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 × 10
8 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 × 10
9 tons in geological reserves and 3.7 × 10
8 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
and under the action of the non-uniform forces
and
. 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.
where
is the average stress, in MPa.
is the deviatoric stress, in MPa.
is the maximum horizontal stress, in MPa.
is the maximum horizontal stress, in MPa.
is the principal direction, in °C.
The extrusion load acting on the casing can be calculated using the formula:
where
P is the extrusion load, in MPa.
is the density of the annular mud or cement slurry, in g/cm
3.
g is the acceleration due to gravity, in m/s
2.
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).
where
is the additional axial load, in MPa.
is the Poisson’s ratio of the casing.
is the increase in the internal wellhead pressure of the casing, in MPa.
is the increase in the outer wellhead pressure of the casing, in MPa.
is the inner cross-sectional area for the
jth casing section, in mm
2.
is the length of the jth casing section, in m.
is the cross-sectional area for the
jth casing section, in mm
2.
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:
where
is the radial casing thermal stress, in MPa.
is the circumferential casing thermal stress, in MPa.
is the axial casing thermal stress, in MPa.
is the coefficient of thermal expansion of casing, in 1/°C. T is the temperature change, in °C.
is the elastic modulus of the casing, in GPa.
is the calculation parameter.
is the casing inner diameter, in m.
is the casing outer diameter, in m.
is the elastic modulus of drilling fluid, in GPa.
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:
where
is the Mises equivalent stress, in MPa.
,
,
are the three principal stresses, in MPa.
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 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.
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.
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.
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.
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.
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:
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.
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.
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.
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.