A method for determining a plugging removal process for low-permeability tight gas wells

Abstract

The application discloses a method for determining a plugging removal process for low-permeability and tight gas well plugging, which comprises the following steps: firstly, judging whether a master artificial fracture exists in a gas well reservoir according to whether hydraulic fracturing or acidizing fracturing reconstruction is performed on the gas well reservoir in an early stage; then, judging a plugging type and a plugging position of the gas well; secondly, optimizing a type of a plugging removal fluid; then, calculating an injection amount of the plugging removal fluid; and finally, optimizing the plugging removal process, wherein different numerical simulation methods are adopted to optimize the method and construction parameters of the plugging removal process according to whether hydraulic fracturing or acidizing fracturing reconstruction is performed on the gas well in the early stage and the different plugging types. The method considers influences of different completion modes in the early stage on a formation plugging position and a plugging removal fluid amount calculation, divides a reservoir damage type and position, and provides a basis for optimizing the type of the plugging removal fluid, and therefore, the method has important significance for production increase and potential tapping of the low-permeability and tight gas well.

Description

Technical Field

[0001] This invention relates to the field of petroleum extraction technology, and in particular to a method for determining a deblocking process for low-permeability tight gas wells. Background Technology

[0002] During the development of low-permeability tight gas reservoirs, various factors often lead to reservoir damage during oilfield operations such as drilling, fracturing, acidizing, and gas production, severely impacting recovery rates and economic benefits. To meet the needs of gas field production, unblocking treatment of low-permeability tight gas wells is necessary. The factors contributing to gas well blockage are multifaceted, including particle migration, clay mineral hydration and expansion, organic scale blockage, inorganic scale blockage, water lock, and the Jamin effect. Furthermore, the location of blockage varies, including the wellbore, formation matrix, and formation fractures. Therefore, to achieve ideal unblocking results, it is essential to first diagnose the cause of the blockage and then select specific unblocking measures based on the type and location of the blockage. Current methods for determining the process for unblocking low-permeability tight gas wells have some shortcomings, mainly in: failing to classify reservoir damage analysis according to different prior reservoir stimulation methods; failing to further classify the specific locations of reservoir damage; and failing to propose specific key process requirements for different unblocking fluids. These problems directly affect the unblocking effect.

[0003] Therefore, in order to further improve the unblocking effect of low-permeability tight gas wells, it is necessary to improve the process determination method for unblocking low-permeability tight gas wells, establish a method for determining the unblocking process of low-permeability tight gas reservoirs, clarify the reservoir damage mechanism of low-permeability tight gas reservoirs, reveal the main controlling factors of reservoir damage, and thus effectively guide the selection of acidizing unblocking process and improve the production of low-permeability tight gas reservoirs. Summary of the Invention In view of the above-mentioned shortcomings of the current methods for unclogging low-permeability tight gas wells, the present invention provides a method for determining the unclogging process for low-permeability tight gas wells.

[0004] The present invention provides a method for determining the unblocking process of low-permeability tight gas wells. First, it determines whether a main artificial fracture exists in the gas well reservoir. Then, it determines the type and location of the blockage. Next, it selects the optimal type of unblocking fluid. Then, it calculates the injection volume of the unblocking fluid. Finally, it optimizes the unblocking process. The specific steps are as follows: S1: Based on the early completion method of the gas well, especially whether the reservoir of the gas well has undergone hydraulic fracturing or acid fracturing in the early stage, determine whether there is a main artificial fracture in the gas well reservoir.

[0005] S2: Determine the type of gas well blockage using the following method: (1) Obtain unidentified solid return material from the wellbore or formation, analyze and test the unidentified solid return material, and determine whether the unidentified solid material is mainly inorganic or organic blockage. (2) Based on the anion and cation mineralization of formation water, predict the type and concentration of scale in formation water under the temperature, pressure and pH conditions of the wellbore and formation. (3) Based on the core flow experiment, the gas phase permeability of the core was tested at different water saturation levels to obtain the bound water saturation of the core, thereby determining whether there is liquid phase blockage in the core.

[0006] S3: Determine the location of the blockage in the gas well, using the following method: (1) Obtain dynamic production data of the gas well that caused the blockage, and analyze the trend of casing pressure and oil pressure changes before and after the blockage. If the gas well production drops sharply on a certain day, with a drop rate greater than 20%, and the difference between the well oil pressure and casing pressure is also greater than 3MPa, then the gas well blockage is judged to be well blockage. If the gas well production drops slowly every month within a year, with a drop rate of less than or equal to 20% for two consecutive months, and the difference between the well oil pressure and casing pressure is also less than or equal to 3MPa, then the gas well blockage is judged to be reservoir blockage. (2) Based on the results of step S1, combined with the historical data of gas well downhole operations, determine whether the reservoir blockage is caused by matrix or artificial fracture.

[0007] S4: Select the type of unblocking fluid based on the type and location of the gas well blockage; the method is as follows: (1) If the gas well is mainly damaged by solid phase blockage in the wellbore, matrix or fractures, then an acidic unblocking fluid should be used; (2) If the gas well is mainly damaged by liquid phase blockage in the matrix, then water-locking and liquid-locking methods should be adopted; (3) If the gas well blockage damage is a combination of liquid and solid phase blockage, then acidic unblocking fluid and water-locking fluid should be used simultaneously.

[0008] S5: Calculate the required amount of unblocking fluid, using the following method: (1) If the gas well was not previously subjected to hydraulic fracturing or acid fracturing, the formula for calculating the required quantity is as follows:

[0009] In the formula: V is the volume of unblocking fluid used, m 3 V0 represents the fluid volume of the corresponding wellbore section in the reservoir, in meters. 3 V1, V2, ... V n The volume of unblocking liquid in the reservoir sections corresponding to perforation sections 1, 2, ... n is m. 3 r0 is the tubing radius, in meters; r w Wellbore radius, m; r sThe contamination radius in the near-wellbore zone is given in meters (m); h is the height from the top boundary of the uppermost perforated section of the reservoir to the bottom of the artificial well in meters (m); h1, h2, ... h n These represent the layer thicknesses (m) involved in perforation sections 1, 2, ... n; and φ1, φ2, ... φ n These are the porosities of layers 1, 2, ... n in the perforation section; (2) If the gas well has undergone hydraulic fracturing or acid fracturing in the early stage, the formula for calculating the scale of usage is:

[0010] In the formula: V is the amount of reservoir unblocking fluid used, m 3 V1 is the crack volume, in meters. 3 V2 is the volume of fluid lost from the crack to the matrix, in meters. 3 ; L f Let be the crack length, in meters. W f Crack width, in meters; H f The crack height is in meters (m). S f Let m be the area inside the crack. 2 ; D f The depth of liquid loss into the filtrate within the crack, in meters; φ This represents the matrix porosity of the corresponding layer.

[0011] S6: Optimize the unblocking process using one of the following three methods: Method (1): If the gas well was not hydraulically or acidically fracturing in the early stage, and the blockage type is mainly solid phase blockage in the matrix; the optimization objective is to form wormholes that break through the contamination zone in the matrix. The length of the wormholes in the matrix is ​​calculated using numerical simulation to determine whether the contamination zone has been broken through. The numerical simulation steps are as follows: a. Construct a physical model of the reservoir matrix; b. Using a dual-scale continuous model composed of a radial Darcy scale model and a pore scale model, parameters such as pressure, acid concentration, porosity, and permeability are converted to construct a reservoir matrix vermiform expansion model; c. Grid the reservoir and assign porosity and permeability parameters to the grid using a random normal distribution function; d. The mathematical model was discretized in time and space using the finite volume method to calculate the matrix wormhole expansion length under different porosity, permeability, and unblocking fluid discharge conditions; e. Based on the numerical simulation results of matrix wormhole expansion, adjust the discharge rate and volume of the unblocking fluid to increase the length of the matrix wormhole and form an effective wormhole that penetrates the contamination zone.

[0012] Method (2): If the gas well has undergone hydraulic fracturing or acid fracturing in the early stages, and the blockage type is mainly solid phase blockage within the fractures, the optimization objective is to reduce the filtration loss of the unblocking fluid in the artificial fractures. Numerical simulation is used to calculate the filtration loss of the unblocking fluid from the fractures to the reservoir. The numerical simulation steps are as follows: a. Construct a physical model of reservoir fractures; b. Using a dual-scale continuous model composed of a radial Darcy scale model and a pore scale model, parameters such as pressure, acid concentration, porosity, and permeability are converted to construct a reservoir fracture filtration model; c. Grid the reservoir and assign porosity and permeability parameters to the grid using a random normal distribution function; d. The mathematical model is discretized in time and space using the finite volume method to calculate the volume of unblocking fluid lost from the crack into the matrix under different porosity, permeability, and unblocking fluid discharge conditions; e. Based on the volume of unblocking fluid lost to the matrix in the crack, adjust the discharge and usage volume of the unblocking fluid to reduce its loss in the artificial crack.

[0013] Method (3): If the gas well has undergone hydraulic fracturing or acid fracturing in the early stage, and the blockage type is a composite blockage of solid phase blockage and liquid phase blockage. The optimization objective is to improve the filtration loss of the unblocking fluid in the artificial fracture while also ensuring that it travels a long distance along the fracture length. The flow distance of the unblocking fluid in the fracture and its filtration loss to the reservoir matrix are calculated using numerical simulation. The numerical simulation steps are as follows: a. Construct a physical model of reservoir fractures; b. Using a dual-scale continuous model composed of a radial Darcy scale model and a pore scale model, parameters such as pressure, acid concentration, porosity, and permeability are calculated to construct a reservoir fracture filtration and flow model; c. Grid the reservoir and assign porosity and permeability parameters to the grid using a random normal distribution function; d. The mathematical model is discretized in time and space using the finite volume method to calculate the flow distance of the unblocking fluid in the crack and the volume lost into the matrix under different porosity, permeability, and unblocking fluid discharge conditions; e. Based on the numerical simulation results of crack filtration loss, adjust the discharge rate and volume of the unblocking fluid to increase the filtration loss of the unblocking fluid in the artificial crack and extend the flow distance of the unblocking fluid on the artificial crack. Compared with the prior art, the advantages of the present invention are: (1) Based on the completion method before the initial stage of gas well production, the reservoir damage location is further divided into types that occur in the matrix, fractures or both. (2) For different solid phase blockages, liquid phase blockages and composite blockages that combine both, different deblocking fluid optimization schemes are proposed, and key process construction requirements are put forward.

[0014] (3) The method of the present invention takes into account the impact of different well completion methods on the location of formation blockage and the scale of unblocking fluid usage in the early stage, classifies the types and locations of reservoir damage, and provides the basis for the selection of unblocking fluid type, forming a set of unblocking process flow method for low-permeability gas reservoirs, which has guiding significance for unblocking construction and is of great significance for increasing production potential of long-term low-permeability tight gas wells.

[0015] Other advantages, objectives and features of the present invention will become apparent in part from the following description, and in part from those skilled in the art through study and practice of the invention. Attached Figure Description

[0016] Figure 1 This is a flowchart illustrating the method for determining the unblocking process of low-permeability tight gas wells as described in this invention.

[0017] Figure 2 This is an X-ray diffraction pattern of the unidentified solid return material from the well in Example 1.

[0018] Figure 3 This is a diagram of the dual-scale wormhole expansion model constructed in Example 1.

[0019] Figure 4 This is a diagram showing the simulated growth results of acid-etched wormholes in Example 1.

[0020] Figure 5 This is a diagram of the crack filtration model constructed in Example 2.

[0021] Figure 6 The figure shows the results of the numerical simulation experiment of acid fracturing and etching in Example 2. Detailed Implementation

[0022] The preferred embodiments of the present invention will be described below with reference to the accompanying drawings. It should be understood that the preferred embodiments described herein are for illustration and explanation only and are not intended to limit the present invention.

[0023] The operation flow of the method for determining the unblocking process of low-permeability tight gas wells of the present invention is as follows: Figure 1 As shown, the method first determines whether a main artificial fracture exists in the gas well reservoir, then identifies the type and location of the blockage, followed by selecting the optimal type of unblocking fluid, calculating the required injection volume, and finally optimizing the unblocking process. A specific implementation example of this method is as follows. Example 1 The following method was used to determine the unblocking process for a low-yield gas well B in the Changqing Jingbian gas field, which is blocked by lower ancient carbonate rocks: Step S1: Obtain the downhole operation history of well B. It is found that well B was put into production directly after perforation completion, so it is determined that there are no artificial fractures in the well.

[0024] Step S2: Obtain the unidentified solid flowback material from the well. Perform X-ray diffraction experiments on the unidentified solid flowback material. The obtained X-ray diffraction pattern is shown below. Figure 2 .according to Figure 2 The data revealed that the unidentified solids returned from the well were mainly inorganic, with calcium carbonate as the primary component.

[0025] Formation water was obtained from the well, and the anion and cation mineralization of the formation water was tested. The test results are shown in Table 1. The scaling trend of the water sample was predicted under the conditions of 10 MPa, 100℃ and pH=5.83. It was found that the scale in the well was carbonate and the scaling concentration was 154.1 mg / L.

[0026] Table 1. Anion and cation mineralization data of a certain carbonate gas well B

[0027] Water-lock damage experiments were conducted on core samples from the target reservoir. The results showed that the bound water saturation of the reservoir was 57.34%, the original water saturation was 22.21%, the water-lock damage rate was 40.11%, and the degree of water-lock damage was moderate to strong.

[0028] Step S3: Obtain the production dynamic data and oil-casing pressure difference trend of single well B in the early stage of blockage, as shown in Table 2. The gas well production drop rate in two adjacent months within one year is less than 20%, and the difference between well oil pressure and casing pressure is less than 3MPa. Therefore, it is determined that well B is blocked in the reservoir.

[0029] Table 2. Production Dynamics Data of Carbonate Gas Well B

[0030] Based on the analysis results of step S1, since well B was put into production directly in the early stage, the reservoir matrix was relatively dense and there were no main artificial fractures caused by acid fracturing. Therefore, it was determined that the location of the blockage damage included the reservoir matrix.

[0031] Step S4: Based on the analysis in steps S1, S2, and S3, it is known that the blockage in the gas well is located within the matrix, and there is also liquid phase blockage within the matrix. Therefore, the preferred type of unblocking fluid should be a combination of acidic unblocking fluid and water-locking fluid; the volume ratio of acidic unblocking fluid to water-locking fluid is 2:1.

[0032] Acidic unblocking solution formula (by mass percentage): 10% acetic acid + 6% hydrochloric acid + 1% corrosion inhibitor (formaldehyde + NaI) + 0.1% fluorocarbon bis-hydrophobic surfactant + 2% iron ion stabilizer (sodium ethylenediaminetetraacetate), the remainder being water.

[0033] The hydrolysis and liquid-locking formula (by mass percentage) is: 2% wetting reversal agent (fluorosilicone cationic compound) + 5% nonionic surfactant (fluorinated fatty alcohol polyoxyethylene ether), with the remainder being water.

[0034] Step S5: Since it is known from step S1 that there are no artificial fractures in the formation, the formula for calculating the amount of unblocking fluid used is:

[0035] Step S6: As the analysis in steps S1 and S4 shows, well B had not undergone hydraulic fracturing or acid fracturing in the early stages, and the blockage types were mainly solid phase blockage and liquid phase blockage in the matrix. Numerical simulation was used to calculate the filtration loss and matrix wormhole expansion length under different unblocking fluid discharge conditions.

[0036] Based on seismic data, drilling data, and laboratory analysis results from carbonate gas well B, the reservoir lithology is determined to be tight carbonate rock, with an existing pressure of 13 MPa, a formation porosity of 5.89%, a reservoir rock permeability of 0.32 mD, and an average pore throat radius of 1.4 x 10⁻⁶ m². -6 m, based on these parameters, construct a physical model of the reservoir matrix.

[0037] A two-scale continuous model, consisting of a radial Darcy-scale model and a pore-scale model, is used to construct a two-scale wormhole expansion model, such as... Figure 3 As shown.

[0038] The Darcy scale model is as follows: (6) (7) In the formula: Q m Darcy velocity in a certain direction, m / s; K is core permeability, 10 -3 um 2 ; ρ The density of the acid solution is kg / m³. 3 P is pressure, MPa; t is time, s; μ The viscosity of the acid solution is given in mPa·s. u This is the Darcy velocity vector, in m / s, which includes velocities in both the x and y directions.

[0039] The chemical field equations are as follows: (8) (9) In the formula: C f The mass concentration of acid solution inside the pores at a certain time, in kmol / m 3 U is the velocity vector, m / s; D is the diffusion coefficient, m 2 / s;k c The mass transfer coefficient is given in m / s. a V The specific surface area of ​​the pores is m. 2 / m 3 C s The mass concentration of acid at the pore wall surface, kmol / m 3 ;k s The reaction rate constant is denoted as m / s. α ρ is the dissolving power number, kg / kmol; s Density of rock, kg / m³ 3 .

[0040] Equations (6) to (9) together constitute the Darcy scale model in the dual-scale wormhole expansion model.

[0041] The porosity scaling model is as follows: (10) (11) (12) In the formula: K 0 represents the initial penetration rate, 10 -3 um 2 ; φ 0 represents the initial porosity; r p The original throat radius is in meters. β These are empirical constants; r p0 The original pore radius is in meters. a V The specific surface area of ​​the pores is m. 2 / m 3 ; a 0 represents the original specific surface area, in m. 2 / m 3 .

[0042] Equations (10) to (12) together constitute the pore scale model in the dual-scale model.

[0043] Both the injection and outflow ends use constant pressure boundaries, and the initial conditions of the model are: (13) When t > 0, closed boundaries are used on both sides of the core sample, and the following boundary conditions are specified: (14) (15) (16) (17) In the formula: P inj Injection pressure, MPa; l P represents the core length in meters. a Standard atmospheric pressure, 0.1 MPa; n is the core width, m; C f The mass concentration of the reaction liquid phase inside the pores, kmol / m 3 .

[0044] The mathematical model was subjected to integral discrete numerical simulation in time and space using the finite volume method. The filtration loss of the unblocking fluid and the expansion length of the matrix wormholes were calculated under different unblocking fluid discharge conditions, as detailed in Table 3.

[0045] The growth and expansion patterns of acid-etched wormholes were analyzed based on the results of characterization parameter analysis. The simulated growth results of acid-etched wormholes are as follows: Figure 4 As shown, the main controlling factor affecting the formation of acid-etched wormholes is the acid injection rate. Finally, the optimal combination of matrix acidification engineering factors is determined to be: adjusting the unblocking fluid flow rate to 0.6 m³. 3 / min, volume is 20m 3 This ultimately forms effective worm holes that penetrate the pollution zone.

[0046] Table 3. Construction parameters of a tight sandstone gas well B

[0047] Example 2 The following method was used to determine the unblocking process for a low-yield gas well C in the Changqing Jingbian gas field, which is blocked by lower ancient carbonate rocks: Step S1: Obtain the downhole operation history of well C. It is found that acid fracturing was carried out before the initial production stage of well C, so there is already a main artificial fracture in the well.

[0048] Step S2: Obtain the unidentified solid flowback material from the well. Analyze and test the unidentified solid flowback material. The test results show that the unidentified solid flowback material from the well is mainly inorganic, and the main component is calcium carbonate.

[0049] Formation water was obtained from the well, and the anion and cation mineralization of the formation water was tested. The results are shown in Table 4. The scaling trend of the water sample was predicted under the conditions of 10 MPa, 100℃ and pH=6.95. It was found that the scale in the well was carbonate and the scaling concentration was 559.57 mg / L.

[0050] Table 4. Anion and cation mineralization data of a certain carbonate gas well C

[0051] Water-lock damage experiments were conducted on core samples from the target reservoir. The results showed that the bound water saturation of the reservoir was 58.06%, the original water saturation was 22.21%, the water-lock damage rate was 40.11%, and the degree of water-lock damage was moderate to strong.

[0052] Step S3: Obtain the production dynamic data and oil-casing pressure difference trend of well C in the early stage of blockage. As shown in Table 5, the gas well production drop rate in the two adjacent months is less than 20%, and the difference between well oil pressure and casing pressure is less than 3MPa. Therefore, it is determined that well C is blocked in the reservoir.

[0053] Table 5. Production Dynamics of a Carbonate Gas Well C

[0054] Based on the analysis results of step S1, after the initial acid fracturing and production of well C, the reservoir matrix was relatively dense, but there were main artificial fractures caused by acid fracturing. Therefore, it was determined that the location of the plugging damage included both the reservoir matrix and the reservoir fractures.

[0055] Step S4: Based on the analysis in steps S1, S2, and S3, the blockage in the gas well is located within the artificially etched fractures and the matrix. The blockage type within the fractures is solid-phase blockage, while the blockage type within the matrix is ​​a combination of solid-phase and liquid-phase blockage. Therefore, the preferred unblocking fluid should be a combination of an acidic unblocking fluid and a water-locking fluid. The volume ratio of the acidic unblocking fluid to the water-locking fluid is 2:1.

[0056] Acidic unblocking solution formula (by mass percentage): 10% acetic acid + 6% hydrochloric acid + 1% corrosion inhibitor (formaldehyde + NaI) + 0.1% fluorocarbon bis-hydrophobic surfactant + 2% iron ion stabilizer (sodium ethylenediaminetetraacetate), the remainder being water.

[0057] Water-locking agent formulation (by mass percentage): 2% wetting reversal agent (fluorosilicone cationic compound) + 5% nonionic surfactant (fluorinated fatty alcohol polyoxyethylene ether), the remainder being water.

[0058] Step S5: Since it is known from step S1 that an artificial fracture already exists in the formation, the formula for calculating the amount of unblocking fluid used is:

[0059] Step S6: As the analysis in steps S1 and S4 shows, well C underwent hydraulic fracturing or acid fracturing in the early stages, and the blockage type was a combination of solid phase blockage and liquid phase blockage. Based on the seismic data, drilling data and laboratory analysis results of carbonate gas well C, the current reservoir pressure is 12 MPa, the formation porosity is 7.14% and the permeability is 0.67 mD. Based on these parameters, a physical model of the fractures in the carbonate gas well C reservoir is constructed.

[0060] A two-scale acid-etched crack filtration model is constructed using a radial Darcy-scale model and a pore-scale model, as shown in the figure. Figure 5 As shown.

[0061] The Darcy scale model is as follows: (18)

[0062] In the formula: U is the dynamic viscosity of the acid solution, in mPa·s; U is the velocity vector, in m / s; T is time, in s; I is the coefficient of friction between the fluid and the porous medium. Fluid density, kg / m³ 3 ; P Pressure, Pa; Porosity; K For penetration rate, m 2 ; Q m For mass source, kg / (m 3 ·s); F Due to the effects of gravity and other volume forces, kg / (m 2 ·s 2 ).

[0063] The chemical field equation describes chemical reactions, i.e., convection-diffusion phenomena, and is constructed from the chemical equilibrium equation and the porosity change equation.

[0064] (19) (20) In the formula: The mass concentration of the acid solution inside the pores, in mol / m³ 3 ; The mass concentration of acid at the pore wall surface, in mol / m 3 ; m is the diffusion coefficient. 2 / s; The mass transfer coefficient is given in m / s. The reaction rate constant is denoted as m / s. Density of rock, kg / m³ 3 ; The specific surface area of ​​the pores is m. 2 / m 3 ; , where is the dissolving power number, kg / kmol.

[0065] Equations (18) to (20) together constitute the Darcy scale model in the dual-scale continuous medium model of acid filtration loss in cracks.

[0066] The pore size model is as follows: By modifying the Carman-Kozeny empirical formula, the relationship between permeability, pore radius, specific surface area and porosity is obtained.

[0067] (twenty one) (twenty two) (twenty three) In the formula: m is the initial permeability. 2 ; Initial porosity; The original bore radius is in meters. These are empirical constants; The original pore radius; Specific surface area of ​​pores; This represents the original specific surface area.

[0068] Equations (21) to (23) together constitute the pore scale model in the dual-scale continuous medium model.

[0069] Numerical simulations were performed using the finite volume method, which involved integral discretization of the mathematical model in both time and space. The flow distance of the unblocking fluid in the crack and the volume lost into the matrix under different unblocking fluid discharge rates were calculated, as detailed in Table 6. The results of the acid fracturing and etching numerical simulation experiments are shown below. Figure 6 .

[0070] Based on the numerical simulation results of crack filtration loss, the unblocking process was optimized, and the unblocking fluid discharge rate was adjusted to 1.0 m³. 3 / min, volume 30m 3 Ultimately, this increases the filtration rate of the unblocking fluid in the artificial cracks and extends the flow distance of the unblocking fluid on the artificial cracks.

[0071] Table 6. Construction parameters of a tight sandstone gas well C

[0072] The above description is merely a preferred embodiment of the present invention and is not intended to limit the present invention in any way. Although the present invention has been disclosed above with reference to preferred embodiments, it is not intended to limit the present invention. Any person skilled in the art can make some modifications or alterations to the above-disclosed technical content to create equivalent embodiments without departing from the scope of the present invention. Any simple modifications, equivalent changes, and alterations made to the above embodiments based on the technical essence of the present invention without departing from the scope of the present invention shall still fall within the scope of the present invention.

Claims

1. A method for determining the unblocking process for low-permeability tight gas wells, characterized in that, The steps are as follows: S1: Determine whether there is a main artificial fracture in the gas well reservoir based on whether the reservoir has undergone hydraulic fracturing or acid fracturing in the early stage of the gas well. S2: Determine the type of blockage in the gas well, including solid phase blockage, liquid phase blockage, or a combination of solid phase blockage and liquid phase blockage; S3: Determine the location of the blockage in the gas well; S4: Select the type of unblocking fluid based on the type and location of the gas well blockage; S5: Calculate the required amount of unblocking fluid, using the following method: (1) If the gas well was not previously subjected to hydraulic fracturing or acid fracturing, the formula for calculating the required quantity is as follows: In the formula: V is the volume of unblocking fluid used, m 3 V0 represents the fluid volume of the corresponding wellbore section in the reservoir, in meters. 3 V1, V2, ... V n The volume of unblocking liquid in the reservoir sections corresponding to perforation sections 1, 2, ... n is m. 3 r0 is the tubing radius, in meters; r w Wellbore radius, m; r s The contamination radius in the near-wellbore zone is given in meters (m); h is the height from the top boundary of the uppermost perforated section of the reservoir to the bottom of the artificial well in meters (m); h1, h2, ... h n These represent the layer thicknesses (m) involved in perforation sections 1, 2, ... n; and φ1, φ2, ... φ n These are the porosities of layers 1, 2, ... n in the perforation section; (2) If the gas well has undergone hydraulic fracturing or acid fracturing in the early stage, the formula for calculating the scale of usage is: In the formula: V is the amount of reservoir unblocking fluid used, m 3 V1 is the crack volume, in meters. 3 V2 is the volume of fluid lost from the crack to the matrix, in meters. 3 ; L f Let be the crack length, in meters. W f Crack width, in meters; H f The crack height is in meters (m). S f Let m be the area inside the crack. 2 ; D f The depth of liquid loss into the filtrate within the crack, in meters; φ This represents the matrix porosity of the corresponding layer. S6: Optimize the unblocking process using one of the following three methods: Method (1): If the gas well was not hydraulically or acidically fracturing in the early stage, and the blockage type is solid phase blockage within the matrix; calculate the length of the wormholes in the matrix using numerical simulation to determine whether the contaminated zone has been breached; the numerical simulation steps are as follows: a. Construct a physical model of the reservoir matrix; b. Using a dual-scale continuous model composed of a radial Darcy scale model and a pore scale model, parameters such as pressure, acid concentration, porosity, and permeability are converted to construct a reservoir matrix vermiform expansion model; c. Grid the reservoir and assign porosity and permeability parameters to the grid using a random normal distribution function; d. The mathematical model was discretized in time and space using the finite volume method to calculate the matrix wormhole expansion length under different porosity, permeability, and unblocking fluid discharge conditions; e. Based on the numerical simulation results of matrix wormhole expansion, adjust the discharge rate and volume of the unblocking fluid to increase the length of the matrix wormhole and form an effective wormhole that penetrates the contamination zone; Method (2): If the gas well has undergone hydraulic fracturing or acid fracturing in the early stage, and the blockage type is solid phase blockage within the fracture, the loss of unblocking fluid from the fracture to the reservoir is calculated using numerical simulation. The numerical simulation steps are as follows: a. Construct a physical model of reservoir fractures; b. Using a dual-scale continuous model composed of a radial Darcy scale model and a pore scale model, parameters such as pressure, acid concentration, porosity, and permeability are converted to construct a reservoir fracture filtration model; c. Grid the reservoir and assign porosity and permeability parameters to the grid using a random normal distribution function; d. The mathematical model is discretized in time and space using the finite volume method to calculate the volume of unblocking fluid lost from the crack into the matrix under different porosity, permeability, and unblocking fluid discharge conditions; e. Based on the volume of unblocking fluid lost to the matrix in the crack, adjust the discharge and usage volume of the unblocking fluid to reduce the loss of unblocking fluid in the artificial crack; Method (3): If the gas well has undergone hydraulic fracturing or acid fracturing in the early stage, and the blockage type is a composite blockage of solid phase blockage and liquid phase blockage, the flow distance of the unblocking fluid in the fracture and the filtration loss to the reservoir matrix are calculated by numerical simulation. The numerical simulation steps are as follows: a. Construct a physical model of reservoir fractures; b. Using a dual-scale continuous model composed of a radial Darcy scale model and a pore scale model, parameters such as pressure, acid concentration, porosity, and permeability are calculated to construct a reservoir fracture filtration and flow model; c. Grid the reservoir and assign porosity and permeability parameters to the grid using a random normal distribution function; d. The mathematical model is discretized in time and space using the finite volume method to calculate the flow distance of the unblocking fluid in the crack and the volume lost into the matrix under different porosity, permeability, and unblocking fluid discharge conditions; e. Based on the numerical simulation results of crack filtration loss, adjust the discharge rate and volume of the unblocking fluid to increase the filtration loss of the unblocking fluid in the artificial crack and extend the flow distance of the unblocking fluid on the artificial crack.

2. The method for determining the unblocking process for low-permeability tight gas wells as described in claim 1, characterized in that, Step S2, the method for determining the type of gas well blockage is as follows: (1) Obtain unidentified solid return material from the wellbore or formation, analyze and test the unidentified solid return material, and determine whether the unidentified solid material is mainly inorganic or organic blockage. (2) Based on the anion and cation mineralization of formation water, predict the type and concentration of scale in formation water under the temperature, pressure and pH conditions of the wellbore and formation. (3) Based on the core flow experiment, the gas phase permeability of the core was tested at different water saturation levels to obtain the bound water saturation of the core, thereby determining whether there is liquid phase blockage in the core.

3. The method for determining the unblocking process for low-permeability tight gas wells as described in claim 1, characterized in that, Step S3, the method for determining the location of the blockage in the gas well is as follows: (1) Obtain dynamic production data of the gas well that caused the blockage, and analyze the trend of casing pressure and oil pressure changes before and after the blockage. If the gas well production drops sharply on a certain day, with a drop rate greater than 20%, and the difference between the well oil pressure and casing pressure is also greater than 3MPa, then the gas well blockage is judged to be well blockage. If the gas well production drops slowly every month within a year, with a drop rate of less than or equal to 20% for two consecutive months, and the difference between the well oil pressure and casing pressure is also less than or equal to 3MPa, then the gas well blockage is judged to be reservoir blockage. (2) Based on the results of step S1, combined with the historical data of gas well downhole operations, determine whether the reservoir blockage is caused by matrix or artificial fracture.

4. The method for determining the unblocking process for low-permeability tight gas wells as described in claim 1, characterized in that, Step S4, the method for selecting the type of unblocking fluid is as follows: (1) If the gas well is mainly damaged by solid phase blockage in the wellbore, matrix or fractures, then an acidic unblocking fluid should be used; (2) If the gas well is mainly damaged by liquid phase blockage in the matrix, then water-locking and liquid-locking methods should be adopted; (3) If the gas well blockage damage is a combination of liquid and solid phase blockage, then acidic unblocking fluid and water-locking fluid should be used simultaneously.

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