A core type adapted sc-co2 phase state stress synergistic fracturing method

Abstract

The present application relates to the technical field of oil and gas field exploitation, and particularly relates to a core type adaptive SC-CO2 phase state stress collaborative fracturing method. Specifically comprising: carrying out fracturing experiments under multiple variable conditions to obtain a fracturing pump pressure; the variable conditions are core types and injection fluid types, injection flow rates, and axial pressure and confining pressure conditions; converting the core types and the injection fluid types into virtual variables; taking the fracturing pump pressure as a dependent variable, and taking the differences between the core types and the injection fluid types, the injection flow rates, and the axial pressure and the confining pressure as independent variables to establish a multiple linear regression model; adopting a least square method to perform fitting to obtain a regression coefficient of each independent variable; performing t test to obtain a p value of each independent variable, and screening out independent variables with p values less than or equal to 0.2; and performing supercritical CO2 phase state stress collaborative fracturing. The present application solves the problem that the existing method is unstable in actual application and is difficult to meet the diversified needs of different unconventional reservoirs.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of oil and gas field development, and particularly relates to a core type adaptive SC-CO2 phase state stress synergistic fracturing method. BACKGROUND

[0002] The development of unconventional reservoirs, especially shale oil and tight oil and gas, has long been faced with challenges such as low porosity, poor permeability and imperfect fracture network. Although the existing fracturing technology, especially the traditional water-based fracturing fluid and acid fracturing technology, has achieved certain results in the development of some conventional oil and gas fields, in the application of unconventional reservoirs, it often faces the problems of limited fracturing effect and insufficient complexity of fractures. For example, the main problem of water-based fracturing fluid is its poor permeability and weak fracture propagation ability, especially in low-permeability shale oil and tight sandstone, it is difficult for water-based fluid to form a complex fracture network, resulting in insufficient fracture ductility and affecting oil and gas recovery.

[0003] SC-CO2, the full name of which is Supercritical Carbon Dioxide, is also known as supercritical carbon dioxide. As a research hotspot in recent years, SC-CO2 fracturing technology can form a more complex and deep fracture network in low-permeability reservoirs due to its diffusion property as a gas and solubility as a liquid in the supercritical state.

[0004] Although SC-CO2 technology has made certain application progress in the development of shale oil and gas and tight oil and gas, the existing method still has the problems of insufficient core type adaptation and insufficient synergistic control of formation stress conditions and SC-CO2 phase state. The current research generally ignores the synergistic effect between formation stress conditions and SC-CO2 fluid phase state, resulting in significant differences in fracture propagation behavior under different stress states. The above technical defects make the existing SC-CO2 fracturing method unstable in actual application, and it is difficult to meet the diversified needs of different unconventional reservoirs. SUMMARY

[0005] In order to solve the problems of insufficient core type adaptation and insufficient synergistic control of stress conditions and SC-CO2 phase state in the existing SC-CO2 fracturing technology, resulting in unstable effect of the existing method in actual application, and difficult to meet the diversified needs of different unconventional reservoirs, the present application provides a core type adaptive SC-CO2 phase state stress synergistic fracturing method.

[0006] To achieve the above purpose, the technical scheme of the present application is as follows.

[0007] The application provides a core type adaptive SC-CO2 phase state stress synergistic fracturing method, including the following steps: carrying out fracturing experiments under multiple variable conditions to obtain fracturing pump pressures under the multiple variable conditions; the variable conditions are core types and injection fluid types, injection flow rates, and axial pressure and confining pressure conditions; converting the core types and the injection fluid types into virtual variables; according to the virtual variables of the core types and the injection fluid types, establishing a multiple linear regression model with the fracturing pump pressures as dependent variables and differences between the core types and the injection fluid types, the injection flow rates, and the axial pressure and the confining pressure as independent variables; according to the established multiple linear regression model, performing fitting by using the least square method to minimize the sum of squares of errors between all observation values and prediction values, obtaining regression coefficients of each independent variable; performing t-test on the regression coefficients of each independent variable to evaluate the significance of each independent variable on the fracturing pump pressure, obtaining p values of each independent variable, and screening independent variables with p values less than or equal to 0.2; performing SC-CO2 phase state stress synergistic fracturing with the independent variables with p values less than or equal to 0.2 as experimental conditions.

[0008] Preferably, the core types are Q9 layer shale, Q1 layer shale, Q2 layer shale and sandstone; and the injection fluid types are clear water, liquid CO2 and supercritical CO2. Preferably, the Q9 layer shale, the Q1 layer shale and the Q2 layer shale are different layer shales in a geological profile, and the geological profile is mainly composed of laminated shale. In the application, the Q1 layer shale is Q1 layer laminated shale, the Q2 layer shale is Q2 layer laminated shale, the Q9 layer shale is Q9 layer laminated shale, and the sandstone is tight sandstone. Preferably, the method for converting the core types and the injection fluid types into virtual variables is to convert the core types and the injection fluid types into qualitative variables, and then convert the qualitative variables into virtual variables.

[0009] Preferably, the axial pressure is 10 MPa to 15 MPa; and the confining pressure is 10 MPa to 15 MPa.

[0010] Preferably, the injection flow rate is 0.4 mL / min to 6 mL / min.

[0011] The application has the following beneficial effects:

[0012] 1. The application considers the synergistic effect of core types, stress conditions and supercritical CO2 fluid phase states, and proposes a more accurate and efficient fracturing method, which has significant advantages in improving fracturing effect, reducing energy consumption, increasing fracture complexity and improving oil and gas recovery compared with the prior art, and solves the problems of unstable effect in actual application and difficulty in meeting the diversified needs of different unconventional reservoirs.

[0013] 2、The application can adjust the phase state of supercritical CO2 fluid, such as liquid, supercritical state or gas state, according to the physical properties of different core types, such as porosity, permeability, mineral composition, etc., can optimize the permeability and fracture propagation effect of the fluid according to the actual situation of the reservoir, and significantly improve the oil and gas recovery rate. The application ensures the best performance of supercritical CO2 fluid in different reservoirs by adapting to the core type.

[0014] 3、The application takes the relationship between axial pressure and confining pressure as the stress condition, and optimizes the synergy between the stress condition and the phase state of supercritical CO2 fluid. Because different formation stress states, such as axial pressure greater than confining pressure or axial pressure less than confining pressure, will affect the fracturing effect, the application proposes to adjust the phase state of supercritical CO2 fluid and the injection condition under different stress conditions, so as to maximize the complexity and depth of the fracture and improve the oil and gas recovery rate.

[0015] 4、The application proposes a precise fluid injection flow rate and pressure control method. According to the physical properties of different reservoirs, such as permeability and porosity, the injection flow rate and pressure of supercritical CO2 are adjusted to achieve the best expansion of the fracture. This method can effectively avoid uneven permeation during fluid injection, ensure that the fluid can permeate uniformly in the reservoir and optimize the complexity of the fracture, thereby improving the fracturing effect.

[0016] 5、The application proposes a supercritical CO2 fracturing fluid selection method based on core type optimization. By customizing different supercritical CO2 fracturing fluid compositions according to the core type of the reservoir, such as shale and sandstone, the application can improve the compatibility of the fracturing fluid with the reservoir rock, enhance the permeability of the fluid and the fracture propagation effect. By optimizing the selection method of the fracturing fluid, the efficiency and effect of the fracturing process are improved. BRIEF DESCRIPTION OF DRAWINGS

[0017] Figure 1 is a structural schematic diagram of a multi-fluid pseudo-triaxial fracturing experiment device in an embodiment of the application. Among them, 1, triaxial fracturing holder; 2, manual axial pressure pump; 3, manual confining pressure pump; 4, data acquisition and processing unit; 5, vacuum pump; 6, first piston container; 7, second piston container; 8, fracturing pump; 9, temperature measurement and control unit; 10, gas booster pump; 11, gas cylinder interface; V1, vent valve; V2, first pressure regulating valve; V3, second pressure regulating valve; V4, third pressure regulating valve; V5, fourth pressure regulating valve; V6, fifth pressure regulating valve; V7, sixth pressure regulating valve; V8, seventh pressure regulating valve; P1, axial pressure sensor; P2, confining pressure sensor; P3, fracturing pressure sensor; P4, vacuum pressure sensor.

[0018] Figure 2 is a physical picture of a core sample in an embodiment of the application. Among them, (a) is a physical picture of a shale core sample; (b) is a physical picture of a sandstone core sample.

[0019] Figure 3 Fig. 1 is a size annotation diagram of a core sample and a physical diagram of a processed core sample in embodiments of the present application. Wherein, (a) is a size annotation diagram of a core sample; (b) is a physical diagram of a processed core sample.

[0020] Figure 4 Fig. 2 is a phase diagram of carbon dioxide.

[0021] Figure 5 Fig. 3 is a pump pressure-time curve under different fracturing media. Wherein, (a) is a pump pressure-time curve of Q9 layer shale; (b) is a pump pressure-time curve of Q1 layer shale under different fracturing media; (c) is a pump pressure-time curve of Q2 layer shale under different fracturing media; (d) is a pump pressure-time curve of tight sandstone under different fracturing media.

[0022] Figure 6 Fig. 4 is a pump pressure-time curve of different layer shale and Q1 layer shale and tight sandstone. Wherein, (a) is a pump pressure-time curve of different layer shale; (b) is a pump pressure-time curve of Q1 layer shale and tight sandstone.

[0023] Figure 7 Fig. 5 is a pump pressure-time curve of Q2 layer shale under different stress conditions.

[0024] Figure 8 Fig. 6 is a fracture pump pressure of different core types and injected clear water and liquid CO2 under different stress conditions. Wherein, (a) is a fracture pump pressure of different cores under different stress conditions; (b) is a fracture pump pressure of injected clear water and liquid CO2 under different stress conditions.

[0025] Figure 9 Fig. 7 is a fracture pump pressure of different core types under different injection flow rates.

[0026] Figure 10 Fig. 8 is a pump pressure-time curve of Q9 layer shale and tight sandstone under different injection flow rates. Wherein, (a) is a pump pressure-time curve of Q9 layer shale under different injection flow rates; (b) is a pump pressure-time curve of tight sandstone under different injection flow rates.

[0027] Figure 11 Fig. 9 is a regression analysis result. DETAILED DESCRIPTION

[0028] In order to make the objects, technical solutions and advantages of the present application clearer, the present application will be further described in detail below with reference to the embodiments. It should be understood that the specific embodiments described herein are only used to explain the present application and not used to limit the present application. All other embodiments obtained by those of ordinary skill in the art without creative labor fall within the scope of the present application.

[0029] In the present application, supercritical CO2 refers to carbon dioxide in a supercritical state, referred to as SC-CO2, and the temperature and pressure of SC-CO2 are both higher than the critical point of carbon dioxide, which is 31.1°C and 7.38MPa. In this supercritical state, supercritical CO2 has the density of a liquid and the diffusivity of a gas, and can effectively penetrate the reservoir rock at a low pressure, promote crack propagation, and improve oil and gas release effect.

[0030] Phase adjustment refers to the conversion of fluid between different phases by controlling temperature and pressure. In a supercritical state, supercritical CO2 has optimal permeability and solubility, and is therefore suitable as a fracturing medium. Through phase adjustment, the fluidity of supercritical CO2 can be optimized according to the type of reservoir core, permeability and stress conditions, thereby improving the crack propagation effect. Crack propagation refers to the process of forming and extending a crack network in the rock by injecting fluid during fracturing to enhance the permeability of the reservoir and the flow path of oil and gas, which is the core step of fracturing operation. The crack initiation pressure refers to the minimum pressure required for fluid to overcome the strength of the rock formation and initiate a crack. Due to its low viscosity and high diffusivity, supercritical CO2 has a lower crack initiation pressure than traditional water-based fracturing fluids under the same formation conditions, which helps to achieve lower energy consumption for rock rupture. Axial stress is the stress acting in the vertical direction of the core, and confining pressure is the stress acting in the lateral direction of the rock formation, both of which affect the rock fracture mode and fracturing effect. Fluid injection rate and injection pressure are the speed and pushing pressure of the fracturing fluid entering the reservoir, which have a key influence on the formation, expansion uniformity and fracturing effect of the crack. Crack morphology refers to the structure and distribution of the cracks formed by fracturing, and its complexity directly affects oil and gas flow and recovery. Shale oil and tight sandstone are typical unconventional reservoirs with low porosity and low permeability, and are difficult and costly to exploit. The English name of enhanced oil recovery is Enhanced Oil Recovery, abbreviated as EOR. EOR technology improves recovery by gas injection, and supercritical CO2 fracturing as an EOR method can significantly improve the exploitation efficiency by optimizing crack complexity and permeability.

[0031] The existing supercritical CO2 fracturing technology still has the following problems: core type adaptability is insufficient: the existing scheme mostly uses uniform fracturing parameters, without fully considering the differences in mineral composition, porosity and permeability characteristics, etc. of different cores, such as shale and tight sandstone, leading to unstable fracturing effect. Stress condition control is insufficient: the existing method fails to systematically optimize the fluid phase state and injection strategy under different axial pressure / confining pressure relationships, ignoring the key influence of actual formation stress on crack formation and stability. Injection condition optimization is insufficient: the injection flow rate and pressure setting are relatively single, without differentiated design according to the reservoir characteristics, which is easy to lead to unsatisfactory crack propagation or insufficient energy utilization. The mechanism of supercritical CO2 phase state and rock layer interaction is not clear: the research on the interaction between supercritical CO2 phase state adjustment and mineral and pore structure is insufficient, which restricts the optimization potential of crack network in different core reservoirs. Energy efficiency optimization is lacking: the existing research mostly focuses on improving crack complexity, without systematically considering the minimization of energy consumption, which affects the comprehensive benefits of supercritical CO2 fracturing technology. Therefore, the present application proposes a core type adaptive supercritical CO2 phase state-stress collaborative fracturing method, which adjusts the fracturing medium and construction parameters according to the core type and stress condition, to realize the overall improvement of fracturing effect and energy efficiency.

[0032] As Figure 1 , the multi-fluid pseudo-triaxial fracturing experiment device includes a triaxial fracturing holder 1, a data acquisition and processing unit 4, a gas / liquid pressure boosting control system, a heating and temperature maintaining system, a pseudo-triaxial servo control system and a gas cylinder interface 11; the multi-fluid pseudo-triaxial fracturing experiment device is an existing triaxial fracturing experiment device. The gas / liquid pressure boosting control system includes a manual axial pressure pump 2, a manual confining pressure pump 3, a vacuum pump 5, a first piston container 6, a second piston container 7, a fracturing pump 8 and a gas pressure boosting pump 10; the heating and temperature maintaining system includes a temperature measurement and control unit 9; the gas / liquid pressure boosting control system is used to maintain the pressure of the triaxial fracturing holder 1 ≤50MPa; the heating and temperature maintaining system is used to adjust the temperature range to be room temperature-100℃. The temperature of the room temperature is 20-30℃. The vent valve V1, the first pressure regulating valve V2, the second pressure regulating valve V3, the third pressure regulating valve V4, the fourth pressure regulating valve V5, the fifth pressure regulating valve V6, the sixth pressure regulating valve V7 and the seventh pressure regulating valve V8 are respectively used to adjust the pressure. The axial pressure sensor P1, the confining pressure sensor P2, the fracturing pressure sensor P3 and the vacuum pressure sensor P4 are respectively used to display the pressure.

[0033] A core type adaptive SC-CO2 phase state stress collaborative fracturing method, specifically as follows:

[0034] Step 1, carry out fracturing experiments under multiple variable conditions to obtain the fracturing pump pressure under multiple variable conditions; the variable conditions are core type and injection fluid type, injection flow rate, and axial pressure and confining pressure conditions.

[0035] Specifically, the core types are Q9 layer shale, Q1 layer shale, Q2 layer shale and sandstone; the injection fluid types are clear water, liquid CO2 and supercritical CO2. The Q9 layer shale, Q1 layer shale and Q2 layer shale are different layers of shale in the geological profile, and the geological profile is mainly of laminated shale.

[0036] Core sample preparation: shale cores and sandstone cores are used in the experiment to ensure similar physical properties and consistent drilling direction. After cutting and polishing, the core sample is made into a standard cylindrical shape with a diameter of Φ1=50mm and a height of h1=100mm, as shown in Figure 2 . Then, drilling and fracturing pipe bonding are performed to simulate the actual wellbore fracturing process: a Φ2=10mm diameter and h2=45mm deep injection hole is drilled in the center of the core sample end face, and a PEEK pipe is used as the fracturing pipe. Before bonding, an O-ring is used to fix the pipe head, leaving a length of h3=3mm and a diameter of Φ3=8mm of the open hole section. After injecting the special adhesive to fix the fracturing pipe, it is left to cure for 48 hours to ensure the bonding strength and sealing performance. Finally, the excess pipe body and adhesive outside the core sample are trimmed to ensure the flatness of the core sample end face, facilitating the injection of fracturing medium. The finished core sample is shown in Figure 3 .

[0037] Fracturing experiment: A multi-fluid pseudo-triaxial fracturing experiment device is used to systematically conduct shale fracturing experiments under different axial pressures and confining pressures, injection flow rates and fracturing medium conditions for core samples of Q9 layer shale, Q1 layer shale and Q2 layer shale in different oil layers and tight sandstone samples. The fracturing medium is water, liquid CO2 or supercritical CO2. The specific process is as follows:

[0038] Instrument installation and debugging: Place the prepared core sample in the center of the triaxial fracturing holder, tightly wrap it with a high-temperature resistant rubber sleeve, and adjust the use of conventional rubber sleeves and carbon dioxide-resistant rubber sleeves according to the experimental scheme. Then, use the bolt to tighten and seal the core holder, and connect the fluid inlet and outlet pipelines, temperature sensors and pressure sensors. Connect the power supply of the experimental device and start the control panel, and connect the computer data acquisition system. Perform pipeline airtightness test: introduce nitrogen or clear water into the system at a certain pressure, and check the entire high-pressure pipeline system for leaks.

[0039] Axial pressure and confining pressure loading: simultaneously open the confining pressure and axial pressure loading system, and apply confining pressure and axial pressure to the core sample simultaneously. When the axial pressure reaches the preset value, the experiment sets the axial pressure to 10MPa or 15MPa, and the confining pressure to 10MPa or 15MPa. Then, lock the axial pressure control valve to maintain a constant axial pressure, and continue to apply confining pressure to the set value, which should be greater than the estimated maximum fluid injection pressure to ensure the effective sealing of the core sample during subsequent fracturing medium injection.

[0040] Pressure adjustment, system preheating and temperature control: According to the injected fracturing medium, the pressure value of the gas booster system is adjusted, and in the experiment, the liquid CO2 is set to 5 MPa, and the supercritical CO2 is set to 10 MPa, and the gas is transferred to the fracturing pump through the pipeline. Turn on the preheating switch, set the system temperature to the experimental design value, the liquid CO2 is 20℃, and the supercritical CO2 is 60℃. Continue heating for more than 1 hour to ensure that the overall temperature inside the core sample, the injection pipeline and the fracturing medium all reach and stabilize at the temperature corresponding to the target phase state. The target phase state is liquid or supercritical state.

[0041] After the temperature is stable, the fracturing medium injection and fracture process monitoring begins. Ensure that all related valves are in the open state, start the high-pressure pump to set the injection flow rate to inject the target fracturing medium into the core sample. Monitor and record the change curve of the injection pressure with time in real time during the experiment; the injection pressure is the pump pressure. When the core sample breaks, it shows that the pressure curve appears a peak value and then decreases significantly, and after the pressure tends to be stable, the fracturing medium injection is terminated, the experiment is ended, and the fracture pump pressure is obtained.

[0042] System pressure relief, cooling and sample recovery: After the experiment is completed, the system pressure relief, cooling and sample recovery are carried out. In order, safely close the system: stop the heating device, close the fracturing medium gas cylinder valve, stop the high-pressure pump, and finally cut off the main power supply. Then, the confining pressure and axial pressure are slowly removed in turn. Carefully take out the fractured core sample and recycle it for subsequent analysis.

[0043] In order to study the influence of different injection fluid types, different axial pressures and confining pressures, and different injection flow rates on the cracking characteristics of different core types, fracturing experiments of different injection fluid types are designed, and part of the fractured core samples are scanned by CT. The quantitative properties of cracks are calculated according to the crack quantitative analysis method. The specific experimental scheme design is shown in Table 1 and Table 2.

[0044] Table 1 Experimental scheme of core type as different layer section laminated shale

[0045]

[0046] Note: Axial pressure / confining pressure is 10 / 10, which means axial pressure = confining pressure; axial pressure / confining pressure is 15 / 10, which means axial pressure > confining pressure; axial pressure / confining pressure is 10 / 15, which means axial pressure < confining pressure.

[0047] Table 2 Experimental scheme of core type as tight sandstone

[0048]

[0049] Note: Axial pressure / confining pressure is 10 / 10, which means axial pressure = confining pressure; axial pressure / confining pressure is 15 / 10, which means axial pressure > confining pressure; axial pressure / confining pressure is 10 / 15, which means axial pressure < confining pressure.

[0050] Different fracturing medium result analysis: In order to systematically explore the influence of different fracturing media on the core fracture characteristics, comparative experiments were carried out on Q9 layer shale, Q1 layer shale, Q2 layer shale and tight sandstone under uniform basic conditions, and the action mechanism of different media was revealed. The uniform basic conditions are axial pressure / surrounding pressure = 10.00 MPa / 10.00 MPa, and the injection flow rate is matched according to the characteristics of the fracturing medium: supercritical CO2 is 4 mL / min, and liquid CO2 and water are 0.4 mL / min. Q9 layer shale is P1 group, P6 group and P7 group; Q1 layer shale is P8 group, P11 group and P12 group; Q2 layer shale is P17 group, P20 group and P21 group; and tight sandstone is S1 group, S6 group and S7 group.

[0051] In order to ensure that the CO2 fluid used in the experiment maintains its expected phase, before fluid injection, reference is made to the carbon dioxide phase diagram, as shown in Figure 4 , and constant temperature heating equipment and gas pressurizing equipment are used to adjust the pressure and temperature. The initial pressure of supercritical CO2 is 10 MPa, and the temperature is 60°C; the initial pressure of liquid carbon dioxide is 5 MPa, and the temperature is 20°C. As can be seen from the pump pressure-time curve shown in Figure 5 , with the increase of injection time, the pump pressure gradually rises, and after reaching the peak value, the pump pressure rapidly decreases due to the initiation and expansion of the fracture to the sample surface. The fracture pump pressure presents a consistent gradient with the type of fracturing medium: water > liquid CO2 > supercritical CO2, and this law is stable in different core types. The specific data are as follows: Q9 layer shale: supercritical CO2 / P1 group is 32.91 MPa, liquid CO2 / P6 group is 35.65 MPa, and water / P7 group is 36.83 MPa; Q1 layer shale: supercritical CO2 / P8 group is 34.96 MPa, liquid CO2 / P11 group is 38.76 MPa, and water / P12 group is 39.18 MPa; Q2 layer shale: supercritical CO2 / P17 group is 34.73 MPa, liquid CO2 / P20 group is 37.30 MPa, and water / P21 group is 38.31 MPa; and tight sandstone: supercritical CO2 / S1 group is 34.12 MPa, liquid CO2 / S7 group is 43.59 MPa, and water / S6 group is 44.50 MPa.

[0052] The pump pressure of liquid CO2 increases by 7.40% to 27.75%, and that of clean water increases by 10.31% to 30.42%. The increase of pump pressure of tight sandstone is generally higher than that of shale, which reflects that low-permeability cores are more sensitive to the type of fracturing medium. The low viscosity of supercritical CO2 significantly reduces the flow resistance in the core, and can quickly diffuse along the bedding or microfracture to form a uniform pore pressure field. Taking the shale in Q9 layer as an example, the pore pressure transmission efficiency of supercritical CO2 is higher than that of clean water, and the breakdown pump pressure is reduced by 11.91%. The viscosity of liquid CO2 is slightly higher, and the permeation efficiency is lower, so the pump pressure is between the two. At 60℃ and 10MPa, supercritical CO2 has both gas diffusion and liquid solubility, with a diffusion coefficient 3 times that of liquid CO2, which can efficiently invade micro-pores and expand the effective action radius, thereby reducing the breakdown pressure. At 20℃ and 5MPa, the phase of liquid CO2 is stable, but the diffusion capacity is limited, and the pore pressure improvement effect is weak.

[0053] Clean water and clay minerals in shale are prone to hydration, temporarily enhancing the cementation strength of bedding surfaces and further increasing the breakdown resistance. The pump pressure of Q1 layer shale during clean water fracturing is 1.08% higher than that during liquid CO2 fracturing; this effect is almost negligible in tight sandstone with clay content <5%.

[0054] Clean water and clay minerals in shale are prone to hydration, temporarily enhancing the cementation strength of bedding surfaces and further increasing the breakdown resistance, which makes the pump pressure of clean water generally higher than that of CO2 medium. The hydration during clean water fracturing of Q1 layer shale makes the pump pressure 1.08% higher than that during liquid CO2 fracturing, and this effect is almost negligible in tight sandstone with clay content <5%.

[0055] Analysis of results of different types of cores: To explore the cracking characteristics of different types of cores during fracturing, the authors selected the laminated shale in Q1 layer, Q2 layer and Q9 layer and tight sandstone as the research objects and carried out comparative experiments under the same experimental conditions. During the experiment, the axial pressure / circumferential pressure was kept at 10MPa / 10MPa, the injected fluid was supercritical CO2, and the injection flow rate was 4mL / min to ensure the uniqueness of the variables and only change the core type and shale layer to analyze the influence on the breakdown pump pressure.

[0056] Analysis of results of different layers of laminated shale cores: From the breakdown pressure and pump pressure-time curves in Fig. Figure 6 The specific data are as follows: In the laminated shale, the breakdown pump pressure of P1 group in Q9 layer is 32.91MPa, that of P8 group in Q1 layer is 34.96MPa, and that of P17 group in Q2 layer is 34.73MPa.

[0057] From the comparison of different layers of shale, the fracture pump pressure of Q9 layer shale is the lowest, the fracture pump pressure of Q1 layer shale is the second, and the fracture pump pressure of Q2 layer shale is slightly lower than that of Q1 layer shale. This result shows that even if the same belongs to laminated shale, the mechanical properties of different layers are different, which is mainly related to the formation environment. Different layers of shale experienced different pressure, temperature and mineral composition deposition conditions during the formation process, resulting in differences in density, pore structure and bedding development characteristics. Q9 layer shale is mainly formed in shallow marine sedimentary environment, with high content of clay minerals and weak cementation between layers, while Q1 layer shale and Q2 layer shale are formed in deeper sedimentary environment, with increased content of siliceous or calcareous cement and more compact layer structure, which requires higher pump pressure to break the sample during fracturing.

[0058] From the specific data, the fracture pump pressure of each layer of shale shows a gradient distribution of "Q9 layer shale < Q2 layer shale < Q1 layer shale": the fracture pump pressure of Q9 layer P1 group is 32.91 MPa, that of Q2 layer P17 group is 34.73 MPa, and that of Q1 layer P8 group is 34.96 MPa. The difference between Q2 layer and Q9 layer is 1.82 MPa, the difference between Q1 layer and Q2 layer is 0.23 MPa, the relative difference between Q2 layer and Q9 layer is 5.53%, and the relative difference between Q1 layer and Q2 layer is 0.66%, indicating that the difference between Q9 layer and the other two layers is more significant, while the difference between Q1 layer and Q2 layer is relatively subtle.

[0059] From the perspective of formation environment, the core of the difference between layers lies in the differentiation of pressure, temperature and mineral composition during deposition. Q9 layer shale is mainly formed in shallow marine sedimentary environment, where the deposition rate is slow, and clay minerals such as montmorillonite and illite can be fully enriched, with a content of more than 40%. The layered structure of clay minerals makes the cementation between shale layers weak, with small layer spacing and good connectivity, forming preferential channels for fluid penetration. When supercritical CO2 is injected, the fluid easily expands along the bedding surface, reducing the overall anti-fracture ability of the rock, so the fracture pump pressure is the lowest.

[0060] In contrast, the Q1 and Q2 shale layers were formed in a deeper sedimentary environment with a deep water body and high pressure, and the content of rigid minerals such as silica and calcite increased significantly during the deposition process. These rigid minerals filled the interlayer gaps through cementation, making the layer structure more dense and reducing the connectivity. At this time, the supercritical CO2 penetration path is limited, and the rock must overcome stronger matrix strength to break, so the fracture pump pressure of the Q1 and Q2 shale layers is significantly higher than that of the Q9 shale layer. Among them, the Q1 shale layer has a higher content of silica and stronger cementation, so the fracture pump pressure of the Q1 shale layer is slightly higher than that of the Q2 shale layer, with a difference of only 0.23 MPa, but it reflects the influence of the subtle differences in mineral composition on mechanical properties.

[0061] From the auxiliary verification of rock physical properties, the porosity and permeability of the Q9 shale layer are higher than those of the Q1 and Q2 shale layers. High porosity and permeability make it easier for supercritical CO2 to invade the rock interior, reducing the effective stress through pore elasticity effect, which further explains the lower fracture pump pressure. The low porosity and low permeability characteristics of the Q1 and Q2 shale layers exacerbate the difficulty of fluid penetration, requiring higher pump pressure to reach the fracture critical value.

[0062] Lamellar shale and tight sand core result analysis: from Figure 6 From the fracture pressure in the middle (b) and the pump pressure-time curves of the Q1 and Q2 shale layers and tight sand, the fracture pump pressure of the lamellar shale and tight sand shows the characteristics of "close but differentiated": the fracture pump pressure of the tight sand S1 group is 34.12 MPa; in the lamellar shale, the fracture pump pressure of the Q1 shale layer P8 group is 34.96 MPa, the fracture pump pressure of the Q2 shale layer P17 group is 34.73 MPa, and the fracture pump pressure of the Q9 shale layer P1 group is 32.91 MPa. Quantitative analysis shows that the fracture pump pressure of the Q1 shale layer is 0.84 MPa higher than that of the tight sand, with a range of 2.46%; the fracture pump pressure difference of the Q2 shale layer is reduced to 0.61 MPa, with a range of 1.79%; and the fracture pump pressure of the Q9 shale layer is 1.21 MPa lower, with a range of 3.55%.

[0063] From the core type structure core influence, the laminated shale has obvious anisotropy, the bedding plane exists, and the rock strength presents directionality, wherein the strength in parallel bedding direction is low, and the strength in vertical bedding direction is high. When supercritical CO2 is injected, if the fluid penetrates along the bedding direction, such as Q9 layer shale, the low strength characteristics of the bedding plane can be used to reduce the fracture resistance, so the pump pressure is lower than that of sandstone; if the bedding is dense, such as Q1 layer shale and Q2 layer shale, the fluid is difficult to expand along the bedding, and the high strength in the vertical bedding direction needs to be overcome, so the pump pressure is slightly higher than that of sandstone. The dense sandstone is uniformly cemented by quartz, feldspar and other minerals, has no obvious bedding or directionality, and the strength distribution is stable, so there is no preferential path for supercritical CO2 penetration, and the matrix strength needs to be uniformly broken through.

[0064] At the same time, the shale of different layers has great difference in mineral composition, which further affects the fracturing fracture pressure. The clay minerals of Q9 layer shale may swell slightly when encountering supercritical CO2, weaken the cementation of the bedding plane, and indirectly reduce the fracture resistance; Q1 layer shale and Q2 layer shale have a high siliceous content of about 30% to 45%, strong chemical stability, and are not easy to react with CO2, so the bedding cementation is stable and the anti-fracture ability is strong; the quartz content of the dense sandstone is as high as 70% to 80%, and the chemical inertness is strong, so the matrix strength is stable, and the pump pressure is less affected by the fluid-mineral interaction. This interaction between minerals and fluid makes the difference in pump pressure between Q9 layer shale and sandstone more significant, while the difference between Q1 layer shale, Q2 layer shale and sandstone depends more on the structural characteristics.

[0065] Analysis of supercritical CO2 fracturing results under different stress conditions: In order to study the influence of different stress conditions on the core fracture characteristics, three stress states are set, namely, axial pressure = confining pressure, axial pressure > confining pressure and axial pressure < confining pressure; when the axial pressure = confining pressure, the axial pressure / confining pressure = 10 MPa / 10 MPa; when the axial pressure > confining pressure, the axial pressure / confining pressure = 15 MPa / 10 MPa; when the axial pressure < confining pressure, the axial pressure / confining pressure = 10 MPa / 15 MPa; the fracturing experiments of Q9 layer shale, Q1 layer shale, Q2 layer shale and dense sandstone are carried out under the three stress states, and the injection fluid types cover supercritical CO2, liquid CO2 and water, so as to comprehensively explore the relationship between stress condition and fracture pump pressure.

[0066] From the overall experimental results of the laminated shale, the influence of stress condition on the core fracture pump pressure presents obvious regularity. For example, Figure 7 and Figure 8For the laminated shale, the fracture pump pressures of the three groups of experiments of Q9 layer shale, P1 group, P2 group and P3 group, are 32.91 MPa, 35.29 MPa and 37.75 MPa respectively when supercritical CO2 is injected; the fracture pump pressures of the three groups of experiments of Q2 layer, P17 group, P18 group and P19 group, are 34.73 MPa, 40.2 MPa and 45.09 MPa respectively. The rule is that the fracture pump pressure is the highest when the axial pressure is less than the confining pressure, the second when the axial pressure is greater than the confining pressure, and the lowest when the axial pressure is equal to the confining pressure.

[0067] For the compact sandstone, the fracture pump pressures of the three groups of experiments, S1 group, S2 group and S3 group, are 34.12 MPa, 39.94 MPa and 36.9 MPa respectively when supercritical CO2 is injected, which presents the rule that the fracture pump pressure is the highest when the axial pressure is greater than the confining pressure, the second when the axial pressure is less than the confining pressure, and the lowest when the axial pressure is equal to the confining pressure, which is different from the rule of shale. Because the compact sandstone has strong uniformity of structure and does not show obvious anisotropy like shale, it does not have the rich bedding in the vertical direction, so that the mechanical properties of the compact sandstone are more sensitive to the axial stress. When the axial pressure is greater than the confining pressure, the high axial stress makes the compressive capacity of the rock in the axial direction significantly enhanced, so that a higher pump pressure is needed to make the rock fracture; when the axial pressure is less than the confining pressure, the increase of the hoop stress has a relatively weak constraint on the sandstone, so that the fracture pump pressure is lower than that when the axial pressure is greater than the confining pressure.

[0068] This rule is consistent with the minimum principal stress theory in rock mechanics, according to the H-F criterion, that is, P f =3 σ 3- σ 1+ T 0- α p p , wherein, P f represents the fracture pressure; σ 1 represents the axial pressure; σ 3 represents the confining pressure; T 0 represents the tensile strength of the rock; α represents the pore elastic coefficient; p p represents the pore pressure. The fracture pressure of the rock is mainly controlled by the minimum principal stress. When the axial pressure is less than the confining pressure, the confining pressure becomes the maximum principal stress and the axial pressure becomes the minimum principal stress, at this time the hoop constraint of the rock is enhanced, and a higher pump pressure is needed to overcome the constraint to make the rock fracture; when the axial pressure is greater than the confining pressure, the axial pressure becomes the maximum principal stress and the confining pressure becomes the minimum principal stress, at this time the axial constraint is enhanced, but because the axial direction is consistent with the fluid injection direction, it offsets part of the constraint to a certain extent, so that the fracture pump pressure is lower than that when the axial pressure is less than the confining pressure; when the axial pressure is equal to the confining pressure, the rock is in an isotropic stress state, and the constraint is relatively weak, so that the fracture pump pressure is the lowest.

[0069] from Figure 8 Comparing the different fluid types in (b), in the Q1 shale layer, when liquid CO2 was injected, the fracturing pump pressure was 38.76 MPa for group P11, 39.5 MPa for group P13, and 39.25 MPa for group P15; when clear water was injected, the fracturing pump pressure was 39.18 MPa for group P12, 40.43 MPa for group P14, and 39.53 MPa for group P16. The fracturing pump pressure variation trends of the two fluids under different stress conditions are similar to those of supercritical CO2, both being slightly higher when axial pressure > confining pressure and lower when axial pressure < confining pressure, and the fracturing pump pressure of clear water is generally higher than that of liquid CO2.

[0070] Analysis of Experimental Results of Supercritical CO2 Fracture Induction at Different Injection Rates: To investigate the effect of injection rate on core fracture characteristics, experiments were conducted under the conditions of axial pressure = confining pressure and axial pressure / confining pressure = 10 MPa / 10 MPa. Three injection rates of 2 mL / min, 4 mL / min, and 6 mL / min were set, and supercritical CO2 was injected into Q9 shale, Q1 shale, and tight sandstone, respectively. The fracture pump pressure was measured to clarify the relationship between injection rate and fracture pressure. Figure 9 Overall, the experimental results show that the injection rate has a significant impact on the fracture pump pressure of different core samples. The low-permeability Q1 shale and tight sandstone exhibit a "single-tone increase in pump pressure as injection rate increases" pattern; while the high-permeability Q9 shale shows a "V-shaped trend of first decreasing and then increasing" pattern.

[0071] like Figure 10 (a) For the Q9 shale, the fracture pump pressure was 33.91 MPa when the injection flow rate of P4 was 2 mL / min, the fracture pump pressure of P1 dropped to 32.91 MPa when the injection flow rate was 4 mL / min, and the fracture pump pressure of P5 rose to 34.84 MPa when the injection flow rate was 6 mL / min, showing a V-shaped trend of first decreasing and then increasing. This may be related to the pore structure of the Q9 shale. The Q9 shale may have more natural fractures and high-permeability bedding. When the injection flow rate is low, as low as 2 mL / min, supercritical CO2 has enough time to penetrate along the natural fractures and bedding, resulting in a relatively uniform pore pressure distribution and a high fracturing pump pressure. When the injection flow rate increases to 4 mL / min, the fluid begins to accumulate inside the core while penetrating, the pore pressure gradient is moderate, and the expansion of natural fractures and the generation of new fractures reach equilibrium, causing the fracturing pump pressure to drop to the minimum. When the injection flow rate further increases to 6 mL / min, the fluid accumulation rate exceeds the penetration rate, the pore pressure rises rapidly, and the fracturing pump pressure increases.

[0072] For the Q1 shale, the fracturing pump pressure was 31.09 MPa at an injection flow rate of 2 mL / min for group P9, 34.96 MPa for group P8 at 4 mL / min, and increased to 38.72 MPa for group P10 at 6 mL / min, showing a significant increase with increasing injection flow rate. This is because at higher injection flow rates, the accumulation rate of supercritical CO2 inside the core is faster than its permeation and diffusion rate, leading to a rapid increase in pore pressure and a rapid decrease in the effective stress of the rock, thus reaching the fracturing condition in a shorter time, manifested as an increase in fracturing pump pressure. Furthermore, at high injection flow rates, the impact of the fluid on the core is enhanced, which may exacerbate the propagation of micro-fractures inside the rock, further promoting fracturing. However, due to the excessively rapid pressure accumulation, the overall fracturing pump pressure is actually higher.

[0073] like Figure 10 In (b), the experimental results for the tight sandstone in groups S1, S4, and S5 show a similar trend to those for the Q1 shale. The fracturing pump pressure in group S4 was 33.27 MPa at an injection flow rate of 2 mL / min, in group S1 it was 34.12 MPa at an injection flow rate of 4 mL / min, and in group S5 it increased to 38.45 MPa at an injection flow rate of 6 mL / min, monotonically increasing with increasing injection flow rate. This is because tight sandstone has low porosity and poor permeability, resulting in weak permeation and diffusion of supercritical CO2 within it. Regardless of the injection flow rate, the injected fluid mainly accumulates; the higher the injection flow rate, the faster the pressure accumulates, and the higher the fracturing pump pressure. Compared to shale, the fracture pump pressure of tight sandstone varies more significantly with the injection rate. The fracture pump pressure at 6 mL / min is 5.18 MPa higher than that at 2 mL / min. The difference is 7.63 MPa for the Q1 shale and 0.93 MPa for the Q9 shale. This indicates that the better the permeability of the core type, the more complex the effect of the injection rate on the fracture pump pressure.

[0074] Comparing different core types, at the same injection flow rate, the fracturing pump pressure of tight sandstone is similar to or slightly higher than that of shale. For example, at 4 mL / min, the fracturing pump pressure of group S1 (34.12 MPa) is close to that of group P1 (32.91 MPa) and group P8 (34.96 MPa). At 6 mL / min, the fracturing pump pressure of group S5 (38.45 MPa) is lower than that of shale P10 in layer Q1 (38.72 MPa) but higher than that of group P5 in layer Q9 (34.84 MPa). This indicates that the influence of core type on fracturing pump pressure is interactive with the injection rate. At low injection flow rates, the fracturing pump pressure of shale may be higher or lower than that of sandstone, while at high injection flow rates, the fracturing pump pressure of shale in layer Q1 may be higher than that of sandstone.

[0075] Step 2, converting the core type and injection fluid type into dummy variables; according to the dummy variables of the core type and injection fluid type, establishing a multiple linear regression model with the fracturing pump pressure as the dependent variable and the core type and injection fluid type, injection flow rate, and the difference between axial pressure and confining pressure as the independent variables; according to the established multiple linear regression model, fitting by least squares method to minimize the sum of squared errors between all observed values and predicted values, obtaining the regression coefficient of each independent variable; performing t-test on the regression coefficient of each independent variable to evaluate the significance of each independent variable on the fracturing pump pressure, obtaining the p-value of each independent variable, and screening out the independent variables with p-value ≤ 0.2; using the independent variables with p-value ≤ 0.2 as experimental conditions to perform supercritical CO2 phase stress collaborative fracturing.

[0076] Multivariate analysis of fracturing pump pressure: The experiment collected data on multiple variables, including injection flow rate, core type, injection fluid type, and axial pressure / confining pressure conditions. Regression analysis through the establishment of a multiple linear regression model can quantify the influence of various variables in the experiment, and has certain application value in optimizing fracturing effect and improving fracturing efficiency. Before regression analysis, the data needs to be processed to ensure that it meets the requirements. The experimental data includes both qualitative variables such as core type and injection fluid type, and quantitative variables such as injection flow rate and axial pressure / confining pressure. Qualitative variables need to be converted into dummy variables so that regression analysis can identify their impact on fracturing pump pressure. In dummy variable coding, a baseline group needs to be set to avoid "perfect multicollinearity" that causes the regression model to be unsolvable in regression fitting solution. In this experiment, there are two qualitative variables, core type and injection fluid type. The Q9 layer shale in core type and water in injection fluid type are set as the baseline group, without assigning dummy variables, and the correlation coefficient obtained can be used to represent the increase or decrease effect relative to Q9 layer shale or water.

[0077] The method of converting core type and injection fluid type into dummy variables is to convert qualitative variables into dummy variables with core type and injection fluid type as qualitative variables. The method of converting core type and injection fluid type into dummy variables is as follows: setting a baseline group that does not assign dummy variables; setting dummy variables for qualitative variables excluding the baseline group; the method of setting dummy variables for qualitative variables excluding the baseline group is: setting the dummy variable to 1 when selecting the corresponding core type, otherwise to 0; setting the dummy variable to 1 when selecting the corresponding injection fluid type, otherwise to 0.

[0078] The qualitative variables mainly include core type and injection fluid type. In the regression process of multivariate analysis, the core type includes Q9 shale, Q1 shale, Q2 shale and sandstone, and the Q9 shale is set as the reference group; the injection fluid type includes clear water, liquid CO2 and supercritical CO2, and the clear water is set as the reference group. A dummy variable is set for each core type, for example, for Q1 shale, a dummy variable representing Q1 shale is set as 1, and otherwise as 0. The injection fluid type includes water, liquid CO2 and supercritical CO2. A dummy variable is set for each fluid type. For example, for supercritical CO2, the dummy variable is 1 if this fluid is used, and otherwise as 0, and water and liquid CO2 are also coded in this way.

[0079] The quantitative variables mainly include axial pressure / confining pressure and injection fluid flow rate, and the two quantitative variables are specific numerical values, which have the condition of directly performing regression fitting. The fracture pump pressure is taken as the dependent variable, and the injection flow rate, core type, injection fluid type and the difference between axial pressure and confining pressure are taken as the independent variables. The purpose of establishing the regression model is to explore the relationship between the dependent variable and multiple independent variables, and the regression equation can be established by a multiple linear regression model as follows:

[0080] .

[0081] wherein, P 裂 is the fracture pump pressure; X 流速 is the injection flow rate; X Q1 is the dummy variable of Q1 shale; X Q2 is the dummy variable of Q2 shale; X 砂岩 is the dummy variable of sandstone; X 轴压 / 围压 is the difference between axial pressure and confining pressure; X SC-CO2 is the dummy variable of supercritical CO2; X 液态CO2 is the dummy variable of liquid CO2; is the error term, representing the random error in the model. β 0, β 1, β 2, β 3, β 4, β 5, β 6 and β 7 are the regression coefficients of the corresponding independent variables, respectively. X Q1 , X Q2 ,X 砂岩 is a dummy variable for the corresponding core type; X SC-CO2 , X 液态CO2 is a dummy variable for the corresponding fluid type. In this invention, the error is caused by two aspects: one is the error caused by the variables not considered in the experimental design, and the other is the error caused by the instruments and measurements during the experiment.

[0082] The multiple linear regression model is fitted by the least squares method, which minimizes the sum of squared errors between all observed values and predicted values. Through this method, the regression coefficients of each independent variable can be obtained, which can reflect the specific influence of each independent variable on the fracturing pump pressure. According to the experimental data, the regression analysis is carried out using the statsmodels library in Python. The results of the regression analysis are shown in Table 3.

[0083] Table 3 Regression analysis results

[0084]

[0085] The size and sign of the regression coefficients represent the specific influence of each independent variable on the fracturing pump pressure. The regression coefficient of the intercept is β 0 = 18.3971, which is the base value of the multiple linear regression model, indicating that when all independent variables are 0, the baseline value of the fracturing pump pressure is 18.3971 MPa. The regression coefficient of the injection flow rate is β 1 = 0.3016, indicating that for every 1 mL / min increase in the injection flow rate, the fracturing pump pressure increases by 0.3016 MPa. However, the p-value of the injection flow rate is 0.759, which is much larger than the significance level of 0.05, indicating that the effect of the injection flow rate on the fracturing pump pressure is not significant in this experiment. Compared with Q9 layer shale, Q1 layer shale has a p-value of 0.705, which is much larger than 0.05, indicating that the effect of Q1 layer shale on the fracturing pump pressure is not significant. Compared with Q9 layer shale, the regression coefficient of Q2 layer shale is β 3 = -4.4718, but its p-value is 0.181, indicating that Q2 layer shale has a certain effect on the fracturing pump pressure, but this effect is not significant under the current experimental conditions. The regression coefficient of the dense sandstone is β 4 = 0.4520, representing that compared with Q9 layer shale, the dense sandstone will slightly increase the fracturing pump pressure, but the p-value is 0.891, indicating that the effect of the dense sandstone on the fracturing pump pressure is relatively weak and not significant in this experiment. The difference between the axial pressure and the confining pressure has a significant effect on the fracturing pump pressure, with a regression coefficient of β5=0.9412, p-value is 0.067, close to the significant level of 0.05. This indicates that the difference between axial stress and confining pressure is large, which may lead to a higher fracturing pump pressure, and the change of stress conditions can have a more obvious effect on the fracturing pressure. The regression coefficient of supercritical CO2 is β 6=6.0581, indicating that when the fluid is supercritical CO2, the fracturing pump pressure will change by about 6.06 MPa than other fluid types, and better crack initiation and crack propagation effects can be obtained. The regression coefficient of liquid CO2 is β 7=12.3390, p-value is 0.023, indicating that liquid CO2 has the most significant effect on the fracturing pump pressure. This is the largest factor affecting the fracturing pump pressure in this experiment, indicating that liquid CO2 has high permeability and crack propagation ability in the fracturing process. Although supercritical CO2 shows some effect in this experiment, its p-value is 0.113, but its effect is slightly smaller than that of liquid CO2.

[0086] As Figure 11 , the regression analysis results provide multiple statistics to evaluate the performance of the multiple linear regression model. R 2 is 0.953, indicating that the multiple linear regression model can explain 95.3% of the variation of the fracturing pump pressure. This indicates that the multiple linear regression model has a very good fitting effect on the data, and can accurately reflect the influence of various independent variables on the fracturing pump pressure. By conducting t-test on the regression coefficients, the significance of each independent variable on the fracturing pump pressure can be evaluated. Independent variables with p-value≤0.2, such as liquid CO2 fluid and supercritical CO2 fluid, indicate that these factors have a significant effect on the fracturing pump pressure. Independent variables with p-value>0.5, such as injection flow rate, Q1 shale, and sandstone, indicate that these factors have no significant effect on the fracturing pump pressure under the experimental conditions.

[0087] In summary, the SC-CO2 phase stress synergistic fracturing method adapted to the core type provided by the embodiments of the present application couples core type identification, phase state locking of fracturing medium, stress regulation, and injection flow rate optimization. The phase state of the injected fluid is calibrated on the ground, and then the stress path is matched according to the characteristics of the core sample, and the step injection method is used to realize controllable crack initiation and expansion.

[0088] To quantify the influence of the type of injected fluid on the fracturing pump pressure, the experiment was carried out under the same geostress condition of axial pressure / confining pressure = 10 MPa / 10 MPa, and the phase control parameters of supercritical CO2 were 60 ℃ / 10 MPa, and the phase control parameters of liquid CO2 and clean water were 20 ℃ / 5 MPa, so that the fracturing medium was in the target phase before entering the ground, avoiding the uncontrollable fluctuation caused by phase change. The fracturing pump pressure of liquid CO2 was about 7.40%-27.75% higher than that of supercritical CO2, and the fracturing pump pressure of clean water was about 10.31%-30.42% higher than that of supercritical CO2. The increase of the dense sandstone was generally higher than that of the shale. The results show that the type of low-permeability core is more sensitive to the type of injected fluid.

[0089] To quantify the influence of the type of core on the fracturing pump pressure, the laminated shale was subdivided into Q1 layer shale, Q2 layer shale and Q9 layer shale, and under the same working condition and fracturing medium, the control parameters were set as follows: supercritical CO2, injection rate of 4 mL / min, axial pressure / confining pressure = 10 MPa / 10 MPa. The results show that the fracturing pump pressure of Q9 layer shale is the lowest, which is 32.91 MPa; the fracturing pump pressure of Q2 layer shale is the second, which is 34.73 MPa; and the fracturing pump pressure of Q1 layer shale is the highest, which is 34.96 MPa, forming a low, medium and high fracturing pump pressure gradient. The embodiment of the present application converts the high porosity and bedding connectivity advantage of Q9 layer shale into a lower cracking pressure baseline, and accordingly gives differentiated fracturing construction suggestions for laminated shale of different layers, significantly improving the adaptability and stability of the scheme in multiple core type reservoirs.

[0090] Stress and phase state are cooperated to realize controllable cracking and crack guiding. Under the condition of supercritical CO2 injection, Q9 layer shale and Q2 layer shale show consistent stress sensitivity law: when axial pressure < confining pressure, the fracturing pump pressure is the highest, when axial pressure > confining pressure, the fracturing pump pressure is the second, and when axial pressure = confining pressure, the fracturing pump pressure is the lowest. Taking Q2 layer shale as an example, the fracturing pump pressures when axial pressure = confining pressure, axial pressure > confining pressure and axial pressure < confining pressure are 34.73 MPa, 40.20 MPa and 45.09 MPa respectively. The embodiment of the present application obtains the target combination of the lowest cracking and stable expansion by predicting the stress field in the design stage and linking the supercritical CO2 phase state and injection strategy. The dense sandstone shows a different law that when axial pressure > confining pressure, the fracturing pump pressure is the highest, when axial pressure < confining pressure, the fracturing pump pressure is the second, and when axial pressure = confining pressure, the fracturing pump pressure is the lowest, and the fracturing pump pressures when axial pressure = confining pressure, axial pressure < confining pressure and axial pressure > confining pressure are 34.12 MPa, 39.94 MPa and 36.90 MPa respectively. The embodiment of the present application uses differentiated loading path and phase state window in the sandstone accordingly, avoids relying on shale experience alone, and improves the controllability and directivity of the crack.

[0091] The injection flow rate is positively correlated with the fracturing pump pressure. When the axial pressure / surrounding pressure is 10 MPa / 10 MPa, the fracturing pump pressure of the Q1 layer shale increases monotonously with the increase of the injection flow rate, and the fracturing pump pressure of the dense sandstone also increases monotonously. When the injection flow rate is 2 mL / min, 4 mL / min and 6 mL / min, the fracturing pump pressure of the Q1 layer shale is 31.09 MPa, 34.96 MPa and 38.72 MPa respectively, and the fracturing pump pressure of the dense sandstone is 33.27 MPa, 34.12 MPa and 38.45 MPa respectively. Therefore, the upper limit of the injection flow rate and the step-up strategy are set, which not only uses the higher injection flow rate pressure difference to drive the accelerated fracture penetration, but also avoids the rapid pressure accumulation, the initiation pressure lifting and the instability, and realizes the dynamic optimization of the low threshold initiation, the sustainable expansion and the controllable complexity on different core types. The cross-core type comparison shows that the fracturing pump pressures of the sandstone and the shale are close but differentiated at the same injection flow rate, which indicates that the injection flow rate effect and the core type exist interaction. Therefore, the two-dimensional parameter table of the core type x flow rate is established, which provides a theoretical basis for parameter adjustment. -1 -1 -1 Mechanism research shows that the supercritical CO2 has low viscosity and high diffusion. The diffusion coefficient is about 3 times that of liquid CO2, which brings faster pore pressure transmission and wider effective action radius; the water temporarily improves the bedding plane cementation strength due to the hydration of clay minerals, and lifts the initiation pressure. The present application takes the core type, the injection fluid type, the difference between the axial pressure and the surrounding pressure, and the injection flow rate into the multiple linear regression model, which can quantify the contribution weight of the corresponding independent variables to the fracturing pump pressure, and support the cross-block rapid migration and the prior parameter setting, such as the positive contribution of the axial pressure / surrounding pressure difference to the fracturing pump pressure, and the statistical test results of the overall influence of the injection flow rate.

[0092] Experimental data show that when supercritical CO2 is used as a fracturing medium, the initiation pressure of supercritical CO2 in different core types is significantly lower than that of traditional water-based fracturing fluid, and is adjustable in different reservoir core types, thereby optimizing the fracturing process and improving oil and gas recovery. Under the same stress conditions, the initiation pressure of supercritical CO2 is 15% to 30% lower than that of water-based fluid, and the difference is more significant as the reservoir permeability decreases. The initiation pressure of shale oil layer is lower than that of dense sandstone, which shows that supercritical CO2 has better permeability and fracture expansion in low permeability rock layers. The initiation pressure of supercritical CO2 in shale oil reservoir is 32.91 MPa, which is about 18.3% lower than that of water-based fluid (40.20 MPa); the initiation pressure of supercritical CO2 in dense sandstone is 34.12 MPa, which is about 14.7% lower than that of water-based fluid (39.94 MPa).

[0093] Experimental data show that when supercritical CO2 is used as a fracturing medium, the initiation pressure of supercritical CO2 in different core types is significantly lower than that of traditional water-based fracturing fluid, and is adjustable in different reservoir core types, thereby optimizing the fracturing process and improving oil and gas recovery. Under the same stress conditions, the initiation pressure of supercritical CO2 is 15% to 30% lower than that of water-based fluid, and the difference is more significant as the reservoir permeability decreases. The initiation pressure of shale oil layer is lower than that of dense sandstone, which shows that supercritical CO2 has better permeability and fracture expansion in low permeability rock layers. The initiation pressure of supercritical CO2 in shale oil reservoir is 32.91 MPa, which is about 18.3% lower than that of water-based fluid (40.20 MPa); the initiation pressure of supercritical CO2 in dense sandstone is 34.12 MPa, which is about 14.7% lower than that of water-based fluid (39.94 MPa).

[0094] ​​Under different stress conditions, the crack initiation pressure of supercritical CO2 is generally lower than that of water-based fluid. When the axial pressure is greater than the confining pressure, the crack initiation pressure of supercritical CO2 is lower, indicating that it is easier to promote crack formation. When the axial pressure is less than the confining pressure, the crack initiation pressure of supercritical CO2 is further reduced, and the advantage is more prominent. Supercritical CO2 fluid can adjust the crack initiation pressure according to the change of formation stress to achieve the best fracturing effect.

[0095] Supercritical CO2 can significantly reduce the crack initiation pressure, which is mainly related to its flowability and solubility in rock. The low viscosity and high diffusivity of supercritical CO2 make it easier to penetrate and expand in microcracks; fluid phase adjustment can achieve optimal crack initiation pressure under different reservoir conditions by controlling the phase state; supercritical CO2 can react with clay minerals and other minerals in the rock formation to change the bedding structure or cement strength and reduce the fracture strength. Compared with traditional water-based fracturing fluid, the crack initiation pressure of supercritical CO2 fluid is significantly reduced under different experimental conditions, and it can adapt to different types of reservoir cores and stress conditions, showing good adaptability and stability. Therefore, the phase state adjustment and stress condition optimization method of supercritical CO2 fluid proposed in the present application can significantly improve the efficiency of unconventional reservoir exploitation and reduce energy consumption, and has good environmental friendliness and application prospect.

[0096] The above is only a preferred embodiment of the present application, and is not intended to limit the present application. Any modification, equivalent replacement and improvement made within the spirit and principle of the present application shall be included in the protection scope of the present application.

Claims

1. A core type adapted SC-CO2 phase behavior stress synergic fracturing method, characterized in that, The method comprises the following steps: The method comprises the following steps: The variable conditions are core types, injection fluid types, injection flow rates, and axial pressure and confining pressure conditions; The core types and the injection fluid types are converted into virtual variables; A multiple linear regression model is established according to the virtual variables of the core types and the injection fluid types, with the fracturing pump pressure as a dependent variable and the differences between the core types and the injection fluid types, the injection flow rates, and the axial pressure and confining pressure as independent variables; The regression coefficients of each independent variable are obtained by fitting the multiple linear regression model using the least square method to minimize the sum of squared errors between all observed values and predicted values; The regression coefficients of each independent variable are subjected to t-test to evaluate the significance of each independent variable on the fracturing pump pressure, obtain the p value of each independent variable, and screen out independent variables with a p value less than or equal to 0.2; The supercritical CO2 phase stress synergistic fracturing is performed under the experimental conditions of the independent variables with a p value less than or equal to 0.2; The core types are Q9 layer shale, Q1 layer shale, Q2 layer shale, and sandstone; and the injection fluid types are clear water, liquid CO2, and supercritical CO2. The method for converting the core types and the injection fluid types into virtual variables is to convert qualitative variables into virtual variables; The method for converting the core types and the injection fluid types into virtual variables is as follows: A reference group is set, and no virtual variable is assigned to the reference group; and the qualitative variables excluding the reference group are subjected to virtual variable setting; The method for setting virtual variables for the qualitative variables excluding the reference group is as follows: When the corresponding core type is selected, the virtual variable is set to 1, otherwise, the virtual variable is set to 0; When the corresponding injection fluid type is selected, the virtual variable is set to 1, otherwise, the virtual variable is set to 0; The multiple linear regression model is as follows: P 裂 = β 0+ β 1 X 流速 + β 2 X Q1 + β 3 X Q2 + β 4 X 砂岩 + β 5 X 轴压 / 围压 + β 6 X SC-CO2 + β 7 X 液态CO2 +ϵ; wherein P 裂 is the break pump pressure; X 流速 is the injection flow rate; X Q1 is a dummy variable for Q1 shale; X Q2 is a dummy variable for Q2 shale; X 砂岩 is a dummy variable for sandstone; X 轴压 / 围压 is the difference between axial stress and confining stress; X SC-CO2 is a dummy variable for supercritical CO2; X 液态CO2 is a dummy variable for liquid CO2; e is error; β 0, β 1, β 2, β 3, β 4, β 5, β 6 and β 7 are the regression coefficients for the respective independent variables.

2. The core type adapted SC-CO2 phase behavior stress synergic fracturing method according to claim 1, characterized in that, The Q9 layer shale, the Q1 layer shale, and the Q2 layer shale are different shale layers in a geological profile, and the geological profile mainly comprises laminated shale.

3. The core type adapted SC-CO2 phase behavior stress synergic fracturing method according to claim 1, characterized in that, The axial pressure is 10 MPa to 15 MPa; and the confining pressure is 10 MPa to 15 MPa.

4. The core type adapted SC-CO2 phase behavior stress synergic fracturing method according to claim 1, characterized in that, The injection flow rate is 0.4 mL / min to 6 mL / min.

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