A method for optimizing CO2 foam fracturing parameters in deep coal seams based on phase state control

Abstract

The application discloses a kind of deep coal seam CO2 foam fracturing parameter optimization methods based on phase state regulation, first, build the wellbore flow heat absorption model fusing fluid residence time, mixed heat capacity and formation heat transfer characteristics, accurately calculate well fluid temperature and pressure, according to the calculation result, using Span-Wagner state equation, in combination with carbon dioxide phase diagram determines well fluid real phase state, and carry out indoor true triaxial equivalent simulation experiment and sand-carrying performance experiment with this as boundary condition, according to the result fed back by experiment, by adjusting ground injection displacement and foam quality and other parameters, actively control well fluid phase state, to realize the fine regulation and control of reservoir reconstruction effect.The application can effectively eliminate phase state prediction deviation, realize the active regulation and control of well fluid phase state, significantly improve the fracturing reconstruction volume of deep coalbed gas and single well production.

Description

Technical Field

[0001] This invention belongs to the field of unconventional natural gas development and reservoir stimulation technology, specifically involving a method for optimizing CO2 foam fracturing parameters in deep coal seams based on phase regulation. Background Technology

[0002] In deep coalbed methane development, carbon dioxide (CO2) foam fracturing technology has attracted much attention due to its ability to combine enhanced production with carbon sequestration and utilization (CCUS). Unlike conventional hydraulic fracturing, CO2 is extremely sensitive to temperature and pressure. During its journey from wellhead injection to reaching the deep reservoir, its phase undergoes complex transformations between gaseous, liquid, and supercritical states due to increased well depth (rising geothermal temperature and pressure) and the fluid's own thermal effects (compression heat generation or Joule-Thomson effect). Existing deep coalbed CO2 foam fracturing experimental technologies have the following main shortcomings: (1) Insufficient basis for parameter design: Traditional design often ignores the heat transfer and temperature change mechanism in the wellbore flow process, and only sets the surface discharge and temperature based on experience, which cannot predict the true phase state of the fluid when it reaches the bottom of the well.

[0003] (2) Distortion of experimental evaluation: Indoor experiments often use static formation temperature (such as constant 50℃) for heating, ignoring the heat exchange between the fluid and the well wall and its own temperature change process during high-speed injection, resulting in experimental results that cannot truly reflect the fracture and sand carrying patterns at the bottom of the well.

[0004] (3) Lack of parameter optimization closed loop: numerical simulation and physical experiment are separated, and a scientific closed loop of "determining phase state through calculation, evaluating quality through experiment, and inferring parameters through evaluation" has not been formed.

[0005] Therefore, existing technologies cannot achieve precise control over the CO2 phase state within the wellbore, and there is an urgent need for a method that can closely integrate wellbore flow heat transfer calculations, experimental equivalent evaluations, and construction parameter optimization. Summary of the Invention

[0006] This invention addresses the technical problems in existing deep coal seam CO2 foam fracturing technology, which suffer from the neglect of the endothermic hysteresis effect and component heat distribution differences during high-speed fluid flow in the wellbore, and the common use of static formation temperature as the control standard. This leads to distorted bottom hole phase prediction, significant deviations between experimental evaluation environment and actual working conditions, and consequently, unclear understanding of fracture creation and sand carrying mechanisms and a lack of basis for optimizing process parameters. The purpose is to provide a method for optimizing deep coal seam CO2 foam fracturing parameters based on phase regulation.

[0007] This invention is achieved through the following technical solution: A method for optimizing CO2 foam fracturing parameters in deep coal seams based on phase state control includes the following steps: S1. Multi-source data acquisition and integration: Collect geological data, engineering data, and fluid property data of deep coalbed methane wells to be fractured, and perform preprocessing. Step S1 collects fracturing construction parameters and thermodynamic boundary conditions to obtain key input parameters required for the calculation of the wellbore flow endothermic model. It comprehensively collects and integrates three major categories of data: geological, engineering and fluid properties, and finally constructs a multi-dimensional input dataset that includes wellbore environmental parameters and fluid property parameters. Step S1 specifically includes the following sub-steps: S11. Collect geological data, engineering data, and fluid property data of deep coalbed methane wells to be fractured; The geological data includes thermal conductivity (λ) and specific heat capacity (C). p Geological data is obtained through core analysis and is used to calculate the heat exchange rate between the fluid and the wellbore. The engineering data includes wellbore structure data, injection construction parameters, and wellbore heat transfer data; the wellbore structure data includes tubing / casing inner diameter (D), vertical depth (h), and average tubing friction coefficient (f); the wellbore structure data is used to determine fluid flow path, heat exchange area, energy loss, etc.; the injection construction parameters include the set wellhead injection temperature (T). in ), wellhead injection pressure (P) in The injection parameters are key variables that determine the fluid residence time. The wellbore heat transfer data include determining the cement sheath thickness (δ) and the overall fluid-formation heat transfer coefficient (U). The fluid property data includes the CO2 foam mass (Γ) and the physical states of carbon dioxide and the base fluid; the CO2 foam mass is obtained through fracturing fluid component analysis; the physical states of carbon dioxide and the base fluid include the specific heat capacity, thermal conductivity, density, viscosity, and enthalpy of carbon dioxide and the base fluid (water) at different temperatures and pressures; the physical states of carbon dioxide and the base fluid are used to quantify the differences in heat capacity distribution of the mixed fluid during the heating process; the physical states of carbon dioxide and the base fluid are obtained by calling the NIST (National Institute of Standards and Technology) database or the Span-Wagner equations of state library. S12, Data Preprocessing: Perform a rationality analysis on the data obtained in step S11, handle missing and outlier values, and unify the processing units and dimensions; The methods for handling missing and outlier values, as well as the methods for standardizing processing units and dimensions, all employ conventional techniques.

[0008] S2. Construct a wellbore flow endothermic model that considers displacement and component effects: The purpose of step S2 is to establish a wellbore flow heat absorption model (wellbore control equations) based on the principles of fluid mechanics and thermodynamics, including mass conservation, momentum conservation and energy conservation. The key is to introduce the fluid residence time (determined by the displacement) and mixing heat capacity (determined by the foam mass) terms to calculate the heat absorption and temperature and pressure evolution of the fluid as it flows from the wellhead to the bottom of the well. The wellbore flow heat absorption model is a multiphase flow heat absorption calculation model that considers the heat distribution of components and is constructed based on the law of energy conservation. The wellbore flow heat absorption model consists of a set of wellbore governing equations (wellbore-formation heat transfer equations). The set of wellbore governing equations includes the formulas for calculating the equivalent density of the mixed fluid and the formulas for calculating the specific heat capacity of the mixed fluid, which are established based on the three major equations of mass conservation, momentum conservation and energy conservation. Step S2 specifically includes the following steps: S21. Construct a wellbore flow endothermic model consisting of the formulas for calculating the equivalent density and specific heat capacity of the mixed fluid: Equivalent density and specific heat capacity reflect the heat distribution between the two components in the mixture, thus reflecting the influence of different components on the heat absorption capacity. The formula for calculating the equivalent density of the mixed fluid is: In the formula: The equivalent density of the mixed fluid is expressed in kg / m³. 3 ; The mass of CO2 foam is the volume fraction of the gas phase, which is dimensionless. The density of carbon dioxide during injection is expressed in kg / m³. 3 ; This refers to the density of the base liquid (water), expressed in kg / m³. 3 ; The formula for calculating the thermal conductivity of the mixed fluid is: In the formula: Specific heat capacity of the mixed fluid, expressed in J / (kg·K); This represents the specific heat capacity of carbon dioxide, expressed in J / (kg·K). This is the specific heat capacity of the base liquid (water), expressed in J / (kg·K). The mass fraction of carbon dioxide in the mixed fluid is dimensionless. Wherein, the mass fraction of carbon dioxide in the mixed fluid The calculation formula is: In the formula: The mass fraction of carbon dioxide in the mixed fluid is dimensionless. The mass of CO2 foam is the volume fraction of the gas phase, which is dimensionless. The density of carbon dioxide during injection is expressed in kg / m³. 3 ; This refers to the density of the base liquid (water), expressed in kg / m³. 3 ; S22. Based on the displacement effect, the wellbore flow heat absorption model is analyzed, and the actual bottom-hole flow temperature and pressure of the output fluid when it reaches the target layer under different displacement conditions are calculated. Then, the changes in fluid pressure and the changes in bottom-hole temperature caused by different heat absorption are determined. Based on interphase heat transfer, the heat exchange between water and carbon dioxide phases and the overall heat balance after heat absorption are determined during the flow of CO2 foam fluid. The actual bottom hole flowing pressure (P) when the output fluid reaches the target formation wf The discretized iterative summation formula for ) is: in: In the formula: This refers to the bottom hole flowing pressure, expressed in Pa. The injection pressure at the wellhead, expressed in Pa. The average mixing density of the entire wellbore is expressed in kg / m³. 3 ; The acceleration due to gravity is taken as 9.8 m / s². 2 ; Reservoir depth, in meters (m); is the average friction coefficient of the wellbore, which is dimensionless; This refers to the inner diameter of the oil pipe, in meters (m). The average fluid velocity is expressed in m / s. Fluid injection displacement, in meters (m³) 3 / s; Based on the analytical solution of heat transfer in Ramey wellbore, output the true bottom-hole flow temperature (T) when the fluid reaches the target formation. wf The calculation formula for ) is as follows: in: In the formula: This represents the actual bottom-hole flow temperature, expressed in Kelvin (K). This refers to the Earth's surface temperature, measured in Kelvin (K). The injection temperature at the wellhead, expressed in Kelvin (K). This represents the geothermal gradient, measured in K / m. The reservoir depth is expressed in meters (m). The relaxation distance is expressed in meters (m). Mass flow rate, in kg / s; Specific heat capacity of the mixed fluid, expressed in J / (kg·K); The equivalent heat transfer coefficient includes formation thermal resistance, and its unit is W / (m²). 2 ·K); The thermal conductivity of the formation is expressed in W / (m·K). For Ramey's dimensionless time function, long-term injections are usually taken as constants; The radius of the wellbore is in meters (m). The overall heat transfer coefficient of the wellbore is W / (m²). 2 ·K); The heat exchange is handled using the "homogeneous transient heat balance" method to avoid complex theoretical modeling. It is assumed that at any depth section of the wellbore, the gas (liquid) phase carbon dioxide and water instantly reach thermal equilibrium, that is, the temperature of the two always remains the same. Then, the above Ramey heat transfer model is used to carry out the calculation.

[0009] S3. Bottom-hole fluid phase inversion and operating condition classification: The actual bottom-hole flow temperature (T) of the fluid when it reaches the target layer, calculated in step S2, is used to determine the bottom-hole fluid phase inversion and operating condition classification. wf ) and the actual bottom hole flowing pressure (P) wf Combining the carbon dioxide phase diagram and the phase equilibrium theory of mixed fluids, the physical state of the fluid at the instant of contact with the coal seam was determined, and an experimental plan was formulated accordingly. Step S3 includes the following sub-steps: S31. Phase determination: The actual bottom-hole flow temperature (T) when the fluid reaches the target layer, calculated in step S2, is used. wf ) and the actual bottom hole flowing pressure (P) wf Projecting the phase onto a carbon dioxide pressure-temperature (PT) phase diagram for phase determination: If the actual bottom-hole flow temperature T wf ≥304.19 K and actual bottom hole flowing pressure P wf When the pressure is ≥7.38 MPa, it is determined to be in the supercritical state (usually corresponding to small and medium displacement and deep wells). If the actual bottom-hole flow temperature T wf <304.19K and actual bottom hole flowing pressure P wf >Saturated vapor pressure P at the actual bottom-hole flow temperature sat (T wf When the liquid state is reached, it is determined to be liquid (usually corresponding to large displacement and low injection temperature). If the actual bottom-hole flow temperature T wf <304.19K and actual bottom hole flowing pressure P wf ≤Saturated vapor pressure P at the actual bottom hole flow temperaturesat (T wf When ), it is determined to be in a gaseous state; The saturated vapor pressure P at the actual bottom-hole flow temperature sat (T wf The auxiliary equation in the Span-Wagner (1996) equation of state is used to determine, and thus the carbon dioxide foam state, the saturated vapor pressure P at the actual bottom-hole flow temperature. sat (T wf The formula for calculating ) is: In the formula: This is the saturated vapor pressure at the actual bottom-hole flow temperature, in Pa. The critical pressure for carbon dioxide is taken as 7.38 × 10⁻⁶. 6 Pa; The critical temperature for carbon dioxide is taken as 304.1282 K; This represents the actual bottom-hole flow temperature, expressed in Kelvin (K). For coefficients, dimensionless constants, ~ The values ​​are -7.0602, 1.9391, -1.6464, and -3.2996, respectively. For each term, there is an exponent, a dimensionless constant, with t1~t4 being 1.0, 1.5, 2.0, and 4.0 respectively; S32. Determine the experimental operating parameters and, based on the inversion results, set two typical experimental operating conditions: The saturated vapor pressure under real bottom hole flow temperature conditions determines the true phase state of the bottom hole fluid, which is the inversion result. The calculated bottom hole temperature and pressure can then be used as the experimental operating parameters. Operating Condition A (Liquid Emulsion): Based on the large displacement calculation results, a lower experimental temperature T1 is set; the experimental temperature T1 must satisfy T1 < 31.04℃ to simulate the bottom hole characteristics of liquid carbon dioxide foam fracturing fluid; Condition B (Supercritical Mixture): Based on the calculation results of small displacement, a higher experimental temperature T2 is set; the experimental temperature T2 must satisfy T2 > 31.04℃ to simulate the bottom hole characteristics of supercritical carbon dioxide foam fracturing fluid.

[0010] S4. Indoor equivalent simulation experiment: Step S4 aims to accurately map the two experimental operating parameters determined in step S32 to the control parameters of the indoor physical experiment, to recreate the real thermodynamic environment of the deep strata indoors, and to quantitatively evaluate the fracture-making ability and sand-carrying capacity of the fluid respectively. Step S4 includes the following sub-steps: S41. Experimental Sample Preparation and Installation: Drill a suitable raw coal sample, process it into a standard specimen that meets the requirements of true triaxial loading, pre-place a simulated wellbore of appropriate size in the center of the specimen, and place it into a pressure chamber after cementing and sealing. S42. In-situ stress and formation environment loading: The aforementioned in-situ stress and formation environment loading include in-situ stress simulation and loading, as well as temperature simulation and control, specifically: The in-situ stress simulation and loading method is as follows: using a true triaxial fracturing system, based on geological data, a reasonable triaxial principal stress (σ) is applied. V , σ H , σ h ); The temperature simulation and control method is as follows: The constant temperature environment module of the experimental system is activated, abandoning the traditional practice of using the original formation temperature, and the ambient temperature is set to the actual bottom-hole flow temperature (T) when the fluid reaches the target layer, as determined in step S2. wf This is to simulate the real thermal environment around the well after long-term fluid injection; S43. Simulation of hydraulic fracturing and fracture creation: The fracturing simulation includes injection control, process simulation, and multidimensional monitoring. The injection control method is as follows: adjust the injection system to ensure that the CO2 foam fracturing fluid can be preheated to the actual bottom hole flow temperature (T) through the constant temperature heating casing. wf After injection, the pump pressure is controlled to reach or exceed the actual bottom hole flowing pressure (P) calculated in step S2. wf ); The process simulation method is as follows: inject CO2 foam fracturing fluid and conduct true triaxial fracturing model experiments; The multidimensional monitoring method is as follows: real-time recording of pump pressure curve characteristics, monitoring of fracture signals generated by fracture propagation using an experimental system, and observation of the three-dimensional morphology of fractures and damage to the coal and rock matrix by combining CT scans and other methods after the experiment, to evaluate the ability of this phase fluid to activate natural cleavage. S44, Simulation of proppant carrying by fracturing fluid: Under the same bottom hole temperature and pressure conditions, a visual proppant carrying performance evaluation experiment was carried out using a high temperature and high pressure rheometer to test the apparent viscosity of CO2 foam fracturing fluid and the proppant settling rate under this phase; the proppant settling rate under the experimental sand ratio was recorded to evaluate the proppant suspension and transport capacity of the fluid under this phase. S5. Feedback on Indoor Equivalent Simulation Experiment Results and Optimization of Engineering Parameters: Step S5 aims to form a closed loop of "calculation-experiment-site", and use the experimental results to correct the construction plan in reverse. Step S5 includes the following sub-steps: S51. Based on the test data of the indoor equivalent simulation experiment in step S4, compare and analyze the differences in fracturing pressure, fracture complexity index and fracturing fluid proppant carrying capacity under different working conditions (such as supercritical state and liquid state), and select the best phase working condition. The method for analyzing the differences in fracture-forming capacity (rupture pressure, fracture complexity index) is as follows: analyze and compare the CT scan results of the samples after the fracturing experiment to determine which phase can form a more complex fracture morphology. The analytical method for the differences in proppant carrying capacity of fracturing fluid is to analyze the settling rate data to determine which phase has a stronger suspension capacity. S52. Construction parameter optimization decision-making: Based on the analysis of the experimental results in step S51, and considering the principle that the pre-fracturing fluid needs to form more complex fracture morphology and the subsequent proppant-carrying fluid needs to have high fracturing fluid delivery efficiency, the total wellhead injection rate, injection temperature, and carbon dioxide foam quality in step S2 are adjusted in reverse. Based on the comprehensive evaluation results of the experiment on fracture-making capacity and sand-carrying performance, the optimal phase range was determined. Then, based on the optimal phase of fracture-making capacity and the optimal phase of sand-carrying performance, the total injection rate, injection temperature and carbon dioxide foam mass fraction of each injection segment were optimized in reverse segment to ensure that the carbon dioxide foam fracturing fluid can be maintained in the optimal phase range when it reaches the bottom of the well during the fracture-making and sand-carrying stages.

[0011] The beneficial effects of this invention are: This invention provides a method for optimizing deep coalbed methane fracturing construction parameters based on wellbore flow heat transfer mechanism through phase state prediction and experimental evaluation during the development of deep coalbed methane reservoirs. It is a closed-loop optimization method with a clear physical mechanism.

[0012] This invention breaks through the theoretical blind spots of traditional experimental parameter setting, realizes the accurate reproduction of real working conditions at the bottom of the well, and guides the setting of indoor experimental parameters, eliminating phase distortion caused by temperature difference (such as incorrectly simulating a fluid that should be in a liquid state as a supercritical state), and significantly improving the guiding value of indoor physical simulation results for field engineering. This invention establishes a quantitative analysis method with a clear physical mechanism. By introducing parameters such as fluid residence time and heat capacity of mixed components (foam mass), this invention can accurately quantify the differences in heat absorption of fluids under different construction discharge rates (e.g., large discharge rate leads to heat absorption lag and maintenance of liquid state, while small discharge rate leads to sufficient heat absorption and conversion to supercritical state). This allows for the accurate identification of the phase transition boundary of CO2 during the entire injection process, providing a reliable physical premise for studying the fracturing mechanism of different phase fluids in deep coal seam development. This invention constructs a closed-loop optimization system of "computational inversion - experimental verification - engineering optimization", which can directly evaluate and optimize the actual effects of surface injection schemes (displacement rate, wellhead temperature) at the bottom of the well. At the same time, it can use indoor experiments to flexibly guide and optimize surface construction parameters, providing a direct basis for the refined design of deep coal seam fracturing construction parameters. Attached Figure Description

[0013] Figure 1 This is a flowchart of the method of the present invention; Figure 2 This is the phase diagram of carbon dioxide; Figure 3 This is a CT scan image of the fracture morphology after hydraulic fracturing of liquid carbon dioxide mixed foam in Embodiment 1 of the present invention; Figure 4 This is a graph showing the experimental results of the proppant carrying capacity of the liquid carbon dioxide mixed foam fracturing fluid in Example 1 of this invention; Figure 5 This is a CT scan image of the fracture morphology after hydraulic fracturing of supercritical carbon dioxide mixed foam in Embodiment 1 of the present invention. Figure 6 This is a graph showing the experimental results of the sand-carrying performance of the supercritical carbon dioxide mixed foam fracturing fluid in Example 1 of this invention.

[0014] For those skilled in the art, other related figures can be obtained from the above figures without any creative effort. Detailed Implementation

[0015] To enable those skilled in the art to better understand the technical solution of the present invention, the technical solution of the present invention will be further described below with reference to the accompanying drawings and specific embodiments.

[0016] Example 1

[0017] like Figure 1 As shown, a method for optimizing CO2 foam fracturing parameters in deep coalbed methane based on phase state control includes the following steps: S1. Multi-source data acquisition and integration: Collect geological data, engineering data, and fluid property data of deep coalbed methane wells to be fractured, and perform preprocessing. S11. Data collection: Based on on-site production data, the main property parameters are as follows: Reservoir depth: 1500m; Initial bottom hole temperature: 52.5℃ (325.65K); Initial bottom hole pressure: 14.0MPa; Tubing inner diameter: 62.0 mm; Wellbore radius: 108 mm; Overall heat transfer coefficient: 45.0 W / (m²) 2• K); Formation thermal conductivity: 0.42 W / (m·K); Fracturing fluid foam mass: 65%, base fluid is slickwater, assumed to be clear water; Design injection rate: 4.0 m³ / h 3 / min; Average wellbore friction coefficient: 0.001; Wellhead injection temperature: -10℃ (263.15K); Wellhead injection pressure: 22.0MPa; S12. Convert all parameter units to national standard units before proceeding with subsequent calculations; S2. Construct a wellbore flow endothermic model that considers displacement and component effects: S21. Calculate the equivalent density of the mixed fluid using the following formula: In the formula: The equivalent density of the mixed fluid is expressed in kg / m³. 3 ; The mass of CO2 foam is the volume fraction of the gas phase, which is dimensionless. The density of carbon dioxide during injection is expressed in kg / m³. 3 ; This refers to the density of the base liquid (water), expressed in kg / m³. 3 ; The formula for calculating the thermal conductivity of a fluid mixture is: In the formula: Specific heat capacity of the mixed fluid, expressed in J / (kg·K); This represents the specific heat capacity of carbon dioxide, expressed in J / (kg·K). This is the specific heat capacity of the base liquid (water), expressed in J / (kg·K). The mass fraction of carbon dioxide in the mixed fluid is dimensionless. Wherein, the mass fraction of carbon dioxide in the mixed fluid The calculation formula is: In the formula: The mass fraction of carbon dioxide in the mixed fluid is dimensionless. The mass of CO2 foam is the volume fraction of the gas phase, which is dimensionless. The density of carbon dioxide during injection is expressed in kg / m³. 3 ; This refers to the density of the base liquid (water), expressed in kg / m³. 3 ; In this embodiment, the density of carbon dioxide is measured under the conditions of a wellhead injection temperature of -10°C and a wellhead injection pressure of 22.0 MPa. 1044 kg / m 3 ; Calculate the equivalent density of the mixed fluid. It is 1028.6 kg / m 3 Specific heat capacity of the mixed fluid It is 2748.6 J / (kg·K); S22. Calculate the actual bottom-hole flow temperature (T) of the output fluid when it reaches the target formation. wf ) and the actual bottom hole flowing pressure (P) wf ); The actual bottom hole flowing pressure (P) wf The discretized iterative summation formula for ) is: in: In the formula: This refers to the bottom hole flowing pressure, expressed in Pa. The injection pressure at the wellhead, expressed in Pa. The average mixing density of the entire wellbore is expressed in kg / m³. 3 ; The acceleration due to gravity is taken as 9.8 m / s². 2 ; Reservoir depth, in meters (m); is the average friction coefficient of the wellbore, which is dimensionless; This refers to the inner diameter of the oil pipe, in meters (m). The average fluid velocity is expressed in m / s. Fluid injection displacement, in meters (m³) 3 / s; Based on the analytical solution of heat transfer in Ramey wellbore, the actual bottom hole flow temperature (T) wf The calculation formula for ) is as follows: in: In the formula: This represents the actual bottom-hole flow temperature, expressed in Kelvin (K). This refers to the Earth's surface temperature, measured in Kelvin (K). The injection temperature at the wellhead, expressed in Kelvin (K). This represents the geothermal gradient, measured in K / m. The reservoir depth is expressed in meters (m). The relaxation distance is expressed in meters (m). Mass flow rate, in kg / s; Specific heat capacity of the mixed fluid, expressed in J / (kg·K); The equivalent heat transfer coefficient includes formation thermal resistance, and its unit is W / (m²). 2 ·K); The thermal conductivity of the formation is expressed in W / (m·K). For Ramey's dimensionless time function, long-term injections are usually taken as constants; The radius of the wellbore is in meters (m). The overall heat transfer coefficient of the wellbore is W / (m²). 2 ·K); In this embodiment, the bottom hole flowing pressure is calculated based on known parameters. Approximately 31.2 MPa, bottom hole flow temperature T wf It is approximately 28.5℃.

[0018] S3. Bottom-hole fluid phase inversion and operating condition classification: The actual bottom-hole flow temperature (T) of the fluid when it reaches the target layer, calculated in step S2, is used to determine the bottom-hole fluid phase inversion and operating condition classification. wf ) and the actual bottom hole flowing pressure (P) wf Combining the carbon dioxide phase diagram and the phase equilibrium theory of mixed fluids, the physical state of the fluid at the instant of contact with the coal seam was determined, and an experimental plan was formulated accordingly. S31. According to the calculation result in step S2, T wf =28.5℃=301.65K<304.19K; Calculate the saturated vapor pressure at this temperature using the formula: In the formula: This is the saturated vapor pressure at the actual bottom-hole flow temperature, in Pa. The critical pressure for carbon dioxide is taken as 7.38 × 10⁻⁶. 6 Pa; The critical temperature for carbon dioxide is taken as 304.1282 K; This represents the actual bottom-hole flow temperature, expressed in Kelvin (K). For coefficients, dimensionless constants, ~ The values ​​are -7.0602, 1.9391, -1.6464, and -3.2996, respectively. For each term, there is an exponent, a dimensionless constant, with t1~t4 being 1.0, 1.5, 2.0, and 4.0 respectively; S32. Calculate the saturated vapor pressure P according to formula S31. sat (28.5℃) is approximately 6.97MPa < 31.2MPa. Therefore, it can be concluded that under these temperature and pressure conditions, the carbon dioxide fracturing fluid is still in a liquid state when it enters the bottom of the well and contacts the coal seam. The injection conditions belong to operating condition A (liquid emulsion), and the experimental conditions are set at 28.5℃.

[0019] S4. Indoor equivalent simulation experiment: S41. Conduct a fracturing simulation experiment. Drill a suitable raw coal sample and process it into a standard cubic specimen (100mm×100mm×100mm) that meets the requirements of true triaxial loading. A simulated wellbore of appropriate size is pre-placed in the center of the specimen, and after cementing and sealing, it is placed in a pressure chamber. Based on the original formation pressure and the bottom hole fluid pressure, set the triaxial confining pressure: vertical stress σ V Take 37.5 MPa, maximum horizontal principal stress σ H Take 32.0 MPa, σ h Take 24.0 MPa; through the injection pipeline with a heating sleeve, set the temperature of the injected fluid to 28.5℃ to ensure that it is the same as the on-site fracturing construction conditions; S42. After the fracturing experiment, cracks formed in the sample. The rock sample was then subjected to CT scanning to observe the crack morphology. Figure 3 As shown, the main crack is quite obvious, but there are few branch cracks; S43. Conduct a visual sand-carrying performance evaluation experiment. Prepare the foam fracturing fluid base fluid, add quartz sand and mix evenly. Add liquid carbon dioxide to a high-pressure vessel, and stir under conditions of 28.5℃ and 31.2MPa. Then let it stand for observation. Observe the sand settling situation after standing for 2 hours. Figure 4 As shown, after standing for 2 hours, the liquid fracturing fluid system did not show obvious sand settling, and the sand settling rate was less than 5%. S5. Feedback on Indoor Equivalent Simulation Experiment Results and Optimization of Engineering Parameters: S51. Based on the experimental results in step S4, it can be seen that when the bottom flow temperature is 28.5℃, carbon dioxide is in a liquid state. Although it can form the main fracture, the fracture morphology is not complex and its sand-carrying capacity is not ideal. Therefore, we tried to adjust the fluid phase to the supercritical state, adjusted the fluid injection temperature to 35℃ to achieve the supercritical state, realized the phase transition, adjusted the working condition A to working condition B, and conducted the experiment again. S52. To achieve the phase change, the original injection rate was adjusted to ensure that the fracturing fluid enters the formation and forms supercritical carbon dioxide foam fracturing fluid. Through the formula in step S2, it was calculated that when the injection rate was adjusted to 2.5 m3 / min, the bottom hole flow temperature of the fluid entering the formation could reach 33.8℃, and the bottom hole flow pressure was 29.5 MPa, which could meet the construction requirements of working condition B. S53. Under the conditions of bottom hole flow temperature of 33.8℃ and bottom hole flow pressure of 29.5MPa, the experiment in step S4 was repeated; after the true triaxial fracturing experiment, the CT scan fracture morphology obtained after the experiment is as follows. Figure 5As shown, a very complex fracture network was formed. It can be seen that the fracture morphology in condition B is more complex than that in condition A. Therefore, utilizing the low viscosity and high diffusivity of supercritical carbon dioxide can better connect the micropores inside the coal and rock, thereby forming a volumetric fracturing network. After the fracturing fluid proppant-carrying capacity experiment, the proppant-carrying effect is as follows: Figure 6 As shown, after standing for 2 hours, the sand settling rate is about 25%, which is significantly higher than that of condition A. This proves that the sand carrying capacity of the supercritical carbon dioxide foam fracturing fluid system is not as good as that of the liquid carbon dioxide foam fracturing fluid system. Therefore, when the fracturing fluid system enters the formation under condition A, both the fracture creation capacity and the sand carrying capacity are greatly improved. S54. Based on the above analysis, it is recommended to reduce the total drainage volume during the pre-construction joint stage to 2.5 m³. 3 / min, of which the base liquid injection displacement is 0.875 m³ / min. 3 / min, liquid carbon dioxide injection displacement is 1.625 m³ / min. 3 At a flow rate of [unspecified] / min, the injection temperature of liquid carbon dioxide is maintained at -10℃. Under low flow rates, the fluid fully absorbs heat, achieving a bottomhole flow temperature of 33.8℃. This ensures that the carbon dioxide foam fracturing fluid is in a supercritical state upon entering the wellbore, which is more conducive to forming complex fracture networks. In the later proppant-carrying stage, a normal 4.0 m [unspecified] ... 3 The total construction discharge rate is 1.4 m³ / min, of which the base liquid injection discharge rate is 1.4 m³ / min. 3 / The liquid carbon dioxide injection displacement is 2.6 m³ / min. 3 At a flow rate of [unspecified] / min, the injection temperature of liquid carbon dioxide remains at -10℃. Due to the delayed heat absorption of the fluid at high flow rates, the bottom-hole flow temperature drops back to 28.5℃, ensuring that the carbon dioxide foam fracturing fluid remains liquid upon entering the wellbore. This enhances its sand-carrying capacity, facilitating the formation of high-conductivity fracture channels and preventing sand blockage. Through segmented total injection flow rate optimization, a fracture depth of 2.5 m is achieved. 3 / min, carrying 4.0 m of sand 3 A combined displacement construction scheme of / min can achieve better construction results.

[0020] The implementation effect of Example 1 is as follows: Through the "calculation-experiment-on-site" process of the present invention, the original fracturing scheme was successfully upgraded to a refined fracturing scheme with phase control.

[0021] The adjacent well D-02 has a designed total injection displacement of 4.0 m³. 3 / min (base fluid injection displacement 1.4 m) 3 / min, liquid carbon dioxide injection displacement 2.6 m 3 / min, under operating condition A), fracturing was performed, and during the subsequent stable production process, the daily production of a single well was approximately 2200 m³ / min. 3 / day. To verify the optimization effect of this method, in the construction of well D-01 described in this embodiment, based on the experimental evaluation results, the total injection displacement during the fracturing and fracture creation stage was optimized to 2.5 m³ / day. 3 / min (base fluid injection displacement 0.875 m) 3 / min, liquid carbon dioxide injection displacement 1.625 m³ 3 / min, operating condition B), the total injection displacement during the sand-carrying support stage is adjusted to 4.0 m. 3 / min (base fluid injection displacement 1.4 m) 3 / min, liquid carbon dioxide injection displacement 2.6 m 3 / min, operating condition A), during the subsequent stable production process, the daily production of well D-01 was approximately 5800 m³ / min. 3 The daily production reached 2.6 times that of well D-02. By controlling the phase state in stages and taking into account both fracture creation and sand carrying operations, the single-well productivity and economic benefits were significantly improved.

[0022] This invention addresses the challenges of accurately predicting the carbon dioxide phase and controlling fracture morphology in deep coalbed methane wells under high temperature and pressure conditions. It constructs a wellbore flow endothermic model that integrates fluid residence time, mixing heat capacity, and formation heat transfer characteristics. This model accurately calculates the bottom-hole fluid temperature and pressure. Based on the calculation results, the Span-Wagner equation of state, combined with a carbon dioxide phase diagram, is used to determine the true phase state (liquid or supercritical) of the bottom-hole fluid. Using this as boundary condition, laboratory true triaxial equivalent simulation experiments and proppant carrying capacity experiments are conducted. Based on the experimental feedback, the bottom-hole fluid phase state is actively controlled by adjusting parameters such as surface injection rate and foam quality, thereby achieving refined control of reservoir stimulation effects. This invention effectively eliminates phase prediction bias, enables active control of the bottom-hole fluid phase state, and significantly improves the fracturing volume and single-well production of deep coalbed methane.

[0023] The applicant declares that the above description is only a specific embodiment of the present invention, but the protection scope of the present invention is not limited thereto. Those skilled in the art should understand that any changes or substitutions that can be easily conceived by those skilled in the art within the technical scope disclosed in the present invention fall within the protection and disclosure scope of the present invention.

Claims

1. A method for optimizing CO2 foam fracturing parameters in deep coal seams based on phase state control, characterized in that: Includes the following steps: S1. Collect geological data, engineering data, and fluid property data of the deep coalbed methane well to be fractured, and perform preprocessing. S2. Construct a wellbore flow endothermic model that considers displacement and component effects, and calculate the actual bottom-hole flow temperature and actual bottom-hole flow pressure when the output fluid reaches the target formation. S3. Combine the actual bottom-hole flow temperature and actual bottom-hole flow pressure of the fluid when it reaches the target layer, calculated in step S2, with the carbon dioxide phase diagram and the mixed fluid phase equilibrium theory to determine the physical state of the fluid at the instant it contacts the coal seam, and formulate the indoor equivalent simulation experiment scheme for step S4 accordingly. S4. Conduct an indoor equivalent simulation experiment based on the experimental operating parameters obtained in step S3; S5. Optimize engineering parameters based on the feedback from the indoor equivalent simulation experiment results in step S4.

2. The method for optimizing CO2 foam fracturing parameters in deep coal seams based on phase state control according to claim 1, characterized in that: The geological data includes thermal conductivity and specific heat capacity; The engineering data includes wellbore structure data, injection construction parameters, and wellbore heat transfer data; the wellbore structure data includes tubing / casing inner diameter, vertical depth, and average tubing friction coefficient; the injection construction parameters include the set wellhead injection temperature, wellhead injection pressure, and designed injection rate; the wellbore heat transfer data includes determining the cement sheath thickness and the overall fluid-formation heat transfer coefficient. The fluid property data includes the CO2 foam mass and the physical properties of carbon dioxide and the base liquid; the physical properties of carbon dioxide and the base liquid include the specific heat capacity, thermal conductivity, density, viscosity and enthalpy data of carbon dioxide and the base liquid at different temperatures and pressures.

3. The method for optimizing CO2 foam fracturing parameters in deep coal seams based on phase state control according to claim 1, characterized in that: Step S2 specifically includes the following steps: S21. Construct a wellbore flow endothermic model consisting of the formulas for calculating the equivalent density and specific heat capacity of the mixed fluid: S22. Based on the displacement effect, the wellbore flow heat absorption model is analyzed to calculate the actual bottom-hole flow temperature and pressure of the output fluid when it reaches the target layer under different displacement conditions, thereby determining the changes in fluid pressure and the changes in bottom-hole temperature caused by different heat absorption. Based on interphase heat transfer, the heat exchange between water and carbon dioxide phases and the overall heat balance after heat absorption are determined during the flow of CO2 foam fluid.

4. The method for optimizing CO2 foam fracturing parameters in deep coal seams based on phase state control according to claim 3, characterized in that: The formula for calculating the equivalent density of the mixed fluid is: In the formula: The equivalent density of the mixed fluid is expressed in kg / m³. 3 ; The mass of CO2 foam is the volume fraction of the gas phase, which is dimensionless. The density of carbon dioxide during injection is expressed in kg / m³. 3 ; This refers to the density of the base liquid (water), expressed in kg / m³. 3 ; The formula for calculating the thermal conductivity of the mixed fluid is: In the formula: Specific heat capacity of the mixed fluid, expressed in J / (kg·K); This represents the specific heat capacity of carbon dioxide, expressed in J / (kg·K). This is the specific heat capacity of the base liquid (water), expressed in J / (kg·K). The mass fraction of carbon dioxide in the mixed fluid is dimensionless. Wherein, the mass fraction of carbon dioxide in the mixed fluid The calculation formula is: In the formula: The mass fraction of carbon dioxide in the mixed fluid is dimensionless. The mass of CO2 foam is the volume fraction of the gas phase, which is dimensionless. The density of carbon dioxide during injection is expressed in kg / m³. 3 ; This refers to the density of the base liquid (water), expressed in kg / m³. 3 .

5. The method for optimizing CO2 foam fracturing parameters in deep coal seams based on phase state control according to claim 3, characterized in that: The actual bottom hole flowing pressure (P) wf The discretized iterative summation formula for ) is: in: In the formula: This refers to the bottom hole flowing pressure, expressed in Pa. The injection pressure at the wellhead, expressed in Pa. The average mixing density of the entire wellbore is expressed in kg / m³. 3 ; The acceleration due to gravity is taken as 9.8 m / s². 2 ; Reservoir depth, in meters (m); is the average friction coefficient of the wellbore, which is dimensionless; This refers to the inner diameter of the oil pipe, in meters (m). The average fluid velocity is expressed in m / s. Fluid injection displacement, in meters (m³) 3 / s; Based on the analytical solution of heat transfer in Ramey wellbore, the actual bottom hole flow temperature (T) wf The calculation formula for ) is as follows: in: In the formula: This represents the actual bottom-hole flow temperature, expressed in Kelvin (K). This refers to the Earth's surface temperature, measured in Kelvin (K). The injection temperature at the wellhead, expressed in Kelvin (K). This represents the geothermal gradient, measured in K / m. The reservoir depth is expressed in meters (m). The relaxation distance is expressed in meters (m). Mass flow rate, in kg / s; Specific heat capacity of the mixed fluid, expressed in J / (kg·K); The equivalent heat transfer coefficient includes formation thermal resistance, and its unit is W / (m²). 2 ·K); The thermal conductivity of the formation is expressed in W / (m·K). For Ramey's dimensionless time function, long-term injections are usually taken as constants; The radius of the wellbore is in meters (m). The overall heat transfer coefficient of the wellbore is W / (m²). 2 ·K).

6. The method for optimizing CO2 foam fracturing parameters in deep coal seams based on phase state control according to claim 1, characterized in that: Step S3 includes the following sub-steps: S31. Project the actual bottom-hole flow temperature and actual bottom-hole flow pressure of the fluid when it reaches the target layer, calculated in step S2, onto the carbon dioxide pressure-temperature phase diagram to determine the phase state: If the actual bottom-hole flow temperature is ≥304.19 K and the actual bottom-hole flow pressure is >7.38 MPa, it is determined to be in a supercritical state. If the actual bottom-hole flow temperature is <304.19K and the actual bottom-hole flow pressure is > the saturated vapor pressure at the actual bottom-hole flow temperature, it is determined to be in liquid state; If the actual bottom-hole flow temperature T wf <304.19K and actual bottom hole flowing pressure P wf ≤Saturated vapor pressure P at the actual bottom hole flow temperature sat (T wf When ), it is determined to be in a gaseous state; S32. Determine the experimental operating parameters. Based on the inversion results, set operating condition A (liquid emulsion) and operating condition B (supercritical mixture). Operating condition A (liquid emulsion) corresponds to the large displacement calculation results. Set the experimental temperature T1, and T1 < 31.04℃. Operating condition B (supercritical mixture) corresponds to the small displacement calculation results. Set the experimental temperature T2, and T2 > 31.04℃.

7. The method for optimizing CO2 foam fracturing parameters in deep coal seams based on phase state control according to claim 1, characterized in that: Step S4 includes the following sub-steps: S41. Experimental Sample Preparation and Installation: Drill a suitable raw coal sample, process it into a standard specimen that meets the requirements of true triaxial loading, pre-place a simulated wellbore of appropriate size in the center of the specimen, and place it into a pressure chamber after cementing and sealing. S42. In-situ stress and formation environment loading: The aforementioned in-situ stress and formation environment loading include in-situ stress simulation and loading, as well as temperature simulation and control, specifically: The in-situ stress simulation and loading method is as follows: using a true triaxial fracturing system, a reasonable triaxial principal stress is applied based on geological data; The temperature simulation and control method is as follows: the constant temperature environment module of the experimental system is activated, abandoning the traditional practice of using the original formation temperature, and the ambient temperature is set to the actual bottom-hole flow temperature when the fluid reaches the target layer as determined in step S2, so as to simulate the real thermal environment around the well after long-term fluid injection. S43. Simulation of hydraulic fracturing and fracture creation: The fracturing simulation includes injection control, process simulation, and multidimensional monitoring. The injection control method is as follows: adjust the injection system to ensure that the CO2 foam fracturing fluid can be preheated to the actual bottom hole flow temperature through the constant temperature heating casing and then injected, and control the pump injection pressure to reach or exceed the actual bottom hole flow pressure calculated in step S2. The process simulation method is as follows: inject CO2 foam fracturing fluid and conduct true triaxial fracturing model experiments; The multidimensional monitoring method is as follows: real-time recording of pump pressure curve characteristics, monitoring of fracture signals generated by fracture propagation using an experimental system, and observation of the three-dimensional morphology of fractures and damage to the coal and rock matrix by combining CT scans and other methods after the experiment, to evaluate the ability of this phase fluid to activate natural cleavage. S44, Simulation of proppant carrying by fracturing fluid: Under the same bottom hole temperature and pressure conditions, a visual proppant carrying performance evaluation experiment was carried out using a high-temperature and high-pressure rheometer to test the apparent viscosity of CO2 foam fracturing fluid and the proppant settling rate under this phase. The proppant settling rate under the experimental proppant ratio was recorded to evaluate the proppant suspension and transport capacity of the fluid under this phase.

8. The method for optimizing CO2 foam fracturing parameters in deep coal seams based on phase state control according to claim 1, characterized in that: Step S5 includes the following sub-steps: S51. Based on the test data of the indoor equivalent simulation experiment in step S4, adjust the injection conditions appropriately, compare and analyze the differences in fracture-creating capacity and sand-carrying performance of fracturing fluid under different working conditions, and select the best phase working condition. S52. Based on the experimental results analysis in step S51, and considering the principle that the pre-fracturing fluid needs to form more complex fracture morphology and the subsequent sand-carrying fluid needs to have high fracturing fluid delivery efficiency, the total wellhead injection rate, injection temperature, and carbon dioxide foam quality in step S2 are adjusted in reverse.

9. The method for optimizing CO2 foam fracturing parameters in deep coal seams based on phase state control according to claim 8, characterized in that: The method for analyzing the differences in fracture-forming ability is as follows: analyze and compare the CT scan results of the samples after the fracturing experiment to determine which phase can form a more complex fracture morphology. The method for analyzing the differences in proppant carrying capacity of fracturing fluid is as follows: analyze the settling rate data to determine which phase has a stronger suspension capacity.

Images