Fracturing effect evaluation method based on flowback water production data

Abstract

The invention discloses a fracturing effect evaluation method based on flowback water production data, and the method comprises the steps: taking the maximum cumulative water yield obtained through calculation of a harmonic decline model as an initial effective fracture volume for calculation in a calculation process, and taking the maximum cumulative water yield as an initial value of an iteration process; calculating to obtain a crack compression coefficient, and obtaining an initial effective crack effective volume coefficient according to the material balance curve graph. In the boundary control stage, the yield normalized pressure and material balance time double logarithmic curve (RNP-tm) is represented as a straight line with the slope being 1; in a rectangular coordinate system, the linear relation between the yield normalization pressure and the material balance time is found, the intercept of a straight line is solved, and therefore the convergent fracture compression coefficient and the effective fracture volume are obtained through iteration. The method is of great significance in evaluating the fracturing effect in the fracturing flowback process and guiding the design of a field flowback scheme.

Description

Technical Field

[0001] The present invention relates to the field of unconventional oil and gas production engineering, and more particularly to a fracturing effect evaluation method based on flowback water production data. Background Art

[0002] During the fracturing and flowback process, microseismic monitoring and post-fracturing evaluation are often used to evaluate the fracturing effect. To better evaluate the fracturing effect, researchers have established mathematical models and numerical simulation models based on pump-off pressure drop curves and fracturing flowback data to effectively evaluate parameters such as the post-fracturing SRV stimulation area, flow stage characteristics, fracture half-length, and fracture permeability. This provides a variety of methods for optimizing post-fracturing flowback plans and evaluating fracturing stimulation effects.

[0003] Generally, a double logarithmic derivative chart is drawn for the entire fracturing flowback process, which mainly includes the well storage effect stage, dual linear flow with limited fracture diversion, unsteady linear flow, elliptical flow or pseudo-radial flow, pseudo-stable flow, composite linear flow, pseudo-radial flow, and boundary-controlled pseudo-stable flow. Studies have shown that in shale and tight sandstone oil and gas reservoirs, the horizontal well multi-stage fracturing flowback process mainly goes through three stages: (1) Early linear flow: The fracturing fluid flows along the main fracture to the wellbore. The fracture permeability is obtained by analyzing the fracturing fluid flowback data in this stage. (2) Pseudo-stable stage: As the fracturing fluid flows back, the fracture is in a state of exhaustion, and the pressure wave in the fracture continues to propagate outward to the intersection boundary between the fracture and the matrix. (3) Linear flow stage: As the fracturing fluid flows back to the wellbore, the formation fluid flows into the fracture, forming a two-phase flow flowback. The fracture half-length and matrix permeability are obtained based on the flowback data in this stage. Summary of the Invention

[0004] In order to overcome the above-mentioned defects of the prior art, the present invention proposes a fracturing effect evaluation method based on flowback water production data. The maximum cumulative water production calculated by the Arps harmonic decline model is used as the initial effective fracture volume and used as the initial value of the iterative process. The fracture compression coefficient is calculated, and the initial effective fracture volume coefficient is obtained based on the material balance curve. In the boundary control stage, the double logarithmic curve of production normalized pressure and material balance time (RNP-t m ) is represented by a straight line with a slope of 1. By finding the linear relationship between production-normalized pressure and material equilibrium time in a rectangular coordinate system and determining the intercept of the line, a convergent fracture compressibility coefficient and effective fracture volume are iteratively derived. This is of great significance for evaluating the fracturing effect of the fracturing flowback process and guiding the design of field flowback plans.

[0005] The technical solutions of the present invention are as follows:

[0006] The present invention proposes a fracturing effect evaluation method based on flowback water production data. The maximum cumulative water production calculated by the Arps harmonic decline model is used as the initial effective fracture volume and the initial value of the iterative process. The fracture compression coefficient is calculated, and the initial effective fracture volume coefficient is obtained based on the material balance curve. In the boundary control stage, the double logarithmic curve of production normalized pressure and material balance time (RNP-t m ) is represented by a straight line with a slope of 1. By finding the linear relationship between production-normalized pressure and material equilibrium time in a rectangular coordinate system and determining the intercept of the line, a convergent fracture compressibility coefficient and effective fracture volume are iteratively derived. This is of great significance for evaluating the fracturing effect of the fracturing flowback process and guiding the design of field flowback plans.

[0007] The present invention provides a method for evaluating fracturing effects based on flowback water production data, which specifically includes the following steps:

[0008] Step 1: Organize the water production data, casing pressure data, reservoir parameters, and fracture parameters during the fracturing flowback phase;

[0009] Step 2: Calculate the maximum cumulative flowback water production based on the harmonic decline curve model, which is used as the initial value of the initial effective fracture volume, and calculate the fracture compression coefficient;

[0010] Step 3: Calculate the material balance time t m The yield normalized pressure RNP, the yield normalized pressure derivative dRNP, and RNP-t are plotted. m Double logarithmic derivative chart, and classification of different flow stage characteristics of fracturing fluid backflow;

[0011] Step 4: Divide the quasi-stable flow stage on the double logarithmic derivative chart, then draw the linear coordinate system RNP-tm, fit a straight line, and calculate the slope of the straight line m;

[0012] Step 5: Draw a semi-logarithmic chart of pressure normalized yield PNR-normalized cumulative water production Wp to obtain the final cumulative flowback volume.

[0013] Furthermore, the above step 2 includes: calculating the maximum cumulative flowback water production according to the harmonic decline curve model as the initial value of the initial effective fracture volume, and calculating the fracture compression coefficient; specifically including:

[0014] Step 2.1 Calculate the maximum cumulative water production based on the harmonic decline model;

[0015] Step 2.2 Calculate the crack compression coefficient.

[0016] Furthermore, in the above step 2, step 2.1 specifically includes:

[0017] During the fracturing process, fracturing fluid is injected into the formation. Therefore, the fluid pressure within the fractures during the initial flowback phase is higher than the original formation pressure, and the fracturing fluid is produced as a single-phase water flow. The water saturation within the fractures during the initial flowback phase is approximately 1. The produced water primarily comes from the volume of the fractures stimulated by the fracturing process. Therefore, the total water production during the flowback phase is approximately equal to the effective pore volume of the fractures at the initial stage of flowback.

[0018] The initial effective fracture volume is calculated by the Arps harmonic decline model. In this model, the daily water production and the cumulative water production are in a semi-logarithmic linear relationship, which can be obtained as

[0019]

[0020] Simplified:

[0021]

[0022] Among them, q w is the water production rate, m 3 / d;q wi is the initial production of fracturing fluid, m 3 / d;W p is the cumulative water production, m 3 ;d i is the initial decline rate of fracturing fluid flowback, 1 / d.

[0023] Furthermore, in the above step 2, step 2.1 specifically includes:

[0024] The fracture compressibility coefficient is defined as the rate of change of unit fracture volume with pressure under isothermal conditions and is an important indicator for evaluating changes in the effective pore volume of a fracture. During the flowback process, the fluid pressure within the fracture drops rapidly. Under the stress of the surrounding rock, the fracture gradually closes, and the fracturing zone decreases. The net pressure acting on the fracture is the difference between the minimum principal stress of the rock and the flow pressure within the fracture:

[0025] p n =σ min -p f (3)

[0026] The minimum principal stress can be replaced by the crack closure pressure, and then equation (3) becomes:

[0027] p n =p c -p wf (4)

[0028] The crack compression coefficient is:

[0029] c f =a(p n ) -b (5)

[0030] When the proppant density is 0, 0.1, 0.2, 0.3, 0.4, and 0.5, a is 0.0238, 0.0261, 0.0264, 0.0274, 0.0456, and 0.053, and b is 0.64, 0.663, 0.683, 0.71, 0.809, and 0.893.

[0031] Among them, σ min is the minimum principal stress, MPa; p n is the net pressure of the crack; p c is the crack closure pressure; a and b are regression fitting coefficients. f is the fluid pressure in the fracture, MPa; p wf is the bottom hole pressure, MPa; c f is the crack compression coefficient, 1 / MPa.

[0032] Furthermore, in the above step 3, the step 3 specifically includes:

[0033] Step 3.1: Based on the material balance method, establish the material balance equation for the water phase in the flowback process;

[0034] Step 3.2: Establish radial flow and linear flow mathematical models, and define the yield normalized pressure, pressure normalized yield, and material balance time.

[0035] The above-mentioned step 3.1 specifically includes:

[0036] During fracturing fluid flowback, the drop in formation pressure causes the fluid volume to expand and the fracture pore volume to contract, generating elastic energy that provides energy for the flowback process. The volume of fracturing fluid returned within the effective fracture volume is the material balance equation for the water phase. The cumulative water production during the flowback phase is equal to the sum of the expansion of the formation fluid and water and the reduction in pore volume caused by the drop in formation pressure. Thus,:

[0037] q w dtB w =-dV EF +dV o +dV w (6)

[0038] B w is the volume coefficient of the water phase under pressure; V EF is the effective pore volume of the fracture, m 3 ; V o is the volume of the oil phase, m 3 ; V w is the volume of the aqueous phase, m 3 .

[0039] According to the definition of isothermal compressibility coefficient of oil, water and rock, we can get:

[0040] dV w =-V w C w dp (7)

[0041] dV o =-V o C o dp (8)

[0042] dV EF =V EF C f dp (9)

[0043] C w 、C o 、C f is the isothermal compressibility coefficient of water, oil phase and rock, 1 / MPa.

[0044] Combining formula (6-9), we can get:

[0045] q w dtB w =-(V EF C f +V o C o +V w C w )dp (10)

[0046] Simplified:

[0047] dp / dt=-q w B w / V EF C t (11)

[0048] in,

[0049] C t =C f +S o C o +S w C w , integrating formula (12) yields:

[0050]

[0051] p i is the original formation pressure, MPa; is the average formation pressure, MPa; C t is the comprehensive compression coefficient, 1 / MPa.

[0052] Furthermore, the above step 3.2 specifically includes:

[0053] For each perforation cluster, the horizontal well is assumed to have radial flow within a cylinder, where the cylinder is the length of the perforation cluster and the width of the main fracture network, and single-phase water flow along the main fracture network toward the perforations. Figure 1 As shown in (a), based on the ABBASI model theory, the water phase flows in the fracture and enters the wellbore in a radial flow manner. The water flow returns at a constant production rate and enters the boundary stability stage. The mathematical model of the seepage in the fracture is:

[0054]

[0055] Bottom hole boundary conditions: Crack termination boundary conditions: r is the radial distance, m; φ f is the fracture porosity; μ is the water phase viscosity, MPa·s; K f is the fracture permeability, mD; R e is the crack radius, m; R w is the well diameter, m; p wf is the bottom hole flowing pressure, MPa.

[0056] Substituting the boundary conditions into equation (14) yields:

[0057]

[0058] The average fracture pressure in a circular fracture is:

[0059]

[0060] Substituting into formula (15) and simplifying it, we get:

[0061]

[0062] Where w = V EF / π(R e 2 -R w 2 )(18)

[0063] w is the crack width, m; t is the time, d.

[0064] The model solution is:

[0065]

[0066] Transforming formula (19) yields:

[0067]

[0068] like Figure 1As shown in (b), when the fracture pressure drops below the breakthrough pressure, the fracturing fluid and formation water enter the fracture due to transient linear flow in the matrix. The oil and water then flow through the fracture toward the wellbore. This model assumes that the fracturing water is completely replaced by oil. This flow pattern is a combination of fracture storage and quasi-linear flow.

[0069] When the fracture flow stage is linear flow, the pressure distribution in the boundary control stage is:

[0070]

[0071] Bottom hole boundary conditions:

[0072] Crack termination boundary conditions: x is the length of the crack in the extension direction, m; h is the crack height, m; x f is the half length of the crack, m.

[0073] The model is solved to obtain:

[0074]

[0075] Transforming formula (22) into:

[0076]

[0077] Define the yield normalization pressure: Pressure normalized water production: Material balance time is: RNP is the yield normalized pressure, MPa / (m 3 / d);t m is the material equilibrium time, d.

[0078] Furthermore, the above step 5 specifically includes:

[0079] During the calculation process, the maximum cumulative water production calculated by the harmonic decline model is used as the initial effective fracture volume and the initial value of the iterative process. The fracture compression coefficient is calculated, and the initial effective fracture volume coefficient is obtained based on the material balance curve. In the boundary control stage, the double logarithmic curve of production normalized pressure and material balance time (RNP-t m ) is expressed as a straight line with a slope of 1; by finding the linear relationship between the production-normalized pressure and the material balance time in a rectangular coordinate system, the intercept of the straight line is obtained, and the convergent fracture compression coefficient and effective fracture volume are iteratively obtained.

[0080] The effective crack volume is:

[0081]

[0082] m is the intercept of the line.

[0083] Technical effects and advantages of the present invention:

[0084] The maximum cumulative water production calculated by the Arps harmonic decline model is used as the initial effective fracture volume and the initial value of the iterative process. The fracture compression coefficient is calculated, and the initial effective fracture volume coefficient is obtained based on the material balance curve. In the boundary control stage, the double logarithmic curve of production normalized pressure and material balance time (RNP-t m ) is represented by a straight line with a slope of 1. By finding the linear relationship between production-normalized pressure and material equilibrium time in a rectangular coordinate system and determining the intercept of the line, a convergent fracture compressibility coefficient and effective fracture volume are iteratively derived. This is of great significance for evaluating the fracturing effect of the fracturing flowback process and guiding the design of field flowback plans. BRIEF DESCRIPTION OF THE DRAWINGS

[0085] In order to more clearly illustrate the technical solutions in the embodiments of this article or the prior art, the following briefly introduces the drawings required for use in the embodiments or the description of the prior art. Obviously, the drawings described below are only some embodiments of this article. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying any creative work.

[0086] Figure 1 The figure shows the physical model of water phase seepage during the flowback process;

[0087] Figure 2 The figure shows the maximum cumulative water production calculated based on the Arps harmonic decline model;

[0088] Figure 3 Shown is the double logarithmic derivative of the yield normalized pressure-material balance time;

[0089] Figure 4 The figure shows the quasi-stable characteristic curve;

[0090] Figure 5 Shown is the normalized water production-normalized cumulative water production curve. DETAILED DESCRIPTION

[0091] The following is a clear and complete description of the technical solutions in the embodiments of the present invention. Obviously, the embodiments described are only some embodiments of the present invention, not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without making any creative efforts are within the scope of protection of the present invention.

[0092] To make the objectives, technical solutions, and advantages of the embodiments of the present invention more clear, the technical solutions in the embodiments of the present invention will be clearly and completely described below in conjunction with the accompanying drawings of the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without making creative efforts shall fall within the scope of protection of the present invention.

[0093] This specification provides method operation steps as described in the embodiments or flowcharts, but more or fewer operation steps may be included based on routine or non-creative work. The order of steps listed in the embodiments is only one way of executing the steps among many orderings and does not represent the only execution order. When a system or device product is actually executed, the method can be executed in the order shown in the embodiments or the drawings or in parallel.

[0094] It should be noted that the present invention is a fracturing effect evaluation method based on flowback water production data, which can be used to evaluate the fracturing effect based on flowback data in the field of unconventional oil and gas production engineering.

[0095] The present invention proposes a fracturing effect evaluation method based on flowback water production data. The maximum cumulative water production calculated by the Arps harmonic decline model is used as the initial effective fracture volume and the initial value of the iterative process. The fracture compression coefficient is calculated, and the initial effective fracture volume coefficient is obtained based on the material balance curve. In the boundary control stage, the double logarithmic curve of production normalized pressure and material balance time (RNP-t m ) is represented by a straight line with a slope of 1. By finding the linear relationship between production-normalized pressure and material equilibrium time in a rectangular coordinate system and determining the intercept of the line, a convergent fracture compressibility coefficient and effective fracture volume are iteratively derived. This is of great significance for evaluating the fracturing effect of the fracturing flowback process and guiding the design of field flowback plans.

[0096] Figure 1 The physical model of water phase seepage during the flowback process is established based on the material balance method. Based on the radial flow and linear flow models, a pressure distribution expression is established to solve for the bottomhole flow pressure.

[0097] Step 101 includes: the cumulative water production during the flowback phase is equal to the sum of the expansion of the formation fluid and water and the reduction of the pore volume caused by the drop in formation pressure, then:

[0098] q w dtB w =-dV EF +dV o +dV w (6)

[0099] B w is the volume coefficient of the water phase under pressure; V EF is the effective pore volume of the fracture, m 3 ; V o is the volume of the oil phase, m 3 ; V w is the volume of the aqueous phase, m 3 .

[0100] According to the definition of isothermal compressibility coefficient of oil, water and rock, we can get:

[0101] dV w =-V w C w dp (7)

[0102] dV o =-V o C o dp (8)

[0103] dV EF =V EF C f dp (9)

[0104] C w 、C o 、C f is the isothermal compressibility coefficient of water, oil phase and rock, 1 / MPa.

[0105] Combining formula (6-9), we can get:

[0106] q w dtB w =-(V EF C f +V o C o +V w C w )dp (10)

[0107] Simplified:

[0108] dp / dt=-q w B w / V EF C t (11)

[0109] in,

[0110] C t =C f +S o C o +S w C w , integrating formula (12) yields:

[0111]

[0112] p i is the original formation pressure, MPa; is the average formation pressure, MPa; C t is the comprehensive compression coefficient, 1 / MPa. Step 102 includes: Figure 1 As shown in (a), based on the ABBASI model theory, the water phase flows in the fracture and enters the wellbore in a radial flow manner. The water flow returns at a constant production rate and enters the boundary stability stage. The mathematical model of the seepage in the fracture is:

[0113]

[0114] Bottom hole boundary conditions: Crack termination boundary conditions: r is the radial distance, m; φ f is the fracture porosity; μ is the water phase viscosity, MPa·s; K f is the fracture permeability, mD; R e is the crack radius, m; R w is the well diameter, m; p wf is the bottom hole flowing pressure, MPa.

[0115] Substituting the boundary conditions into equation (14) yields:

[0116]

[0117] The average fracture pressure in a circular fracture is:

[0118]

[0119] Substituting into formula (15) and simplifying it, we get:

[0120]

[0121] Where w = V EF / π(R e 2 -R w 2 )(18)

[0122] w is the crack width, m; t is the time, d.

[0123] The model solution is:

[0124]

[0125] Transforming formula (19) yields:

[0126]

[0127] Step 103 includes: Figure 1 As shown in (b), when the fracture pressure drops below the breakthrough pressure, the fracturing fluid and formation water enter the fracture due to transient linear flow in the matrix. Oil and water then flow through the fracture toward the wellbore. This model assumes that the fracturing water is completely replaced by oil. This flow regime is a combination of fracture storage and quasi-linear flow.

[0128] When the fracture flow stage is linear flow, the pressure distribution in the boundary control stage is:

[0129]

[0130] Bottom hole boundary conditions: Crack termination boundary conditions: x is the length of the crack in the extension direction, m; h is the crack height, m; x f is the half length of the crack, m.

[0131] The model is solved to obtain:

[0132]

[0133] Transforming formula (22) into:

[0134]

[0135] Figure 2 The figure shows the maximum cumulative water production calculated based on the Arps harmonic decline model. During the fracturing process, fracturing fluid is injected into the formation. Therefore, the fluid pressure within the fractures during the initial flowback phase is higher than the original formation pressure, and the fracturing fluid produces a single-phase flow. The water saturation within the fractures during the initial flowback phase is approximately 1, and the produced water primarily comes from the fracture stimulation volume. Therefore, the total water production during the flowback phase is approximately equal to the effective pore volume of the fracture at the initial flowback phase.

[0136] Step 201 includes: calculating the initial effective fracture volume by using the Arps harmonic decline model, in which the daily water production and the cumulative water production are in a semi-logarithmic linear relationship, and the following can be obtained:

[0137]

[0138] Simplified:

[0139]

[0140] Among them, q w is the water production rate, m 3 / d;q wi is the initial production of fracturing fluid, m 3 / d;W p is the cumulative water production, m 3 ;di is the initial decline rate of fracturing fluid flowback, 1 / d.

[0141] The maximum cumulative water production during flowback is calculated to be 28691.721m 3 .

[0142] Step 202 includes: During the flowback process, the fluid pressure in the fracture drops rapidly. Under the stress of the surrounding rock, the fracture gradually closes and the fracturing area decreases. The net pressure acting on the fracture is the difference between the minimum principal stress of the rock and the flow pressure in the fracture:

[0143] p n =σ min -p f (3)

[0144] The minimum principal stress can be replaced by the crack closure pressure, and then equation (3) becomes:

[0145] p n =p c -p wf (4)

[0146] The crack compression coefficient is:

[0147] c f =a(p n ) -b (5)

[0148] When the proppant density is 0, 0.1, 0.2, 0.3, 0.4, and 0.5, a is 0.0238, 0.0261, 0.0264, 0.0274, 0.0456, and 0.053, and b is 0.64, 0.663, 0.683, 0.71, 0.809, and 0.893.

[0149] Among them, σ min is the minimum principal stress, MPa; p n is the net pressure of the crack; p c is the crack closure pressure; a and b are regression fitting coefficients. f is the fluid pressure in the fracture, MPa; p wf is the bottom hole pressure, MPa; c f is the crack compression coefficient, 1 / MPa.

[0150] The calculated crack compression coefficient is 0.0136601.

[0151] Figure 3The chart shows a double logarithmic derivative of yield normalized pressure versus material balance time. This chart is constructed by calculating yield normalized pressure, yield normalized pressure derivative, and material balance time. The chart shows characteristic curves for radial flow, linear flow, and quasi-steady flow.

[0152] Step 301 specifically includes:

[0153] Define the yield normalization pressure: Pressure normalized water production: Material balance time is: RNP is the yield normalized pressure, MPa / (m 3 / d);t m is the material equilibrium time, d.

[0154] Figure 4 The following is a quasi-stable characteristic curve. Figure 3 The flow characteristics of the pseudo-steady flow curve in the double logarithmic plate are established by establishing a linear relationship between material balance time and output normalized pressure in a rectangular coordinate system. The slope of the line is calculated and recorded as m. m is the intercept of the line.

[0155] Figure 5 The figure shows the normalized water production-normalized cumulative water production curve. During the calculation process, the maximum cumulative water production calculated by the harmonic decline model is used as the initial effective fracture volume and the initial value of the iterative process. The fracture compression coefficient is calculated, and the initial effective fracture volume coefficient is obtained based on the material balance curve. In the boundary control stage, the double logarithmic curve of production normalized pressure and material balance time (RNP-t m ) is expressed as a straight line with a slope of 1; by finding the linear relationship between the production-normalized pressure and the material balance time in a rectangular coordinate system, the intercept of the straight line is obtained, and the convergent fracture compression coefficient and effective fracture volume are iteratively obtained.

[0156] Step 501 is:

[0157] The effective crack volume is:

[0158]

[0159] The calculated effective fracture pore volume is 24510.7327m 3 The error between the maximum cumulative water production calculated during flowback and the result is 17.06%.

[0160] The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the present invention should be included in the scope of protection of the present invention.

Claims

1. A fracturing effect evaluation method based on flowback water production data, characterized in that: The following steps are involved: Step 1: Obtain water production data, casing pressure data, reservoir parameters, and fracture parameters during the fracturing flowback phase; Step 2: Calculate the maximum cumulative flowback water production based on the harmonic decline curve model, which is used as the initial value of the initial effective fracture volume, and calculate the fracture compression coefficient; Step 3: Calculate the production normalized pressure RNP and the production normalized pressure derivative dRNP at the material balance time tm, draw a double logarithmic derivative chart of RNP-tm, and divide the characteristics of different flow stages of the fracturing fluid backflow; Step 4: Divide the quasi-stable flow stage on the double logarithmic derivative chart, then draw the linear coordinate system RNP-tm, fit a straight line, and calculate the slope of the straight line m; Step 5: Draw a semi-logarithmic chart of pressure normalized yield PNR-normalized cumulative water production Wp to obtain the final cumulative flowback volume.

2. A fracturing effect evaluation method based on flowback water production data according to claim 1, characterized in that: The step 2 includes: Step 2.1: Calculate the maximum cumulative water production based on the harmonic decline model as the initial value of the initial effective fracture volume; Step 2.2 calculates the fracture compressibility coefficient, which is used in the radial flow and linear flow seepage backflow models of the water phase.

3. The fracturing effect evaluation method based on flowback water production data according to claim 2, characterized in that: The step 2.1 includes: The initial effective fracture volume is calculated by the Arps harmonic decline model. In this model, the daily water production and the cumulative water production are in a semi-logarithmic linear relationship, which can be obtained as Simplified: Among them, q w is the water production rate, m 3 / d;q wi is the initial production of fracturing fluid, m 3 / d;W p is the cumulative water production, m 3 ;d i is the initial decline rate of fracturing fluid flowback, 1 / d.

4. The fracturing effect evaluation method based on flowback water production data according to claim 2, characterized in that: The step 2.2 includes: During the flowback process, the fluid pressure in the fracture drops rapidly. Under the stress of the surrounding rock, the fracture gradually closes and the fracturing area decreases. The net pressure acting on the fracture is the difference between the minimum principal stress of the rock and the flow pressure in the fracture: p n =σ min -p f (3) The minimum principal stress can be replaced by the crack closure pressure, and then equation (3) becomes: p n =p c -p wf (4) The crack compression coefficient is: c f =a(p n ) -b (5) Among them, σ min is the minimum principal stress, MPa; p n is the net pressure of the crack; p c is the crack closure pressure; a and b are regression fitting coefficients; p f is the fluid pressure in the fracture, MPa; p wf is the bottom hole pressure, MPa; c f is the crack compression coefficient, 1 / MPa.

5. The fracturing effect evaluation method based on flowback water production data according to claim 1, characterized in that: The step 3 includes: Step 3.1: Based on the material balance method, establish the material balance equation for the water phase in the flowback process; Step 3.2: Establish radial flow and linear flow mathematical models, and define the yield normalized pressure, pressure normalized yield, and material balance time.

6. A fracturing effect evaluation method based on flowback water production data according to claim 5, characterized in that: The step 3.1 specifically includes: The cumulative water production during the flowback phase is equal to the sum of the expansion of formation fluid and water and the reduction of pore volume caused by the drop in formation pressure, so: q w dtB w =-dV EF +dV o +dV w (6) B w is the volume coefficient of the water phase under pressure; V EF is the effective pore volume of the fracture, m 3 ; V o is the volume of the oil phase, m 3 ; V w is the volume of the aqueous phase, m 3 ; According to the definition of isothermal compressibility coefficient of oil, water and rock, we can get: dV w =-V w C w dp (7) dV o =-V o C o dp (8) dV EF =V EF C f dp (9) C w 、C o 、C f is the isothermal compressibility of water, oil phase, and rock, 1 / MPa; Combining formula (6-9), we can get: q w dtB w =-(V EF C f +V o C o +V w C w )dp (10) Simplified: dp / dt=-q w B w / V EF C t (11) in, C t =C f +S o C o +S w C w , integrating formula (12) yields: p i is the original formation pressure, MPa; is the average formation pressure, MPa; C t is the comprehensive compression coefficient, 1 / MPa.

7. The method for evaluating fracturing effect based on flowback water production data according to claim 5, characterized in that: The step 3.2 specifically includes: Based on the ABBASI model theory, water flows in the fracture and enters the wellbore in a radial flow manner. When the water flow rate is constant and the boundary stability stage is reached, the mathematical model of the seepage in the fracture is: Bottom hole boundary conditions: Crack termination boundary conditions: r is the radial distance, m; φ f is the fracture porosity; μ is the water phase viscosity, MPa·s; K f is the fracture permeability, mD; R e is the crack radius, m; R w is the well diameter, m; p wf is the bottom hole flowing pressure, MPa; Substituting the boundary conditions into equation (14) yields: The average fracture pressure in a circular fracture is: Substituting into formula (15) and simplifying it, we get: where, w = V EF / π(R e 2 -R w 2 )(18) w is the crack width, m; t is the time, d; The model solution is: Transforming formula (19) yields: When the fracture flow stage is linear flow, the pressure distribution in the boundary control stage is: Bottom hole boundary conditions: Crack termination boundary conditions: x is the length of the crack in the extension direction, m; h is the crack height, m; x f is the half length of the crack, m; The model is solved to obtain: Transforming formula (22) into: Define the yield normalization pressure: Pressure normalized water production: Material balance time is: RNP is the yield normalized pressure, MPa / (m 3 / d);t m is the material equilibrium time, d.

8. The method for evaluating fracturing effect based on flowback water production data according to claim 1, characterized in that: The step 5 specifically includes: During the calculation process, the maximum cumulative water production calculated by the harmonic decline model is used as the initial effective fracture volume and the initial value of the iterative process. The fracture compression coefficient is calculated, and the initial effective fracture volume coefficient is obtained according to the material balance curve. In the boundary control stage, the double logarithmic curve of production normalized pressure and material balance time (RNP-t m ) is represented by a straight line with a slope of 1; by finding the linear relationship between production-normalized pressure and material balance time in a rectangular coordinate system and obtaining the intercept of the straight line, the convergent fracture compressibility coefficient and effective fracture volume are iteratively obtained; The effective crack volume is: m is the intercept of the line.

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