Study on the Risk of Reservoir Wellbore Collapse Throughout the Full Life Cycle of the Qianmiqiao Bridge Carbonate Rock Gas Storage Reservoir

Abstract

Underground gas storage (UGS) in heterogeneous carbonate reservoirs is crucial for energy security but frequently faces wellbore instability challenges, which traditional static methods struggle to address due to dynamic full life cycle changes. This study systematically analyzes the dynamic evolution of wellbore stress in the Bs8 well (Qianmiqiao carbonate UGS) during drilling, acidizing, and injection-production operations, establishing a quantitative risk assessment model based on the Mohr–Coulomb criterion. Results indicate a significantly higher wellbore instability risk during drilling and initial gas injection stages, primarily manifested as shear failure, with greater severity observed in deeper well sections (e.g., 4277 m) due to higher in situ stresses. During acidizing, while the wellbore acid column pressure can reduce principal stress differences, the process also significantly weakens rock strength (e.g., by approximately 30%), inherently increasing the risk of wellbore instability, though the primary collapse mode remains shallow shear breakout. In the injection-production phase, increasing formation pressure is identified as the dominant factor, shifting the collapse mode from initial shallow shear failure to predominant wide shear collapse, notably at 90°/270° from the maximum horizontal stress direction, thereby significantly expanding the unstable zone. This dynamic assessment method provides crucial theoretical support for full life cycle integrity management and optimizing safe operation strategies for carbonate gas storage wells.

1. Introduction

Wellbore instability is a pervasive and costly challenge in petroleum engineering, directly impacting drilling efficiency, production safety, and overall economic benefits [1]. Understanding the mechanical behavior of the rock surrounding the wellbore, particularly its stability, is paramount for ensuring the integrity of downhole operations [2]. With escalating global energy demands and the imperative for energy security, underground gas storage (UGS) facilities have emerged as a cornerstone for peak regulation and a stable natural gas supply [3]. These facilities are critical for maintaining energy balances and strategic reserves. Carbonate rock gas reservoirs, with their ultra-large storage capacity, excellent sealing properties, and deep burial characteristics, have become an important carrier for unconventional natural gas development. However, carbonate reservoirs generally exhibit strong non-homogeneity, complex stress fields, and susceptibility to disturbances from reservoir reconstruction activities, leading to frequent wellbore instability incidents. These incidents pose serious threats to the safe operation, economic benefits, and environmental safety of gas storage facilities [4]. Research indicates that wellbore instability not only can induce drilling hazards such as stuck drill pipe and leakage but also may cause damage to reservoir permeability and increase the risk of gas leakage. This has become a key bottleneck limiting the efficient development of deep carbonate rock gas reservoirs [5]. Given the inherent geological complexities of carbonate formations, such as dissolution vugs, natural fractures, and strong anisotropy, predicting and mitigating wellbore instability in these reservoirs presents unique challenges compared to more homogenous sandstone reservoirs [6,7].

Traditional wellbore stability evaluation systems are often based on static geological parameters for analysis. However, during the operation of gas storage facilities, geological parameters exhibit significant dynamic changes, making it challenging to accurately quantify collapse and fracture pressures based solely on static parameters. Notably, throughout the full life cycle of a gas storage well (including drilling, acid fracturing, and injection-production operations), the stress field around the wellbore displays significant dynamic evolution characteristics. This dynamic nature, coupled with the inherent complexities of carbonate reservoirs such as strong heterogeneity and complex stress fields, poses a unique challenge that traditional static methods cannot address. For example, in vuggy reservoirs, stress concentration zones tend to form at the boundaries of caves, potentially leading to shear or tensile failure. During the gas injection phase, the increase in pore pressure may cause the principal stress direction to reverse (with the minimum principal stress becoming the maximum principal stress), thereby altering the rock failure mode (from tensile failure to shear failure) [8]. This multi-stage coupled dynamic stress mechanism makes it difficult for traditional static evaluation methods to accurately predict wellbore integrity failure. Therefore, a dynamic approach that accounts for the evolving stress field and rock properties throughout the well’s operational life is essential for reliable stability assessment [9,10].

Based on the aforementioned issues, existing research primarily explores the problem from three directions: first, focusing on the evolution mechanism of the stress field to reveal the dynamic response of the stress field around the wellbore during injection-production cycles and its coupling effects with reservoir reconstruction [11,12,13]; second, in the field of uncertainty quantification, developing sensitivity analysis methods for geomechanical parameters based on probabilistic statistics [14,15]; and third, in the aspect of risk prediction model construction, proposing a four-dimensional dynamic stress field-driven framework for calculating wellbore failure thresholds [16,17]. While these studies have advanced our understanding, current literature still exhibits certain limitations when applied to the full life cycle management of carbonate rock gas storage wells. Specifically, there is a lack of a complete theoretical system for multi-stage coupling mechanisms, making systematic, full life cycle dynamic quantification of wellbore instability risks challenging. Furthermore, the nonlinear stress disturbance mechanism caused by reservoir reconstruction processes (such as acid fracturing) has not been fully considered in existing models, and the connection between parameter sensitivity analysis and field engineering practices is not yet tight enough, leading to certain barriers in translating theoretical achievements into engineering applications.

To overcome these limitations and provide a more robust and practically applicable solution, numerical simulation has emerged as a powerful and indispensable tool. Unlike analytical solutions, which often rely on highly simplified geological and operational assumptions, numerical methods can comprehensively account for complex wellbore geometries, heterogeneous rock properties, anisotropic stress fields, and the dynamic interaction between fluid flow and rock deformation over time. Experimental studies, while providing fundamental rock mechanical properties, often face challenges in replicating in situ stress conditions and large-scale reservoir complexities. Therefore, numerical simulation offers a cost-effective and flexible platform to model the dynamic evolution of wellbore stability throughout the full life cycle, from drilling to injection production, and to incorporate the effects of various operational activities [18,19].

Considering this, this study takes deep carbonate rock gas reservoirs as its research object and systematically reveals the dynamic characteristics of the stress field around the wellbore throughout the full life cycle. It establishes a wellbore instability risk quantification model for gas storage reservoirs based on the Mohr–Coulomb criterion, aiming to provide theoretical support and technical guidance for the safe and efficient development of deep carbonate rock gas reservoirs.

2. Quantitative Evaluation Method for Borehole Instability

2.1. Wellbore Stress Calculation Method

When the borehole is opened, the original stress balance of the formation is disrupted. Under the combined action of the original formation stress and the borehole fluid column pressure, the stresses around the borehole are redistributed. In a cylindrical coordinate system, the redistributed stresses around the borehole can also be represented by radial stress, tangential stress (also called circumferential or hoop stress), and axial stress. As shown in Figure 1, radial stress acts in all directions perpendicular to the borehole wall, tangential stress surrounds the borehole, and axial stress is parallel to the borehole axis. If this redistributed stress state exceeds the rock strength, the rock will fail.

Assuming the rocks around the borehole are small-deformation elastic media, and based on the principles of poroelasticity and rock mechanics, the stress states around the borehole under the separate actions of borehole fluid column pressure, horizontal formation stress, and overburden pressure are calculated. Then, by using the superposition principle, the expressions for the stress state of the rocks around the borehole in cylindrical coordinates are obtained.

(1)

The stress state around the wellbore under the sole action of wellbore column pressure $P_i$:

$$\begin{array}{l}{\sigma }_r={\displaystyle \frac{R^2}{r^2}}{P}_i\\ {\sigma }_{\theta }=-{\displaystyle \frac{R^2}{r^2}}{P}_i\end{array}$$

(1)

(2)

The stress state around the wellbore under the sole action of maximum horizontal in situ ${\sigma }_H$:

$$\begin{array}{l}{\sigma }_r={\displaystyle \frac{{\sigma }_H}{2}}\left(1-{\displaystyle \frac{R^2}{r^2}}\right)+{\displaystyle \frac{{\sigma }_H}{2}}\left(1+{\displaystyle \frac{3R^4}{r^4}}-{\displaystyle \frac{4R^2}{r^2}}\right)\cos 2\theta \\ {\sigma }_{\theta }={\displaystyle \frac{{\sigma }_H}{2}}\left(1+{\displaystyle \frac{R^2}{r^2}}\right)-{\displaystyle \frac{{\sigma }_H}{2}}\left(1+{\displaystyle \frac{3R^4}{r^4}}\right)\cos 2\theta \\ {\sigma }_{r\theta }={\displaystyle \frac{{\sigma }_H}{2}}\left(1-{\displaystyle \frac{3R^4}{r^4}}+{\displaystyle \frac{2R^2}{r^2}}\right)\sin 2\theta \end{array}$$

(2)

(3)

The stress state around the wellbore under the sole action of minimum horizontal in situ stress ${\sigma }_h$.

$$\begin{array}{l}{\sigma }_r={\displaystyle \frac{{\sigma }_h}{2}}\left(1-{\displaystyle \frac{R^2}{r^2}}\right)-{\displaystyle \frac{{\sigma }_h}{2}}\left(1+{\displaystyle \frac{3R^4}{r^4}}-{\displaystyle \frac{4R^2}{r^2}}\right)\cos 2\theta \\ {\sigma }_{\theta }={\displaystyle \frac{{\sigma }_h}{2}}\left(1+{\displaystyle \frac{R^2}{r^2}}\right)+{\displaystyle \frac{{\sigma }_h}{2}}\left(1+{\displaystyle \frac{3R^4}{r^4}}\right)\cos 2\theta \\ {\sigma }_{r\theta }=-{\displaystyle \frac{{\sigma }_h}{2}}\left(1-{\displaystyle \frac{3R^4}{r^4}}+{\displaystyle \frac{2R^2}{r^2}}\right)\sin 2\theta \end{array}$$

(3)

(4)

The stress state around the wellbore under the sole action of overburden pressure ${\sigma }_v$.

$${\sigma }_z={\sigma }_v-\mu \left[2\left({\sigma }_H-{\sigma }_h\right){\left({\displaystyle \frac{R}{r}}\right)}^2\cos 2\theta \right]$$

(4)

(5)

By performing superposition processing on the stress states around the wellbore under the sole actions of casing column pressure, horizontal in situ stress, and overburden pressure, we derive the expression for the stress state of the rock around the wellbore in vertical wellbore cylindrical coordinates, which is as follows:

$$\begin{array}{l}{\sigma }_r={\displaystyle \frac{R^2}{r^2}}{P}_w+{\displaystyle \frac{({\sigma }_H+{\sigma }_h)}{2}}(1-{\displaystyle \frac{R^2}{r^2}})+{\displaystyle \frac{({\sigma }_H-{\sigma }_h)}{2}}(1+{\displaystyle \frac{3R^4}{r^4}}-{\displaystyle \frac{4R^2}{r^2}})\cos 2\theta \\ {\sigma }_{\theta }=-{\displaystyle \frac{R^2}{r^2}}{P}_w+{\displaystyle \frac{({\sigma }_H+{\sigma }_h)}{2}}(1+{\displaystyle \frac{R^2}{r^2}})-{\displaystyle \frac{({\sigma }_H-{\sigma }_h)}{2}}(1+{\displaystyle \frac{3R^4}{r^4}})\cos 2\theta \\ {\sigma }_z={\sigma }_v-\nu [2({\sigma }_H-{\sigma }_h){({\displaystyle \frac{R}{r}})}^2\cos 2\theta ]\end{array}$$

(5)

where, ${\sigma }_r,{\sigma }_{\theta },{\sigma }_z$ represents the stress components of the rock around the wellbore in vertical wellbore cylindrical coordinates, MPa; ${\sigma }_H$ and ${\sigma }_{\mathrm{h}}$ are the maximum and minimum horizontal in situ stresses, respectively, MPa; ${\sigma }_v$ is the overburden pressure, MPa; $P_w$ is the mud column pressure, MPa; $R$ is the wellbore radius, m; $r$ is the distance from any point in the formation to the wellbore center, m; $\theta$ is the angular coordinate around the wellbore, °; $\nu$ is Poisson’s ratio.

2.2. Wellbore Instability Discriminant Criteria

The selection of strength criteria plays a crucial role in the calculation of wellbore collapse pressure. The most used strength criteria include: Mohr–Coulomb criterion, Drucker–Prager criterion, and Hoek–Brown criterion. Practice has shown that for relatively hard rocks, the results calculated using the Mohr–Coulomb criterion are more reliable; therefore, the Mohr–Coulomb criterion is adopted in this study, which is:

$${\sigma }_1={\sigma }_3{\cot }^2\left(45-{\displaystyle \frac{\varphi }{2}}\right)+2C_{\mathrm{o}}\cot \left(45-{\displaystyle \frac{\varphi }{2}}\right)$$

(6)

where, ${\sigma }_1$ and ${\sigma }_3$ represent the maximum and minimum horizontal stresses, respectively, measured in MPa; $C_{\mathrm{o}}$ represents the cohesion, measured in MPa; and $\varphi$ represents the friction angle, °.

The Mohr–Coulomb criterion indicates that shear failure in rock primarily depends on the stress state it is subjected to. The greater the difference between the maximum and minimum principal stresses (Δσ = σ_max − σ_min), the higher the likelihood of wellbore collapse. Therefore, clarifying the maximum and minimum stress differences in carbonate reservoir gas storage wells at different stages is a prerequisite for analyzing wellbore instability.

2.3. Wellbore Collapse Mechanisms

For vertical wellbores, Figure 2 illustrates six wellbore rock shear failure modes: including shear failure with wide collapse (i.e., ϭ_ѳ > ϭ_z > ϭ_r), shear failure with shallow collapse (i.e., ϭ_z > ϭ_ѳ > ϭ_r), shear failure with high-angle stepwise collapse (i.e., ϭz > ϭr > ϭѳ), shear failure with narrow collapse (i.e., ϭ_r > ϭ_z > ϭ_ѳ), shear failure with low-angle stepwise collapse (i.e., ϭ_ѳ > ϭ_r > ϭ_z), and shear failure with deep collapse (i.e., ϭ_r > ϭ_ѳ > ϭ_z). These modes, with their specific numbering, are consistent with the classification presented in the original source [20]. These six modes correspond to different stress states and provide a theoretical foundation for wellbore instability risk analysis.

2.4. Coefficient of Wellbore Collapse

It is assumed that the formation is a homogeneous, isotropic, linear elastic porous medium, and the surrounding rock of the wellbore is in a plane-strain state. The surrounding rock of the wellbore is comprehensively affected by the drilling fluid column pressure pi, overburden in situ stress, maximum horizontal in situ stress, and minimum horizontal in situ stress (the three principal stresses are σ₁, σ₂, σ₃). The mechanical model is shown in Figure 3.

There are two basic forms of borehole instability: compressive-shear failure and tensile failure. In engineering, the Mohr–Coulomb strength criterion and the maximum tensile stress strength criterion are generally used to evaluate the compressive-shear failure and tensile failure of the wellbore. The wellbore stability coefficient is used to evaluate the stability of the wellbore. The strength of the surrounding rock of the wellbore and the stress state of the surrounding rock are regarded as fixed values, and they are functions of the stress state of the surrounding rock of the wellbore and rock mechanical parameters. For the evaluation of wellbore stability, considering the errors that may be caused by the uncertainty of the calculation model and parameters, the wellbore stability coefficient and the strength–stress difference are introduced for processing. According to the Mohr–Coulomb criterion and the maximum tensile stress theory, the calculation criterion for wellbore collapse is:

$$K={\displaystyle \frac{\left({\sigma }_1-{\sigma }_3\right)-\sin \left(\phi \right)\left({\sigma }_1+{\sigma }_3\right)}{2C\cos \left(\phi \right)}}$$

(7)

where K is the wellbore stability coefficient; σ_max and σ_min are the maximum and minimum principal in situ stresses, respectively, in MPa; C is the rock cohesion, in MPa; and φ is the rock internal friction angle, in (°).

When K > 1, it indicates that the surrounding rock of the wellbore undergoes shear failure and the wellbore collapses; when K = 1, the surrounding rock of the wellbore is in a limit-stable state; when K < 1, the surrounding rock of the wellbore is stable.

3. Borehole Collapse Risks During the Entire Life Cycle of Qianmiqiao Gas Storage

Based on the above-mentioned research methods, this study takes Well Bs8 in Qianmiqiao Gas Storage as the research object and systematically studies the evolution characteristics of the stress field around the wellbore and the borehole collapse mode during its entire life cycle. The Banshen 8 Block is in the main buried-hill structural belt of Qianmiqiao. Its main pay zones are the Shangmajiaogou Formation and the Fengfeng Formation. The reservoir lithology of the Shangmajiaogou Formation is mainly dolomitic limestone and calcareous dolomite, with typical carbonate rock reservoir characteristics.

Table 1. Rock mechanical parameters of the reservoir in Well Bs8.

Well Section (m)	Compressive Strength (MPa)	Cohesion (MPa)	Internal Friction Angle (°)	Formation Pressure (MPa)	Poisson’s Ratio	Maximum Horizontal In Situ Stress (MPa)	Minimum Horizontal In Situ Stress (MPa)	Vertical In Situ Stress (MPa)
4277	77.20	2.24	18.84	1.00	0.20	77.12	67.90	100.60
4277 (Acidized)	54.04	1.57	13.19	1.00	0.20	77.12	67.90	100.60

lists in detail the rock mechanical parameters of Well Bs8 under the original reservoir conditions.

3.1. Research on the Characteristics of Stress Changes Around the Wellbore in Qianmiqiao Gas Storage

3.1.1. Characteristics of Stress Changes Around the Wellbore During the Drilling Stage

The Qianmiqiao carbonate rock gas storage is an underground gas storage converted from a depleted condensate gas reservoir. After decades of continuous exploitation, the reservoir pressure system has changed significantly. The current formation pressure coefficient has dropped to 0.4, belonging to a typical low-pressure reservoir system. To minimize the damage caused by the invasion of drilling fluid into the reservoir, a low-density drilling fluid system with a density of 1.0 g/cm³ was used in the drilling engineering design. Based on the theoretical model of the stress field around the wellbore, this study focused on numerically simulating and analyzing the stress distribution characteristics around the wellbore. Figure 4 specifically illustrates the stress distributions under these initial low formation pressure conditions (pore pressure coefficient of 0.4).

As shown in Figure 4, the distribution characteristics of the stress around the wellbore during the drilling stage are mainly affected by formation depth and the in situ stress field. At 4277 m, due to the relatively shallow formation depth and the relatively low in situ stress field, the magnitude relationship of the stress around the wellbore is always σz > σθ > σr, indicating that vertical stress is the maximum principal stress, tangential stress is the intermediate principal stress, and radial stress is the minimum principal stress. This stress state is conducive to the stability of the wellbore because the increase in vertical stress can effectively inhibit the shear failure of the wellbore.

3.1.2. Characteristics of Stress Changes Around the Wellbore During the Acid-Treatment Process

To improve the injection-production capacity of the carbonate rock reservoir in the Qianmiqiao Block, after the drilling operation was completed, a composite acid solution with a density of 1.14 g/cm³ was used to acidize the reservoir. Laboratory experimental studies show that the action of acid can reduce the strength of carbonate rock in the reservoir by about 30%. According to the Mohr–Coulomb criterion, the change in rock strength is closely related to the stress around the wellbore. Specifically, acidizing reduces the rock’s cohesion and internal friction angle. For instance, based on experimental data, post-acidizing cohesion might decrease from 2.24 MPa to approximately 1.57 MPa, and the internal friction angle might see a reduction from 18.84° to around 13.19°, significantly impacting the rock’s shear resistance.

Figure 5 illustrates the characteristics of stress distribution around the wellbore at a depth of 4277 m under the action of acid. This figure also reflects the stress state influenced by an initial low formation pressure (coefficient 0.4) during the acid treatment operation. As shown in Figure 5, the stress distribution around the wellbore during the acidization stage is largely consistent with that observed during the drilling stage, although the principal stress difference decreases. Specifically, at 4277 m, following acid treatment, the magnitude relationship of the principal stresses around the wellbore remains σ_z > σ_θ > σ_r, but the maximum principal stress difference is reduced.

However, this reduction in stress difference does not necessarily imply a reduced risk of wellbore instability. This is primarily due to the wellbore fluid injection pressure applied during acidizing. Crucially, acidizing often leads to a significant decrease in rock strength (e.g., reduced cohesion and friction angle), which can inherently increase the risk of wellbore instability. Therefore, the actual wellbore stability during and after acidizing will ultimately depend on the dynamic changes in wellbore pressure throughout the injection and subsequent production operations, balancing the altered stress state with the weakened rock properties.

3.1.3. Characteristics of Stress Changes Around the Wellbore During the Injection-Production Process

The designed operating pressure of Qianmiqiao Gas Storage is 18.0–34.0 MPa, and the designed storage capacity is 107.0 × 10⁸ m³. After 7 injection-production cycles, the gas storage has been operating stably overall. The injection-production gas volume has gradually increased, and the formation pressure has steadily increased.

Figure 6 shows the characteristics of stress changes around the wellbore at the wellbore wall at well depths of 4277 m during the injection-production process, respectively. It can be seen from Figure 4 that the distribution characteristics of the stress around the wellbore during the injection-production stage have changed significantly. With the increase in formation pressure, circumferential stress gradually increases, axial stress and radial stress gradually decrease, and the magnitude relationship of the stress around the wellbore changes from σ_z > σ_θ > σ_r to σ_θ > σ_z > σ_r. This change in stress state indicates that the change in formation pressure during the injection-production process has a significant impact on the stress field around the wellbore. At 4277 m, with the increase in formation pressure, circumferential stress gradually becomes the maximum principal stress, vertical stress becomes the intermediate principal stress, and radial stress becomes the minimum principal stress. This change in the stress state may lead to differences in the stability of the wellbore in different directions. It is necessary to further analyze the wellbore collapse mode to determine the specific instability risk. The trends observed in Figure 6 illustrate this dynamic shift as pore pressure rises from the initial depleted state to higher operational pressures.

3.2. Research on the Borehole Collapse Mode of Qianmiqiao Gas Storage

The change in stress around the wellbore can only reflect the stress characteristics at the wellbore wall and is used to preliminarily judge the collapse risk at the wellbore wall. To reflect the collapse risk more comprehensively in a certain area around the wellbore, this study further constructed a collapse mode within a certain range around the wellbore, clarifying the possible collapse range around the wellbore and the shape of the wellbore after collapse at different stages.

3.2.1. Borehole Collapse Mode During the Drilling Stage

Figure 7 are the borehole collapse mode diagrams of the Qianmiqiao carbonate rock reservoir at well depths of 4277 m before the acid treatment at different times, respectively. It can be seen from Figure 5 that the borehole collapse mode during the drilling stage is mainly affected by the stress state around the wellbore. At 4277 m, the original borehole collapse mode includes wide breakout of shear failure and shallow breakout of shear failure, indicating that the stability of the wellbore varies greatly in different directions. In the range within 1.2 R from the wellbore wall at the wellbore angles of 90° and 270°, due to the large difference between circumferential stress and radial stress, wide breakout of shear failure mainly occurs. This collapse mode has a large collapse range and may lead to relatively serious wellbore instability. In the 90° and 270° directions of the wellbore, due to the large difference between vertical stress and radial stress, shallow breakout of shear failure mainly occurs. This collapse mode has a relatively small collapse range, but its impact on the stability of the wellbore still needs to be paid attention to. In the current state, the borehole collapse mode is only a shallow breakout of shear failure, indicating that the stability of the wellbore has improved, but measures still need to be taken to prevent wellbore instability.

3.2.2. Borehole Collapse Mode During the Acidization Stage

Figure 8 shows the borehole collapse mode diagrams of the Qianmiqiao carbonate rock reservoir at well depths of 4277 m during the acid-treatment process, respectively. It can be seen from Figure 6 that the borehole collapse mode during the acidization stage is mainly a shallow breakout of shear failure, indicating that the stability difference of the wellbore in different directions is small. At 4277 m, the borehole collapse mode during the acid-treatment process is the same as that in the current state, but the collapse risk is reduced, indicating that acidization effectively improves the stability of the wellbore.

3.2.3. Borehole Collapse Mode During the Injection-Production Stage

Figure 9 shows the borehole collapse mode diagrams of the Qianmiqiao carbonate rock reservoir at well depths of 4277 m during the injection-production process, respectively. It can be seen from Figure 7 that the borehole collapse mode during the injection-production stage is mainly affected by the change in formation pressure. At 4277 m, with the increase in formation pressure, the borehole collapse mode is mainly dominated by wide breakout of shear failure, indicating that the stability difference of the wellbore in different directions is large. In the areas closer to the wellbore wall at the wellbore angles of 90° and 270°, due to the large difference between circumferential stress and radial stress, wide breakout of shear failure mainly occurs. This collapse mode has a large collapse range and may lead to serious wellbore instability. In the 0° and 180° directions of the wellbore, due to the large difference between vertical stress and radial stress, shallow breakout of shear failure mainly occurs. This collapse mode has a relatively small collapse range, but its impact on wellbore stability still needs to be paid attention to.

4. Discussion

The systematic analysis of wellbore stability across the full life cycle of the Qianmiqiao Gas Storage reservoir reveals that dynamic changes in stress fields and rock mechanical properties significantly influence wellbore integrity. Traditional static methods, while foundational, are insufficient for accurately predicting and managing borehole instability in such dynamic environments. The findings highlight the critical importance of continuously monitoring formation pressure and updating geomechanical models to reflect actual operational conditions.

Our study demonstrates that both drilling operations in depleted reservoirs and gas injection phases pose considerable risks due to altered stress states and increased loads on the wellbore. The observed shift in collapse modes from shallow to wide breakouts during injection production signifies a profound change in the failure mechanism, demanding a flexible and adaptive approach to wellbore design and intervention strategies. Furthermore, the beneficial impact of acidizing, primarily through its effect on rock strength, underscores the importance of considering reservoir stimulation treatments in wellbore stability assessments.

While this study provides a robust framework for dynamic risk assessment, it is acknowledged that direct experimental validation of rock mechanical property changes under dynamic stress and acid exposure, as well as comprehensive comparative studies with alternative wellbore stability models, would further strengthen the findings. Future work will focus on integrating more advanced constitutive models for rock behavior and incorporating uncertainty quantification methods to enhance predictive accuracy and decision-making in real-world scenarios.

5. Conclusions

This study takes Well Bs8 in the Qianmiqiao carbonate rock gas storage as a case, constructs a quantitative model for dynamic borehole instability risk during the entire life cycle of the gas storage based on the Mohr–Coulomb criterion, and systematically reveals the dynamic evolution laws of the stress field around the wellbore and the borehole collapse modes during key stages such as drilling, acidization, and injection-production operations. The research confirms:

(1)

The stress field of the wellbore in carbonate rock gas storage shows significant dynamic evolution characteristics throughout its full life cycle, highlighting the inadequacy of traditional static evaluation methods. Specifically, stress states at 4277 m depth showed complex shifts, with deep well sections exhibiting greater susceptibility to stress changes.

(2)

During the drilling and initial gas injection stages, the wellbore predominantly exhibits shear-failure-induced collapse, with higher instability risk and severity observed in deeper well sections (e.g., 4277 m). Acidizing, while maintaining the same primary collapse mode (shallow breakout shear failure), effectively reduced overall collapse risk by decreasing the maximum–minimum stress difference and weakening rock strength.

(3)

The dynamic change of formation pressure is the dominant factor in the evolution of the borehole collapse mode during the injection-production stage. Specifically, as formation pressure increased from initial depletion levels, the collapse mode at 4277 m depth transformed from predominantly shallow breakout shear failure to wide breakout shear failure, significantly expanding the affected area and indicating a greater challenge to wellbore integrity.