A Prediction Method for Calculating Fracturing Initiation Pressure Considering the Modification of Rock Mechanical Parameters After CO₂ Treatment

Abstract

The establishment of a more realistic CO₂ fracturing model serves to elucidate the intricate mechanisms underlying CO₂ fracturing transformation. Additionally, it furnishes a foundational framework for devising comprehensive fracturing construction plans. However, current research has neglected to consider the influence of CO₂ on rock properties during CO₂ fracturing, resulting in an inability to precisely replicate the alterations in the reservoir post-CO₂ injection into the formation. This disparity from the actual conditions poses a substantial limitation to the application and advancement of CO₂ fracturing technology. This work integrates variations in the physical parameters of rocks after complete contact and reaction with CO₂ into the numerical model of crack propagation. This comprehensive approach fully acknowledges the impact of pre-CO₂ exposure on the mechanical parameters of reservoir rocks. Consequently, it authentically restores the reservoir state following CO₂ injection, ensuring a more accurate representation of the post-fracturing conditions. In comparison with conventional numerical simulation methods, the approach outlined in this paper yields a reduction in the error associated with predicting fracturing pressure by 9.8%.

1. Introduction

In recent years, the escalating global demand for energy has propelled the extensive exploration and utilization of unconventional oil and gas resources. Notably, unconventional reservoirs are characterized by lower permeability [1,2,3,4]. Before formal extraction, reservoir transformation is often a prerequisite, and CO₂ fracturing stands out as a commonly employed method for such transformation [5,6,7]. In contrast to conventional fracturing methods, CO₂ fracturing demonstrates superior environmental friendliness. This method not only conserves substantial water resources but also facilitates CO₂ storage [8,9,10], thereby contributing to a reduction in greenhouse gas content. Furthermore, owing to the low viscosity and exceptional fluidity of CO₂, it possesses the capability to effectively penetrate and open micropores. Consequently, the fracturing process entails a lower initiation pressure, simplifying the formation of intricate fracture networks [11,12,13]. Pre-CO₂ fracturing can reduce the initiation difficulty of rock fracturing, thereby enhancing the effectiveness of hydraulic fracturing treatment. While the anticipated environmental and efficacy advantages of this technology are noteworthy, practical applications still encounter certain issues and challenges that necessitate further in-depth research [14,15,16].

1.1. Experimental Study on CO₂ Fracturing

CO₂ fracturing research is usually divided into two methods, namely experimental methods and numerical simulation methods [17,18,19]. In CO₂ experimental research, Ishida et al. [20] investigated the differences in fracture morphology and initiation pressure between liquid CO₂ and supercritical CO₂ fracturing in granite. Kizaki et al. [21] found through granite supercritical CO₂ and hydraulic fracturing experiments that compared to simple vertical fractures generated by water fracturing, the fractures generated by supercritical CO₂ fracturing are more complex. Zhang et al. [22] studied the initiation and propagation laws of CO₂ fracturing fractures in shale and pointed out that the degree of bedding development has a significant impact on the complexity of CO₂ fracturing fractures. Bennour et al. [23] studied the differences in crack propagation when shale is fractured with water, oil, and liquid CO₂, and pointed out that hydraulic fracturing tends to produce Type I cracks, while water and liquid CO₂ fracturing are prone to producing Type II cracks. Zou et al. [24] studied the crack propagation law of supercritical CO₂ fracturing in layered dense sandstone and pointed out that even under high-level, stress-difference conditions, supercritical CO₂ can promote the opening and shear fracture of bedding and natural fractures, thereby forming a complex fracture network. In CO₂ experimental research, researchers tend to focus more on true triaxial CO₂ fracturing experiments, which are actually the result of multiple-factor coupling. Through this experiment, CO₂ fracturing cannot be analyzed from the mechanism level. This article analyzes the effect of CO₂ on rocks from the perspective of basic mechanical experiments on rocks treated with CO₂ and deeply explores the evolution law of rock mechanics after CO₂ contact with rocks.

1.2. Numerical Study on CO₂ Fracturing

In a numerical simulation study of CO₂ fracturing, Yan et al. [25] considered the influence of CO₂ phase change and divided the supercritical CO₂ fracturing process into the supercritical CO₂ fracturing stage and the CO₂ phase change-induced fracturing stage. Based on the extended finite element method, a fluid–solid coupling model for the supercritical CO₂ fracturing stage was established. He et al. [26] established a three-dimensional dynamic model to study the expansion of CO₂ fracturing fractures. Research has found that the higher the reservoir temperature, the lower the initial in situ stress, and the longer and wider the cracks. Zhang et al. [27] conducted numerical studies on CO₂ fracturing using COMSOL software, and the results showed that CO₂ fracturing produces a rougher fracturing surface, especially for sandstone samples with a large number of large pores. Based on the above, it can be found that the current numerical simulation research of CO₂ fracturing mainly focuses on the differences introduced by the properties of CO₂ itself to the fracturing process [28]. Few researchers have paid attention to the impact of CO₂ on the properties of reservoir rocks, especially for pre-CO₂ fracturing [29]. The pre-CO₂ process not only replenishes the formation energy, but also affects the mechanical properties of reservoir rocks. Ignoring its influence will inevitably affect the numerical simulation results and cause significant errors, affect construction design, and cause engineering losses [30,31,32].

In summary, there are still shortcomings in the modification testing of rock mechanical properties using CO₂ in current CO₂ experimental research. However, in CO₂ numerical simulation research, the modification effect of CO₂ on rocks is often overlooked, and it is impossible to accurately reproduce the changes in the reservoir after CO₂ injection into the formation [33,34]. To address these issues, this article focuses on pre-CO₂ fracturing technology, which allows for full contact and reaction between rocks and CO₂, followed by mechanical experiments to quantify the impact of CO₂ on the mechanical properties of rocks, and analyzes the underlying mechanisms of CO₂ fracturing. At the same time, the experimental results are used to establish a pre-CO₂ fracturing simulation with modified mechanical parameters. This model fully considers the influence of pre-CO₂ fracturing on the mechanical parameters of reservoir rocks, accurately restores the reservoir state after CO₂ injection, and provides a reference for CO₂ fracturing construction design.

2. Evolution of Rock Mechanical Properties Under CO₂ Action

2.1. Experimental Sample and Design

2.1.1. Experimental Sample

The experimental sample of this study is shale, extracted from the Gulong shale oil field in Daqing, China. The vertical in situ stress is 50 MPa, the minimum in situ stress is 40 MPa, the maximum in situ stress is 55 MPa, the formation stress is 25 MPa, and the reservoir temperature is 110 °C. It presents obvious hard brittleness, and the rock is relatively dense with no obvious cracks on the surface. To maintain the same initial state of the rock, the experimental samples in this article are all cut from the same rock. The specific samples can be seen in Figure 1.

2.1.2. Experimental Design

For hydraulic fracturing research, key mechanical parameters include the elastic modulus, Poisson’s ratio, and tensile strength [35]. In this study, the elastic modulus and Poisson’s ratio were determined through triaxial compression tests, while tensile strength was measured using splitting tests. The experiments were conducted with a TAW-2000 microcomputer-controlled electro-hydraulic servo rock triaxial testing machine, which, along with interchangeable molds, enabled both triaxial compression and splitting tests. Permeability measurements were performed using a PDP-200 permeability tester.

The experimental process can be seen in Figure 2. The rock samples were firstly dried at 110 °C for 8 h to remove the influence of bound water inside the rock. Subsequently, the rock core holder was placed in a vacuum for 48 h and immersed in shale oil at 110 °C for 72 h to reach a saturated oil state, restoring the reservoir rock to its true state before extraction. To compare the changes in rock mechanical parameters before and after the influence of CO₂ and highlight the effect of CO₂ on rock modification, this study set up a control group experiment to test the saturated oil state and the mechanical properties of CO₂-modified rock samples. The CO₂-modified rock samples were obtained by further processing the saturated oil rock samples. The saturated oil rock samples were placed in a sealed reaction vessel, and CO₂ was injected into the reaction vessel at a temperature of 110 °C. The pressure inside the reaction vessel was maintained at 40 MPa, keeping CO₂ in a supercritical state for 30 min. At the end of the reaction period, the pressure was released, and the rock sample was removed to obtain the CO₂-modified specimen. Finally, permeability tests, triaxial compression tests, and splitting tests were conducted on the above rock samples, with the triaxial compression test set at a confining pressure of 45 MPa, consistent with the minimum horizontal principal stress of the reservoir.

2.2. Analysis of Experimental Results

The results or data from the triaxial compression and splitting experiments were processed to obtain the elastic modulus, Poisson’s ratio, and tensile strength, as presented in

Table 1. Experimental results.

	Saturated Oil Shale	CO2-Modified Shale
Elastic modulus (Gpa)	21.63	18.93
Poisson’s ratio	0.195	0.172
Tensile strength (Mpa)	6.18	5.69
Permeability (mD)	0.87	2.43

. The rock samples after the experiment are shown in Figure 3 and Figure 4. The following will analyze the parameters of the elastic modulus, Poisson’s ratio, and tensile strength.

2.2.1. The Influence of CO₂ on the Rocks’ Elastic Modulus

Figure 5 shows the comparison of the rocks’ elastic modulus before and after CO₂ modification. It can be seen from this figure that CO₂ has a weakening effect on the rocks’ elastic modulus. Following CO₂ modification, the reservoir’s elastic modulus decreased from 21.63 GPa to 18.93 GPa, representing a reduction of 12.5%.

The change in the elastic modulus can be explained by the theory of damage mechanics, in which damage variables are usually used to quantify internal damage to rocks. The most common definition method for damage variables is the Rabotnov damage variable [36]:

$$D=1-{\displaystyle \frac{\overline{A}}{A}}$$

(1)

where $\overline{A}$ is the effective bearing area, m²; A is the total bearing area, which is a fixed value related to the phase state, m²; D is the damage variable.

When the damage variable D is 1, the effective bearing area of the rock is equal to the total bearing area, and no damage occurs inside the rock. When the damage variable D is 0, the effective bearing area of the rock is 0, and the rock is completely destroyed.

Supercritical CO₂ (SC-CO₂) has extremely strong fluidity. Under high pressure, CO₂ will invade the interior of rocks. During the invasion process, it will inevitably damage the internal structure of the rocks and dissolve the minerals inside the rocks, causing the micropores to open and the effective bearing area to decrease. Ultimately, the rocks will be damaged and the damage variable will increase [37]. According to the assumption of strain equivalence, the relationship between the effective stress and the damage variable is as follows:

$$\overline{\sigma }={\displaystyle \frac{\sigma }{1-D}}$$

(2)

where $\overline{\sigma }$ is the effective stress, Pa. According to the definition of the elastic modulus, Equation (3) can be obtained:

$$E={\displaystyle \frac{\sigma }{\epsilon }}$$

(3)

Equations (2) and (3) can be combined as follows:

$$E=E_0\cdot (1-D)$$

(4)

where E is the elastic modulus of the rock after damage, Pa; E₀ is the undamaged elastic modulus, Pa.

When SC-CO₂ invades the interior of the rock, the rock undergoes damage, and the damage variable D increases. It can be inferred from Equation (4) that the elastic modulus of the sample after SC-CO₂ treatment should decrease, which is consistent with the experimental results in this paper.

2.2.2. The Influence of CO₂ on the Rocks’ Poisson’s Ratio

Figure 6 shows the comparison of the rocks’ Poisson’s ratio before and after CO₂ modification. The rocks’ Poisson’s ratio after CO₂ treatment has a downward trend, decreasing from 0.195 to 0.172, with a decrease of 11.8%.

The reasons for the decrease in Poisson’s ratio can be explained from two aspects. On the one hand, CO₂ has a certain dissolution effect, especially for clay minerals. Shale contains a large amount of clay minerals. When CO₂ enters the interior of the rock, dissolution occurs, and the clay content inside the rock decreases, leading to an increase in brittleness and a corresponding decrease in the overall Poisson’s ratio. On the other hand, after CO₂ invades the interior of the rock, it expands due to dissolution and capillary forces. In triaxial compression experiments, the internal pores of the rock are preferentially compressed when subjected to axial compression, and radial strain is less likely to occur when the pores are closed. The Poisson effect weakens and Poisson’s ratio decreases. The synergistic effect of the above two mechanisms ultimately leads to a decrease in the Poisson’s ratio of shale after CO₂ intrusion, which is consistent with the experimental results.

2.2.3. The Influence of CO₂ on Rock Tensile Strength

Figure 7 shows the comparison of the rocks’ tensile strength before and after CO₂ modification. It can be seen from this figure that CO₂ has a weakening effect on the rocks’ tensile strength. After CO₂ modification, the reservoir’s tensile strength decreased from 6.18 MPa to 5.69 MPa, which is a decrease of 7.9%.

The dissolution effect of CO₂ and the damage to the internal structure of the rocks during transport and flow can both reduce the bonding area of rocks, leading to a decrease in bonding strength. When subjected to tensile stress, fracturing is more likely to occur, and the specific mechanical parameters are manifested as a decrease in tensile strength.

2.2.4. The Influence of CO₂ on Rock Permeability

Figure 8 shows the comparison of permeability between shale and supercritical CO₂ under saturated oil conditions. From this figure, it can be seen that after shale is soaked in supercritical CO₂, the permeability increases from 0.87 mD to 2.43 mD, which is an increase of nearly 180%. Permeability is a quantification of the connectivity of internal pores in rocks. The entry of supercritical CO₂ into rock pores will destroy the original pore structure, and the dissolution effect of CO₂ will expand the original pores, causing an increase in the volume of connected channels. The macroscopic parameter is an increase in permeability. The findings of this study are highly consistent with those reported in the existing literature [38].

3. Numerical Simulation of Pre-CO₂ Fracturing

3.1. Numerical Implementation Methods

In previous CO₂ studies, the changes in the mechanical properties of reservoir rocks under CO₂ action were usually not considered, resulting in significant errors in numerical simulation results. In this paper, the changes in rock mechanical properties were fully considered in the numerical simulation study.

The numerical simulation data in this article come from a fractured shale oil reservoir well in the Gulong area of Daqing, China. The fracturing of the well is divided into two steps. Firstly, 75 m³ of CO₂ is injected into the well at a pressure of 40 MPa within 30 min, and CO₂ pre-fracturing is carried out before fracturing. Then, slippery water is used to perform hydraulic fracturing on the reservoir. The numerical simulation part simulates the input parameters based on the actual situation of the well and verifies the numerical simulation results using the fracturing results of the well. Therefore, the numerical simulation part of this article reproduces the construction process and is designed according to the following steps:

Step 1: In situ stress balance, restoring the initial stress state of the reservoir.

Step 2: Pre-injection of CO₂, in which CO₂ is continuously injected into the formation at a constant pressure of 40 MPa for 30 min to calculate the injected formation pressure.

Step 3: The evolution of rock mechanical properties under the action of CO₂. In this step, the range of CO₂-modified reservoirs is calculated by the CO₂ injection rate. The rock mechanical properties within this range are uniformly modified to the CO₂-modified reservoir rock mechanical properties obtained in this experiment. If the rock mechanical parameters are not within this range, the mechanical properties of the saturated oil rock samples obtained in the experiment are assigned.

Step 4: Slippery water fracturing simulation, in which hydraulic fracturing numerical simulation is performed to obtain the initiation pressure.

3.2. Modeling

3.2.1. Seepage Control Equation

The flow of CO₂ into the reservoir during the injection process is calculated using Darcy’s law [39]:

$$v={\displaystyle \frac{-k}{\eta }}\cdot {\displaystyle \frac{d\phi }{dl}}$$

(5)

where v is the seepage velocity, m/s; k is the rock permeability, mD; η is the fluid viscosity, mPa·s; φ is the flow force, MPa; and l is the distance between the two stages of seepage, m.

3.2.2. Rock Constitutive Equation

The constitutive equation of the rock matrix is mainly based on elasticity and calculated using the generalized Hooke’s law. The specific equations are as follows (6)–(9):

$$\sigma =D^{\mathrm{el}}{\epsilon }^{\mathrm{el}}$$

(6)

$$D^{\mathrm{el}}=\left[\begin{array}{cccccc}\lambda +2G& \lambda & \lambda & 0& 0& 0\\ \lambda & \lambda +2G& \lambda & 0& 0& 0\\ \lambda & \lambda & \lambda +2G& 0& 0& 0\\ 0& 0& 0& G& 0& 0\\ 0& 0& 0& 0& G& 0\\ 0& 0& 0& 0& 0& G\end{array}\right]$$

(7)

$$G={\displaystyle \frac{E}{2(1+\mu )}}$$

(8)

$$\lambda ={\displaystyle \frac{E\mu }{(1+\mu )(1-2\mu )}}$$

(9)

where σ is the total stress, Pa; ${\epsilon }^{\mathrm{el}}$ is the total elastic strain, dimensionless; $D^{\mathrm{el}}$ is the elastic tensor, Pa; λ is the Lame constant, Pa; G is the shear model, Pa; E is the elastic modulus, Pa; and μ is the initial Poisson’s ratio.

3.2.3. Fracture Propagation Equation

The fracture initiation simulation method in this article uses the extended finite element method (XFEM). The crack adopts a traction separation mode, and the initial damage and damage evolution of the element are linear elastic characteristics. The traction separation behavior can be described by Equation (10):

$$t_N=E{\epsilon }_{\mathrm{n}}$$

(10)

where t_N is the traction force, Pa; and ε_n is the separation displacement, m.

In the calculation of initiation pressure, the maximum nominal principal stress criterion (MAXS) is used as the fracture criterion:

$$f=\max \{{\displaystyle \frac{〈t_n〉}{t_n^0}},{\displaystyle \frac{t_s}{t_s^0}},{\displaystyle \frac{t_t}{t_t^0}}\}$$

(11)

where t_n is the normal stress on the possible crack surface, Pa; t_s and t_t are the tangential nominal stress on the crack surface, Pa; $t_n^0$, $t_s^0$, and $t_t^0$ are the maximum strength of rocks in three directions, Pa, among which $t_n^0$ is the tensile strength; <> is the Macaulay parentheses, which indicate that a pure compressive stress state will not cause damage. Equation (11) indicates that rock damage occurs when the stress ratio in one of the three directions reaches 1.

The damage scalar D_n represents the overall damage of the material. When the initial value of the damage scalar is 0, the rock undergoes damage. As the loading continues, D_n gradually evolves from 0 to 1. The stress component of traction separation is affected by the following damages:

$$t_{n1}=(1-D_n)\cdot \overline{t_{n1}}$$

(12)

where $\overline{t_{n1}}$ is the stress calculated according to the undamaged front elastic traction separation criterion under the current strain, and t_n1 is the actual stress borne.

In addition, the damage scalar D_n can be calculated using Equation (13):

$$D={\displaystyle \frac{d_m^f(d_m^{\max }-d_m^0)}{d_m^{\max }(d_m^f-d_m^0)}}$$

(13)

where $d_m^{\max }$ is the maximum displacement reached by the element during the loading process; $d_m^f$ is the displacement when the unit is completely destroyed; and $d_m^0$ is the displacement at the initial damage of the element.

3.2.4. Modified Area Equation

The fluid sweep area can be calculated as follows:

$$V_{\mathrm{in}}=S_{\mathrm{a}}\cdot L_{\mathrm{h}}\cdot \phi \cdot \left(1-S_{\mathrm{bw}}\right)$$

(14)

Among them, V_in is the volume of fluid injection, m³; S_a is the affected area of the fluid, m²; L_h is the length of the fracturing section, m; φ is the porosity of the reservoir, %; S_bw is the bound water saturation, %.

The above governing equations were implemented using the commercial software Abaqus 2020.

4. Verification

This article takes well Q7-H2 in the Gulong area of Daqing Oilfield in China as an example. The fracturing curve of the well is shown in Figure 9. The AB section of the well is in the CO₂ injection stage, and after point B, it involves smooth water fracturing. When the pressure reaches point C, a fracture occurs, and the fracturing pressure is 51.9 MPa. The numerical simulation parameters are all engineering parameters or are obtained from the experiments, and the specific parameters can be seen in

Table 2. Numerical simulation parameters.

Parameters	Value	Unit
Model size	50∗50	m
Reservoir temperature	110	°C
Vertical in situ stress	50	MPa
Minimum horizontal principal stress	45	MPa
Maximum horizontal principal stress	55	MPa
Porosity	4.3%	/
Formation pressure	25	MPa
Fracturing section length	50	M
Pre-CO2 injection pressure	40	MPa
Pre-CO2 injection time	30	min
Pre-CO2 injection volume	75	m3
Bound water saturation	0.18	/
Initial elastic modulus	21.63	GPa
Elastic modulus after CO2 action	18.93	GPa
Initial Poisson’s ratio	0.195	/
Poisson’s ratio after CO2 action	0.172	/
Initial tensile strength	6.18	MPa
Tensile strength after CO2 action	5.69	MPa
Initial permeability	0.87	mD
Permeability after CO2 action	2.43	mD
Smooth water fracturing flow rate	16	m3/min
CO2 viscosity	0.0001	Pa·s
Slippery water viscosity	0.001	Pa·s

.

Numerical simulation was conducted using the parameters in Table 2, and Figure 10 shows the simulation results.

Figure 10a shows the initial model mechanical parameters and permeability distribution, with the initial formation in a homogeneous state. Figure 10b shows the distribution of reservoir pore pressure after pre-injection of carbon dioxide. It can be observed that when carbon dioxide is injected into the reservoir, the reservoir pore pressure significantly increases, and pre-injection of carbon dioxide has the effect of supplementing reservoir energy. Figure 10c shows the distribution relationship of the elastic modulus, Poisson’s ratio, and tensile strength of the reservoir after injecting carbon dioxide. It can be observed from this figure that after the modification of the pre-CO₂-affected reservoir, the elastic modulus, Poisson’s ratio, and tensile strength near the wellbore have all decreased. The rock modification area is about 42.5 m², and the regional radius is about 3.7 m. Subsequent smooth water fracturing was carried out based on the mechanical parameters and pore pressure distribution at this time. Figure 10d shows the pore pressure distribution map of the fracturing transformation initiation frame. From this graph, it can be seen that the model initiation pressure is 55.9 MPa, while the actual engineering initiation pressure is 51.9 MPa, with a difference of only 4 MPa and an error of 7.7%. This can prove that the numerical simulation method for pre-CO₂ fracturing considering rock modification proposed in this article has high accuracy. If the effects of CO₂ on the physical properties of rock are not considered, the rock initiation pressure may be overestimated. This could lead to increased investment in fracturing equipment and result in unnecessary resource wastage.

It should be noted that both the experimental design and numerical simulation in this article are based on the fracturing wells in the Gulong area, but this method is not limited to the Gulong shale oil block. According to the method proposed in this article, the experimental and numerical simulation parameters can be reset according to the actual conditions of the target fracturing section, allowing us to calculate the initiation pressure of pre-CO₂ fracturing projects in different blocks.

5. Discussion

The most prominent feature of this method is that it repeatedly considers the phenomenon of rock modification under the action of carbon dioxide. In order to prove its necessity, this paper uses traditional methods to simulate the Gulong Q7-H2 well. Figure 11 shows the calculation results using traditional methods, where Figure 11a shows the distribution relationship of the reservoir’s elastic modulus, Poisson’s ratio, tensile strength, and permeability after injecting carbon dioxide. Due to the traditional method not considering rock modification, the mechanical properties of reservoir rocks remain consistent, all of which are mechanical parameters in a saturated oil state. The subsequent smooth water fracturing process was carried out based on the mechanical parameters and pore pressure distribution at this time. Figure 11b shows the pore pressure distribution map of the fracturing transformation initiation frame. From this graph, it can be seen that the model’s initiation pressure is 61 MPa, which differs from the actual initiation pressure by 9.1 MPa, with an error of 17.5%. In comparison, the initiation pressure calculated by using the method in this article is 9.8% smaller compared to using the traditional method, which further proves that in the pre-CO₂ fracturing simulation, the modification effect of carbon dioxide on reservoir rocks must be fully considered, and the calculation method proposed in this article can effectively improve prediction accuracy. This study has certain limitations. First, it assumes that the formation is homogeneous and isotropic, which may not accurately reflect real conditions. Additionally, thermal stress effects were not considered in this model. Future research will aim to address these aspects to enhance the model’s accuracy.

6. Conclusions

This article exemplifies the Gulong shale oil well Q7-H2 and puts forward a universally applicable method for calculating pre-CO₂ fracturing initiation pressure. The methodology encompasses CO₂-modified rock experiments and simulations of pre-CO₂ fracturing. Subsequent verification attests to the high accuracy of the proposed fracturing pressure calculation method. The research findings indicate the following:

(1)

After being treated with carbon dioxide in situ, the elastic modulus of reservoir shale decreased by 12.5%, Poisson’s ratio decreased by 11.8%, the tensile strength decreased by 7.9%, and the permeability increased by 180%.

(2)

Upon pre-CO₂ injection into the reservoir, there was a noteworthy increase in pore pressure within the near-wellbore region. This augmentation not only supplemented formation capacity but also induced modifications in the reservoir rocks near the wellbore area.

(3)

The accurate prediction of pre-CO₂ fracturing initiation pressure necessitates the consideration of CO₂’s influence on the modification of reservoir rock mechanical properties. In comparison with traditional numerical simulation methods, the approach proposed in this paper achieves a reduction in the predicted initiation pressure error of 9.8%.

(4)

This study provides guidance for the design of operational parameters in pre-injected CO₂ fracturing.