Spontaneous imbibition gas production method and system for tight gas reservoir

Abstract

The invention discloses a spontaneous imbibition gas production method and system for a tight gas reservoir, particularly relates to the technical field of yield increase in oil-gas field development, and is used for solving the problem of gas flow channel blockage caused by mismatching of liquid phase suction and gas output time sequences in a soaking process in the prior art. According to the method, a dynamic balance mechanism of imbibition power and gas output power is established, double chemical agents are adopted to cooperatively regulate and control the imbibition process and gas flow channel maintenance, and the well opening opportunity is accurately determined based on the pressure recovery feature recognition technology to achieve efficient gas phase replacement of the tight gas reservoir. Firstly, reservoir rock physical property parameters and fluid property parameters are obtained, a dynamic equilibrium coefficient is calculated, and the optimal concentration of a first chemical agent and the optimal concentration of a second chemical agent are determined; injecting the chemical agent into the fracturing fluid for hydraulic fracturing, and shutting in the well for soaking, so that the chemical agent forms a wetting modified layer and an interfacial tension adjusting film in the reservoir; the characteristic points established by the gas-phase flow channel are identified by monitoring a pressure recovery curve, and production is started to realize efficient gas recovery.

Description

Technical Field

[0001] This invention relates to the field of production enhancement technology in oil and gas field development, and more specifically, to a method and system for spontaneous seepage gas production in tight gas reservoirs. Background Technology

[0002] Tight gas reservoir development typically requires the use of hydraulic fracturing to construct artificial fracture systems and establish gas flow channels. To improve post-fracturing flowback efficiency and gas recovery, the industry commonly employs methods such as adding flowback aids and wetting reversal agents to the fracturing fluid system. These methods aim to reduce the capillary force binding the liquid phase by lowering the interfacial tension and altering the wettability of the reservoir rock surface, thereby facilitating the flow of fracturing fluid from the matrix to the fractures and creating favorable conditions for gas replacement. Existing technologies primarily focus on improving the performance of single chemical agents, such as developing highly efficient dual-repellent surfactants or potent water-locking agents, and then shutting in the well after fracturing operations, relying on the reservoir's own capillary forces to achieve the permeation and replacement of the fracturing fluid.

[0003] However, existing technologies have significant limitations in practical applications. During the spontaneous adsorption stage of the well-clogging process, capillary force, as the main driving force for liquid phase adsorption into the matrix, exhibits a temporal mismatch with the process of gas production driven by the gas pressure within the matrix. This mismatch leads to a failure of effective synergy between liquid phase adsorption and gas production. The adsorbed liquid phase may prematurely block the micro- and nano-pore throats through which gas flows out, thus inhibiting effective gas replacement and causing the overall efficiency of the spontaneous adsorption process to fall short of expectations. Summary of the Invention

[0004] In order to overcome the above-mentioned defects of the prior art, the present invention provides a method and system for spontaneous seepage gas production in tight gas reservoirs to solve the problems mentioned in the background art.

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

[0006] A method for spontaneous seepage gas extraction from a tight gas reservoir includes the following steps:

[0007] S1. Obtain the rock physical properties and fluid properties of the target reservoir;

[0008] S2. Determine the dynamic balance coefficient between the seepage driving force and the gas production driving force of the target reservoir based on the rock physical property parameters and fluid property parameters, and calculate the first chemical agent concentration used to regulate the liquid phase absorption rate and the second chemical agent concentration used to maintain the gas flow channel based on the dynamic balance coefficient.

[0009] S3. Inject the first and second chemical agents into the fracturing fluid system and pump them into the target reservoir for hydraulic fracturing.

[0010] S4. After hydraulic fracturing is completed, the well is shut in and left to simmer, allowing the first chemical agent to form a wetting and modifying layer on the surface of the reservoir matrix, while the second chemical agent forms an interfacial tension regulating film in the pore throat.

[0011] S5. Monitor the bottom hole pressure recovery data during the well shut-in process and identify specific change characteristics in the pressure recovery curve that characterize the establishment of an effective gas phase flow channel.

[0012] S6. Determine the well opening time and carry out production based on specific change characteristics, so that the reservoir modified by wetting and the interfacial tension can achieve effective gas phase replacement.

[0013] Furthermore, the rock physical properties and fluid properties of the target reservoir are obtained, including:

[0014] The porosity and permeability of the target reservoir are obtained by interpreting well logging data, and the rock and mineral composition of the target reservoir is obtained by core experiment analysis.

[0015] The viscosity of natural gas and the salinity of formation water in the target reservoir were obtained by sampling and analyzing formation fluids.

[0016] Furthermore, based on rock physical properties and fluid properties, the dynamic balance coefficient between the seepage kinetics and gas production kinetics of the target reservoir is determined. Based on this dynamic balance coefficient, the concentrations of a first chemical agent used to regulate the liquid phase inhalation rate and a second chemical agent used to maintain the gas flow channel are calculated, including:

[0017] Based on porosity, permeability, and rock mineral composition, characteristic parameters of capillary force curves were obtained through spontaneous percolation experiments using core samples.

[0018] Based on natural gas viscosity and formation water salinity, characteristic parameters of gas pressure recovery were obtained through pressure decay experiments;

[0019] The characteristic parameters of the capillary force curve and the characteristic parameters of the gas pressure recovery are input into the experimentally calibrated synergistic relationship to calculate the dynamic equilibrium coefficient.

[0020] Based on the numerical range of the dynamic equilibrium coefficient, the concentrations of the first and second chemical agents are obtained by querying the pre-established chemical agent concentration matching relationships.

[0021] Furthermore, the dynamic equilibrium coefficient is calculated by inputting the capillary force curve characteristic parameters and the gas pressure recovery characteristic parameters into the experimentally calibrated synergistic formula. This is achieved by using multiple regression analysis to fit the capillary force curve characteristic parameters obtained from the core experiment and the gas pressure recovery characteristic parameters obtained from the pressure decay experiment, establishing a mathematical expression describing the coupling relationship between the infiltration dynamics and the gas production dynamics. This mathematical expression is used as the synergistic formula, and the specific value of the dynamic equilibrium coefficient is directly calculated by inputting the specific parameters into this synergistic formula.

[0022] Furthermore, based on the numerical range of the dynamic equilibrium coefficient, the first and second chemical agent concentrations are obtained from the pre-established chemical agent concentration matching relationship in the following way: a database of correspondences between different dynamic equilibrium coefficient numerical ranges and optimal chemical agent concentrations is established through a large number of core experiments. This database is stored as a chemical agent concentration matching relationship table. By comparing the actual calculated dynamic equilibrium coefficient values ​​with the numerical ranges in the matching relationship table, the corresponding first and second chemical agent concentration values ​​are obtained.

[0023] Further, the first and second chemical agents are injected into the fracturing fluid system and pumped into the target reservoir for hydraulic fracturing, including:

[0024] Prepare the first chemical reagent solution according to the first chemical reagent concentration, and prepare the second chemical reagent solution according to the second chemical reagent concentration;

[0025] The first chemical agent solution and the second chemical agent solution are respectively added to the fracturing fluid base fluid to form a fracturing fluid system containing the first chemical agent and the second chemical agent;

[0026] The fracturing fluid system is pumped into the target reservoir, and hydraulic fracturing is carried out according to the designed discharge rate and pressure to form an artificial fracture network.

[0027] Furthermore, after hydraulic fracturing is completed, the well is shut in and left to simmer, allowing the first chemical agent to form a wetting and modifying layer on the reservoir matrix surface, while simultaneously allowing the second chemical agent to form an interfacial tension regulating film in the pore throat, including:

[0028] Keep the wellhead closed to allow the fracturing fluid containing the first and second chemical agents to come into full contact with the reservoir matrix under reservoir temperature conditions;

[0029] The first chemical agent in the fracturing fluid is transported to the matrix surface and adsorbed through capillary force to form a wetting and modified layer;

[0030] Simultaneously, the second chemical agent in the fracturing fluid accumulates at the pore throat and forms an interfacial tension regulating film.

[0031] Maintain the well shut-in state until the wetting modification layer and interfacial tension regulating film are stably formed.

[0032] Furthermore, by monitoring bottomhole pressure recovery data during the well shut-in process, specific changes in the pressure recovery curve that characterize the establishment of effective gas flow channels are identified, including:

[0033] Pressure recovery curves are generated by continuously collecting bottom hole pressure data during the well shut-in process using downhole pressure gauges.

[0034] Calculate the first and second derivative curves of the pressure recovery curve;

[0035] Identify the inflection point of the pressure recovery curve when the second derivative curve changes from a negative value to a positive value;

[0036] Confirm the plateau segment of the first derivative curve that appears after the inflection point of the pressure recovery curve;

[0037] The starting point of the plateau segment of the first derivative curve is identified as a specific change characteristic characterizing the establishment of an effective gas-phase flow channel.

[0038] Furthermore, based on specific change characteristics, the timing of well opening and production are determined to enable effective gas phase replacement in the reservoir after wetting modification and interfacial tension adjustment, including:

[0039] Once the starting point of the plateau segment of the first derivative curve is identified, the production valves are immediately opened to initiate well opening operations.

[0040] The nozzle size and gas production are controlled according to the pre-designed production system, so that the gas in the reservoir can be stably produced through the established effective gas phase flow channel.

[0041] Maintaining the production pressure differential enables the reservoir treated with the wetting modification layer and the interfacial tension regulating membrane to achieve effective gas phase replacement.

[0042] On the other hand, the present invention provides a spontaneous seepage gas production system for tight gas reservoirs, comprising the following modules:

[0043] The parameter acquisition module is used to acquire the rock physical properties and fluid properties of the target reservoir.

[0044] The concentration control module is used to determine the dynamic balance coefficient between the seepage driving force and the gas production driving force of the target reservoir based on the rock physical property parameters and fluid property parameters, and to calculate the first chemical agent concentration used to control the liquid phase inhalation rate and the second chemical agent concentration used to maintain the gas flow channel based on the dynamic balance coefficient.

[0045] The hydraulic fracturing module is used to inject the first and second chemical agents into the fracturing fluid system and pump them into the target reservoir for hydraulic fracturing.

[0046] The forming module is used to shut in and simmer the well after hydraulic fracturing is completed, so that the first chemical agent forms a wetting and modifying layer on the surface of the reservoir matrix, while the second chemical agent forms an interfacial tension regulating film in the pore throat.

[0047] The feature recognition module is used to monitor the bottom hole pressure recovery data during the well shut-in process and identify specific change features in the pressure recovery curve that characterize the establishment of an effective gas phase flow channel.

[0048] The timing determination module is used to determine the timing of well opening and production based on specific change characteristics, so that the reservoir modified by wetting and interfacial tension can achieve effective gas phase replacement.

[0049] Compared with the prior art, the present invention has the following beneficial effects:

[0050] 1. By synergistically regulating the infiltration and gas production dynamics, a dynamic balance between liquid phase inhalation and gas production during the well-clogging process in tight gas reservoirs is achieved. Specifically, a dynamic balance coefficient is introduced to precisely quantify the matching relationship between reservoir infiltration and production capacity. Based on this coefficient, the concentrations of the first and second chemical agents are intelligently proportioned, enabling the wetting modification layer and the interfacial tension regulating film to form synchronously at different locations in the reservoir. This synergistic effect ensures that the fracturing fluid effectively infiltrates the matrix under capillary force, while maintaining unobstructed gas flow channels through interfacial tension regulation, fundamentally solving the problem of mismatched timing between liquid phase inhalation and gas production in traditional methods.

[0051] 2. By accurately identifying the establishment timing of effective gas flow channels through real-time monitoring of pressure recovery characteristics, the optimal timing for switching from well shut-in to production is achieved. Based on the characteristic identification mechanism of pressure recovery curve derivative changes, the critical state of gas flow channel formation within the reservoir can be accurately captured, thereby initiating production at the most suitable time. This intelligent decision-making mechanism based on physical feature identification ensures that reservoirs modified by wetting and interfacial tension adjustment can achieve efficient gas phase replacement, significantly improving gas recovery efficiency after fracturing in tight gas reservoirs. Attached Figure Description

[0052] Figure 1 This is a flowchart of a method for spontaneous seepage gas extraction from a tight gas reservoir according to the present invention;

[0053] Figure 2 This is a schematic diagram of the structure of a spontaneous seepage gas extraction system for a tight gas reservoir according to the present invention. Detailed Implementation

[0054] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. 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.

[0055] Example 1: Figure 1 This invention provides a method for spontaneous seepage gas extraction from tight gas reservoirs, comprising the following steps:

[0056] S1. Obtain the rock physical properties and fluid properties of the target reservoir;

[0057] S2. Determine the dynamic balance coefficient between the seepage driving force and the gas production driving force of the target reservoir based on the rock physical property parameters and fluid property parameters, and calculate the first chemical agent concentration used to regulate the liquid phase absorption rate and the second chemical agent concentration used to maintain the gas flow channel based on the dynamic balance coefficient.

[0058] S3. Inject the first and second chemical agents into the fracturing fluid system and pump them into the target reservoir for hydraulic fracturing.

[0059] S4. After hydraulic fracturing is completed, the well is shut in and left to simmer, allowing the first chemical agent to form a wetting and modifying layer on the surface of the reservoir matrix, while the second chemical agent forms an interfacial tension regulating film in the pore throat.

[0060] S5. Monitor the bottom hole pressure recovery data during the well shut-in process and identify specific change characteristics in the pressure recovery curve that characterize the establishment of an effective gas phase flow channel.

[0061] S6. Determine the well opening time and carry out production based on specific change characteristics, so that the reservoir modified by wetting and the interfacial tension can achieve effective gas phase replacement.

[0062] S1. Obtain the rock physical properties and fluid properties of the target reservoir. The specific implementation is as follows:

[0063] When obtaining the rock physical and fluid properties of the target reservoir, the porosity and permeability are first determined through well logging data interpretation. Specifically, density logging and neutron logging data are used to calculate porosity values ​​using a dual-water model; for example, the calculated porosity values ​​typically range from 5% to 15%. Permeability is obtained by calculating permeability using resistivity logging curves combined with Archie's formula, while also referencing core analysis data to establish a permeability interpretation model. The final permeability values ​​range, for example, from 0.01 millidarcy to 1 millidarcy. The model parameters used in these well logging interpretation processes are pre-calibrated based on the regional geological characteristics, ensuring the accuracy of the interpretation results.

[0064] When obtaining the rock and mineral composition of the target reservoir through core experiments, representative core samples are first obtained from the cored well section of the target reservoir. These core samples are then pulverized to a particle size of 200 mesh and analyzed using an X-ray diffractometer. A copper target X-ray source is used, with an operating voltage of 40 kV, an operating current of 30 mA, a scanning range of 5° to 65°, and a scanning speed of 2° per minute. By analyzing the intensity of characteristic peaks in the diffraction pattern, the relative contents of major minerals such as quartz, feldspar, and clay minerals are calculated. Further quantitative analysis of montmorillonite, illite, and kaolinite is required for the clay minerals. The final rock and mineral composition is expressed as a mass percentage of each mineral, with the sum of all components equal to 100%.

[0065] When obtaining the natural gas viscosity and formation water salinity of a target reservoir through formation fluid sampling and analysis, a representative formation fluid sample is first obtained from the target reservoir using a downhole sampler. The obtained sample is then transferred to a high-pressure physical property analyzer for component analysis. Gas chromatography is used to determine the mole fraction of each component in the natural gas. Based on the critical parameters and interaction coefficients of each component, the viscosity of the natural gas under formation temperature of 80 degrees Celsius and formation pressure of 30 MPa is calculated using the principle of corresponding states. This viscosity value is, for example, in the range of 0.02 centipoise to 0.08 centipoise. The formation water salinity is determined by filtering the water sample and analyzing it using ion chromatography. The concentrations of major ions such as chloride, sodium, calcium, and magnesium ions are measured. Finally, the total salinity is expressed in milligrams per liter (mg / L), with a value range, for example, between 10,000 mg / L and 200,000 mg / L. All analytical procedures are performed using industry-standard analytical methods to ensure the reliability and accuracy of the data.

[0066] S2. Determine the dynamic balance coefficient between the seepage kinetics and gas production kinetics of the target reservoir based on the rock physical properties and fluid properties. Calculate the first chemical agent concentration used to regulate the liquid phase inhalation rate and the second chemical agent concentration used to maintain the gas flow channel based on the dynamic balance coefficient. Specifically, the implementation is as follows:

[0067] The specific implementation process for obtaining the characteristic parameters of the capillary force curve through spontaneous core adsorption experiments based on porosity, permeability, and rock mineral composition is as follows. First, a representative standard core sample from the target reservoir is selected. The core sample has a diameter of 2.5 cm and a length of 5 cm. After washing and drying, its basic physical properties are determined. The core sample is placed in a core holder and saturated with formation water under simulated formation temperature of 80 degrees Celsius and confining pressure of 20 MPa. After saturation, one end of the core sample is connected to a simulated fracture container filled with fracturing fluid containing a tracer. The change in core sample mass is monitored in real time using a high-precision balance, and the data on the change in core mass over time during adsorption are recorded. Based on the adsorption experiment data, a curve relating adsorption recovery rate to the square root of time is plotted. Characteristic parameters such as the maximum adsorption rate, final adsorption recovery rate, and half-life are extracted from the curve. These parameters together constitute the characteristic parameters of the capillary force curve. During the experiment, the temperature fluctuation range was kept within ±1 degree Celsius, and the pressure fluctuation range was kept within ±0.5 MPa to ensure the stability of the experimental conditions.

[0068] The specific implementation method for obtaining gas pressure recovery characteristic parameters through pressure decay experiments based on natural gas viscosity and formation water salinity is as follows. First, standard core samples with a diameter of 2.5 cm and a length of 5 cm are prepared. After oil washing and drying, they are saturated under formation water salinity conditions. The saturated core samples are then placed in a core holder, and a confining pressure of 20 MPa is applied while maintaining the temperature at 80 degrees Celsius. Natural gas with an initial pressure of 30 MPa is applied to one end of the core sample, and then the inlet valve is quickly closed. The pressure decay over time is recorded. Pressure data is collected using a high-precision pressure sensor at a sampling frequency of 1 time per second, continuously monitored until the pressure decay stabilizes. Characteristic parameters such as the pressure recovery half-life, final stable pressure, and decay curve slope are extracted from the pressure decay curve. These parameters together constitute the gas pressure recovery characteristic parameters. Temperature fluctuations are strictly controlled within ±1 degree Celsius during the experiment to ensure the accuracy of the experimental data.

[0069] The specific process for calculating the dynamic equilibrium coefficient by inputting the characteristic parameters of the capillary force curve and the characteristic parameters of gas pressure recovery into an experimentally calibrated synergistic formula is as follows. First, a training dataset is established through numerous core experiments. This dataset contains combinations of characteristic parameters of the capillary force curve and gas pressure recovery obtained under different physical property conditions. Multiple regression analysis is used to fit the training data, establishing a mathematical expression describing the coupling relationship between adsorption and gas production dynamics. This mathematical expression includes multiple characteristic parameters as input variables, such as maximum adsorption rate and pressure recovery half-life, and the output is the dynamic equilibrium coefficient. Each coefficient in the mathematical expression is determined using the least squares method to ensure that the error between the predicted and experimental values ​​is minimized. In practical applications, the numerical values ​​of the characteristic parameters obtained from specific experiments are input into this mathematical expression to directly calculate the specific value of the dynamic equilibrium coefficient. The dynamic equilibrium coefficient typically ranges from 0.1 to 10; a larger value indicates a better synergistic effect between adsorption and gas production dynamics.

[0070] The specific implementation method for obtaining the first and second chemical agent concentrations from a pre-established chemical agent concentration matching relationship based on the numerical range of the dynamic equilibrium coefficient is as follows. First, a chemical agent concentration optimization database is established through numerous core experiments. This database contains the optimal chemical agent concentration combinations corresponding to different dynamic equilibrium coefficient ranges. During the experiments, multiple chemical agent concentration ratio schemes are tested for each dynamic equilibrium coefficient range. The optimal concentration combination is determined by comparing the percolation effect and gas flow performance. These experimental data are compiled into a chemical agent concentration matching relationship table, which clearly lists the dynamic equilibrium coefficient range and the corresponding first and second chemical agent concentration ranges. In practical applications, the calculated dynamic equilibrium coefficient values ​​are compared with the numerical ranges in the matching relationship table. Once the corresponding range is found, the corresponding first and second chemical agent concentration values ​​can be retrieved. The first chemical agent concentration is usually expressed as a mass percentage, for example, ranging from 0.1% to 1%. The second chemical agent concentration is also expressed as a mass percentage, for example, ranging from 0.05% to 0.5%. The matching relationship table also considers the influence of environmental factors such as formation temperature and pressure to ensure the accuracy of the recommended concentrations.

[0071] S3. Inject the first and second chemical agents into the fracturing fluid system and pump them into the target reservoir for hydraulic fracturing. The specific implementation is as follows:

[0072] The specific implementation process for preparing the first chemical reagent solution according to the first chemical reagent concentration and the second chemical reagent solution according to the second chemical reagent concentration is as follows: First, calculate the required mass of the first chemical reagent based on the first chemical reagent concentration value obtained from the chemical reagent concentration matching relationship. For example, when the first chemical reagent concentration is 0.5%, 5 kg of the first chemical reagent is needed to prepare 1000 kg of solution. Slowly add the weighed first chemical reagent powder to the stirred clean water, maintaining the water temperature between 25°C and 30°C, and controlling the stirring speed at 200 rpm to 300 rpm. Continue stirring for 30 to 40 minutes until completely dissolved, forming a homogeneous first chemical reagent solution. Similarly, calculate the required mass of the second chemical reagent based on the obtained second chemical reagent concentration value. For example, when the second chemical reagent concentration is 0.2%, 2 kg of the second chemical reagent is needed to prepare 1000 kg of solution. Add the weighed second chemical agent to clean water in another container, maintaining the water temperature between 20°C and 25°C. Stir at 150 to 200 rpm for 20 to 30 minutes until completely dissolved, forming a homogeneous solution of the second chemical agent. Use an electronic balance with an accuracy of 0.1 grams for weighing during the preparation process to ensure the accuracy of the chemical agent dosage.

[0073] The specific implementation method for adding the first and second chemical agent solutions to the fracturing fluid base fluid to form a fracturing fluid system containing the first and second chemical agents is as follows: First, prepare the fracturing fluid base fluid, which is mainly water with added thickeners, anti-swelling agents, and other conventional additives. Add the first chemical agent solution to the fracturing fluid base fluid according to the designed ratio, for example, 0.5% to 1% of the total volume of the fracturing fluid. Next, add the second chemical agent solution to the fracturing fluid base fluid according to the designed ratio, for example, 0.2% to 0.5% of the total volume of the fracturing fluid. During the addition process, maintain stirring at a speed of 100 to 150 rpm to ensure uniform mixing of the chemical agent solutions and the fracturing fluid base fluid. After mixing, sample the fracturing fluid system for testing to determine the actual concentrations of the first and second chemical agents, ensuring that the deviation from the designed concentration does not exceed ±5%. Simultaneously, test the viscosity, pH value, and other indicators of the fracturing fluid to ensure that the performance of the fracturing fluid meets the construction requirements.

[0074] The specific implementation process for pumping the fracturing fluid system into the target reservoir and performing hydraulic fracturing according to the designed displacement and pressure to form an artificial fracture network is as follows: First, the prepared fracturing fluid system is transferred to the sand mixing truck of the fracturing unit. The proppant is then added to the fracturing fluid system according to the designed proportion, typically 10% to 30% of the total fracturing fluid volume. The fracturing pump truck is started, and the fracturing fluid system is pumped into the wellbore according to the designed displacement, typically 4 to 8 cubic meters per minute. During pumping, the wellhead pressure is monitored in real time using a surface pressure monitoring system. The pumping pressure is controlled above the reservoir fracturing pressure but below the pressure limit of the wellhead equipment; for example, the operating pressure is controlled within the range of 50 to 70 MPa. After the fracturing fluid enters the reservoir, artificial fractures are formed. The expansion of these fractures is controlled by adjusting the pumping displacement and pressure, resulting in an artificial fracture network with a certain length and conductivity. During construction, parameters such as pump injection rate, pressure, and fluid volume are recorded in real time. Construction parameters are adjusted promptly based on pressure response characteristics to ensure the formation of an effective artificial fracture network. After construction, the well is immediately shut in and enters the well-closing phase.

[0075] S4. After hydraulic fracturing is completed, the well is shut in and allowed to simmer, allowing the first chemical agent to form a wetting and modifying layer on the reservoir matrix surface, while the second chemical agent forms an interfacial tension regulating film in the pore throat. Specifically, this is implemented as follows:

[0076] The specific implementation process for maintaining the wellhead closed to ensure sufficient contact between the fracturing fluid containing the first and second chemical agents and the reservoir matrix under reservoir temperature conditions is as follows: After hydraulic fracturing operations are completed, immediately close all wellhead valves to ensure a complete wellbore seal. At this time, the wellbore is filled with fracturing fluid containing the first and second chemical agents, and the fracturing fluid begins to contact the reservoir matrix under reservoir temperature conditions. The reservoir temperature is typically maintained within the range of 80°C to 120°C. Temperature changes are monitored in real time using a downhole temperature monitoring system to ensure that temperature fluctuations do not exceed ±2°C. The contact time between the fracturing fluid and the reservoir matrix is ​​typically 48 to 72 hours. During this period, the wellhead pressure is maintained within the range of 10 MPa to 20 MPa to ensure that the fracturing fluid can fully penetrate the matrix pores. Pressure changes are continuously recorded using a wellhead pressure gauge at 1-hour intervals to ensure that the pressure remains stable within the set range.

[0077] The specific implementation of the transport and adsorption of the primary chemical agent in the fracturing fluid to the matrix surface and the formation of a wetting-modified layer through capillary forces is as follows. During the shut-in and shut-in process, the primary chemical agent in the fracturing fluid spontaneously migrates to the reservoir matrix surface under the action of capillary forces. The primary chemical agent molecules enter the matrix pores through diffusion, and their migration rate depends on the magnitude of the capillary force and the chemical agent concentration gradient. The primary chemical agent molecules that have migrated to the matrix surface combine with the rock surface through chemisorption to form a monolayer wetting-modified layer. The formation process of this wetting-modified layer can be monitored by changes in the contact angle; for example, a change in the contact angle from hydrophilic 30 degrees to hydrophobic 110 degrees indicates a significant change in wettability. The thickness of the wetting-modified layer is typically 1 to 10 nanometers, and a coverage of over 90% is considered effective. Maintaining a stable reservoir temperature is crucial during the formation process, as temperature fluctuations can affect the adsorption rate and modification effect of the chemical agent.

[0078] The specific implementation method for simultaneously causing the second chemical agent in the fracturing fluid to accumulate at the pore throat and form an interfacial tension regulating film is as follows. The second chemical agent, flowing with the fracturing fluid, reaches the pore throat. Due to the capillary effect and interfacial tension at the pore throat, the second chemical agent selectively accumulates there. The second chemical agent molecules align directionally at the oil-gas-water interface, forming a stable interfacial tension regulating film by reducing interfacial tension. This interfacial tension regulating film can reduce the oil-water interfacial tension from the original 30 millinewtons per meter to below 1 millinewton per meter, significantly improving fluid flowability. The thickness of the interfacial tension regulating film is typically 5 to 20 nanometers. During its formation, appropriate ionic strength and pH conditions must be maintained, for example, a pH value maintained between 6.5 and 7.5, and an ionic strength maintained between 0.1 mol / L and 0.5 mol / L. Changes in interfacial tension can be monitored using an interfacial tension meter to confirm the formation effect of the interfacial tension regulating film.

[0079] The specific procedures for maintaining the well shut-in state until the wetting-modified layer and interfacial tension regulating film are stably formed are as follows: The shut-in time needs to be determined based on reservoir conditions and chemical agent characteristics, typically 3 to 7 days. During this period, the progress of the chemical agent's action is assessed by periodically monitoring changes in wellhead pressure and temperature. When the wellhead pressure change rate is less than 0.01 MPa per hour and the temperature fluctuation is less than 1 degree Celsius, it indicates that the system has reached a stable state. Simultaneously, chemical agent concentration changes are analyzed through downhole fluid sampling. When the concentration decrease of the first chemical agent is less than 5% and the concentration decrease of the second chemical agent is less than 3%, it indicates that the adsorption and aggregation process of the chemical agent is basically complete. To confirm the stability of the wetting-modified layer and interfacial tension regulating film, a small-scale well opening test can be conducted to observe the pressure recovery characteristics. If the pressure recovery curve shows a steady upward trend without significant fluctuations, it indicates that the wetting-modified layer and interfacial tension regulating film have been stably formed, and the next production stage can begin. Throughout the entire shut-in and well-shutting process, the well site must be kept quiet to avoid any vibration interference and ensure the stability of the chemical agent's action process.

[0080] S5. Monitor the bottom hole pressure recovery data during the well shut-in process, and identify specific changes in the pressure recovery curve that characterize the establishment of an effective gas phase flow channel. Specifically, this is implemented as follows:

[0081] The specific implementation process of generating a pressure recovery curve by continuously collecting bottom hole pressure data during the well shut-in process using a downhole pressure gauge is as follows: A high-precision quartz pressure gauge is lowered to the middle of the producing formation. The gauge has high measurement accuracy, and data is collected at fixed time intervals. The pressure gauge monitors the bottom hole pressure changes in real time, and the monitoring duration needs to cover the entire pressure recovery phase until the pressure changes tend to stabilize. The collected pressure data is transmitted to the surface data acquisition system via cable. The system automatically records the correspondence between time and pressure, forming the raw pressure dataset. The raw data is preprocessed, including removing outlier data points and performing data smoothing. Outlier determination is based on the variation range of adjacent data points. The preprocessed data is plotted as a pressure recovery curve according to the time series, with the horizontal axis representing time and the vertical axis representing pressure. The pressure recovery curve reflects the change law of bottom hole pressure recovery over time after well shut-in, and the shape characteristics of the curve are closely related to the reservoir permeability.

[0082] The specific implementation method for calculating the first and second derivative curves of the pressure recovery curve is as follows: The first derivative of the pressure recovery curve is calculated using numerical differentiation. For each data point, the instantaneous rate of change is obtained by calculating the ratio of the pressure change to the time change between adjacent data points. An appropriate data window size is set during the calculation to ensure the smoothness of the derivative curve. After obtaining the first derivative curve, the second derivative is calculated using the same numerical differentiation method, i.e., the first derivative curve is differentiated again to obtain the acceleration of the pressure change. All derivative calculations are standardized to avoid the influence of dimensions on the analysis results. After the calculation is completed, the first and second derivative curves are plotted respectively, with the horizontal axis representing time and the vertical axis representing the rate of pressure change and the acceleration of the pressure change, respectively.

[0083] The specific method for identifying the inflection point of the pressure recovery curve corresponding to the transition from a negative to a positive value in the second derivative curve is as follows: A systematic analysis of the second derivative curve is performed to find the point where the value changes from negative to positive. When the second derivative values ​​of multiple consecutive data points continuously increase from negative to positive and cross zero, this point is considered a transition from negative to positive. The time coordinate corresponding to this point is mapped onto the original pressure recovery curve to locate the corresponding pressure data point; this point is the inflection point of the pressure recovery curve. At the inflection point, the acceleration of pressure change is zero, indicating a stage transition in the pressure recovery process. To ensure accuracy, a reasonable threshold condition is set, requiring the change in the second derivative at the inflection point to reach a certain standard to avoid misjudging noise fluctuations. Simultaneously, a sufficient number of data points before and after the inflection point must maintain the same sign for their second derivatives to ensure the reliability of the inflection point.

[0084] The specific implementation process for the plateau segment of the first derivative curve after confirming the inflection point of the pressure recovery curve is as follows: After locating the inflection point, the changing characteristics of the first derivative curve are analyzed backward. The criteria for determining the plateau segment are that the first derivative value remains relatively stable over a continuous time period, with fluctuations controlled within a reasonable range. The duration of the plateau segment needs to reach a certain length, during which the rate of change of the first derivative value remains at a low level. The starting point of the plateau segment is defined as the first data point that meets specific conditions, requiring that the deviation of the first derivative values ​​of multiple consecutive data points after this point from the average value is less than a set range, and the value change trend is stable. To eliminate the interference of random fluctuations, the dispersion of data points within the plateau segment is required to be less than a specified threshold. At the same time, the first derivative value of the plateau segment should be significantly greater than the previous value, indicating that the pressure recovery rate has reached a new stable stage.

[0085] The specific method for identifying the starting point of the plateau segment of the first derivative curve as a specific change characteristic representing the establishment of an effective gas-phase flow channel is as follows: Once a plateau segment meeting the conditions is confirmed in the first derivative curve, the starting point of the plateau segment is used as the feature identification point. The time and pressure coordinates corresponding to this point are the key parameters of the specific change characteristic. This characteristic indicates that the gas-phase flow channel within the reservoir has been effectively established, and the pressure recovery mode has changed from an early, slow recovery to a stable and rapid recovery. To ensure identification accuracy, the pressure recovery at this feature point must account for a significant proportion of the total recovery, and the pressure recovery rate must remain stable for a period of time thereafter. This feature point indicates that the wetting modification layer and the interfacial tension regulating film have fully played their roles, and the gas-phase permeability has been significantly improved. The identification of this feature point provides a direct basis for determining the optimal well opening time, indicating that the reservoir is ready for efficient production.

[0086] S6. Determine the well opening timing and conduct production based on specific change characteristics to achieve effective gas phase replacement in the reservoir that has undergone wetting modification and interfacial tension adjustment. Specifically, this is implemented as follows:

[0087] The specific implementation process for opening a well upon identifying the starting point of the plateau segment on the first derivative curve is as follows: After detecting the starting point of the plateau segment on the first derivative curve of the pressure recovery curve, an opening command is immediately issued through the control system. The opening operation begins with a slow opening of the production valves, initially controlled at 10% to 20% to avoid pressure surges impacting the reservoir. During the opening process, wellhead pressure changes are monitored in real time, with the pressure drop rate controlled within the range of 0.5 MPa to 1 MPa per hour. Once the wellhead pressure stabilizes, the valve opening is gradually increased to full open. The optimal time for well opening is within two hours of the plateau segment starting point, at which point a complete and effective gas flow channel has been established within the reservoir, and the wetting modification layer and interfacial tension regulating film have reached their optimal function. The relationship between valve opening changes and pressure response is recorded during the well opening process to provide a reference for subsequent production system adjustments.

[0088] The specific operations for controlling nozzle size and gas production according to a pre-designed production system to ensure stable gas production from the reservoir through established effective gas-phase flow channels are as follows: Based on reservoir properties and fracture network characteristics, a reasonable production system is formulated, including the nozzle size selection range and gas production control targets. In the initial production stage, smaller nozzle sizes are used, such as nozzles with a diameter of four to six millimeters, to control the daily gas production at a low level. The production pressure differential is controlled by adjusting the nozzle size, maintaining it within 30% to 50% of the reservoir fracture pressure. Gas production is controlled by adjusting the nozzle size and wellhead pressure, keeping the gas production stable within ±5% of the design value. During production, parameters such as gas production, wellhead pressure, and pressure differential before and after the nozzle are monitored in real time to ensure stable gas production through the effective gas-phase flow channels.

[0089] The specific implementation method for maintaining the production pressure differential to achieve effective gas-phase replacement in reservoirs treated with wetting-modified layers and interfacial tension regulating films is as follows. By precisely controlling the nozzle size and wellhead pressure, the production pressure differential is maintained within an optimal range, such as 2 MPa to 5 MPa. This production pressure differential ensures effective gas production while preventing reservoir damage. During the maintenance of the production pressure differential, the wetting-modified layer keeps the reservoir surface hydrophobic, reducing water phase flow resistance; the interfacial tension regulating film reduces oil-gas interfacial tension, improving gas flow efficiency. Effective gas-phase replacement is characterized by a stable increase in gas production, a gradual decrease in water production, and a continuous improvement in the gas-water ratio. Pressure recovery tests are conducted periodically during production to verify the stability of the effective gas-phase flow channels, and the production pressure differential is adjusted based on the test results. Continuous monitoring and timely adjustments are maintained throughout the entire production phase to ensure long-term stable effective gas-phase replacement in the reservoir.

[0090] Example 2: Figure 2 A schematic diagram of a spontaneous seepage gas production system for a tight gas reservoir according to the present invention is provided. The spontaneous seepage gas production system for a tight gas reservoir includes the following modules:

[0091] The parameter acquisition module is used to acquire the rock physical properties and fluid properties of the target reservoir.

[0092] The concentration control module is used to determine the dynamic balance coefficient between the seepage driving force and the gas production driving force of the target reservoir based on the rock physical property parameters and fluid property parameters, and to calculate the first chemical agent concentration used to control the liquid phase inhalation rate and the second chemical agent concentration used to maintain the gas flow channel based on the dynamic balance coefficient.

[0093] The hydraulic fracturing module is used to inject the first and second chemical agents into the fracturing fluid system and pump them into the target reservoir for hydraulic fracturing.

[0094] The forming module is used to shut in and simmer the well after hydraulic fracturing is completed, so that the first chemical agent forms a wetting and modifying layer on the surface of the reservoir matrix, while the second chemical agent forms an interfacial tension regulating film in the pore throat.

[0095] The feature recognition module is used to monitor the bottom hole pressure recovery data during the well shut-in process and identify specific change features in the pressure recovery curve that characterize the establishment of an effective gas phase flow channel.

[0096] The timing determination module is used to determine the timing of well opening and production based on specific change characteristics, so that the reservoir modified by wetting and interfacial tension can achieve effective gas phase replacement.

[0097] All calculations involved in the embodiments are dimensionless numerical calculations, and the preset parameters and thresholds in the calculations are set by those skilled in the art according to the actual situation.

[0098] The above embodiments can be implemented, in whole or in part, by software, hardware, firmware, or any other combination thereof. When implemented using software, the above embodiments can be implemented, in whole or in part, in the form of a computer program product.

[0099] Those skilled in the art will recognize that the modules and algorithm steps of the various examples described in conjunction with the embodiments disclosed herein can be implemented in electronic hardware, or a combination of computer software and electronic hardware. Whether these functions are implemented in hardware or software depends on the specific application and inventive constraints of the technical solution. Those skilled in the art can use different methods to implement the described functions for each specific application, but such implementation should not be considered beyond the scope of this application.

[0100] In addition, the functional modules in the various embodiments of this application can be integrated into one processing module, or each module can exist physically separately, or two or more modules can be integrated into one module.

[0101] In the several embodiments provided in this application, it should be understood that the disclosed systems, apparatuses, and methods can be implemented in other ways. For example, the apparatus embodiments described above are merely illustrative; for instance, the division of modules is only a logical functional division, and in actual implementation, there may be other division methods. For example, multiple modules or components may be combined or integrated into another system, or some features may be ignored or not executed. Furthermore, the coupling or direct coupling or communication connection shown or discussed may be through some interfaces; the indirect coupling or communication connection between apparatuses or modules may be electrical, mechanical, or other forms.

[0102] The above description is merely a specific embodiment of this application, but the scope of protection of this application is not limited thereto. Any variations or substitutions that can be easily conceived by those skilled in the art within the scope of the technology disclosed in this application should be included within the scope of protection of this application. Therefore, the scope of protection of this application should be determined by the scope of the claims.

[0103] In conclusion, the above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

Claims

1. A method for spontaneous seepage gas extraction from a tight gas reservoir, characterized in that, Includes the following steps: S1. Obtain the rock physical properties and fluid properties of the target reservoir; S2. Determine the dynamic balance coefficient between the seepage driving force and the gas production driving force of the target reservoir based on the rock physical property parameters and fluid property parameters, and calculate the first chemical agent concentration used to regulate the liquid phase absorption rate and the second chemical agent concentration used to maintain the gas flow channel based on the dynamic balance coefficient. S3. Inject the first and second chemical agents into the fracturing fluid system and pump them into the target reservoir for hydraulic fracturing. S4. After hydraulic fracturing is completed, the well is shut in and left to simmer, allowing the first chemical agent to form a wetting and modifying layer on the surface of the reservoir matrix, while the second chemical agent forms an interfacial tension regulating film in the pore throat. S5. Monitor the bottom hole pressure recovery data during the well shut-in process and identify specific change characteristics in the pressure recovery curve that characterize the establishment of an effective gas phase flow channel. S6. Determine the well opening time and carry out production based on specific change characteristics, so that the reservoir modified by wetting and the interfacial tension can achieve effective gas phase replacement.

2. The method for spontaneous seepage gas extraction from a tight gas reservoir according to claim 1, characterized in that, Obtain the rock physical properties and fluid properties of the target reservoir, including: The porosity and permeability of the target reservoir are obtained by interpreting well logging data, and the rock and mineral composition of the target reservoir is obtained by core experiment analysis. The viscosity of natural gas and the salinity of formation water in the target reservoir were obtained by sampling and analyzing formation fluids.

3. The method for spontaneous seepage gas extraction from a tight gas reservoir according to claim 2, characterized in that, The dynamic balance coefficient between the seepage and gas production forces of the target reservoir is determined based on rock physical parameters and fluid properties. The concentrations of the first chemical agent used to regulate the liquid phase inhalation rate and the second chemical agent used to maintain the gas flow channel are then calculated based on these dynamic balance coefficients. Based on porosity, permeability, and rock mineral composition, characteristic parameters of capillary force curves were obtained through spontaneous percolation experiments using core samples. Based on natural gas viscosity and formation water salinity, characteristic parameters of gas pressure recovery were obtained through pressure decay experiments; The characteristic parameters of the capillary force curve and the characteristic parameters of the gas pressure recovery are input into the experimentally calibrated synergistic relationship to calculate the dynamic equilibrium coefficient. Based on the numerical range of the dynamic equilibrium coefficient, the concentrations of the first and second chemical agents are obtained by querying the pre-established chemical agent concentration matching relationships.

4. The method for spontaneous seepage gas extraction from a tight gas reservoir according to claim 3, characterized in that, The dynamic equilibrium coefficient is calculated by inputting the characteristic parameters of the capillary force curve and the characteristic parameters of gas pressure recovery into the experimentally calibrated synergistic formula. This is achieved by using multiple regression analysis to fit the characteristic parameters of the capillary force curve obtained from the core experiment and the characteristic parameters of gas pressure recovery obtained from the pressure decay experiment, establishing a mathematical expression describing the coupling relationship between the infiltration dynamics and the gas production dynamics. This mathematical expression is used as the synergistic formula, and the specific value of the dynamic equilibrium coefficient is directly calculated by inputting the specific parameters into this synergistic formula.

5. A method for spontaneous seepage gas extraction from a tight gas reservoir according to claim 3, characterized in that, Based on the numerical range of the dynamic equilibrium coefficient, the first and second chemical agent concentrations are obtained from the pre-established chemical agent concentration matching relationship in the following way: A database of correspondences between different dynamic equilibrium coefficient numerical ranges and optimal chemical agent concentrations is established through a large number of core experiments. This database is stored as a chemical agent concentration matching relationship table. By comparing the actual calculated dynamic equilibrium coefficient values ​​with the numerical ranges in the matching relationship table, the corresponding first and second chemical agent concentration values ​​are obtained.

6. A method for spontaneous seepage gas extraction from a tight gas reservoir according to claim 3, characterized in that, Injecting the first and second chemical agents into the fracturing fluid system and pumping them into the target reservoir for hydraulic fracturing includes: Prepare the first chemical reagent solution according to the first chemical reagent concentration, and prepare the second chemical reagent solution according to the second chemical reagent concentration; The first chemical agent solution and the second chemical agent solution are respectively added to the fracturing fluid base fluid to form a fracturing fluid system containing the first chemical agent and the second chemical agent; The fracturing fluid system is pumped into the target reservoir, and hydraulic fracturing is carried out according to the designed discharge rate and pressure to form an artificial fracture network.

7. A method for spontaneous seepage gas extraction from a tight gas reservoir according to claim 6, characterized in that, After hydraulic fracturing is completed, the well is shut in and left to simmer, allowing the first chemical agent to form a wetting and modifying layer on the reservoir matrix surface, while simultaneously allowing the second chemical agent to form an interfacial tension regulating film in the pore throat, including: Keep the wellhead closed to allow the fracturing fluid containing the first and second chemical agents to come into full contact with the reservoir matrix under reservoir temperature conditions; The first chemical agent in the fracturing fluid is transported to the matrix surface and adsorbed through capillary force to form a wetting and modified layer; Simultaneously, the second chemical agent in the fracturing fluid accumulates at the pore throat and forms an interfacial tension regulating film. Maintain the well shut-in state until the wetting modification layer and interfacial tension regulating film are stably formed.

8. A method for spontaneous seepage gas extraction from a tight gas reservoir according to claim 7, characterized in that, Monitor bottomhole pressure recovery data during the well shut-in process and identify specific changes in the pressure recovery curve that characterize the establishment of effective gas flow channels, including: Pressure recovery curves are generated by continuously collecting bottom hole pressure data during the well shut-in process using downhole pressure gauges. Calculate the first and second derivative curves of the pressure recovery curve; Identify the inflection point of the pressure recovery curve when the second derivative curve changes from a negative value to a positive value; Confirm the plateau segment of the first derivative curve that appears after the inflection point of the pressure recovery curve; The starting point of the plateau segment of the first derivative curve is identified as a specific change characteristic characterizing the establishment of an effective gas-phase flow channel.

9. A method for spontaneous seepage gas extraction from a tight gas reservoir according to claim 8, characterized in that, Determining well opening timing and initiating production based on specific change characteristics enables effective gas phase replacement in reservoirs that have undergone wetting modification and interfacial tension adjustment, including: Once the starting point of the plateau segment of the first derivative curve is identified, the production valves are immediately opened to initiate well opening operations. The nozzle size and gas production are controlled according to the pre-designed production system, so that the gas in the reservoir can be stably produced through the established effective gas phase flow channel. Maintaining the production pressure differential enables the reservoir treated with the wetting modification layer and the interfacial tension regulating membrane to achieve effective gas phase replacement.

10. A system for spontaneous seepage gas production in a tight gas reservoir, used to implement the method for spontaneous seepage gas production in a tight gas reservoir as described in any one of claims 1-9, characterized in that, Includes the following modules: The parameter acquisition module is used to acquire the rock physical properties and fluid properties of the target reservoir. The concentration control module is used to determine the dynamic balance coefficient between the seepage driving force and the gas production driving force of the target reservoir based on the rock physical property parameters and fluid property parameters, and to calculate the first chemical agent concentration used to control the liquid phase inhalation rate and the second chemical agent concentration used to maintain the gas flow channel based on the dynamic balance coefficient. The hydraulic fracturing module is used to inject the first and second chemical agents into the fracturing fluid system and pump them into the target reservoir for hydraulic fracturing. The forming module is used to shut in and simmer the well after hydraulic fracturing is completed, so that the first chemical agent forms a wetting and modifying layer on the surface of the reservoir matrix, while the second chemical agent forms an interfacial tension regulating film in the pore throat. The feature recognition module is used to monitor the bottom hole pressure recovery data during the well shut-in process and identify specific change features in the pressure recovery curve that characterize the establishment of an effective gas phase flow channel. The timing determination module is used to determine the timing of well opening and production based on specific change characteristics, so that the reservoir modified by wetting and interfacial tension can achieve effective gas phase replacement.

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