Numerical Study on the Influence of Saltwater Seepage in High-Pressure Salt-Gypsum Layers on Wellbore Integrity

Abstract

The salt layer serves as an excellent caprock for oil and gas resources, with its underlying strata often containing abundant hydrocarbon reserves. However, the strong creep characteristics of the salt layer frequently lead to damage issues. Therefore, research on the wellbore integrity of salt layers holds significant practical value. This study focuses on the wellbore integrity of high-pressure salt layers. Based on the Heard time-hardening creep model, a numerical simulation model of composite salt-layered wellbores incorporating a saline water seepage field was established. This study analyzed the mechanical influence of factors such as well inclination angle, azimuth angle, brine density, and liquid column density on the wellbore. The results indicate that high formation pressure, salt creep, and saline water seepage in high-pressure salt layers are the main causes of wellbore stress and deformation. These conditions pose a high risk of damage to the casing and cement sheath. When designing directional well trajectories within high-pressure salt layers, the inclination angle should be controlled between 45° and 60°, and the azimuth angle should be kept below 30°.

1. Introduction

Salt formations serve as excellent caprocks for oil and gas resources. Significant hydrocarbon reserves have been discovered beneath salt formations in regions such as the Sichuan Basin and Tarim Basin in China, the Gulf of Mexico in the United States, and the Amu Darya Basin in Turkmenistan. However, the plastic flow of salt formations often exacerbates casing damage. This issue is particularly pronounced in high-pressure salt formations, where drilling design faces significant challenges such as high formation pressure, high-density fluids, and poor cementing quality. These challenges pose new difficulties for wellbore integrity research.

Many experts and scholars, both domestically and internationally, have conducted research on salt formation creep and wellbore mechanics. Wu Fei [1] and colleagues utilized the Abel dashpot model and fractional derivatives to establish a salt creep model with strain triggering. By comparing it with the Nishihara model, they demonstrated that this model achieved higher calculation accuracy. Wang Baojun [2] conducted uniaxial creep experiments under different axial pressures to study the creep characteristics of salt rock. Using the inverse function of an S-shaped curve, they developed a new model for simulating uniaxial creep in salt rock. Yi Haiyang [3] analyzed the fitting performance of the Bailey–Norton model, Nishihara model, Burgers model, and fractional derivative model on creep rates through experiments. He found that fractional creep can better describe the changes in mechanical properties caused by creep damage of salt rock. Wu [4] developed a salt creep model based on fractional derivative theory, while Wang [5] performed uniaxial compression creep and unloading rebound experiments on salt rock samples under different axial stresses. The test results indicate that the instantaneous strain generated by salt rock mainly contributes by unrecoverable instantaneous plastic strain under a higher axial stress, and the creep strain mainly consists of unrecoverable visco-plastic creep strain. Kou Yongqiang [6] attributed casing damage in the Shengli Oilfield to the combined effects of fluid–solid coupling and casing corrosion during water injection and production processes. Using the finite element method, he quantitatively analyzed the influence of geological faults, reservoir lithology, and oilfield development on casing stress and strain patterns. Yang Dan [7] addressed wellbore stress issues under gas injection conditions and developed a thermodynamic model for wellbores based on elastoplastic and thermodynamic theories. He also proposed an improved method for addressing cement sheath bonding failure in casings. Liu Kui [8] and colleagues derived stress and thermal stress distributions for casings, cement sheaths, and formation points during hydraulic fracturing using solutions from elastic force complex functions and elasticity-based thermal stress analysis. Yin Fei [9] established a finite element model for directional wells under salt formations, investigating the impact of salt creep on wellbore mechanics during drilling, cementing, completion, and production processes. It is concluded that the numerical simulation method of directional wellbore evolution in creep strata can predict the mechanical behavior of wellbore over the whole life cycle. Marcelo [10], considering various steps in construction and production, proposed a new stress analysis approach for wellbores. Shi [11], emphasizing the importance of the initial loading state, proposed a new mechanical model for vertical wellbores under isotropic horizontal in situ stress. Wu Zhiqiang [12] addressed the limitation of traditional cementing quality evaluation methods in assessing the hydraulic sealing integrity of the casing–cement interface. He proposed combining localized differential detection techniques with cement defect detection methods. Gao Deli [13] attributed shale gas wellbore integrity failures to cement sheath sealing issues during cementing and casing deformation during fracturing. He proposed solutions such as optimizing the mud system for shale gas reservoirs, using mechanical seals locally in wellbore annuli, and employing volume fracturing techniques. Dou Yihua [14] categorized horizontal well cement sheath deficiencies into primary and secondary interface failures. Finite element analysis showed that primary interface failure in the cement sheath is the main cause of casing stress damage. Wang Hao [15], investigating casing damage in the Nanpu Oilfield through statistical analysis, concluded that non-uniform in situ stress, mudstone creep, and formation sand production are the primary causes of casing damage in the oilfield. Lin Hun [16] and colleagues used numerical simulation methods to study the effects of temperature–pressure coupling, formation slippage, and volume fracturing on casing stress in deep shale gas formations. It was found that under the action of temperature–pressure coupling, the maximum equivalent stress of the casing is significantly increased, and it is easy to yield and deform at the fault surface. He [17] proposed a coupled analysis method for the fatigue failure of cement sheaths and salt rock creep, demonstrating its applicability through mechanical experiments. Valov [18] developed a fully coupled linear thermo-poroelastic model to describe the mechanical compression of casings caused by fluid pressure and non-uniform in situ stress, as well as the heating or cooling of casings relative to the reservoir temperature. Andreas [19] applied a consolidated stress distribution model to the stress evolution of well MC252-1 in the deepwater Gulf of Mexico. During the blowout process, the mechanisms of casing failure (collapse/fracture and tensile/compressive deformation), cement sheath failure (internal or external interface separation), and rock formation failure remained stable. However, after cement solidification, when the system reached radial stress and displacement continuity, the cement sheath exhibited a tendency for radial cracking and disk-like (tensile) failure. Yang [20] developed an unsteady-state creep model capable of describing the creep and stabilization phases of salt rock. Zhou [21] proposed a new creep constitutive model based on time fractional derivatives and conducted creep experiments on salt rock. Yang Chunhe [22] analyzed the damage characteristics of salt rock during creep based on salt rock creep compression tests and rock creep damage mechanics models. Using thermodynamic principles, they derived the functional relationship between the salt rock creep damage factor and creep rate and established a constitutive relationship to simulate the entire creep process of salt rock. J. Ślizowski [23] conducted creep experiments on brown mudstone containing 20–30% salt. It was found that the content of insoluble parts has no significant rheological influence. Wang [24] proposed a new creep damage constitutive model for salt rock, which accurately reflects creep failure behavior under high stress and effectively describes primary and static creep under low stress. Liu Jiang [25] analyzed the effects of different pressure and temperature conditions on salt rock, calculated creep characteristic parameters using elastoplastic theory, and established a steady-state creep constitutive model for salt rock. Ren Song [26] proposed a salt rock creep similarity model based on dimensional analysis and conducted creep tests on salt rock at a depth of 1000 m. The study obtained mechanical parameters for salt rock and developed similar materials based on industrial material ratios, performing uniaxial and triaxial tests to explore the effects of different cement-sand ratios on the creep characteristics of the materials. Zhang Huabin [27] conducted staged triaxial compression tests on argillaceous salt rock and developed an improved Burgers constitutive model. Dou Jintao [28], while establishing an integral creep constitutive equation, introduced an integral operator and used inversion methods to solve the viscoelastic solution for wellbore displacement. Combining model identification theory, the creep behavior of formations under in situ stress and drilling fluid pressure was predicted. Tao He [17] established a three-dimensional numerical model incorporating the wellbore, open hole section (cavity neck), and bedded salt cavern by coupling the fatigue damage of the cement sheath with the creep analysis of rock salt. They investigated the wellbore integrity of bedded salt gas storage caverns. The results indicate that the creep capacity of bedded salt rock is lower than that of high-purity rock salt, which reduces the cavern shrinkage rate and thereby preserves the gas tightness of the wellbore.

A summary of previous research reveals that studies on the impact of abnormal high-pressure brine layers, formed by the long-term dehydration of gypsum within high-pressure salt formations, on wellbore integrity are currently lacking. Therefore, this paper takes Iraq’s M oilfield as a case study and employs numerical simulation methods to investigate the effects of high-pressure salt brine seepage on wellbore integrity. The study develops an analysis method specifically tailored for wellbore integrity in high-pressure salt formations, providing technical guidance for the design of drilling and completion operations, as well as for production development in oilfields.

2. Governing Equations

2.1. Creep Constitutive Equation

Rock creep refers to the characteristic of rock where the strain increases over time under constant stress. Numerous creep experiments have shown that under constant temperature conditions, rock creep typically undergoes three stages: instantaneous creep (segment ab), steady-state creep (segment bc), and accelerated creep (segment cd), as shown in Figure 1.

For salt rock materials, the creep process primarily occurs during the instantaneous creep and steady-state creep stages. After drilling through salt rock formations, stress concentration appears around the wellbore, causing the salt rock to enter the instantaneous creep stage. Following casing and cementing, the salt rock transitions into the steady-state creep stage, which persists for a long period. Extensive engineering practices have demonstrated that the Heard model and Weertman model can accurately describe the creep behavior of salt-gypsum layers [29]. The Heard model, which is based on the dislocation glide mechanism, is applicable to salt layers under high stress and low temperature. In contrast, the Weertman model, based on the dislocation climb mechanism, is suitable for salt layers under high temperature and low stress. In the M oilfield in Iraq, the salt formations exhibit high-pressure and low temperature. Therefore, the creep characteristics of salt rock in this field can be represented using the Heard model, with its constitutive equation expressed as follows:

$$\dot{\overline{\epsilon }}=A\exp (-{\displaystyle \frac{Q}{R\tau }})\sinh (B\sigma )$$

(1)

where $\dot{\overline{\epsilon }}$ is the steady-state creep rate, 1/h; $Q$ is the activation energy of salt rock, cal/mol; $R$ is the molar gas constant, 1.987 cal/mol∙K; $\tau$ is the deviatoric stress of $\sigma$; and $A$ and $B$ are rheological constants.

The incremental method can be used to apply the Heard model in the finite element model. The Heard model is a thermoelastic creep model that assumes the creep phase includes only two stages: initial creep and steady-state creep. The material temperature remains constant, and the non-elastic strain consists solely of creep strain, excluding plastic strain.

The expression for the total strain increment $\left\{\mathrm{\Delta }e\right\}$ is as follows:

$$\left\{\mathrm{\Delta }e\right\}=\left\{\mathrm{\Delta }{e}^e\right\}+\left\{\mathrm{\Delta }{e}^c\right\}$$

(2)

where $\left\{\mathrm{\Delta }{e}^e\right\}$ is the elastic strain increment, and $\left\{\mathrm{\Delta }{e}^{\mathrm{c}}\right\}$ is the creep strain increment.

The stress increment expression is as follows:

$$\left\{\mathrm{\Delta }\sigma \right\}=\left[\begin{array}{c}{D}_e\end{array}\right]\left\{\mathrm{\Delta }e\right\}-\left[\begin{array}{c}{D}_e\end{array}\right]\left\{e_0\right\}$$

(3)

where $\left[D_e\right]$ is the elastic stiffness matrix, and $\left\{\mathrm{\Delta }{e}_0\right\}$ is the initial strain.

$$\left\{e_0\right\}=\left\{\mathrm{\Delta }{e}^{\mathfrak{c}}\right\}$$

(4)

The expression for the creep strain increment $\left\{\mathrm{\Delta }{e}^{\mathrm{c}}\right\}$ is as follows:

$$\left\{\mathrm{\Delta }{e}^{\mathfrak{c}}\right\}=\gamma s\mathrm{\Delta }t$$

(5)

where $\gamma$ is the creep coefficient, and $s$ is the deviatoric stress.

$$\gamma ={\displaystyle \frac{3\dot{\overline{\epsilon }}}{2\sigma }}$$

(6)

Based on the principle of virtual work, the finite element equation can be derived from Equation (3) as follows:

$$[K]\left\{\mathrm{\Delta }u\right\}=\left\{\mathrm{\Delta }R\right\}+\left\{\begin{array}{c}\mathrm{\Delta }{P}_0\end{array}\right\}$$

(7)

where $\left[K\right]$ is the elastic stiffness matrix, $\left\{\mathrm{\Delta }u\right\}$ is the displacement increment, $\left\{\mathrm{\Delta }R\right\}$ includes the external load increment and unbalanced force, and $\left\{\begin{array}{c}\mathrm{\Delta }{P}_0\end{array}\right\}$ is the initial stress increment.

2.2. Casing Yield Failure Criterion

Under the creep effect of salt rock, the casing is subjected to uneven external compressive loads. This reduces the collapse strength of the casing, making it prone to yield failure. Aasen [30] and Yang Henglin [31] suggested that the von Mises yield criterion is suitable for evaluating casing failure under non-uniform loads. The expression is as follows:

$${\sigma }_e=\sqrt{{\displaystyle \frac{1}{2}}\left[{\left({\sigma }_1-{\sigma }_2\right)}^2+{\left({\sigma }_2-{\sigma }_3\right)}^2+{\left({\sigma }_3-{\sigma }_1\right)}^2\right]}$$

(8)

where ${\sigma }_1$, ${\sigma }_2$, ${\sigma }_3$ are the three principal stresses, and ${\sigma }_e$ is the equivalent stress of the casing under triaxial stress conditions.

2.3. Fluid Seepage Equation in Porous Media

According to fluid mechanics theory, fluid seepage in porous media follows Darcy’s law [32]. The rate of change in fluid mass within the formation rock over time is expressed as follows:

$$\frac{d}{dt}\underset{V}{{\displaystyle \int }}{\rho }_w{n}_{w}dV$$

(9)

The fluid mass entering through the surface of the rock per unit time is expressed as follows:

$$-\underset{S}{{\displaystyle \int }}{\rho }_w{n}_w{n}^T\cdot v_{w}dS$$

(10)

where $v_w$ is the seepage velocity, $n_w$ is the porosity of the rock, ${\rho }_w$ is the fluid density, and $n^T$ is the outward normal to the rock surface.

According to the law of mass conservation:

$$\frac{d}{dt}\underset{V}{{\displaystyle \int }}{\rho }_w{n}_{w}dV=-\underset{S}{{\displaystyle \int }}{\rho }_w{n}_w{n}^T\cdot v_{w}dS$$

(11)

Based on Darcy’s law, the differential equation can be expressed as

$$\begin{array}{c}{s}_w\left(m^T-m^T{\displaystyle \frac{D_{ep}}{3K_S}}\right){\displaystyle \frac{d\epsilon }{dt}}-{𝛻}^T\left[k\left({\displaystyle \frac{𝛻p_w}{{\rho }_w}}-g\right)\right]+\\ \left\{\xi n_w+n_w{\displaystyle \frac{s_w}{K_w}}+s_w\left[{\displaystyle \frac{1-n_w}{3K_S}}-{\displaystyle \frac{m^T{D}_{ep}m}{{(3K_S)}^2}}\right](s_w+\xi p_w)\right\}{\displaystyle \frac{d{p}_W}{dt}}=0\end{array}$$

(12)

where $K_w$ is the bulk modulus of the fluid.

The solution method for the fluid–solid coupled seepage model involves explicit iterative solving. The seepage field is computed using the finite difference method, while the geotechnical deformation field is solved using the finite element method. The calculated permeability and porosity are reintroduced into the seepage field, and the process is iterated repeatedly until the fluid–solid coupled deformation field is obtained.

3. Model Development

3.1. Basic Assumptions

To simplify the model and improve computational efficiency, the following assumptions are made:

(1) The formation, cement sheath, and casing are all isotropic, homogeneous, and continuous materials.

(2) The interfaces between the formation, cement sheath, and casing are perfectly bonded, with no relative sliding.

(3) The casing is free of internal defects and, like the cement sheath, is considered an ideal cylinder with uniform thickness, concentric, and coaxial with the wellbore.

3.2. Physical Model

As shown in Figure 2, a three-dimensional mechanical model and finite element model of the casing-cement sheath-formation system are established. Within the salt-gypsum layer, the long-term dehydration of gypsum forms an abnormally high-pressure brine interlayer, which macroscopically alters the distribution of in situ stress. Therefore, the finite element model is divided into three parts: the top and bottom layers are gypsum layers, and the middle interlayer consists of sandstone and salt rock formations.

3.3. Boundary Conditions

The entire formation is subjected to three principal in situ stresses acting in different directions. The stresses applied to the model boundaries are uniformly distributed over the boundary surfaces. Vertical stress is applied to the top surface of the model, while the minimum and maximum horizontal stresses are applied to the side surfaces. The casing and cement sheath at the top are subjected to axial compressive stress caused by the weight of the overlying material, calculated based on the densities of the cement and casing as well as the relevant depth. The bottom of the formation, cement sheath, and casing is fixed, with no displacement in the vertical direction. It is assumed that the sandstone acts as a migration pathway for brine. Under initial conditions, the sandstone is fluid-free, meaning the pore pressure is zero. The sandstone boundary is subjected to a pore pressure of 52.7 MPa, and all contact surfaces between the sandstone and other materials are considered impermeable boundaries.

3.4. Model Parameters

The casing material is P110, and general contact is applied throughout the model. Normal contact is set as rigid contact, with a friction coefficient of 0.1. The fluid column pressure on the inner surface of the casing is 41.256 MPa (fluid density: 1500 kg/m³).

Table 1. Basic parameters of salt rock creep.

${\mathit{\sigma }}_{\mathit{H}}$ (MPa)	${\mathit{\sigma }}_{\mathit{h}}$ (MPa)	${\mathit{\sigma }}_{\mathit{v}}$ (MPa)	A	B	Q (cal/mol)
70.26	60.48	62.53	41.256	0.621	11,035

lists the in situ stress and salt rock creep parameters,

Table 2. Material parameters.

	Elastic Modulus (MPa)	Poisson’s Ratio	Friction Angle (°)	Density (kg/m3)	Outer Diameter (mm)	Inner Diameter (mm)
Salt Rock	5000	0.35	24	2280	5000	155.5
Sandstone	19,300	0.25	20	2170	5000	155.5

provides the material parameters, and

Table 3. Fluid mechanics parameters.

Fluid Density (kg/m3)	Rock Porosity	Viscosity (Pa·s)	Permeability (md)	Pore Pressure (MPa)
1600	0.215	0.52	1200	52.7

shows the fluid mechanics parameters. The creep time is set to 14,400 h.

4. Simulation Results and Analysis

4.1. Wellbore Stress Distribution Patterns

The stress distribution on the wellbore was obtained through numerical simulation calculations, using the equivalent stress on the casing and cement sheath as the criteria for determining material yield failure, while neglecting radial and shear stresses in the wellbore. Along path ab in Figure 2, the equivalent stress on the inner surface of the casing is shown in Figure 3, and the equivalent stress on the inner surface of the cement sheath is shown in Figure 4.

As shown in Figure 3 in the initial state, the maximum equivalent stress on the casing in the brine layer is 579.7 MPa, while in the salt rock formation, it is 405.3 MPa. After 14,400 h, the maximum equivalent stress on the casing in the brine layer increases to 598.4 MPa, and in the salt rock formation, it rises to 872.6 MPa. The changes in equivalent stress in different formations before and after creep indicate the following: for the casing, the equivalent stress in the brine layer remains below the yield strength of P110 steel (758–862 MPa), ensuring no failure occurs. However, in the salt rock formation, the equivalent stress on the casing increases over time and exceeds its yield strength after 14,400 h, resulting in compressive failure of the casing.

As shown in Figure 4, the equivalent stress on the cement sheath is significantly higher in the brine layer and salt rock formation than in regular formations, with the equivalent stress in the brine layer consistently exceeding that in the salt rock formation. In the initial state, the maximum equivalent stress on the cement sheath in the brine layer is 38.2 MPa, and in the salt rock formation, it is 42.5 MPa. After 14,400 h, the maximum equivalent stress in the brine layer increases to 68.8 MPa, while in the salt rock formation, it rises to 60.2 MPa. The changes in equivalent stress across different formations indicate the following: for the cement sheath, brine seepage causes the equivalent stress to remain at a high level, increasing the risk of compressive deformation of the cement sheath. In the initial stage, the stress on the cement sheath in the salt rock formation is within a safe range, but after 14,400 h, the risk of failure becomes significant.

In conclusion, the maximum stress on the casing occurs in the salt rock formation, while the maximum stress on the cement sheath occurs in the brine layer. Based on strength failure criteria, both sections pose a risk of wellbore failure.

4.2. The Influence of Cement Sheath Elastic Modulus on Wellbore Stress Distribution

The cement sheath is a critical component of wellbore integrity. To investigate the effect of the cement sheath’s elastic modulus on wellbore stress distribution, elastic modulus values of 7 GPa, 10 GPa, 13 GPa, and 15 GPa were assigned. The stress variation curves for the casing and cement sheath obtained through numerical simulation are shown in Figure 5 and Figure 6. Based on the previous section’s results, the equivalent stress changes for the casing were taken from the salt rock formation, while those for the cement sheath were taken from the brine layer.

As shown in the figures, the stress on the casing gradually decreases as the elastic modulus of the cement sheath increases. When the elastic modulus is 15 GPa, the maximum equivalent stress on the casing is 793.5 MPa, a 7.8% reduction compared to when the modulus is 7 GPa, ensuring that the casing stress remains within a safe range. Similarly, the stress on the cement sheath decreases with increasing elastic modulus. At an elastic modulus of 15 GPa, the stress on the cement sheath decreases by 5.2%, keeping it within a safe range. In conclusion, appropriately increasing the elastic modulus of the cement sheath is beneficial for reducing the overall equivalent stress on the wellbore.

4.3. The Influence of Inclination Angle and Azimuth Angle on Wellbore Stress Distribution

The inclination angle and azimuth angle are critical parameters for designing the trajectory of directional wells and also influence the mechanical distribution of the wellbore under the action of in situ stress. To study the effects of inclination and azimuth angles on the stress distribution in the formation and wellbore, the stress changes were calculated under inclination angles (α) of 30°, 45°, and 60°, and various azimuth angles (β). The stress variation curves for the casing and cement sheath obtained through numerical simulation are shown in Figure 7 and Figure 8.

As shown in the figure, when the inclination angle is 45°, the minimum equivalent stress on the casing in the salt rock formation is 517.4 MPa. As the azimuth angle increases, the equivalent stress on the casing in the salt rock formation increases under different inclination angles. When the azimuth angle is in the range of 40° to 60°, high-stress regions appear on the cement sheath, and the equivalent stress on the cement sheath decreases as the inclination angle increases. In conclusion, increasing the inclination angle while appropriately controlling the azimuth angle helps prevent stress-induced failure of the cement sheath.

4.4. The Influence of Brine Density on Wellbore Stress Distribution

To study the effect of brine density on wellbore stress distribution, brine densities were assumed to be 1600 kg/m³, 1800 kg/m³, 2000 kg/m³, 2200 kg/m³, and 2400 kg/m³. The numerical simulation results are shown in Figure 9 and Figure 10.

As shown in the figures, the equivalent stress on the casing is significantly influenced by creep time but is less affected by brine density. An increase in brine density causes only a slight change in the equivalent stress on the casing. In contrast, the equivalent stress on the cement sheath is less affected by creep time but is significantly influenced by changes in brine density. When the brine density exceeds 2000 kg/m³, the equivalent stress surpasses the strength of the cement sheath. In conclusion, the impact of brine density is most pronounced on the cement sheath in the brine layer section.

4.5. The Influence of Liquid Column Density on Wellbore Stress Distribution

Assuming the liquid density inside the casing is 1500 kg/m³, 1600 kg/m³, 1700 kg/m³, 1800 kg/m³, and 1900 kg/m³, the numerical simulation results are shown in Figure 11 and Figure 12.

From the numerical simulation results above, it can be observed that the equivalent stress on the casing is significantly influenced by both creep time and liquid column density. With a constant creep time, an increase in liquid column density reduces the equivalent stress on the casing. When the liquid column density is 1900 kg/m³, the equivalent stress on the casing is 643.6 MPa, an 8.5% decrease compared to the initial density. The equivalent stress on the cement sheath is more affected by liquid column density and less by creep time. An increase in liquid column density decreases the equivalent stress on the cement sheath. When the liquid column density is 1900 kg/m³, the equivalent stress on the cement sheath is 59.2 MPa, a 13.5% decrease compared to the initial density. In conclusion, appropriately increasing the liquid column density helps to balance external in situ stress.

5. Conclusions

In this paper, the wellbore integrity of high-pressure salt-gypsum layer is studied, and a numerical simulation model of composite salt-gypsum layer wellbore with saltwater seepage field is established. The influence of the elastic modulus of the cement sheath, well inclination angle, azimuth angle, saltwater density, and liquid column density on wellbore mechanics is numerically analyzed. The following conclusions are drawn:

(1) In composite salt-gypsum formations, salt rock creep is time-dependent, leading to an increase in equivalent stress on the casing over time, which can result in casing yield failure. Salt rock creep is the primary cause of directional wellbore integrity failure. Meanwhile, brine seepage in the salt layer increases the stress on the outer wall of the cement sheath, making it prone to compressive deformation. Brine seepage is a secondary cause of wellbore failure.

(2) As the elastic modulus of the cement sheath increases, the stress on the wellbore gradually decreases, with the casing stress reducing by 7.8% and the cement sheath stress reducing by 5.2%. Increasing the elastic modulus of the cement sheath helps reduce the overall equivalent stress on the wellbore, thereby lowering the risk of compressive deformation.

(3) Numerical simulation results indicate that the degree of wellbore shrinkage is higher at the azimuth of the minimum horizontal in situ stress compared to the azimuth of the maximum horizontal in situ stress. When the azimuth is 0°, the equivalent stress on the casing is at its minimum, while at 90°, the equivalent stress reaches its maximum. Within the azimuth range of 45° to 60°, high-stress regions appear on the cement sheath, and the equivalent stress on the cement sheath decreases as the well inclination angle increases. Appropriately increasing the well inclination angle helps reduce the stress on the wellbore and prevent wellbore failure.

(4) When the density of the brine layer changes, the equivalent stress on the casing is significantly influenced by creep time but less so by the brine density. At the same time, an increase in brine density leads to a slight increase in the equivalent stress on the casing. The equivalent stress on the cement sheath is less affected by creep time but more influenced by changes in brine density, increasing as the brine density increases. The impact of brine density is particularly pronounced on the cement sheath in the brine layer section, which is prone to compressive failure.

(5) When the liquid column density inside the casing changes, the equivalent stress on the casing is significantly affected by both creep time and liquid column density. With constant creep time, an increase in liquid column density reduces the equivalent stress on the casing. Properly increasing the liquid column density helps balance external in situ stress and reduce the overall stress on the wellbore.