Horizontal well soaking drainage numerical simulation method considering chemical osmotic pressure

Abstract

The invention discloses a horizontal well soaking drainage numerical simulation method considering chemical osmotic pressure, and belongs to the technical field of unconventional oil-gas exploration and development, and the method comprises the following steps: step 1, based on dual factors of capillary force and chemical osmotic pressure, establishing a spontaneous imbibition driving force curve formula; 2, based on the fracturing fluid spontaneous imbibition mathematical model considering the chemical osmotic pressure, setting the membrane efficiency E as 0 to obtain a first model; replacing the capillary force pc between the oil phase and the water phase in the first model with the spontaneous imbibition driving force pc + pi to obtain a second model; step 3, determining parameter values; step 4, establishing a neglect chemical osmotic pressure model by using Eclipse software; 5, determining values of a driving force constant pm, a curve fitting index n and a correction constant c, and drawing a spontaneous imbibition driving force curve; and step 6, establishing a horizontal well soaking drainage numerical simulation model based on the spontaneous imbibition driving force curve by utilizing Eclipse software. According to the method, the accuracy of horizontal well soaking drainage numerical simulation is improved.

Description

Technical Field

[0001] The present invention belongs to the technical field of unconventional oil and gas exploration and development, and particularly relates to a horizontal well shut-in and drainage numerical simulation method considering chemical osmotic pressure. Background Art

[0002] Shale oil and gas, tight oil and gas, and coalbed methane are unconventional oil and gas resources that typically lack natural, stable industrial production capacity. Horizontal wells combined with hydraulic fracturing are needed to increase individual well productivity. After hydraulic fracturing, spontaneous imbibition of fracturing fluid during the well shut-in and production process can help increase individual well productivity. Capillary forces are generally considered the primary driving force behind this spontaneous imbibition. However, in the unconventional oil and gas sector, chemical osmotic pressure, in addition to capillary forces, also plays a significant role in this process.

[0003] Currently, the commonly used method for evaluating the effect of horizontal well shut-in and drainage is mainly numerical simulation, which can be specifically divided into two types: self-compiled simulators and commercial simulators (such as Eclipse and CMG software). The self-compiled simulator method can consider more mechanisms and has strong autonomy, but the model is prone to non-convergence problems, is difficult to use, and is difficult to promote and use on a large scale. Commercial simulator simulation is a more commonly used numerical simulation method with more mature technology and is more popular in enterprises and research institutes. However, when Eclipse software is currently simulating, the capillary force curve is added to the matrix area, that is, the simulation only considers the capillary force, and does not consider the effect of chemical osmotic pressure on the spontaneous imbibition of the fracturing fluid, which in turn affects the accuracy of the simulation of the shut-in and drainage process.

[0004] Based on this, this application aims to make up for the defect that the chemical osmotic pressure is not taken into account in the numerical simulation of horizontal well shut-in and production using the Eclipse software. First, a formula for the spontaneous imbibition driving force curve is proposed. Then, the spontaneous imbibition driving force curve considering the dual factors of capillary force and chemical osmotic pressure is drawn using the mathematical model of spontaneous imbibition of fracturing fluid considering the chemical osmotic pressure and the spontaneous imbibition numerical simulation model established by the Eclipse software that ignores the chemical osmotic pressure. Based on the spontaneous imbibition driving force curve, a numerical simulation model for horizontal well shut-in and production is established using the Eclipse software, which can effectively improve the accuracy of the numerical simulation of horizontal well shut-in and production. Summary of the Invention

[0005] The purpose of the present invention is to overcome the above-mentioned deficiencies of the prior art and to provide a numerical simulation method for horizontal well shut-in and drainage taking into account chemical osmotic pressure.

[0006] To achieve the above object, the present invention adopts the following technical solutions:

[0007] The numerical simulation method for horizontal well soaking and drainage considering chemical osmotic pressure includes the following steps:

[0008] Step 1: Based on the dual factors of capillary force and chemical osmotic pressure, a formula for the spontaneous imbibition driving force curve is established;

[0009]

[0010] Where p c+π is the driving force of spontaneous imbibition; p m is the driving force constant; n is the curve fitting exponent; c is the correction constant; S w is water saturation; S wc is the bound water saturation; S or is the residual oil saturation;

[0011] Step 2: Based on the mathematical model of spontaneous imbibition of fracturing fluid taking into account chemical osmotic pressure, the membrane efficiency E is set to 0 to obtain Model 1. The capillary force curve is used in Model 1, and the formula is:

[0012]

[0013] Where p c is the capillary force; p mc is the maximum capillary force; n c is the capillary force curve fitting index;

[0014] The spontaneous imbibition driving force p c+π Instead of the capillary force p between the oil and water phases in model 1 c , get model 2;

[0015] Step 3, determining the values ​​of the spontaneous imbibition numerical simulation parameters in the mathematical model of spontaneous imbibition of the fracturing fluid taking into account the chemical osmotic pressure;

[0016] Step 4, using Eclipse software to establish a spontaneous imbibition numerical simulation model ignoring chemical osmotic pressure, as Model I;

[0017] Step 5: Determine the driving force constant p based on the spontaneous imbibition mathematical model of fracturing fluid considering chemical osmotic pressure, model 2, and model 1. m , the curve fitting index n, the correction constant c, and the spontaneous imbibition driving force curve are drawn;

[0018] Step 6: Using Eclipse software, a horizontal well shut-in and drainage numerical simulation model is established based on the spontaneous imbibition driving force curve, and a horizontal well shut-in and drainage numerical simulation is performed considering chemical osmotic pressure.

[0019] Preferably, step 4 includes the following sub-steps:

[0020] Step 41: Based on the values ​​of the parameters in step 3, set the total number of grids n in the Case Definition window; set the rock length L, rock cross-sectional area A, porosity φ, rock permeability k in the Grid window; and enter the oil phase viscosity μ in the PVT window. o , aqueous phase viscosity μ w ;

[0021] Step 42, in the Regions window, perform crack and matrix partitioning on the model;

[0022] Step 43, based on the values ​​of the parameters in step 3, draw a water phase relative permeability curve according to the water phase relative permeability curve formula, draw an oil phase relative permeability curve according to the oil phase relative permeability curve formula, and draw a capillary force curve according to the capillary force curve formula (2);

[0023] The formula of water phase relative permeability curve is as follows:

[0024]

[0025] Where k rw is the relative permeability of the water phase; k rw (S or ) is the relative permeability of water phase at residual oil saturation; n w is the fitting index of the water phase relative permeability curve;

[0026] The formula of oil phase relative permeability curve is as follows:

[0027]

[0028] Where k ro is the relative permeability of the oil phase; k ro (S wc ) is the relative permeability of the oil phase at irreducible water saturation; n o is the fitting index of oil phase relative permeability curve;

[0029] Step 44, adding a water phase relative permeability curve, an oil phase relative permeability curve, and a capillary force curve to the matrix region in the SCAL window;

[0030] Step 45: Set the initial oil phase pressure p in the rock in the Initialization window. 0 , and use non-equilibrium initialization to input the initial water saturation of the fracture area, the initial water saturation of the fracture is 1, and input the initial water saturation of the matrix area, the initial water saturation of the matrix is ​​S wc ;

[0031] Step 46: Set the time step Δt and total simulation time t in the Schedule window.max ;

[0032] Get Model I.

[0033] Preferably, step 5 includes the following sub-steps:

[0034] Step 51, determining numerical simulation parameters of model 2 based on numerical simulation parameters of spontaneous imbibition in a mathematical model of spontaneous imbibition of fracturing fluid taking into account chemical osmotic pressure;

[0035] The maximum capillary force p in the spontaneous imbibition numerical simulation parameters mc Replaced by the driving force constant p m , capillary force curve fitting index n c Replace it with the curve fitting exponent n, and then add the correction constant c to form the model two numerical simulation parameters;

[0036] Step 52, based on the values ​​of the parameters determined in step 3, solving and calculating the mathematical model of spontaneous imbibition of the fracturing fluid taking into account the chemical osmotic pressure to obtain a calculation result 1;

[0037] Step 53, set j = 1, g = 0, h = 1;

[0038] Step 54: the driving force constant p m , the curve fitting index n, and the correction constant c are assigned for the jth time, and the values ​​of the remaining parameters in the numerical simulation parameters of model 2 are consistent with the values ​​of the corresponding parameters in the numerical simulation parameters of spontaneous imbibition, and the jth values ​​of the numerical simulation parameters of model 2 are obtained;

[0039] Step 55, performing a calculation on the model 2 according to the j-th value of the numerical simulation parameter of the model 2 to obtain the j-th calculation result 2;

[0040] Step 56, comparing the j-th calculation result 2 with the corresponding item in the calculation result 1;

[0041] When the difference between the corresponding terms is within the error range, let g = g + 1, based on the driving force constant p m , the jth assignment of the curve fitting index n and the correction constant c, and the gth spontaneous imbibition driving force fitting curve is obtained, and then the process proceeds to step 57;

[0042] Otherwise, adjust the driving force constant p m , the curve fitting index n, the value of the correction constant c, set j = j + 1, and then go to step 54;

[0043] Step 57, replacing the capillary force curve in Model I with the g-th spontaneous imbibition driving force fitting curve to obtain Model II, and obtaining the h-th calculation result three through Model II;

[0044] Step 58, comparing the hth calculation result three with the corresponding item in the calculation result one;

[0045] When the maximum difference of the corresponding items is within the error range, the g-th spontaneous imbibition driving force fitting curve is taken as the spontaneous imbibition driving force curve;

[0046] Otherwise, adjust the driving force constant p m , the curve fitting index n, the value of the correction constant c, let j = j + 1, h = h + 1, and then go to step 54.

[0047] Preferably, the driving force constant p m , curve fitting index n, correction constant c for the first assignment, driving force constant p m The value of is the maximum capillary force p in step 3 mc The value of the curve fitting index n is the capillary force curve fitting index n in step 3. c The value of the correction constant c is the difference in actual osmotic pressure inside and outside the rock P π , calculated by formula (5)

[0048] P π =EαRT(C 0 -C w ) (5)

[0049] Where, P π is the difference in actual osmotic pressure between the inside and outside of the rock; E is the membrane efficiency; α is the dissociation coefficient; R is the ideal gas constant; T is the absolute temperature; C 0 is the initial salt concentration of the solution inside the rock; C w is the salt concentration of the solution outside the rock, P π ,E,α,R,T,C 0 、C w The value of is consistent with the value of the corresponding parameter in step 3.

[0050] Preferably, the driving force constant p m , curve fitting index n, correction constant c for the jth (j ≥ 2) assignment, driving force constant p m The increase in the j-th assignment compared to the j-1-th assignment is no more than the driving force constant p m The j-1th assignment is 3%, the j-th assignment of the curve fitting index n is reduced by no more than 3% of the j-1th assignment of the curve fitting index n compared to the j-1th assignment, and the j-th assignment of the correction constant c is reduced by no more than 50% of the j-1th assignment of the correction constant c compared to the j-1th assignment.

[0051] Preferably, step 6 includes the following sub-steps:

[0052] Step 61, selecting research subjects;

[0053] Half of a cluster of hydraulic fractures in a horizontal well and its nearby matrix were selected as the research objects for numerical simulation.

[0054] Step 62, determining the parameters of the numerical simulation model for well shut-in and drainage production, wherein the parameters of the numerical simulation model for well shut-in and drainage production include the number of grids, model length, model width, formation thickness, fracture half-length, cluster spacing, crude oil density, original formation pressure, bottom hole flowing pressure, matrix porosity, matrix permeability, fracture conductivity, injection fluid volume, well shut-in time, and model simulation time;

[0055] Step 63: Based on the spontaneous imbibition numerical simulation parameter values ​​obtained in step 3 and the soaking well drainage numerical simulation model parameter values ​​obtained in step 62, the research object is modeled using Eclipse software to form a horizontal well soaking well drainage numerical simulation model, specifically:

[0056] In the Case Definition window, set the number of grids and perform grid division;

[0057] In the Grid window, set the model length, model width, formation thickness, fracture half-length, and cluster spacing to define the model size;

[0058] In the Grid window, set the matrix porosity, matrix permeability, and fracture conductivity and assign attributes;

[0059] Set the oil phase viscosity μ in the PVT window o , aqueous phase viscosity μ w , crude oil density, defining fluid properties;

[0060] In the Regions window, perform crack and matrix partitioning on the model;

[0061] In the SCAL window, add the water phase relative permeability curve and the oil phase relative permeability curve to the matrix area, and add the spontaneous imbibition driving force curve to the matrix partition;

[0062] In the Initialization window, set the original formation pressure and use non-equilibrium initialization to input the initial water saturation of the fracture area. The initial water saturation of the fracture is 1. Input the initial water saturation of the matrix area. The initial water saturation of the matrix is ​​S. wc ;

[0063] Add a horizontal well in the Schedule window and set the bottom hole pressure, injection fluid volume, soak time, and model simulation time.

[0064] Step 64 , performing calculations in the Run window to perform numerical simulations of horizontal well shut-in and drainage considering chemical osmotic pressure.

[0065] The beneficial effects of the present invention are:

[0066] The present invention aims to address the defect of Eclipse software in performing horizontal well shut-in and drainage numerical simulations that does not consider chemical osmotic pressure. First, a formula for the spontaneous imbibition driving force curve is proposed. Then, a mathematical model for spontaneous imbibition of fracturing fluid that considers chemical osmotic pressure and a numerical simulation model for spontaneous imbibition established with Eclipse software that ignores chemical osmotic pressure are used to draw a spontaneous imbibition driving force curve that considers both capillary force and chemical osmotic pressure. Based on the spontaneous imbibition driving force curve, a numerical simulation model for horizontal well shut-in and drainage is established using Eclipse software, effectively improving the accuracy of numerical simulations for horizontal well shut-in and drainage. Targeting the field of unconventional oil and gas development, this method can effectively evaluate the shut-in and drainage effects of horizontal wells and study the impact of shut-in time on cumulative production. The method also has the advantages of good convergence and ease of promotion. BRIEF DESCRIPTION OF THE DRAWINGS

[0067] The drawings in the specification, which constitute a part of this application, are used to provide further understanding of this application. The illustrative embodiments of this application and their descriptions are used to explain this application and do not constitute improper limitations on this application.

[0068] Figure 1 This is a flow chart of a numerical simulation method for horizontal well soaking and drainage considering chemical osmotic pressure according to the present invention;

[0069] Figure 2 1 is a graph showing the relative permeability of the water phase and the relative permeability of the oil phase in the embodiment;

[0070] Figure 3 is a capillary force curve diagram in the embodiment;

[0071] Figure 4 is a schematic diagram of Model 1 in the embodiment;

[0072] Figure 5 It is a comparison chart of the change curves of the imbibition recovery degree over time in the calculation result 1, the final calculation result 2, and the final calculation result 3;

[0073] Figure 6 It is a comparison diagram of the water saturation distribution curve inside the rock of calculation result 1 and final calculation result 2;

[0074] Figure 7 It is a comparison diagram of the spontaneous imbibition driving force curve and the capillary force curve;

[0075] Figure 8 is a schematic diagram of reservoir matrix-fracture;

[0076] Figure 9 This is a numerical simulation model diagram of horizontal well soaking and drainage;

[0077] Figure 10 is the reservoir oil saturation field after hydraulic fracturing;

[0078] Figure 11 It is the production curve during the soaking and drainage production period;

[0079] Figure 12 It is the production curve under different soaking time conditions. DETAILED DESCRIPTION

[0080] It should be noted that the following detailed descriptions are illustrative and intended to provide further explanation of the present application. Unless otherwise specified, all technical and scientific terms used herein have the same meaning as commonly understood by those skilled in the art to which the present application belongs.

[0081] The present invention will be further described below with reference to the accompanying drawings and examples.

[0082] like Figure 1 As shown in the figure, the numerical simulation method for horizontal well soaking and drainage considering chemical osmotic pressure includes the following steps:

[0083] Step 1: Based on the dual factors of capillary force and chemical osmotic pressure, a formula for the spontaneous imbibition driving force curve is established;

[0084]

[0085] Where p c+π is the driving force of spontaneous imbibition; p m is the driving force constant; n is the curve fitting exponent; c is the correction constant; S w is water saturation; S wc is the bound water saturation; S or is the residual oil saturation, which is determined based on experience and is usually in the range of 0.05 to 0.4. In this application, the value is 0.25;

[0086] Step 2: Based on the mathematical model of spontaneous imbibition of fracturing fluid taking into account chemical osmotic pressure, the membrane efficiency E is set to 0 to obtain Model 1. The capillary force curve is used in Model 1, and the formula is:

[0087]

[0088] Where p c is the capillary force; p mc is the maximum capillary force; n c is the capillary force curve fitting index;

[0089] The spontaneous imbibition driving force p c+π Instead of the capillary force p between the oil and water phases in model 1 c , get model 2;

[0090] Specifically, the mathematical model of spontaneous imbibition of fracturing fluid considering chemical osmotic pressure, its specific solution method, spontaneous imbibition numerical simulation parameters and other technical solutions involved in this application have been disclosed in the Chinese patent application entitled "Numerical Simulation Method of Spontaneous Imbibition of Fracturing Fluid Considering Chemical Osmotic Pressure" and application publication number CN119989704A, and will not be repeated here; the solution methods of Model 1 and Model 2 are consistent with those disclosed in CN119989704A;

[0091] Step 3, determining the values ​​of the spontaneous imbibition numerical simulation parameters in the mathematical model of spontaneous imbibition of the fracturing fluid taking into account the chemical osmotic pressure;

[0092] Step 4, using Eclipse software to establish a spontaneous imbibition numerical simulation model ignoring chemical osmotic pressure, as Model I;

[0093] Step 5: Determine the driving force constant p based on the spontaneous imbibition mathematical model of fracturing fluid considering chemical osmotic pressure, model 2, and model 1. m , the curve fitting index n, the correction constant c, and the spontaneous imbibition driving force curve are drawn;

[0094] Step 6: Using Eclipse software, a horizontal well shut-in and drainage numerical simulation model is established based on the spontaneous imbibition driving force curve, and a horizontal well shut-in and drainage numerical simulation is performed considering chemical osmotic pressure.

[0095] Preferably, step 4 includes the following sub-steps:

[0096] Step 41: Based on the values ​​of the parameters in step 3, set the total number of grids n in the Case Definition window; set the rock length L, rock cross-sectional area A, porosity φ, rock permeability k in the Grid window; and enter the oil phase viscosity μ in the PVT window. o , aqueous phase viscosity μ w ;

[0097] Step 42, in the Regions window, perform crack and matrix partitioning on the model;

[0098] Step 43, based on the values ​​of the parameters in step 3, draw a water phase relative permeability curve according to the water phase relative permeability curve formula, draw an oil phase relative permeability curve according to the oil phase relative permeability curve formula, and draw a capillary force curve according to the capillary force curve formula (2);

[0099] The formula of water phase relative permeability curve is as follows:

[0100]

[0101] Where k rw is the relative permeability of the water phase; krw (S or ) is the relative permeability of water phase at residual oil saturation; n w is the fitting index of the water phase relative permeability curve;

[0102] The formula of oil phase relative permeability curve is as follows:

[0103]

[0104] Where k ro is the relative permeability of the oil phase; k ro (S wc ) is the relative permeability of the oil phase at irreducible water saturation; n o is the fitting index of oil phase relative permeability curve;

[0105] Step 44, adding a water phase relative permeability curve, an oil phase relative permeability curve, and a capillary force curve to the matrix region in the SCAL window;

[0106] Step 45: Set the initial oil phase pressure p in the rock in the Initialization window. 0 , and use non-equilibrium initialization to input the initial water saturation of the fracture area, the initial water saturation of the fracture is 1, and input the initial water saturation of the matrix area, the initial water saturation of the matrix is ​​S wc ;

[0107] Step 46: Set the time step Δt and total simulation time t in the Schedule window. max ;

[0108] Get Model I.

[0109] Preferably, step 5 includes the following sub-steps:

[0110] Step 51, determining numerical simulation parameters of model 2 based on numerical simulation parameters of spontaneous imbibition in a mathematical model of spontaneous imbibition of fracturing fluid taking into account chemical osmotic pressure;

[0111] The maximum capillary force p in the spontaneous imbibition numerical simulation parameters mc Replaced by the driving force constant p m , capillary force curve fitting index n c Replace it with the curve fitting exponent n, and then add the correction constant c to form the model two numerical simulation parameters;

[0112] Step 52, based on the values ​​of the parameters determined in step 3, solving and calculating the mathematical model of spontaneous imbibition of the fracturing fluid taking into account the chemical osmotic pressure to obtain a calculation result 1;

[0113] Step 53, set j = 1, g = 0, h = 1;

[0114] Step 54: the driving force constant p m , the curve fitting index n, and the correction constant c are assigned for the jth time, and the values ​​of the remaining parameters in the numerical simulation parameters of model 2 are consistent with the values ​​of the corresponding parameters in the numerical simulation parameters of spontaneous imbibition, and the jth values ​​of the numerical simulation parameters of model 2 are obtained;

[0115] Step 55, performing a calculation on the model 2 according to the j-th value of the numerical simulation parameter of the model 2 to obtain the j-th calculation result 2;

[0116] Step 56, comparing the j-th calculation result 2 with the corresponding item in the calculation result 1;

[0117] When the difference between the corresponding terms is within the error range, let g = g + 1, based on the driving force constant p m , the jth assignment of the curve fitting index n and the correction constant c, and the gth spontaneous imbibition driving force fitting curve is obtained, and then the process proceeds to step 57;

[0118] Otherwise, adjust the driving force constant p m , the curve fitting index n, the value of the correction constant c, set j = j + 1, and then go to step 54;

[0119] Step 57, replacing the capillary force curve in Model I with the g-th spontaneous imbibition driving force fitting curve to obtain Model II, and obtaining the h-th calculation result three through Model II;

[0120] Step 58, comparing the hth calculation result three with the corresponding item in the calculation result one;

[0121] When the maximum difference of the corresponding items is within the error range, the g-th spontaneous imbibition driving force fitting curve is taken as the spontaneous imbibition driving force curve;

[0122] Otherwise, adjust the driving force constant p m , the curve fitting index n, the value of the correction constant c, let j = j + 1, h = h + 1, and then go to step 54.

[0123] Preferably, the driving force constant p m , curve fitting index n, correction constant c for the first assignment, driving force constant p m The value of is the maximum capillary force p in step 3 mc The value of the curve fitting index n is the capillary force curve fitting index n in step 3. c The value of the correction constant c is the difference in actual osmotic pressure inside and outside the rock P π , calculated by formula (5)

[0124] P π=EαRT(C 0 -C w ) (5)

[0125] Where, P π is the difference in actual osmotic pressure between the inside and outside of the rock; E is the membrane efficiency; α is the dissociation coefficient; R is the ideal gas constant; T is the absolute temperature; C 0 is the initial salt concentration of the solution inside the rock; C w is the salt concentration of the solution outside the rock, P π ,E,α,R,T,C 0 、C w The value of is consistent with the value of the corresponding parameter in step 3;

[0126] The driving force constant p m , curve fitting index n, correction constant c for the jth (j ≥ 2) assignment, driving force constant p m The increase in the j-th assignment compared to the j-1-th assignment is no more than the driving force constant p m The j-1th assignment is 3%, the j-th assignment of the curve fitting index n is reduced by no more than 3% of the j-1th assignment of the curve fitting index n compared to the j-1th assignment, and the j-th assignment of the correction constant c is reduced by no more than 50% of the j-1th assignment of the correction constant c compared to the j-1th assignment.

[0127] Specifically, calculation result 1 and calculation result 2 are the imbibition production degree data and rock internal water saturation data at different times, and calculation result 3 is the imbibition production degree data at different times.

[0128] In step 46, comparing the j-th calculation result 2 with the corresponding item in the calculation result 1 means:

[0129] When comparing the curves of the change of imbibition production degree over time, the maximum difference refers to the maximum difference between the two curves along the vertical axis; when comparing the curves of the distribution of water saturation inside the rock, the maximum difference refers to the maximum difference between the two curves along the vertical axis.

[0130] Wherein, step 49, comparing the h-th calculation result 3 with the corresponding item in the calculation result 1, refers to comparing the curves of the change of the imbibition recovery degree over time, and the maximum difference refers to the maximum difference between the two curves along the vertical axis direction.

[0131] Preferably, step 6 includes the following sub-steps:

[0132] Step 61, selecting research subjects;

[0133] While achieving refined reservoir characterization, computational speed must be considered. To reduce the number of model grids and computer computing power, half of a cluster of hydraulic fractures in a horizontal well (half-fractures) and the surrounding matrix were selected as the research objects for numerical simulation.

[0134] Step 62, determining the parameters of the numerical simulation model for well shut-in and drainage production, wherein the parameters of the numerical simulation model for well shut-in and drainage production include the number of grids, model length, model width, formation thickness, fracture half-length, cluster spacing, crude oil density, original formation pressure, bottom hole flowing pressure, matrix porosity, matrix permeability, fracture conductivity, injection fluid volume, well shut-in time, and model simulation time;

[0135] Step 63: Based on the spontaneous imbibition numerical simulation parameter values ​​obtained in step 3 and the soaking well drainage numerical simulation model parameter values ​​obtained in step 62, the research object is modeled using Eclipse software to form a horizontal well soaking well drainage numerical simulation model, specifically:

[0136] In the Case Definition window, set the number of grids and perform grid division;

[0137] In the Grid window, set the model length, model width, formation thickness, fracture half-length, and cluster spacing to define the model size;

[0138] In the Grid window, set the matrix porosity, matrix permeability, and fracture conductivity and assign attributes;

[0139] Set the oil phase viscosity μ in the PVT window o , aqueous phase viscosity μ w , crude oil density, defining fluid properties;

[0140] In the Regions window, perform crack and matrix partitioning on the model;

[0141] In the SCAL window, add the water phase relative permeability curve and the oil phase relative permeability curve to the matrix region, and add the spontaneous imbibition driving force curve to the matrix partition; the water phase relative permeability curve and the oil phase relative permeability curve are consistent with those determined in step 43;

[0142] In the Initialization window, set the original formation pressure and use non-equilibrium initialization to input the initial water saturation of the fracture area. The initial water saturation of the fracture is 1. Input the initial water saturation of the matrix area. The initial water saturation of the matrix is ​​S. wc ;

[0143] Add a horizontal well in the Schedule window and set the bottom hole pressure, injection fluid volume, soak time, and model simulation time.

[0144] Step 64 , performing calculations in the Run window to perform numerical simulations of horizontal well shut-in and drainage considering chemical osmotic pressure.

[0145] During the simulation, the hydraulic fracturing process is simulated by setting the injection fluid volume, and the horizontal well shut-in measures are simulated by setting the shut-in time. After the shut-in is completed, the drainage and production process is simulated until the oil well is abandoned.

[0146] Export calculation results in the Result window to display numerical simulation results for horizontal well shut-in and production considering chemical osmotic pressure. These simulation results include, but are not limited to, the distribution of reservoir oil saturation and production curves during shut-in and production periods.

[0147] Based on this, the simulation method can also be used to vary the soaking time, conducting numerical simulations of horizontal well soaking and production under different soaking time conditions. Production curves for these conditions can then be plotted based on the calculated results. This allows for studying the impact of different soaking times on horizontal well production, providing technical support for on-site evaluation of soaking and production effectiveness and optimizing optimal soaking times.

[0148] Example:

[0149] Step 1: Based on the dual factors of capillary force and chemical osmotic pressure, a formula for the spontaneous imbibition driving force curve is established;

[0150]

[0151] Where p c+π is the driving force of spontaneous imbibition; p m is the driving force constant; n is the curve fitting exponent; c is the correction constant; S w is water saturation; S wc is the bound water saturation; S or is the residual oil saturation, which is determined based on experience and is usually in the range of 0.05 to 0.4. In this application, the value is 0.25;

[0152] Step 2: Based on the mathematical model of spontaneous imbibition of fracturing fluid taking into account chemical osmotic pressure, the membrane efficiency E is set to 0 to obtain Model 1. The capillary force curve is used in Model 1, and the formula is:

[0153]

[0154] Where p c is the capillary force; p mc is the maximum capillary force; n c is the capillary force curve fitting index;

[0155] The spontaneous imbibition driving force p c+π Instead of the capillary force p between the oil and water phases in model 1 c, get model 2;

[0156] Specifically, the mathematical model of spontaneous imbibition of fracturing fluid considering chemical osmotic pressure, its specific solution method, spontaneous imbibition numerical simulation parameters and other technical solutions involved in this application have been disclosed in the Chinese patent application entitled "Numerical Simulation Method of Spontaneous Imbibition of Fracturing Fluid Considering Chemical Osmotic Pressure" and application publication number CN119989704A, and will not be repeated here; the solution methods of Model 1 and Model 2 are consistent with those disclosed in CN119989704A;

[0157] Step 3: Determine the values ​​of the numerical simulation parameters of spontaneous imbibition in the mathematical model of spontaneous imbibition of the fracturing fluid taking into account the chemical osmotic pressure, wherein the values ​​of the numerical simulation parameters of spontaneous imbibition are shown in Table 1 below.

[0158] Table 1 Parameters for the numerical simulation of spontaneous imbibition

[0159]

[0160] Step 4, using Eclipse software to establish a spontaneous imbibition numerical simulation model ignoring chemical osmotic pressure as Model I; Step 4 includes the following sub-steps:

[0161] Step 41: Based on the values ​​of the parameters in step 3, set the total number of grids n in the Case Definition window; set the rock length L, rock cross-sectional area A, porosity φ, rock permeability k in the Grid window; and enter the oil phase viscosity μ in the PVT window. o , aqueous phase viscosity μ w ;

[0162] Step 42, in the Regions window, perform crack and matrix partitioning on the model;

[0163] Step 43, based on the values ​​of the various parameters in Table 1, draw a water phase relative permeability curve according to the water phase relative permeability curve formula (3), draw an oil phase relative permeability curve according to the oil phase relative permeability curve formula (4), and draw a capillary force curve according to the capillary force curve formula (2);

[0164] The water phase relative permeability curve and the oil phase relative permeability curve are as follows: Figure 2 As shown, the capillary force curve is Figure 3 As shown;

[0165] Step 44: Add the matrix area in the SCAL window. Figure 2 The water phase relative permeability curve, oil phase relative permeability curve and Figure 3 Capillary force curve;

[0166] Step 45: Set the initial oil phase pressure p in the rock in the Initialization window. 0 , and use non-equilibrium initialization to input the initial water saturation of the fracture area, the initial water saturation of the fracture is 1, and input the initial water saturation of the matrix area, the initial water saturation of the matrix is ​​S wc ;

[0167] Step 46: Set the time step Δt and total simulation time t in the Schedule window. max ;

[0168] Get model I, then perform simulation calculation to get the calculation results of model I, such as Figure 4 shown.

[0169] Step 5: Determine the driving force constant p based on the spontaneous imbibition mathematical model of fracturing fluid considering chemical osmotic pressure, model 2, and model 1. m , the curve fitting index n, the correction constant c, and the spontaneous imbibition driving force curve are drawn;

[0170] According to steps 51 to 58, the driving force constant p m After assigning the curve fitting index n and the correction constant c four times, the curves of the imbibition recovery degree changing with time in the calculation results 1, the final calculation results 2, and the final calculation results 3 are compared. Figure 5 As shown in the figure, the comparison of the rock internal water saturation distribution curves of calculation result 1 and final calculation result 2 is as follows: Figure 6 shown.

[0171] The comparison between the spontaneous imbibition driving force curve and the capillary force curve is as follows: Figure 7 shown.

[0172] Among them, the driving force constant p m The assignment process of the curve fitting index n and the correction constant c is shown in Table 2.

[0173] Table 2 Driving force constant p m , the assignment process of curve fitting index n and correction constant c

[0174] Assignment times j <![CDATA[Driving force constant p m / MPa]]> Curve fitting index n Correction constant c / MPa 1 5.005 2.4 0.487 2 5.1 2.38 0.4 3 5.25 2.33 0.2 4 5.4 2.3 0.1

[0175] Step 6: Using Eclipse software, establish a horizontal well soaking and drainage numerical simulation model based on the spontaneous imbibition driving force curve; Step 6 includes the following sub-steps:

[0176] Step 61, selecting research subjects;

[0177] While achieving refined reservoir characterization, computing speed must be considered. To reduce the number of model grids and computer computing power, half of a cluster of hydraulic fractures in a horizontal well (half-fractures) and the surrounding matrix were selected as research objects for numerical simulation. Figure 8 This is a schematic diagram of the reservoir matrix-fracture. The red area in the figure is the semi-fracture.

[0178] Step 62, determining parameter values ​​of the numerical simulation model for well soaking and production, the parameter values ​​of the numerical simulation model for well soaking and production are shown in Table 3;

[0179] Table 2 Parameters of the numerical simulation model for well soaking and production

[0180] parameter Value Grid quantity 100000 Model length / m 150 Model width / m 9 Layer thickness / m 50 Crack half length / m 90 Cluster spacing / m 9 <![CDATA[Crude oil density / (g·cm -3 )]]> 0.876 Original formation pressure / MPa 50.1 Bottom hole pressure / MPa 35 <![CDATA[Fracture conductivity / (μm 2 ·cm)]]> 3 Matrix porosity / % 5 <![CDATA[Matrix permeability / μm 2 > <![CDATA[3×10 -6 ]]> <![CDATA[Injection volume / m 3 > 45 Steeping time / day 20 Model simulation time / year 2

[0181] Based on step 63, a horizontal well soaking and drainage numerical simulation model is formed. Figure 9 As shown in the figure, the added water phase relative permeability curve and oil phase relative permeability curve are shown in the figure. Figure 2 As shown, the added spontaneous imbibition driving force curve is Figure 7 The spontaneous imbibition driving force curve in the figure is shown. The Run window is used to calculate and perform a numerical simulation of horizontal well shut-in and production considering chemical osmotic pressure. During the simulation, the hydraulic fracturing process is simulated by setting the injection volume, and the horizontal well shut-in measures are simulated by setting the shut-in time. After the shut-in is completed, the production process is simulated until the well is abandoned. According to the calculation results, the oil saturation field of the reservoir after hydraulic fracturing is as follows: Figure 10 As shown in the figure, the production curve during the soaking and drainage production period is as follows: Figure 11 shown.

[0182] On this basis, according to the simulation method of this application, the soaking time in Table 3 can also be changed to carry out numerical simulation of horizontal well soaking production under different soaking time conditions, and the production curve under different soaking time conditions can be drawn according to the calculation results, as shown in FIG. Figure 12 The effects of different soaking times on horizontal well production were then studied to provide technical support for on-site evaluation of soaking and production effects and optimization of reasonable soaking time.

[0183] Although the above describes the specific embodiments of the present invention in conjunction with the accompanying drawings, it is not a limitation of the present invention. Those skilled in the art should understand that various modifications or variations that can be made by those skilled in the art on the basis of the technical solution of the present invention without any creative work are still within the scope of protection of the present invention.

Claims

1. A numerical simulation method for horizontal well soaking and drainage considering chemical osmotic pressure, characterized by: The following steps are involved: Step 1: Based on the dual factors of capillary force and chemical osmotic pressure, a formula for the spontaneous imbibition driving force curve is established; Where p c+π is the driving force of spontaneous imbibition; p m is the driving force constant; n is the curve fitting exponent; c is the correction constant; S w is water saturation; S wc is the bound water saturation; S or is the residual oil saturation; Step 2: Based on the mathematical model of spontaneous imbibition of fracturing fluid taking into account chemical osmotic pressure, the membrane efficiency E is set to 0 to obtain Model 1. The capillary force curve is used in Model 1, and the formula is: Where p c is the capillary force; p mc is the maximum capillary force; n c is the capillary force curve fitting index; The spontaneous imbibition driving force p c+π Instead of the capillary force p between the oil and water phases in model 1 c , get model 2; Step 3, determining the values ​​of the spontaneous imbibition numerical simulation parameters in the mathematical model of spontaneous imbibition of the fracturing fluid taking into account the chemical osmotic pressure; Step 4, using Eclipse software to establish a spontaneous imbibition numerical simulation model ignoring chemical osmotic pressure, as Model I; Step 5: Determine the driving force constant p based on the spontaneous imbibition mathematical model of fracturing fluid considering chemical osmotic pressure, model 2, and model 1. m , the curve fitting index n, the correction constant c, and the spontaneous imbibition driving force curve are drawn; Step 6: Using Eclipse software, a horizontal well shut-in and drainage numerical simulation model is established based on the spontaneous imbibition driving force curve, and a horizontal well shut-in and drainage numerical simulation is performed considering chemical osmotic pressure.

2. The horizontal well soaking and drainage numerical simulation method considering chemical osmotic pressure according to claim 1 is characterized in that: The step 4 includes the following sub-steps: Step 41: Based on the values ​​of the parameters in step 3, set the total number of grids n in the Case Definition window; set the rock length L, rock cross-sectional area A, porosity φ, rock permeability k in the Grid window; and enter the oil phase viscosity μ in the PVT window. o , aqueous phase viscosity μ w ; Step 42, in the Regions window, perform crack and matrix partitioning on the model; Step 43, based on the values ​​of the parameters in step 3, draw a water phase relative permeability curve according to the water phase relative permeability curve formula, draw an oil phase relative permeability curve according to the oil phase relative permeability curve formula, and draw a capillary force curve according to the capillary force curve formula (2); The formula of water phase relative permeability curve is as follows: Where k rw is the relative permeability of the water phase; k rw (S or ) is the relative permeability of water phase at residual oil saturation; n w is the fitting index of the water phase relative permeability curve; The formula of oil phase relative permeability curve is as follows: Where k ro is the relative permeability of the oil phase; k ro (S wc ) is the relative permeability of the oil phase at irreducible water saturation; n o is the fitting index of oil phase relative permeability curve; Step 44, adding a water phase relative permeability curve, an oil phase relative permeability curve, and a capillary force curve to the matrix region in the SCAL window; Step 45: Set the initial oil phase pressure p in the rock in the Initialization window. 0 , and use non-equilibrium initialization to input the initial water saturation of the fracture area, the initial water saturation of the fracture is 1, and input the initial water saturation of the matrix area, the initial water saturation of the matrix is ​​S wc ; Step 46: Set the time step Δt and total simulation time t in the Schedule window. max ; Get Model I.

3. The horizontal well soaking and drainage numerical simulation method considering chemical osmotic pressure according to claim 2 is characterized in that: The step 5 includes the following sub-steps: Step 51, determining numerical simulation parameters of model 2 based on numerical simulation parameters of spontaneous imbibition in a mathematical model of spontaneous imbibition of fracturing fluid taking into account chemical osmotic pressure; The maximum capillary force p in the spontaneous imbibition numerical simulation parameters mc Replaced by the driving force constant p m , capillary force curve fitting index n c Replace it with the curve fitting exponent n, and then add the correction constant c to form the model two numerical simulation parameters; Step 52, based on the values ​​of the parameters determined in step 3, solving and calculating the mathematical model of spontaneous imbibition of the fracturing fluid taking into account the chemical osmotic pressure to obtain a calculation result 1; Step 53, set j = 1, g = 0, h = 1; Step 54: the driving force constant p m , the curve fitting index n, and the correction constant c are assigned for the jth time, and the values ​​of the remaining parameters in the numerical simulation parameters of model 2 are consistent with the values ​​of the corresponding parameters in the numerical simulation parameters of spontaneous imbibition, and the jth values ​​of the numerical simulation parameters of model 2 are obtained; Step 55, performing a calculation on the model 2 according to the j-th value of the numerical simulation parameter of the model 2 to obtain the j-th calculation result 2; Step 56, comparing the j-th calculation result 2 with the corresponding item in the calculation result 1; When the difference between the corresponding terms is within the error range, let g = g + 1, based on the driving force constant p m , the jth assignment of the curve fitting index n and the correction constant c, and the gth spontaneous imbibition driving force fitting curve is obtained, and then the process proceeds to step 57; Otherwise, adjust the driving force constant p m , the curve fitting index n, the value of the correction constant c, set j = j + 1, and then go to step 54; Step 57, replacing the capillary force curve in Model I with the g-th spontaneous imbibition driving force fitting curve to obtain Model II, and obtaining the h-th calculation result three through Model II; Step 58, comparing the hth calculation result three with the corresponding item in the calculation result one; When the maximum difference of the corresponding items is within the error range, the g-th spontaneous imbibition driving force fitting curve is taken as the spontaneous imbibition driving force curve; Otherwise, adjust the driving force constant p m , the curve fitting index n, the value of the correction constant c, let j = j + 1, h = h + 1, and then go to step 54.

4. The horizontal well soaking and drainage numerical simulation method considering chemical osmotic pressure according to claim 3 is characterized in that: The driving force constant p m , curve fitting index n, correction constant c for the first assignment, driving force constant p m The value of is the maximum capillary force p in step 3 mc The value of the curve fitting index n is the capillary force curve fitting index n in step 3. c The value of the correction constant c is the difference in actual osmotic pressure inside and outside the rock P π , calculated by formula (5) P π =EαRT(C 0 -C w ) (5) Where, P π is the difference in actual osmotic pressure between the inside and outside of the rock; E is the membrane efficiency; α is the dissociation coefficient; R is the ideal gas constant; T is the absolute temperature; C 0 is the initial salt concentration of the solution inside the rock; C w is the salt concentration of the solution outside the rock, P π ,E,α,R,T,C 0 、C w The value of is consistent with the value of the corresponding parameter in step 3.

5. The horizontal well soaking and drainage numerical simulation method considering chemical osmotic pressure according to claim 4 is characterized in that: The driving force constant p m , curve fitting index n, correction constant c for the jth (j ≥ 2) assignment, driving force constant p m The increase in the j-th assignment compared to the j-1-th assignment is no more than the driving force constant p m The j-1th assignment is 3%, the j-th assignment of the curve fitting index n is reduced by no more than 3% of the j-1th assignment of the curve fitting index n compared to the j-1th assignment, and the j-th assignment of the correction constant c is reduced by no more than 50% of the j-1th assignment of the correction constant c compared to the j-1th assignment.

6. The horizontal well soaking and drainage numerical simulation method considering chemical osmotic pressure according to claim 3 is characterized in that: The step 6 includes the following sub-steps: Step 61, selecting research subjects; Half of a cluster of hydraulic fractures in a horizontal well and its nearby matrix were selected as the research objects for numerical simulation. Step 62, determining the parameters of the numerical simulation model for well shut-in and drainage production, wherein the parameters of the numerical simulation model for well shut-in and drainage production include the number of grids, model length, model width, formation thickness, fracture half-length, cluster spacing, crude oil density, original formation pressure, bottom hole flowing pressure, matrix porosity, matrix permeability, fracture conductivity, injection fluid volume, well shut-in time, and model simulation time; Step 63: Based on the spontaneous imbibition numerical simulation parameter values ​​obtained in step 3 and the soaking well drainage numerical simulation model parameter values ​​obtained in step 62, the research object is modeled using Eclipse software to form a horizontal well soaking well drainage numerical simulation model, specifically: In the Case Definition window, set the number of grids and perform grid division; In the Grid window, set the model length, model width, formation thickness, fracture half-length, and cluster spacing to define the model size; In the Grid window, set the matrix porosity, matrix permeability, and fracture conductivity and assign attributes; Set the oil phase viscosity μ in the PVT window o , aqueous phase viscosity μ w , crude oil density, defining fluid properties; In the Regions window, perform crack and matrix partitioning on the model; In the SCAL window, add the water phase relative permeability curve and the oil phase relative permeability curve to the matrix area, and add the spontaneous imbibition driving force curve to the matrix partition; In the Initialization window, set the original formation pressure and use non-equilibrium initialization to input the initial water saturation of the fracture area. The initial water saturation of the fracture is 1. Input the initial water saturation of the matrix area. The initial water saturation of the matrix is ​​S. wc ; Add a horizontal well in the Schedule window and set the bottom hole pressure, injection fluid volume, soak time, and model simulation time. Step 64 , performing calculations in the Run window to perform numerical simulations of horizontal well shut-in and drainage considering chemical osmotic pressure.

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