Composite salt formation is a high-quality caprock for oil and gas resources. The accident encountered in composite salt formation drilling is a big problem to be solved in the drilling process. According to statistics, nearly 50% of drilling accidents occur in composite salt formations. The composite salt formation is mainly composed of salt, gypsum, and interbed mud, and the lithology is complex and changeable. Therefore, it is very important to study the deformation mechanism and leading influencing factors of composite salt formation in view of the problem of frequent accidents in the drilling process. In this article, the creep parameters based on the constitutive equation of creep of salt rock are obtained by combining theoretical with experimental research. A three-dimensional directional wellbore mechanical model is established to analyze the influence of inclination on borehole shrinkage.

The salt gypsum layer refers to the formation with salt or gypsum as the main component. In the oil drilling industry, we usually regard the formation as mainly composed of sodium chloride or other water-soluble inorganic salts such as potassium chloride, magnesium chloride, calcium chloride, gypsum, or Glauber’s nitrate as the salt gypsum formation, that is, the salt gypsum layer. According to statistics, salt rocks in sedimentary basins are the best caprock, under which are buried a considerable amount of oil and gas resources in the world, especially rich unconventional oil and gas resources [1-3]. Therefore, the salt gypsum layer is not only the focus of the world oil industry but also the focus of our oil and gas resource development.

Along with the process of oil and gas exploitation, the shallow, easily recoverable resources are gradually exhausted, and the exploitation center is gradually transferred to the deep oil and gas resources. The salt rock with very low permeability and porosity is the best caprock, and the drilling of salt rock is unavoidable in the drilling process. The gypsum rocks, which are mainly composed of salt or gypsum, exist above oil and gas reservoirs. The gypsum rocks found in our drilling are mainly distributed in Tarim, Jianghan, Sichuan, Shengli, Zhongyuan, North China, Xinjiang, Qinghai Changqing, and so forth. Various accidents occurred in the drilling of the gypsum rocks in the above oil fields, such as sticking and squeezing casing.

Hambley et al. [4] improved the creep constitutive model of salt rock by fully combining the experimental and field data. Fossum et al. [5] determined the stress-related probability distribution function through the pure salt creep test and creep model. Weidinger et al. [6] established a composite plastic deformation model to explicitly consider the heterogeneity of the observed dislocation structure and calculated the transient creep and steady-state creep of salt rock with this model combined with the mechanical laws of dislocation motion. Urai et al. [7] discussed the process of dissolution and precipitation of microscopic salt rocks and discussed the effect of these mechanisms on the strain rate during long-term creep. Through the new method of mold creep experiment, Moosavi et al.[8] conducted the experiment under the condition of constant pressure 30.73–65.58 MPa. According to the power relationship between creep rate and applied stress, the stress index (n) was calculated to be 3.28 and 4.72 at low temperature and high temperature, respectively. Q (activation energy) is 40.7 kJ/mol at low temperature and 27.0 kJ/mol at high temperature. Zhou et al. [9] substituted the Newton damper of the classical original model with the Abel damper and proposed a new creep constitutive equation of salt rock based on Riemann–Liouville fractional calculus, which can be used to describe the nonlinear creep strain of salt rock. Zhu et al. [10] studied the microscopic mechanism of viscosity and damage behavior of salt crystals in the creep process, designed a model to compare three microscopic damage prediction strategies for salt crystals, and concluded that the creep model with damaged nodes has stronger ductility and can realize the smooth transition between steady-state creep and third-order creep. Orozco et al. [11] studied the effects of salt composition, temperature, stress difference, and well running time on the creep of salt rock by combining experiments and models to reduce accidents during drilling in salt rock. Orlic et al. [12] conducted geomechanical numerical simulations and concluded that the creep of salt rock depends to a large extent on the properties of salt, stress difference, and in situ temperature, which provides a basis for well reaming.

In view of the research on the stability of compound salt formation walls, Jin et al. [13] proposed to use brine mud appropriately and balance the dissolution rate of salt rock in the wellbore with the shrinkage rate by adjusting the concentration of chlorine (Cl) and NaCl, so as to prevent the blockage and sticking. Based on rock mechanics, Zeng [14] analyzed the effect of drilling fluid density on formation creep in deep salt-gypsum intervals after drilling and proposed a calculation model for calculating the creep pressure of salt-gypsum intervals. Zhang et al. [15] analyzed the difficulties of salt-gypsum formation drilling in the Tahe oilfield and used RWD (reamer while drilling), reasonable drilling assembly, and appropriate drilling fluid density to drill salt-gypsum formation. Zeng [16] took samples of gypsum salt layer in a deep well for a creep experiment, analyzed the change of creep pressure, drew the density map of drilling fluid, and combined with the dissolution law of gypsum salt rock, put forward the method of determining reasonable drilling fluid, which has been applied in actual drilling. Zhao et al. [17] concluded through experiments that layered salt rock is a special combination of soft rock with less elastic modulus and greater lateral deformation ability. Ye et al. [18] concluded through field analysis that in the drilling process of composite salt formation, polysulfone under-saturated saline-silicate drilling fluid could well meet the geological requirements in the drilling process, and appropriate adjustment of Cl content could achieve a dynamic balance between salt rock shrinking and salt rock dissolution. Zeng et al. [19] established a finite element 3D model of borehole shrinkage of composite salt formation with interbed salt rock, sand, and mudstone under the action of three-way in-situ stress, and obtained borehole shrinkage value of salt formation under mud density. Xu et al. [20] conducted experiments on uniaxial compression, triaxial compression, and creep to obtain mechanical characteristic parameters of salt rock and analyzed the creep mechanism of layered salt rock. Ma et al. [21] conducted a creep test on artificially pressed salt rock samples and determined that the creep law was similar to that of the natural core. They also determined the influence of various mineral component contents on creep through a triaxial creep experiment and concluded that the steady-state creep rate of samples with high content was lower. Based on theoretical model analysis, Chen et al. [22] determined the main influencing factors of gypsum rock creep and the direct factors of creep diameter shrinkage and proposed a method to predict the stuck time by reversing borehole diameter shrinkage. Zhao et al. [23] analyzed mineral components and physical and chemical functions of composite salt formations by microscopic analysis, analyzed the mechanism of borehole wall instability, and selected drilling fluid density and components suitable for composite salt formations by integrating various elements. Lin et al. [24] established a 3D composite salt layer model of salt rock–soft mudstone–salt rock and drew the density chart of drilling fluid, considering the creep between soft mudstone and salt gypsum layer. Li et al. [25] established and analyzed the model of salt creep causing dislocation to the stratum with dip angle.

In view of the research on directional drilling in salt formations, Zeng et al. [19] established a finite element 3D model of borehole shrinkage in composite salt formations with interbed salt rock, sandstone, and mudstone under the action of 3-direction in situ stress and obtained borehole shrinkage in salt formations with mud density. Zhao et al. [23] analyzed mineral components and physical and chemical functions of composite salt formations by microscopic analysis, analyzed the mechanism of borehole wall instability, and selected drilling fluid density and components suitable for composite salt formations by integrating various elements. Lin et al. [24] established a 3D composite salt layer model of salt rock-soft mudstone-salt rock and drew the density chart of drilling fluid, considering the creep between soft mudstone and salt gypsum layer.

The Tarim composite salt rock has strong rheological properties under high temperatures and high pressure. If the drilling fluid properties are not selected properly during drilling, borehole shrinkage, stuck pipe, and borehole wall collapse will occur in a very short time. The bearing capacity of the salt formation is low, and the pressure of the drilling fluid column exceeds the rock fracture pressure easily to produce tensile fractures, resulting in serious leakage. It is worth noting that there has been much research on borehole stability, diameter reduction, stuck pipe, and collapse of deep composite salt formations. However, in this article, based on the integration concept of geology and engineering, combined with geological, geomechanical, and engineering data, salt formation resistance to creep is studied, and a 3D multilayer mechanical model around the well is established. In this article, based on the creep mechanism study of deep composite salt formations in this block, a quantitative study on the relationship between depth and ground temperature resistance to creep mud density was carried out by using the 3D mechanical model around the well and numerical calculation.

After statistical analysis of a large number of on-site accidents in the Kumgalemu group, as shown in Figure 1, a total of 1532 times of stuck pipe, 151 times of loss, and 44 times of overflow occurred. Among them, 753 times of stuck pipe, 49% of the total, 72 times of loss, 48% of the total, and 20 times of overflow, 45% of the total. The salt rock section accounts for 49% of drilling accidents in the whole Kumgremu group and is the formation with the most frequent accidents. The gypsum-salt section is a composite salt layer of salt rock, mudstone, and sandstone. Among them, stuck pipe occurs most frequently, which is the main cause of drilling accidents. 46% of the strata where stuck pipe occurs are salt rock strata.

The composite salt formation is mainly composed of salt rock, gypsum, gypsum mudstone, and mud gypsum salt, with a thin layer of mudstone and argillaceous siltstone in the middle. Salt formations also have strong rheological properties under high temperatures and pressure and are prone to creep, which makes it easy to close and get stuck. Especially in deep wells and high-temperature conditions, the creep rate of salt formations can be as high as to close the bit immediately.

The constitutive relation of gypsum and salt creep obtained by many previous studies is as follows. Figure 2 for typical creep curve graph, t = 0 as the starting point, the force produced by the elastic deformation of specimen deformation; the creep curve was divided into 3 stages, the first I stage of creep into a transitional phase, at this stage of the strain rate decreases with the increase of time. The second stage is the steady creep stage, and the strain rate is a constant, which does not change with time. The third stage is the accelerated creep stage; the strain rate in this stage increases gradually, and finally, the shear failure of the rock will be caused. In drilling, the creep of stages I and II is very important. The creep of stage I is very short, and the creep variable is small, while the creep of stage II is long. Therefore, the creep of salt rock can be measured by the strain rate of the steady creep stage. The steady creep rate of salt rock is closely related to its structure and temperature pressure. To study the rheological properties of a specific salt rock is to determine the relationship between steady creep rate and temperature and pressure, namely, the creep equation.

Many studies have shown that the Weertman model is the main creep model of salt rock under high temperatures and pressure.

When the temperature is high, and the stress value is relatively small, the creep mechanism is dominated by dislocation climbing multilateralization. In this case, the power law can be used to describe the steady-state creep of salt rock:

ε˙=Aexp(QRT)σn

where A′ is the rheological constant and n is the nonlinear coefficient (generally n = 4–5, up to 7).

The rock samples were collected from the field or underground in the complex section of the accident. The temperature and pressure conditions were determined according to the actual temperature and pressure conditions at the time of the underground accident, and the rock creep simulation was carried out. The creep displacement of salt rock under different temperature and pressure conditions was recorded, the creep rate of salt rock was calculated, and the creep relationship of salt rock under high temperature and pressure was determined according to the power relation. Rock samples are the direct material and basis for the study of rock mechanical properties in a real stratum environment, so it is particularly important to collect rock samples in complex sections. The rock samples used in this study are all from natural outcrops in Keshen block. The samples collected include pure salt rock, gypsum salt rock, pure salt rock, mudstone complex, etc., which can be processed into standard test pieces for rock mechanics experiments.

In the rock creep experiment, the complex temperature and pressure conditions in the well are adopted to consider the creep behavior under different confining pressure (axial pressure) and temperature conditions, and the confining pressure (axial pressure) and temperature conditions under deep conditions are adopted to carry out high-temperature triaxial creep experiment considering the different effective stress and temperature of the formation. According to the parameters and results of triaxial creep tests, the creep constitutive relation, that is, the relation of steady-state strain rate with temperature and deviatoric stress, is fitted.

The experimental specimen, as shown in Figure 3, is a specimen from the same area as a uniaxial experiment. The experimental specimen specifications are 100 mm long and a diameter of 50 mm. Specimens 1 and 2 are the core of black and white alternate with, when the specimen processing, notice the halite is water soluble and easily affected with damp be affected with damp in the air, the dry processing method was adopted, the specimens processing for Φ50 mm × 100 mm specimen, and in the process of the experiment wrapped a layer of soft plastic film, to avoid the impact of air humidity.

This creep experiment adopts the lateral isobaric triaxial experiment, and the schematic diagram of the triaxial experiment is shown in Figure 4.

The experimental scheme is shown in Table 1. Under 25℃ and different confining pressures, 3 stage loading with increasing axial pressure was carried out, respectively, with each stage loading lasting 24 hours. The confining pressure of Salt Rock 1 (S1) is 15 MPa, and the 3 stage axial pressure is 20, 25, and 30 MPa, respectively. The confining pressure of salt Rock 2 (S2) is 5 MPa, and the 3 stage axial pressure is 20, 25, and 30 MPa, respectively. The confining pressure loading rate was 2 MPa/min, the axial pressure loading rate was 5 MPa/min to the target value, and the creep experiment was carried out.

By sorting out the experimental data of the two cores respectively and drawing the curves (Figures 5 and 6), axial strain and axial pressure, it can be seen that under different loading conditions, the creep of salt rock increases with the increase of time and gradually tends to slow until it reaches a stable creep. Creep experiments on the laboratory scale include transitional creep and steady creep phases. The creep rate under different conditions is obtained by fitting the steady creep stage, respectively (Table 2).

In Figures 6 and 7, the Axial strain (orange) represents the initial creep stage, while the Axial strain (green) represents the steady-state creep stage. The expression for creep rate is the axial strain of the steady-state creep stage divided by the steady-state creep segment time. It can be calculated that when the confining pressure is 15 MPa and the axial pressure is 20, 25, and 30 MPa, the creep rates of S1 salt rock are 8.573 × 10−9, 2.224 × 10−8, and 3.087 × 10−8 s−1. When the confining pressure is 5 MPa and the axial pressure is 20, 25, and 30 MPa, the creep rates of S2 salt rock are 1.969 × 10−8, 4.863 × 10−8, and 5.471 × 10−8 s−1.

It should be noted that due to the limitations of high-temperature conditions, the laboratory conducts salt creep experiments at 25°C. The results of the creep rate from the experiment at 25°C are compared with the salt creep experiment database from several laboratories (Figure 7). The creep rates obtained under 25°C conditions in our experiment are close to the result at 110°C in magnitude (strain rate is in the range of 10−9 to 10−8s−1) from the database. In this research, we can use the creep relationship analyzed from the result at 25°C. Further refinement experiments are needed in the future.

Considering the above characteristics of the creep curve and the fact that the creep of salt rock in the wellbore is mainly controlled by dislocation creep, the relationship between stress difference and creep rate can be summarized as the following equation:

ε˙=Aexp(QRT)(Δσ)2

Calculate the logarithm of both sides of the equal sign of the above equation, and get:

lnε˙=lnA0QRT+nln(σ1σ3)

Figure 8 shows how to fit n according to the preceding formula.

Then, fit A0, as shown in Figure 9.

According to the fitting, A0 is the material attribute parameter, and the fitting is 0.0866. Q is the activation energy, 10580 cal/mol; n is the power law exponent, and the fit is 1.125.

3.1. Establish the Inclined Well Model under the Condition of a 3D Longitudinal Multilay

The quantitative study of the relationship between stress, well inclination, and mud density is an important content for the stability of drilling borehole walls in composite salt gypsum formation. Because there are many sets of faults in the deep salt gypsum layer, it is the design requirement of engineering to carry out directional well technology and build an inclined well in the salt layer. The mechanical model is an innovative achievement of this research. The model connects the wellbore, salt rock experiment, and underground stress through the inclined well modeling under the condition of a 3D longitudinal multilayer. The characteristics of this model consider the 3D-inclined borehole stress field and the multi-interbedded characteristics of composite salt formations (Figure 9). The idea of concrete model establishment:

(1) Formation lithology distribution is the data basis of multiayer modeling. According to specific geological and engineering data, the mechanical model can be established to reflect the real formation lithology longitudinal distribution.

The 3D multilayer composite salt layer directional well model generally reflects the characteristics of salt rock and interlayer, with the aim of highlighting the main contradictions. In actual working conditions, the composition of layering and fine layers is very complex, and we will gradually refine it in subsequent work.

The lithology of the composite salt layer is complex. In the composite salt layer with interbedded gypsum, salt, and mudstone, the main rock types are salt rock, gypsum, gypsum salt rock, mudstone, gypsum containing mudstone, gypsum mudstone, salt mudstone, gray mudstone, and mudstone. It also includes some sandstones, such as argillaceous siltstone and gypsum siltstone. Some areas may also contain dolomite interlayers, with illite as the main mineral component, as well as chlorite and aged stones. This type of salt layer is the main component of gypsum salt layers encountered during drilling in China.

The main basis for setting the thickness of each lithology salt layer when establishing a 3D multilayer composite salt layer finite element model is the drilling log and rock debris description in the drilling geological engineering data. Taking a well in the Tarim Basin as an example, according to the exploration data and lithologic analysis, the lithology at horizon C5 is a composite gypsum salt formation (well section: 5198–5224 m), with an overall thickness of 26 m. According to the cuttings description of the good section, the cuttings from 5198 to 5201 m are gray gypsum mudstone with a thickness of 3 m. 5203–5207, 5209–5212, and 5217–5224 m are gray mudstone with thicknesses of 4, 3, 7, 5201–5203, 5207–5209, and 5212–5217 m are gypsum salt rocks with thicknesses of 2, 2, and 5 m, respectively. On this basis, when establishing a layered composite salt layer finite element model, in order to facilitate the study of salt rock creep characteristics, the overall model thickness is set to 20 m. Due to the similarity in physical parameters between the gypsum mudstone layer and the mudstone layer, the parameters of the mudstone are substituted into the finite element model, set to 11 m, and the thickness of the salt rock layer is set to 9 m. The above is the method for setting the thickness of each lithology salt layer in the layered composite salt layer finite element model.

  1. The specific data of wellbore design and construction are also the data basis for the establishment of the model, which can be used to establish the inclined well model under the longitudinal multilayer condition reflecting the real well inclination.

  2. The inclined well model can be simplified into a longitudinal stereoscopic model, which can reflect not only the mechanical properties of the whole large section of salt rock and mudstone but also the mechanical properties of the local multiple thin interbedded rocks in the large section of lithology.

  3. In the longitudinal stereoscopic model, the maximum horizontal stress, vertical stress, and minimum horizontal stress are applied in the three principal stress directions, respectively. In the salt layer, because the differential stress is very small, the principal stress applied to the salt layer is equal. The well is the central axis of symmetry in the 1/2 longitudinal multilayer. The vertical stress Sv is 151 MPa, the maximum horizontal principal stress SH is 156 MPa, the minimum horizontal principal stress Sh is 146 MPa, and the temperature is 115°C.

  4. The vertical stress Sv is 151 MPa, the maximum horizontal principal stress SH is 156 MPa, the minimum horizontal principal stress Sh is 146 MPa, and the temperature is 115°C.

  5. The effect of drilling mud density can be achieved by applying pressure to the wellbore wall.

  6. The reduction rate can be characterized by the ratio of the salt formation’s contraction displacement perpendicular to the inclined borehole wall to the borehole radius.

  7. After experiments and literature review, the composite salt layer is simplified as salt rock and the host rock (mainly mudstone), with the main difference being that salt rock has creep characteristics in terms of physical properties (Figure 10).

  8. The stress result presented in this article is the von Mises stress. Von Mises is a yield criterion, and the value of the yield criterion is commonly referred to as equivalent stress. It follows the fourth strength theory of material mechanics (shape change specific energy theory). The fourth strength theory suggests that shape change is the main cause of material flow failure. Plastic materials follow the fourth strength theory, and the results are more realistic. Mises stress is an equivalent stress, and its calculation formula is:

σv=(σxxσyy)2+(σyyσzz)+(σzzσxx)22+3(σxy2+σyz2+σzx2)
(1)

When the equivalent stress of the point stress state reaches a fixed value unrelated to the stress state, the material yields; in other words, when the material is in a plastic state, the equivalent stress is always a constant value.

Differential stress, also known as stress intensity, is the value of the first principal stress minus the third principal stress, which is an equivalent stress derived from the third strength theory of material mechanics set basic mechanical parameters as shown in the following table (Table 3).

3.2. Calculation Method of the Inclined Well Mechanical Model under the Condition of 3D Longitudinal Multilayer Composite Salt Formation

The inclined well model under the condition of a 3D longitudinal multilayer is a model to simulate the creep diameter reduction under the relation of well inclination, depth, and mud density. The specific application of this model is that it can be compared with the field resistance stuck in the directional well block according to experimental data and rules so as to ensure that the creep deformation is at the same quantity level. On the other hand, the drilling fluid density required to control creep can be determined by specifying the reduction rate, that is, the reduction ratio. Figure 11 shows the stress distribution of different strata. Blue shows salt rock, where the differential stress in salt is low due to creep characteristics, while blue corresponds to the situation where the differential stress is the lowest. At the same time, the results show that there is shrinkage displacement in the well wall of the salt layer. The model can quantitatively calculate the stress distribution and shrinkage of the inclined well.

3.3. Research on Inclined Well Model under 3D Longitudinal Multilayer Condition

The research was carried out based on the inclined well model under the condition of a 3D longitudinal multilayer. According to the field blockage data of a well, the well inclination of 39–42° and the depth of 5674–5711 m were studied, and the simulation time was set at 40 hours. Based on the creep relation under deep conditions, the shrinkage problem of the inclined well wall is studied.

The calculation model and field practice can be mutually verified. The Wells all have 700-800 m-long sections of salt rock, and the longitudinal continuous creep of large sections is stable and relatively controllable. One of the characteristics of a well is that there are many thin salt gypsum interlayers with strong creep in the middle mudstone section because the many thin salt gypsum interlayers inevitably aggravate the blockage and downhole complexity. The second feature is the incline Angle between the inclined well section and the formation. However, the ground stress, geometric dip Angle, and the dislocation trend of thin interbedded strata will increase the degree of blockage in the inclined section and deep section of the well.

The influence of different well inclinations on creep diameter reduction was studied. In other words, 30°, 45°, 60°, and 80° were used to simulate the well inclinations during the modeling of directional wells. When the inclination is 30° (Table 4), the differential stress distribution in the model shows that the internal differential stress in the salt formation (blue) is about 6.92–79.6 MPa, meaning that the internal differential stress in the salt is very small. The difference in the stress of mudstone and gypsum salt layer is 116.0–297.8 MPa. When the drilling fluid density is 2.3 g/cm3, the maximum wall shrinkage value is 2.04 × 10−2 m, and the shrinkage rate is about 8.5% (Figures 12-15, Figure 11).

The differential stress distribution in the model shows that the internal differential stress in the salt formation (blue) is about 7.41–77.3 MPa when the borehole inclination is 45° (Table 5), meaning that the internal differential stress in the salt is very small. The difference in the stress of mudstone and gypsum salt layer is 112.1–287.1 MPa. When the drilling fluid density is 2.3 g/cm3, the maximum wall shrinkage value is 2.54 × 10−2 m, and the shrinkage rate is about 10.5% (Figures 16-19).

When the inclination is 60° (Table 6), the differential stress distribution of the model in the figure shows that the internal differential stress in the salt formation (blue) is about 9.69–76.6 MPa, meaning that the internal differential stress in the salt is very small. The difference in the stress of mudstone and gypsum salt layer is 101.1–277.5 MPa. When the drilling fluid density is 2.3 g/cm3, the maximum borehole shrinkage value is 3.70 × 10−2 m, and the shrinkage rate is about 15.4% (Figures 20-23).

When the inclination is 80° (Table 7), the differential stress distribution of the model in the figure shows that the internal differential stress in the salt formation (blue) is about 8.13–75.51 MPa, meaning that the internal differential stress in the salt is very small. The difference in the stress of mudstone and gypsum salt layer is 109.2–277.7 MPa. When the drilling fluid density is 2.3 g/cm3, the maximum shrinkage value of the borehole wall is 4.18 × 10−2 m, and the shrinkage rate is about 17.3% (Figures 24-27).

The results show that the ratio of borehole shrinkage increases from 8.5% to 17.3% with the increase in borehole inclination, which has an important effect on the creep shrinkage of the borehole (Figure 28). Under the same formation depth, salt rock properties, drilling fluid density, and time conditions, the degree of blockage will be significantly increased with the increase of borehole inclination. Therefore, it is necessary to increase the drilling fluid density further to ensure stability in salt rock when the directional well has a large inclination.

As a comparison, add a reference scenario for simulation; that is, under the same other parameters. The salt layer does not exhibit creep behavior. On the basis of the above finite element model, the creep parameters of the salt rock were removed, and model simulations were carried out with well inclination angles of 30°, 45°, 60°, and 80° (Figure 29).As shown in Table 8, it summarize the reduced diameter behavior of elastic behavior and creep behavior under different wellbore inclination angles.

In this article, composite salt formation is taken as the main research object, and a series of studies are mainly carried out on accidents such as sticking caused by the creep shrinkage of salt rock during the drilling process of composite salt formation. First, the creep constitutive equation is determined as the power-law equation and the creep parameters of salt rock through the laboratory creep experiment. Furthermore, a 3D directional wellbore mechanical model of composite formation was constructed, and different drilling fluid densities were selected to simulate borehole creep shrinkage, and the drilling fluid density chart was drawn, which provided a basis for reasonable selection of drilling fluid density.

  1. The lithology of composite salt formations is complex and varied, and the causes of downhole accidents are also different. In drilling accidents in composite salt formations, stuck pipe occurs most frequently, and most of the stuck pipe is caused by creep shrinkage of salt rocks.

  2. The triaxial creep experiment of salt rock contains both the transitional creep stage and the steady creep stage. In the experiment, the confining pressure is kept constant, and the axial pressure is increased, the deformation of salt rock increases, and the creep rate accelerates accordingly. The creep parameters A0 = 0.0866, Q = 10580cal/mol, and n = 1.125 were obtained by fitting the creep results of salt rock, which can provide a basis for the subsequent numerical simulation.

  3. There is also a difference in borehole reduction ratio between different inclinations of boreholes in composite salt formations. Aiming at the creep characteristics of salt rock, the 1/2 finite element model of the wellbore is used to simulate 4 different incline angles in 3D formation. A certain inclination can be selected according to the underground stress and temperature conditions to study the relationship between borehole shrinkage and inclination. At depths of 5000–5800 m, the drilling fluid density was 2.3 g/cm3, and the well inclination was 30°, 45°, 60°, and 80°. The diameter reduction ratios were 8.5%, 10.5%, 15.4%, and 17.3%, respectively. The simulation results show that the inclination is proportional to the borehole shrinkage. With the enlargement of the inclination, the borehole shrinkage rate increases.

The data supporting the results are all included in the manuscript.

The authors declared that they have no conflicts of interest to this work.

The research is funded by the National Natural Science Foundation of China (No. 52174011) and research on reaming while drilling and open hole overlapping suspension technology of expansion pipe (No. 2021DJ4102).

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