A method for optimizing well shut-in time by coupling shale hydration expansion and fracturing

Abstract

The present invention discloses a method for optimizing the soaking time of coupled shale hydration expansion and fracturing, including: drawing soaking time-rock tensile strength and soaking time-rock cohesion curves; calculating the length of hydraulic fractures and the width at different positions in the fractures, the pressure in the fractures, and the filtration loss; calculating the pressure distribution, water saturation distribution, and porosity distribution of the reservoir matrix and micro-fractures considering the shale hydration expansion and hydration fracturing; repeating the steps until the calculation time reaches the soaking end time, and then terminating the cyclic calculation; calculating the fracturing transformation volume under different soaking times, and drawing the soaking time-transformation volume curve. The present invention is used to simulate and calculate the fracturing transformation volume considering the shale hydration expansion and hydration fracturing under different soaking times, determine a reasonable soaking time range for shale gas wells after shale gas well fracturing, provide a basis for the evaluation of the fracturing transformation effect of shale gas wells and the optimization of the soaking system, and overcome the defects and shortcomings of the prior art.

Description

Technical Field

[0001] The invention relates to a method for optimizing well shut-in time by coupling shale hydration expansion and fracturing, and belongs to the field of oil and gas field development. Background Art

[0002] With the vigorous development of shale gas resources, hydraulic fracturing has become an indispensable technical means in shale gas industrial exploitation. Numerous studies and field experience have shown that during the post-fracturing well shut-in process, the fracturing fluid will be lost into the reservoir, and the shale strength will be gradually reduced under the action of water and rock, so that micro-cracks will be cracked and expanded, thereby improving the fracturing transformation effect; but at the same time, a large amount of clay minerals in the shale will hydrate and expand with the fracturing fluid filtrate, which will cause the reservoir porosity and permeability conditions to deteriorate and hinder gas seepage. Therefore, post-fracturing well shut-in is a double-edged sword for improving the productivity of shale gas wells. In order to maximize the beneficial effects of well shut-in, it is crucial to determine a reasonable well shut-in time. If the well shut-in time is too short, the shale hydration and fracturing effect will end too early, and the fracturing transformation volume will be small; while if the well shut-in time is too long, the reservoir porosity and permeability conditions caused by the shale hydration and expansion will be too damaged, which will reduce the productivity of shale gas wells.

[0003] At present, there are many methods to determine the range of shut-in time. Some methods determine the optimal shut-in time by simulating the fracturing-shut-in-production process to obtain the production capacity of shale gas wells under different shut-in times; some methods determine the range of shut-in time based on the clay content of shale and the law of ion diffusion; and some methods propose methods to determine the shut-in time through hydration expansion experiments of different clay minerals and the proportion of viscosity mineral content in shale. However, the above judgment methods do not take into account the invasion of fracturing fluid during fracturing, and the joint effects of hydration expansion and hydration fracturing on reservoir structure during fracturing-shut-in, so the above methods are not perfect. Summary of the invention

[0004] In order to overcome the problems in the prior art, the present invention provides a shut-in time optimization method for coupling shale hydration expansion and fracturing. The method is used to simulate and calculate the fracturing transformation volume considering shale hydration expansion and hydration fracturing under different shut-in times, determine a reasonable shut-in time range for shale gas wells after well fracturing, and provide a basis for evaluating the fracturing transformation effect of shale gas wells and optimizing the shut-in system.

[0005] The technical solution provided by the present invention to solve the above technical problems is: a method for optimizing the well-keeping time by coupling shale hydration expansion and fracturing, comprising the following steps:

[0006] Step S1, selecting a rock sample with cemented natural fractures in the target reservoir to conduct a triaxial rock mechanics experiment, and drawing a soaking time-rock tensile strength and soaking time-rock cohesion curve;

[0007] Step S2, establishing a reservoir grid based on the target well reservoir geological model, and adding initial fracture units;

[0008] Step S3, calculating the length of the hydraulic fracture, the width at different positions in the fracture, the pressure in the fracture, and the filtration loss;

[0009] Step S4, calculating the pressure distribution, water saturation distribution and porosity distribution of the reservoir matrix and micro-cracks taking into account the hydration expansion and hydration fracturing of shale;

[0010] Step S5, repeating steps S3-S4 until the calculation time reaches the end time of soaking, ending the cycle calculation, and then proceeding to the next step;

[0011] Step S6, calculating the fracturing stimulation volume under different shut-in times, and drawing a shut-in time-stimulation volume curve.

[0012] A further technical solution is that the specific process of step S1 is: cleaning and drying the rock sample; soaking the rock sample in fracturing fluid degelling liquid for 0 days, 3 days, 5 days, 10 days, 15 days and 20 days respectively; wrapping the rock sample with a latex protective sleeve; placing the rock sample in a pressure chamber for a triaxial rock compression test; and then fitting the experimental data with the formula to draw immersion time-rock tensile strength and immersion time-rock cohesion curves.

[0013] A further technical solution is that the formula in step S1 is:

[0014] σ=Alnt s +B

[0015] τ=Clnt s +D

[0016] Where: t s is the experimental time, d; A, B, C, D are the fitting parameters of the formula; σ is the tensile strength of the experimental rock sample, MPa; τ is the cohesive force of the experimental rock sample, MPa.

[0017] A further technical solution is that the specific process of step S2 is: according to the target reservoir, a structured grid of the target reservoir is established in a rectangular coordinate system, and the number of grids is n i ×n j In the reservoir grid, initial fracture units are added at the grid positions corresponding to the fracturing operation, and the initial units of each cluster of fractures pass through three reservoir grids along the direction of fracture initiation and propagation.

[0018] A further technical solution is that the specific calculation process of step S3 is:

[0019] Step S31: Based on the established reservoir model, numerically solve the fracture extension model considering fracturing fluid loss to obtain the width of each fracture unit at time t1. Filtration at each fracture unit The corresponding relationship between the hydraulic fracture width and the pressure inside the fracture can be used to obtain the pressure at each fracture unit at time t1:

[0020] Step S32, calculating the stress intensity factor of each crack tip at time t1 according to the pressure at each crack unit and the total number of crack units in each crack;

[0021]

[0022] In the formula, is the stress intensity factor at the tip of the e-th crack at time t1, MPa·m 1 / 2 ; is the pressure of the e-th crack tip unit at time t1, MPa; is the total number of elements of the e-th crack at time t1;

[0023] Step S33: Based on the stress intensity factor of each crack tip The fracture toughness K of shale IC Determine the expansion of each crack;

[0024] when When t1, the crack at time t1 does not expand and the crack length remains unchanged; When the crack at time t1 expands, the crack length increases, the total number of units of this crack increases by 1, the width of the new crack unit at time t1 is 0m, and the filtration loss at the new crack unit is 0m 3 / s, and calculate the pressure of the new fracture unit.

[0025] A further technical solution is that the fracture propagation model considering fracturing fluid loss in step S31 includes:

[0026]

[0027]

[0028]

[0029] Where: μ w is the viscosity of the fracturing fluid, mPa·s; w F is the hydraulic fracture width, m; P F is the hydraulic fracture pressure, MPa; Q is the pumping rate of the fracturing operation, m 3 / s; c is the number of fracturing clusters; x F is the crack unit length, m; h F is the height of hydraulic fracture, m; δ F is the Dirac function of the injection point source of the fracturing fluid, which takes 1 when the fracture unit passes through the wellbore and takes 0 when it does not pass through the wellbore; Q v is the filtration loss of hydraulic fracture unit fracturing fluid, m 3 / s; K f is the permeability of the reservoir microfracture system, mD; is the distance from the hydraulic fracture to the center point of the reservoir grid where it is located, m; P fw is the water phase pressure of the reservoir microfracture system, MPa; E is the Young's modulus of the reservoir rock, MPa; v is the Poisson's ratio of the reservoir rock; σ h is the minimum horizontal principal stress of the reservoir, MPa.

[0030] A further technical solution is that the specific calculation process of step S4 is:

[0031] Step S41, the calculated hydraulic fracture unit number, fracture unit width, fracture unit pressure and fracture unit filtration amount are substituted as initial conditions into the shale gas reservoir gas-water two-phase seepage model to simulate and calculate the water phase pressure, gas phase pressure and water saturation at any grid in the shale reservoir matrix at time t1, and the water phase pressure, gas phase pressure and water saturation at any grid in the microfracture system;

[0032] Step S42, substituting the calculated water saturation at each grid of the shale matrix and microcrack system at time t1 into the following formula, the volume strain of each grid in the matrix and microcracks under the action of shale hydration expansion, the porosity of each grid in the matrix and microcracks after damage by hydration expansion, and the permeability of the matrix and microcracks after damage by hydration expansion can be obtained;

[0033]

[0034]

[0035]

[0036] In the formula, is the volume strain of the matrix at the (i, j) grid caused by shale hydration expansion at time t1; is the volume strain of microcracks at the (i, j) grid caused by shale hydration expansion at time t1; k1 and k2 are empirical expansion coefficients, k1 = 0.0112, = k2 0.00201;

[0037] Step S43, for the reservoir grid with increased water saturation, obtain the shale tensile strength and cohesion of the reservoir grid where the fracturing fluid filtrate invades at time t1 through the soaking time-tensile strength curve and the soaking time-cohesion curve;

[0038] Step S44, judging whether the microcracks at the reservoir grid are damaged according to the tensile strength and cohesion of the shale at the reservoir grid where the fracturing fluid filtrate invades at time t1;

[0039] If tensile damage occurs, the microfracture permeability and porosity at the reservoir grid at time t1 after shale hydration expansion and tensile damage are calculated;

[0040] If no tensile failure occurs, continue to determine whether shear failure occurs in the microcracks at the reservoir grid;

[0041] If shear failure occurs, the microfracture permeability and microfracture porosity at the reservoir grid at time t1 after shale hydration expansion and shear failure are calculated;

[0042] If shear failure does not occur, proceed to the next step.

[0043] A further technical solution is that the shale gas reservoir gas-water two-phase seepage model in step S41 includes:

[0044] Gas-water two-phase seepage model of microfracture system in shale gas reservoir:

[0045]

[0046]

[0047] P fc =P fg -P fw

[0048] Where: K frw , K frg is the relative permeability of liquid and gas phases in the microfracture grid; P fg , P fw is the gas and liquid pressure of the microcrack grid, MPa; K m is the matrix permeability, mD; K mrw , K mrg is the relative permeability of liquid and gas phases in the microfracture grid; P mw , P mg is the pressure of liquid and gas phase in the matrix grid, MPa; B g is the volume coefficient of the gas; μ g is the viscosity of the gas, mPa·s; V f is the volume of the microcrack grid, m3 ; α is the unit conversion coefficient, α = 0.001; λ is the judgment parameter of whether the hydraulic fracture unit passes through the micro-fracture grid. If the micro-fracture grid has cracks passing through it, λ = 1; if the micro-fracture grid has no cracks passing through it, λ = 0; φ f is the porosity of microcracks, dimensionless; S fw , S fg is the liquid and gas saturation in the microfracture grid; P fc is the capillary force of microcracks, MPa;

[0049] Gas-water two-phase flow model in shale matrix:

[0050]

[0051]

[0052] P mc =P mg -P mw

[0053] Where: φ m is the porosity of the matrix, dimensionless; S mw , S mg is the liquid and gas saturation in the matrix grid; P mc is the capillary force of the matrix, MPa.

[0054] A further technical solution is that the specific process of step S5 is:

[0055] Step S51, taking the pressure, water saturation, permeability and porosity at each grid of the shale matrix and microfracture system at time t1 obtained in step S4 taking into account the hydration expansion and hydration fracturing of shale as initial parameters, repeating steps S3-S4, and calculating the parameters such as the width, pressure, and filtration loss of each unit of the hydraulic fracture at time t2, as well as various parameters at each grid of the reservoir matrix and microfracture;

[0056] Step S52: When the calculated time reaches the fracturing construction time t frac-end After that, the simulation calculation of the well soaking stage is entered. At this time, the pumping displacement Q = 0m 3 / s, continue to use the parameters obtained by simulation calculation as initial parameters, and continue to repeat steps S3-S4 to calculate the width, pressure, and filtration loss of each unit of hydraulic fractures during the soaking period, as well as the pressure, water saturation, permeability, and porosity of each grid of the reservoir matrix and microfractures. After the calculation time reaches the soaking end time, the cycle calculation ends and the next step is entered.

[0057] A further technical solution is that the calculation formula for the fracturing transformation volume in step S6 is:

[0058]

[0059] Where: V shut-in is the fracturing stimulation volume, m 3 ; α 1,i,j is the judgment parameter of the fracturing transformation range in the matrix system; α 2,i,j It is a parameter for judging the scope of hydraulic fracturing in micro-fracture systems.

[0060] The present invention has the following beneficial effects: the present invention combines shale hydration expansion and hydration fracturing with the fracture extension model and the reservoir dual medium model, considers the seepage of fracturing fluid filtrate in the reservoir, the influence of shale hydration expansion and micro-fracture fracturing extension during fracturing and well shut-in, obtains the fracturing transformation volume under different well shut-in times through simulation calculation, and then determines a reasonable well shut-in time range based on the relationship between well shut-in time and fracturing transformation volume. This method not only couples fracture extension and reservoir flow process, but also considers hydration expansion and hydration fracturing in the fracturing-well shut-in process. BRIEF DESCRIPTION OF THE DRAWINGS

[0061] Figure 1 It is the tensile strength curve of shale rock under different immersion time;

[0062] Figure 2 It is the cohesion curve of shale rock under different immersion time;

[0063] Figure 3 This is the fracturing transformation volume curve under different well shut-in times. DETAILED DESCRIPTION

[0064] The technical solution of the present invention will be described clearly and completely below in conjunction with the accompanying drawings. 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 creative work are within the scope of protection of the present invention.

[0065] A method for optimizing the well-keeping time by coupling shale hydration expansion and fracturing of the present invention comprises the following steps in sequence:

[0066] Step 1: Select rock samples with cemented natural fractures in the target reservoir to conduct triaxial rock mechanics experiments, and draw immersion time-rock tensile strength and immersion time-rock cohesion curves;

[0067] The experimental equipment uses a triaxial rock mechanics stress-strain test system. The experimental core uses a standard core sample with cemented natural fractures.

[0068] Experimental process: Drill standard rock samples from the target reservoir; clean and dry the rock samples; soak the rock samples in fracturing fluid for 0 days, 3 days, 5 days, 10 days, 15 days and 20 days; wrap the rock samples with latex protective sleeves; put the rock samples into the pressure chamber for triaxial rock compression experiments. Fit the experimental data with formulas (1) to (2), and draw the soaking time-rock tensile strength (σ) and soaking time-rock cohesion (τ) curves;

[0069] σ=Alnt s +B (1)

[0070] τ=Clnt s +D (2)

[0071] Where: t s is the experimental time, d; A, B, C, D are the fitting parameters of the formula; σ is the tensile strength of the experimental rock sample, MPa; τ is the cohesive force of the experimental rock sample, MPa.

[0072] Step 2: Establish a reservoir grid based on the target well reservoir geological model and add initial fracture units;

[0073] According to the target reservoir, a structured grid of the target reservoir is established in a rectangular coordinate system, and the number of grids is n i ×n j ;x i,j and i,j Respectively represent the length and width of each grid, and the subscript (i, j) represents the position of each grid in the reservoir. In the reservoir grid, the initial fracture unit is added at the grid position corresponding to the fracturing operation, and the initial unit of each cluster of fractures passes through three reservoir grids along the fracture initiation and propagation direction.

[0074] The present invention uses an embedded discrete fracture model to describe hydraulic fractures, so that during the fracturing process, the fracture length gradually increases, and the reservoir grid divides the fracture trajectory into multiple fracture units.

[0075] The total number of hydraulic fracture units is n L , the crack unit number is L (L = 1, 2, ... n L -1,n L ), the crack unit length is x F ; The number of fracturing clusters is c; The fluid pressure in the Lth fracture unit is P F,L ; The initial matrix water saturation of each reservoir grid is The initial matrix porosity is The initial matrix gas phase pressure is The initial matrix water phase pressure is The initial water saturation of the microfracture system is The initial microcrack system porosity is The initial gas phase pressure of the microcrack system is The initial water phase pressure of the micro-fracture system is

[0076] Step 3, calculating the length of the hydraulic fracture, the width at different positions in the fracture, the fracture pressure and the filtration loss;

[0077] Step 31: Based on the established reservoir model, the following fracture propagation model considering fracturing fluid loss is used for calculation to obtain the number of hydraulic fracture units, the width and fluid pressure at different fracture units, and the fluid loss of each fracture unit during the construction process;

[0078] The fracture propagation model considering fracturing fluid loss is:

[0079]

[0080]

[0081]

[0082] Where: μ w is the viscosity of the fracturing fluid, mPa·s; w F is the hydraulic fracture width, m; P F is the hydraulic fracture pressure, MPa; Q is the pumping rate of the fracturing operation, m 3 / s; c is the number of fracturing clusters; x F is the crack unit length, m; h F is the height of hydraulic fracture, m; δ F is the Dirac function of the injection point source of the fracturing fluid, which takes 1 when the fracture unit passes through the wellbore and takes 0 when it does not pass through the wellbore; Q v is the filtration loss of hydraulic fracture unit fracturing fluid, m 3 / s; K f is the permeability of the reservoir microfracture system, mD; is the distance between the hydraulic fracture and the center point of the reservoir grid where it is located, m; P fw is the water phase pressure of the reservoir microfracture system, MPa; E is the Young's modulus of the reservoir rock, MPa; v is the Poisson's ratio of the reservoir rock; σ h is the minimum horizontal principal stress of the reservoir, MPa;

[0083] Initial conditions:

[0084]

[0085] Where: w F,L,t＝0 is the initial crack width before fracturing construction begins, m; Q t＝0 is the pumping flow rate before fracturing construction begins, m3 / s.

[0086] Boundary conditions:

[0087] Q t＞0 =Q (7)

[0088] Where: Q t＞0 is the pumping flow rate after the fracturing operation starts, m 3 / s;

[0089] The numerical solution of the above fracturing model can obtain the width of each fracture unit at time t1: Filtration at each fracture unit The pressure at each fracture unit at time t1 can be obtained by the corresponding relationship between hydraulic fracture width and fracture pressure (Formula (5)):

[0090] Step 32, calculating the stress intensity factor of each crack tip at time t1 according to the pressure at each crack unit and the total number of crack units in each crack;

[0091] Specifically, the pressure of the tip unit of the eth (e=1,...c-1,c) crack at time t1 is calculated. and the total number of crack units of the e-th crack Substituting into the following formula, we can obtain the stress intensity factor at the tip of the e-th crack at time t1:

[0092]

[0093] Where: is the stress intensity factor at the tip of the e-th crack at time t1, MPa·m 1 / 2 ; is the pressure of the e-th crack tip unit at time t1, MPa; is the total number of elements of the e-th crack at time t1;

[0094] Step 33: Based on the stress intensity factor at each crack tip The fracture toughness K of shale IC (Take K IC =2MPa·m 1 / 2 ) Determine the expansion of each crack;

[0095] when When t1, the crack at time t1 does not expand and the crack length remains unchanged; When the crack at time t1 expands, the crack length increases, the total number of units of this crack increases by 1, the width of the new crack unit at time t1 is 0m, and the filtration loss at the new crack unit is 0m 3 / s, and calculate the pressure of the new fracture unit by formula (4); after the extension of all fractures is judged, proceed to step 4 for calculation;

[0096] Step 4, calculating the pressure distribution, water saturation distribution and porosity distribution of the reservoir matrix and micro-fractures considering the shale hydration expansion and hydration fracturing;

[0097] Step 41, the calculated parameters such as the number of hydraulic fracture units, the width of the fracture unit, the pressure of the fracture unit and the filtration loss of the fracture unit are substituted as initial conditions into the following shale gas reservoir gas-water two-phase seepage model for simulation calculation;

[0098] Gas-water two-phase seepage model of microfracture system in shale gas reservoir:

[0099]

[0100]

[0101] P fc =P fg -P fw (11)

[0102] Where: K frw , K frg is the relative permeability of liquid and gas phases in the microfracture grid; P fg , P fw is the gas and liquid pressure of the microcrack grid, MPa; K m is the matrix permeability, mD; K mrw , K mrg is the relative permeability of liquid and gas phases in the microfracture grid; P mw , P mg is the pressure of liquid and gas phase in the matrix grid, MPa; B g is the volume coefficient of the gas; μ g is the viscosity of the gas, mPa·s; V f is the volume of the microcrack grid, m 3 ; α is the unit conversion coefficient, α = 0.001; λ is the judgment parameter of whether the hydraulic fracture unit passes through the micro-fracture grid. If the micro-fracture grid has cracks passing through it, λ = 1; if the micro-fracture grid has no cracks passing through it, λ = 0; φ f is the porosity of microcracks, dimensionless; S fw , S fg is the liquid and gas saturation in the microfracture grid; Pfc is the capillary force of microcracks, MPa;

[0103] Gas-water two-phase flow model in shale matrix:

[0104]

[0105]

[0106] P mc =P mg -P mw (14)

[0107] In the formula, φ m is the porosity of the matrix, dimensionless; S mw , S mg is the liquid and gas saturation in the matrix grid; P mc is the capillary force of the matrix, MPa.

[0108] Initial conditions

[0109]

[0110]

[0111]

[0112]

[0113] Boundary conditions

[0114] The outer boundary of the reservoir in the present invention is a non-permeable boundary, that is, the pressure gradient at the outer boundary is 0.

[0115]

[0116] Through the calculation of the above model, the water phase pressure, gas phase pressure and water saturation at any grid in the shale reservoir matrix at time t1, as well as the water phase pressure, gas phase pressure and water saturation at any grid in the microfracture system can be numerically solved. If the water saturation of the simulated matrix or microfracture grid increases, it means that the fracturing fluid filtrate seepage has entered the grid. In this case, the porosity and permeability of the shale matrix and microfractures in the grid will be affected by hydration expansion;

[0117] Step 42, substituting the calculated water saturation at each grid of the shale matrix and the water saturation at each grid of the microfracture system at time t1 into formulas (20) to (22), obtaining the volume strain of each grid in the matrix and microfractures under the action of shale hydration expansion, the porosity of each grid in the matrix and microfractures after damage by hydration expansion, and the permeability of the matrix and microfractures after damage by hydration expansion;

[0118]

[0119]

[0120]

[0121] In the formula, is the volume strain of the matrix at the (i, j) grid caused by shale hydration expansion at time t1; is the volume strain of microcracks at the (i, j) grid caused by shale hydration expansion at time t1; k1 and k2 are empirical expansion coefficients, k1 = 0.0112, = k2 0.00201;

[0122] Step 43: As the fracturing fluid filtrate enters the shale reservoir, the water-rock interaction will change the rock properties and cause the expansion of microcracks in the shale reservoir. For the reservoir grid (i, j) with increased water saturation, the shale tensile strength at the reservoir grid (i, j) invaded by the fracturing fluid filtrate at time t1 can be obtained through the immersion time-tensile strength (σ) curve and the immersion time-cohesion (τ) curve in step 1. and cohesion

[0123] Step 44, substituting the above parameters into formula (23) to determine whether the microcracks at the reservoir grid (i, j) are tensilely damaged;

[0124]

[0125]

[0126] Where P n is the normal stress on the microcracks, MPa; is the tensile strength of shale at time t1, MPa; σ H is the maximum horizontal principal stress of the shale reservoir, MPa; σ h is the minimum horizontal principal stress of the shale reservoir, MPa; β is the angle between the natural fractures in the shale reservoir and the maximum horizontal principal stress direction, °; ​​K fn is the normal stiffness of natural fracture, MPa / m, K fn =1.44×10 4MPa / m; ζ is the unit conversion coefficient;

[0127] If the above calculation results meet the inequality condition in formula (23), the microfractures at the reservoir grid (i, j) will be tensilely damaged. The microfracture permeability at the reservoir grid (i, j) at time t1 after shale hydration expansion and tensile damage is calculated by formula (24): At the same time, according to the corresponding relationship between microfracture permeability and porosity (Formula (22)), the microfracture porosity at the reservoir grid (i, j) at time t1 after shale hydration expansion and tensile damage can be obtained:

[0128] If the calculation result does not satisfy the inequality condition in formula (23), the microcracks at the reservoir grid (i, j) will not undergo tensile failure, and it is necessary to determine whether shear failure has occurred;

[0129] The shale tensile strength at the reservoir grid (i, j) where the fracturing fluid filtrate invades at time t1 is calculated as Cohesion Substitute parameters such as gas phase pressure into formula (25) to determine whether shear failure occurs in the microcracks at the grid (i, j);

[0130]

[0131]

[0132] Where P τ is the tangential stress on the microcracks, MPa; is the shale cohesion at time t1, MPa; f is the friction coefficient of natural fractures; is the shear expansion angle of natural fractures, °; K fs is the shear stiffness of natural fractures, MPa / m, K fs =1.8×10 3 MPa / m;

[0133] If the calculation result satisfies the inequality condition in formula (25), the micro-fractures at the reservoir grid (i, j) undergo shear failure. The micro-fracture permeability at the grid (i, j) at time t1 after shale hydration expansion and shear failure is calculated by formula (26): At the same time, according to formula (22), the microfracture porosity at the grid (i, j) at time t1 after shale hydration expansion and shear failure can be obtained:

[0134] If the calculation result does not satisfy the inequality condition in formula (25), the microcracks at the reservoir grid (i, j) will not undergo shear failure, and the next step is performed;

[0135] Step 5, repeat steps 3 to 4 until the calculation time reaches the end time of soaking, end the cycle calculation, and then proceed to the next step;

[0136] Step 51: Through the above simulation calculation, the pressure, water saturation, permeability and porosity of each grid of the shale matrix and microfracture system at time t1 are obtained considering the hydration expansion and hydration fracturing of shale. Substitute these parameters into steps 3-4 to calculate the parameters such as the width, pressure, and filtration loss of each unit of the hydraulic fracture at time t2, as well as various parameters at each grid of the reservoir matrix and microfracture;

[0137] Step 52: When the calculation time reaches the fracturing construction time t frac-end After that, the simulation calculation of the well soaking stage is entered. At this time, the pumping displacement Q = 0m 3 / s, continue to substitute the parameters obtained by simulation calculation into steps 3-4, calculate the parameters such as the width, pressure, and filtration loss of each unit of hydraulic fractures during the soaking period, as well as the parameters such as pressure, water saturation, permeability, and porosity at each grid of the reservoir matrix and microfractures, until the calculation time reaches the soaking end time t shut-in (t shut-in =1d, 3d, 5d, 7d, 10d, 15d, 20d), end the loop calculation and go to step 6;

[0138] Step 6, calculating the fracturing stimulation volume under different well shut-in times, and drawing a well shut-in time-transformation volume curve;

[0139] After the fracturing-well soaking simulation is completed, obtain t shut-in Width of each unit of hydraulic fracture under time Total number of crack elements Porosity of each grid in the reservoir matrix Porosity of each grid in the microfracture system Water saturation of each grid in the reservoir matrix Water saturation of each grid in the microfracture system The fracturing transformation volume after fracturing-well soaking can be calculated by the following formula:

[0140]

[0141] Where: V shut-in is the fracturing stimulation volume, m 3 ; α 1,i,j is the judgment parameter of the fracturing transformation range in the matrix system. When α 1,i,j =1; if When α 1,i,j =0; α 2,i,jis the judgment parameter of the fracturing transformation range in the micro-fracture system. When α 2,i,j =1; if When α 2,i,j =0;

[0142] The fracturing transformation volume under different shut-in times can be obtained by calculation, and a shut-in time-transformation volume curve can be drawn. The shut-in time range can be determined by the changing trend of the fracturing transformation volume as the shut-in time increases.

[0143] Example

[0144] Taking a shale gas well in a certain block in southern Sichuan as an example, the post-pressure soaking time determination method of the present invention was used to perform simulation calculations, and the soaking time-rock tensile strength curve, soaking time-rock cohesion curve and soaking time-transformation volume curve were drawn to determine the soaking time range. The calculation steps for the shale gas well are as follows.

[0145] Step 1: Through triaxial rock mechanics experiments, the tensile strength and cohesion of shale samples after being immersed in fracturing fluid for 0, 3, 5, 10, 15 and 20 days are tested. The experimental data are fitted with formulas (1) to (2) to draw the immersion time-tensile strength (σ) and immersion time-cohesion (τ) curves of the target reservoir.

[0146] Step 2: Establish a structured grid in the xy coordinate system according to the reservoir conditions. The length and width of the grid are set to 1m. The total number of reservoir grids is 300×400, that is, n i =300, n j = 400. Initial matrix water saturation of each reservoir grid Initial matrix porosity Initial matrix gas phase pressure Initial matrix permeability Initial water saturation of microfracture system Initial microfracture system porosity Initial microcrack system gas phase pressure The initial gas phase pressure of the microcrack system is Initial microcrack permeability

[0147] On the basis of the established grid, add 6 initial hydraulic fractures with a cluster spacing of 15m. The length of each initial fracture is 3m, and each fracture has 3 initial fracture units. The total number of hydraulic fracture units is n L =12, hydraulic fracture unit length x F =1m, the initial width of each crack unit is w F,L,t＝0 =0m, fracturing operation displacement Q = 12m3 / s.

[0148] Step 3: The width w of each hydraulic fracture unit at t = 1s is obtained by simulation calculation using formulas (3) to (7): F,L,1s , the filtration loss Q at each fracture unit v,L,1s Substituting the width into formula (5) we can calculate the pressure P at each hydraulic fracture unit at t = 1s: F,L,1s .

[0149] The pressure of the two tip units above and below the first crack at t = 1s and the total number of crack units n Le,1s Substituting into formula (8), we can calculate the stress intensity factors K at the two tips of the first crack at t = 1s. Ii,e,1s The stress intensity factors of the two tips of the first crack are respectively compared with the fracture toughness of the shale reservoir. For comparison, if K I i ,e,1s >K IC , then the first crack will expand at the end point, adding a crack unit, and the width of the new crack unit is 0m, and the filtration loss is 0m 3 / s; if K I,1,0 ≤K IC , then the first crack does not expand; then, continue to calculate the stress intensity factors of the two tips of the second to sixth cracks and judge their expansion conditions;

[0150] Step 4: Based on the number of hydraulic fracture units, the width of the fracture unit, the pressure at the fracture unit and the filtration loss at the fracture unit calculated in step 3, the water phase pressure P at any grid in the shale reservoir matrix at t = 1 s is calculated by formulas (9) to (19): mw i,j,1s , gas phase pressure P mg i,j,1s and water saturation S mw i,j,1s , and the water phase pressure P at any grid in the microfracture system fw i,j,1s , gas phase pressure P fg i,j,1s and water saturation S fw i,j,1s ;

[0151] Substitute these parameters into formulas (20) to (22) to calculate the porosity of the shale matrix and microcracks and the permeability of the matrix and microcracks at t = 1s under the action of hydration expansion. Combined with the t-σ curve and t-τ curve obtained in step 1 and the calculated parameters, the tensile damage of the microcracks at the grid position where the fracturing fluid has invaded is determined by formula (23). If the tensile damage condition is met, the permeability and porosity of the microcracks under the action of shale hydration expansion and hydration fracturing are calculated by formula (24) and formula (22); if the tensile damage condition is not met, the shear damage of the microcracks is determined by formula (25). If shear damage occurs, the permeability and porosity of the microcracks under the action of shale hydration expansion and hydration fracturing are calculated by formula (26) and formula (22); if shear damage occurs, proceed to the next step;

[0152] Step 5: Substitute the obtained parameters into steps 3-4 to perform simulation calculation at t = 2s; if the simulation time t = 90min, the fracturing stage ends and the fracturing operation displacement Q drops to 0m 3 / s, repeat steps 3 to 4 to start the simulation calculation of the well soaking stage.

[0153] Step 6: When the soaking time reaches 1 day, obtain the width of each unit of the hydraulic fracture Total number of crack elements n Le,1d , the porosity of each grid of the reservoir matrix φ mi,j,1d , the porosity of each grid in the micro-fracture system φ fi,j,1d , water saturation S of each grid of the reservoir matrix mw i,j,1d , water saturation S of each grid in the microfracture system fw i,j,1d The fracturing transformation volume V after one day of well shut-in considering hydration expansion and hydration fracturing is calculated by formula (27): shut-in =18841.44m 3 Similarly, the fracturing transformation volume with well shut-in time of 3 days, 5 days, 7 days, 10 days, 15 days and 20 days was calculated, and the well shut-in time-transformation volume curve was drawn. According to the curve analysis, the growth trend of fracturing transformation volume decreased significantly after well shut-in for 10 days, and it was not meaningful to continue to take well shut-in measures after 15 days, so the well shut-in time range was determined to be 10 to 15 days.

[0154] The above description is not intended to impose any form of limitation on the present invention. Although the present invention has been disclosed through the above embodiments, it is not intended to limit the present invention. Any technician familiar with the profession can make some changes or modifications to equivalent embodiments of equivalent changes using the technical contents disclosed above without departing from the scope of the technical solution of the present invention. However, any simple modification, equivalent change and modification made to the above embodiments based on the technical essence of the present invention without departing from the content of the technical solution of the present invention still falls within the scope of the technical solution of the present invention.

Claims

1. A method for optimizing the well-keeping time by coupling shale hydration expansion and fracturing, characterized in that: The following steps are involved: Step S1, selecting a rock sample with cemented natural fractures in the target reservoir to conduct a triaxial rock mechanics experiment, and drawing a soaking time-rock tensile strength and soaking time-rock cohesion curve; Step S2, establishing a reservoir grid based on the target well reservoir geological model, and adding initial fracture units; Step S3, calculating the length of the hydraulic fracture, the width at different positions in the fracture, the pressure in the fracture, and the filtration loss; Step S4, calculating the pressure distribution, water saturation distribution and porosity distribution of the reservoir matrix and micro-cracks taking into account the hydration expansion and hydration fracturing of shale; Step S5, repeating steps S3-S4 until the calculation time reaches the end time of soaking, ending the cycle calculation, and then proceeding to the next step; Step S51, taking the pressure, water saturation, permeability and porosity at each grid of the shale matrix and microfracture system at time t1 obtained in step S4 taking into account the hydration expansion and hydration fracturing of shale as initial parameters, repeating steps S3-S4, and calculating the width, pressure and filtration loss of each unit of the hydraulic fracture at time t2, as well as various parameters at each grid of the reservoir matrix and microfracture; Step S52: When the calculated time reaches the fracturing construction time t frac-end After that, the simulation calculation of the well soaking stage is entered. At this time, the pumping displacement Q = 0m 3 / s, continue to use the parameters obtained by simulation calculation as initial parameters, and continue to repeat steps S3-S4 to calculate the width, pressure, and filtration loss of each unit of hydraulic fractures during the soaking period, as well as the pressure, water saturation, permeability, and porosity of each grid of the reservoir matrix and microfractures, until the calculation time reaches the soaking end time, end the cycle calculation, and enter the next step; Step S6, calculating the fracturing stimulation volume under different shut-in times, and drawing a shut-in time-stimulation volume curve.

2. The method for optimizing the well shut-in time by coupling shale hydration expansion and fracturing according to claim 1, characterized in that: The specific process of step S1 is: cleaning and drying the rock sample; soaking the rock sample in fracturing fluid debonding liquid for 0 days, 3 days, 5 days, 10 days, 15 days and 20 days respectively; wrapping the rock sample with a latex protective sleeve; placing the rock sample in a pressure chamber for a triaxial rock compression test; and then fitting the experimental data with the formula to draw immersion time-rock tensile strength and immersion time-rock cohesion curves.

3. The method for optimizing the well shut-in time by coupling shale hydration expansion and fracturing according to claim 2, characterized in that: The formula in step S1 is: σ=Alnt s +B τ=Clnt s +D Where: t s is the experimental time, d; A, B, C, D are the fitting parameters of the formula; σ is the tensile strength of the experimental rock sample, MPa; τ is the cohesive force of the experimental rock sample, MPa.

4. The method for optimizing the well shut-in time by coupling shale hydration expansion and fracturing according to claim 1, characterized in that: The specific process of step S2 is: according to the target reservoir, a structured grid of the target reservoir is established in a rectangular coordinate system, and the number of grids is n i ×n j In the reservoir grid, initial fracture units are added at the grid positions corresponding to the fracturing operation, and the initial units of each cluster of fractures pass through three reservoir grids along the direction of fracture initiation and propagation.

5. The method for optimizing the well shut-in time by coupling shale hydration expansion and fracturing according to claim 1, characterized in that: The specific calculation process of step S3 is: Step S31: Based on the established reservoir model, numerically solve the fracture extension model considering fracturing fluid loss to obtain the width of each fracture unit at time t1. Filtration at each fracture unit The corresponding relationship between the hydraulic fracture width and the pressure inside the fracture can be used to obtain the pressure at each fracture unit at time t1: Step S32, calculating the stress intensity factor of each crack tip at time t1 according to the pressure at each crack unit and the total number of crack units in each crack; In the formula, is the stress intensity factor at the tip of the e-th crack at time t1, MPa·m 1 / 2 ; is the pressure of the e-th crack tip unit at time t1, MPa; is the total number of elements of the e-th crack at time t1; Step S33: Based on the stress intensity factor of each crack tip The fracture toughness K of shale IC Determine the expansion of each crack; when When t1, the crack at time t1 does not expand and the crack length remains unchanged; When the crack at time t1 expands, the crack length increases, the total number of units of this crack increases by 1, the width of the new crack unit at time t1 is 0m, and the filtration loss at the new crack unit is 0m 3 / s, and calculate the pressure of the new fracture unit.

6. The method for optimizing the well shut-in time by coupling shale hydration expansion and fracturing according to claim 5, characterized in that: The fracture propagation model considering fracturing fluid loss in step S31 includes: Where: μ w is the viscosity of the fracturing fluid, mPa·s; w F is the hydraulic fracture width, m; P F is the hydraulic fracture pressure, MPa; Q is the pumping rate of the fracturing operation, m 3 / s; c is the number of fracturing clusters; x F is the crack unit length, m; h F is the height of hydraulic fracture, m; δ F is the Dirac function of the injection point source of the fracturing fluid, which takes 1 when the fracture unit passes through the wellbore and takes 0 when it does not pass through the wellbore; Q v is the filtration loss of hydraulic fracture unit fracturing fluid, m 3 / s; K f is the permeability of the reservoir microfracture system, mD; is the distance from the hydraulic fracture to the center point of the reservoir grid where it is located, m; P fw is the water phase pressure of the reservoir microfracture system, MPa; E is the Young's modulus of the reservoir rock, MPa; v is the Poisson's ratio of the reservoir rock; σ h is the minimum horizontal principal stress of the reservoir, MPa.

7. The method for optimizing the well shut-in time by coupling shale hydration expansion and fracturing according to claim 1, characterized in that: The specific calculation process of step S4 is: Step S41, the calculated hydraulic fracture unit number, fracture unit width, fracture unit pressure and fracture unit filtration amount are substituted as initial conditions into the shale gas reservoir gas-water two-phase seepage model to simulate and calculate the water phase pressure, gas phase pressure and water saturation at any grid in the shale reservoir matrix at time t1, and the water phase pressure, gas phase pressure and water saturation at any grid in the microfracture system; Step S42, substituting the calculated water saturation at each grid of the shale matrix and microcrack system at time t1 into the following formula, the volume strain of each grid in the matrix and microcracks under the action of shale hydration expansion, the porosity of each grid in the matrix and microcracks after damage by hydration expansion, and the permeability of the matrix and microcracks after damage by hydration expansion can be obtained; In the formula, is the volume strain of the matrix at the (i, j) grid caused by shale hydration expansion at time t1; is the volume strain of microcracks at the (i, j) grid caused by shale hydration expansion at time t1; k1 and k2 are empirical expansion coefficients, k1 = 0.0112, = k2 0.00201; Step S43, for the reservoir grid with increased water saturation, obtain the shale tensile strength and cohesion of the reservoir grid where the fracturing fluid filtrate invades at time t1 through the soaking time-tensile strength curve and the soaking time-cohesion curve; Step S44, judging whether the microcracks at the reservoir grid are damaged according to the tensile strength and cohesion of the shale at the reservoir grid where the fracturing fluid filtrate invades at time t1; If tensile damage occurs, the microfracture permeability and porosity at the reservoir grid at time t1 after shale hydration expansion and tensile damage are calculated; If no tensile failure occurs, continue to determine whether shear failure occurs in the microcracks at the reservoir grid. If shear failure occurs, the microfracture permeability and microfracture porosity at the reservoir grid at time t1 after shale hydration expansion and shear failure are calculated; If shear failure does not occur, proceed to the next step.

8. The method for optimizing the well shut-in time by coupling shale hydration expansion and fracturing according to claim 7, characterized in that: The gas-water two-phase seepage model of the shale gas reservoir in step S41 includes: Gas-water two-phase seepage model of microfracture system in shale gas reservoir: P fc =P fg -P fw Where: K frw , K frg is the relative permeability of liquid and gas phases in the microfracture grid; P fg , P fw is the gas and liquid pressure of the microcrack grid, MPa; K m is the matrix permeability, mD; K mrw , K mrg is the relative permeability of liquid and gas phases in the microfracture grid; P mw , P mg is the pressure of liquid and gas phase in the matrix grid, MPa; B g is the volume coefficient of the gas; μ g is the viscosity of the gas, mPa·s; V f is the volume of the microcrack grid, m 3 ; α is the unit conversion coefficient, α = 0.001; λ is the judgment parameter of whether the hydraulic fracture unit passes through the micro-fracture grid. If the micro-fracture grid has cracks passing through it, λ = 1; if the micro-fracture grid has no cracks passing through it, λ = 0; φ f is the porosity of microcracks, dimensionless; S fw , S fg is the liquid and gas saturation in the microfracture grid; P fc is the capillary force of microcracks, MPa; Gas-water two-phase flow model in shale matrix: P mc =P mg -P mw Where: φ m is the porosity of the matrix, dimensionless; S mw , S mg is the liquid and gas saturation in the matrix grid; P mc is the capillary force of the matrix, MPa.

9. The method for optimizing the well shut-in time by coupling shale hydration expansion and fracturing according to claim 1, characterized in that: The calculation formula of the fracturing transformation volume in step S6 is: Where: V shut-in is the fracturing stimulation volume, m 3 ; α 1,i,j is the judgment parameter of the fracturing transformation range in the matrix system; α 2,i,j is the judgment parameter of the fracturing transformation range in the micro-fracture system; x F is the crack unit length, m; h F is the height of hydraulic fracture, m.

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