Method for water injection pressure recovery degree and soaking time of old well energy storage group

Abstract

The invention relates to the technical field of fracturing in oil and gas field development, in particular to a method for water injection pressure recovery degree and soaking time of an old well energy storage group, which comprises the following steps of: 1, establishing a multiphase flow fluid-solid coupling seepage model, and carrying out historical fitting of production dynamics before oil well refracturing to obtain four-dimensional ground stress and formation pressure distribution of an oil reservoir; calculating the remaining oil reserve; 2, according to the remaining oil reserve threshold value interval of the area, it is determined that the group refractures the group well, if the remaining oil reserve is within the threshold value interval, the operation is continued, and if the remaining oil reserve is not within the threshold value interval, the operation is stopped; and 3, according to production characteristics before water injection and energy increasing of the target group well. According to the method, blindness of refracturing construction design of the old well energy storage group is reduced, the overall reconstruction effect of fracturing is enhanced to the maximum extent, the reservoir reconstruction volume and the resource utilization degree are improved, and efficient development of tight reservoir oil and gas resources is achieved.

Description

Technical Field

[0001] The invention relates to the technical field of fracturing in oil and gas field development, and is a method for restoring the degree of water injection pressure and the soaking time of an old well energy storage group. Background Art

[0002] Oil and gas wells in low-porosity and low-permeability reservoirs produce rapidly after fracturing in the early stage of development, and the output increases sharply. However, with the increase in water production and the influence of factors such as limited formation energy, the output decreases rapidly, resulting in a low degree of recovery. Therefore, it is necessary to carry out secondary transformation of old wells to most effectively tap the potential of the remaining oil and improve the recovery rate of oil and gas reservoirs.

[0003] Repeated fracturing technology is a commonly used and effective means for the development of low permeability oil and gas reservoirs. Repeated fracturing means that after the initial fracturing, as the production progresses, the pore pressure inside the reservoir decreases, and the ground stress distribution near the wellbore is affected by the supporting fractures, causing the ground stress to reverse, resulting in the new fracture direction opened by repeated fracturing being perpendicular to the direction of the initial fracturing fracture. When it extends to a certain distance in the stress reversal zone, the ground stress turns again, and then returns to the direction of the initial fracture extension and continues to extend. Group repeated fracturing refers to the use of group fracturing technology between two or more parallel or adjacent old wells. Energy storage group repeated fracturing means that the formation energy needs to be supplemented before group repeated fracturing. At present, the main energy storage fluids are clean water, return fluid, etc. First, it changes the ground stress state around the well, which is conducive to the formation of a new fracture network. Second, it provides energy for subsequent production. After group repeated fracturing, the fracturing efficiency and the fracture volume of the oil layer are greatly improved, and the production increase effect will also be greatly improved. Summary of the invention

[0004] The present invention provides a method for restoring the degree of water injection pressure and the time of well shut-in for an old well energy storage group, which overcomes the deficiencies of the above-mentioned prior art and can effectively solve the problem that the existing repeated fracturing construction design for the old well energy storage group is blind in terms of the degree of water injection pressure recovery and the time of well shut-in, and there is no systematic, scientific and effective method.

[0005] The technical solution of the present invention is achieved through the following measures: A method for restoring the water injection pressure and the well soaking time of an old well energy storage group, comprising the following steps:

[0006] Step 1: Establish a fluid-solid coupling seepage model for multiphase flow, conduct historical matching of the production performance of the oil well before repeated fracturing, obtain the four-dimensional geostress and formation pressure distribution of the reservoir, and calculate the remaining oil reserves;

[0007] Step 2: According to the threshold interval of the remaining oil reserves in the area, determine the group wells to be repeatedly fractured. If the remaining oil reserves are within the threshold interval, continue; if the remaining oil reserves are not within the threshold interval, stop;

[0008] Step 3: Calculate the formation deficit of a single well based on the production characteristics of the target group wells before water injection, including cumulative production, liquid consumption and formation pressure, and calculate the injection volume based on the pressure recovery degrees F1, F2 and F3;

[0009] Step 4: According to the injection volume in step 3, inject the energy storage fluid into each target well. After all target group wells have completed the energy injection, simulate the pressure distribution diagram and water saturation distribution under the well shut-in time of T1, T2, T3, and T4;

[0010] Step 5: Establish a coupling model, and simulate the expansion of hydraulic fractures caused by repeated fracturing of the group through the coupling model. According to the reservoir transformation volume of repeated fracturing, the degree of water injection pressure recovery and the time of well soaking are optimized, and the first pressure recovery degree and the first time of well soaking are simulated to find the first value of the current reservoir transformation volume, and then go to step 3. On the basis of the first value, narrow the range of the pressure recovery degree and the time of well soaking to find the second value of the current reservoir transformation volume. If the second value is greater than the first value, the first value is the optimal value. If the second value is not greater than the first value, the second value is the optimal value. Repeat this process until the interval of pressure recovery degree is 1% and the time interval is 1 day, and then the iteration ends.

[0011] The following are further optimizations and / or improvements to the above technical solutions:

[0012] The establishment of the coupling model in step 5 above includes:

[0013] Step i: Collect data of the target area and establish a three-dimensional geological model;

[0014] Step II: Establish a fluid-solid-thermal coupling model. According to the initial hydraulic fracturing construction data of the old well and the microseismic monitoring data, use the fluid-solid-thermal coupling model to obtain the crack morphology and parameters of the initial fracturing in the old well. Then establish an embedded discrete fracture model. The crack morphology and parameters of the initial fracturing in the old well are embedded into the three-dimensional geological model through the embedded discrete fracture model. The initial fracturing cracks in the old well include fracture height, fracture length and fracture width.

[0015] The fluid-structure thermal coupling model in step ii above includes:

[0016] The stress equilibrium equation of porous elastic rock is:

[0017]

[0018] In the above formula, g(d) is the attenuation function, g(d) = k + (1-k) (1-d) 2 , k is equal to 1×10 -9 , d is the phase field variable; is tensile stress; is the compressive stress; σ0 is the initial stress; α(d) is the Biot coefficient, K is the rock bulk modulus of porous media, K s is the bulk modulus of rock skeleton particles; Ι is the unit tensor; p is the pore fluid pressure;

[0019] The seepage balance equation of porous elastic rock is:

[0020]

[0021] In the above formula, p is the pore fluid pressure; M(d) is the Biot modulus, K f is the bulk modulus of the fluid, K s is the bulk modulus of rock skeleton particles, φ is the porosity of rock; α(d) is the Biot coefficient, K is the rock bulk modulus of the porous medium; ε ii is the volume strain; k is the permeability of the reservoir; μ f is the viscosity of the fluid, q f is the injection volume;

[0022] The temperature balance equation of poroelastic rock is:

[0023]

[0024] In the above formula, (ρC) eff is the heat capacity of the porous medium containing the fluid, (ρC) eff =φρ l C l +(1-φ)ρ s C s , φ is the porosity of the rock, ρ l Density of the fluid, C l is the specific heat capacity of the fluid, ρ s is the density of rock, C s is the specific heat capacity of rock; T is the temperature of the reservoir; λ eff is the average thermal conductivity, λ eff =φλ l +(1-φ)λ s ,λ l is the thermal conductivity of the fluid, λ s is the thermal conductivity of rock; ν is the velocity of fluid; Q is the heat source / sink;

[0025] The phase field evolution equation of poroelastic rock is:

[0026]

[0027] In the above formula, l0 is the length scale parameter; G c is the maximum energy release rate; d is the phase field variable; H is the maximum value of the tensile strain energy density, k is equal to 1×10 -9 , is the tensile strain energy density, σ0 is the initial stress, ε is the strain tensor, p is the pore fluid pressure, φ0 is the initial rock porosity, K f is the bulk modulus of the fluid, K s is the bulk modulus of rock skeleton particles, and K is the rock bulk modulus of porous media.

[0028] The target area data in the above step i includes the well logging curve and fault data of the target area.

[0029] The fluid-solid coupling model of the multiphase flow described in step 1 above includes:

[0030] The calculation equation of ground stress is as follows:

[0031]

[0032] In the above formula, σ eff is the effective stress; α is the biot pore elastic coefficient; p is the pore fluid pressure;

[0033] The saturation normalization equation is:

[0034] S o +S w =0

[0035] In the above formula, S o is the oil saturation; S w is water saturation;

[0036] The capillary pressure equation is:

[0037] p c (S w )=p0-p w

[0038] In the above formula, p c is the capillary pressure; S w is water saturation; p0 is oil pressure, p w For water pressure.

[0039] The calculation equation of formation pressure is:

[0040]

[0041] In the above formula, ρ o is the viscosity of the oil; v o is the oil flow rate, K ro is the relative permeability of oil, k is the permeability of the reservoir, p0 is the oil pressure, μ0 is the oil phase viscosity; S o is the oil saturation; q o is the oil production;

[0042] The calculation model of water saturation is as follows:

[0043]

[0044] In the above formula, ρ w is the viscosity of water; v w is the water flow velocity, K rw is the relative permeability of water, k is the permeability of the reservoir, p w is the water pressure, μ w is the viscosity of the water phase; S w is water saturation; q w The amount of water collected.

[0045] The remaining oil reserves in step 1 above are calculated as follows:

[0046]

[0047] In the above formula, D po (t) is the remaining oil reserves of the target group wells from the start of production to time t; D Ro is the original crude oil reserves; q i is the oil production of the i-th well at time t, i = 1, 2, 3, ..., n, and n is the number of repeated fracturing wells of the target well.

[0048] The single well formation deficit volume (m 3 ) = Cumulative liquid production (m 3 )-Liquid volume (m 3 );

[0049] The pressure recovery degree is:

[0050] Pressure recovery degree (%) = a × injection volume (m 3 )+b

[0051] In the above formula, a and b are fitting values.

[0052] The present invention reduces the blindness of repeated fracturing construction design of the old well energy storage group, maximizes the overall transformation effect of fracturing, increases the reservoir transformation volume and resource utilization, and realizes the efficient development of tight reservoir oil and gas resources. BRIEF DESCRIPTION OF THE DRAWINGS

[0053] Attached Figure 1 This is the single well fitting diagram of the target area.

[0054] Attached Figure 2 This is the pressure distribution diagram for different soaking times.

[0055] Attached Figure 3 It is the microseismic data characteristics of the group's well area. DETAILED DESCRIPTION

[0056] The present invention is not limited by the following embodiments, and specific implementation methods can be determined based on the technical solution of the present invention and actual conditions.

[0057] The present invention will be further described below in conjunction with embodiments and drawings:

[0058] Embodiment 1: The method for determining the water injection pressure recovery degree and well soaking time of an old well energy storage group comprises the following steps:

[0059] Step 1: Establish a fluid-solid coupling seepage model for multiphase flow, conduct historical matching of the production performance of the oil well before repeated fracturing, obtain the four-dimensional geostress and formation pressure distribution of the reservoir, and calculate the remaining oil reserves;

[0060] Fluid-structure interaction models for multiphase flow include:

[0061] The calculation equation of ground stress is as follows:

[0062] ▽(σ eff -αp)=0

[0063] In the above formula, σ eff is the effective stress; α is the biot pore elastic coefficient; p is the pore fluid pressure;

[0064] The saturation normalization equation is:

[0065] S o +S w =0

[0066] In the above formula, S o is the oil saturation; S w is water saturation;

[0067] The capillary pressure equation is:

[0068] p c (S w )=p0-p w

[0069] In the above formula, p c is the capillary pressure; S w is water saturation; p0 is oil pressure, p w For water pressure.

[0070] The calculation equation of formation pressure is:

[0071]

[0072] In the above formula, ρ o is the viscosity of the oil; v o is the oil flow rate, K ro is the relative permeability of oil, k is the permeability of the reservoir, p0 is the oil pressure, μ0 is the oil phase viscosity; S o is the oil saturation; q o is the oil production;

[0073] The calculation model of water saturation is as follows:

[0074]

[0075] In the above formula, ρ w is the viscosity of water; v w is the water flow velocity, K rw is the relative permeability of water, k is the permeability of the reservoir, p w is the water pressure, μ w is the viscosity of the water phase; S w is water saturation; q w The amount of water collected.

[0076] The calculation method of the remaining oil reserves is:

[0077]

[0078] In the above formula, D po (t) is the remaining oil reserves of the target group wells from the start of production to time t; D Ro is the original crude oil reserves; q i is the oil production of the i-th well at time t, i = 1, 2, 3, ..., n, and n is the number of repeated fracturing wells of the target well.

[0079] Through the established multiphase flow solid coupling model, the daily liquid production of a single well was fitted by adopting the strategy of fixed oil production, fitting bottom hole pressure and daily production. Figure 1 , it fully fits the production dynamics of the target block, has high overall fitting accuracy, and a reliable model. At the same time, it can obtain the four-dimensional ground stress and formation pressure distribution.

[0080] Step 2: According to the threshold interval of the remaining oil reserves in the area, determine the group wells to be repeatedly fractured. If the remaining oil reserves are within the threshold interval, continue; if the remaining oil reserves are not within the threshold interval, stop;

[0081] After obtaining the distribution of remaining oil reserves in the well area, the upper and lower limits of remaining oil reserves in the repeated fracturing well area are determined according to the input-output ratio and fracturing scale. and Based on economic benefits, when the remaining oil reserves D po exist It can be used as a group well for repeated fracturing.

[0082] Step 3: Calculate the formation deficit of a single well based on the production characteristics of the target group wells before water injection, including cumulative production, liquid consumption and formation pressure, and calculate the injection volume based on the pressure recovery degrees F1, F2 and F3;

[0083] The single well formation deficit (m 3 ) = Cumulative liquid production (m 3 )-Liquid volume (m 3 );

[0084] The pressure recovery degree is:

[0085] Pressure recovery degree (%) = a × injection volume (m 3 )+b

[0086] In the above formula, a and b are fitting values.

[0087] The cumulative production, liquid consumption and formation pressure of each target well before energy enhancement are counted and summarized, and the deficit is calculated, as shown in the following table.

[0088]

[0089]

[0090] Then the total injection volume is calculated based on the 80%, 90%, and 100% pressure recovery scenarios, and then divided into each single well, as shown in the following table.

[0091] The pressure recovery degree is calculated by the following formula:

[0092] Pressure recovery degree (%) = 0.0002*injection volume (m 3 )+65.189

[0093]

[0094] Step 4: According to the injection volume in step 3, inject the energy storage fluid into each target well. After all target group wells have completed the energy injection, simulate the pressure distribution diagram and water saturation distribution under the well shut-in time of T1, T2, T3, and T4;

[0095] The injection volume is calculated based on the pressure recovery degree, and the target well is injected with energy storage fluid. After all target wells are fully energized, the pressure distribution of the simulated well shut-in time is 0 days, 10 days, 20 days, 30 days, and 60 days. Figure 2 , and saturation distribution. Combined with the original perforation layer and the vertical distribution characteristics of the remaining oil, it is decided whether additional perforation is needed.

[0096] Step 5: Establish a coupling model, and simulate the expansion of hydraulic fractures caused by repeated fracturing of the group through the coupling model. According to the reservoir transformation volume of repeated fracturing, the water injection pressure recovery degree and the soaking time are optimized, and the first pressure recovery degree and the first soaking time are simulated. Then, according to the first pressure recovery degree and the first soaking time, the fracture length, fracture width and fracture height of the fracturing fracture corresponding to the first pressure recovery degree and the first soaking time are calculated, and the current reservoir transformation volume is obtained by the formula reservoir transformation volume (SRV) = fracture width × fracture height × fracture length. Find the first value of the current reservoir transformation volume, and go to step 3. On the basis of the first value, narrow the range of the pressure recovery degree and the soaking time, and find the second value of the current reservoir transformation volume. If the second value is greater than the first value, the first value is the optimal value. If the second value is not greater than the first value, the second value is the optimal value. It is iterated in this way until the interval of the pressure recovery degree is 1% and the time interval is 1 day, and the iteration ends.

[0097] Based on the different pressure recovery degrees and soaking time schemes in step 3 and step 4, the reservoir stimulation volume (SRV) under different schemes is obtained by simulation based on the coupling model on the basis of these schemes. The optimal value each time is the maximum value of the reservoir stimulation volume under the current different pressure recovery degrees and soaking time schemes. Then continue to narrow the range of pressure recovery degrees and soaking time near the optimal value. If the optimal value of the current step is greater than the optimal value of the previous step, take the value of the previous step. Otherwise, take the optimal value of the current step. The iteration ends until the interval of pressure recovery degree is 1% and the time interval is 1 day.

[0098] The establishment of the coupled model in step 5 includes:

[0099] Step i: Collect target area data and establish a three-dimensional geological model; the target area data includes well logging curves and fault data of the target area.

[0100] The dynamic and static basic data of the target area are collected, verified, screened and processed, and a high-precision three-dimensional geological model is established using Petrel software. First, the well data of the target area, such as logging curves and fault data, are used for geological modeling through Petrel software. The reservoir is divided into two small layers. The first small layer has a model step of 20m×20m×0.5m, which can be subdivided into 97 layers vertically, and the number of model grids is 1.6 million; the second small layer has a model step of 20m×20m×0.5m, which can be subdivided into 90 layers vertically, and the number of model grids is 2 million.

[0101] Step II: Establish a fluid-solid-thermal coupling model. According to the initial hydraulic fracturing construction data of the old well and the microseismic monitoring data, use the fluid-solid-thermal coupling model to obtain the crack morphology and parameters of the initial fracturing in the old well. Then establish an embedded discrete fracture model. The crack morphology and parameters of the initial fracturing in the old well are embedded into the three-dimensional geological model through the embedded discrete fracture model. The initial fracturing cracks in the old well include fracture height, fracture length and fracture width.

[0102] Fluid-structure thermal coupling models include:

[0103] The stress equilibrium equation of porous elastic rock is:

[0104]

[0105] In the above formula, g(d) is the attenuation function, g(d) = k + (1-k) (1-d) 2 , k is equal to 1×10 -9 , d is the phase field variable; is tensile stress; is the compressive stress; σ0 is the initial stress; α(d) is the Biot coefficient, K is the rock bulk modulus of porous media, K s is the bulk modulus of rock skeleton particles; Ι is the unit tensor; p is the pore fluid pressure;

[0106] The seepage balance equation of porous elastic rock is:

[0107]

[0108] In the above formula, p is the pore fluid pressure; M(d) is the Biot modulus, K f is the bulk modulus of the fluid, K s is the bulk modulus of rock skeleton particles, φ is the porosity of rock; α(d) is the Biot coefficient, K is the rock bulk modulus of the porous medium; ε ii is the volume strain; k is the permeability of the reservoir; μ f is the viscosity of the fluid, q f is the injection volume;

[0109] The temperature balance equation of poroelastic rock is:

[0110]

[0111] In the above formula, (ρC) eff is the heat capacity of the porous medium containing the fluid, (ρC) eff =φρ l C l+(1-φ)ρ s C s , φ is the porosity of the rock, ρ l Density of the fluid, C l is the specific heat capacity of the fluid, ρ s is the density of rock, C s is the specific heat capacity of rock; T is the temperature of the reservoir; λ eff is the average thermal conductivity, λ eff =φλ l +(1-φ)λ s ,λ l is the thermal conductivity of the fluid, λ s is the thermal conductivity of rock; ν is the velocity of fluid; Q is the heat source / sink;

[0112] The phase field evolution equation of poroelastic rock is:

[0113]

[0114] In the above formula, l0 is the length scale parameter; G c is the maximum energy release rate; d is the phase field variable; H is the maximum value of the tensile strain energy density, k is equal to 1×10 -9 , is the tensile strain energy density, σ0 is the initial stress, ε is the strain tensor, p is the pore fluid pressure, φ0 is the initial rock porosity, K f is the bulk modulus of the fluid, K s is the bulk modulus of rock skeleton particles, and K is the rock bulk modulus of porous media.

[0115] According to the initial hydraulic fracturing construction data of old wells and microseismic monitoring data, the fluid-solid-thermal coupling model was used to obtain the initial fracturing crack morphology and parameters, and the obtained hydraulic fracture morphology and parameters were embedded into the three-dimensional geological model through an embedded discrete fracture model.

[0116] The hydraulic fracture expansion of the group's repeated fracturing wells is simulated by the fluid-solid-thermal coupling model, and the water injection pressure recovery degree and the well shut-in time are optimized according to the re-fracturing transformation volume. When the pressure recovery degree of 100% and the well shut-in time of 30 days are simulated, the first value of the reservoir transformation volume of repeated fracturing is SRV1, and the process proceeds to step 3. The pressure recovery degrees of 90%, 95%, and 100% and the well shut-in of 10 days, 15 days, 30 days, 45 days, and 60 days after water injection are implemented in the target area. After obtaining the second value SRV2 of the current reservoir transformation volume, the process continues to proceed to step 3 and iterates until the interval of the pressure recovery degree is 1% and the time interval is 1 day. After the iteration is completed, the pressure recovery degree and the well shut-in time corresponding to the optimal solution of the reservoir transformation volume in the target area are determined.

[0117] Example 2: Through the method of Example 1, the optimal solution for the reservoir transformation volume of the target area is that the pressure recovery degree is 100%, the well soaking time is 25 days, and the target area is subjected to group repeated fracturing according to the global optimal solution, such as Figure 3 As shown, a complex fracture network of vertical wells is formed.

[0118] The above technical features constitute the embodiments of the present invention, which have strong adaptability and implementation effect. Non-essential technical features can be added or reduced according to actual needs to meet the requirements of different situations.

Claims

1. A method for calculating the water injection pressure recovery degree and well soaking time of an old well energy storage group, characterized in that The steps include: Step 1: Establish a fluid-solid coupling seepage model for multiphase flow, conduct historical matching of the production performance of the oil well before repeated fracturing, obtain the four-dimensional geostress and formation pressure distribution of the reservoir, and calculate the remaining oil reserves; Step 2: According to the threshold interval of the remaining oil reserves in the area, determine the group wells to be repeatedly fractured. If the remaining oil reserves are within the threshold interval, continue; if the remaining oil reserves are not within the threshold interval, stop; Step 3: Calculate the formation deficit of a single well based on the production characteristics of the target group wells before water injection, including cumulative production, liquid consumption and formation pressure, and calculate the injection volume based on the pressure recovery degrees F1, F2 and F3; Step 4: According to the injection volume in step 3, inject the energy storage fluid into each target well. After all target group wells have completed the energy injection, simulate the pressure distribution diagram and water saturation distribution under the well shut-in time of T1, T2, T3, and T4; Step 5: Establish a coupling model, and simulate the expansion of hydraulic fractures caused by repeated fracturing of the group through the coupling model. According to the reservoir transformation volume of repeated fracturing, the degree of water injection pressure recovery and the time of well soaking are optimized, and the first pressure recovery degree and the first time of well soaking are simulated to find the first value of the current reservoir transformation volume, and then go to step 3. On the basis of the first value, narrow the range of the pressure recovery degree and the time of well soaking to find the second value of the current reservoir transformation volume. If the second value is greater than the first value, the first value is the optimal value. If the second value is not greater than the first value, the second value is the optimal value. Repeat this process until the interval of pressure recovery degree is 1% and the time interval is 1 day, and then the iteration ends.

2. The method for determining the water injection pressure recovery degree and well soaking time of an old well energy storage group according to claim 1, characterized in that The establishment of the coupled model in step 5 includes: Step i: Collect data of the target area and establish a three-dimensional geological model; Step II: Establish a fluid-solid-thermal coupling model. According to the initial hydraulic fracturing construction data of the old well and the microseismic monitoring data, use the fluid-solid-thermal coupling model to obtain the crack morphology and parameters of the initial fracturing in the old well. Then establish an embedded discrete fracture model. The crack morphology and parameters of the initial fracturing in the old well are embedded into the three-dimensional geological model through the embedded discrete fracture model. The initial fracturing cracks in the old well include fracture height, fracture length and fracture width.

3. The method for determining the water injection pressure recovery degree and well soaking time of an old well energy storage group according to claim 2, characterized in that The fluid-structure thermal coupling model in step ii includes: The stress equilibrium equation of porous elastic rock is: In the above formula, g(d) is the attenuation function, g(d) = k + (1-k) (1-d) 2 , k is equal to 1×10 -9 , d is the phase field variable; is tensile stress; is the compressive stress; σ0 is the initial stress; α(d) is the Biot coefficient, K is the rock bulk modulus of porous media, K s is the bulk modulus of rock skeleton particles; Ι is the unit tensor; p is the pore fluid pressure; The seepage balance equation of porous elastic rock is: In the above formula, p is the pore fluid pressure; M(d) is the Biot modulus, K f is the bulk modulus of the fluid, K s is the bulk modulus of rock skeleton particles, φ is the porosity of rock; α(d) is the Biot coefficient, K is the rock bulk modulus of the porous medium; ε ii is the volume strain; k is the permeability of the reservoir; μ f is the viscosity of the fluid, q f is the injection volume; The temperature balance equation of porous elastic rock is: In the above formula, (ρC) eff is the heat capacity of the porous medium containing the fluid, (ρC) eff =φρ l C l +(1-φ)ρ s C s , φ is the porosity of the rock, ρ l Density of the fluid, C l is the specific heat capacity of the fluid, ρ s is the density of rock, C s is the specific heat capacity of rock; T is the temperature of the reservoir; λ eff is the average thermal conductivity, λ eff =φλ l +(1-φ)λ s ,λ l is the thermal conductivity of the fluid, λ s is the thermal conductivity of rock; ν is the velocity of fluid; Q is the heat source / sink; The phase field evolution equation of poroelastic rock is: In the above formula, l0 is the length scale parameter; G c is the maximum energy release rate; d is the phase field variable; H is the maximum value of the tensile strain energy density, k is equal to 1×10 -9 , is the tensile strain energy density, σ0 is the initial stress, ε is the strain tensor, p is the pore fluid pressure, φ0 is the initial rock porosity, K f is the bulk modulus of the fluid, K s is the bulk modulus of rock skeleton particles, K is the rock bulk modulus of porous media; Or / and, in step i, the target area data includes well logging curves and fault data of the target area.

4. The method for restoring the water injection pressure and the soaking time of the old well energy storage group according to claim 1, 2 or 3, characterized in that The fluid-solid coupling model of the multiphase flow described in step 1 includes: The calculation equation of ground stress is as follows: In the above formula, σ eff is the effective stress; α is the biot pore elastic coefficient; p is the pore fluid pressure; The saturation normalization equation is: S o +S w =0 In the above formula, S o is the oil saturation; S w is water saturation; The capillary pressure equation is: p c (S w )=p0-p w In the above formula, p c is the capillary pressure; S w is water saturation; p0 is oil pressure, p w For water pressure. The calculation equation of formation pressure is: In the above formula, ρ o is the viscosity of the oil; v o is the oil flow rate, K ro is the relative permeability of oil, k is the permeability of the reservoir, p0 is the oil pressure, μ0 is the oil phase viscosity; S o is the oil saturation; q o is the oil production; The calculation model of water saturation is as follows: In the above formula, ρ w is the viscosity of water; v w is the water flow velocity, K rw is the relative permeability of water, k is the permeability of the reservoir, p w is the water pressure, μ w is the viscosity of the water phase; S w is water saturation; q w The amount of water collected.

5. The method for restoring the water injection pressure and the well soaking time of the old well energy storage group according to claim 1, 2 or 3, characterized in that The remaining oil reserves in step 1 are calculated as: In the above formula, D po (t) is the remaining oil reserves of the target group wells from the start of production to time t; D Ro is the original crude oil reserves; q i is the oil production of the i-th well at time t, i = 1, 2, 3, ..., n, and n is the number of repeated fracturing wells of the target well.

6. The method for determining the water injection pressure recovery degree and well soaking time of an old well energy storage group according to claim 4, characterized in that The remaining oil reserves in step 1 are calculated as: In the above formula, D po (t) is the remaining oil reserves of the target group wells from the start of production to time t; D Ro is the original crude oil reserves; q i is the oil production of the i-th well at time t, i = 1, 2, 3, ..., n, and n is the number of repeated fracturing wells of the target well.

7. The method for restoring the water injection pressure and the soaking time of the old well energy storage group according to claim 1, 2, 3 or 6, characterized in that The single well formation deficit volume (m 3 ) = Cumulative liquid production (m 3 )-Liquid volume (m 3 ); The pressure recovery degree is: Pressure recovery degree (%) = a × injection volume (m 3 )+b In the above formula, a and b are fitting values.

8. The method for determining the water injection pressure recovery degree and well soaking time of an old well energy storage group according to claim 4, characterized in that The single well formation deficit volume (m 3 ) = Cumulative liquid production (m 3 )-Liquid volume (m 3 ); The pressure recovery degree is: Pressure recovery degree (%) = a × injection volume (m 3 )+b In the above formula, a and b are fitting values.

9. The method for determining the water injection pressure recovery degree and well soaking time of an old well energy storage group according to claim 5, characterized in that The pressure recovery degree described in step 5 is: Pressure recovery degree (%) = a × injection volume (m 3 )+b In the above formula, a and b are fitting values.

Images