Pressure control flowback method, device, equipment and medium

Abstract

The invention relates to the technical field of pressure control flow-back, and discloses a pressure control flow-back method, device, equipment and medium, and the method comprises the following steps: based on the initial formation pressure, the initial formation water saturation, the initial bottom hole pressure and the wellhead flow at the end of fracturing, obtaining the wellhead flow of a preset time length of well opening; obtaining an initial resistance reduction ratio based on the wellhead flow of the preset well opening duration; based on the wellhead flow and the initial resistance reduction ratio of the preset well opening duration, the friction resistance of the flowback fluid in the shaft is obtained; obtaining an initial oil nozzle diameter based on the target bottom hole pressure, the initial wellhead pressure, the wellhead flow of the preset well opening duration and the friction resistance of the flowback fluid in the shaft; iteratively updating the initial resistance reduction ratio, the friction resistance of the flowback fluid in the shaft and the initial diameter of the oil nozzle to obtain the flowback bottom hole pressure; and based on the target bottom hole pressure and the bottom hole pressure after flow-back, the diameter of the oil nozzle for pressure control flow-back is determined, and the bottom hole pressure for pressure control flow-back is accurately controlled.

Description

Technical Field

[0001] This application relates to the technical field of controlled-pressure flowback, and particularly to a method, device, equipment and medium for controlled-pressure flowback. Background Art

[0002] Controlled-pressure flowback after fracturing is an important link in oil and gas field development, especially in the development of low-permeability and extra-low-permeability oil and gas reservoirs. A reasonable flowback rate is conducive to improving the flowback efficiency of fracturing fluid, effectively controlling the backflow of proppants, and improving the effective conductivity of fractures, thereby enhancing the effect of fracturing stimulation.

[0003] The flowback rate of fracturing fluid is related to the bottom-hole pressure. Under an excessive bottom-hole pressure, the fracturing fluid flows back slowly, which will cause formation pollution; under a too low bottom-hole pressure, the fracturing fluid flows back quickly, which will cause proppant backflow and reduce the fracture conductivity. To enable the fracturing fluid to flow back out of the formation faster while ensuring that as many proppants as possible remain in the fractures, it is necessary to precisely control the bottom-hole pressure. However, the prior art cannot directly monitor the bottom-hole pressure, which brings great difficulties to controlled-pressure flowback. Summary of the Invention

[0004] The purpose of the embodiments of this application is to provide a method, device, equipment and medium for controlled-pressure flowback to solve the great difficulties in controlled-pressure flowback caused by the inability of the prior art to directly monitor the bottom-hole pressure.

[0005] To achieve the above purpose, the first aspect of this application provides a method for controlled-pressure flowback, including:

[0006] Obtain the initial formation pressure, initial formation water saturation, initial bottom-hole pressure, initial wellhead pressure and target bottom-hole pressure at the end of fracturing;

[0007] Based on the initial formation pressure, initial formation water saturation, initial bottom-hole pressure and the wellhead flow rate at the end of fracturing, obtain the wellhead flow rate for a preset open-well duration;

[0008] Based on the wellhead flow rate for the preset open-well duration, obtain the initial pressure drop ratio;

[0009] Based on the wellhead flow rate for the preset open-well duration and the initial pressure drop ratio, obtain the friction of the flowback fluid in the wellbore;

[0010] Based on the target bottom-hole pressure, initial wellhead pressure, wellhead flow rate for the preset open-well duration and the friction of the flowback fluid in the wellbore, obtain the initial choke diameter;

[0011] Iteratively update the initial pressure drop ratio, the friction of the flowback fluid in the wellbore and the initial choke diameter to obtain the bottom-hole pressure after flowback;

[0012] Determine the choke diameter for pressure-controlled flowback based on the target bottom-hole pressure and the bottom-hole pressure after flowback.

[0013] In an embodiment of the present application, obtaining the wellhead flow rate for a preset open-well duration based on the initial formation pressure, the initial formation water saturation, the initial bottom-hole pressure, and the wellhead flow rate at the end of fracturing includes:

[0014] Obtain the formation pressure for the preset open-well duration and the formation water saturation for the preset open-well duration based on the wellhead flow rate at the end of fracturing;

[0015] Obtain the total fluid volume flowed back during the preset open-well duration based on the initial formation pressure, the formation pressure for the preset open-well duration, the initial formation water saturation, and the formation water saturation for the preset open-well duration;

[0016] Obtain the wellhead flow rate for the preset open-well duration based on the ratio of the preset open-well duration to the total fluid volume.

[0017] In an embodiment of the present application, obtaining the initial drag reduction ratio based on the wellhead flow rate for the preset open-well duration includes:

[0018] Obtain the initial drag reduction ratio based on the wellhead flow rate for the preset open-well duration and a first formula, where the first formula includes:

[0019]

[0020] In the formula, A0 represents the initial drag reduction ratio, D represents the wellbore diameter, Q0 represents the wellhead flow rate for the preset open-well duration, B represents the concentration of the fracturing fluid thickening agent, and C represents the concentration of the fracturing fluid proppant.

[0021] In an embodiment of the present application, obtaining the friction resistance of the flowback fluid in the wellbore based on the wellhead flow rate for the preset open-well duration and the initial drag reduction ratio includes:

[0022] Obtain the friction resistance of the flowback fluid in the wellbore based on the wellhead flow rate for the preset open-well duration, the initial drag reduction ratio, and a second formula, where the second formula includes:

[0023] P jt0 =1.39×10 12 A0D -4.8 Q0 1.8 H

[0024] In the formula, P jt0 represents the friction resistance of the flowback fluid in the wellbore, A0 represents the initial drag reduction ratio, D represents the wellbore diameter, Q0 represents the wellhead flow rate for the preset open-well duration, and H represents the vertical distance from the bottom hole to the wellhead.

[0025] In the embodiment of the present application, obtaining the initial choke diameter based on the target bottom-hole pressure, the initial wellhead pressure, the wellhead flow rate during the preset open-well duration, and the friction of the produced fluid in the wellbore includes:

[0026] Obtaining the initial choke diameter based on the target bottom-hole pressure, the initial wellhead pressure, the wellhead flow rate during the preset open-well duration, the friction of the produced fluid in the wellbore, and a third formula, where the third formula includes:

[0027]

[0028] In the formula, d0 represents the initial choke diameter, Q0 represents the wellhead flow rate during the preset open-well duration, ρ represents the density of the produced fluid, P jd* represents the target bottom-hole pressure, P jk0 represents the initial wellhead pressure, P jt0 represents the friction of the produced fluid in the wellbore, g represents the gravitational constant, and H represents the vertical distance from the bottom of the well to the wellhead.

[0029] In the embodiment of the present application, iteratively updating the initial drag reduction ratio, the friction of the produced fluid in the wellbore, and the initial choke diameter to obtain the bottom-hole pressure after flowback includes:

[0030] Obtaining the real-time wellhead flow rate after the preset open-well duration and the real-time wellhead pressure after the preset open-well duration;

[0031] Obtaining the updated drag reduction ratio based on the real-time wellhead flow rate after the preset open-well duration;

[0032] Obtaining the updated friction of the produced fluid in the wellbore based on the real-time wellhead flow rate after the preset open-well duration and the updated drag reduction ratio;

[0033] Obtaining the updated choke diameter based on a preset value and the initial choke diameter;

[0034] Obtaining the choke friction based on the real-time wellhead flow rate after the preset open-well duration and the updated choke diameter;

[0035] Obtaining the bottom-hole pressure after flowback based on the real-time wellhead pressure after the preset open-well duration, the updated friction of the produced fluid in the wellbore, and the choke friction.

[0036] In the embodiment of the present application, determining the choke diameter for controlled-pressure flowback based on the target bottom-hole pressure and the bottom-hole pressure after flowback includes:

[0037] Obtaining an error based on the target bottom-hole pressure and the bottom-hole pressure after flowback;

[0038] When the error is greater than the preset threshold, the updated pressure reduction ratio, the friction of the updated flowback fluid in the wellbore, and the updated choke diameter are continuously iteratively updated until the error is less than or equal to the preset threshold;

[0039] When the error is equal to the preset threshold, determine the choke diameter at the end of the iterative update as the choke diameter for controlled-pressure flowback;

[0040] When the error is less than the preset threshold, determine the average value of the choke diameter at the end of the iterative update and the choke diameter before the previous end of the iterative update as the choke diameter for controlled-pressure flowback.

[0041] The second aspect of the present application provides a controlled-pressure flowback device, including:

[0042] An acquisition module, configured to acquire the initial formation pressure, the initial formation water saturation, the initial bottom-hole pressure, the initial wellhead pressure, and the target bottom-hole pressure at the end of fracturing;

[0043] A first obtaining module, configured to obtain the wellhead flow rate for a preset opening duration based on the initial formation pressure, the initial formation water saturation, the initial bottom-hole pressure, and the wellhead flow rate at the end of fracturing;

[0044] A second obtaining module, configured to obtain the initial pressure reduction ratio based on the wellhead flow rate for the preset opening duration;

[0045] A third obtaining module, configured to obtain the friction of the flowback fluid in the wellbore based on the wellhead flow rate for the preset opening duration and the initial pressure reduction ratio;

[0046] A fourth obtaining module, configured to obtain the initial choke diameter based on the target bottom-hole pressure, the initial wellhead pressure, the wellhead flow rate for the preset opening duration, and the friction of the flowback fluid in the wellbore;

[0047] An iterative update module, configured to iteratively update the initial pressure reduction ratio, the friction of the flowback fluid in the wellbore, and the initial choke diameter to obtain the bottom-hole pressure after flowback;

[0048] A determination module, configured to determine the choke diameter for controlled-pressure flowback based on the target bottom-hole pressure and the bottom-hole pressure after flowback.

[0049] The third aspect of the present application provides a controlled-pressure flowback device, including:

[0050] A memory, configured to store instructions;

[0051] A processor, configured to call instructions from the memory and be able to implement the controlled-pressure flowback method of the first aspect when executing the instructions.

[0052] A third aspect of the present application provides a machine-readable storage medium, on which instructions are stored for causing a machine to execute the bottomhole pressure control and flowback method of the first aspect described above.

[0053] Through the above technical solution, by controlling the nozzle diameter of the bottomhole pressure control and flowback to accurately control the bottomhole pressure of the bottomhole pressure control and flowback, formation contamination caused by too slow flowback and proppant backflow caused by too fast flowback are avoided.

[0054] Other features and advantages of the embodiments of the present application will be described in detail in the subsequent specific implementation part. BRIEF DESCRIPTION OF THE DRAWINGS

[0055] The 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 implementation, they are used to explain the embodiments of the present application, but do not constitute a limitation to the embodiments of the present application. In the drawings:

[0056] Figure 1 Schematically shows a flowchart of a bottomhole pressure control and flowback method according to an embodiment of the present application;

[0057] Figure 2 Schematically shows a schematic diagram of a formation-fracture geometry model according to an embodiment of the present application;

[0058] Figure 3 Schematically shows a schematic diagram of the change of the bottomhole pressure according to an embodiment of the present application;

[0059] Figure 4 Schematically shows a schematic diagram of the formation pressure distribution after 34 iterative update operations according to an embodiment of the present application. DETAILED DESCRIPTION OF THE EMBODIMENTS

[0060] To make the objectives, technical solutions, and advantages of the embodiments of the present application clearer, the technical solutions in the embodiments of the present application will be clearly and completely described below with reference to the drawings in the embodiments of the present application. It should be understood that the specific implementation described here is only used to illustrate and explain the embodiments of the present application, and is not used to limit the embodiments of the present application. Based on the embodiments in the present application, all other embodiments obtained by those of ordinary skill in the art without creative efforts fall within the scope of protection of the present application.

[0061] It should be noted that the acquisition, transmission, storage, use, processing, etc. of data in the technical solutions of the present application all comply with the relevant regulations of national laws and regulations. In the embodiments of the present application, some industry-existing solutions such as software, components, models, etc. may be mentioned, and they should be regarded as exemplary. The purpose is only to illustrate the feasibility in the implementation of the technical solutions of the present application, but it does not mean that the applicant has already or necessarily used this solution.

[0062] It should be noted that if there are directional indications involved in the embodiments of the present application (such as up, down, left, right, front, back...), then such directional indications are only used to explain the relative positional relationship, movement conditions, etc. between components in a certain specific posture (as shown in the drawings). If this specific posture changes, then the directional indications will also change accordingly.

[0063] In addition, if there are descriptions involving "first", "second", etc. in the embodiments of the present application, then such descriptions of "first", "second", etc. are only for descriptive purposes and cannot be understood as indicating or implying their relative importance or implicitly specifying the quantity of the indicated technical features. Thus, the features defined with "first" and "second" may explicitly or implicitly include at least one such feature. In addition, the technical solutions between various embodiments can be combined with each other, but it must be based on the fact that those of ordinary skill in the art can implement it. When the combination of technical solutions results in contradictions or cannot be implemented, it should be considered that such a combination of technical solutions does not exist and is not within the scope of protection required by the present application.

[0064] Figure 1 Schematically shows a flow chart of a method for controlled-pressure flowback according to an embodiment of the present application. As Figure 1 shown, the embodiments of the present application provide a method for controlled-pressure flowback, and the method may include the following steps.

[0065] Step S110: Obtain the initial formation pressure, initial formation water saturation, initial bottom-hole pressure, initial wellhead pressure, and target bottom-hole pressure at the end of fracturing.

[0066] In the embodiments of the present application, the initial formation pressure, initial formation water saturation, initial bottom-hole pressure, and initial wellhead pressure at the end of fracturing are all parameters that are easily obtained during the fracturing construction process. The target bottom-hole pressure is preset according to the actual fracturing situation and proppant.

[0067] Step S120: Based on the initial formation pressure, initial formation water saturation, initial bottom-hole pressure, and the wellhead flow rate at the end of fracturing, obtain the wellhead flow rate for a preset open-well duration.

[0068] In the embodiments of the present application, according to the initial formation pressure, initial formation water saturation, initial bottom-hole pressure, and the wellhead flow rate at the end of fracturing obtained in step S110, to determine the wellhead flow rate for a preset open-well duration.

[0069] Further, step S120 includes the following steps:

[0070] Step S121: Based on the wellhead flow rate at the end of fracturing, obtain the formation pressure for a preset open-well duration and the formation water saturation for a preset open-well duration;

[0071] Step S122: Obtain the total fluid volume produced during the preset open - well time based on the initial formation pressure, the formation pressure at the preset open - well time, the initial formation water saturation, and the formation water saturation at the preset open - well time.

[0072] Step S123: Obtain the wellhead flow rate at the preset open - well time based on the ratio of the preset open - well time to the total fluid volume.

[0073] In step S121, the wellhead is not opened at the end of fracturing, and the wellhead flow rate at the end of fracturing is equal to 0. An equation is constructed based on the wellhead flow rate at the end of fracturing:

[0074]

[0075] In the above formula, φ represents the formation porosity, S w represents the formation water saturation, c to represents the compressibility of the oil - phase fluid, p c ′ represents the derivative of the capillary force with respect to the water saturation, c t represents the comprehensive formation compressibility, m represents the formation matrix, represents the derivative of the formation pressure with respect to time, represents the derivative of the formation water saturation with respect to time, K m represents the formation matrix permeability, represents the oil - phase mobility, λ w represents the water - phase mobility, p w represents the formation pressure, q o represents the oil - phase production rate, q w represents the water - phase production rate.

[0076] The above formula is transformed to obtain a matrix equation to be solved. Solving the matrix equation includes:

[0077]

[0078] In the above formula, q represents the fluid source term, and G and K represent the numerical matrices to be solved.

[0079] Use the finite - element analysis method to solve the formation pressure and formation water saturation at each moment after the well is opened:

[0080]

[0081] In the above formula, N represents the shape function for finite - element solution. In finite - element analysis, the shape function is used to approximate the unknowns within the element and transform the problem from the continuous domain to the discrete domain. Through the shape function, the finite - element method transforms the partial - differential equation into a system of linear algebraic equations and finally solves for the unknowns at the nodes.

[0082] From the formation pressure and formation water saturation at each moment after the well is opened obtained by solving, the formation pressure for the preset well-opening duration and the formation water saturation for the preset well-opening duration are extracted. Schematically, if the preset well-opening duration is set to 1 minute, then the formation pressure after the well has been opened for 1 minute and the formation water saturation after the well has been opened for 1 minute are obtained. In the following text, the case where the preset well-opening duration is set to 1 minute is taken as an example for discussion. It can be understood that the preset well-opening duration can be set according to actual needs, and the embodiments of the present application do not limit this.

[0083] In step S122, based on the initial formation pressure, the formation pressure after the well has been opened for 1 minute, the initial formation water saturation, and the formation water saturation after the well has been opened for 1 minute, a spatial integration is performed to obtain the total fluid volume flowing back in 1 minute after the well is opened. Among them, the total fluid volume spatial integration formula includes:

[0084]

[0085] In the above formula, V0 represents the total fluid volume flowing back in 1 minute after the well is opened, S w0 represents the initial formation water saturation at the end of fracturing, p w0 represents the initial formation pressure at the end of fracturing, S w1 represents the formation water saturation after the well has been opened for 1 minute, p w0 represents the formation pressure after the well has been opened for 1 minute.

[0086] In step S123, according to the ratio of the preset well-opening duration to the total fluid volume, the wellhead flow rate for the preset well-opening duration is obtained:

[0087]

[0088] In the above formula, Q0 represents the wellhead flow rate after the well has been opened for 1 minute, and Δt represents the preset duration.

[0089] Step S130: Based on the wellhead flow rate for the preset well-opening duration, an initial resistance reduction ratio is obtained.

[0090] In the embodiments of the present application, based on the wellhead flow rate after the well has been opened for 1 minute obtained in step 120, an initial resistance reduction ratio is obtained.

[0091] Further, step S130 includes the following steps:

[0092] Step S131: Based on the wellhead flow rate for the preset well-opening duration and the first formula, an initial resistance reduction ratio is obtained, where the first formula includes:

[0093]

[0094] Wherein, A0 represents the initial resistance reduction ratio, D represents the wellbore diameter, Q0 represents the wellhead flow rate during the preset well-opening duration, B represents the concentration of the fracturing fluid thickening agent, and C represents the concentration of the fracturing fluid proppant. Schematically, Q0 is the wellhead flow rate for 1 minute of well opening.

[0095] Step S140: Obtain the friction resistance of the produced fluid in the wellbore based on the wellhead flow rate during the preset well-opening duration and the initial resistance reduction ratio.

[0096] In the embodiment of the present application, the friction resistance of the produced fluid in the wellbore is obtained according to the wellhead flow rate during the preset well-opening duration and the initial resistance reduction ratio.

[0097] Further, step S140 includes the following steps:

[0098] Step S141: Obtain the friction resistance of the produced fluid in the wellbore based on the wellhead flow rate during the preset well-opening duration, the initial resistance reduction ratio, and the second formula, where the second formula includes:

[0099] P jt0 = 1.39×10 12 A0D -4.8 Q0 1.8 H

[0100] Wherein, P jt0 represents the friction resistance of the produced fluid in the wellbore, a0 represents the initial resistance reduction ratio, D represents the wellbore diameter, Q0 represents the wellhead flow rate during the preset well-opening duration, and H represents the vertical distance from the bottom of the well to the wellhead. Schematically, Q0 is the wellhead flow rate for 1 minute of well opening.

[0101] Step S150: Obtain the initial choke diameter based on the target bottom hole pressure, the initial wellhead pressure, the wellhead flow rate during the preset well-opening duration, and the friction resistance of the produced fluid in the wellbore.

[0102] In the embodiment of the present application, the initial choke diameter is obtained according to the target bottom hole pressure, the initial wellhead pressure, the wellhead flow rate for 1 minute of well opening, and the friction resistance of the produced fluid in the wellbore.

[0103] Further, step S150 includes the following steps:

[0104] Step S151: Obtain the initial choke diameter based on the target bottom hole pressure, the initial wellhead pressure, the wellhead flow rate during the preset well-opening duration, the friction resistance of the produced fluid in the wellbore, and the third formula, where the third formula includes:

[0105]

[0106] Wherein, d0 represents the initial choke diameter, Q0 represents the wellhead flow rate during the preset well-opening duration, ρ represents the density of the produced fluid, P jd* represents the target bottom hole pressure, P jk0Denotes the initial wellhead pressure, P jt0 Denotes the frictional resistance of the flowback fluid in the wellbore, g denotes the gravitational constant, and H denotes the vertical distance from the bottom of the well to the wellhead. Schematically, Q0 is the wellhead flow rate 1 minute after opening the well.

[0107] Step S160: Iteratively update the initial resistance reduction ratio, the frictional resistance of the flowback fluid in the wellbore, and the initial choke diameter to obtain the bottomhole pressure after flowback.

[0108] In the embodiment of the present application, the initial resistance reduction ratio, the frictional resistance of the flowback fluid in the wellbore, and the initial choke diameter are iteratively updated to determine the bottomhole pressure after flowback.

[0109] Furthermore, step S160 includes the following steps:

[0110] Step S161: Obtain the real-time wellhead flow rate after the preset well-opening duration and the real-time wellhead pressure after the preset well-opening duration;

[0111] Step S162: Obtain the updated resistance reduction ratio based on the real-time wellhead flow rate after the preset well-opening duration;

[0112] Step S163: Obtain the updated frictional resistance of the flowback fluid in the wellbore based on the real-time wellhead flow rate after the preset well-opening duration and the updated resistance reduction ratio;

[0113] Step S164: Obtain the updated choke diameter based on the preset value and the initial choke diameter;

[0114] Step S165: Obtain the choke frictional resistance based on the real-time wellhead flow rate after the preset well-opening duration and the updated choke diameter;

[0115] Step S166: Obtain the bottomhole pressure after flowback based on the real-time wellhead pressure after the preset well-opening duration, the updated frictional resistance of the flowback fluid in the wellbore, and the choke frictional resistance.

[0116] In step S161, the real-time wellhead flow rate 1 minute after opening the well is measured in real time by a flow velocity meter, and the real-time wellhead pressure 1 minute after opening the well is measured in real time by a pressure gauge.

[0117] In step S162, the resistance reduction ratio is updated based on the wellhead flow rate 1 minute after opening the well and the fourth formula, and the fourth formula includes:

[0118]

[0119] In the formula, A i Denotes the resistance reduction ratio after the i-th iterative update, D denotes the wellbore diameter, Q i Denotes the real-time wellhead flow rate after the preset well-opening duration, B denotes the concentration of the fracturing fluid thickener, and C denotes the concentration of the fracturing fluid proppant. Schematically, Q iis the real-time wellhead flow rate after the well has been opened for 1 minute.

[0120] In step S163, according to the wellhead flow rate after the well has been opened for 1 minute, the updated pressure drop reduction ratio, and the fifth formula, the friction of the fluid flowing back in the wellbore is updated. The fifth formula includes:

[0121] P jti = 1.39×10 12 A i D -4.8 Q i 1.8 H

[0122] In the formula, P jti represents the friction of the fluid flowing back in the wellbore after the i-th iterative update, A i represents the pressure drop reduction ratio after the i-th iterative update, D represents the wellbore diameter, Q i represents the real-time wellhead flow rate after the well has been opened for a preset duration, and H represents the vertical distance from the bottom of the well to the wellhead. Schematically, Q i is the real-time wellhead flow rate after the well has been opened for 1 minute.

[0123] In step S164, based on the product of the preset value 1.01 and the initial choke diameter, the updated choke diameter is obtained. Among them, the choke diameter is updated through the sixth formula. The sixth formula includes:

[0124] d i = d i-1 * 1.01

[0125] In the above formula, d i represents the choke diameter after the i-th iterative update, and d i-1 represents the choke diameter after the (i - 1)-th iterative update.

[0126] In step S165, based on the real-time wellhead flow rate after the well has been opened for a preset duration, the updated choke diameter, and the seventh formula, the choke friction is determined. The seventh formula includes:

[0127]

[0128] In the above formula, P yzi represents the choke friction after the i-th iterative update, Q i represents the real-time wellhead flow rate after the well has been opened for a preset duration, ρ represents the density of the fluid flowing back, and d i represents the choke diameter after the i-th iterative update. Schematically, Q i is the real-time wellhead flow rate after the well has been opened for 1 minute.

[0129] In step S166, according to the eighth formula, the real-time wellhead pressure after the preset open well duration, the updated friction of the produced fluid in the wellbore, and the choke friction, determine the bottom hole pressure after flowback. The eighth formula is as follows:

[0130] P jdi = P jki + P jti + P yzi + ρgH

[0131] In the above formula, P jdi represents the bottom hole pressure after flowback, P jki represents the real-time wellhead pressure after the preset open well duration, P jti represents the friction of the produced fluid in the wellbore after the i-th iterative update, P yzi represents the choke friction after the i-th iterative update, ρ represents the density of the produced fluid, g represents the gravitational constant, and H represents the vertical distance from the bottom hole to the wellhead.

[0132] Step S170: Based on the target bottom hole pressure and the bottom hole pressure after flowback, determine the choke diameter for controlled pressure flowback.

[0133] In the embodiments of the present application, according to the target bottom hole pressure and the bottom hole pressure after flowback, the choke diameter for controlled pressure flowback can be determined, and the bottom hole pressure is controlled to be maintained near the target bottom hole pressure by the choke diameter for controlled pressure flowback.

[0134] Further, step S170 includes the following steps:

[0135] Step S171: Based on the target bottom hole pressure and the bottom hole pressure after flowback, obtain an error;

[0136] Step S172: When the error is greater than the preset threshold, continue to iteratively update the updated drag reduction ratio, the updated friction of the produced fluid in the wellbore, and the updated choke diameter until the error is less than or equal to the preset threshold;

[0137] Step S173: When the error is equal to the preset threshold, determine the choke diameter at the end of the iterative update as the choke diameter for controlled pressure flowback;

[0138] Step S174: When the error is less than the preset threshold, determine the average value of the choke diameter at the end of the iterative update and the choke diameter before the end of the iterative update as the choke diameter for controlled pressure flowback.

[0139] In step S171, the error calculation formula includes:

[0140]

[0141] In the above formula, P jdiDenotes the bottom-hole pressure after backflow, P jd* Denotes the target bottom-hole pressure.

[0142] In step S172, illustratively, the preset threshold is 0. If ω i > 0, continue to iteratively update the updated flow resistance reduction ratio, the friction of the updated backflow fluid in the wellbore, and the updated choke diameter until the error is less than or equal to the preset threshold.

[0143] In step S173, if ω i = 0, use the choke diameter at the end of the iterative update as the choke diameter for controlled-pressure backflow.

[0144] In step S174, if ω i < 0, determine the average value of the choke diameter at the end of the iterative update and the choke diameter at the previous time before the end of the iterative update as the choke diameter for controlled-pressure backflow.

[0145] The embodiments of the present application can control the bottom-hole pressure near the target bottom-hole pressure to prevent formation contamination caused by too slow backflow and proppant backflow caused by too fast backflow.

[0146] Illustratively, after determining the choke diameter for controlled-pressure backflow in step S170, start timing until the preset duration is reached, then return to step S160 and re-execute the subsequent steps to keep the bottom-hole pressure always maintained near the target bottom-hole pressure. Among them, the preset duration can be set according to actual needs, and no specific limitation is made in this embodiment.

[0147] Figure 2 Illustratively shows a schematic diagram of the formation-fracture geometry model according to the embodiments of the present application. When using the finite element analysis method, the formation-fracture geometry model as shown in Figure 2 is adopted. The reservoir size, fracture length, and fracture interval of the formation-fracture geometry model can be determined according to the wellbore sweep range and the fracturing evaluation effect. Illustratively, the reservoir size of the formation-fracture geometry model in the embodiments of the present application is 100 m, and the length and interval of the fractures are both 20 m.

[0148] Using the formation-fracture geometry model as shown in Figure 2 obtain the change of the bottom-hole pressure. Figure 3 Illustratively shows a schematic diagram of the change of the bottom-hole pressure according to the embodiments of the present application. As shown in Figure 3 , as the choke diameter continuously increases, the bottom-hole pressure gradually decreases. After 34 iterative update operations, the bottom-hole pressure is controlled from 27800000 Pa to a specific value of 20000000 Pa.

[0149] Figure 4Schematically shown is a schematic diagram of the formation pressure distribution after 34 iterative update operations in the embodiment of the present application. As Figure 4 shown, the bottom hole pressure is 20,000,000 Pa at this time.

[0150] The embodiment of the present application also provides a pressure control and flowback device, including:

[0151] An acquisition module, configured to acquire the initial formation pressure, initial formation water saturation, initial bottom hole pressure, initial wellhead pressure, and target bottom hole pressure at the end of fracturing;

[0152] A first obtaining module, configured to obtain the wellhead flow rate for a preset opening duration based on the initial formation pressure, initial formation water saturation, initial bottom hole pressure, and wellhead flow rate at the end of fracturing;

[0153] A second obtaining module, configured to obtain an initial pressure drop ratio based on the wellhead flow rate for the preset opening duration;

[0154] A third obtaining module, configured to obtain the friction of the flowback fluid in the wellbore based on the wellhead flow rate for the preset opening duration and the initial pressure drop ratio;

[0155] A fourth obtaining module, configured to obtain an initial choke diameter based on the target bottom hole pressure, initial wellhead pressure, wellhead flow rate for the preset opening duration, and friction of the flowback fluid in the wellbore;

[0156] An iterative update module, configured to iteratively update the initial pressure drop ratio, friction of the flowback fluid in the wellbore, and initial choke diameter to obtain the bottom hole pressure after flowback;

[0157] A determination module, configured to determine the choke diameter for pressure control and flowback based on the target bottom hole pressure and the bottom hole pressure after flowback.

[0158] It can be understood that the pressure control and flowback device provided in the embodiment of the present application can implement each process of the pressure control and flowback method in the above embodiment, and can achieve the same technical effects. To avoid repetition, it will not be elaborated here.

[0159] The embodiment of the present application also provides a pressure control and flowback device, including:

[0160] A memory, configured to store instructions;

[0161] A processor, configured to call instructions from the memory and be able to implement the pressure control and flowback method as described above when executing the instructions. And it can achieve the same technical effects. To avoid repetition, it will not be elaborated here.

[0162] The embodiments of the present application further provide a machine-readable storage medium, on which instructions are stored, and the instructions are used to cause a machine to execute the pressure control and backflow method as described above. And the same technical effects can be achieved. To avoid repetition, details are not described here again.

[0163] Those skilled in the art should understand that the embodiments of the present application can be provided as a method, a system, or a computer program product. Therefore, the present application can take the form of a complete hardware embodiment, a complete software embodiment, or an embodiment combining software and hardware aspects. Moreover, the present application can take 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 methods, devices (systems), and computer program products according to the embodiments of the present application. It should be understood that each process and / or block in the flowchart and / or block diagram can be realized by computer program instructions, and the combination of processes and / or blocks in the flowchart and / or block diagram can also be realized by computer program instructions. These computer program instructions can be provided to the processor of a general-purpose computer, a special-purpose computer, an embedded processor, or other programmable data processing devices to generate a machine, so that the instructions executed by the processor of the computer or other programmable data processing devices generate a device for realizing the specified function in one process Figure 1 one process or multiple processes and / or blocks Figure 1 or multiple blocks.

[0165] These computer program instructions can also be stored in a computer-readable memory that can direct a computer or other programmable data processing device to work in a specific manner, so that the instructions stored in the computer-readable memory generate a manufactured product including an instruction device, and the instruction device realizes the specified function in one process Figure 1 one process or multiple processes and / or blocks Figure 1 or multiple blocks.

[0166] These computer program instructions can also be loaded onto a computer or other programmable data processing device, so that a series of operation steps are executed on the computer or other programmable device to generate a computer-implemented process. Therefore, the instructions executed on the computer or other programmable device provide steps for realizing the specified function in one process Figure 1 one process or multiple processes and / or blocks Figure 1 or multiple blocks.

[0167] In a typical configuration, a computing device includes one or more processors (CPUs), an input / output interface, a network interface, and a 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 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 controlled pressure backflow, characterized in that, Including: Obtaining the initial formation pressure, initial formation water saturation, initial bottom-hole pressure, initial wellhead pressure and target bottom-hole pressure at the end of fracturing; Based on the initial formation pressure, the initial formation water saturation, the initial bottom-hole pressure and the wellhead flow rate at the end of fracturing, obtaining the wellhead flow rate for a preset opening time; Based on the wellhead flow rate for the preset opening time, obtaining the initial pressure drop ratio; Based on the wellhead flow rate for the preset opening time and the initial pressure drop ratio, obtaining the friction resistance of the produced fluid in the wellbore; Based on the target bottom-hole pressure, the initial wellhead pressure, the wellhead flow rate for the preset opening time and the friction resistance of the produced fluid in the wellbore, obtaining the initial choke diameter; Iteratively updating the initial pressure drop ratio, the friction resistance of the produced fluid in the wellbore and the initial choke diameter to obtain the bottom-hole pressure after flowback; Based on the target bottom-hole pressure and the bottom-hole pressure after flowback, determining the choke diameter for controlled-pressure flowback.

2. The method according to claim 1, wherein The obtaining the wellhead flow rate for a preset opening time based on the initial formation pressure, the initial formation water saturation, the initial bottom-hole pressure and the wellhead flow rate at the end of fracturing includes: Based on the wellhead flow rate at the end of fracturing, obtaining the formation pressure for a preset opening time and the formation water saturation for a preset opening time; Based on the initial formation pressure, the formation pressure for a preset opening time, the initial formation water saturation and the formation water saturation for a preset opening time, obtaining the total fluid volume produced during the preset opening time; Based on the ratio of the preset opening time to the total fluid volume, obtaining the wellhead flow rate for the preset opening time.

3. The method according to claim 1, characterized in that, The obtaining the initial pressure drop ratio based on the wellhead flow rate for the preset opening time includes: Based on the wellhead flow rate for the preset opening time and a first formula, obtaining the initial pressure drop ratio, where the first formula includes: In the formula, A0 represents the initial pressure drop ratio, D represents the wellbore diameter, Q0 represents the wellhead flow rate for the preset opening time, B represents the concentration of the fracturing fluid thickening agent, and C represents the concentration of the fracturing fluid proppant.

4. The method according to claim 1, wherein The obtaining the friction resistance of the produced fluid in the wellbore based on the wellhead flow rate for the preset opening time and the initial pressure drop ratio includes: Based on the wellhead flow rate for the preset opening time, the initial pressure drop ratio and a second formula, obtaining the friction resistance of the produced fluid in the wellbore, where the second formula includes: P jt0 = 1.39×10 12 A0D -4.8 Q0 1.8 H where P jt0 represents the frictional resistance of the backflow fluid in the wellbore, A0 represents the initial resistance reduction ratio, D represents the wellbore diameter, Q0 represents the wellhead flow rate during the preset well-opening duration, and H represents the vertical distance from the bottom of the well to the wellhead.

5. The method according to claim 1, wherein The obtaining the initial choke diameter based on the target bottom-hole pressure, the initial wellhead pressure, the wellhead flow rate for the preset opening time and the friction resistance of the produced fluid in the wellbore includes: Based on the target bottom-hole pressure, the initial wellhead pressure, the wellhead flow rate for the preset opening time, the friction resistance of the produced fluid in the wellbore and a third formula, obtaining the initial choke diameter, where the third formula includes: Wherein, d0 represents the initial nozzle diameter, Q0 represents the wellhead flow rate during the preset open - well duration, ρ represents the density of the back - flow fluid, P jd* represents the target bottom - hole pressure, P jk0 represents the initial wellhead pressure, P jt0 represents the friction of the back - flow fluid in the wellbore, g represents the gravitational constant, and H represents the vertical distance from the bottom hole to the wellhead.

6. The method according to claim 1, wherein The iteratively updating the pressure drop ratio, the friction resistance of the produced fluid in the wellbore and the choke diameter to obtain the bottom-hole pressure after flowback includes: Obtaining the real-time wellhead flow rate after a preset opening time and the real-time wellhead pressure after a preset opening time; Obtain an updated pressure reduction ratio based on the real-time wellhead flow rate after the preset well-opening duration; Obtain the updated friction of the fluid flowing back in the wellbore based on the real-time wellhead flow rate after the preset well-opening duration and the updated pressure reduction ratio; Obtain an updated choke diameter based on a preset value and the initial choke diameter; Obtain the choke friction based on the real-time wellhead flow rate after the preset well-opening duration and the updated choke diameter; Obtain the bottom-hole pressure after fluid flowing back based on the real-time wellhead pressure after the preset well-opening duration, the updated friction of the fluid flowing back in the wellbore, and the choke friction; 7. The method according to claim 1, wherein The determining the choke diameter for controlled-pressure fluid flowing back based on the target bottom-hole pressure and the bottom-hole pressure after fluid flowing back includes: Obtain an error based on the target bottom-hole pressure and the bottom-hole pressure after fluid flowing back; When the error is greater than a preset threshold, continue to iteratively update the updated pressure reduction ratio, the updated friction of the fluid flowing back in the wellbore, and the updated choke diameter until the error is less than or equal to the preset threshold; When the error is equal to the preset threshold, determine the choke diameter at the end of the iterative update as the choke diameter for controlled-pressure fluid flowing back; When the error is less than the preset threshold, determine the average value of the choke diameter at the end of the iterative update and the choke diameter before the last iteration as the choke diameter for controlled-pressure fluid flowing back.

8. A pressure-controlled flowback device, characterized in that, including: An acquisition module for acquiring the initial formation pressure, the initial formation water saturation, the initial bottom-hole pressure, the initial wellhead pressure, and the target bottom-hole pressure at the end of fracturing; A first obtaining module for obtaining the wellhead flow rate during a preset well-opening duration based on the initial formation pressure, the initial formation water saturation, the initial bottom-hole pressure, and the wellhead flow rate at the end of fracturing; A second obtaining module for obtaining an initial pressure reduction ratio based on the wellhead flow rate during the preset well-opening duration; A third obtaining module for obtaining the friction of the fluid flowing back in the wellbore based on the wellhead flow rate during the preset well-opening duration and the initial pressure reduction ratio; A fourth obtaining module for obtaining an initial choke diameter based on the target bottom-hole pressure, the initial wellhead pressure, the wellhead flow rate during the preset well-opening duration, and the friction of the fluid flowing back in the wellbore; An iterative update module for iteratively updating the initial pressure reduction ratio, the friction of the fluid flowing back in the wellbore, and the initial choke diameter to obtain the bottom-hole pressure after fluid flowing back; A determining module for determining the choke diameter for controlled-pressure fluid flowing back based on the target bottom-hole pressure and the bottom-hole pressure after fluid flowing back.

9. A pressure-controlled flowback device, characterized in that, including: A memory configured to store instructions; A processor configured to call the instructions from the memory and, when executing the instructions, be capable of implementing the controlled-pressure fluid flowing back method according to any one of claims 1 to 7.

10. A machine-readable storage medium, characterized in that, Instructions are stored on the machine-readable storage medium, and the instructions are used to cause the machine to execute the controlled-pressure fluid flowing back method according to any one of claims 1 to 7.

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