Horizontal well integrated acidification method considering spatial and temporal evolution law of permeability

Abstract

The application discloses a horizontal well integrated acidification method considering the space-time evolution law of permeability and relates to the technical field of oil and gas development, which comprises the following steps: collecting stratum data of a target horizontal well region, dividing the target horizontal well into wellbore units, stratum units and time units respectively, sequentially calculating the equivalent elliptical invasion radius and equivalent wellbore radius of drilling fluid in each stratum unit, the stratum invasion zone permeability after the injection of drilling fluid, the local skin factor of each stratum unit, the comprehensive skin factor, the temporary plugging agent filter cake skin factor and the permeability of the stratum at any time, combining the above results, calculating the flow of any stratum unit at any time after the injection of drilling fluid and temporary plugging acidification, and obtaining the drilling fluid and acid liquid injection amount of the stratum unit in a specific time range; the application considers the difference of the permeability damage zone of the horizontal well, on the basis of the specific pollution of the drilling fluid to the horizontal section stratum, obtains a relatively optimal result of the acidification operation, and fully improves the quality of the acidification operation.

Description

Technical Field

[0001] This invention relates to the field of oil and gas development technology, specifically to an integrated horizontal well acidizing method that takes into account the spatiotemporal evolution of permeability. Background Technology

[0002] Horizontal wells offer advantages such as increased contact area with the reservoir, reduced oil and gas flow resistance, improved production dynamics, and increased oil and gas well production, making horizontal well development technology highly favored. However, during drilling and completion processes in both onshore and offshore oil and gas development, solid particles and liquid phases in the drilling fluid can extensively infiltrate the formation surrounding the wellbore, maintaining prolonged contact with the formation, increasing oil and gas flow resistance, and causing near-wellbore contamination. Furthermore, the longer the horizontal wellbore unit, the greater the flow resistance of the drilling fluid, leading to an increase in the pressure differential acting on the oil and gas reservoir and exacerbating reservoir damage. Therefore, without targeted reservoir stimulation measures during drilling and completion, it will be difficult to achieve effective development of the reservoir where the horizontal well is located.

[0003] In classic horizontal well contamination zone calculation models, the damage around the horizontal wellbore is typically considered a cylindrical region of impaired permeability. Later, considering formation anisotropy, Frick and Economides et al. viewed the horizontal contamination zone as a continuous elliptical frustum-shaped region that linearly decreases from the heel to the toe. However, these models fail to account for the fact that, in both onshore and offshore oil and gas development, significant differences in the physical properties of the horizontal section can lead to non-uniform variations in permeability damage along the wellbore axis. Current methods for temporary plugging and acidizing in horizontal wells largely rely on classic horizontal well contamination zone calculation models to determine acidizing dosage, failing to accurately consider the spatiotemporal evolution of formation properties such as porosity and permeability during the process. This negatively impacts the effectiveness of acidizing. Furthermore, current temporary plugging and acidizing techniques lack a horizontal comparison between the drilling fluid injection volume in the horizontal section and the acid injection volume after plugging and acidizing, making it difficult to create a direct comparison between the non-uniform contamination status of the horizontal section after drilling fluid injection and the acidizing improvement effect. Summary of the Invention

[0004] In view of this, the present invention provides an integrated horizontal well acidizing method that considers the spatiotemporal evolution of permeability. Addressing the problems existing in the temporary plugging acidizing process for horizontal wells in carbonate reservoirs, this method can accurately characterize the morphology of the contaminated zone in the horizontal well unit, accurately understand the spatiotemporal evolution of reservoir properties before and after temporary plugging acidizing, and simulate the flow distribution in the formation at different times to guide acidizing operations. This effectively improves the accuracy of temporary plugging acidizing in the well unit, expands reservoir development, and enhances the quality of onshore and offshore oil and gas development operations.

[0005] The technical solution of this invention is an integrated horizontal well acidizing method that considers the spatiotemporal evolution of permeability, comprising the following steps:

[0006] Step S1: Collect formation data for the target horizontal well area, and divide the target horizontal well into wellbore units, formation units, and time units respectively;

[0007] Step S2: Calculate the equivalent elliptical invasion radius and equivalent wellbore radius of the drilling fluid in each formation unit;

[0008] Step S3: Simulate drilling fluid injection and calculate the permeability of the formation invasion zone after drilling fluid injection;

[0009] Step S4: Calculate the local skin factor for each formation unit, and the comprehensive skin factor associated with drilling fluid formation contamination;

[0010] Step S5: Calculate the skin factor of the temporary plugging agent filter cake, taking into account the effect of the accumulation of the temporary plugging agent in the formation unit;

[0011] Step S6: Calculate the formation permeability at any given time by combining the acid concentration during the temporary plugging acidizing process;

[0012] Step S7: Based on the acid fluid combination system, simulate the flow of acid fluid in the horizontal well and calculate the injection pressure of the wellbore unit during acidizing;

[0013] Step S8: Combining the comprehensive skin factor, the skin factor of the temporary plugging agent filter cake, and the injection pressure of each wellbore unit during acidizing, calculate the flow rate of any formation unit at any time after drilling fluid injection and after temporary plugging acidizing, and obtain the drilling fluid and acid injection volume of the formation unit within a specific time range.

[0014] The technical effects of this invention are:

[0015] (1) Based on the drilling fluid leakage data of different horizontal sections monitored in the field and the equal volume conversion method, this invention accurately obtains the drilling fluid contamination depth, local skin factor and comprehensive skin factor when considering the difference in permeability damage zone in horizontal wells, and calculates the injection volume of drilling fluid in formations of different horizontal sections. Based on clarifying the specific contamination of drilling fluid in formations of horizontal sections, it obtains the better results for implementing acidizing operations, which fully improves the quality of acidizing operations.

[0016] (2) The difference in formation flow caused by changes in permeability during the temporary plugging acidizing process was considered, and the formation flow of different horizontal sections before and after the temporary plugging acidizing was simulated, providing a valuable reference for achieving uniform acidizing stimulation of horizontal wells. Attached Figure Description

[0017] To more clearly illustrate the technical solutions of the embodiments of the present invention, the accompanying drawings used in the embodiments will be briefly introduced below.

[0018] Figure 1This is a diagram showing the equivalent permeability of the intrusion zone of the target well after drilling fluid injection into the formation, as described in this embodiment of the invention.

[0019] Figure 2 This is a diagram showing the formation permeability of the target well after temporary plugging and acidizing in an embodiment of the present invention.

[0020] Figure 3 This is a diagram showing the formation fluid absorption profile of the target well before and after temporary plugging and acidizing in an embodiment of the present invention.

[0021] Figure 4 This is a comparison chart showing the cumulative acid ingress into the formation when the target well uses temporary plugging acidizing technology and when it does not. Detailed Implementation

[0022] The present invention will be further described in detail below with reference to the embodiments and accompanying drawings.

[0023] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. The described embodiments are only some, not all, of the embodiments of the present invention. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0024] See Figure 1 A horizontal well integrated acidizing method considering the spatiotemporal evolution of permeability includes the following steps:

[0025] Step S1: Collect formation data for the target horizontal well area, and divide the target horizontal well into wellbore units, formation units, and time units respectively;

[0026] The wellbore unit division operation involves directly dividing the horizontal section of the target horizontal well into multiple wellbore units of length Δx on the x-axis. The formation unit size is consistent with the wellbore unit size. The time unit is obtained by dividing the total consumption time of the temporary plugging acidizing into multiple segments. Each segment is a time unit, and the time point at the end of the segment corresponds to the time of that time unit.

[0027] Step S2: Calculate the equivalent elliptical invasion radius and equivalent wellbore radius of the drilling fluid in each formation unit.

[0028] Based on the drilling fluid leakage data monitored on-site, the horizontal invasion radius of drilling fluid in each formation unit was calculated using the equal volume conversion method. Anisotropic formations were then converted into isotropic formations using conformal transformation to obtain the equivalent elliptical invasion radius and equivalent wellbore radius of the drilling fluid.

[0029] The method for calculating the equivalent elliptical intrusion radius of each stratigraphic unit is shown in Equation (1):

[0030]

[0031] In equation (1), r d Let m be the radius of the equivalent ellipse intrusion; r be the radius of the intrusion. w I is the radius of the horizontal wellbore, in meters. ani r is the permeability anisotropy coefficient, dimensionless; h Let the horizontal intrusion radius be m;

[0032] In the calculation, it is assumed that the reservoir pore volume within the contaminated zone is entirely occupied by drilling fluid filtrate. Therefore, the reservoir pore volume in that contaminated zone is equal to the drilling fluid filtrate loss in that zone, satisfying the following formula:

[0033]

[0034] In equations (11) and (12), Δx i Φ is the length of wellbore element i, in meters; i Q represents the porosity of a formation unit, in %; i The working fluid filtration loss, m 3 ;k h —Horizontal formation permeability, mD; k v —Vertical permeability of the formation, mD.

[0035] The horizontal intrusion radius can be calculated according to equation (11), as shown in equation (13):

[0036]

[0037] Based on this, the calculation method for the equivalent wellbore radius is shown in equation (2):

[0038]

[0039] In equation (2), r we Let be the equivalent wellbore radius, in meters (m).

[0040] Step S3: Simulate drilling fluid injection and calculate the permeability of the formation invasion zone after drilling fluid injection.

[0041] Next, after simulating drilling fluid injection, the equivalent elliptical invasion radius is substituted into the equivalent permeability formula of the invasion zone to calculate the formation invasion zone permeability. The calculation method of formation invasion zone permeability after drilling fluid injection is shown in equation (3):

[0042]

[0043] In equation (3), k dFor the intrusive zone of the formation, mD; k i 0 The original formation permeability is given by mD and k. c For the permeability of the flushing belt, mD; r c The wellbore radius, in meters, is the radius after subtracting the mud cake thickness; Ei is an exponential integral function.

[0044] Step S4: Calculate the local skin factor for each formation unit, as well as the comprehensive skin factor associated with drilling fluid formation contamination.

[0045] After drilling fluid injection, based on the original formation permeability, intrusion zone permeability, equivalent elliptical intrusion radius, and equivalent wellbore radius, and considering formation contamination caused by drilling fluid, the local skin factor of each formation unit is calculated according to the Hawkins formula. The specific calculation method is shown in Equation (4):

[0046]

[0047] In equation (4), S i These are local epidermal factors of each stratigraphic unit, and are dimensionless.

[0048] After drilling fluid is introduced into a formation unit, the pollution status of the formation by the drilling fluid needs to be considered. In this case, the comprehensive skin factor after drilling fluid pollution of the formation is calculated as shown in Equation (5):

[0049]

[0050] In equation (5), S e The epidermal factor is dimensionless; L is the length of the horizontal segment, in meters; Δx i is the length of wellbore unit i, in meters; h is the reservoir thickness, in meters; N is the formation unit number.

[0051] Step S5: Calculate the temporary plugging agent filter cake skin factor, taking into account the effect of temporary plugging agent accumulation in the formation unit.

[0052] The temporary plugging method used in this invention is fiber temporary plugging. During the injection of the temporary plugging fluid, the fibers will continuously accumulate at each formation unit. The time period j to n is divided into jj parts, and the fiber filter cake skin factor accumulated in each formation unit is shown in formula (6):

[0053]

[0054] In equation (6), S fc,i , where is the surface factor of the filter cake of the temporary plugging agent, dimensionless; jj is the j-th secondary time unit divided within the j-th time unit; Let mD be the permeability of the formation unit in the j-th time unit; k fc,i Φ is the permeability of the filter cake containing the temporary plugging agent, in mD;fc,i Porosity of the temporary plugging agent filter cake, %; Let m be the fiber accumulation volume within the jj-th second-order time unit. 3 n represents the number of time units.

[0055] Step S6: Calculate the formation permeability at any given time by combining the acid concentration during the temporary plugging acidizing process.

[0056] During temporary plugging acidizing, as the acid reacts with the rock, the pore structure of the formation unit is altered, and both porosity and permeability change. These changes will cause variations in the filter cake surface factor, thereby altering the formation flow rate after temporary plugging acidizing. This also directly leads to differences in the formation fluid uptake profile during the temporary plugging acidizing process. Therefore, it is necessary to obtain the acid mass concentration in the formation unit based on the Darcy-scale model of carbonate matrix acidizing, then calculate the porosity distribution in the formation unit at any given time, and finally calculate the permeability at any given time.

[0057] The method for determining the acid mass concentration in each stratigraphic unit based on the Darcy-scale model of carbonate matrix acidification is shown in equation (71):

[0058]

[0059] In equation (71): C l,i The mass concentration of the acid solution is kg / m³. 3 ; r represents the radial position in cylindrical coordinates, m; u r D represents the radial upward Darcy velocity, in m / s; e m is the diffusion coefficient. 2 / s; D is the formation permeability, mD; μ is the acid viscosity, Pa·s; Porosity after formation damage, %; α v For specific surface area, m 2 / m 3 ;k c K is the mass transfer coefficient, m / s; s is the reaction rate constant, in m / s.

[0060] According to the Dirichlet boundary conditions, the injection velocity at the inlet is a constant u0, the acid concentration is C0, the pressure at the outlet is a constant, and the acid flow rate is 0. Assuming the initial acid concentration is 0 and the initial porosity distribution is the porosity value before temporary plugging and acidizing after drilling fluid injection, the initial and boundary conditions are specifically shown in equations (72) and (73):

[0061]

[0062] In equations (72) and (73), u0 is the injection velocity, m3 / s;p p The original formation pressure is Pa; Φ i 0 This represents the original porosity, %.

[0063] Furthermore, during the acidizing process, as the acid is continuously consumed, it dissolves the formation rocks and minerals, causing changes in porosity. By discretizing the porosity model and substituting the acid mass concentration into the discretized model, the porosity distribution in the formation unit at any time during the temporary plugging acidizing process can be calculated.

[0064]

[0065] In the formula: C l,i The mass concentration of the acid solution is kg / m³. 3 ; Let be the porosity at formation element i at time j, in %; ρ represents the porosity at formation unit i at time j-1, in %; s Density of rock, kg / m³ 3 α represents the mass of rock dissolved per unit mass of acid solution, in kg / kg.

[0066] Since the porosity increases after mineral dissolution, leading to an increase in formation permeability, assuming that the change in permeability is entirely determined by the direct influence of porosity, the original porosity and the porosity of the formation unit at time j are substituted into the empirical formula for pore structure to calculate the permeability at any time during the temporary plugging acidizing process:

[0067]

[0068] In equation (7), Let Φ be the permeability of the formation unit at time j, in mD; i 0 The original porosity of the formation unit, in %. denoted as porosity (%), representing the porosity of the formation unit in the j-th time unit; δ is an empirical constant with a value of 1; β is an empirical constant with a value of 1.2.

[0069] Step S7: Based on the acid fluid combination system, simulate the flow of acid fluid in the horizontal well and calculate the injection pressure of the wellbore unit during acidizing;

[0070] The simulated fluid flow in the wellbore is performed by injecting fluid according to the combination of "acid-fracturing fluid-temporary plugging fluid-fracturing fluid". Under this condition, the injection pressure is calculated based on the reservoir pressure of the horizontal well at the initial moment, the hydraulic fracture width of each wellbore unit, the hydraulic fracture spacing, the combined fluid density, and the flow velocity of the combined fluid at the wellbore unit. The calculation is based on the frictional pressure drop and acceleration pressure drop formulas in the perforated and non-perforated areas of the horizontal wellbore variable mass flow model, as shown in Equation (8).

[0071]

[0072] In equation (8), p w,i Inject pressure into the wellbore unit, MPa; p p f is the formation pressure where the horizontal well is located, in MPa; p,i Δl is the wellbore friction factor in the perforated area, dimensionless; i d is the width of the hydraulic fracture (m); d is the diameter of the horizontal wellbore (m); ρ is the density of the acid-fluid combination system (kg / m³). 3 ;v i The fluid velocity of the acid-liquid composite system at wellbore unit i is given in m / s; Δx i Let v be the length of wellbore element i, in meters; i+1 v is the fluid velocity of the acid mixture system at wellbore unit i+1, in m / s; i-1 f is the fluid velocity of the acid mixture system at wellbore unit i-1, in m / s; w,i The friction factor of the wellbore wall in the unperforated area is dimensionless.

[0073] Step S8: Combining the comprehensive skin factor, the skin factor of the temporary plugging agent filter cake, and the injection pressure of each wellbore unit during acidizing, calculate the flow rate of any formation unit at any time after drilling fluid injection and after temporary plugging acidizing, and obtain the drilling fluid and acid injection volume of the formation unit within a specific time range.

[0074] As the fluid flows through the wellbore, it is continuously filtered out into the formation. To simulate fluid flow in the formation, the comprehensive skin factor, fiber cake skin factor, and pressure of each wellbore unit obtained in the above steps are substituted into the formation flow equation. By coupling these three parameters, the flow rates of different formation units after drilling fluid injection and after temporary plugging and acidizing can be calculated separately. The initial conditions for the flow process are that the wellbore pressure and formation pressure are the same, the flow rate in the wellbore is zero, and the boundary conditions are the injection situation at the heel of the horizontal section as the boundary conditions of the model, assuming that the fluid does not flow at the toe of the horizontal section.

[0075] In this case, when drilling fluid is injected, the formation unit is not temporarily plugged with a plugging agent, and the flow rate is not affected by the plugging agent. At this time, the fiber filter cake skin factor in equations (91) and (92) is 0. Substituting the two equations into equation (9), the flow rate of different formation units after drilling fluid injection is calculated. At this time, q r,i This represents the flow rate of any formation unit at any time after drilling fluid injection.

[0076] After temporary plugging and acidizing, the flow rate calculation for different formation units must take into account the influence of the fiber plugging agent. At this time, the fiber filter cake skin factor in equations (91) and (92) is not 0. Similarly, substituting the two equations into equation (9), q r,i Let f represent the flow rate of any formation unit at any time after temporary plugging acidizing. Calculate the flow rates of different formation units after temporary plugging acidizing:

[0077] q r,i =a(p w,i -p e )+b (9)

[0078] In equation (9), q r,i Let m be the flow rate of any formation unit at any time after drilling fluid injection or temporary plugging and acidizing. 3 / s;p e The pressure at the outer boundary of the reservoir is MPa.

[0079] The expression for 'a' is shown in equation (91):

[0080]

[0081] In equation (91), μ is the fluid viscosity in the formation unit at the current time, in mPa·s; η is the pressure conductivity coefficient, in MPa. -1 ; t represents the time corresponding to the current time unit; t n-1 The time corresponding to the previous time unit, t and t n-1 The difference is the length of the current time unit.

[0082] The expression for b is shown in equation (92):

[0083]

[0084] In equation (92), Let m be the flow rate at the i-th stratigraphic unit at time j. 3 / s;q j-1 r,i Let m be the flow rate at the i-th formation unit at time j-1. 3 / s;q n-1 r,i Let m be the flow rate at the i-th formation unit at time n-1. 3 / s.

[0085] This allows for the calculation of the flow rates of different formation units at any given time after drilling fluid injection and temporary plugging acidizing. The drilling fluid and acid injection volume of that formation unit at the corresponding time is equal to the flow rates of different formation units at any given time after drilling fluid injection and temporary plugging acidizing. The drilling fluid and acid injection volume of a formation unit within a specific time range is obtained by summing the drilling fluid and acid injection volumes of the formation units at each time within that time range. During the acidizing process, the injection of drilling fluid and acid at any given time is performed according to the results calculated above.

[0086] Example:

[0087] Taking a horizontal well Y in a carbonate oil and gas block in southern Sichuan as an example, the method described in this invention is used to design a multi-stage temporary plugging acidizing construction pumping procedure, clarify the changes in formation physical parameters during the integrated temporary plugging acidizing process, calculate the fluid inflow rate in the horizontal well section of the formation, and analyze the effect of temporary plugging acidizing technology on uniform acidizing and unplugging of the reservoir.

[0088] Various process parameters are shown in Table 1, and the acidification pumping procedure is shown in Table 2.

[0089] Table 1 shows the various process parameters used to calculate the acidification effect in the embodiments.

[0090]

[0091] Table 2 shows the pumping procedure for multi-stage temporary acid plugging in the embodiments.

[0092]

[0093] Figure 1 The equivalent permeability of the intrusion zone after drilling fluid injection into the formation of Well Y is shown. Due to the heterogeneity of the formation, the equivalent permeability varies greatly at different locations. Under such circumstances, direct acidizing will result in very uneven acid distribution, serious acid waste, and failure to achieve the expected formation stimulation effect.

[0094] Figure 2 To assess the formation permeability after temporary plugging and acidizing of Well Y, the use of fiber-based temporary plugging followed by acidizing significantly reduced the permeability differences in the formation, improving its heterogeneity. Furthermore, the uniform permeability distribution means that the amount of acid introduced into the formation is more even, thus significantly enhancing the acidizing effect.

[0095] Figure 3The figures show the formation fluid absorption profiles before and after temporary plugging and acidizing in Well Y. The information in the figures indicates that the fluid absorption profile fluctuates greatly during the drilling fluid injection stage, indicating severe non-uniform contamination of the formation. This is an inevitable result of the differences in formation permeability. The curves during the temporary plugging and acidizing stage show that, under the condition of non-uniform formation contamination, fiber-based temporary plugging and acidizing can effectively adjust the formation fluid absorption profile and achieve the goal of uniform formation acidizing.

[0096] Figure 4 The cumulative acid ingress in the formation before and after using temporary plugging acidizing technology in Well Y was higher in the ranges of 250-320m, 400-500m, around 700m, and 800-900m than in other horizontal well sections. This indicates that the uneven acid ingress in the formation was caused by heterogeneity, with more acid in high-permeability layers and less in low-permeability layers. After using temporary plugging acidizing technology, the cumulative acid ingress in low-permeability layers increased significantly, while the cumulative acid ingress in high-permeability layers decreased to some extent. The acid ingress in each horizontal well section was more uniform, and the formation acidizing effect was obvious, effectively addressing the non-uniform contamination caused by the large spatial and temporal differences in permeability in the formation.

[0097] The above description is merely a preferred embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any variations or substitutions that can be easily conceived by those skilled in the art within the technical scope disclosed in the embodiments of the present invention should be included within the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be determined by the scope of the claims.

Claims

1. A horizontal well integrated acidification method considering the spatiotemporal evolution law of permeability, characterized in that, The method comprises the following steps: Step S1: Collecting formation data of the target horizontal well region, and dividing the target horizontal well into wellbore units, formation units and time units respectively; Step S2: Calculating the equivalent elliptical invasion radius and the equivalent wellbore radius of the drilling fluid in each formation unit; Step S3: Simulating drilling fluid injection, and calculating the formation invasion zone permeability after drilling fluid injection; Step S4: Calculating the local skin factor of each formation unit, and the comprehensive skin factor related to drilling fluid formation pollution; Step S5: Calculating the temporary plugging agent filter cake skin factor considering the accumulation of temporary plugging agent in the formation unit; Step S6: Calculating the formation permeability at any time in combination with the acid concentration in the temporary plugging acidizing process; Step S7: Based on the acid fluid combination system, simulating the flow of acid fluid in the horizontal well, and calculating the injection pressure of the wellbore unit during acidizing; Step S8: In combination with the comprehensive skin factor, the temporary plugging agent filter cake skin factor and the injection pressure of each wellbore unit during acidizing, the flow of any formation unit at any time after drilling fluid injection and temporary plugging acidizing is calculated, and the drilling fluid and acid injection amount of the formation unit in a specific time range is obtained; The calculation method of the local skin factor of each formation unit is shown in formula (4): （4） In formula (4), S i is the local skin factor for each formation zone, dimensionless; k d is the permeability of the invaded zone, mD; k i 0 is the original formation permeability, mD; r w is the horizontal wellbore radius, m; I ani is the permeability anisotropy factor, dimensionless; r h is the horizontal invaded radius, m; The calculation method of the comprehensive skin factor is shown in formula (5): （5） In formula (5), S e is a dimensionless skin factor; L is a horizontal section length, m; Δ x i is a length of the wellbore unit i , m; h is a reservoir thickness, m; N is a formation unit number; The temporary plugging agent in step S5 is fiber, and the calculation method of the temporary plugging agent filter cake skin factor is shown in formula (6): （6） In formula (6), is a skin factor for the temporary plugging agent filter cake, dimensionless; The calculation method of the flow of any formation unit at any time after drilling fluid injection and temporary plugging acidizing is shown in formula (9): is the jth secondary time unit divided in the jth time unit; is the permeability of the formation unit in the jth time unit, mD; is the permeability of the temporary plugging agent filter cake, mD; is the porosity of the temporary plugging agent filter cake, %; is the fiber accumulation volume in the jth secondary time unit, m 3 ; n is the number of time units; The calculation method of the equivalent elliptical invasion radius of each formation unit in step S2 is shown in formula (1): （9） In formula (9), q r,i is the flow rate of any formation unit at any time after the drilling fluid injection or after the temporary plugging acidification, m 3 / s; p e is the reservoir outer boundary pressure, MPa; wherein a The expression of (91) is shown as equation (92). （91） In formula (91), The calculation method of the equivalent wellbore radius is shown in formula (2): is the fluid viscosity in the formation unit at the current time, mPa-s; The calculation method of the formation invasion zone permeability after drilling fluid injection in step S3 is shown in formula (3): is the derivative pressure coefficient, MPa -1 ; t is the time corresponding to the current time unit; t n-1 is the time corresponding to the previous time unit; b The expression of the above is shown as equation (92): （92） In formula (92), q j r,i Qi,jis the flow rate at the ith formation unit at the jth time, m 3 / s; q j-1 r,i Qi,j-1is the flow rate at the ith formation unit at the j-1th time, m 3 / s; q n-1 r,i Qi,n-1is the flow rate at the ith formation unit at the n-1th time, m 3 / s.

2. The horizontal well integrated acidification method considering the spatial and temporal evolution law of permeability according to claim 1, characterized in that: The permeability of the formation at any time in step S6 satisfies formula (7): （1） In formula (1), r d is the equivalent elliptical invasion radius, m; r w is the horizontal wellbore radius, m; I ani K = permeability anisotropy coefficient, dimensionless; r h m for horizontal intrusion radius The acid fluid combination system in step S7 is a combination system of "acid fluid-fracturing fluid-temporary plugging fluid-fracturing fluid" injected in sequence. （2） In formula (2), r we Rtis the equivalent wellbore radius, m.

3. The horizontal well integrated acidizing method considering the spatial and temporal evolution law of permeability according to claim 2, characterized in that: The calculation method of the injection pressure of the wellbore unit during acidizing in step S7 is shown in formula (8): （3） In Equation (3), k d Kf is the permeability of the flushed zone, mD; k i 0 Ko is the original formation permeability, mD; k c Kf is the permeability of the flushed zone, mD; r c Rm is the wellbore radius minus the mudcake thickness, m; The calculation method of the equivalent elliptical invasion radius of each formation unit in step S2 is shown in formula (1): is an exponential integral function.

4. The horizontal well integrated acidizing method considering the spatial and temporal evolution law of permeability according to claim 3, characterized in that: ​ （7） in formula (7), k i j Kj is the permeability of the formation element at the jth time unit, mD; K0is the initial permeability of the formation element, %; Kj is the porosity of the formation element in the jth time unit, %; ​ K0is the initial permeability of the formation element, %; β K0is the initial permeability of the formation element, %.

5. The horizontal well integrated acidizing method considering the spatial and temporal evolution law of permeability according to claim 4, characterized in that: ​ 6. The horizontal well integrated acidizing method considering the spatial and temporal evolution law of permeability according to claim 5, characterized in that: ​ （8） In formula (8), p w,i Pw is the wellbore unit pressure, MPa; p p Pf is the formation pressure at the location of the horizontal well, MPa; f p,i F is the perforation zone wellbore friction factor, dimensionless; Δ l i is the hydraulic fracture width, m; d ​ is the density of the acid-combo fluid, kg / m 3 ; v i is the acid-combo fluid flow rate at wellbore unit i , m / s;Δ x i is the length of wellbore unit i , m; v i+1 is the acid-combo fluid flow rate at wellbore unit i +1, m / s; v i-1 is the acid-combo fluid flow rate at wellbore unit i -1, m / s; f w,i is the unperforated zone wellbore skin factor, dimensionless.​

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