Dynamic correction method for storage capacity of gas storage of condensate gas reservoir

Abstract

The invention relates to the technical field of gas reservoir engineering and development, in particular to a dynamic correction method for the storage capacity of a gas storage of a condensate gas reservoir. Comprising the following specific steps: S1, based on a gas reservoir engineering method and geological data, calculating an original gas-bearing pore volume of a gas storage, and constructing an initial material balance model and various key parameters related to the initial material balance model; according to the method, through basic data collection and model construction, experimental determination and multi-path pore volume change calculation, and then model correction, parameter review, experimental simulation and final prediction and optimization, the storage capacity related parameters can be accurately calculated and corrected, the influence of various factors on the pore volume is effectively quantified, and the calculation efficiency is improved. Accurate prediction of the storage capacity change of the gas storage under future multi-cycle injection and production is achieved, injection and production parameters are optimized to remarkably improve the working gas amount and the storage capacity utilization rate, and good economic benefits and gas storage operation benefits are brought.

Description

Technical Field

[0001] This invention relates to the field of gas reservoir engineering and development technology, specifically a method for dynamically adjusting the storage capacity of a condensate gas reservoir. Background Technology

[0002] Underground gas storage facilities are a crucial link in the natural gas industry chain and an important component of the pipeline transportation system. They not only regulate supply and demand to ensure stable supply during daily natural gas supply but also play an irreplaceable role in emergency situations such as accidents. Currently, my country has 27 gas storage facilities in operation for peak-shaving production, forming a storage capacity of approximately 20 billion cubic meters. The types of reservoirs used in gas storage facilities are also diversifying. For gas storage facilities converted from depleted oil and gas reservoirs, based on the original reservoir and drive type, they have gradually developed into: dry gas type gas storage facilities (elastic drive), water-drive type (water-driven and elastic drive) gas storage facilities, and complex condensate gas reservoir (water-driven, elastic drive, and complex condensate action) gas storage facilities, etc. Through years of practice, domestic gas storage facilities have gradually recognized that under the special multi-cycle injection and production operation conditions of gas storage facilities, various factors affect the storage capacity and its composition parameters during multi-cycle operation. Based on these parameters, researchers have developed various modified material balance equations to describe the changing patterns of gas storage capacity and its composition parameters. However, with the development of gas storage facilities in my country, some complex and depleted oil and gas reservoirs have begun to be constructed as gas storage facilities. The complex reservoir properties, condensation phenomena, oil and gas conditions, and edge and bottom water states of these reservoirs pose significant challenges to the accurate prediction of storage capacity and parameters. The periodic changes in effective reservoir stress make the reservoir rocks stress-sensitive, severely impacting fluid flow within the reservoir. During injection and production, fluid lock-in occurs in the gas-water transition zone as circulation proceeds, leading to a decrease in reservoir flow utilization efficiency. When condensation occurs, the produced condensate oil creates a three-phase fluid within the reservoir. The relative flow interactions between these fluids reduce the reservoir's flow capacity, and the condensed liquid components occupy the reservoir's storage space, further reducing its operational capacity. Additionally, the depletion of formation pressure from before storage construction to the end of production also leads to complex edge and bottom water relationships in the gas storage facility, resulting in different fluid distribution zones in the reservoir's horizontal and vertical planes. These combined factors make the calculation of gas storage capacity and working gas volume extremely difficult. In existing technologies, for edge water condensate gas reservoirs with condensate gas properties, the material balance equation does not consider the storage capacity loss caused by condensate precipitation, resulting in unsatisfactory calculation results for multi-cycle working gas volume.

[0003] Based on this, the present invention provides a method for dynamically adjusting the storage capacity of a condensate gas reservoir to solve the aforementioned technical problems. Summary of the Invention

[0004] The purpose of this invention is to provide a method for dynamic correction of condensate gas reservoir storage capacity. This invention, through basic data collection and model construction, experimental measurement and multi-pathway calculation of pore volume change, model correction, parameter verification, experimental simulation and final prediction and optimization, can accurately calculate and correct storage capacity-related parameters, effectively quantify the influence of various factors on pore volume, achieve accurate prediction of storage capacity changes under future multi-cycle injection and production, and optimize injection and production parameters to significantly improve working gas volume and storage capacity utilization, bringing good economic benefits and storage operation efficiency.

[0005] To achieve the above objectives, the present invention provides the following technical solution:

[0006] This invention provides a method for dynamically adjusting the storage capacity of a condensate gas reservoir, comprising the following specific steps:

[0007] S1: Based on gas reservoir engineering methods and geological data, calculate the original gas-bearing pore volume of the gas storage tank, and construct an initial mass balance model and various related key parameters;

[0008] S2: Through core stress sensitivity experiments and gas-water mutual drive experiments, the permeability damage rate and residual gas saturation were determined to quantify rock stress sensitivity, bound water deformation and pore volume loss in the water-flooded area.

[0009] S3: Combining numerical simulation and production dynamic data, the reservoir is divided into zones, and the pore volume reduction caused by condensate oil occupation and gas-water mutual drive is calculated to generate the total reduction.

[0010] S4: Modify the material balance model, integrate dynamic parameters, construct a multi-period reservoir capacity analytical model, and output the available pore volume;

[0011] S5: The actual storage capacity and working gas volume are verified by using the pressure drop method, and the historical fitting of the three-dimensional geological model is combined to verify the efficiency of pore volume utilization in the zone.

[0012] S6: Through multi-cycle injection and production experiments with long cores, the effects of condensate oil back-evaporation and residual changes were simulated, and the influence terms of condensate components in the model were iteratively corrected.

[0013] S7: Predicts storage capacity changes under future multi-cycle injection and production, optimizes injection and production parameters, and outputs working gas volume and storage capacity utilization improvement schemes.

[0014] The specific steps for calculating the original pore volume and constructing the material model in S1 are as follows:

[0015] S1.1: Collect geological materials of the gas storage facility, including stratigraphic structure, lithological distribution, and reservoir physical property parameter distribution, as well as collect dynamic production data, including gas injection, gas production, and water production of the gas storage facility;

[0016] S1.2: Calculate the original pore volume using the volumetric method formula: Where A is the gas-bearing area; h is the effective thickness; Porosity; S wi To bind water saturation;

[0017] S1.3: Incorporate various key parameters, including natural gas expansion, water flooding, condensate oil precipitation, and rock and bound water compression, to establish a material balance equation.

[0018] The specific operational steps of the mass balance equation in S1.3 are as follows:

[0019] For non-constant volume gas reservoirs with water flooding and where both rocks and fluids within the reservoir are compressible, the mass balance of the gas storage facility as development progresses is as follows:

[0020]

[0021] make:

[0022]

[0023] Where G represents natural gas reserves, 10 4 m 3 S wi C represents the initial bound water saturation, in percentage. w The compressibility coefficient of formation water is given in MPa. -1 ;P i P represents the original and current formation pressure, in MPa; G represents... P To accumulate gas production, 10 4 m 3 W e To accumulate the flood volume, 10 4 m 3 W p To accumulate water production, 10 4 m 3 E p Cumulative black oil production, 10 4 m 3 B gi B g B is the original, current natural gas volume factor, dimensionless; w is the volume coefficient of formation water, dimensionless;

[0024] C e·f =P i ·C e When ≤0.10, E p This can be ignored, and equation (1) can be transformed as follows:

[0025]

[0026] The formula for calculating the reservoir water flooding volume under the corresponding formation pressure is as follows:

[0027]

[0028] Neglecting the effects of bound water and pore expansion, (3) can be rewritten as:

[0029]

[0030] Substituting the gas storage production dynamics into formula (4) yields the total water production and flooding volume at the corresponding time and pressure. Simultaneously, the flooding volume is substituted into formula (5):

[0031] W i =W e / [C t ×(P i -P) (5)

[0032] Among them, W i For the original groundwater reserves, 10 4 m 3 We represents the water flooding volume at formation pressure P, 10 4 m 3 ;P i P is the original formation pressure, MPa; C is the current formation pressure, MPa; t C is the overall compression factor. t =C w +C f .

[0033] The specific steps in S2 are as follows:

[0034] S2.1: Select reservoir cores from the gas storage facility, process them into standard samples, clean them, dry them, vacuum them to saturate them with formation water, and then place them in a core holder connected to a pressure pump, flow meter, confining pressure system and data acquisition device;

[0035] S2.2: With a fixed osmotic pressure of 1MPa, four cycles of loading and unloading were carried out within the confining pressure range of 15MPa-40MPa. The permeability was measured when the pressure point stabilized. Based on this, a model of the relationship between permeability and effective stress was established, the permeability damage rate was calculated, the rock stress sensitivity was assessed, and the pore volume loss was quantified.

[0036] S2.3: Prepare 12 core samples that have been evacuated and saturated with simulated formation water. Set up an experimental setup with nitrogen supplied by an intermediate container, pressure applied by a high-precision displacement pump, confining pressure provided by a hand pump, differential pressure measured by a pressure sensor, and flow rate measured by a gas flow meter.

[0037] S2.4: First, gas-driven water flow and pressure are recorded to calculate the bound water saturation. Then, water-driven gas flow is recorded to calculate the residual gas saturation. This process is repeated 6 times to analyze the two-phase gas-water flow characteristics and quantify the deformation of rock and bound water and the pore volume loss in the water-flooded area.

[0038] The specific formulas for calculating the permeability damage rate in relation to rock stress sensitivity, rock and bound water deformation, and pore volume loss in the flooded area are as follows:

[0039] The specific formula for the permeability damage rate is as follows:

[0040]

[0041] Where D1 and D2 are the maximum permeability damage rate and the irreversible permeability damage rate, respectively, as percentages; K max With K min K0 and K1 represent the maximum and minimum permeability under the initial test stress conditions, respectively, in mD; K0 and K1 represent the permeability under the initial stress conditions and the permeability after returning to the initial stress state, respectively, in mD.

[0042] The specific formulas for rock stress sensitivity, rock and bound water deformation, and pore volume loss in the flooded zone are as follows:

[0043]

[0044] Where ΔV1 is the original gas-bearing pore volume lost in the flooded area, m 3 ΔV4 represents the rock stress-sensitive reduction volume, in meters. 3 ΔV5 is the deformation volume of rock and bound water, in meters. 3 W emax The cumulative flooding volume at the upper limit pressure of the gas storage facility, in meters. 3 W pmax The cumulative water production at the upper limit pressure of the gas storage facility, in m 3 B wmax S is the upper limit pressure formation water volume factor; wc The original bound water saturation of the gas reservoir, %; S gr The residual gas saturation at the end of gas reservoir development, in %; The rock porosity at the lower limit pressure of the gas storage tank, in %; The porosity of the rock under the original gas reservoir conditions is expressed as %; G i The original geological reserves of the gas reservoir, m 3 B gi m is the original natural gas volume factor. 3 C w The formation water compressibility coefficient is given in MPa. -1 S wi Initial water saturation for gas reservoir development, %; C f For; Pmax P represents the upper limit pressure of the gas storage facility, in MPa; min This represents the lower limit pressure of the gas storage facility, in MPa.

[0045] The specific steps in S3 are as follows:

[0046] S3.1: Integrate geological models, production dynamic data, and experimentally measured relative permeability parameters;

[0047] S3.2: Construct a three-dimensional geological model based on Petrel and divide the reservoir into pure gas zone, transition zone, and water-flooded zone;

[0048] S3.3: Adjust the parameters of permeability and water body size to match actual production data;

[0049] S3.4: The specific formula for calculating the volume occupied by condensate oil is: ΔV6=Q pcon B g n; where ΔV6 is the pore volume occupied by the condensate after analysis, m 3 Q pcon B represents the estimated gas content within the reservoir before reservoir construction. g is the volume factor of multi-component natural gas, dimensionless; n is the percentage of condensate gas condensed at the current pressure relative to the original gas content;

[0050] S3.5: The specific formula for calculating the deduction for gas-water mutual drive is as follows:

[0051]

[0052] Where ΔV2 is the original gas-bearing pore volume lost in the transition zone, m 3 ΔV3 represents the original gas-bearing pore volume lost in the pure gas region, in meters. 3 W emin The cumulative flooding volume at the lower limit pressure of the gas storage facility, in meters. 3 W pmin To determine the cumulative water production at the lower limit pressure of the gas storage facility, m 3 B wmin S is the lower limit pressure formation water volume factor; wct Bound water saturation (%) for stable operation in the transition zone; S grt Residual gas saturation (%) for stable operation in the transition zone; W econ The cumulative flood volume before reservoir construction, in m 3 W pcon To calculate the cumulative water production before reservoir construction, m 3 B wcon S represents the formation water volume coefficient before reservoir construction. srcon The residual gas saturation (%) for stable operation in the pure gas zone; S wccon The bound water saturation level, in %, represents the level required for stable operation in the pure gas zone.

[0053] S3.6: The specific formula for generating the total deduction is: ΣΔV=ΔV1+ΔV2+ΔV3+ΔV6;

[0054] S3.7: Compare the pore volume loss between numerical simulation and mass balance method. If the deviation is >5%, recalibrate the parameters.

[0055] The specific steps in S4 are as follows:

[0056] S4.1: Update the dynamic parameters of water flooding, rock compressibility coefficient, and condensate back-evaporation ratio to the initial mass balance equation;

[0057] S4.2: Based on the pore volume deduction results, the reconstructed mass balance equation is as follows:

[0058] V gm =V gi -ΔV1-ΔV2-ΔV3-ΔV4-ΔV5-ΔV6

[0059] Among them, V gm The effective gas-bearing pore volume of the gas storage facility is expressed in m. 3 V gi The original gas-bearing pore volume of the gas storage facility is expressed in m. 3 ;

[0060] S4.3: Introduce the number of cycles and pressure changes to establish a recursive formula for the storage capacity parameter;

[0061] S4.4: Outputs the effective pore volume under the current pressure and associates it with the gas volume factor to calculate the reservoir capacity.

[0062] The specific steps in S5 are as follows:

[0063] S5.1: Collect multi-cycle injection and production data of the gas storage facility, including formation pressure, cumulative gas production, and gas compressibility factor;

[0064] S5.2: Plot the relationship between apparent formation pressure and cumulative gas production, and perform linear regression analysis;

[0065] S5.3: Based on the slope of the regression line, the actual working gas volume is calculated as: Q work =-1 / b;

[0066] S5.4: Based on the gas volume coefficient, the actual effective storage capacity of the gas storage facility is verified as: Q 实际 =Q work ×B g ;

[0067] S5.5: Adjust numerical simulation parameters, including permeability and water body size, to match pressure drop results with production dynamic data;

[0068] S5.6: Compare the differences in pore volume utilization between the simulation and the actual pure gas zone, transition zone, and water-flooded zone to verify the rationality of the deduction.

[0069] S5.7: If the deviation is >5%, recalibrate the stress-sensitive or water-flooded parameters.

[0070] The specific steps in S6 are as follows:

[0071] S6.1: Simulate 6 rounds of injection and production cycles, and record the condensate oil production, gas phase permeability changes and residual oil saturation in each round;

[0072] S6.2: Calculate the condensate oil back-evaporation efficiency and the rate of change of residual oil saturation based on experimental data;

[0073] S6.3: Input the experimentally obtained condensate oil back-evaporation efficiency and residual oil saturation change rate into the numerical model to update the ΔV6 calculation formula;

[0074] S6.4: Compare the experimental data with the model-predicted changes in condensate oil saturation. If the error is >5%, recalibrate the parameters.

[0075] The specific steps in S7 are as follows:

[0076] S7.1: Based on the modified multi-cycle model, input the current gas storage parameters, run the injection and production simulation for the next 5-10 cycles, and output the dynamic changes in storage capacity, working gas volume and flooding volume;

[0077] S7.2: Focus on assessing the marginal impact of condensate back-evaporation, stress damage accumulation, and water flooding on storage capacity;

[0078] S7.3: Through sensitivity analysis, determine the core control parameters of the optimal upper limit of gas injection pressure and the timing of drainage at the end of the cycle;

[0079] S7.4: Generate the final plan, which includes the prediction curve, optimization parameters and economic analysis, and clarify the target for improving storage capacity utilization.

[0080] Compared with the prior art, the beneficial effects of the present invention are:

[0081] This invention, through basic data collection and model building, experimental measurement and multi-pathway calculation of pore volume change, model correction, parameter verification, experimental simulation and final prediction and optimization, can accurately calculate and correct storage capacity-related parameters, effectively quantify the impact of various factors on pore volume, achieve accurate prediction of storage capacity changes under future multi-cycle injection and production, and optimize injection and production parameters to significantly improve working gas volume and storage capacity utilization, bringing good economic benefits and gas storage operation benefits. Attached Figure Description

[0082] Figure 1 This is a flowchart illustrating the overall method for dynamically adjusting the storage capacity of a condensate gas reservoir according to the present invention.

[0083] Figure 2 This is a flowchart illustrating the overall technical framework of a dynamic adjustment method for the storage capacity of a condensate gas reservoir according to the present invention. Detailed Implementation

[0084] The technical solutions of the present invention will be clearly and completely described below with reference to the embodiments of the present invention. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those of ordinary skill in the art without creative effort are within the scope of protection of the present invention.

[0085] Example:

[0086] like Figures 1-2 As shown in the figure, this embodiment provides a method for dynamically adjusting the storage capacity of a condensate gas reservoir, including the following specific steps:

[0087] S1: Based on gas reservoir engineering methods and geological data, calculate the original gas-bearing pore volume of the gas storage tank, and construct an initial mass balance model and various related key parameters;

[0088] S2: Through core stress sensitivity experiments and gas-water mutual drive experiments, the permeability damage rate and residual gas saturation were determined to quantify rock stress sensitivity, bound water deformation and pore volume loss in the water-flooded area.

[0089] S3: Combining numerical simulation and production dynamic data, the reservoir is divided into zones, and the pore volume reduction caused by condensate oil occupation and gas-water mutual drive is calculated to generate the total reduction.

[0090] S4: Modify the material balance model, integrate dynamic parameters, construct a multi-period reservoir capacity analytical model, and output the available pore volume;

[0091] S5: The actual storage capacity and working gas volume are verified by using the pressure drop method, and the historical fitting of the three-dimensional geological model is combined to verify the efficiency of pore volume utilization in the zone.

[0092] S6: Through multi-cycle injection and production experiments with long cores, the effects of condensate oil back-evaporation and residual changes were simulated, and the influence terms of condensate components in the model were iteratively corrected.

[0093] S7: Predicts storage capacity changes under future multi-cycle injection and production, optimizes injection and production parameters, and outputs working gas volume and storage capacity utilization improvement schemes.

[0094] The specific steps for calculating the original pore volume and constructing the material model in S1 are as follows:

[0095] S1.1: Collect geological materials of the gas storage facility, including stratigraphic structure, lithological distribution, and reservoir physical property parameter distribution, as well as collect dynamic production data, including gas injection, gas production, and water production of the gas storage facility;

[0096] S1.2: Calculate the original pore volume using the volumetric method formula: Where A is the gas-bearing area; h is the effective thickness; Porosity; S wi To bind water saturation;

[0097] S1.3: Incorporate various key parameters, including natural gas expansion, water flooding, condensate oil precipitation, and rock and bound water compression, to establish a material balance equation.

[0098] The specific operational steps for the mass balance equation in S1.3 are as follows:

[0099] For non-constant volume gas reservoirs with water flooding and where both rocks and fluids within the reservoir are compressible, the mass balance of the gas storage facility as development progresses is as follows:

[0100]

[0101] make:

[0102]

[0103] Where G represents natural gas reserves, 10 4 m 3 S wi C represents the initial bound water saturation, in percentage. w The compressibility coefficient of formation water is given in MPa. -1 ;P i P represents the original and current formation pressure, in MPa; G represents... P To accumulate gas production, 10 4 m 3 W e To accumulate the flood volume, 10 4 m 3 W p To accumulate water production, 10 4 m 3 E p Cumulative black oil production, 10 4 m 3 B gi B g The original, current volume coefficient of natural gas is dimensionless.

[0104] B w is the volume coefficient of formation water, dimensionless;

[0105] C e·f =P i ·C e When ≤0.10, E p This can be ignored, and equation (1) can be transformed as follows:

[0106]

[0107] The formula for calculating the reservoir water flooding volume under the corresponding formation pressure is as follows:

[0108]

[0109] Neglecting the effects of bound water and pore expansion, (3) can be rewritten as:

[0110]

[0111] Substituting the gas storage production dynamics into formula (4) yields the total water production and flooding volume at the corresponding time and pressure. Simultaneously, the flooding volume is substituted into formula (5):

[0112] W i =W e / [C t ×(P i -P) (5)

[0113] Among them, W i For the original groundwater reserves, 10 4 m 3 We represents the water flooding volume at formation pressure P, 10 4 m 3 ;P i P is the original formation pressure, MPa; C is the current formation pressure, MPa; t C is the overall compression factor. t =C w +C f .

[0114] The specific steps in S2 are as follows:

[0115] S2.1: Select reservoir cores from the gas storage facility, process them into standard samples, clean them, dry them, vacuum them to saturate them with formation water, and then place them in a core holder connected to a pressure pump, flow meter, confining pressure system and data acquisition device;

[0116] S2.2: With a fixed osmotic pressure of 1MPa, four cycles of loading and unloading were carried out within the confining pressure range of 15MPa-40MPa. The permeability was measured when the pressure point stabilized. Based on this, a model of the relationship between permeability and effective stress was established, the permeability damage rate was calculated, the rock stress sensitivity was assessed, and the pore volume loss was quantified.

[0117] S2.3: Prepare 12 core samples that have been evacuated and saturated with simulated formation water. Set up an experimental setup with nitrogen supplied by an intermediate container, pressure applied by a high-precision displacement pump, confining pressure provided by a hand pump, differential pressure measured by a pressure sensor, and flow rate measured by a gas flow meter.

[0118] S2.4: First, gas-driven water flow and pressure are recorded to calculate the bound water saturation. Then, water-driven gas flow is recorded to calculate the residual gas saturation. This process is repeated 6 times to analyze the two-phase gas-water flow characteristics and quantify the deformation of rock and bound water and the pore volume loss in the water-flooded area.

[0119] The specific formulas for calculating the permeability damage rate in relation to rock stress sensitivity, rock and bound water deformation, and pore volume loss in the flooded zone are as follows:

[0120] The specific formula for the penetration damage rate is:

[0121]

[0122] Where D1 and D2 are the maximum permeability damage rate and the irreversible permeability damage rate, respectively, as percentages; K max With K min K0 and K1 represent the maximum and minimum permeability under the initial test stress conditions, respectively, in mD; K0 and K1 represent the permeability under the initial stress conditions and the permeability after returning to the initial stress state, respectively, in mD.

[0123] The specific formulas for rock stress sensitivity, rock and bound water deformation, and pore volume loss in the water-flooded zone are as follows:

[0124]

[0125] Where ΔV1 is the original gas-bearing pore volume lost in the flooded area, m 3 ΔV4 represents the rock stress-sensitive reduction volume, in meters. 3 ΔV5 is the deformation volume of rock and bound water, in meters. 3 W emax The cumulative flooding volume at the upper limit pressure of the gas storage facility, in meters. 3 W pmax The cumulative water production at the upper limit pressure of the gas storage facility, in m 3 B wmax S is the upper limit pressure formation water volume factor; wc The original bound water saturation of the gas reservoir, %; S gr The residual gas saturation at the end of gas reservoir development, in %; The rock porosity at the lower limit pressure of the gas storage tank, in %; The porosity of the rock under the original gas reservoir conditions is expressed as %; G i The original geological reserves of the gas reservoir, m 3 B gi m is the original natural gas volume factor.3 C w The formation water compressibility coefficient is given in MPa. -1 S wi Initial water saturation for gas reservoir development, %; C f For; P max P represents the upper limit pressure of the gas storage facility, in MPa; min This represents the lower limit pressure of the gas storage facility, in MPa.

[0126] The specific steps in S3 are as follows:

[0127] S3.1: Integrate geological models, production dynamic data, and experimentally measured relative permeability parameters;

[0128] S3.2: Construct a three-dimensional geological model based on Petrel and divide the reservoir into pure gas zone, transition zone, and water-flooded zone;

[0129] S3.3: Adjust the parameters of permeability and water body size to match actual production data;

[0130] S3.4: The specific formula for calculating the volume occupied by condensate oil is: ΔV6=Q pcon B g n; where ΔV6 is the pore volume occupied by the condensate after analysis, m 3 Q pcon B represents the estimated gas content within the reservoir before reservoir construction. g is the volume factor of multi-component natural gas, dimensionless; n is the percentage of condensate gas condensed at the current pressure relative to the original gas content;

[0131] S3.5: The specific formula for calculating the deduction for gas-water mutual drive is as follows:

[0132]

[0133]

[0134] Where ΔV2 is the original gas-bearing pore volume lost in the transition zone, m 3 ΔV3 represents the original gas-bearing pore volume lost in the pure gas region, in meters. 3 W emin The cumulative flooding volume at the lower limit pressure of the gas storage facility, in meters. 3 W pmin To determine the cumulative water production at the lower limit pressure of the gas storage facility, m 3 B wmin S is the lower limit pressure formation water volume factor; wct Bound water saturation (%) for stable operation in the transition zone; S grt Residual gas saturation (%) for stable operation in the transition zone; W econ The cumulative flood volume before reservoir construction, in m3 W pcon To calculate the cumulative water production before reservoir construction, m 3 B wcon S represents the formation water volume coefficient before reservoir construction. srcon The residual gas saturation (%) for stable operation in the pure gas zone; S wccon The bound water saturation level, in %, represents the level required for stable operation in the pure gas zone.

[0135] S3.6: The specific formula for generating the total deduction is: ΣΔV=ΔV1+ΔV2+ΔV3+ΔV6;

[0136] S3.7: Compare the pore volume loss between numerical simulation and mass balance method. If the deviation is >5%, recalibrate the parameters.

[0137] The specific steps in S4 are as follows:

[0138] S4.1: Update the dynamic parameters of water flooding, rock compressibility coefficient, and condensate back-evaporation ratio to the initial mass balance equation;

[0139] S4.2: Based on the pore volume deduction results, the reconstructed mass balance equation is as follows:

[0140] V gm =V gi -ΔV1-ΔV2-ΔV3-ΔV4-ΔV5-ΔV6

[0141] Among them, V gm The effective gas-bearing pore volume of the gas storage facility is expressed in m. 3 V gi The original gas-bearing pore volume of the gas storage facility is expressed in m. 3 ;

[0142] S4.3: Introduce the number of cycles and pressure changes to establish a recursive formula for the storage capacity parameter;

[0143] S4.4: Outputs the effective pore volume under the current pressure and associates it with the gas volume factor to calculate the reservoir capacity.

[0144] The specific steps in S5 are as follows:

[0145] S5.1: Collect multi-cycle injection and production data of the gas storage facility, including formation pressure, cumulative gas production, and gas compressibility factor;

[0146] S5.2: Plot the relationship between apparent formation pressure and cumulative gas production, and perform linear regression analysis;

[0147] S5.3: Based on the slope of the regression line, the actual working gas volume is calculated as: Q work =-1 / b;

[0148] S5.4: Based on the gas volume coefficient, the actual effective storage capacity of the gas storage facility is verified as: Q 实际 =Q work ×B g ;

[0149] S5.5: Adjust numerical simulation parameters, including permeability and water body size, to match pressure drop results with production dynamic data;

[0150] S5.6: Compare the differences in pore volume utilization between the simulation and the actual pure gas zone, transition zone, and water-flooded zone to verify the rationality of the deduction.

[0151] S5.7: If the deviation is >5%, recalibrate the stress-sensitive or water-flooded parameters.

[0152] The specific steps in S6 are as follows:

[0153] S6.1: Simulate 6 rounds of injection and production cycles, and record the condensate oil production, gas phase permeability changes and residual oil saturation in each round;

[0154] S6.2: Calculate the condensate oil back-evaporation efficiency and the rate of change of residual oil saturation based on experimental data;

[0155] S6.3: Input the experimentally obtained condensate oil back-evaporation efficiency and residual oil saturation change rate into the numerical model to update the ΔV6 calculation formula;

[0156] S6.4: Compare the experimental data with the model-predicted changes in condensate oil saturation. If the error is >5%, recalibrate the parameters.

[0157] The specific steps in S7 are as follows:

[0158] S7.1: Based on the modified multi-cycle model, input the current gas storage parameters, run the injection and production simulation for the next 5-10 cycles, and output the dynamic changes in storage capacity, working gas volume and flooding volume;

[0159] S7.2: Focus on assessing the marginal impact of condensate back-evaporation, stress damage accumulation, and water flooding on storage capacity;

[0160] S7.3: Through sensitivity analysis, determine the core control parameters of the optimal upper limit of gas injection pressure and the timing of drainage at the end of the cycle;

[0161] S7.4: Generate the final plan, which includes the prediction curve, optimization parameters and economic analysis, and clarify the target for improving storage capacity utilization.

[0162] like Figures 1-2As shown, this embodiment provides a method for dynamic correction of the storage capacity of a condensate gas reservoir. The specific method is as follows: First, S1: Based on the gas reservoir engineering method and geological data, calculate the original gas-bearing pore volume of the storage reservoir and construct an initial material balance model and various related key parameters; the specific steps for calculating the original pore volume and constructing the material model are as follows: S1.1: Collect geological materials of the storage reservoir, including stratigraphic structure, lithological distribution, and reservoir physical property parameter distribution, and collect dynamic production data, including gas injection, gas production, and water production of the storage reservoir; S1.2: Calculate the original pore volume using the volumetric method formula: Where A is the gas-bearing area; h is the effective thickness; Porosity; S wi S1.3: Incorporating various key parameters including natural gas expansion, water flooding, condensate oil precipitation, and rock and bound water compression, a mass balance equation is established. Specific operational details are as follows: For non-constant volume gas reservoirs with water flooding activity and where both rock and fluid within the reservoir can be compressed, the mass balance relationship of the gas storage facility progresses through the development stages as follows:

[0163]

[0164] make:

[0165]

[0166] Where G represents natural gas reserves, 10 4 m 3 S wi C represents the initial bound water saturation, in percentage. w The compressibility coefficient of formation water is given in MPa. -1 ;P i P represents the original and current formation pressure, in MPa; G represents... P To accumulate gas production, 10 4 m 3 W e To accumulate the flood volume, 10 4 m 3 W p To accumulate water production, 10 4 m 3 E p Cumulative black oil production, 10 4 m 3 B gi B g B is the original, current natural gas volume factor, dimensionless; w is the volume coefficient of formation water, dimensionless;

[0167] C e·f =P i ·Ce When ≤0.10, E p This can be ignored, and equation (1) can be transformed as follows:

[0168]

[0169] The formula for calculating the reservoir water flooding volume under the corresponding formation pressure is as follows:

[0170]

[0171] Neglecting the effects of bound water and pore expansion, (3) can be rewritten as:

[0172]

[0173] Substituting the gas storage production dynamics into formula (4) yields the total water production and flooding volume at the corresponding time and pressure. Simultaneously, the flooding volume is substituted into formula (5):

[0174] W i =W e / [C t ×(P i -P) (5)

[0175] Among them, W i For the original groundwater reserves, 10 4 m 3 We represents the water flooding volume at formation pressure P, 10 4 m 3 ;P i P is the original formation pressure, MPa; C is the current formation pressure, MPa; t C is the overall compression factor. t =C w +C fSecondly, S2: Through core stress sensitivity experiments and gas-water mutual drive experiments, the permeability damage rate and residual gas saturation were determined to quantify rock stress sensitivity, bound water deformation, and pore volume loss in the water-flooded zone. The specific steps were as follows: S2.1: Select reservoir cores from the gas storage facility, process them into standard samples, clean, dry, and vacuum-saturate them with formation water, then place them in a core holder connected to a pressure pump, flow meter, confining pressure system, and data acquisition device; S2.2: Fix the permeability pressure at 1 MPa, and perform four cycles of loading and unloading within a confining pressure range of 15 MPa-40 MPa. Permeability was measured at each stable pressure point, and a system was established based on this. A permeability-effective stress relationship model was developed to calculate permeability damage rate, assess rock stress sensitivity, and quantify pore volume loss. S2.3: Twelve core samples were prepared, evacuated and saturated with simulated formation water. An experimental setup was established, using an intermediate container to supply nitrogen, a high-precision displacement pump for pressurization, a hand-cranked pump to provide confining pressure, a pressure sensor to measure differential pressure, and a gas flow meter to measure flow rate. S2.4: First, gas-driven water was used to record gas-water flow rates and pressures to calculate bound water saturation. Then, water-driven gas was used to record relevant data to calculate residual gas saturation. This process was repeated six times to analyze the two-phase gas-water flow characteristics and quantify rock and bound water deformation and pore volume loss in the water-flooded zone. Temperature range: room temperature to 120℃, temperature control accuracy: ±0.5℃; gas working pressure: 70MPa, capable of pressurizing CO2, N2, CH4, and multi-component mixed gases; backpressure system: control pressure: 0–70MPa, control accuracy ±0.05MPa. The specific formula for calculating the permeability damage rate in relation to rock stress sensitivity, rock and bound water deformation, and pore volume loss in the flooded area is as follows: The specific formula for the permeability damage rate is as follows:

[0176]

[0177] Where D1 and D2 are the maximum permeability damage rate and the irreversible permeability damage rate, respectively, as percentages; K max With K min K0 and K1 represent the maximum and minimum permeability under the initial test stress conditions, respectively, in mD; K0 and K1 represent the permeability under the initial stress conditions and the permeability after returning to the initial stress state, respectively, in mD.

[0178] The specific formulas for rock stress sensitivity, rock and bound water deformation, and pore volume loss in the flooded zone are as follows:

[0179]

[0180] Where ΔV1 is the original gas-bearing pore volume lost in the flooded area, m 3 ΔV4 represents the rock stress-sensitive reduction volume, in meters. 3 ΔV5 is the deformation volume of rock and bound water, in meters. 3 W emax The cumulative flooding volume at the upper limit pressure of the gas storage facility, in meters.3 W pmax The cumulative water production at the upper limit pressure of the gas storage facility, in m 3 B wmax S is the upper limit pressure formation water volume factor; wc The original bound water saturation of the gas reservoir, %; S gr The residual gas saturation at the end of gas reservoir development, in %; The rock porosity at the lower limit pressure of the gas storage tank, in %; The porosity of the rock under the original gas reservoir conditions is expressed as %; G i The original geological reserves of the gas reservoir, m 3 B gi m is the original natural gas volume factor. 3 C w The formation water compressibility coefficient is given in MPa. -1 S wi Initial water saturation for gas reservoir development, %; C f For; P max P represents the upper limit pressure of the gas storage facility, in MPa; min The lower limit pressure of the gas storage tank is MPa. S3: Combining numerical simulation and production dynamic data, the reservoir is divided into zones, and the pore volume reduction caused by condensate oil occupation and gas-water mutual drive is calculated to generate the total reduction. Specific steps are: S3.1: Integrate the geological model, production dynamic data, and experimentally measured relative permeability parameters; S3.2: Construct a three-dimensional geological model based on Petrel, dividing the reservoir into pure gas zone, transition zone, and water-flooded zone; S3.3: Adjust the parameters of permeability and water volume to match actual production data; S3.4: The specific formula for calculating the condensate oil occupied volume is: ΔV6=Q pcon B g n; where ΔV6 is the pore volume occupied by the condensate after analysis, m 3 Q pcon B represents the estimated gas content within the reservoir before reservoir construction. g is the volume factor of multi-component natural gas, dimensionless; n is the percentage of condensate gas condensed at the current pressure relative to the original gas content; S3.5: The specific formula for calculating the gas-water interdrive deduction is:

[0181]

[0182] Where ΔV2 is the original gas-bearing pore volume lost in the transition zone, m 3 ΔV3 represents the original gas-bearing pore volume lost in the pure gas region, in meters. 3 W emin The cumulative flooding volume at the lower limit pressure of the gas storage facility, in meters. 3 W pmin To determine the cumulative water production at the lower limit pressure of the gas storage facility, m 3 Bwmin S is the lower limit pressure formation water volume factor; wct Bound water saturation (%) for stable operation in the transition zone; S grt Residual gas saturation (%) for stable operation in the transition zone; W econ The cumulative flood volume before reservoir construction, in m 3 W pcon To calculate the cumulative water production before reservoir construction, m 3 B wcon S represents the formation water volume coefficient before reservoir construction. srcon The residual gas saturation (%) for stable operation in the pure gas zone; S wccon S3.6: The specific formula for generating the total deduction is: ΣΔV=ΔV1+ΔV2+ΔV3+ΔV6; S3.7: Compare the pore volume loss between numerical simulation and the material balance method. If the deviation is >5%, recalibrate the parameters. S4: Modify the material balance model, integrate dynamic parameters, construct a multi-period reservoir capacity analytical model, and output the available pore volume; the specific steps are: S4.1: Update the dynamic parameters of water flooding, rock compressibility coefficient, and condensate oil back-evaporation ratio to the initial material balance equation; S4.2: Based on the pore volume deduction results, reconstruct the material balance equation as follows:

[0183] V gm =V gi -ΔV1-ΔV2-ΔV3-ΔV4-ΔV5-ΔV6

[0184] Among them, V gm The effective gas-bearing pore volume of the gas storage facility is expressed in m. 3 V gi The original gas-bearing pore volume of the gas storage facility is expressed in m. 3 S4.3: Introduce the number of cycles and pressure changes to establish a recursive formula for the storage capacity parameter; the specific recursive formula is as follows:

[0185]

[0186] Gr work(i) =G rmmax(i) -G rmmin(i)

[0187] G rmin(i) =G r(i) -G rm(i) +G rmmin(i)

[0188] G rmax(i) =Gr work(i) +G rmin(i)

[0189] Where: i is the cycle number, dimensionless; P is the pressure, MPa; Z is the volume coefficient, dimensionless; G r(f) Total inventory, 10 8 m 3 G r(0) The remaining geological reserves before reservoir construction, 10 8 m 3 Q pi This represents the total cumulative condensate gas produced in the current cycle, 10 8 m 3 Q pm(t) The total amount of dry gas injected in the current cycle, 10 8 m 3 G rm(i-1) For available inventory, 10 8 m 3 V m(i-1) For movable pore volume, 10 4 m 3 G rmmax(i) For movable storage capacity, 10 8 m 3 G rmmin(i) Available inventory, 10 8 m 3 G rwork(i) For working gas volume, 10 8 m 3 G rmin(i) For cushion volume, 10 8 m 3 G rmax(i) For storage capacity, 10 8 m 3 S4.4: Output the effective pore volume under the current pressure and correlate it with the gas volume factor to calculate the storage capacity. S5: Verify the actual storage capacity and working gas volume using the pressure drop method, and combine it with historical fitting of the three-dimensional geological model to verify the efficiency of pore volume utilization in the zone; the specific steps are: S5.1: Collect multi-cycle injection and production data of the gas storage facility, including formation pressure, cumulative gas production, and gas compressibility factor; S5.2: Plot the relationship between apparent formation pressure and cumulative gas production, and perform linear regression analysis; S5.3: Calculate the actual working gas volume Q based on the slope of the regression line. work =-1 / b; S5.4: Combining the gas volume coefficient, the actual effective storage capacity of the gas storage facility is verified as: Q 实际 =Q work ×B gS5.5: Adjust numerical simulation parameters, including permeability and water volume, and match pressure drop method results with production dynamic data; S5.6: Compare the differences in pore volume utilization between the simulation and the actual pure gas zone, transition zone, and water-flooded zone to verify the rationality of the deduction; S5.7: If the deviation is >5%, recalibrate stress-sensitive or water-flooded parameters; S6: Simulate condensate back-evaporation and residual changes through long core multi-cycle injection-production experiments, and iteratively correct the condensate component influence terms in the model; the specific steps are as follows: S6.1: Simulate 6 rounds of injection-production cycles, and record the condensate production, gas phase permeability change, and residual oil saturation in each round; S6.2: Calculate the condensate back-evaporation efficiency and residual oil saturation change rate based on the experimental data; S6.3: Input the experimentally obtained condensate back-evaporation efficiency and residual oil saturation change rate into the numerical model and update the ΔV6 calculation formula; S6.4: Compare the experimental data with the model-predicted condensate oil saturation change, and if the error is >5%, recalibrate the parameters. Finally, S7: Predict storage capacity changes under future multi-cycle injection and production, optimize injection and production parameters, and output working gas volume and storage capacity utilization improvement schemes. Specific steps are as follows: S7.1: Based on the modified multi-cycle model, input the current gas storage parameters, run injection and production simulations for the next 5-10 cycles, and output the dynamic changes in storage capacity, working gas volume, and water flooding volume; S7.2: Focus on evaluating the marginal impact of condensate back-evaporation, stress damage accumulation, and water flooding on storage capacity; S7.3: Through sensitivity analysis, determine the core control parameters for the optimal upper limit of injection pressure and the timing of drainage at the end of the cycle; S7.4: Generate the final scheme including prediction curves, optimized parameters, and economic analysis, clarifying the storage capacity utilization improvement target.

[0190] In the description of this specification, references to terms such as "an embodiment," "example," "specific example," etc., indicate that a specific feature, structure, material, or characteristic described in connection with that embodiment or example is included in at least one embodiment or example of the invention. In this specification, illustrative expressions of the above terms do not necessarily refer to the same embodiment or example. Furthermore, the specific features, structures, materials, or characteristics described may be combined in any suitable manner in one or more embodiments or examples.

[0191] The preferred embodiments of the present invention disclosed above are merely illustrative of the invention. These preferred embodiments do not exhaustively describe all details, nor do they limit the invention to the specific implementations described. Clearly, many modifications and variations can be made based on the content of this specification. This specification selects and specifically describes these embodiments to better explain the principles and practical applications of the invention, thereby enabling those skilled in the art to better understand and utilize the invention. The invention is limited only by the claims and their full scope and equivalents.

Claims

1. A method for dynamically adjusting the storage capacity of a condensate gas reservoir, characterized in that, The specific steps include: S1: Based on gas reservoir engineering methods and geological data, calculate the original gas-bearing pore volume of the gas storage tank, and construct an initial mass balance model and various related key parameters; S2: Through core stress sensitivity experiments and gas-water mutual drive experiments, the permeability damage rate and residual gas saturation were determined to quantify rock stress sensitivity, bound water deformation and pore volume loss in the water-flooded area. S3: Combining numerical simulation and production dynamic data, the reservoir is divided into zones, and the pore volume reduction caused by condensate oil occupation and gas-water mutual drive is calculated to generate the total reduction. S4: Modify the material balance model, integrate dynamic parameters, construct a multi-period reservoir capacity analytical model, and output the available pore volume; S5: The actual storage capacity and working gas volume are verified by using the pressure drop method, and the historical fitting of the three-dimensional geological model is combined to verify the efficiency of pore volume utilization in the zone. S6: Through multi-cycle injection and production experiments with long cores, the effects of condensate oil back-evaporation and residual changes were simulated, and the influence terms of condensate components in the model were iteratively corrected. S7: Predicts storage capacity changes under future multi-cycle injection and production, optimizes injection and production parameters, and outputs working gas volume and storage capacity utilization improvement schemes.

2. The method for dynamically adjusting the storage capacity of a condensate gas reservoir according to claim 1, characterized in that, The specific steps for calculating the original pore volume and constructing the material model in S1 are as follows: S1.1: Collect geological materials of the gas storage facility, including stratigraphic structure, lithological distribution, and reservoir physical property parameter distribution, as well as collect dynamic production data, including gas injection, gas production, and water production of the gas storage facility; S1.2: Calculate the original pore volume using the volumetric method formula: Where A is the gas-bearing area; h is the effective thickness; Porosity; S wi To bind water saturation; S1.3: Incorporate various key parameters, including natural gas expansion, water flooding, condensate oil precipitation, and rock and bound water compression, to establish a material balance equation.

3. The method for dynamically adjusting the storage capacity of a condensate gas reservoir according to claim 2, characterized in that, The specific operational steps of the mass balance equation in S1.3 are as follows: For non-constant volume gas reservoirs with water flooding and where both rocks and fluids within the reservoir are compressible, the mass balance of the gas storage facility as development progresses is as follows: make: Where G represents natural gas reserves, 10 4 m 3 S wi C represents the initial bound water saturation, in percentage. w The compressibility coefficient of formation water is given in MPa. -1 ;P i P represents the original and current formation pressure, in MPa; G represents... P To accumulate gas production, 10 4 m 3 W e To accumulate the flood volume, 10 4 m 3 W p To accumulate water production, 10 4 m 3 E p Cumulative black oil production, 10 4 m 3 B gi B g B is the original, current natural gas volume factor, dimensionless; w is the volume coefficient of formation water, dimensionless; C e·f =P i ·C e When ≤0.10, E p This can be ignored, and equation (1) can be transformed as follows: The formula for calculating the reservoir water flooding volume under the corresponding formation pressure is as follows: Neglecting the effects of bound water and pore expansion, (3) can be rewritten as: Substituting the gas storage production dynamics into formula (4) yields the total water production and flooding volume at the corresponding time and pressure. Simultaneously, the flooding volume is substituted into formula (5): W i =W e / [C t ×(P i -P) (5) Among them, W i For the original groundwater reserves, 10 4 m 3 We represents the water flooding volume at formation pressure P, 10 4 m 3 ;P i P is the original formation pressure, MPa; C is the current formation pressure, MPa; t C is the overall compression factor. t =C w +C f .

4. The method for dynamically adjusting the storage capacity of a condensate gas reservoir according to claim 1, characterized in that, The specific steps in S2 are as follows: S2.1: Select reservoir cores from the gas storage facility, process them into standard samples, clean them, dry them, vacuum them to saturate them with formation water, and then place them in a core holder connected to a pressure pump, flow meter, confining pressure system and data acquisition device; S2.2: With a fixed osmotic pressure of 1MPa, four cycles of loading and unloading were carried out within the confining pressure range of 15MPa-40MPa. The permeability was measured when the pressure point stabilized. Based on this, a model of the relationship between permeability and effective stress was established, the permeability damage rate was calculated, the rock stress sensitivity was assessed, and the pore volume loss was quantified. S2.3: Prepare 12 core samples that have been evacuated and saturated with simulated formation water. Set up an experimental setup with nitrogen supplied by an intermediate container, pressure applied by a high-precision displacement pump, confining pressure provided by a hand pump, differential pressure measured by a pressure sensor, and flow rate measured by a gas flow meter. S2.4: First, gas-driven water flow and pressure are recorded to calculate the bound water saturation. Then, water-driven gas flow is recorded to calculate the residual gas saturation. This process is repeated 6 times to analyze the two-phase gas-water flow characteristics and quantify the deformation of rock and bound water and the pore volume loss in the water-flooded area.

5. The method for dynamically adjusting the storage capacity of a condensate gas reservoir according to claim 4, characterized in that, The specific formulas for calculating the permeability damage rate in relation to rock stress sensitivity, rock and bound water deformation, and pore volume loss in the flooded area are as follows: The specific formula for the permeability damage rate is as follows: Where D1 and D2 are the maximum permeability damage rate and the irreversible permeability damage rate, respectively, as percentages; K max With K min K0 and K1 represent the maximum and minimum permeability under the initial test stress conditions, respectively, in mD; K0 and K1 represent the permeability under the initial stress conditions and the permeability after returning to the initial stress state, respectively, in mD. The specific formulas for rock stress sensitivity, rock and bound water deformation, and pore volume loss in the flooded zone are as follows: Where ΔV1 is the original gas-bearing pore volume lost in the flooded area, m 3 ΔV4 represents the rock stress-sensitive reduction volume, in meters. 3 ΔV5 is the deformation volume of rock and bound water, in meters. 3 W emax The cumulative flooding volume at the upper limit pressure of the gas storage facility, in meters. 3 W pmax The cumulative water production at the upper limit pressure of the gas storage facility, in m 3 B wmax S is the upper limit pressure formation water volume factor; wc The original bound water saturation of the gas reservoir, in %; S gr The residual gas saturation at the end of gas reservoir development, in %; The rock porosity at the lower limit pressure of the gas storage tank, in %; The porosity of the rock under the original gas reservoir conditions is expressed as %; G i The original geological reserves of the gas reservoir, m 3 B gi m is the original natural gas volume factor. 3 C w The formation water compressibility coefficient is given in MPa. -1 S wi Initial water saturation for gas reservoir development, %; C f For; P max P represents the upper limit pressure of the gas storage facility, in MPa; min This represents the lower limit pressure of the gas storage facility, in MPa.

6. The method for dynamically adjusting the storage capacity of a condensate gas reservoir according to claim 1, characterized in that, The specific steps in S3 are as follows: S3.1: Integrate geological models, production dynamic data, and experimentally measured relative permeability parameters; S3.2: Construct a three-dimensional geological model based on Petrel and divide the reservoir into pure gas zone, transition zone, and water-flooded zone; S3.3: Adjust the parameters of permeability and water body size to match actual production data; S3.4: The specific formula for calculating the volume occupied by condensate oil is: ΔV6=Q pcon B g n; where ΔV6 is the pore volume occupied by the condensate after analysis, m 3 Q pcon B represents the estimated gas content within the reservoir before reservoir construction. g is the volume factor of multi-component natural gas, dimensionless; n is the percentage of condensate gas condensed at the current pressure relative to the original gas content; S3.5: The specific formula for calculating the deduction for gas-water mutual drive is as follows: Where ΔV2 is the original gas-bearing pore volume lost in the transition zone, m 3 ΔV3 represents the original gas-bearing pore volume lost in the pure gas region, in meters. 3 W emin The cumulative flooding volume at the lower limit pressure of the gas storage facility, in meters. 3 ; W pmin To determine the cumulative water production at the lower limit pressure of the gas storage facility, m 3 B wmin S is the lower limit pressure formation water volume factor; wct Bound water saturation (%) for stable operation in the transition zone; S grt Residual gas saturation (%) for stable operation in the transition zone; W econ The cumulative flood volume before reservoir construction, in meters. 3 W pcon To calculate the cumulative water production before reservoir construction, m 3 B wcon S represents the formation water volume coefficient before reservoir construction. srcon The residual gas saturation (%) for stable operation in the pure gas zone; S wccon The bound water saturation level, in %, represents the level required for stable operation in the pure gas zone. S3.6: The specific formula for generating the total deduction is: ΣΔV=ΔV1+ΔV2+ΔV3+ΔV6; S3.7: Compare the pore volume loss between numerical simulation and mass balance method. If the deviation is >5%, recalibrate the parameters.

7. The method for dynamically adjusting the storage capacity of a condensate gas reservoir according to claim 1, characterized in that, The specific steps in S4 are as follows: S4.1: Update the dynamic parameters of water flooding, rock compressibility coefficient, and condensate back-evaporation ratio to the initial mass balance equation; S4.2: Based on the pore volume deduction results, the reconstructed mass balance equation is as follows: V gm =V gi -ΔV1-ΔV2-ΔV3-ΔV4-ΔV5-ΔV6 Among them, V gm The effective gas-bearing pore volume of the gas storage facility is expressed in m. 3 V gi The original gas-bearing pore volume of the gas storage facility is expressed in m. 3 ; S4.3: Introduce the number of cycles and pressure changes to establish a recursive formula for the storage capacity parameter; S4.4: Outputs the effective pore volume under the current pressure and associates it with the gas volume factor to calculate the reservoir capacity.

8. The method for dynamically adjusting the storage capacity of a condensate gas reservoir according to claim 1, characterized in that, The specific steps in S5 are as follows: S5.1: Collect multi-cycle injection and production data of the gas storage facility, including formation pressure, cumulative gas production, and gas compressibility factor; S5.2: Plot the relationship between apparent formation pressure and cumulative gas production, and perform linear regression analysis; S5.3: Based on the slope of the regression line, the actual working gas volume is calculated as: Q work =-1 / b; S5.4: Based on the gas volume coefficient, the actual effective storage capacity of the gas storage facility is verified as: Q 实际 =Q work ×B g ; S5.5: Adjust numerical simulation parameters, including permeability and water body size, to match pressure drop results with production dynamic data; S5.6: Compare the differences in pore volume utilization between the simulation and the actual pure gas zone, transition zone, and water-flooded zone to verify the rationality of the deduction. S5.7: If the deviation is >5%, recalibrate the stress-sensitive or water-flooded parameters.

9. The method for dynamically adjusting the storage capacity of a condensate gas reservoir according to claim 1, characterized in that, The specific steps in S6 are as follows: S6.1: Simulate 6 rounds of injection and production cycles, and record the condensate oil production, gas phase permeability changes and residual oil saturation in each round; S6.2: Calculate the condensate oil back-evaporation efficiency and the rate of change of residual oil saturation based on experimental data; S6.3: Input the experimentally obtained condensate oil back-evaporation efficiency and residual oil saturation change rate into the numerical model to update the ΔV6 calculation formula; S6.4: Compare the experimental data with the model-predicted changes in condensate oil saturation. If the error is >5%, recalibrate the parameters.

10. The method for dynamically adjusting the storage capacity of a condensate gas reservoir according to claim 1, characterized in that, The specific steps in S7 are as follows: S7.1: Based on the modified multi-cycle model, input the current gas storage parameters, run the injection and production simulation for the next 5-10 cycles, and output the dynamic changes in storage capacity, working gas volume and flooding volume; S7.2: Focus on assessing the marginal impact of condensate back-evaporation, stress damage accumulation, and water flooding on storage capacity; S7.3: Through sensitivity analysis, determine the core control parameters of the optimal upper limit of gas injection pressure and the timing of drainage at the end of the cycle; S7.4: Generate the final plan, which includes the prediction curve, optimization parameters and economic analysis, and clarify the target for improving storage capacity utilization.

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