Method for fine characterization of reservoirs and permeable bodies in early development of strongly heterogeneous carbonate gas reservoirs

Abstract

The application discloses a method for fine depiction of reservoir and permeation body in early development of strong heterogeneous carbonate rock gas reservoir, which comprises the following steps: step 1, a static method is used to depict the distribution form and area of the reservoir and permeation body of a gas well; step 2, according to the production dynamic data of the gas well, a production instability analysis method is used to calculate the well control area of the gas well; step 3, a numerical well test is used to determine the permeability distribution form of the gas well; step 4, the reservoir and permeation body area obtained in step 1 is compared with the well control area obtained in step 2, and the reservoir and permeation body distribution form obtained in step 1 is compared with the permeability distribution form obtained in step 3, respectively, if the error of the comparison results is less than a set threshold value, then the well control area obtained in step 2 and the permeability distribution form obtained in step 3 are used to realize the fine depiction of the reservoir and permeation body in the early development of the strong heterogeneous carbonate rock gas reservoir. The application effectively solves the problem that the reservoir and permeation body of the strong heterogeneous gas reservoir is not fine enough.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas exploration and development technology, and particularly relates to a method for fine characterization of reservoir-permeability bodies in the early stage of development of strongly heterogeneous carbonate gas reservoirs. Background Technology

[0002] Reservoir detailing refers to characterizing the reservoir within a gas well, on a per-well basis. Currently, in the early stages of gas reservoir development, seismic identification technology is mainly used to characterize the reservoir. However, due to the large errors in seismic identification technology, the characterization of the reservoir is not detailed enough, resulting in errors of tens or even hundreds of meters in the accuracy of the characterized reservoir. This is especially true for highly heterogeneous carbonate gas reservoirs, where the vertical and horizontal variations of the reservoir are significant. Gas wells within the same reservoir characterized by seismic identification technology often exhibit large differences in production characteristics. Therefore, further detailed reservoir characterization is needed.

[0003] Publication CN112946782A discloses a method for fine seismic characterization of tight oil and gas reservoirs. Based on the geological and geophysical characteristics of tight oil and gas, and using post-stack time-migrated seismic data, it optimizes inversion methods and analyzes reservoir inversion results. Based on the reservoir inversion results, the storage coefficient is calculated. This method overcomes the difficulty of comprehensively characterizing fractured reservoirs caused by the different dimensions of different seismic attributes. For fault and fracture prediction methods and parameters at different scales, after unifying the dimensions, the information representing fractures, fractures, and fracture zone extents is added to obtain a comprehensive fracture evaluation body. The reservoir and fracture information bodies are then fused to obtain a comprehensive evaluation body. This technology can intuitively reflect the development law of tight oil and gas reservoirs and enable high-precision and high-efficiency evaluation well location deployment. In practical applications, it has achieved good results and has a high agreement rate with actual drilling. However, in practical applications, the lateral or multi-directional distribution of tight oil and gas reservoirs often does not vary much, while for strongly heterogeneous carbonate reservoirs, the reservoir distribution can change dramatically at a distance of a few hundred or even tens of meters. Therefore, although this technology can characterize the development pattern of tight oil and gas reservoirs, it is not suitable for application in strongly heterogeneous carbonate gas reservoirs. Summary of the Invention

[0004] The purpose of this invention is to overcome the aforementioned problems in the prior art and to provide a method for fine characterization of reservoirs and permeable bodies in the early stages of development of strongly heterogeneous carbonate gas reservoirs. This invention characterizes the reservoirs and permeable bodies using early seismic identification technology, and then uses dynamic methods such as instability analysis and numerical well testing to clarify the area and distribution morphology of the reservoirs and permeable bodies, effectively solving the problem of insufficient fine characterization of reservoirs and permeable bodies in strongly heterogeneous gas reservoirs.

[0005] To achieve the above objectives, the technical solution adopted by the present invention is as follows:

[0006] A method for fine characterization of reservoir-permeability bodies in the early stages of development of strongly heterogeneous carbonate gas reservoirs, comprising the following steps:

[0007] Step 1: Static method to characterize the distribution morphology and area of ​​the gas well's reservoir;

[0008] Step 2: Based on the production dynamic data of the gas well, calculate the well control area of ​​the gas well using the production instability analysis method;

[0009] Step 3: Numerical well testing to determine the permeability distribution pattern of the gas well;

[0010] Step 4: Compare the reservoir area obtained in Step 1 with the well control area obtained in Step 2, and compare the reservoir distribution pattern obtained in Step 1 with the permeability distribution pattern obtained in Step 3. If the error of the comparison results is less than the set threshold, the reservoir in the early stage of development of strongly heterogeneous carbonate gas reservoirs can be finely characterized by the well control area obtained in Step 2 and the permeability distribution pattern obtained in Step 3.

[0011] In step 1, the specific method for statically characterizing the reservoir area and distribution morphology of a gas well is as follows:

[0012] Based on stratigraphic division, sedimentary facies research, and reservoir research, we comprehensively analyze the core, outcrop, and rock electrical characteristics, carry out reservoir classification and evaluation, summarize the conventional logging response characteristics, imaging logging characteristics, seismic response models, sedimentary microfacies models, and karst models of high-quality fracture-vuggy reservoirs in each small layer, and establish seismic-geological response models for different types of reservoirs.

[0013] Based on understanding the seismic-geological response patterns of different types of reservoirs, the vertical distribution characteristics of high-quality fractured-vuggy and porous reservoirs in each layer were clarified through fine calibration using conventional logging and imaging logging.

[0014] By conducting earthquake prediction with different attributes, multi-attribute overlay analysis, and combining gas well imaging logging for detailed characterization, the planar distribution characteristics of fractured-vuggy and porous high-quality reservoirs and permeable bodies are clarified.

[0015] By using the facies method and extracting various seismic attributes, combined with the distribution characteristics of sedimentary microfacies and karst dominant facies, the distribution morphology of different layers and different types of reservoirs and seepage bodies is finely depicted, and the area of ​​different layers and different types of reservoirs and seepage bodies is measured by mapping software.

[0016] In step 2, the specific calculation process for the well-controlled area is as follows:

[0017] Step (1): First, calculate the normalized pseudo-pressure of the gas well. Then, based on the normalized pseudo-pressure, calculate the material balance pseudo-time, normalized production, normalized cumulative production integral, and normalized cumulative production integral derivative of the gas well for each production data point. Then, plot the rectangular coordinate curve of the change value of normalized pseudo-pressure per unit production and the material balance pseudo-time of all production data points, and determine the actual well-controlled reserves of the gas well based on the slope of the regression line.

[0018] Step (2): Iteratively calculate the normalized pseudo-pressure, pseudo-material balance time, normalized production, normalized cumulative production integral and normalized cumulative production integral derivative until convergence, satisfying the allowable error of actual well-controlled reserves;

[0019] Step (3): Based on the results of step (2), plot the double logarithmic curves of normalized yield versus material balance pseudo-time, normalized yield integral versus material balance pseudo-time, and normalized yield integral derivative versus material balance pseudo-time respectively. After plotting, fit at least one set of double logarithmic curves to the theoretical curve.

[0020] Step (4): Select any fitting point on the fitted curve, record the actual fitting point and the corresponding theoretical fitting point, and then calculate the well control area of ​​the gas well based on the porosity, effective thickness, comprehensive compressibility coefficient and well control radius of the gas reservoir.

[0021] In step (1), the calculation method for the normalized pseudo-pressure is as follows:

[0022]

[0023] In equation (1), p p The normalized pseudo-pressure is given in MPa; p is the formation pressure in MPa; μ is the natural gas viscosity in mPa·s; and Z is the real gas deviation coefficient, dimensionless.

[0024] In step (1), the method for calculating the pseudo-time of material equilibrium is as follows:

[0025]

[0026] In equation (2), t ca For the material balance simulation time of a production data point; G 设 For the set well control reserves of the gas well, 10 8 m 3 C ti The combined compressibility coefficient of rock and fluid under initial conditions, in MPa. -1 ; q represents the daily production of the gas well, m 3 / d;p pi The normalized pseudopressure is the pressure under the original formation pressure, in MPa.

[0027] In step (1), the method for calculating the normalized yield is as follows:

[0028]

[0029] In equation (3), p represents the normalized output. wf This refers to the bottom hole flowing pressure during the gas well production process, in MPa.

[0030] In step (1), the method for calculating the regularized cumulative product integral is as follows:

[0031]

[0032] In equation (4), Let i represent the normalized output, and the subscript i represents the integral.

[0033] In step (1), the method for calculating the integral derivative of the normalized cumulative product is as follows:

[0034]

[0035] In equation (5), Let represent the normalized output, with the subscript i indicating the integral and the subscript d indicating the derivative.

[0036] In step (1), the change in normalized pseudo-pressure per unit output is... Plotting a rectangular coordinate curve of the change in normalized pseudo-pressure per unit output versus the material balance pseudo-time for all production data points refers to plotting... With t ca The method for determining the actual well-controlled reserves of a gas well based on the slope of the regression line is as follows: (The text then describes a rectangular coordinate curve for the gas well.)

[0037]

[0038] In equation (6), G 实 The actual well-controlled reserves of the gas well; Slope is... With t ca The slope of the rectangular coordinate curve, 10 3 m 3 / d / MPa / d.

[0039] In step (4), the method for calculating the well control area of ​​the gas well is as follows:

[0040]

[0041]

[0042] In equations (7) and (8), A is the well-controlled area of ​​the gas well, and r eThis represents the well control radius of the gas well. denoted as porosity of the gas reservoir, h as effective thickness of the gas well, and C as comprehensive compressibility coefficient of the gas well.

[0043] In step 3, the method for determining the permeability distribution pattern of the gas well is as follows:

[0044] Strongly heterogeneous carbonate gas reservoirs possess complex reservoir characteristics, encompassing three continuous media systems: cavern, fractures, and matrix. The bedrock system supplies fluid to the fracture system, and the fracture system supplies fluid to the cavern system. Fluid flows to the wellbore through the cavern system. Based on this, single-phase flow continuity equations are established for the matrix, fractures, and cavern systems of carbonate gas reservoirs, as follows:

[0045] The single-phase flow continuity equation for the corresponding matrix is:

[0046]

[0047] The single-phase flow continuity equation corresponding to the crack is:

[0048]

[0049] The continuity equation for single-phase flow in the corresponding karst cave is:

[0050]

[0051] The single-phase flow continuity equation is solved by backward difference to obtain the single-phase flow model of the heterogeneous carbonate gas reservoir corresponding to the matrix, the numerical well test discrete mathematical model of the corresponding fracture, and the numerical well test discrete mathematical model of the corresponding cavern. Then, the permeability distribution pattern of the gas well is determined based on the single-phase flow model of the heterogeneous carbonate gas reservoir and the numerical well test discrete mathematical model.

[0052] In step 4, if the comparison result between the reservoir area obtained in step 1 and the well control area obtained in step 2 and / or the comparison result between the reservoir distribution morphology obtained in step 1 and the permeability distribution morphology obtained in step 3 is greater than the set threshold, then the reservoir area and reservoir distribution morphology are re-delineated using the static method in step 1, and the re-delineated reservoir area and reservoir distribution morphology are compared until the error of the comparison result is less than the set threshold.

[0053] The advantages of using this invention are:

[0054] 1. This invention has strong applicability for characterizing reservoirs and permeable bodies in highly heterogeneous carbonate gas reservoirs. Compared with characterization methods that rely solely on seismic identification technology, this invention, based on a combination of dynamic and static methods and a combination of well and seismic methods, can achieve comprehensive and detailed characterization of reservoirs and permeable bodies.

[0055] 2. This invention is of great significance for subsequent well site deployment. By implementing well site deployment using the characterization results of this invention, the average test production of gas wells has increased from 545,000 cubic meters / day in the early stage to 1,238,000 cubic meters / day, which is a significant achievement.

[0056] 3. The specific formula for calculating controlled reserves used in this invention is mainly aimed at the characteristics of the early stage of development of highly heterogeneous gas reservoirs. In the early stage of development, the degree of gas well production is not high, and there is a certain error in calculating the controlled reserves of gas wells using the traditional material balance method. Therefore, the instability analysis method is used to calculate the controlled reserves, which can more accurately determine the controlled reserves and area of ​​gas wells. Attached Figure Description

[0057] Figure 1 This is a flowchart of Example 1.

[0058] Figure 2 This is a schematic diagram illustrating the horizontal and vertical calibration of the gas well reservoir in different orientations, as shown in Example 2.

[0059] Figure 3 This is a schematic diagram of the planar distribution area and morphology of the gas well reservoir body as depicted by the static method in Example 2.

[0060] Figure 4 This is a schematic diagram of the permeability distribution morphology of the gas well reservoir determined by numerical well testing in Example 2. Detailed Implementation

[0061] This invention discloses a method for fine characterization of reservoir-permeable bodies in the early stages of development of strongly heterogeneous carbonate gas reservoirs. After characterizing the reservoir-permeable bodies using early seismic identification techniques, this method further utilizes dynamic methods such as instability analysis and numerical well testing to clarify the area and distribution morphology of the reservoir-permeable bodies, thereby obtaining finely characterized reservoir-permeable bodies. Figure 1 As shown, it includes the following steps:

[0062] Step 1: Static method is used to characterize the distribution morphology and area of ​​the gas well's reservoir.

[0063] Specifically, the method for characterizing the distribution morphology and area of ​​the reservoir in a gas well using the static method is as follows:

[0064] Based on stratigraphic division, sedimentary facies studies, and reservoir studies, we comprehensively analyze core, outcrop, and rock electrical characteristics to conduct reservoir classification and evaluation. We summarize the conventional logging response characteristics, imaging logging characteristics, seismic response models, sedimentary microfacies models, and karst models of high-quality fracture-vuggy reservoirs in various sub-layers, and establish seismic-geological response models for different types of reservoirs.

[0065] Based on understanding the seismic-geological response patterns of different types of reservoirs, the vertical distribution characteristics of high-quality fractured-vuggy and porous reservoirs in each sublayer were clarified through fine calibration using conventional logging and imaging logging.

[0066] By conducting earthquake prediction with different attributes, multi-attribute overlay analysis, and combining gas well imaging logging for detailed characterization, the planar distribution characteristics of high-quality fractured and porous reservoirs are clarified.

[0067] By using the facies method and extracting various seismic attributes, combined with the distribution characteristics of sedimentary microfacies and karst dominant facies, the distribution morphology of different layers and different types of reservoirs and seepage bodies is finely depicted, and the area of ​​different layers and different types of reservoirs and seepage bodies is measured by mapping software.

[0068] Step 2: Based on the production dynamic data of the gas well, calculate the well control area of ​​the gas well using the production instability analysis method.

[0069] Specifically, the calculation process for the well-controlled area is as follows:

[0070] Step (1): First, calculate the normalized pseudo-pressure of the gas well. Then, based on the normalized pseudo-pressure, calculate the material balance pseudo-time, normalized production, normalized cumulative production integral, and normalized cumulative production integral derivative of the gas well for each production data point. Then, plot the rectangular coordinate curve of the change value of normalized pseudo-pressure per unit production and the material balance pseudo-time of all production data points, and determine the actual well-controlled reserves of the gas well based on the slope of the regression line.

[0071] In this step, the calculation methods for the normalized pseudo-pressure of the gas well, the material balance pseudo-time for each production data point of the gas well, the normalized production of the gas well, the normalized cumulative production integral of the gas well, and the derivative of the normalized cumulative production integral of the gas well are as follows:

[0072] The method for calculating the normalized pseudo-pressure of a gas well is as follows:

[0073]

[0074] In equation (1), p p The normalized pseudo-pressure is given in MPa; p is the formation pressure in MPa; μ is the natural gas viscosity in mPa·s; and Z is the real gas deviation coefficient, dimensionless.

[0075] The method for calculating the material balance pseudo-time for each production data point of a gas well is as follows:

[0076]

[0077] In equation (2), t ca For the material balance simulation time of a production data point; G 设 For the set well control reserves of the gas well, 108 m 3 C ti The combined compressibility coefficient of rock and fluid under initial conditions, in MPa. -1 ; q represents the daily production of the gas well, m 3 / d;p pi The normalized pseudopressure is the pressure under the original formation pressure, in MPa.

[0078] The method for calculating the regularized production of a gas well is as follows:

[0079]

[0080] In equation (3), p represents the normalized output. wf This refers to the bottom hole flowing pressure during the gas well production process, in MPa.

[0081] The method for calculating the regularized cumulative production integral of a gas well is as follows:

[0082]

[0083] In equation (4), Let i represent the normalized output, and the subscript i represents the integral.

[0084] The method for calculating the integral derivative of the normalized cumulative production of a gas well is as follows:

[0085]

[0086] In equation (5), Let represent the normalized output, with the subscript i indicating the integral and the subscript d indicating the derivative.

[0087] In this step, the change in normalized pseudo-pressure per unit output is... Plotting a rectangular coordinate curve of the change in normalized pseudo-pressure per unit output versus the material balance pseudo-time for all production data points refers to plotting... With t ca The method for determining the actual well-controlled reserves of a gas well based on the slope of the regression line is as follows: (The text then describes a rectangular coordinate curve for the gas well.)

[0088]

[0089] In equation (6), G 实 The actual well-controlled reserves of the gas well; Slope is... With t ca The slope of the rectangular coordinate curve, 10 3 m 3 / d / MPa / d.

[0090] Step (2): Iteratively calculate the normalized pseudo-pressure, pseudo-material balance time, normalized production, normalized cumulative production integral, and derivative of the normalized cumulative production integral until convergence, satisfying the allowable error for actual well-controlled reserves. For example, the allowable error for actual well-controlled reserves can be 5%.

[0091] Step (3): Based on the results of step (2), plot the double logarithmic curves of normalized production and material balance pseudo-time, normalized production integral and material balance pseudo-time, and normalized production integral derivative and material balance pseudo-time respectively. After plotting, fit at least one set of double logarithmic curves with the theoretical curve.

[0092] It should be noted that the theoretical chart here is based on a conventional circular dual-medium flow theory model, considering the PVT properties of gas fields under varying bottom hole flowing pressure and formation pressure changes. It is a theoretical chart based on dual-medium flow. Furthermore, three sets of logarithmic curves are plotted. The difference between using one, two, or three sets to fit the theoretical chart curves lies in the accuracy of the results. Using all three sets yields higher accuracy, but the error obtained using only one set is between 5% and 7%. Under suitable conditions, at least one set of logarithmic curves can be used to fit the theoretical chart curves.

[0093] Step (4): Select any fitting point on the fitted curve, record the actual fitting point and the corresponding theoretical fitting point, and then calculate the well control area of ​​the gas well based on the porosity, effective thickness, comprehensive compressibility coefficient and well control radius of the gas reservoir.

[0094] In this step, the well control area of ​​the gas well is calculated as follows:

[0095]

[0096]

[0097] In equations (7) and (8), A is the well-controlled area of ​​the gas well, and r e This represents the well control radius of the gas well. denoted as porosity of the gas reservoir, h as effective thickness of the gas well, and C as comprehensive compressibility coefficient of the gas well.

[0098] Step 3: Numerical well testing to determine the permeability distribution pattern of the gas well.

[0099] Specifically, the method for determining the permeability distribution pattern of gas wells is as follows:

[0100] Strongly heterogeneous carbonate gas reservoirs possess complex reservoir characteristics, encompassing three continuous media systems: cavern, fractures, and matrix. The bedrock system supplies fluid to the fracture system, and the fracture system supplies fluid to the cavern system. Fluid flows to the wellbore through the cavern system. Based on this, single-phase flow continuity equations are established for the matrix, fractures, and cavern systems of carbonate gas reservoirs, as follows:

[0101] The single-phase flow continuity equation for the corresponding matrix is:

[0102]

[0103] The single-phase flow continuity equation corresponding to the crack is:

[0104]

[0105] The continuity equation for single-phase flow in the corresponding karst cave is:

[0106]

[0107] The single-phase flow continuity equation is solved using a backward difference method to obtain a single-phase flow model for the heterogeneous carbonate gas reservoir corresponding to the matrix, a numerical well test discrete mathematical model for the corresponding fractures, and a numerical well test discrete mathematical model for the corresponding caverns. Then, the permeability distribution morphology of the gas well is determined based on the single-phase flow model and the numerical well test discrete mathematical model of the heterogeneous carbonate gas reservoir. It should be noted that the method used here to determine the permeability distribution morphology of the gas well based on the single-phase flow model and the numerical well test discrete mathematical model of the heterogeneous carbonate gas reservoir is a conventional method, mainly using difference equations to solve the model to determine the permeability distribution shape.

[0108] Step 4: Compare the reservoir area obtained in Step 1 with the well-controlled area obtained in Step 2, and compare the reservoir distribution morphology obtained in Step 1 with the permeability distribution morphology obtained in Step 3. If the error of the comparison results is less than the set threshold, the reservoir area in the early stage of development of strongly heterogeneous carbonate gas reservoirs is finely characterized using the well-controlled area obtained in Step 2 and the permeability distribution morphology obtained in Step 3. If the comparison results of the reservoir area obtained in Step 1 and the well-controlled area obtained in Step 2 and / or the comparison results of the reservoir distribution morphology obtained in Step 1 and the permeability distribution morphology obtained in Step 3 are greater than the set threshold, the reservoir area and reservoir distribution morphology are re-characterized using the static method in Step 1, and the re-characterized reservoir area and reservoir distribution morphology are compared until the error of the comparison results is less than the set threshold.

[0109] The present invention employs the aforementioned specific process, which enables precise characterization of reservoirs and permeable bodies in the early stages of development of highly heterogeneous carbonate gas reservoirs.

[0110] Example 2

[0111] The applicant applied the method described in Example 1 to a gas well in central Sichuan Basin for verification, as follows:

[0112] The initial test production of this gas well was 102.66 × 10⁻⁶. 4 m 3 / d, the unobstructed flow rate is 154.32×10 4 m 3 / d, but after production began, due to the strong heterogeneity of the reservoir, the gas well could not maintain stable production and could only produce at 8×10 4 m 3 At a production scale of / d, the oil pressure is maintained at 14.6MPa. Now, a detailed characterization of the reservoir and permeability is being performed on this gas well to clarify its distribution.

[0113] ① The static method characterizes the distribution morphology and area of ​​the gas well's reservoir. Through seismic imaging identification combined with a comprehensive histogram of well logging curves, the lateral and longitudinal dimensions of the gas well's reservoir are calibrated at different orientations. The calibration is as follows: Figure 2 As shown, we can obtain the following: Figure 3 The diagram shows the planar distribution area and morphology of the gas well reservoir. The reservoir is approximately fan-shaped, with an area of ​​1.76 km². 2 .

[0114] ② Based on the production dynamic data of the gas well, the well-controlled area was calculated using the production instability analysis method. The calculated controlled reserves of the gas well are 8.64 × 10⁻⁶. 8 m 3 Controlled area 1.74 km² 2 If the error value is less than 5%, it meets the requirements, and the reservoir area of ​​the gas well is evaluated as 1.76 km². 2 .

[0115] ③ Numerical well testing is used to determine the permeability distribution pattern of the gas well. Based on the single-phase flow continuity equations established in step 3 for the carbonate gas reservoir matrix, fractures, and caverns, these equations are solved using difference equations to obtain the following results: Figure 4 The permeability distribution pattern of the gas well reservoir is shown.

[0116] ④ By comparing the morphology and well-controlled area, it can be seen that the area error of the gas well reservoir body determined by the static and dynamic methods is 1.1%, which is less than the set threshold of 5% and meets the requirements. At the same time, the distribution morphology depicted by the static and dynamic methods is almost identical, both being approximately fan-shaped, which also meets the requirements. Thus, the detailed characterization of the gas well reservoir body is completed.

[0117] The above description is merely a specific embodiment of the present invention. Any feature disclosed in this specification may be replaced by other equivalent or similar features unless otherwise specified. All features or steps in the disclosed methods or processes may be combined in any way, except for mutually exclusive features and / or steps.

Claims

1. A method for fine characterization of reservoir-permeability bodies in the early stages of development of strongly heterogeneous carbonate gas reservoirs, comprising the following steps: Step 1: Static method to characterize the distribution morphology and area of ​​the gas well's reservoir; Step 2: Based on the production dynamic data of the gas well, calculate the well control area of ​​the gas well using the production instability analysis method; Step 3: Numerical well testing to determine the permeability distribution pattern of the gas well; Step 4: Compare the reservoir area obtained in Step 1 with the well control area obtained in Step 2, and compare the reservoir distribution pattern obtained in Step 1 with the permeability distribution pattern obtained in Step 3. If the error of the comparison results is less than the set threshold, the reservoir in the early stage of development of strongly heterogeneous carbonate gas reservoirs can be finely characterized by the well control area obtained in Step 2 and the permeability distribution pattern obtained in Step 3. In step 2, the specific calculation process for the well-controlled area is as follows: Step (1): First, calculate the normalized pseudo-pressure of the gas well. Then, based on the normalized pseudo-pressure, calculate the material balance pseudo-time, normalized production, normalized cumulative production integral, and normalized cumulative production integral derivative of the gas well for each production data point. Then, plot the rectangular coordinate curve of the change value of normalized pseudo-pressure per unit production and the material balance pseudo-time of all production data points, and determine the actual well-controlled reserves of the gas well based on the slope of the regression line. Step (2): Iteratively calculate the normalized pseudo-pressure, pseudo-material balance time, normalized production, normalized cumulative production integral, and derivative of normalized cumulative production integral until convergence, satisfying the allowable error of actual well-controlled reserves; Step (3): Based on the results of step (2), plot the double logarithmic curves of normalized production and material balance pseudo-time, normalized production integral and material balance pseudo-time, and normalized production integral derivative and material balance pseudo-time respectively. After plotting, fit at least one set of double logarithmic curves with the theoretical curve. Step (4): Select any fitting point on the fitted curve, record the actual fitting point and the corresponding theoretical fitting point, and then calculate the well control area of ​​the gas well based on the porosity, effective thickness, comprehensive compressibility coefficient and well control radius of the gas reservoir. In step 3, the method for determining the permeability distribution pattern of the gas well is as follows: Strongly heterogeneous carbonate gas reservoirs possess complex reservoir characteristics, encompassing three continuous media systems: cavern, fractures, and matrix. The bedrock system supplies fluid to the fracture system, and the fracture system supplies fluid to the cavern system. Fluid flows to the wellbore through the cavern system. Based on this, single-phase flow continuity equations are established for the matrix, fractures, and cavern systems of carbonate gas reservoirs, as follows: The single-phase flow continuity equation for the corresponding matrix is: （9） The single-phase flow continuity equation corresponding to the crack is: （10） The continuity equation for single-phase flow in the corresponding karst cave is: （11） The single-phase flow continuity equation is solved by backward difference to obtain the single-phase flow model of the heterogeneous carbonate gas reservoir corresponding to the matrix, the numerical well test discrete mathematical model of the corresponding fracture, and the numerical well test discrete mathematical model of the corresponding cavern. Then, the permeability distribution pattern of the gas well is determined based on the single-phase flow model of the heterogeneous carbonate gas reservoir and the numerical well test discrete mathematical model.

2. The method for fine characterization of reservoir-permeability bodies in the early stage of development of strongly heterogeneous carbonate gas reservoirs according to claim 1, characterized in that: In step (1), the calculation method for the normalized pseudo-pressure is as follows: （1） In equation (1), To normalize the pseudo-pressure, MPa; p Formation pressure, MPa; Here is the viscosity of natural gas, in mPa•s; This is the deviation coefficient for real gases, dimensionless.

3. The method for fine characterization of reservoir-permeability bodies in the early stage of development of strongly heterogeneous carbonate gas reservoirs according to claim 2, characterized in that: In step (1), the method for calculating the pseudo-time of material equilibrium is as follows: （2） In equation (2), The material balance time for a production data point; For the set well control reserves of the gas well, 10 8 m 3 ; The combined compressibility coefficient of rock and fluid under initial conditions, in MPa. -1 ; q m is the daily production of the gas well. 3 / d; The normalized pseudopressure is the pressure under the original formation pressure, in MPa.

4. The method for fine characterization of reservoir-permeability bodies in the early stage of development of strongly heterogeneous carbonate gas reservoirs according to claim 3, characterized in that: In step (1), the method for calculating the normalized yield is as follows: （3） In equation (3), Indicates normalized output; This refers to the bottom hole flowing pressure during the gas well production process, in MPa.

5. The method for fine characterization of reservoir-permeability bodies in the early stage of development of strongly heterogeneous carbonate gas reservoirs according to claim 4, characterized in that: In step (1), the method for calculating the regularized cumulative product integral is as follows: （4） In equation (4), Indicates normalized output, subscript i This represents the integral.

6. The method for fine characterization of reservoir-permeability bodies in the early stage of development of strongly heterogeneous carbonate gas reservoirs according to claim 5, characterized in that: In step (1), the method for calculating the integral derivative of the normalized cumulative product is as follows: （5） In equation (5), Indicates normalized output, subscript i The expression represents the integral, and the subscript d represents the derivative.

7. The method for fine characterization of reservoir-permeability bodies in the early stage of development of strongly heterogeneous carbonate gas reservoirs according to claim 6, characterized in that: In step (1), the change in normalized pseudo-pressure per unit output is... Plotting the rectangular coordinate curve of the change in normalized pseudo-pressure per unit output versus the material balance pseudo-time for all production data points refers to plotting... and The method for determining the actual well-controlled reserves of a gas well based on the slope of the regression line is as follows: (The text then describes a rectangular coordinate curve for the gas well.) （6） In equation (6), This refers to the actual well-controlled reserves of the gas well; for and The slope of the rectangular coordinate curve, 10 3 m 3 / d / MPa / d.

8. The method for fine characterization of reservoir-permeability bodies in the early stage of development of strongly heterogeneous carbonate gas reservoirs according to claim 7, characterized in that: In step (4), the method for calculating the well control area of ​​the gas well is as follows: （7） （8） In equations (7) and (8), This refers to the well-controlled area of ​​the gas well. This represents the well control radius of the gas well. Porosity of the gas reservoir The effective thickness of the gas well. The overall compressibility coefficient of the gas well 。

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