Numerical Simulation Analysis of Wellbore Integrity and Casing Damage in High-Temperature Injection and Production of Shale Oil

Abstract

Shale oil represents a relatively new form of unconventional oil and gas resource, and the extensive exploration and development of shale oil resources carry significant implications for China’s oil and gas supply and demand dynamics. At present, within the realm of low-maturity shale oil extraction technologies, the reservoir must be subjected to elevated temperatures ranging between 400 to 60 °C. Prolonged exposure of wellbores to such high temperatures can result in a substantial decrease in cement strength, the formation of microcracks due to cement cracking, and damage stemming from thermal stresses on the casing. Casing damage stands out as a prominent factor contributing to wellbore integrity failures and well shutdowns within the context of shale oil development. Given the limited natural energy reservoirs of shale oil formations, it becomes necessary to supplement the reservoir’s energy during the development process. Furthermore, shale oil exhibits high viscosity and poor flowability, and conventional water injection methods yield limited efficacy. This situation can induce significant shifts in the stress field and rock mechanical parameters, potentially activating specific formations and complicating the load dynamics on the casing. Consequently, the risk of failure increases. In light of these considerations, this study uses numerical simulations to study the integrity of high-temperature injection and production wellbores in shale oil and aims to encompass a comprehensive evaluation and analysis of the principal factors that influence casing damage, the fluctuations in thermal stress, and the yield strength of various steel grades of casings exposed to alternating stress conditions. Subsequently, this paper developed a model for simulating the temperature and pressure within shale oil and steam injection wellbores to support engineering design analysis. The research results indicate that the application of pre-stress results in a significant increase in stress at the casing pipe head while causing a noticeable decrease in stress within the pipe wall. When N80 casing is used, the entire casing experiences thermal stresses surpassing the casing’s yield limit. Stress concentration may arise at both ends of the external seal, potentially leading to casing contraction, shear failure, and, under non-uniform stress conditions, casing bending deformation. The temperature of steam injection significantly influences the temperature field of the casing wall, with stress values experiencing a marked reduction when the steam injection temperature decreases from 350 °C to 200 °C, underscoring the substantial impact of temperature on casing thermal stress. As the steam injection process advances along with injection-production cycles, shear stresses at the interface can exceed the bond strength, resulting in relative slippage between the cement and the casing. The bonding force between the wellbore and the cement primarily depends on the interface’s friction, particularly in the context of friction during wellhead lifting. This study endeavors to determine rational injection and production parameters under varying conditions, optimize completion methods, reduce casing damage, and extend the casing’s operational life; it aims to offer critical technical support for the safe and efficient development of shale oil resources.

1. Introduction

Shale oil is a new type of unconventional hydrocarbon resource, and it has been recognized as a crucial alternative energy source for the 21st century due to its abundant reserves and feasible development prospects. Currently, shale oil production, represented by the Permian Basin, Bakken, and Eagle Ford in North America, has achieved economic viability with an annual output of 2.4 × 10⁸ tons and is on the rise, contributing to energy independence in the United States [1]. China also possesses significant shale oil resources, estimated by the Ministry of Natural Resources to be 1.53 × 10⁹ tons in geological reserves and 3.7 × 10⁸ tons in recoverable resources [2]. Since 2011, key efforts have been made in shale oil development in fields such as Xinjiang Oilfield, Daqing Oilfield, and Jilin Oilfield, resulting in significant progress. Therefore, the large-scale exploration and development of shale oil resources hold great significance for addressing China’s oil and gas supply and demand pressures [3,4]. In the early stages of low-maturity shale oil extraction, it is necessary to heat the formation to temperatures ranging from 400 to 600 °C. Prolonged exposure of wellbores to high temperatures can lead to a sharp decrease in cement strength, the development of microcracks in the cement ring, and thermal stress damage to casing and completion tubing, ultimately compromising wellbore integrity and impacting the safe and efficient development of oil and gas resources [5,6,7,8,9]. Based on conventional oil and gas field development experience, the percentage of casing damage increases with the passage of time, especially in the later stages of development, making casing damage a significant reason for well abandonment. For example, as of the end of 2016, Daqing Oilfield had accumulated over 20,000 damaged wells, with a casing damage rate of 21%. By the end of 2017, Bameihe Block in Jianghan Oilfield had 646 damaged wells, with a casing damage rate of 32% [10]. Common causes of casing damage include geological factors, such as structural stress, reservoir creep, sand production, formation subsidence, and fault reactivation, and engineering factors, such as water injection, perforation, acidization, and fracturing, as well as corrosion factors, such as sulfur, carbon dioxide, hydrogen sulfide, and corrosion by formation water and injected water, while casing quality factors include defects in quality, residual stress, and thread sealing. Since deformation issues in casing pipes have been evident in the early stages of shale oil and gas well development, it can be anticipated that wellbore integrity issues will be even more complex during long-term development compared to conventional oil and gas wells.

Therefore, proactive measures, including risk assessment and related contingency plans, need to be developed as soon as possible to minimize losses. Zhang Yonggui [11] established a mechanical model for thermal recovery well casings, studied the calculation methods for thermal stress and extrusion pressure in the model, and fully considered the interaction between the casing and formation in the casing mechanical model. However, the casing stress condition is affected by well depth, and the influence of various factors on casing strength at different well depths still requires further research. Li Jing et al. [12] studied the theoretical solution of thermal stress in the casing–cement–ring-formation coupled system, qualitatively indicating the factors affecting casing thermal stress but not considering the effect of the cement ring’s thickness on casing thermal stress variations. Tian Zhonglan et al. [13] have made significant contributions by developing models that enable the assessment and calculation of casing damage resulting from a variety of factors, and these models provide valuable insights into the underlying mechanisms and typical patterns associated with casing damage, as well as the phenomenon of shale slippage. From this, it can be seen that China has conducted extensive research on the structural aspects of wellbore integrity in thermal recovery wells [14,15,16]. However, there has been relatively limited research on the impact of heating methods for shale oil extraction on the integrity of wellbores, casing, cement, and the geological formations as a whole [17,18,19,20]. This research gap is particularly significant due to the inherent limitations of shale oil reservoirs, which necessitate the timely supplementation of subsurface energy during the development process. Furthermore, the high viscosity and poor flow properties of shale oil make conventional water injection methods less effective, resulting in significant changes in subsurface stress fields and rock mechanical parameters [21,22,23,24,25,26,27]. This can potentially activate certain geological formations, leading to the complex load conditions experienced by casing pipes and an increased risk of casing failure.

Therefore, this paper conducts a study on the wellbore integrity and casing damage in high-temperature shale oil injection and production wells using numerical simulation methods. The study involves a comprehensive evaluation and analysis of geological factors in the reservoir, single-well completion engineering factors, and steam injection and production process factors. The goal is to clearly identify the primary factors that affect casing damage and to understand the patterns of thermal stress and yield strength variations in casing materials under alternating stress conditions. Subsequently, a thermal and pressure model for shale oil steam injection and production wells is constructed. Advanced simulation software is employed for the numerical calculations and analyses. The research includes engineering design analysis and a temperature–pressure profile analysis, among other aspects of the study. The aim is to determine reasonable injection and production parameters for different operating conditions, achieve optimization of well completion methods, reduce casing damage, and extend the lifespan of casing pipes. This research is intended to provide technical support for the safe and efficient development of shale oil resources.

2. The Primary Causes of Casing Damage in Steam Injection Wells

Currently, many shale oil fields are facing serious casing damage issues in their thermal recovery wells, with the main types of casing damage being contraction, rupture, shear, and corrosion. These casing damage problems have posed significant challenges to the production of shale oil fields. The study of wellbore integrity and casing deformation during shale oil high-temperature injection and production processes can draw insights from the casing damage issues in shale oil recovery. The decline in production in thermal recovery wells, and in severe cases, production shutdown, underscores the importance of understanding the mechanisms of casing damage in shale oil thermal recovery wells. It is only by comprehending the mechanisms of casing damage that appropriate protective and remedial measures can be developed based on the primary causes of casing damage. This is of paramount significance in extending the lifespan of casing and wellbores, stabilizing and increasing thermal recovery production in shale oil fields. The primary causes of casing damage in steam injection wells are shown in Figure 1.

2.1. The Geological Factors

(1)

Influence of Surrounding Rock Pressure

After drilling, an annular space is formed in the surrounding rock, disrupting the original equilibrium. When the stress at the stress concentration point reaches the yield limit of the surrounding rock, plastic deformation or formation rupture occurs. This deformation and rupture are constrained by the casing and the outer cement ring. Additionally, the casing experiences deformation and damage due to the reaction force from the surrounding rock.

(2)

Influence of Stratum Dip Angle

Many of the currently developed oil fields are characterized by anticlinal structural reservoirs, resulting in strata having a certain dip angle. Weak structural planes in the strata may weaken during oil and gas production and enhanced recovery measures. When the dip angle of the strata exceeds the internal friction angle of the rocks, gravity can cause sliding in weak rock layers.

(3)

Fault Activity

During the oil field development process, changes in subsurface pressure due to crustal movement, earthquakes, high-pressure injection, and other factors can alter rock mechanics properties and subsurface stress. This can induce the reactivation of pre-existing faults, especially after water injection, intensifying damage to the casing. Some oil fields in China, such as Daqing and Jilin, have experienced casing damage concentrated near faults, which is a consequence of fault reactivation. Once the faults are reactivated, it can lead to extensive casing damage near fault zones, often characterized by casing shear failure, and the depth of these damages is generally consistent.

(4)

Mudrock Water Absorption and Creep

Mudrock is an unstable rock type, and its mechanical properties and stress state change when the temperature rises or water enters the formation. This leads to the displacement, deformation, and expansion of mudrock, increasing external loads on the casing. When the casing’s compressive strength is lower than the external load, it can result in casing compression deformation or even shear failure. Due to steam intrusion into the formation and water ingress into the mudrock, the elastic modulus decreases, reducing the stratum’s bearing capacity and increasing the compressive stress on the casing.

2.2. The Engineering Factors

(1)

Casing Material Issues

The choice of casing material plays a crucial role in its resistance to deformation. By improving the steel grade and wall thickness and using thermal recovery casing, some progress can be made. However, the design and control of casing integrity measures still may not fully meet on-site requirements. Different steel grades have varying resistance to deformation and strength.

(2)

Cementing Quality Issues

Cementing is a critical process before drilling completion and has a direct impact on the well’s lifespan and subsequent injection and production operations. The cementing quality can be influenced by various factors such as irregularities in the wellbore, well inclination, non-compliance with cementing standards, inadequate displacement of drilling mud, improper slurry density, mud cake issues, cleanliness of the wellbore and casing exterior before cementing, and inappropriate tension loads on the casing after cementing. These factors can adversely affect the cementing quality, which in turn affects the casing’s integrity and lifespan.

(3)

Steam Injection Parameters

Many oil fields employ steam injection for shale oil recovery. High-temperature, high-pressure steam injection into the wellbore can have detrimental effects on the casing’s integrity. Steam temperatures can exceed the maximum allowable temperatures for certain casing grades, causing a decrease in yield strength and elastic modulus. Additionally, the tension generated on the casing due to thermal expansion and contraction, coupled with axial stress under continuous high temperatures, can result in fatigue cracks and compression deformations, ultimately leading to casing damage. Common casing thread types have temperature limits below 300 °C, which, when exceeded, can cause radial deformation of the threads that may lead to leaks and uncoupling issues.

(4)

Perforation-Induced Damage

Casing damage can also be attributed to well-perforation activities. The main reasons include outer cement ring rupture and even casing rupture, or significant perforation depth errors or misfires, which are especially critical for secondary enhanced recovery wells or those with thin interlayers. If thin layers of shale or mudstone are unintentionally penetrated, water intrusion and expansion of these formations can lead to changes in subsurface stress, ultimately resulting in casing damage. An inappropriate perforation density can also impact casing strength. In low-permeability sandstone reservoirs, high-density perforation completion or cyclic high-pressure from long-term water injection or reservoir acidizing can lead to casing damage.

(5)

Corrosion-Induced Casing Damage

Casing damage can include corrosion. Casing corrosion can have severe consequences, including perforations and multiple leak points. Corrosion can accelerate casing fatigue, causing early deformation and damage. It is a complex issue in oil and gas wells, requiring comprehensive technical measures for mitigation.

(6)

High Temperatures Leading to Casing Damage

High temperatures in the wellbore can adversely affect casing integrity in two main ways: reducing casing strength and increasing thermal stress within the casing. These two factors, along with other contributing factors, can significantly increase the likelihood of casing damage.

(7)

Formation Sand Production Impact

The formation and production of sand can affect casing integrity. Analyzing cavity shapes based on the principles of the Provencher natural balance arch theory and considering the interaction between the casing and the formation, a formula for calculating the axial force on the casing during sand production was derived. This can help determine the relationship between casing instability failure and sand production volume. Different steel grades and wall thicknesses of casing can impact casing failure during sand production. In highly sand-prone oil fields, it is advisable to use high-strength, thick-walled casing sections, particularly in critical areas, to prevent casing damage.

3. Casing Stress Analysis

Before steam injection, the casing primarily experiences the following loads: longitudinal axial loads, internal and external pressure loads, frictional loads, and bending loads. These loads stem from the casing’s own weight, the buoyancy of drilling mud, internal pressure from drilling fluids, formation stress, frictional forces, and wellbore deviation. After steam injection, the casing undergoes significant temperature changes due to the heat from the injected steam. The steel material expands when heated but is constrained by the wellbore and cement sheath. As a result, substantial thermal stresses develop within the casing. These wells are fully cased and cemented, with packers used at the top of the reservoir. Perforation completion is employed. Steam is delivered through a thermal insulation column to the section below the packer, then through the annular space and perforation casing to heat the viscous crude oil reservoir [28,29,30]. During this phase, significant temperature differentials occur, leading to substantial thermal stresses. Our analysis comprehensively considers the radial, circumferential, and axial stress variations in the casing string throughout the steam injection process. After oil well production, the casing may experience increased external pressure from formation compaction, which is a significant factor leading to casing damage. Formations containing salt rocks, shale, and mudstone can exhibit viscoelastic deformation under the influence of original in situ stresses. Post-cementing, the casing must withstand the gradually increasing pressure due to wellbore contraction. Over an extended period, this pressure stabilizes and is referred to as the casing’s geomechanical stress extrusion force. As viscoelastic solutions and elastic solutions are consistent for stable solutions of the same problem, seeking the final stable extrusion force can be accomplished using the methods of elastic mechanics. The stress model under in situ stress conditions is shown in Figure 2.

This stress state can be represented in polar coordinates using the average and deviatoric stress in order to consider the stress state as a superposition of uniform and non-uniform forces. Therefore, solving the casing’s stress under non-uniform stress conditions can be transformed into solving the casing’s stress separately under ${\sigma }_{ave}$ and under the action of the non-uniform forces $\sigma \cos 2\theta$ and $\sigma \sin 2\theta$. After superimposing these results, we can obtain the stress state of the casing under non-uniform stress. The final result can be expressed approximately as the external extrusion stress on the casing under non-uniform stress conditions.

$$\left\{\begin{array}{l}{\sigma }_{ave}=\frac{1}{2}\left({\sigma }_1+{\sigma }_2\right)\\ {\sigma }_{dev}=\frac{1}{2}\left({\sigma }_1-{\sigma }_2\right)\\ {\sigma }_r\left(r,\theta \right)={\sigma }_{ave}+{\sigma }_{dve}\cos 2\theta \\ {\tau }_{r\theta }\left(r,\theta \right)={\sigma }_{dve}\sin 2\theta \end{array}\right.$$

(1)

where ${\sigma }_{ave}$ is the average stress, in MPa. ${\sigma }_{dve}$ is the deviatoric stress, in MPa. ${\sigma }_1$ is the maximum horizontal stress, in MPa. ${\sigma }_2$ is the maximum horizontal stress, in MPa. $\theta$ is the principal direction, in °C.

The extrusion load acting on the casing can be calculated using the formula:

$$P=\rho gH\times {10}^{-3}$$

(2)

where P is the extrusion load, in MPa. $\rho$ is the density of the annular mud or cement slurry, in g/cm³. g is the acceleration due to gravity, in m/s². H is the depth at which the casing is located, in m.

The axial load on the casing is typically derived from the gravitational force due to the casing’s self-weight and the buoyant force exerted by the wellbore fluid. Additionally, the casing’s exposure to the bending stress should also be considered. As the majority of the steam injection wells are vertical wells, the influence of the bending loads on the casing can be disregarded. The initial expression for the axial load is obtained by adding the equations for the casing’s self-weight and the buoyant force of the wellbore fluid. Assuming that when the casing is first installed, the pressure inside and outside the wellhead is zero. The additional axial force caused by the change in internal and external pressures in the casing can be calculated using the Lame formula, as described in Equation (3).

$$\mathsf{\Delta }{F}_P=\frac{2\times {10}^{-6}{\mu }_c{\displaystyle \sum _{j=1}^N\left(\mathsf{\Delta }{p}_i{A}_{ij}-\mathsf{\Delta }{p}_o{A}_o\right)\left(L_j/A_j\right)}}{{\displaystyle \sum _{j=1}^N\left(L_j/A_j\right)}}$$

(3)

where $\mathsf{\Delta }{F}_P$ is the additional axial load, in MPa. ${\mu }_c$ is the Poisson’s ratio of the casing. $\mathsf{\Delta }{p}_i$ is the increase in the internal wellhead pressure of the casing, in MPa. $\mathsf{\Delta }{p}_o$ is the increase in the outer wellhead pressure of the casing, in MPa. $A_{ij}$ is the inner cross-sectional area for the jth casing section, in mm². $L_j$ is the length of the jth casing section, in m. $A_j$ is the cross-sectional area for the jth casing section, in mm². N is the number of casing sections calculated in the casing string.

High-temperature steam places the casing in a high-temperature environment downhole, and as the casing is typically made of steel, it undergoes thermal expansion when exposed to heat. However, the casing is constrained by the cement annulus and reservoir, preventing it from expanding freely. As a result, an additional stress induced by the temperature difference, known as thermal stress, is generated in the casing. The generation of thermal stress in the casing is primarily influenced by factors such as temperature, material properties, the properties of the cement annulus restraining the casing, and the characteristics of the reservoir. The thermal stress issue of vertical thermal recovery well casings is the foundation for calculating casing thermal stress. When deriving the expressions for thermal stress in the radial, circumferential, and axial directions, it is considered that the casing has not reached its own yield strength. The components of thermal stress are as follows:

$$\left\{\begin{array}{l}{\sigma }_{\tau }=\left[-\frac{a_c{E}_{c}T}{2\left(1-{\mu }_c\right)}+\frac{E_c{C}_{cl}}{\left(1+{\mu }_c\right)\left(1-2{\mu }_c\right)}\right]\left(1-\frac{r_c^2}{r^2}\right)\\ {\sigma }_{\theta }=\left[-\frac{a_c{E}_{c}T}{2\left(1-{\mu }_c\right)}+\frac{E_c{C}_{cl}}{\left(1+{\mu }_c\right)\left(1-2{\mu }_c\right)}\right]\left(1+\frac{r_c^2}{r^2}\right)\\ {\sigma }_z=-\frac{a_c{E}_{c}T}{1-{\mu }_c}+\frac{2{\mu }_c{E}_c{C}_{cl}}{\left(1+{\mu }_c\right)\left(1-2{\mu }_c\right)}\\ C_{cl}=\frac{a_{c}T \left(1-2{\mu }_c\right)\left[r_{co}^2-r_{ci}^2\right]\left(\frac{E_c}{E_f}-\frac{1+{\mu }_c}{1+{\mu }_f}\right)}{2 \left(1-{\mu }_c\right)\left[\frac{E_c}{E_f}\frac{r_{co}^2-r_{ci}^2}{1+{\mu }_c}+\frac{\left(1-2{\mu }_c\right)\left(r_{co}^2-r_{ci}^2\right)}{1+{\mu }_f}\right]}\end{array}\right.$$

(4)

where ${\sigma }_{\tau }$ is the radial casing thermal stress, in MPa. ${\sigma }_{\theta }$ is the circumferential casing thermal stress, in MPa. ${\sigma }_z$ is the axial casing thermal stress, in MPa. $a_c$ is the coefficient of thermal expansion of casing, in 1/°C. T is the temperature change, in °C. $E_c$ is the elastic modulus of the casing, in GPa. $C_{cl}$ is the calculation parameter. $r_{ci}$ is the casing inner diameter, in m. $r_{co}$ is the casing outer diameter, in m. $E_f$ is the elastic modulus of drilling fluid, in GPa. ${\mu }_f$ is the Poisson’s ratio of the drilling fluid.

During the steam injection process, the injected hot steam causes the casing to expand due to the high temperature. The casing experiences significant thermal stresses internally due to the restraining effect of the cement sheath. If the thermal stresses exceed the casing material’s yield strength, the casing will yield and undergo plastic deformation. During repeated heating cycles, plastic deformation accumulates, gradually reducing the structural strength of the casing and eventually leading to failure. Failure modes can include necking, buckling, and fracture. For metallic materials, the Mises yield criterion is generally employed. When the thermal stress level in the casing exceeds its yield strength, the casing steel undergoes plastic yielding. This is expressed using the Mises yield criterion, represented in terms of principal stresses:

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

(5)

where ${\sigma }_s$ is the Mises equivalent stress, in MPa. ${\sigma }_1$, ${\sigma }_2$, ${\sigma }_3$ are the three principal stresses, in MPa.

4. Numerical Simulation Analysis

4.1. Theoretical Basis of Finite Element Analysis

As the steam injection process continues, the casing is highly susceptible to damage, which can even lead to the abandonment of the oil well, severely impacting reservoir development and the economic benefits of the oil field. Therefore, understanding the distribution of temperature, stress, and strain in the steam injection well casing during production is of utmost importance. It is difficult to simulate the actual conditions of a steam injection wellbore in a laboratory setting. Therefore, the commonly used approach is to employ finite element simulations with thermal-stress coupling. This involves establishing a wellbore-cement annulus-formation combination and using the principles of elastic mechanics for cylindrical structures to create temperature, stress, and strain models for the steam injection well casing. The goal is to identify the causes of wellbore failure and propose effective preventive measures for casing damage in steam injection wells, ultimately extending the casing’s service life and improving production efficiency.

4.2. Assumptions of Finite Element Model

(1)

The cement bond is well-established on both sides, and the casing–cement–formation system is tightly connected, with the tubing, casing, and cement annulus co-axially forming a single unit.

(2)

The well cementing condition is good, and the influence of cementing quality is not considered.

(3)

The initial in situ stress is undisturbed during steam injection.

(4)

The casing has consistent specifications, no wall thickness variations and there is no slippage between the casing and cement annulus or between the cement annulus and the formation.

(5)

The parameters for steam injection at the entrance of the simulated well section are identical to those at the surface wellhead, and heat loss during steam injection is neglected.

(6)

The impact of perforation on the steam injection well is not considered.

(7)

The geological formation in the well section is considered infinite, with the exception of temperature changes near the wellbore, where the temperature remains constant in the rest of the formation.

(8)

Material anisotropy is not considered, and it is assumed that the properties of the formation, cement annulus, and casing materials are isotropic and homogeneous.

(9)

When simulating the wellbore temperature field under a certain temperature, it is assumed that the temperature distribution represents a quasi-steady state condition reached by the wellbore.

4.3. Physical Model

The numerical simulation analysis for casing damage in this study utilizes an indirect coupling approach. Initially, transient thermal analysis using ANSYS finite element analysis is employed to determine the temperature field distribution along the radial direction of the wellbore and the temperatures on the inner and outer walls of the casing. Subsequently, an indirect coupling method is used to import the temperature field of the wellbore into the structural field to obtain the thermal stresses on the inner and outer walls of the casing. The fundamental parameters of the case well and the thermal loss parameters of the surface pipeline are listed in

Table 1. Basic parameters.

Parameters	Value	Parameters	Value
Drilled Depth	1016.0 m	Boiler Outlet Discharge Rate	10 t/h
Casing Specifications	177.8 mm	Wellhead Temperature	336 °C
Casing Depth	1015.3 m	Boiler Outlet Dryness Fraction	75.6%
Artificial Bottom	1010.0 m	Wellhead Pressure	14.15 MPa
Oil Buffer Distance	4.75 m	Pipeline Inner Diameter	0.1 m
Casing Repair Distance	5.07 m	Pipeline Material Thermal Conductivity	57.0 W/(m·°C)
Tubing Specifications	114.3 mm	Pipeline Outer Diameter	0.108 m
Tubing Depth	873.14 m	Insulation Material Thermal Conductivity	0.2 W/(m·°C)
Boiler Outlet Temperature	343.4 °C	Pipeline Length	1000 m
Design Steam Injection Volume	1500 m3	Ambient Temperature	10 °C
Boiler Outlet Pressure	15.3 MPa	Pipeline Surface Emissivity	0.85
Measured Steam Injection Volume	1060 m3	Average Wind Speed	3 m/s
Insulation Layer Thickness	0.07 m	Calculation Step Length	200 m

.

The selected wellbore segment for the numerical simulation study is located at a depth of 800 m, with a 50 m interval. Based on the given relationships, the simulated formation temperature at 800 m is 52 °C. The horizontal principal stresses in the horizontal direction are 20 MPa, the overburden pressure is 13 MPa, the cement sheath pressure is 11 MPa, and the casing self-weight load is 50 MPa. The in situ stress in the model is applied as an initial stress state to better represent real geological conditions. The model employs a structured grid division approach, with local refinements in the mesh for the casing and cement sheath and gradual mesh refinement from the outside to the inside for the formation. This results in a total of 20,560 elements and 116,481 nodes, as shown in Figure 3.

The material parameters for the casing, formation, and cement sheath are shown in

Table 2. Basic parameters of selected material.

Material	Density (kg/m3)	Young’s Modulus (MPa)	Poisson’s Ratio	Coefficient of Thermal Expansion (1/K)	Thermal Conductivity (W/(m·K))
N80 Casing	7850	146	0.3	12	43.27
TP100H Casing	7850	180	0.3	12	43.27
TP110 Casing	7850	180	0.3	12	43.27
TP130TT Casing	7850	165	0.3	12	43.27
Cement Sheath	1900	7.5	0.18	10.5	0.81
Formation	2390	25	0.2	10.3	3.44

.

Applying stress and displacement to the model as boundary conditions, as shown in Figure 4. A represents the radial pressure of 20 MPa; B represents the axial pressure of 13 MPa from the formation; C represents the axial pressure of 11 MPa from the cement sheath; D represents the axial pressure of 50 MPa from the casing; E represents the outer boundary of the formation and is completely fixed (constraint); F represents the displacement constraint on the cutting plane; and G and H represent the axial displacement constraints on the upper and lower surfaces of the model.

In order to address the issue of the excessive axial thermal stresses generated in the casing during steam injection in thermal recovery wells and prevent casing damage, a pre-stressed casing completion technique is employed. By applying a certain level of pre-stress, some of the thermal stresses can be reduced, thereby preventing casing damage. Some casings experience thermal stresses during steam injection that exceed the yield strength of the casing, resulting in plastic deformation and, ultimately, casing failure, which poses a safety risk to the wellbore. Numerical simulation setup: Two analysis steps are used. In the first step, the casing–cement interface is defined as smooth, and pre-tensile stress is applied to the casing to simulate pre-stressing the casing and injecting back cement. In the second analysis step, the casing–cement interface is changed to bonded to simulate the solidification of the cement, bonding between the inner wall of the casing and the cement sheath, and then applying the thermal load. Currently, there is limited research on the calculation methods for reasonable pre-stress values in various oil fields in China. The methods for calculating the pre-stress values mentioned in manuals and textbooks typically involve using the thermal expansion coefficient of steel to calculate the elongation of the casing under thermal conditions and then deriving the corresponding reduction in pre-stress, referred to as uniaxial pre-stress. When applying uniaxial pre-stress, the maximum thermal stress produced in the casing under thermal conditions is calculated as follows:

$${\sigma }_{\max }=\lambda E\mathsf{\Delta }T$$

(6)

where ${\sigma }_{\max }$ is the maximum thermal stress experienced by the casing, in MPa. $\lambda$ is the coefficient of linear expansion for the metal, K⁻¹. E is the elastic modulus of the steel material, in MPa. $\mathsf{\Delta }T$ is the increase in temperature, in °C.

The minimum pre-stress required for the casing string is calculated as follows:

$$\mathsf{\Delta }\sigma ={\sigma }_{\max }-{\sigma }_s$$

(7)

where $\mathsf{\Delta }\sigma$ is the minimum pre-stress required for the casing, in MPa. ${\sigma }_s$ is the minimum yield strength of the casing material, in MPa.

The minimum pre-tension force required for the casing string is calculated as follows:

$$F=\mathsf{\Delta }\sigma S$$

(8)

where F is the pre-tension force for the casing, in kN.

Based on theoretical calculations and field data, the following pre-stress loads are selected for the study, as shown in

Table 3. Pre-stress and corresponding loads.

Applied Pre-Stress (KN)	Corresponding Loads (MPa)
300	45.7
320	48.8
445	67.8
500	76.2
750	114.3
850	129.5
1000	152.4

below.

First, apply the corresponding pre-tension loads to the model individually, with no frictional relative slip allowed between the cement ring and the casing. Next, export the deformations produced in three axes at different nodes under different pre-stress conditions as text files. These files will serve as input for simulating the casing’s state under pre-tension conditions. Simulate the changes in Mises stress in the casing with different pre-stress values applied. The distribution patterns of the casing Mises equivalent stress at the pipe head and the pipe wall are inconsistent. The trend of stress at the pipe head and within the pipe wall with changing pre-stress is illustrated in the following Figure 5 and Figure 6.

From the figures, it can be observed that applying pre-stress leads to a significant increase in the stress at the casing pipe head and a noticeable decrease in stress within the pipe wall. As the pre-tension force increases, the impact on the pipe wall thermal stress gradually diminishes. Without applying pre-stress, the maximum Mises stress in the casing reaches 696 MPa. However, after applying pre-stress levels of 300, 500, 750, 850, and 1000 kN, the actual reduction in thermal stress in the casing due to the sealing of the inner wall by steam injection is significant. In the absence of pre-stress, the casing segment experiences relatively high overall stress, with an inner wall stress of 697 MPa. After applying a 500 kN pre-stress, the casing experiences the maximum equivalent stress of 870 MPa at the wellhead. The application of pre-stress can significantly reduce the thermal stress experienced by the casing wall, but it increases the stress at the wellhead.

5. Analysis of Influencing Factors

5.1. Impact of Different Cement Properties on Casing Damage Patterns

To overcome the challenges of developing high-temperature-resistant elastic cement slurry systems, a series of high-temperature-resistant additive materials were studied in the laboratory. This led to the formulation of high-temperature-resistant elastic cement slurry systems, and their performance was evaluated to provide technical support for cementing operations in high-temperature and complex well environments. Using G-grade cement as the base material, high-temperature elastic additives were incorporated to improve the mechanical properties of the cement rings, as shown in

Table 4. Cement properties.

NO.	Elastic Agent Content %	Elastic Modulus (GPa)
1	8%	5
2	5%	7.5
3	3%	10
4	2%	15
5	1%	20

below.

Through experimental research, the types and quantities of additives, as well as their influence on the properties of oil well cement rings, were determined to simulate the material properties of the cement rings used. Based on adjusting the content of additives in the elastic cement, changes in the mechanical properties of the cement rings were achieved. Simulations were conducted to examine the thermal stress in the casing for cement rings with different Young’s moduli. The continuous increase in the elastic modulus of the cement rings results in a gradual increase in the maximum Mises stress in the casing. However, this increase is not very significant. Although it may not lead to casing yield, it could potentially cause plastic deformation in the cement ring–casing interface, affecting the bond between the cement and the casing. The Numerical simulation results are shown in

Table 5. Numerical simulation results.

NO.	Elastic Modulus (GPa)	Equivalent Stress (MPa)	Deformation (mm)	Plastic Strain
1	5	690	3.18	0.008
2	7.5	691	3.27	0.0096
3	10	692	3.33	0.0097
4	15	696	3.30	0.0101
5	20	728	3.59	0.012

.

Regressing the axial deformation data over the entire wellbore, the axial elongation of the entire wellbore is obtained when the wellbore is unconstrained, as shown in Figure 7.

As the elastic modulus of the cement ring continues to increase, the maximum Mises stress in the casing gradually increases; however, the change is not very significant. With the increasing elastic modulus of the cement ring, both the overall maximum deformation and the deformation range increase. As the elastic modulus of the cement ring increases, the model’s plastic strain also begins to increase, indicating more significant plastic deformation in the cement ring and the formation. However, the strength of the cement and its bond with the casing plays a significant role in their impact on the casing. In practical field applications, selecting appropriate cement properties can provide some protection to the casing; however, the effect is limited.

5.2. Simulation Analysis of the Influence of External Loads on Casing

At a depth of 800 m below the packer, the Mises stress levels in the casing above and below the packer are significantly different. This disparity is due to the packer’s function of isolating the annulus above and below it. The packer experiences horizontal stress due to the thermal compression of the casing. Near and especially below the packer, there is a concentration of local stress, and the average casing stress can reach over 750 MPa, which exceeds the yield strength of the casing and makes it prone to damage. If a packer is not used or if it fails, the overall casing experiences relatively high stress levels and is subjected to very high radial and axial stresses, making the casing more susceptible to damage. At a depth of 800 m in the wellbore, a 2 m rigidly constrained section with packers is installed. Local circumferential pressure is applied to simulate the squeezing of the casing wall at the packer location. The simulation results are obtained, as shown in Figure 8.

The stress distribution in the casing along the 4 m section of the packer is fitted with a function, as shown in Figure 9.

At both ends of the packer, there are abrupt changes in stress due to the external load conditions, resulting in stress concentration on both sides and an increase in local stress. As the deformation gradually increases on both sides of the packer, stress concentration occurs, leading to a sharp increase in deformation, making it prone to failure, as shown in Figure 10.

Due to the hydration of shale, the cohesion and internal friction angle decrease, resulting in a significant reduction in the shear strength of the rock; therefore, as the water content of the shale increases, the rock’s shear strength decreases. In the sand–shale interface, the casing experiences uneven stress, leading to shear failure in this area. Additionally, after shale hydration in the shale section, the shale’s supporting capacity decreases, and stress is transferred to the cement sheath and casing. When the stress on the casing exceeds the yield strength of the casing, plastic deformation occurs in the casing. At a depth of 800 m in the wellbore, a simplified approach is used to apply localized external loads to a 2 m segment based on the shale layer thickness and the length of the packer. The external load values are 50, 75, 100, 125, and 150 MPa. The local load is applied by simulating the circumferential pressure to model the expansion and squeezing of the casing and packer at the casing wall after shale hydration. Different results are calculated for each of the different external load values, as shown in

Table 6. Different external loads.

Local Load (MPa)	Equivalent Stress (MPa)	Deformation (mm)	Plastic Strain
50	729	0.69	0
75	756	0.7	0.0002
100	760	0.703	0.0008
125	772	0.708	0.0009
150	793	0.72	0.0017

.

When the external load remains within 50 MPa, there is no yielding in the casing wall. Yielding begins at approximately 70 MPa. As the external load gradually increases beyond 125 MPa, plastic deformation accumulates noticeably. As the localized external load increases, the maximum principal stress, maximum deformation, and plastic strain in the casing gradually increase. However, there are differences in the behavior of the inner and outer walls of the casing. The stress on the inner and outer walls at different locations under external loads is shown in

Table 7. Stress on inner and outer walls at different external load locations.

Local External Load (MPa)	Inner Wall Stress (MPa)	Outer Wall Stress (MPa)
50	729	720
75	758	704
100	760	687
125	772	665
150	793	634

.

5.3. Impact of Different Injection and Production Parameters on Casing Damage Patterns

Controlling the injection and production parameters in steam injection wells is the most easily controllable influencing factor. The study on the impact of steam injection temperature on casing stress in thermal recovery wells primarily focuses on controlling the steam injection temperature, steam injection pressure, and steam injection rate to regulate the wellbore temperature and pressure field. By employing a method of controlling variables, all other well parameters remain constant except for changes in the temperature, pressure, and rate of steam injection. This approach allows for a clear understanding of how steam temperature affects casing stress. Based on the actual field conditions, various steam injection parameters were selected for simulation and solutions to obtain different temperature fields and stress fields. The chosen steam injection parameters include:

(1)

Steam injection temperature: 350 °C, 320 °C, 300 °C, 280 °C, and 250 °C.

(2)

Steam injection pressure: 8 MPa, 10 MPa, 12 MPa, 15 MPa, and 18 MPa.

(3)

Injection rate: 4 t/h, 6 t/h, 8 t/h, 10 t/h, and 12 t/h.

In order to investigate the influence of the steam injection pressure while controlling the steam injection temperature at 350 °C, the simulated Mises stress on the inner casing wall for different steam injection pressures of 8, 10, 12, 15, and 18 MPa are as shown in

Table 8. Simulation results under different steam injection pressure conditions.

Steam Injection Pressure (MPa)	Casing Stress (MPa)
8	766
10	768
12	768.6
15	769
18	769.6

.

By analyzing the Mises stress values under different steam injection pressure conditions, it is observed that changing the steam injection pressure by 10 MPa results in a mere 1% increase in the Mises stress on the inner casing wall. This implies that changing the steam injection pressure has a minimal impact on the Mises stress in the casing. Consequently, it can be concluded that the steam injection pressure has a relatively small influence on the Mises stress on the inner casing wall and, by extension, on casing damage.

Figure 11 illustrates the influence pattern of the steam injection temperature on the casing stress. It can be observed that when the steam temperature is increased from 200 °C to 350 °C, the Mises stress level on the inner casing wall increases by 48%. This indicates that the stress level in the casing is significantly affected by temperature, and changes in the steam temperature have a significant impact on casing stress. Furthermore, at a temperature of 350 °C, the Mises stress on the inner casing wall reached 696 MPa.

Figure 12 illustrates the influence pattern of the steam injection rate on the casing stress. It can be observed that when the steam injection rate is increased from 4 t/h to 8 t/h, the Mises stress level on the inner casing wall increases by 26%. This indicates that the stress level in the casing is significantly affected by the steam injection rate, and changes in the injection rate have a certain impact on casing stress. Additionally, at an injection rate of 10 t/h, the Mises stress on the inner casing wall reached its maximum value of 696 MPa. Increasing the injection rate further will not result in a continuous increase in casing stress. The injection rate has a noticeable impact on the overall injection volume. Excessive injection rates do not lead to a significantly more pronounced heating effect.

5.4. Impact of Different Insulation Methods and Insulation Effect on Casing Protection and Damage Patterns

During the injection of high-temperature steam into the wellbore, high-temperature thermal stresses often occur. The fundamental reason for this is the differential expansion and constraint of various materials within the wellbore. Materials such as steel casing, cement sheath, and geological formations expand when the temperature rises. Since these materials have different coefficients of thermal expansion and are mutually constrained, they generate thermal stress. Materials with a larger coefficient of thermal expansion will produce greater thermal stress under the same constraints. This method avoids further heat loss along the path. In numerical calculations, a reference temperature of 52 °C for the geological formation and a steam injection temperature of 350 °C are used. To study the influence of insulation methods on the temperature distribution near the casing and, consequently, to determine the casing stress under different insulation methods, this study considers three commonly used insulation measures in engineering. The thermal conductivity coefficients for the casing–cement sheath system under each measure are provided in

Table 9. Thermal conductivity of three heat insulation measures.

Insulation Measure	Thermal Conductivity Coefficients (W/m·°C)
Vacuum Insulation Tube + Packer	0.06
Vacuum Insulation Tube + Nitrogen Gas	0.01
Vacuum Insulation Tube + Nitrogen Gas	0.12
Vacuum Insulation Tube + Nitrogen Gas	0.20

.

The simulation of the annular temperature field under different thermal insulation conditions is shown in Figure 13.

When the thermal conductivity of the wellbore system changes, the heat transfer effect also changes, which shows that the temperature of the inner and outer walls of the casing is affected by the heat transfer coefficient. The use of low thermal conductivity insulation can significantly reduce the wellbore internal temperature. When the apparent thermal conductivity of the heat insulation tube is smaller, the temperature of the casing wall is lower, and the heat insulation effect is more obvious. Taking the temperature field as the input load, the variation rule of the casing thermal stress state is obtained, as shown in Figure 14.

The thermal insulation coefficient has an obvious influence on the temperature field in the wellbore. The temperature in the wellbore is positively correlated with the equivalent thermal stress. The lower the thermal conductivity coefficient is, the better the thermal insulation effect is. The effect of reducing thermal conductivity is more obvious below 0.1 W/m·°C. The thermal insulation coefficient related to thermal insulation can directly affect the casing temperature field during steam injection. The lower the thermal conductivity coefficient, the lower the casing wall temperature, the better the thermal insulation effect. The maximum thermal stress of the casing also decreases with the decrease of the heat insulation coefficient, showing an obvious positive correlation. The effect of reducing the thermal conductivity is more obvious when the thermal insulation coefficient is below 0.1 W/m·℃. With the process of multiple steam huff-and-huffs, the performance of the thermal insulation pipe will decrease, its apparent thermal conductivity will increase greatly, and the stress of the casing will also increase greatly, which may place the casing above the yield strength and cause casing damage in the overlying strata section.

5.5. Effect of Cementing Strength on Casing Damage

Wellbore integrity is a necessary condition to ensure the safe production of oil and gas wells. Compared with the cement ring, casing, and formation body, the interface between the three is a weak link. In production practice, it is found that some oil and gas wells show good cementing quality through logging after cementing; however, there are oil, gas, and water phenomena at the wellhead during actual production. The analysis shows that the cementation failure of the first and second interfaces is caused by the change in temperature and pressure during the operation, which leads to the flow of bottomhole fluid to the surface through the micro-annulus, and the wellbore integrity is damaged. Due to the influence of high temperatures, the thermal deformation properties of the casing and cement ring are more different than those of the cement ring and formation. Therefore, the casing–cement ring interface is more prone to failure than the cement ring–formation interface, and the failure of one interface will cause casing axial elongation. Therefore, the thermal recovery well interface is chosen as the main research object. The device is shown in Figure 15.

G-grade oil well cement was selected as the test cement. The casing section was first inserted into the cement curing tank to ensure a good fit between the simulated casing and the outer tank. The prepared cement slurry was poured into the wall of the casing pipe and then placed in a water bath for curing for 7 days at a curing temperature of 25 °C. The gland is covered on the top of the casing, and a screw is placed on the upper part of the gland, as shown in Figure 16.

The press load is transferred to the gland through the pressure plate to ensure that the axis of the simulated casing coincides with the axis of the press. Start the press, adopt the constant displacement loading mode, and the loading speed is 0.05 mm/min. When the pressure increases to a certain value, the interface between the simulated casing and cement will be damaged, and the simulated casing will be extruded from the cement. The maximum load during the loading process will be recorded, and then the above steps will be repeated to record the experimental data. The test data are shown in Figure 17.

The maximum pressure recorded during the loading process is converted into bond strength using the following formula:

$$S=F/\pi DH$$

(9)

where S is the bond strength at the interface, in MPa; F is the maximum pressure at interface failure, in N; D is the diameter of the simulated casing, in mm; and H is the length of the simulated casing in contact with the cement, in mm. The test result data are shown in the following

Table 10. Test results.

Casing Diameter (mm)	Contact Length (mm)	Failure Load (kN)	Bond Strength (MPa)
140	11.7	160	3.11

.

A simulation of the connection between the cement sheath and the casing was conducted to study casing damage in thermal recovery wells under different junction conditions. Under various junction strength conditions, different degrees of relative slippage occur between the casing and the cement sheath, resulting in casing elongation and wellhead lifting phenomena. Partial loss of the cement sheath can also lead to casing damage in the form of deformation, narrowing, or other damage due to uneven external loads.

As shown in Figure 18 and Figure 19, at different junction strengths, the maximum stress on the wellbore remains at around 682.4 MPa, with a relatively minor impact from the changes in cement sheath bond strength. Under different junction strengths, the maximum displacement at the wellbore increases as the junction strength components increase, with a more significant effect from the variations in cement sheath bond strength—complete detachment results in a substantial elongation. In the absence of detachment or fracture, the bond strength of the cement sheath does not directly affect the thermal stress on the casing wall. However, once a fracture occurs between the cement sheath and casing, it significantly increases the elongation, leading to wellhead uplift.

5.6. Thermal Stress and Yield Strength of Different Steel Grades of Casing

The N80, TP100H, BG110H, and TP130TT casings were selected as the steel grades of the simulated casing in the thermal production well. According to the experimental results that the property parameters of the relevant casing properties change with the temperature at normal temperature, the material properties at a high temperature can be obtained according to the empirical formula of the strength attenuation of the casing under high-temperature conditions of steam injection, as seen in

Table 11. Casing steel strength properties.

Casing Steel Grade	Outer Diameter (mm)	Yield Strength (MPa)	Elastic Modulus (GPa)
TP130TT	177.8	985.1	165
N80	177.8	582.5	146
TP100H	177.8	812.2	176
BG110H	177.8	837.7	180

.

When using N80 casing, the thermal stress experienced by the casing exceeds the casing’s yield limit. However, when using TP100H, TP130TT, and BG110H casings, the entire casing’s thermal stress remains within the casing’s yield limit. N80 casing exhibits a much larger plastic deformation range compared to other casings, as shown in the Figure 20. The difference among different casings in total elongation is not significant. Simulated responses of different steel grades of casings under thermal loads are shown in the following Figure 21 and Figure 22.

6. Optimal Design of Steam Injection-Production Well

According to the simulation results obtained in the previous paper, the optimal design of the injection-production parameters can be obtained by fitting the influence law of the injection-production parameters on casing damage as follows: The common steam injection rates of 4, 6, 8, and 10t/h in steam injection-production wells are selected as reference steam injection rates. The effects of different injection and production parameters on casing stress under 350 °C, 320 °C, 300 °C, 280 °C, and 250 °C conditions are obtained, as shown in the following Figure 23, Figure 24, Figure 25 and Figure 26.

For a steam injection well with a steam injection rate greater than 10 t/h, the maximum thermal stress is consistent with 10t/h. The steam injection parameters selected in the chart are based on the range of steam injection parameters of the casing-damaged wells. Three casing-damaged wells in this block were selected for the optimal design of injection and production parameters, as shown in the following

Table 12. Optimization design of injection and production parameters of casing damage well.

Well No.	Development Method	Wellbore Type	Production Days	Casing Damage Cycles	Casing Steel Grade	Injection Pressure (MPa)	Injection Temperature (°C)	Steam Volume (m3)
1	Steam Injection	Vertical Well	1329	11	TP100H	14.7	350	33,503
2	Steam Injection	Vertical Well	3253	5	TP100H	8.2	350	35,436
3	Steam Injection	Vertical Well	2099	10	TP100H	17.3	350	52,739

.

In comparison to the previous optimized design, the optimization strategies for the injection and production parameters for the three wells are as follows: For well 1, reduce the steam injection rate (as it was too high). For well 2, decrease the steam injection temperature and implement better insulation measures to ensure production. For well 3, decrease the steam injection rate (as it was too high). As a result of the optimization of the injection and production parameters, it is expected that the casing damage cycles for these wells will be postponed by 2–3 cycles.

7. Conclusions

(1)

When using N80 casing, the entire casing experiences a thermal stress exceeding its yield limit. For the TP100H, BG110H, and TP130TT casings, thermal stress remains within the yield limit. Different casings under steam thermal stress show little difference in cross-sectional deformation and total elongation. It is advisable to avoid using N80-grade steel casing whenever possible. Instead, consider using higher-strength steel casing materials for the production zone and casing designed for thermal recovery, and use casing materials with greater resistance to external loads, such as TP130TT, for the sections exposed to mudrock hydration and other external loading conditions.

(2)

Different casings exhibit relatively similar cross-sectional deformation and total elongation under steam thermal stress loads. While an increase in the elastic modulus of the cement sheath may not lead to casing yield, it could induce plastic deformation in the cement sheath-formation structure, potentially affecting the bonding interface of the cement sheath and the casing.

(3)

An increase in local external loads leads to an increase in maximum casing principal stress, maximum deformation, and plastic strain. Stress at the casing’s inner surface increases with external load, while stress at both ends decreases. The opposite trend is observed for stress at the casing’s outer surface. Stress concentration can occur at both ends of the applied pre-stress, potentially leading to casing deformation or bending under non-uniform stress conditions.

(4)

Injection parameters, including pressure, have a limited impact on casing stress, with higher injection pressure leading to slightly higher inner wall pressure. The injection temperature significantly affects the casing’s temperature field and thermal stress; a lower injection temperature leads to reduced stress on the casing. The injection rate has a significant influence on the overall injection volume, with excessively high injection rates not improving the heating effect. The application of pre-stress can reduce the casing wall thermal stress but may increase stress at the wellhead. Adequate pre-stress can delay the casing damage cycle. Pre-stress exceeding 500 kN has an unclear effect on reducing thermal stress and can increase wellhead tensile stress. Excessive pre-stress may exceed the casing’s tensile strength.

(5)

For the existing shale oil steam injection wells, optimizing the injection parameters is essential. Controlling the appropriate injection parameters helps in safeguarding the casing and prolonging its lifespan. The application of suitable pre-stress to shallow wells can alleviate casing wall thermal stress and extend the casing’s operational life. Additionally, employing better insulation methods, such as vacuum insulation pipes and nitrogen insulation, aids in enhancing steam injection efficiency, reducing heat loss, lowering casing wall temperatures, and effectively controlling thermal stress.

(6)

Implementing more effective insulation methods, such as vacuum insulation tubes and nitrogen insulation, can help enhance steam injection efficiency, reduce heat loss, lower the temperature on the casing wall, and effectively control thermal stress. Improving the quality of cementing for the wellbore is essential. In sections with poor cementing quality, it is crucial to prevent significant relative slippage at the interface. In areas prone to slippage between the casing and the external cement sheath, appropriate roughening of the casing’s outer surface can be applied to prevent complete detachment of the cement sheath from the casing.

(7)

For the existing shale oil steam injection wells, it is advisable to optimize the steam injection parameters, controlling them within a reasonable range to protect the casing and extend the casing’s lifespan. Applying appropriate pre-stress to shallow wells can alleviate thermal stress on the casing wall and delay the onset of casing damage.