Method and device for optimizing oil and gas well flowback after fracturing and storage medium

Abstract

The invention discloses a method for optimizing flowback of an oil and gas well after fracturing. The method comprises the following steps: determining initial flowing bottomhole pressure when a target well is opened; determining the sedimentation critical flow of a wellbore proppant of the target well and the critical reflux flow of a crack proppant of the target crack in the flowback process; determining the first minimum flowing bottomhole pressure of the single-phase liquid in the flowback process and the second minimum flowing bottomhole pressure of the gas-liquid two-phase fluid in the flowback process; acquiring a first real-time flow-back flow rate and a first real-time flowing bottomhole pressure in a pure liquid discharge stage and a second real-time flow-back flow rate and a second real-time flowing bottomhole pressure in a gas-liquid two-phase flow stage in real time; in the pure liquid drainage stage, the first real-time bottom hole flowing pressure and the first real-time flow-back flow are adjusted; and in the gas-liquid two-phase flow stage, the second real-time bottom hole flow pressure and the first real-time flow-back flow are adjusted. Quantitative flow-back can be achieved, so that the flow-back system of the fractured oil and gas well is optimized, and technical guidance is provided for flow-back operation.

Description

Technical Field

[0001] The present application relates to the field of petroleum engineering technology, and in particular to a method, a device and a storage medium for optimizing the flowback of oil and gas wells after fracturing. Background Art

[0002] In the petroleum engineering industry, the transition from traditional conventional oil and gas development to unconventional oil and gas development is being realized. Unconventional oil and gas often do not have industrial production capacity. Generally, a large amount of fracturing fluid, proppant and chemical additives need to be pumped into the formation through multi-stage fracturing of horizontal wells to transform the reservoir, form a complex fracture network and improve permeability. After the fracturing is completed and the well is opened, the flowback process will begin. During the flowback process, the coupling mechanism of gas reservoir-fracture-wellbore is complex. An unreasonable flowback system will weaken the transformation effect of the reservoir, reduce the oil and gas seepage area, and reduce the flow efficiency of oil and gas seepage in the formation. Summary of the invention

[0003] The purpose of the embodiments of the present application is to provide a method, device and storage medium for optimizing the flowback of oil and gas wells after fracturing, so as to solve the problem in the prior art that there is no reasonable flowback system, thereby affecting the fracturing effect and reducing production capacity.

[0004] In order to achieve the above objectives, the first aspect of the present application provides a method for optimizing the flowback of oil and gas wells after fracturing, the method comprising:

[0005] Determine the initial bottom hole flowing pressure when the target well is opened;

[0006] Determine the critical flow rate of the wellbore proppant of the target well and the critical flow rate of the fracture proppant of the target fracture during the flowback process;

[0007] Determine a first minimum bottom hole flow pressure of a single-phase liquid during a flowback process and a second minimum bottom hole flow pressure of a gas-liquid two-phase fluid during a flowback process;

[0008] Acquire the real-time flowback flow rate and real-time bottom hole flow pressure at different flowback stages during the flowback process, wherein the real-time flowback flow rate includes a first real-time flowback flow rate at a pure liquid discharge stage and a second real-time flowback flow rate at a gas-liquid two-phase flow stage, and the real-time bottom hole flow pressure includes a first real-time bottom hole flow pressure at a pure liquid discharge stage and a second real-time bottom hole flow pressure at a gas-liquid two-phase flow stage;

[0009] In the pure drainage stage, adjusting the first real-time bottom hole flow pressure and the first real-time flowback flow rate so that the first real-time bottom hole flow pressure is greater than the initial bottom hole flow pressure and less than the first minimum bottom hole flow pressure, and the first real-time flowback flow rate is greater than the critical flow rate of sedimentation and less than the critical return flow rate;

[0010] In the gas-liquid two-phase flow stage, the second real-time bottom hole flow pressure and the first real-time backflow flow rate are adjusted so that the second real-time bottom hole flow pressure is greater than the initial bottom hole flow pressure and less than the second minimum bottom hole flow pressure, and the second real-time backflow flow rate is greater than the sedimentation critical flow rate and less than the critical reflux flow rate.

[0011] In the embodiment of the present application, determining the critical reflux flow rate of the fracture proppant of the target fracture during the flowback process includes determining the critical reflux flow rate according to formula (1):

[0012] q=anvhw f (1)

[0013] Where a is the ratio of the number of effectively opened cracks to the total number of clusters, n is the total number of clusters undergoing fracturing, h is the height of the target crack, and w is the height of the target crack. f is the width of the target fracture, v is the reflux velocity of the fracture proppant, and q is the critical reflux flow rate.

[0014] In the embodiment of the present application, determining the critical reflux flow rate of the fracture proppant of the target fracture during the flowback process further includes determining the reflux flow rate of the fracture proppant according to formula (2):

[0015]

[0016] Where γ is the surface tension of the flowback fluid during the flowback process, μ is the fluid viscosity of the flowback fluid during the flowback process, ΔP is the net pressure acting on the fracture proppant, and d s is the particle diameter of the wellbore proppant, ρ s is the density of the wellbore proppant, v is the return flow rate, and g is the gravitational acceleration.

[0017] In the embodiment of the present application, determining the critical settling flow rate of the wellbore proppant of the target well in the flowback process includes determining the critical settling flow rate according to formula (3):

[0018]

[0019] Among them, d s is the particle diameter of the wellbore proppant, ρ is the fluid density of the wellbore fluid, d W is the diameter of the wellbore, ρ s is the density of the wellbore proppant, q cr is the sedimentation boundary flow rate, g is the acceleration of gravity, and π is the circumference of a circle.

[0020] In the embodiment of the present application, determining the first minimum bottom hole flow pressure of the single-phase liquid during the flowback process includes determining the first minimum bottom hole flow pressure according to formula (4):

[0021]

[0022] Where MD is the vertical depth of the target well, p Hmin is the minimum wellhead pressure of the target well, h w is the friction head loss of single-phase liquid along the way, p wmin is the first minimum bottom hole flowing pressure, and g is the gravitational acceleration.

[0023] In an embodiment of the present application, determining the second minimum bottom hole flow pressure of the gas-liquid two-phase fluid during the backflow process includes: obtaining the wellhead pressure of the target well measured by the wellhead pressure gauge; based on the Berggs-Brill method, converting the wellhead pressure to obtain the second minimum bottom hole flow pressure.

[0024] In an embodiment of the present application, determining the initial bottom hole flow pressure when the target well is opened includes: obtaining the initial wellhead pressure when the target well is opened measured by a wellhead pressure gauge; based on the Berggs-Brill method, converting the initial wellhead pressure to obtain the initial bottom hole flow pressure.

[0025] The second aspect of the present application provides a device for optimizing the flowback of an oil and gas well after fracturing, the device comprising:

[0026] A data acquisition module, used to acquire the real-time backflow flow rate and the real-time bottom hole flow pressure at different backflow stages during the backflow process, wherein the real-time backflow flow rate includes a first real-time backflow flow rate at a pure liquid discharge stage and a second real-time backflow flow rate at a gas-liquid two-phase flow stage, and the real-time bottom hole flow pressure includes a first real-time bottom hole flow pressure at a pure liquid discharge stage and a second real-time bottom hole flow pressure at a gas-liquid two-phase flow stage;

[0027] A data processing module is used to determine the initial bottom hole flow pressure when the target well is opened, the critical flow rate of the wellbore proppant of the target well and the critical return flow rate of the fracture proppant of the target fracture during the flowback process, as well as the first minimum bottom hole flow pressure of the single-phase liquid during the flowback process and the second minimum bottom hole flow pressure of the gas-liquid two-phase fluid during the flowback process;

[0028] The data adjustment module is used to adjust the first real-time bottom hole flow pressure and the first real-time backflow flow rate in the pure drainage stage, so that the first real-time bottom hole flow pressure is greater than the initial bottom hole flow pressure and less than the first minimum bottom hole flow pressure, and the first real-time backflow flow rate is greater than the sedimentation critical flow rate and less than the critical backflow flow rate; in the gas-liquid two-phase flow stage, adjust the second real-time bottom hole flow pressure and the first real-time backflow flow rate, so that the second real-time bottom hole flow pressure is greater than the initial bottom hole flow pressure and less than the second minimum bottom hole flow pressure, and the second real-time backflow flow rate is greater than the sedimentation critical flow rate and less than the critical backflow flow rate.

[0029] A third aspect of the present application provides an electronic device, the electronic device comprising:

[0030] a memory configured to store instructions; and

[0031] The processor is configured to call instructions from the memory and implement a method for optimizing flowback of an oil and gas well after fracturing when executing the instructions.

[0032] A fourth aspect of the present application provides a machine-readable storage medium having instructions stored thereon, the instructions being used to enable a machine to execute a method for optimizing flowback of an oil and gas well after fracturing.

[0033] Through the above technical scheme, firstly, the initial bottom hole flow pressure when the target well is opened is determined, the critical flow rate of the wellbore proppant of the target well and the critical return flow rate of the fracture proppant of the target fracture during the backflow process are determined, and the first minimum bottom hole flow pressure of the single-phase liquid during the backflow process and the second minimum bottom hole flow pressure of the gas-liquid two-phase fluid during the backflow process are determined; then, the real-time backflow flow rate and the real-time bottom hole flow pressure in different backflow stages during the backflow process are obtained, the real-time backflow flow rate includes the first real-time backflow flow rate in the pure liquid discharge stage and the second real-time backflow flow rate in the gas-liquid two-phase flow stage, and the real-time bottom hole flow pressure includes the first real-time backflow flow rate in the pure discharge stage and the second real-time backflow flow rate in the gas-liquid two-phase flow stage. The first real-time bottom hole flow pressure in the liquid stage and the second real-time bottom hole flow pressure in the gas-liquid two-phase flow stage; in the pure liquid discharge stage, the first real-time bottom hole flow pressure and the first real-time flowback flow rate are adjusted so that the first real-time bottom hole flow pressure is greater than the initial bottom hole flow pressure and less than the first minimum bottom hole flow pressure, and the first real-time flowback flow rate is greater than the sedimentation critical flow rate and less than the critical flowback flow rate; in the gas-liquid two-phase flow stage, the second real-time bottom hole flow pressure and the first real-time flowback flow rate are adjusted so that the second real-time bottom hole flow pressure is greater than the initial bottom hole flow pressure and less than the second minimum bottom hole flow pressure, and the second real-time flowback flow rate is greater than the sedimentation critical flow rate and less than the critical flowback flow rate. The present application proposes a method for optimizing the flowback system, which can realize quantitative flowback, thereby effectively improving oil production capacity.

[0034] Other features and advantages of the embodiments of the present application will be described in detail in the subsequent specific implementation section. BRIEF DESCRIPTION OF THE DRAWINGS

[0035] The accompanying drawings are used to provide a further understanding of the embodiments of the present application and constitute a part of the specification. Together with the following specific implementations, they are used to explain the embodiments of the present application, but do not constitute a limitation on the embodiments of the present application. In the accompanying drawings:

[0036] Figure 1 A flow chart of a method for optimizing flowback of an oil and gas well after fracturing according to an embodiment of the present application is schematically shown;

[0037] Figure 2 A schematic diagram of a safe flowback area according to an embodiment of the present application is schematically shown;

[0038] Figure 3 A schematic diagram of a safe flowback area of ​​an example well according to an embodiment of the present application is schematically shown;

[0039] Figure 4 A diagram schematically shows a comparison between actual flowback data and a safety zone in a pure liquid discharge stage according to an embodiment of the present application;

[0040] Figure 5 A diagram schematically shows a comparison between actual flowback data and a safety zone in a gas-liquid two-phase flow stage according to an embodiment of the present application;

[0041] Figure 6 A comparison diagram of effectiveness according to an embodiment of the present application is schematically shown;

[0042] Figure 7 A structural block diagram of a device for optimizing flowback of oil and gas wells after fracturing according to an embodiment of the present application is schematically shown;

[0043] Figure 8 The structure of an electronic device according to an embodiment of the present application is schematically shown.

[0044] Description of Reference Numerals

[0045] 810 memory 820 processor DETAILED DESCRIPTION

[0046] In order to make the purpose, technical scheme and advantages of the embodiments of the present application clearer, the technical scheme in the embodiments of the present application will be clearly and completely described below in conjunction with the drawings in the embodiments of the present application. It should be understood that the specific implementation methods described herein are only used to illustrate and explain the embodiments of the present application, and are not used to limit the embodiments of the present application. Based on the embodiments in the present application, all other embodiments obtained by ordinary technicians in this field without making creative work are within the scope of protection of this application.

[0047] It should be noted that if the embodiments of the present application involve directional indications (such as up, down, left, right, front, back...), the directional indications are only used to explain the relative position relationship, movement status, etc. between the components under a certain specific posture (as shown in the accompanying drawings). If the specific posture changes, the directional indication will also change accordingly.

[0048] In addition, if there are descriptions involving "first", "second", etc. in the embodiments of the present application, the descriptions of "first", "second", etc. are only used for descriptive purposes and cannot be understood as indicating or suggesting their relative importance or implicitly indicating the number of technical features indicated. Therefore, the features defined as "first" and "second" may explicitly or implicitly include at least one of the features. In addition, the technical solutions between the various embodiments can be combined with each other, but they must be based on the ability of ordinary technicians in the field to implement them. When the combination of technical solutions is contradictory or cannot be implemented, it should be deemed that such combination of technical solutions does not exist and is not within the scope of protection required by this application.

[0049] Figure 1 A flow chart of a method for optimizing flowback of oil and gas wells after fracturing according to an embodiment of the present application is schematically shown. Figure 1 As shown, an embodiment of the present application provides a method for optimizing flowback of an oil and gas well after fracturing, and the method may include the following steps.

[0050] Step 101, determining the initial bottom hole flowing pressure of the target well when it is opened;

[0051] In one embodiment, the initial bottom hole flow pressure of the target well is controlled when the well is opened to ensure the stability of the proppant in the fracture when the well is opened.

[0052] Step 102, determining the critical settling flow rate of the wellbore proppant of the target well and the critical reflux flow rate of the fracture proppant of the target fracture during the flowback process;

[0053] In one embodiment, determining the critical settling flow rate of the wellbore proppant of the target well during the backflow process is to determine the minimum flow rate allowed during the backflow process of the oil and gas well after fracturing, that is, the critical settling flow rate of the wellbore proppant is the minimum flow rate allowed during the backflow process, and determining the critical reflux flow rate of the fracture proppant of the target fracture is to determine the maximum flow rate allowed during the backflow process of the oil and gas well after fracturing. The flow rate during the backflow process is greater than the critical settling flow rate and less than the critical reflux flow rate, which can improve the backflow efficiency of the target well, thereby achieving the effect of optimizing the backflow process.

[0054] Step 103, determining a first minimum bottom hole flow pressure of the single-phase liquid during the flowback process and a second minimum bottom hole flow pressure of the gas-liquid two-phase fluid during the flowback process;

[0055] In one embodiment, the minimum bottom hole flow pressures of the single-phase liquid and the gas-liquid two-phase fluid during the flowback process are determined respectively to pave the way for better optimization of the flowback process of the oil and gas well after fracturing.

[0056] Step 104, obtaining the real-time flowback flow rate and the real-time bottom hole flow pressure at different flowback stages during the flowback process, wherein the real-time flowback flow rate includes a first real-time flowback flow rate at a pure liquid discharge stage and a second real-time flowback flow rate at a gas-liquid two-phase flow stage, and the real-time bottom hole flow pressure includes a first real-time bottom hole flow pressure at a pure liquid discharge stage and a second real-time bottom hole flow pressure at a gas-liquid two-phase flow stage;

[0057] In one embodiment, the real-time flowback flow rate and the real-time bottom hole flow pressure at different flowback stages are obtained during the flowback process. The real-time flowback flow rate includes a first real-time flowback flow rate at the pure liquid discharge stage and a second real-time flowback flow rate at the gas-liquid two-phase flow stage. The real-time bottom hole flow pressure includes a first real-time bottom hole flow pressure at the pure liquid discharge stage and a second real-time bottom hole flow pressure at the gas-liquid two-phase flow stage. The pure liquid discharge stage is a single-phase liquid, and the gas-liquid two-phase flow stage is a gas-liquid two-phase fluid. Acquiring the real-time flowback flow rate and the bottom hole flow pressure at the pure liquid discharge stage and the gas-liquid two-phase flow stage respectively can make the obtained flowback data more accurate, thereby better optimizing the flowback of oil and gas wells after fracturing.

[0058] Step 105, in the pure drainage stage, adjusting the first real-time bottom hole flow pressure and the first real-time flowback flow rate, so that the first real-time bottom hole flow pressure is greater than the initial bottom hole flow pressure and less than the first minimum bottom hole flow pressure, and the first real-time flowback flow rate is greater than the sedimentation critical flow rate and less than the critical reflux flow rate;

[0059] In one embodiment, during the pure drainage stage, the target well flowback efficiency can be safely improved by adjusting the first real-time bottomhole flow pressure and the first real-time flowback flow rate so that the first real-time bottomhole flow pressure is greater than the initial bottomhole flow pressure and less than the first minimum bottomhole flow pressure, and the first real-time flowback flow rate is greater than the sedimentation critical flow rate and less than the critical return flow rate.

[0060] Step 106, in the gas-liquid two-phase flow stage, adjust the second real-time bottom hole flow pressure and the first real-time backflow flow rate, so that the second real-time bottom hole flow pressure is greater than the initial bottom hole flow pressure and less than the second minimum bottom hole flow pressure, and the second real-time backflow flow rate is greater than the sedimentation critical flow rate and less than the critical reflux flow rate.

[0061] In one embodiment, during the gas-liquid two-phase flow stage, the second real-time bottom hole flow pressure and the first real-time flowback flow rate are adjusted so that the second real-time bottom hole flow pressure is greater than the initial bottom hole flow pressure and less than the second minimum bottom hole flow pressure, and the second real-time flowback flow rate is greater than the sedimentation critical flow rate and less than the critical return flow rate, thereby safely improving the flowback efficiency of the target well.

[0062] Through the above technical solution, the present application proposes a method for optimizing the flowback system, which can effectively improve the flowback efficiency of the target well, thereby increasing oil production capacity.

[0063] In one embodiment, determining the critical return flow rate of the fracture proppant of the target fracture during the flowback process may include determining the critical return flow rate according to formula (1):

[0064] q=anvhw f (1)

[0065] Where a is the ratio of the number of effectively opened cracks to the total number of clusters, n is the total number of clusters undergoing fracturing, h is the height of the target crack, and w is the height of the target crack. f is the width of the target fracture, v is the reflux velocity of the fracture proppant, and q is the critical reflux flow rate.

[0066] In one embodiment, the effectively opened fractures refer to the number of fractures that are successfully opened or formed in the target group of fractures. During the flowback process, when the liquid flowback flow rate is too high, the proppant in the fracture will be brought out of the fracture, which will harm the gas reservoir and the fracture, damage the gas reservoir transformation effect, and cause fracture loss. The proppant flowing back out of the fracture creates the necessary conditions for the above-mentioned wellbore proppant sedimentation. In order to avoid the backflow of fracture proppant during the flowback process, it is necessary to calculate the critical backflow flow rate of fracture proppant.

[0067] In one embodiment, determining the critical backflow flow rate of the fracture proppant of the target fracture during the flowback process may also include determining the backflow flow rate of the fracture proppant according to formula (2):

[0068]

[0069] Where γ is the surface tension of the flowback fluid during the flowback process, μ is the fluid viscosity of the flowback fluid during the flowback process, ΔP is the net pressure acting on the fracture proppant, and d s is the particle diameter of the wellbore proppant, ρ s is the density of the wellbore proppant, v is the return flow rate, and g is the gravitational acceleration.

[0070] In one embodiment, the net pressure acting on the fracture proppant refers to the net pressure acting on the fracture proppant. In order to avoid the backflow of the fracture proppant during the backflow process, it is necessary to calculate and determine the backflow rate of the fracture proppant. Only after the backflow rate is determined can the critical backflow flow rate mentioned above be determined.

[0071] In one embodiment, determining the critical settling rate of the wellbore proppant of the target well in the flowback process may include determining the critical settling rate according to formula (3):

[0072]

[0073] Among them, d s is the particle diameter of the wellbore proppant, ρ is the fluid density of the wellbore fluid, d Wis the diameter of the wellbore, ρ s is the density of the wellbore proppant, q cr is the sedimentation boundary flow rate, g is the acceleration of gravity, and π is the circumference of a circle.

[0074] In one embodiment, the critical return flow rate of the fracture proppant is the maximum flow rate allowed for optimizing the backflow. The critical settling flow rate refers to the flow rate used to determine at what flow rate the sand or proppant in the wellbore will begin to settle. During the backflow process, when the liquid backflow flow rate is too low, the proppant or formation sand returned from the fracture cannot be carried out of the wellhead, which will cause the proppant in the wellbore to settle. The settled proppant will block the wellbore and reduce the backflow efficiency. In addition, the moving proppant will impact the wellbore and downhole equipment, shortening their service life. In order to avoid the sedimentation of the wellbore proppant during the backflow process, it is necessary to calculate the critical settling flow rate of the wellbore proppant.

[0075] In one embodiment, determining the first minimum bottom hole flow pressure of the single-phase liquid during the flowback process may include determining the first minimum bottom hole flow pressure according to formula (4):

[0076]

[0077] Where MD is the vertical depth of the target well, p Hmin is the minimum wellhead pressure of the target well, h w is the friction head loss of single-phase liquid along the way, p wmin is the first minimum bottom hole flowing pressure, and g is the gravitational acceleration.

[0078] In one embodiment, the vertical depth of the target well refers to the vertical depth of the wellbore placed in the target well. The minimum external wellhead pressure of the target well refers to the minimum external wellhead pressure required for the target well to perform a flowback operation. The friction head loss along the flow represents the head loss caused by friction during the flow of a single-phase liquid. In order to ensure that the single-phase liquid can be discharged from the wellhead when the target well performs a flowback operation, it is necessary to calculate the minimum bottom hole flow pressure required for the single-phase liquid to be discharged from the wellhead, that is, the first minimum bottom hole flow pressure.

[0079] In one embodiment, determining the second minimum bottom hole flow pressure of the gas-liquid two-phase fluid during the flowback process may include:

[0080] Obtaining the wellhead pressure of the target well measured by the wellhead pressure gauge;

[0081] Based on the Bergs-Brill method, the wellhead pressure is converted to obtain the second minimum bottom hole flowing pressure.

[0082] In one embodiment, the acquired wellhead pressure is converted by the Bergs-Brill method to obtain the minimum bottom hole flow pressure required for the gas-liquid two-phase fluid to be discharged from the wellhead, that is, the second minimum bottom hole flow pressure.

[0083] In one embodiment, determining the initial bottom hole flowing pressure of the target well when it is opened includes:

[0084] Obtaining the initial wellhead pressure of the target well when it is opened, measured by the wellhead pressure gauge;

[0085] Based on the Berggs-Brill method, the initial wellhead pressure is converted to obtain the initial bottom hole flowing pressure.

[0086] In one embodiment, the acquired initial wellhead pressure is converted by the Bergs-Brill method to obtain the initial bottom hole flowing pressure.

[0087] The technical solution of this application is described below with a specific embodiment:

[0088] 1. Determine the timing of well opening:

[0089] The initial bottom hole pressure during well opening is controlled to be less than 5-7 MPa of the fracture closure pressure to ensure that the minimum closure stress acting on the proppant is between 5 and 7 MPa, and to ensure the stability of the proppant in the fracture during well opening. Since the fracture closure pressure cannot be directly obtained and is generally equal to the minimum horizontal principal stress value, the fracture closure pressure is replaced by the minimum horizontal principal stress, which can be interpreted by the logging results. For the initial bottom hole pressure, the initial wellhead pressure measured by the wellhead pressure gauge can be converted into the initial bottom hole pressure by the Beggs & Brill method, as shown in formula (5):

[0090]

[0091] Where p is the absolute average pressure in the pipeline, z is the distance of axial flow, and ρ l is the density of the liquid phase, ρ g is the density of the gas phase, H l is the liquid holdup, g is the gravitational acceleration, θ is the angle between the pipe and the horizontal, λ is the resistance coefficient along the two-phase flow, G is the mass flow rate of the mixture, v is the average flow velocity of the mixture, and v sg is the converted velocity of the gas phase, D is the diameter of the tube, and A is the cross-sectional area of ​​the tube.

[0092] 2. Determine the minimum flow rate allowed for flowback optimization, i.e. the critical flow rate for wellbore proppant settling:

[0093] During the flowback process, if the liquid flowback flow rate is too low, the proppant or formation sand returned from the fracture cannot be carried out of the wellhead, which will cause the proppant in the wellbore to settle. The settled proppant will block the wellbore, reducing the flowback efficiency. In addition, the moving proppant will impact the wellbore and downhole equipment, shortening their service life. In order to avoid the settlement of wellbore proppant during the flowback process, the flowback flow rate should be higher than the critical flow rate for the settlement of wellbore proppant. A wellbore proppant settlement model is established, and the critical flow rate for the settlement of wellbore proppant satisfies formula (3):

[0094]

[0095] Among them, d s is the particle diameter of the wellbore proppant, ρ is the fluid density of the wellbore fluid, d W is the diameter of the wellbore, ρ s is the density of the wellbore proppant, q cr is the sedimentation boundary flow rate, g is the acceleration of gravity, and π is the circumference of a circle.

[0096] 3. Determine the maximum flow rate allowed for flowback optimization, i.e. the critical flow rate of fracture proppant:

[0097] During the flowback process, when the liquid flowback flow rate is too high, the proppant in the fracture will be brought out of the fracture, which will harm the gas reservoir and the fracture, damage the gas reservoir transformation effect, and cause fracture loss. The proppant flowing back out of the fracture creates the necessary conditions for the above-mentioned wellbore proppant sedimentation. In order to avoid fracture proppant backflow during the flowback process, the flowback flow rate should be lower than the fracture proppant backflow flow rate. A fracture proppant backflow model is established, and the critical backflow flow rate of the fracture proppant satisfies formula (1) and formula (2):

[0098] q=anvhw f (1)

[0099]

[0100] Where a is the ratio of the number of effectively opened cracks to the total number of clusters, n is the total number of clusters undergoing fracturing, h is the height of the target crack, and w is the height of the target crack. f is the width of the target fracture, v is the backflow velocity of the fracture proppant, q is the critical backflow flow rate, γ is the surface tension of the backflow fluid during the backflow process, μ is the fluid viscosity of the backflow fluid during the backflow process, ΔP is the net pressure acting on the fracture proppant, and d s is the particle diameter of the wellbore proppant, ρ s is the density of the wellbore proppant, and g is the acceleration due to gravity.

[0101] 4. Determine the minimum bottom hole pressure allowed for flowback:

[0102] 1. For single-phase liquid, to ensure that the single-phase liquid can be discharged from the wellhead, the first minimum bottom hole pressure required satisfies formula (4):

[0103]

[0104] Among them, MD is the vertical depth of the target well, P Hmin is the minimum wellhead pressure of the target well, h w is the friction head loss of single-phase liquid along the way, p wmin is the first minimum bottom hole flowing pressure, and g is the gravitational acceleration.

[0105] 2. For gas-liquid two-phase fluid, the second minimum bottom hole pressure that may occur during the flowback process is calculated based on the wellhead pressure using formula (5).

[0106] 5. Determine the critical liquid-carrying velocity of the gas phase to prevent liquid accumulation in the gas-liquid two-phase flow stage. The critical liquid-carrying velocity of the gas phase can be determined according to formula (6):

[0107]

[0108] Where, σ is the interfacial tension, ρ is the density of the fluid in the wellbore, and ρ g is the gas density, V cr is the critical liquid-carrying velocity of the gas phase.

[0109] Then, the critical liquid carrying rate can be determined according to formula (7):

[0110]

[0111] Where A is the wellbore cross-sectional area, p is the pressure, Z is the deviation factor, T is the wellhead temperature, and q sc is the critical liquid carrying flow rate.

[0112] Thus, liquid accumulation can be prevented during the flowback process in the gas-liquid two-phase flow stage.

[0113] 6. Formulate a comprehensive optimization strategy to draw safe return areas:

[0114] Obtain the real-time backflow flow rate and real-time bottom hole flow pressure at different backflow stages during the backflow process. The real-time backflow flow rate includes the first real-time backflow flow rate at the pure liquid discharge stage and the second real-time backflow flow rate at the gas-liquid two-phase flow stage. The real-time bottom hole flow pressure includes the first real-time bottom hole flow pressure at the pure liquid discharge stage and the second real-time bottom hole flow pressure at the gas-liquid two-phase flow stage.

[0115] 1. Optimization of flowback in the pure drainage stage: adjust the first real-time bottom hole flow pressure so that it is greater than the initial bottom hole flow pressure and less than the first minimum bottom hole flow pressure, and make the first real-time flowback flow rate greater than the critical flow rate of sedimentation and less than the critical reflux flow rate, so as to determine the safe flowback area in the pure drainage stage.

[0116] 2. Optimize the flowback in the gas-liquid two-phase flow stage: adjust the second real-time bottom hole flow pressure so that it is greater than the initial bottom hole flow pressure and less than the second minimum bottom hole flow pressure, and make the second real-time flowback flow rate greater than the sedimentation critical flow rate and less than the critical reflux flow rate, and determine the safe flowback area in the pure drainage stage.

[0117] like Figure 2 As shown in the figure, the schematic diagram of each area of ​​the safe backflow chart, the horizontal axis X is the backflow flow rate, the unit is m 3 / d, the vertical coordinate Y is the flowback bottom pressure, in MPa, area F is the safe flowback area, area G is the critical area for safe flowback, and the rest of the areas are unfavorable areas. The flowback system should not be located in the rest of the areas. The bottom flow pressure in areas A, B, C, and D is too high, the opening pressure is too high, and the proppant is not effectively filled; the flow rate in area E is too low to carry the proppant in the wellbore; the flow rate in area H is too high, which will cause the proppant in the fracture to flow back; the bottom flow pressure in areas I, J, K, and L is too low, which will not occur in actual production.

[0118] The following is an example of a shale gas well:

[0119] Calculate various flowback optimization parameters. From the well logging data, we know that the average minimum horizontal principal stress of the well is 92.5MPa, which enables the proppant to achieve effective support. The recommended bottom hole pressure for well opening is 87.5-85.5MPa; the critical sand carrying flow rate is 64m 3 / d; critical reflux flow rate of fracture proppant 189m 3 / d. Determine the safe flowback area F and the critical safe flowback area G, and draw a safe flowback chart for the pure drainage stage of the well, such as Figure 3 shown.

[0120] The actual bottom hole pressure-flow curve (gray scattered points in the figure) of the well in the pure drainage stage is plotted in the same figure, as shown in Figure 4 shown.

[0121] It can be seen that the timing of the well opening meets the bottom hole flow pressure requirement. The flowback flow rate system in the pure drainage stage is reasonable and higher than the critical sand carrying flow rate, which can achieve wellbore proppant carrying without proppant sedimentation in the wellbore. It is also lower than the fracture proppant carrying flow rate, so fracture proppant backflow is not likely to occur. The pressure of the well in the pure drainage stage decreases evenly and gently. According to formula (5), the fracture volume loss at the end of the pure drainage stage is only 5.52%.

[0122]

[0123] Among them, V fi is the initial crack volume, C f is the crack compression coefficient, dP f is the pressure drop compared to the initial bottom hole flowing pressure.

[0124] Next, draw the safe flowback area of ​​the gas-liquid two-phase stage, and draw the bottom hole pressure-flow curve of the gas-liquid two-phase flow stage in the actual flowback process of the well in the same figure, such as Figure 5 As shown in the figure, it can be seen that in the gas-liquid two-phase flow stage, the backflow system of the well is generally in the safe backflow area, but there is a certain period of time in the early stage when the backflow flow rate reaches the front section of the safe backflow critical area. Due to the increase in the degree of fracture initiation in the gas-liquid two-phase flow stage, it is still safe to backflow. In addition, there is a certain period of time when the flow rate is too low, and the wellbore proppant sedimentation occurs. Then the backflow flow rate is increased to carry the sedimentation proppant out of the wellhead. Finally, the effective fracture volume loss rate of the well after 2000h backflow is 27.55%.

[0125] For wells with good data quality and backflow using different backflow methods, the fracture volume loss rate of each well and the proportion of the actual backflow system of each well located in the safe backflow area drawn according to the method recorded in this application are calculated. It is found that the higher the proportion of the actual backflow system located in the safe area, the smaller the fracture volume loss rate at the end of backflow, and the better the transformation effect, which proves that this application can effectively optimize the backflow operation in the actual backflow operation. Figure 6 As shown, the fracture volume loss rate is inversely proportional to the actual system proportion located in the safe zone.

[0126] Figure 2 A schematic diagram of a safe flowback area according to an embodiment of the present application is shown schematically. Figure 2 As shown, in the embodiment of the present application, the horizontal axis X is the backflow flow rate, the unit is m 3 / d, the vertical coordinate Y is the flowback bottom pressure, in MPa, area F is the safe flowback area, area G is the critical area for safe flowback, and the rest of the areas are unfavorable areas. The flowback system should not be located in the rest of the areas. The bottom flow pressure in areas A, B, C, and D is too high, the opening pressure is too high, and the proppant is not effectively filled; the flow rate in area E is too low to carry the proppant in the wellbore; the flow rate in area H is too high, which will cause the proppant in the fracture to flow back; the bottom flow pressure in areas I, J, K, and L is too low, which will not occur in actual production.

[0127] Figure 3 A schematic diagram of a safe flowback area of ​​an example well according to an embodiment of the present application is shown schematically. Figure 3 As shown, in the embodiment of the present application, the horizontal axis X is the backflow flow rate, the unit is m 3 / d, the vertical axis Y is the bottom flow pressure of the return hole, the unit is MPa, area F is the safe return area, and area G is the critical area of ​​safe return.

[0128] Figure 4 A schematic diagram showing a comparison between actual backflow data and a safety zone in a pure drainage phase according to an embodiment of the present application is shown. Figure 4 As shown, in the embodiment of the present application, Figure 4 The multiple black dots in the figure represent the first actual flowback data in the pure drainage stage, and the first actual flowback data are basically within the F safe flowback area.

[0129] Figure 5 A schematic diagram showing a comparison between actual backflow data and safety zone in a gas-liquid two-phase flow stage according to an embodiment of the present application. Figure 5 As shown, in the embodiment of the present application, Figure 5 The multiple black dots in the graph represent the second actual flowback data in the gas-liquid two-phase flow stage. The second actual flowback data are basically within the F safety flowback area and the G safety flowback critical area.

[0130] Figure 6 A comparison diagram of effectiveness according to an embodiment of the present application is schematically shown. Figure 6 As shown in the embodiment of the present application, the dotted line represents the crack volume loss rate, the actual system ratio in the safe zone, the ordinate represents the ratio, from 0 to 100, and the abscissa represents different wells, which correspond to Figure 2 The 8 regions represented in .

[0131] Figure 7 The structure block diagram of a device for optimizing the flowback of oil and gas wells after fracturing according to an embodiment of the present application is schematically shown. Figure 7As shown, in an embodiment of the present application, a device for optimizing the backflow of oil and gas wells after fracturing is provided, and the device includes: a data acquisition module 710, which is used to obtain the real-time backflow flow rate and the real-time bottom hole flow pressure at different backflow stages during the backflow process, wherein the real-time backflow flow rate includes the first real-time backflow flow rate in the pure liquid discharge stage and the second real-time backflow flow rate in the gas-liquid two-phase flow stage, and the real-time bottom hole flow pressure includes the first real-time bottom hole flow pressure in the pure liquid discharge stage and the second real-time bottom hole flow pressure in the gas-liquid two-phase flow stage; a data processing module 720, which is used to determine the initial bottom hole flow pressure when the target well is opened, the sedimentation critical flow rate of the wellbore proppant of the target well during the backflow process, and the fracture proppant of the target fracture The critical reflux flow rate and the first minimum bottomhole flow pressure of the single-phase liquid during the return process and the second minimum bottomhole flow pressure of the gas-liquid two-phase fluid during the return process; the data adjustment module 730 is used to adjust the first real-time bottomhole flow pressure and the first real-time return flow rate in the pure drainage stage, so that the first real-time bottomhole flow pressure is greater than the initial bottomhole flow pressure and less than the first minimum bottomhole flow pressure, and the first real-time return flow rate is greater than the sedimentation critical flow rate and less than the critical reflux flow rate; in the gas-liquid two-phase flow stage, adjust the second real-time bottomhole flow pressure and the first real-time return flow rate, so that the second real-time bottomhole flow pressure is greater than the initial bottomhole flow pressure and less than the second minimum bottomhole flow pressure, and the second real-time return flow rate is greater than the sedimentation critical flow rate and less than the critical reflux flow rate.

[0132] In one embodiment, the data acquisition module 710 acquires the real-time backflow flow rate and the real-time bottom hole flow pressure at different backflow stages during the backflow process, wherein the real-time backflow flow rate includes the first real-time backflow flow rate at the pure liquid discharge stage and the second real-time backflow flow rate at the gas-liquid two-phase flow stage, and the real-time bottom hole flow pressure includes the first real-time bottom hole flow pressure at the pure liquid discharge stage and the second real-time bottom hole flow pressure at the gas-liquid two-phase flow stage. The data acquisition module 710 transmits the acquired data to the data processing module 720. The data processing module 720 receives the data transmitted from the data acquisition module 710, and determines the initial bottom hole flow pressure when the target well is opened, the critical flow rate of the wellbore proppant of the target well during the backflow process, the critical backflow flow rate of the fracture proppant of the target fracture, the first minimum bottom hole flow pressure of the single-phase liquid during the backflow process, and the second minimum bottom hole flow pressure of the gas-liquid two-phase fluid during the backflow process. The data processing module 720 transmits the processed data to the data adjustment module 730. The data adjustment module 730 receives the data transmitted from the data processing module 720, and adjusts the first real-time bottom hole flow pressure and the first real-time backflow flow rate in the pure drainage stage, so that the first real-time bottom hole flow pressure is greater than the initial bottom hole flow pressure and less than the first minimum bottom hole flow pressure, and the first real-time backflow flow rate is greater than the sedimentation critical flow rate and less than the critical backflow flow rate; in the gas-liquid two-phase flow stage, adjusts the second real-time bottom hole flow pressure and the first real-time backflow flow rate, so that the second real-time bottom hole flow pressure is greater than the initial bottom hole flow pressure and less than the second minimum bottom hole flow pressure, and the second real-time backflow flow rate is greater than the sedimentation critical flow rate and less than the critical backflow flow rate.

[0133] Figure 8 The structure block diagram of an electronic device according to an embodiment of the present application is schematically shown. Figure 8 As shown, an embodiment of the present application provides a controller, which may include:

[0134] Memory 810, configured to store instructions; and

[0135] The processor 820 is configured to call instructions from the memory 810 and implement the above-mentioned method for optimizing the flowback of oil and gas wells after fracturing when executing the instructions.

[0136] Specifically, in the embodiment of the present application, the processor 820 may be configured to:

[0137] Determine the initial bottom hole flowing pressure when the target well is opened;

[0138] Determine the critical flow rate of the wellbore proppant of the target well and the critical flow rate of the fracture proppant of the target fracture during the flowback process;

[0139] Determine a first minimum bottom hole flow pressure of a single-phase liquid during a flowback process and a second minimum bottom hole flow pressure of a gas-liquid two-phase fluid during a flowback process;

[0140] Acquire the real-time flowback flow rate and real-time bottom hole flow pressure at different flowback stages during the flowback process, wherein the real-time flowback flow rate includes a first real-time flowback flow rate at a pure liquid discharge stage and a second real-time flowback flow rate at a gas-liquid two-phase flow stage, and the real-time bottom hole flow pressure includes a first real-time bottom hole flow pressure at a pure liquid discharge stage and a second real-time bottom hole flow pressure at a gas-liquid two-phase flow stage;

[0141] In the pure drainage stage, adjusting the first real-time bottom hole flow pressure and the first real-time flowback flow rate so that the first real-time bottom hole flow pressure is greater than the initial bottom hole flow pressure and less than the first minimum bottom hole flow pressure, and the first real-time flowback flow rate is greater than the critical flow rate of sedimentation and less than the critical return flow rate;

[0142] In the gas-liquid two-phase flow stage, the second real-time bottom hole flow pressure and the first real-time backflow flow rate are adjusted so that the second real-time bottom hole flow pressure is greater than the initial bottom hole flow pressure and less than the second minimum bottom hole flow pressure, and the second real-time backflow flow rate is greater than the sedimentation critical flow rate and less than the critical reflux flow rate.

[0143] Further, the processor 820 may be further configured to: determine the critical backflow flow rate of the fracture proppant of the target fracture during the backflow process, including determining the critical backflow flow rate according to formula (1):

[0144] q=anvhw f (1)

[0145] Where a is the ratio of the number of effectively opened cracks to the total number of clusters, n is the total number of clusters undergoing fracturing, h is the height of the target crack, and w is the height of the target crack. f is the width of the target fracture, v is the reflux velocity of the fracture proppant, and q is the critical reflux flow rate.

[0146] Further, the processor 820 may be further configured to: determine the critical backflow flow rate of the fracture proppant of the target fracture during the backflow process further comprising determining the backflow flow rate of the fracture proppant according to formula (2):

[0147]

[0148] Where γ is the surface tension of the flowback fluid during the flowback process, μ is the fluid viscosity of the flowback fluid during the flowback process, ΔP is the net pressure acting on the fracture proppant, and d s is the particle diameter of the wellbore proppant, ρ s is the density of the wellbore proppant, v is the return flow rate, and g is the gravitational acceleration.

[0149] Further, the processor 820 may be further configured to: determine the critical settling rate of the wellbore proppant of the target well during the flowback process, including determining the critical settling rate according to formula (3):

[0150]

[0151] Among them, d s is the particle diameter of the wellbore proppant, ρ is the fluid density of the wellbore fluid, d W is the diameter of the wellbore, ρ s is the density of the wellbore proppant, q cr is the sedimentation boundary flow rate, g is the acceleration of gravity, and π is the circumference of a circle.

[0152] Further, the processor 820 may also be configured to: determine the first minimum bottom hole flow pressure of the single-phase liquid during the flowback process, including determining the first minimum bottom hole flow pressure according to formula (4):

[0153]

[0154] Where MD is the vertical depth of the target well, p Hmin is the minimum wellhead pressure of the target well, h w is the friction head loss of single-phase liquid along the way, p wmin is the first minimum bottom hole flowing pressure, and g is the gravitational acceleration.

[0155] Further, the processor 820 may be further configured to: determine the second minimum bottom hole flow pressure of the gas-liquid two-phase fluid during the flowback process includes:

[0156] Obtaining the wellhead pressure of the target well measured by the wellhead pressure gauge;

[0157] Based on the Bergs-Brill method, the wellhead pressure is converted to obtain the second minimum bottom hole flowing pressure.

[0158] Further, the processor 820 may also be configured to: determine the initial bottom hole flow pressure when the target well is opened, including:

[0159] Obtaining the initial wellhead pressure of the target well when it is opened, measured by the wellhead pressure gauge;

[0160] Based on the Berggs-Brill method, the initial wellhead pressure is converted to obtain the initial bottom hole flowing pressure.

[0161] Through the above technical solution, first, the processor 820 determines the initial bottom hole flow pressure when the target well is opened, determines the critical flow rate of the wellbore proppant of the target well and the critical return flow rate of the fracture proppant of the target fracture during the backflow process, and determines the first minimum bottom hole flow pressure of the single-phase liquid during the backflow process and the second minimum bottom hole flow pressure of the gas-liquid two-phase fluid during the backflow process; then, the processor 820 obtains the real-time backflow flow rate and the real-time bottom hole flow pressure in different backflow stages during the backflow process, the real-time backflow flow rate includes the first real-time backflow flow rate in the pure liquid discharge stage and the second real-time backflow flow rate in the gas-liquid two-phase flow stage, and the real-time bottom hole flow pressure includes the first real-time backflow flow rate in the pure discharge stage and the second real-time backflow flow rate in the gas-liquid two-phase flow stage. The first real-time bottom hole pressure in the liquid phase and the second real-time bottom hole pressure in the gas-liquid two-phase flow phase; in the pure liquid discharge phase, the processor 820 adjusts the first real-time bottom hole pressure and the first real-time flowback flow rate, so that the first real-time bottom hole pressure is greater than the initial bottom hole pressure and less than the first minimum bottom hole pressure, and the first real-time flowback flow rate is greater than the settling critical flow rate and less than the critical flowback flow rate; in the gas-liquid two-phase flow phase, the processor 820 adjusts the second real-time bottom hole pressure and the first real-time flowback flow rate, so that the second real-time bottom hole pressure is greater than the initial bottom hole pressure and less than the second minimum bottom hole pressure, and the second real-time flowback flow rate is greater than the settling critical flow rate and less than the critical flowback flow rate. The present application proposes a method for optimizing the flowback system, which can achieve quantitative flowback, thereby effectively improving oil production capacity.

[0162] An embodiment of the present application also provides a machine-readable storage medium having instructions stored thereon, the instructions being used to enable a machine to execute the above-mentioned method for optimizing the flowback of oil and gas wells after fracturing.

[0163] Those skilled in the art will appreciate that the embodiments of the present application may be provided as methods, systems or computer program products. Therefore, the present application may adopt the form of a complete hardware embodiment, a complete software embodiment or an embodiment in combination with software and hardware. Moreover, the present application may adopt the form of a computer program product implemented on one or more computer-usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) that contain computer-usable program code.

[0164] The present application is described with reference to the flowcharts and / or block diagrams of the methods, devices (systems), and computer program products according to the embodiments of the present application. It should be understood that each process and / or box in the flowchart and / or block diagram, as well as the combination of the processes and / or boxes in the flowchart and / or block diagram, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, a special-purpose computer, an embedded processor, or other programmable data processing device to generate a machine, so that the instructions executed by the processor of the computer or other programmable data processing device generate instructions for implementing the processes in the flowchart and / or block diagram. Figure 1A process or multiple processes and / or boxes Figure 1 A device that provides the functions specified in a block or multiple blocks.

[0165] These computer program instructions may also be stored in a computer-readable memory capable of directing a computer or other programmable data processing device to operate in a specific manner, so that the instructions stored in the computer-readable memory produce an article of manufacture comprising an instruction device, which implements the process Figure 1 A process or multiple processes and / or boxes Figure 1 A function specified in one or more boxes.

[0166] These computer program instructions can also be loaded onto a computer or other programmable data processing device so that a series of operating steps are executed on the computer or other programmable device to produce a computer-implemented process, thereby providing instructions for implementing the process in the computer or other programmable device. Figure 1 A process or multiple processes and / or boxes Figure 1 The steps for the functions specified in one or more boxes.

[0167] In a typical configuration, a computing device includes one or more processors (CPU), input / output interfaces, network interfaces, and memory.

[0168] The memory may include non-permanent memory in a computer-readable medium, random access memory (RAM) and / or non-volatile memory in the form of read-only memory (ROM) or flash RAM. The memory is an example of a computer-readable medium.

[0169] Computer readable media include permanent and non-permanent, removable and non-removable media that can be implemented by any method or technology to store information. Information can be computer readable instructions, data structures, program modules or other data. Examples of computer storage media include, but are not limited to, phase change memory (PRAM), static random access memory (SRAM), dynamic random access memory (DRAM), other types of random access memory (RAM), read-only memory (ROM), electrically erasable programmable read-only memory (EEPROM), flash memory or other memory technology, compact disk read-only memory (CD-ROM), digital versatile disk (DVD) or other optical storage, magnetic cassettes, magnetic tape disk storage or other magnetic storage devices or any other non-transmission media that can be used to store information that can be accessed by a computing device. As defined herein, computer readable media does not include temporary computer readable media (transitory media), such as modulated data signals and carrier waves.

[0170] It should also be noted that the terms "include", "comprises" or any other variations thereof are intended to cover non-exclusive inclusion, so that a process, method, commodity or device including a series of elements includes not only those elements, but also other elements not explicitly listed, or also includes elements inherent to such process, method, commodity or device. In the absence of more restrictions, the elements defined by the sentence "comprises a ..." do not exclude the existence of other identical elements in the process, method, commodity or device including the elements.

[0171] The above are only embodiments of the present application and are not intended to limit the present application. For those skilled in the art, the present application may have various changes and variations. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present application should be included within the scope of the claims of the present application.

Claims

1. A method for optimizing flowback of oil and gas wells after fracturing, characterized in that: The method comprises: Determine the initial bottom hole flowing pressure when the target well is opened; Determine the critical settling flow rate of the wellbore proppant of the target well and the critical return flow rate of the fracture proppant of the target fracture during the flowback process; Determine a first minimum bottom hole flow pressure of a single-phase liquid during a flowback process and a second minimum bottom hole flow pressure of a gas-liquid two-phase fluid during a flowback process; Acquire the real-time flowback flow rate and the real-time bottom hole flow pressure at different flowback stages during the flowback process, wherein the real-time flowback flow rate includes a first real-time flowback flow rate at a pure liquid discharge stage and a second real-time flowback flow rate at a gas-liquid two-phase flow stage, and the real-time bottom hole flow pressure includes a first real-time bottom hole flow pressure at a pure liquid discharge stage and a second real-time bottom hole flow pressure at a gas-liquid two-phase flow stage; In the pure drainage stage, adjusting the first real-time bottom hole flow pressure and the first real-time flowback flow rate so that the first real-time bottom hole flow pressure is greater than the initial bottom hole flow pressure and less than the first minimum bottom hole flow pressure, and the first real-time flowback flow rate is greater than the sedimentation critical flow rate and less than the critical reflux flow rate; In the gas-liquid two-phase flow stage, the second real-time bottom hole flow pressure and the first real-time backflow flow rate are adjusted so that the second real-time bottom hole flow pressure is greater than the initial bottom hole flow pressure and less than the second minimum bottom hole flow pressure, and the second real-time backflow flow rate is greater than the sedimentation critical flow rate and less than the critical reflux flow rate.

2. The method according to claim 1, characterized in that Determining the critical reflux flow rate of the fracture proppant of the target fracture during the flowback process includes determining the critical reflux flow rate according to formula (1): q=anvhw f (1) Wherein, a is the ratio of the number of effectively opened cracks to the total number of clusters, n is the total number of clusters undergoing fracturing, h is the height of the target crack, and w is the height of the target crack. f is the width of the target fracture, v is the reflux velocity of the fracture proppant, and q is the critical reflux flow rate.

3. The method according to claim 2, characterized in that Determining the critical reflux flow rate of the fracture proppant of the target fracture during the flowback process also includes determining the reflux flow rate of the fracture proppant according to formula (2): Wherein, γ is the surface tension of the flowback fluid during the flowback process, μ is the fluid viscosity of the flowback fluid during the flowback process, ΔP is the net pressure acting on the fracture proppant, and d s is the particle diameter of the wellbore proppant, ρ s is the density of the wellbore proppant, v is the reflux velocity, and g is the gravitational acceleration.

4. The method according to claim 1, characterized in that: Determining the critical settling rate of the wellbore proppant of the target well during the flowback process includes determining the critical settling rate according to formula (3): Among them, d s is the particle diameter of the wellbore proppant, ρ is the fluid density of the fluid in the wellbore, d W is the diameter of the wellbore, ρ s is the density of the wellbore proppant, q cr is the sedimentation boundary flow rate, g is the gravitational acceleration, and π is the pi.

5. The method according to claim 1, characterized in that Determining the first minimum bottom hole flow pressure of the single-phase liquid during the flowback process includes determining the first minimum bottom hole flow pressure according to formula (4): Wherein, MD is the vertical depth of the target well, p Hmin is the minimum wellhead pressure of the target well, h w is the friction head loss of the single-phase liquid along the way, p wmin is the first minimum bottom hole flowing pressure, and g is the gravitational acceleration.

6. The method according to claim 1, characterized in that Determining the second minimum bottom hole flow pressure of the gas-liquid two-phase fluid during the flowback process includes: Obtaining the wellhead pressure of the target well measured by a wellhead pressure gauge; Based on the Bergs-Brill method, the wellhead pressure is converted to obtain the second minimum bottom hole flowing pressure.

7. The method according to claim 1, characterized in that Determining the initial bottom hole flowing pressure when the target well is opened includes: Obtaining the initial wellhead pressure of the target well when it is opened, measured by a wellhead pressure gauge; Based on the Bergs-Brill method, the initial wellhead pressure is converted to obtain the initial bottom hole flowing pressure.

8. A device for optimizing flowback of oil and gas wells after fracturing, characterized in that: include: A data acquisition module, used to acquire the real-time flowback flow rate and the real-time bottom hole flow pressure at different flowback stages during the flowback process, wherein the real-time flowback flow rate includes a first real-time flowback flow rate at a pure liquid discharge stage and a second real-time flowback flow rate at a gas-liquid two-phase flow stage, and the real-time bottom hole flow pressure includes a first real-time bottom hole flow pressure at a pure liquid discharge stage and a second real-time bottom hole flow pressure at a gas-liquid two-phase flow stage; A data processing module is used to determine the initial bottom hole flow pressure when the target well is opened, the critical flow rate of the wellbore proppant of the target well and the critical return flow rate of the fracture proppant of the target fracture during the flowback process, as well as the first minimum bottom hole flow pressure of the single-phase liquid during the flowback process and the second minimum bottom hole flow pressure of the gas-liquid two-phase fluid during the flowback process; The data adjustment module is used to adjust the first real-time bottom hole flow pressure and the first real-time flowback flow rate in the pure drainage stage, so that the first real-time bottom hole flow pressure is greater than the initial bottom hole flow pressure and less than the first minimum bottom hole flow pressure, and the first real-time flowback flow rate is greater than the sedimentation critical flow rate and less than the critical return flow rate; in the gas-liquid two-phase flow stage, adjust the second real-time bottom hole flow pressure and the first real-time flowback flow rate, so that the second real-time bottom hole flow pressure is greater than the initial bottom hole flow pressure and less than the second minimum bottom hole flow pressure, and the second real-time flowback flow rate is greater than the sedimentation critical flow rate and less than the critical return flow rate.

9. An electronic device, characterized in that: include: a memory configured to store instructions; as well as A processor is configured to call the instructions from the memory and implement the method for optimizing post-fracture oil and gas well flowback according to any one of claims 1 to 8 when executing the instructions.

10. A machine-readable storage medium, characterized in that: The machine-readable storage medium stores instructions for causing a machine to execute the method for optimizing post-fracture oil and gas well flowback according to any one of claims 1 to 8.

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