments, the lens axis of the macro camera is perpendicular to the laser sheet light plane of the plurality of PIV lasers.

[0013] In one or more alternative embodiments, a filter is provided on the outer surface of the lens of the macro camera.

[0014] In one or more alternative embodiments, the collection and weighing system includes a measuring cup and a precision balance;

[0015] The outlet pipeline of the core holder is connected to the measuring cup;

[0016] The measuring cup can be placed horizontally on the precision balance.

[0017] In one or more optional embodiments, the reservoir development fracturing proppant flowback physical model further includes a first six-way valve and an inlet pressure gauge;

[0018] The first six-way valve is disposed between the intermediate container and the core holder;

[0019] The inlet pressure gauge is connected to the first six-way valve.

[0020] In one or more optional embodiments, the reservoir development fracturing proppant flowback physical model further includes a second six-way valve and an outlet pressure gauge;

[0021] The second six-way valve is located between the confining pressure pump and the core holder;

[0022] The outlet pressure gauge is connected to the second six-way valve.

[0023] Secondly, embodiments of the present invention provide a physical simulation method for proppant flowback in oil and gas reservoir development, applying the physical model for proppant flowback in oil and gas reservoir development described in the first aspect, including:

[0024] Based on the target formation fracturing parameters, simulated fracturing fractures are carved into the real core of the simulated rock sample along a preset path.

[0025] According to the preset sand concentration, a special proppant containing tracer powder is uniformly spread in the simulated hydraulic fracturing fractures of a real rock core.

[0026] The core is fixed in the core holder, and the confining pressure is applied to the preset confining pressure value and stabilized by the confining pressure pump. The two PIV laser emitters are turned on, and the initial particle image is obtained by taking a macro camera.

[0027] The specially formulated fracturing fluid containing fluorescent tracer particles is placed into the intermediate container;

[0028] Start the ISCO plunger dual pump and inject the special fracturing fluid into the core holder at a preset injection rate. After reaching the preset volume, turn off the ISCO plunger dual pump until the preset pump stop time is reached. During this process, take a set of particle images through the macro camera at preset time intervals.

[0029] Restart the ISCO plunger dual pump and inject the special fracturing fluid into the core holder at the preset backflow rate. When the flow rate at the outlet of the core holder is stable, take a set of particle images using the macro camera.

[0030] During the injection process, at preset time intervals, the outflowing solid-liquid mixture is collected once by a collection and weighing system, and a set of particle images are captured by the macro camera.

[0031] When the preset backflow amount or preset backflow time is reached, the ISCO plunger dual pump is turned off, the backflow ends, and the final particle image is obtained by the macro camera.

[0032] Based on all the particle images captured, the velocity flow field of the special fracturing fluid and the real-time motion trajectory and real-time velocity of the proppant particles at the preset flowback velocity are obtained.

[0033] Each collected solid-liquid mixture was subjected to precipitation, filtration, drying, and weighing to obtain the cumulative proppant sand mass at different backflow time points under the preset backflow rate, and a backflow time-cumulative sand mass curve was plotted.

[0034] Based on different preset flowback rates, the process of proppant flowback was simulated multiple times to obtain the velocity flow field of the special fracturing fluid, the real-time motion trajectory and real-time velocity of the proppant particles, and the flowback time-cumulative sand production mass curve under different flowback rates.

[0035] In one or more optional embodiments, the velocity flow field of the specially formulated fracturing fluid is obtained based on all captured particle images, including:

[0036] Each particle image is divided into multiple non-overlapping small windows;

[0037] Cross-correlation calculations are performed on corresponding windows of two adjacent particle images to find the location of the maximum correlation coefficient and determine the particle displacement.

[0038] The velocity vector for each window is calculated based on the corresponding particle displacement and time interval.

[0039] The velocity vectors of each window are combined to obtain the velocity flow field of the specially formulated fracturing fluid.

[0040] In one or more optional embodiments, based on all captured particle images, the real-time trajectory and real-time velocity of the proppant particles at the preset backflow velocity are obtained, including:

[0041] Based on all the particle images captured, proppant particles are identified and tracked, and their trajectories and corresponding velocities are recorded.

[0042] By correlating the motion trajectory and corresponding velocity of the proppant particles with the backflow time, the real-time motion trajectory and real-time velocity of the proppant particles at the preset backflow velocity are obtained.

[0043] In one or more optional embodiments, the special proppant is a particle made of a composite of ceramsite powder and tracer powder, and the tracer powder accounts for 5%-10%.

[0044] In one or more alternative embodiments, the specially formulated fracturing fluid is a mixture of fracturing fluid, breaker and micron-sized fluorescent tracer particles.

[0045] The beneficial effects of the above-mentioned technical solutions provided in the embodiments of the present invention include at least the following:

[0046] This invention provides a physical model for proppant flowback in oil and gas reservoir development. The fracturing physical simulation system can simulate the fracturing flowback process based on simulated rock samples. By setting a transparent simulated rock sample and installing a macro camera and PIV laser on the simulated rock sample, particle images in the real rock core can be obtained, thereby obtaining the migration trajectory and real-time velocity distribution of the proppant in the real rock core during the fracturing flowback process. The solid-liquid mixture discharged at different flowback times can be collected by a collection and weighing system. By setting different simulated flowback velocities, the relationship between the flowback velocity and the proppant migration and sand production can be obtained, which is beneficial for optimizing the fracturing fluid flowback velocity and guiding reservoir fracturing production.

[0047] Other features and advantages of the invention will be set forth in the description which follows, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention may be realized and obtained by means of the structures particularly pointed out in the written description and the accompanying drawings.

[0048] The technical solution of the present invention will be further described in detail below with reference to the accompanying drawings and embodiments. Attached Figure Description

[0049] The accompanying drawings are provided to further illustrate the invention and form part of the specification. They are used in conjunction with embodiments of the invention to explain the invention and do not constitute a limitation thereof. In the drawings:

[0050] Figure 1 This is a schematic diagram of the physical model for the flowback of proppant in oil and gas reservoir development provided in this embodiment of the invention;

[0051] Figure 2 This is a schematic flowchart of the physical simulation method for hydraulic proppant flowback in oil and gas reservoir development provided in this embodiment of the invention;

[0052] Figure 3 This is a schematic diagram of the calculation process for the velocity flow field of the specially designed fracturing fluid provided in an embodiment of the present invention;

[0053] Figure 4 This is a graph showing the cumulative proppant sand output mass changing with backflow time at different backflow rates, as provided in this embodiment of the invention.

[0054] Figure label:

[0055] 1. ISCO plunger double; 2. Intermediate container; 3. First six-way valve; 4. Inlet pressure gauge; 5. Confining pressure pump; 6. Second six-way valve; 7. Outlet pressure gauge; 8. Core holder; 9. Simulated rock sample; 91. Sapphire glass; 911. Mounting cavity; 92. Real core; 10. Simulated hydraulic fracturing fracture; 11. Special proppant; 12. Macro camera; 13. PIV laser; 14. Terminal equipment; 15. Measuring cup; 16. Precision balance. Detailed Implementation

[0056] Exemplary embodiments of the present disclosure will now be described in more detail with reference to the accompanying drawings. While exemplary embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure may be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art.

[0057] In the description of this invention, it should be noted that the terms "center," "upper," "lower," "left," "right," "vertical," "horizontal," "inner," "outer," "far," "near," "front," and "rear," etc., indicating the orientation or positional relationship, are based on the orientation or positional relationship shown in the accompanying drawings and are only for the convenience of describing this invention and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation, and therefore should not be construed as a limitation of this invention. Furthermore, the terms "first," "second," and "third" are used for descriptive purposes only and should not be construed as indicating or implying relative importance.

[0058] In the description of this invention, it should be noted that, unless otherwise explicitly specified and limited, the terms "installation," "connection," and "linking" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral connection; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium; and they can refer to the internal connection of two components. Those skilled in the art can understand the specific meaning of the above terms in this invention based on the specific circumstances.

[0059] The inventors discovered that existing fracturing fluid flowback simulation technologies still have certain limitations, such as:

[0060] The invention patent with application number CN201911333885.6 discloses a simulation experimental device, method and process for proppant injection into cracks. The simulation experiment can simulate the actual situation of proppant injection into cracks and evaluate the proppant injection capability in cracks.

[0061] The invention patent with application number CN 201610827564.1 discloses an experimental device and method for simulating proppant placement and fracturing fluid backflow, which can carry out simulation experiments of proppant placement and fracturing fluid backflow.

[0062] The invention patent with application number CN 201710594394.1 discloses an experimental device and method for simulating fracturing fluid flowback and controlling proppant backflow, which can simulate the process of formation gas loss and the process of fracturing fluid flowback and formation fluid loss to fractures.

[0063] All three patents have significant limitations: (i) existing devices struggle to capture the real-time migration trajectory and velocity distribution of proppant particles during the flowback process; and (ii) they lack the ability to dynamically characterize the proppant velocity field as it changes over flowback time, making it impossible to establish a quantitative correlation model between flowback velocity and the critical point of sand production. These technical deficiencies directly restrict the optimization decision-making for fracturing fluid flowback velocity, necessitating the development of high-precision simulation devices and methods capable of simultaneously analyzing the fluid-particle interaction mechanism.

[0064] Based on this, embodiments of the present invention provide a physical model and simulation method for the flowback of proppant in oil and gas reservoir development fracturing, which will be described in detail below through specific embodiments.

[0065] Example 1

[0066] This invention provides a physical model for the flowback of proppant in oil and gas reservoir development, referring to... Figure 1 As shown, it includes a fracturing physical simulation system, an imaging system, and a collection and weighing system;

[0067] The fracturing physical simulation system includes an ISCO plunger dual-1 pump, an intermediate container 2, a confining pressure pump 5, a core holder 8, and a simulated rock sample 9; the ISCO plunger dual-1 pump, the intermediate container 2, and the core holder 8 are connected in sequence; the confining pressure pump 5 is connected to the confining pressure chamber of the core holder 8; the core holder 8 is used to hold the simulated rock sample 9; the intermediate container 2 is used to hold fracturing fluid;

[0068] The imaging system includes a macro camera 12, multiple PIV lasers 13, and a terminal device 14; the terminal device 14 is signal-connected to the multiple PIV lasers 13 and the macro camera 12 respectively.

[0069] The simulated rock sample 9 is cylindrical and includes a sapphire glass 91 and a real rock core 92 bonded together at the top and bottom. Both the sapphire glass 91 and the real rock core 92 are semi-cylindrical.

[0070] The plurality of PIV lasers 13 and the macro camera 12 are respectively disposed inside the sapphire glass 91 and are located directly above the real rock core 92;

[0071] The plurality of PIV lasers 13 are evenly distributed on both sides of the macro camera 12;

[0072] The outlet pipeline of the core holder 8 is connected to the collection and weighing system.

[0073] In this embodiment of the invention, reference is made to Figure 1 As shown, the simulated rock sample 9 is assembled from a sapphire glass 91 and a real rock core 92. Lasers emitted by multiple PIV lasers 13 can penetrate the upper sapphire glass 91 and illuminate the surface of the real rock core 92. Combined with a macro camera 12, images of the rock core surface can be captured. By adding tracer powder to the proppant and fluorescent tracer particles to the fracturing fluid, particle images of proppant and fracturing fluid transport within the real rock core 92 can be captured using the combination of multiple PIV lasers 13 and the macro camera 12.

[0074] In this embodiment of the invention, the specific process of preparing the simulated rock sample 9 may include:

[0075] Select a cylindrical real rock core 92, cut it in half along the axial direction, and keep one half for later use;

[0076] Based on the shape of half of the real rock core 92 obtained by cutting, a semi-cylinder of the same shape was made using high-transmittance sapphire glass 91;

[0077] The semi-cylindrical sapphire glass 91 and half of the real rock core 92 are spliced ​​together to obtain a complete cylindrical simulated rock sample 9. Specifically, after the splicing surface is precision polished, the sapphire glass 91 and the real rock core 92 are bonded with high-temperature resistant epoxy resin adhesive, and silicone sealant is applied to the joint to prevent high pressure leakage and ensure a seamless transition at the interface between the sapphire glass 91 and the real rock core 92.

[0078] The simulated fracturing fracture 10 is sculpted by using a diamond micro-sculpting tool to carve the main fracture and secondary branch network along a preset path, based on the target formation fracturing fracture parameters, in order to simulate the fracturing fracture state.

[0079] In this embodiment of the invention, the proppant used during simulated fracturing flowback is a specially formulated proppant 11 containing tracer powder. The tracer powder can be titanium dioxide powder. For example, the specially formulated proppant 11 can be particles composed of titanium dioxide powder and ceramic powder, with titanium dioxide accounting for 5%-10% by mass.

[0080] In this embodiment of the invention, the fracturing fluid used to simulate fracturing flowback is a specially formulated fracturing fluid containing a breaker and micron-sized fluorescent tracer particles, to simulate the fracturing fluid with a certain viscosity after the formation is broken during fracturing operations. For example, the volume concentration of the fluorescent tracer particles in the specially formulated fracturing fluid can be 0.1%-0.5%. This range allows for clear particle images to be captured by the macro camera 12 and the PIV laser 13 without causing abnormal viscosity or particle aggregation due to excessively high concentrations.

[0081] In this embodiment of the invention, during the simulated fracturing and flowback process, the simulated rock sample 9 needs to be placed into the inner cavity of the core holder 8. At this time, the side wall of the simulated rock sample 9 is close to the inner cavity wall of the core holder 8. Therefore, it is necessary to leave mounting positions for multiple PIV lasers 13 and macro cameras 12 on the simulated rock sample 9. Optionally, a sealed mounting cavity 911 is hollowed out inside the sapphire glass 91, and the macro camera 12 and multiple PIV lasers 13 are all disposed in the mounting cavity 911.

[0082] In an optional embodiment, multiple PIV lasers 13 and a macro camera 12 can be fixed within the mounting cavity 911 by a rigid bracket, thereby ensuring installation stability and minimizing imaging instability caused by vibration. During installation, the multiple PIV lasers 13 are evenly distributed on both sides of the macro camera 12 to ensure that the surface of the real rock core 92 receives uniform light. The lens axis of the macro camera 12 is perpendicular to the laser sheet light plane of the multiple PIV lasers 13 to ensure the clarity of the particle image.

[0083] In one specific embodiment, there may be two PIV lasers 13, symmetrically arranged on both sides of the macro camera 12, to ensure that the surface of the real rock core 92 receives uniform light source and to ensure the clarity of the particle image.

[0084] In this embodiment of the invention, the outer surface of the lens of the macro camera 12 is provided with a filter (not shown in the figure) to filter the light reflected by the proppant particles and bubbles, eliminate interfering light sources, and ensure the accuracy of the simulation.

[0085] In this embodiment of the invention, the terminal device 14 can be a computer, mobile phone or other device with signal transmission, signal processing and display functions, and is wirelessly connected to the macro camera 12 and PIV laser 13 to control the operation of the macro camera 12 and PIV laser 13, as well as to receive and display images captured by the macro camera 12.

[0086] In this embodiment of the invention, reference is made to Figure 1 As shown, the collection and weighing system includes a measuring cup 15 and a precision balance 16. The outlet line of the core holder 8 is connected to the mouth of the measuring cup 15, allowing the solid-liquid mixture discharged from the outlet of the core holder 8 to flow into the measuring cup 15. The measuring cup 15 can be placed horizontally on the precision balance 16, which is used to weigh the solid-liquid mixture or the dried solid-liquid mixture.

[0087] In this embodiment of the invention, plugs are provided at both ends of the core holder 8. The plugs can seal the inner cavity of the core holder 8 and compress the simulated rock sample 9, thereby ensuring that the core remains stable during the experiment, preventing leakage of experimental fluid, and ensuring the accuracy of the experiment. In addition, both the inlet and outlet plugs are provided with pipeline interfaces for injecting or discharging fluid.

[0088] In this embodiment of the invention, reference is made to Figure 1 As shown, the physical model for proppant flowback in oil and gas reservoir development also includes a first six-way valve 3 and an inlet pressure gauge 4. The first six-way valve 3 is located between the intermediate container 2 and the core holder 8, and is used to control the opening and closing of the inlet pipeline of the core holder 8. The inlet pressure gauge 4 is connected to the first six-way valve 3 and is used to monitor the pressure at the inlet of the core holder 8 in real time.

[0089] In this embodiment of the invention, reference is made to Figure 1 As shown, the physical model for proppant flowback in oil and gas reservoir development also includes a second six-way valve 6 and an outlet pressure gauge 7. The second six-way valve 6 is located between the confining pressure pump 5 and the core holder 8, and is used to control the opening and closing of the outlet pipeline of the core holder 8. The outlet pressure gauge 7 is connected to the second six-way valve 6 and is used to monitor the pressure at the outlet of the core holder 8 in real time.

[0090] The oil and gas reservoir development fracturing proppant flowback physical model provided in this embodiment of the invention, the fracturing physical simulation system can simulate the fracturing flowback process based on simulated rock sample 9. By setting a transparent upper part of the simulated rock sample 9 and installing a macro camera 12 and a PIV laser 13 on the simulated rock sample 9, it is possible to acquire particle images in the real rock core 92, thereby obtaining the migration trajectory and real-time velocity distribution of proppant in the real rock core 92 during the fracturing flowback process. The solid-liquid mixture discharged at different flowback times can be collected by the collection and weighing system. By setting different simulated flowback velocities, the relationship between flowback velocity and proppant migration and sand production can be obtained, which is beneficial for optimizing the fracturing fluid flowback velocity and guiding reservoir fracturing production.

[0091] In this embodiment of the invention, the process of performing physical simulation of proppant flowback in oil and gas reservoir development using the physical model of proppant flowback in oil and gas reservoir development may specifically include:

[0092] According to the preset sand concentration, a special proppant 11 containing tracer powder was uniformly laid in the simulated hydraulic fracture 10 of the real core 92 to simulate the initial state of the proppant in the hydraulic fracture 10.

[0093] The core is fixed in the core holder 8, and the confining pressure is applied to the preset confining pressure value by the confining pressure pump 5 and stabilized to simulate the effective stress acting on the real core 92 and proppant. The two PIV laser emitters are turned on, and the initial particle image is obtained by taking pictures through the macro camera 12.

[0094] The special fracturing fluid containing fluorescent tracer particles is placed into intermediate container 2;

[0095] Start the ISCO plunger dual 1 pump and inject the special fracturing fluid into the core holder 8 at a preset injection rate. After reaching the preset volume, turn off the ISCO plunger dual 1 pump until the preset pump stop time is reached to simulate the situation of fracturing fluid and proppant in the formation after the pump is stopped during construction. During this process, a set of particle images is captured by macro camera 12 at preset time intervals.

[0096] Restart the ISCO plunger dual pump and inject the special fracturing fluid into the core holder 8 at the preset backflow rate. When the flow rate at the outlet of the core holder 8 is stable, take a set of particle images through the macro camera 12.

[0097] During the injection process, at preset time intervals, the outflowing solid-liquid mixture is collected once by the collection and weighing system, and a set of particle images are captured by the macro camera 12.

[0098] When the preset backflow amount or preset backflow time is reached, the ISCO plunger dual pump is turned off, the backflow ends, and the final particle image is obtained by the macro camera 12.

[0099] Based on all the particle images captured, the velocity flow field of the special fracturing fluid and the real-time motion trajectory and real-time velocity of the proppant particles at the preset flowback velocity are obtained.

[0100] Each collected solid-liquid mixture was subjected to precipitation, filtration, drying, and weighing to obtain the cumulative proppant sand mass at different backflow time points under the preset backflow rate, and a backflow time-cumulative sand mass curve was plotted.

[0101] Based on different preset flowback rates, the process of fracturing proppant flowback was simulated multiple times to obtain the flowback time-cumulative sand production quality curves under different flowback rates.

[0102] In this embodiment of the invention, the PIV laser 13 and the macro camera 12 are controlled to work synchronously by the terminal device 14. The particle images captured by the macro camera 12 can be transmitted to the terminal device 14 for display and related calculations.

[0103] Example 2

[0104] Based on the same inventive concept, embodiments of the present invention provide a physical simulation method for proppant flowback during oil and gas reservoir development, referring to... Figure 2 As shown, the physical model for proppant flowback in oil and gas reservoir development described in Example 1 includes:

[0105] S101: Referencing the target formation fracturing parameters, carve simulated fracturing fractures 10 in the real core 92 of simulated rock sample 9 along a preset path;

[0106] S102: According to the preset sand-laying concentration, a special proppant 11 containing tracer powder is uniformly laid in the simulated hydraulic fracture 10 of the real core 92;

[0107] S103: Fix the core in the core holder 8, apply confining pressure to the preset confining pressure value and stabilize it by the confining pressure pump 5, turn on the two PIV laser emitters, and take the initial particle image by the macro camera 12.

[0108] S104: Place the special fracturing fluid containing fluorescent tracer particles into intermediate container 2;

[0109] S105: Start the ISCO plunger dual pump and inject special fracturing fluid into the core holder 8 at a preset injection rate. After reaching the preset volume, turn off the ISCO plunger dual pump until the preset pump stop time is reached. During this process, take a set of particle images through the macro camera 12 at preset time intervals.

[0110] S106: Restart the ISCO plunger dual pump and inject special fracturing fluid into the core holder 8 according to the preset backflow rate. When the flow rate at the outlet of the core holder 8 is stable, take a set of particle images through the macro camera 12.

[0111] S107: During the injection process, at preset time intervals, the outflowing solid-liquid mixture is collected once by the collection and weighing system, and a set of particle images are captured by the macro camera 12.

[0112] S108: When the preset backflow amount or preset backflow time is reached, the ISCO plunger dual pump is turned off, the backflow ends, and the final particle image is obtained by taking a picture through the macro camera 12.

[0113] S109: Based on all the particle images captured, obtain the velocity flow field of the special fracturing fluid and the real-time motion trajectory and real-time velocity of the proppant particles at the preset flowback velocity;

[0114] S110: Each time the solid-liquid mixture is collected, it is subjected to precipitation, filtration, drying and weighing to obtain the cumulative proppant sand mass at different backflow time points under the preset backflow rate, and a backflow time-cumulative sand mass curve is plotted.

[0115] S111: Based on different preset flowback rates, the process of proppant flowback is simulated multiple times to obtain the velocity flow field of the special fracturing fluid, the real-time motion trajectory and real-time velocity of the proppant particles, and the flowback time-cumulative sand production mass curve under different flowback rates.

[0116] In this embodiment of the invention, the physical simulation method for proppant flowback in oil and gas reservoir development corresponds to the physical model for proppant flowback in oil and gas reservoir development described in Example 1. The specific implementation process can refer to the application process of the physical model for proppant flowback in oil and gas reservoir development described in Example 1. Where it is repeated, it will not be described again.

[0117] In this embodiment of the invention, based on all the captured particle images, the velocity flow field of the specially formulated fracturing fluid can be obtained using PIV technology, which may specifically include:

[0118] Each particle image is divided into multiple non-overlapping small windows;

[0119] Cross-correlation calculations are performed on corresponding windows of two adjacent particle images to find the location of the maximum correlation coefficient and determine the particle displacement.

[0120] The velocity vector for each window is calculated based on the corresponding particle displacement and time interval.

[0121] The velocity vectors of each window are combined to obtain the velocity flow field of the specially formulated fracturing fluid.

[0122] In one specific embodiment, reference is made to Figure 3 As shown, the calculation process for obtaining the velocity flow field of the specially formulated fracturing fluid using PIV technology, based on all captured particle images, can specifically include:

[0123] Dividing the interpretation window: First, each particle image is divided into multiple small windows, each containing a certain number of fluid particles, to achieve localized analysis. This allows the particle image in each small region to be processed individually, thereby extracting key information.

[0124] Particle Image Extraction: Extract the particle image within each window from the original particle image, labeled as f(m,n) and g(m,n), respectively. Here, f(m,n) and g(m,n) represent particle images in two consecutive time frames, respectively, for subsequent correlation analysis.

[0125] Perform FFT transformation: Perform Fast Fourier Transform (FFT) on the particle image within each window to transform the image from the spatiotemporal domain to the frequency domain, making it easier to process and analyze the correlation of the particle image in the frequency domain.

[0126] Calculate the cross-correlation function: In the frequency domain, calculate the complex conjugate product between the two particle images, i.e., F*(α, β)·G(α, β), to find the correlation between the two images and determine the particle displacement.

[0127] Perform IFFT transformation: Perform inverse fast Fourier transform (IFFT) on the frequency domain representation calculated in the previous step to convert the image from the frequency domain back to the spatiotemporal domain, thereby obtaining the spatiotemporal domain representation of the correlation function, so as to intuitively analyze the displacement of the particles.

[0128] Peak value identification and displacement calculation: The peak value is found within the relevant function; its location represents the particle's displacement. By calculating the peak value, the particle's displacements dx and dy in the x and y directions can be obtained. Finally, based on this displacement information, the fluid's velocity field can be calculated.

[0129] Optionally, PIV technology can be implemented based on PIV software (such as PIVlab).

[0130] In this embodiment of the invention, based on all captured particle images, the real-time trajectory and velocity of the proppant particles at a preset backflow velocity can be obtained using the PTV algorithm. Specifically, this may include:

[0131] Based on all the captured particle images, the PTV algorithm (such as OpenPTV) is used to identify and track proppant particles, and the motion trajectory and corresponding velocity of the proppant particles are recorded.

[0132] By correlating the motion trajectory and corresponding velocity of the proppant particles with the backflow time, the real-time motion trajectory and real-time velocity of the proppant particles at the preset backflow velocity are obtained.

[0133] In this embodiment of the invention, the solid-liquid mixture collected each time is subjected to precipitation, filtration, drying, and weighing processes to obtain the cumulative proppant sand output mass at different backflow time points under the preset backflow rate, and a backflow time-cumulative sand output mass curve is plotted. Specifically, this may include:

[0134] The solid-liquid mixture collected each time was subjected to precipitation, filtration, drying, and weighing to obtain the mass M of sand discharged each time. tf ;

[0135] Based on the sand output quality M collected each time tf The cumulative proppant output mass S at each return time point was calculated. tf And plot the return time-cumulative sand output quality curve.

[0136] In this embodiment of the invention, reference is made to Figure 4 As shown, based on different preset flowback rates, the process of fracturing proppant flowback is simulated multiple times to obtain flowback time-cumulative sand production curves under different flowback rates. By comparing the curves, the relationship between flowback rate and cumulative proppant return flow can be obtained, thereby optimizing the fracturing fluid flowback rate. Specifically, the flowback rate curve corresponding to the critical sand production point can be obtained by fitting experimental data, and a rate range slightly below the critical value can be selected to ensure flowback efficiency while avoiding sand production risk.

[0137] In an optional embodiment, the special support 11 is a particle made of ceramsite powder and tracer powder, and the proportion of the tracer powder is 5%-10%.

[0138] In an optional embodiment, the special fracturing fluid is a mixture of fracturing fluid, breaker and micron-sized fluorescent tracer particles.

[0139] The present invention provides a physical simulation method for proppant flowback in oil and gas reservoir development fracturing. Through the combination of sapphire glass 91, a PIV laser 13, and a macro camera 12, it enables the observation of the migration process of fracturing fluid and proppant in a real core 92. By carving simulated fracturing fractures 10 on a simulated rock sample 9 and laying specially formulated proppant 11 in the simulated fractures 10, the initial state of the proppant in the simulated fractures 10 is simulated. That is, this method starts the simulation from the state after fracturing and before flowback, rather than from the fracturing process itself, thus eliminating influencing factors during fracturing and improving the accuracy of the simulation results. By taking particle images at intervals, a continuous migration and change process is obtained. Combining all particle images, the velocity flow field of the specially formulated fracturing fluid and the real-time trajectory and velocity of the proppant particles at a preset flowback rate can be analyzed. Furthermore, different flowback rates can be obtained. The flowback time-cumulative sand production curve under different flowback rates helps guide fracturing production in oil and gas reservoirs. Specifically, it is reflected in the following aspects: (1) Quantifying the flow velocity distribution of fracturing fluid during the flowback process using PIV technology reveals the dynamic characteristics of fluid in fractures, which can help identify the risk of proppant scouring in high-velocity areas and verify the matching between flowback rate and fluid sand-carrying capacity; (2) Using PTV technology to track the migration path and instantaneous velocity of individual proppant particles, analyzing the initiation, settling and aggregation behavior of particles, and revealing the transport law of proppant in fractures; (3) Quantifying the cumulative loss of proppant under different flowback rates, establishing a quantitative relationship between flowback rate and sand production, determining the critical flowback rate threshold, and guiding the optimization of flowback strategies: when the flowback rate is below the critical value, the sand production is controllable, but the flowback efficiency is low; when the flowback rate exceeds the critical value, the sand production surges, leading to a decrease in fracture conductivity.

[0140] In this embodiment of the invention, by simulating the velocity field of the specially formulated fracturing fluid, the real-time motion trajectory and velocity of proppant particles at a preset flowback rate, and the flowback time-cumulative sand production mass curve at different flowback rates, the combination of the velocity field and particle trajectory can identify the fluid sand-carrying mechanism, while the flowback time-cumulative sand production mass curve quantifies the economic risk at different flow rates. Therefore, by simulating multiple flowback rates and plotting the flowback time-cumulative sand production mass curve at different flowback rates, the critical point of sudden sand production increase can be identified. Combining the velocity field and particle trajectory, the fluid dynamics conditions corresponding to the critical point can be analyzed. During on-site production, the critical flowback rate is used as the upper limit for on-site construction and dynamically adjusted according to parameters such as formation closure stress and fracture width, achieving a balance between flowback efficiency and fracture stability.

[0141] Obviously, those skilled in the art can make various modifications and variations to this invention without departing from its spirit and scope. This disclosure is not limited to the precise structures described above and shown in the accompanying drawings, and various modifications and changes can be made without departing from its scope. The scope of this disclosure is limited only by the appended claims. Thus, if these modifications and variations of the invention fall within the scope of the claims of the invention and their equivalents, the invention is also intended to include these modifications and variations.

Claims

1. A physical model for proppant flowback during fracturing in oil and gas reservoir development, characterized in that, Includes fracturing physical simulation system, imaging system and collection and weighing system; The fracturing physical simulation system includes an ISCO plunger dual pump, an intermediate container, a confining pressure pump, a core holder, and a simulated rock sample; the ISCO plunger dual pump, the intermediate container, and the core holder are connected in sequence; the confining pressure pump is connected to the confining pressure chamber of the core holder; the core holder is used to hold the simulated rock sample; and the intermediate container is used to hold fracturing fluid. The imaging system includes a macro camera, multiple PIV lasers, and a terminal device; the terminal device is signal-connected to the multiple PIV lasers and the macro camera respectively. The simulated rock sample is cylindrical and consists of a sapphire glass and a real rock core bonded together at the top and bottom. Both the sapphire glass and the real rock core are semi-cylindrical. The plurality of PIV lasers and the macro camera are respectively disposed inside the sapphire glass and located directly above the real rock core; The multiple PIV lasers are evenly distributed on both sides of the macro camera; The outlet pipeline of the core holder is connected to the collection and weighing system.

2. The physical model for proppant flowback in oil and gas reservoir development according to claim 1, characterized in that, The sapphire glass has a sealed mounting cavity, and the macro camera and the multiple PIV lasers are all housed within the mounting cavity.

3. The physical model for proppant flowback in oil and gas reservoir development according to claim 2, characterized in that, The lens axis of the macro camera is perpendicular to the laser sheet plane of the plurality of PIV lasers.

4. The physical model for proppant flowback in oil and gas reservoir development according to claim 1, characterized in that, The macro camera has a filter on the outer surface of its lens.

5. The physical model for proppant flowback in oil and gas reservoir development according to claim 1, characterized in that, The collection and weighing system includes a measuring cup and a precision balance; The outlet pipeline of the core holder is connected to the measuring cup; The measuring cup can be placed horizontally on the precision balance.

6. The physical model for proppant flowback in oil and gas reservoir development according to claim 1, characterized in that, It also includes a first six-way valve and an inlet pressure gauge; The first six-way valve is disposed between the intermediate container and the core holder; The inlet pressure gauge is connected to the first six-way valve.

7. The physical model for proppant flowback in oil and gas reservoir development according to claim 1, characterized in that, It also includes a second six-way valve and an outlet pressure gauge; The second six-way valve is located between the confining pressure pump and the core holder; The outlet pressure gauge is connected to the second six-way valve.

8. A physical simulation method for proppant flowback in oil and gas reservoir development, using the physical model for proppant flowback in oil and gas reservoir development as described in any one of claims 1-7, characterized in that, include: Based on the target formation fracturing parameters, simulated fracturing fractures are carved into the real core of the simulated rock sample along a preset path. According to the preset sand concentration, a special proppant containing tracer powder is uniformly spread in the simulated hydraulic fracturing fractures of a real rock core. The core is fixed in the core holder, and the confining pressure is applied to the preset confining pressure value and stabilized by the confining pressure pump. The two PIV laser emitters are turned on, and the initial particle image is obtained by taking a macro camera. The specially formulated fracturing fluid containing fluorescent tracer particles is placed into the intermediate container; Start the ISCO plunger dual pump and inject the special fracturing fluid into the core holder at a preset injection rate. After reaching the preset volume, turn off the ISCO plunger dual pump until the preset pump stop time is reached. During this process, take a set of particle images through the macro camera at preset time intervals. Restart the ISCO plunger dual pump and inject the special fracturing fluid into the core holder at the preset backflow rate. When the flow rate at the outlet of the core holder is stable, take a set of particle images using the macro camera. During the injection process, at preset time intervals, the outflowing solid-liquid mixture is collected once by a collection and weighing system, and a set of particle images are captured by the macro camera. When the preset backflow amount or preset backflow time is reached, the ISCO plunger dual pump is turned off, the backflow ends, and the final particle image is obtained by the macro camera. Based on all the particle images captured, the velocity flow field of the special fracturing fluid and the real-time motion trajectory and real-time velocity of the proppant particles at the preset flowback velocity are obtained. Each collected solid-liquid mixture was subjected to precipitation, filtration, drying, and weighing to obtain the cumulative proppant sand mass at different backflow time points under the preset backflow rate, and a backflow time-cumulative sand mass curve was plotted. Based on different preset flowback rates, the process of proppant flowback was simulated multiple times to obtain the velocity flow field of the special fracturing fluid, the real-time motion trajectory and real-time velocity of the proppant particles, and the flowback time-cumulative sand production mass curve under different flowback rates.

9. The physical simulation method for proppant flowback in oil and gas reservoir development according to claim 8, characterized in that, Based on all the particle images captured, the velocity flow field of the specially formulated fracturing fluid is obtained, including: Each particle image is divided into multiple non-overlapping small windows; Cross-correlation calculations are performed on corresponding windows of two adjacent particle images to find the location of the maximum correlation coefficient and determine the particle displacement. The velocity vector for each window is calculated based on the corresponding particle displacement and time interval. The velocity vectors of each window are combined to obtain the velocity flow field of the specially formulated fracturing fluid.

10. The physical simulation method for proppant flowback in oil and gas reservoir development according to claim 8, characterized in that, Based on all the captured particle images, the real-time trajectory and velocity of the proppant particles at the preset backflow velocity are obtained, including: Based on all the particle images captured, proppant particles are identified and tracked, and their trajectories and corresponding velocities are recorded. By correlating the motion trajectory and corresponding velocity of the proppant particles with the backflow time, the real-time motion trajectory and real-time velocity of the proppant particles at the preset backflow velocity are obtained.

11. The physical simulation method for proppant flowback in oil and gas reservoir development according to claim 8, characterized in that, The special proppant is a particle made of ceramsite powder and tracer powder, and the tracer powder accounts for 5%-10%.

12. The physical simulation method for proppant flowback in oil and gas reservoir development according to claim 8, characterized in that, The specially formulated fracturing fluid is a mixture of fracturing fluid, breaker, and micron-sized fluorescent tracer particles.

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