Study on the influence of mechanical characteristics of multi-rhythm inter-salt shale oil on fracture propagation in Qianjiang formation, China

There are many inter-salt rhythmic shale reservoirs in Qianjiang sag, and the mineral composition content with different rhythms is different. The thin interbedding characteristics of inter-salt shale oil reservoirs bring technical challenges to hydraulic fracturing. Taking one shale oil well in Qianjiang depression as an example, the mechanical properties and interface characteristics of rock under temperature and confining pressure are analyzed. The physical simulation test of fracture propagation under different fracturing fluid is completed, and the effects of four different factors on fracture propagation are analyzed by numerical analysis method. The results show that the mechanical characteristic and failure modes with different rhythms are obvious differences. Under uniaxial and triaxial compression, glauberite mudstone and shale have high strength, and salt rock shows obvious plastic deformation characteristics. The interbedded rock has clear interface characteristics. The cohesion of glauberite mudstone and shale bedding surface obtained from direct shear test is 0.60 MPa and 0.99 MPa. The fracture morphology of inter-salt shale is mainly affected by the development degree of rock bedding. The mechanical parameters, in situ stress difference, and the displacement have an important impact on the longitudinal propagation of fracturing fractures. The width and height of fracture propagation decrease, with the increase in the minimum horizontal principal stress in the salt layer, and the width of fracture in shale increases. The crack height decreases with the increase in tensile strength of the interlayer. With the increase in fracturing fluid injection rate from 3.0 to 7.0 ml/min, the propagation height of hydraulic fractures and the width of fractures in shale increase significantly. The research results can apply to understanding the mechanism of hydraulic fracture propagation in inter-salt shale formation.


Introduction
Shale oil resources are formed in continental sediments, and it is characterized by new stratigraphic age, frequent phase transformation, multiple types of organic matter, low degree of evolution, low content of brittle minerals, high content of clay, and poor diagenesis (McGlade et al. 2013). The Qianjiang formation developed 193 rhythm layers in Jianghan Basin in China (Fan et al. 2019), covers an area of approximately 4500 km 2 (Hou et al. 2017), and has an approximately 4-km-thick hypersaline sediments consisting of four major units (Li et al. 2018). There is a set of organic-rich shale oil between inter-salt beds, with a general thickness of 5-10 m for a single layer. The maximum cumulative thickness is more than 2000 m, of which Eqs. 3 and 4 unit are the best potential layers with shale oil. The main lithology of the inter-salt shale oil is the striated argillaceous dolomite rich in organic matter, the cloud mudstone, and the dolomitic mudstone filled with calcium and glauber. At present, the development in Jianghan Basin has attracted the attention of geological researchers .
In recent years, the study of inter-salt shale oil mainly focuses on geological evaluation. The brittleness evaluation was studied from core characteristics, brittle mineral composition, elastic parameters, and total stress-strain of rock (Fan et al. 2019). The pore structure of the saline shale in Eq. 3 unit of Qianjiang formation was characterized , and three main rock types are identified: (1) silica-rich carbonate mudstone; (2) carbonate/siliceous mudstone; (3) salt. The influencing factors of lacustrine shale oil were studied, and one formula for calculating brittleness index based on mineral composition method is proposed (Ma et al. 2019). The petrographic and geochemical characteristics of the salt-water lake shale were studied by organic geochemical analysis, X-ray diffraction, scanning electron microscopy, and low-pressure nitrogen adsorption analysis (Hou et al. 2017). The permeability and porosity of shale oil reservoirs are very low. Hydraulic fracturing is the main technology for effective and economic development. Changqing oilfield formed several straight hydraulic fractures (HFs) in shale oil zones with large horizontal stress difference (Tang et al. 2019). An equivalent method for evaluating production performance with complex hydraulic fracture networks in shale oil reservoirs was established . The results show that it is feasible to use the equivalent method to evaluate the contribution of fracture network to production.
Physical simulation of hydraulic fracturing is an important technique to study fracture propagation mechanism, a large number of hydraulic fracturing experiments have been conducted. A series of studies including confining pressure, injection fluid type, and injection section geometry were carried out to explore the dependence of fracturing. The results show that stress and fluid rheology have great influence on the fracture behavior of compacted sand (Bohloli and Pater 2006). The three-dimensional topography scanning system was used to quantitatively extract the fracturing fracture surface. Based on the three-dimensional fracture surface characterization, two quantitative evaluation methods for fracturing effect were established (Yang et al. 2022). The fracture propagation characteristics of fractured carbonate rock are closely related to the pumping mode and fracturing fluid (Guo et al. 2018(Guo et al. , 2020. Through fracturing test, the effects of horizontal stress difference, the angle between the cutting direction and the maximum principal stress on fracture propagation deflection are studied (Cheng et al. 2018). The results show that the DHF technique can realize the directional crack growth along the desired direction. Fracture direction and development are controlled by stress direction and magnitude, and the sample in homogeneities controls the hydraulic fracture development (Yashwanth et al. 2013). The initiation and propagation of fractures caused by supercritical CO 2 injection are mainly controlled by triaxial stress, which conforms to the general trend of continuum mechanics at high stress levels with large stress difference . Higher injection rate leads to higher breakdown pressure, while higher deviatoric stress leads to lower breakdown pressure . The effect of fractures and faults on pore pressure during reservoir fluid flowing through the reservoir is observed and evaluated by using the method of numerical simulation. This problem involves solving equations derived from Biot's consolidation theory (Ranjbar et al. 2022). The finite element model is established by using the bond zone method to study the influence of formation rock characteristics and underground stress state on the development of fracture height, and a cohesive zone method to predict the development of fracture height in formation (Pham and Anh Nguyen 2022). There are differences in the influence of different types of tight rock mass on the propagation of hydraulic fractures. The impacts include fracturing fluid type, pump injection capacity, stress conditions, lithologic characteristics, etc. In order to understand the mechanism of complex fracture networks in inter-salt shale oil reservoirs, it is necessary to understand the main factors affecting fracture propagation.
The inter-salt shale in Qianjiang formation is distributed in different rhythms; the characteristics of mechanical behavior are greatly different from those of gas-bearing shale. These are characterized by multiple lithologic interbedding, complicated mineral compositions, and low elastic modulus. Previous scholars' research on inter-salt shale oil mostly focused on geological genesis and oil & gas content. In the development of inter-salt shale oil & gas by unconventional technology, it is necessary to study the mechanical properties of inter-salt thin interbedded rock mass, which can be applied to the hydraulic fracture propagation, especially the influence of the difference in the longitudinal. In this paper, the mechanics characteristics and fracture patterns of typical rhythmic lithology were analyzed; the microstructure and shear characteristics of different lithologic interfaces were obtained. Hydraulic fracturing was carried out to study the fracture propagation in shale oil cores. The fracturing curve and the fracture morphology were analyzed. The effects of elastic modulus, in situ stress and tensile strength between salt rock and shale on fracture height are discussed. This research results can provide a reliable basis for optimizing hydraulic fracturing design in intersalt shale oil reservoir.

Geological characteristics and core preparation
Qianjiang sag is located in the middle of Jianghan Basin, China, with an area of 2530 km 2 . It is the deepest depression with the fastest subsidence rate. Longitudinally, it is formed by frequent interaction between salt rhythm and inter-salt sandstone, mudstone, and carbonate rocks, in which more than 190 salt rhythm layers are developed. Qianjiang formation is the main shale oil reservoir, and the supply of organic material is insufficient (Fan et al. 2019). The upper part of each rhythm is a salt rock section with a thickness of 5-20 m. The lower part is composed of micritic dolomite, mudstone, glauberite, and its migmatite, with a thickness of 3-8 m. Inter-salt reservoir is characterized by the development of shale, good hydrocarbon source, excellent reservoir, high oil content, overpressure, continuous distribution, and sealing of upper and lower salt beds, (Ma et al. 2019). All the shale oil samples are obtained from one deep exploration well (BYY2). The obtained drilling core is shown in Fig. 1. In order to ensure the mechanical properties and avoid core damage caused by bedding cracking during processing, all the samples required for the tests were processed by wirecutting equipment.

Mechanical properties of typical rhythmic rock
The typical rhythmic cores of inter-salt shale oil reservoir are selected. The size is a cylinder with a diameter of 25 mm and a height of 50 mm, and the parallelism of the end face is less than 0.03. The uniaxial and triaxial compression tests were completed by using MTS815 rock mechanics experimental   Figure 3 is the stress-strain curves of different samples under triaxial compression. Similarly, the peak deviatoric stress and deformation characteristics show great differences. For the same lithology, the peak deviatoric stress at 40 MPa is significantly higher than that of under uniaxial compression. The peak deviatoric stress 1 − 3 of glauberite mudstone at 40 MPa reaches to 290.88 MPa, and the elastic modulus is 14.96 GPa. Salt rock sample shows obvious strain hardening characteristics at 40 MPa. The increase in elastic modulus is 113.87% higher than that of under uniaxial compression. Through the comparison of rock mechanics, the properties of different small layers between inter-salt are differences; during fracturing design, it is necessary to define the small layer through which the well path passes. In the process of longitudinal propagation fracture, salt gypsum layer or shale with different lithology may be encountered. It is easy to expand from high elastic modulus layer to low elastic modulus layer. On the contrary, it is difficult for hydraulic fracturing fracture to expand longitudinally, which brings technical problems to the longitudinal expansion of fractures in thin-layer fracturing. Table 2 shows the mineral composition of typical lithologic cores. It can be seen from Table 2 that there is a large difference in mineral composition between different lithology. The differences of mineral composition and sedimentary environment lead to the differences of mechanical and fracture modes. Among the six samples, the quartz content of 2756# sample is 13.00%, and the corresponding compressive strength is the highest. There is a certain correlation between brittle mineral components and compressive strength.   Fig. 4 that there are great differences in damage modes under uniaxial compression. The shale and dolomitic shale with developed bedding are mainly multiple tensile fractures along the bedding plane, glauberite mudstone is a single tensile fracture plane, and salt rock has no obvious through fracture plane, which is only the local dislocation of salt rock crystal occurs. In Fig. 5, the results show that glauberite mudstone and dolomitic shale are dominated by a single oblique shear fracture surface. It can be seen from Fig. 5 that the mudstone sample contains not only the main shear fracture surface, but also the local bedding surface. Under triaxial compression, salt rock is mainly plastic deformation, there is no penetrating shear fracture surface, and several small vertical splitting cracks can be seen at the end.

Characteristics of inter-salt shale interface
In order to predict the longitudinal propagation of hydraulic fractures, it is of great significance to know the cement strength of salt-mud interface. Four groups of typical samples with different interface were selected, and the microstructure were analyzed by SEM. The results are shown in Fig. 6.
SEM scanning results show that: The crystal characteristics of salt rock are obvious and the structure is dense; due to the different mineral composition, the microstructure of the non-salt minerals is different, but they all show small particles and close arrangement; the structure of the saltmud interface is clear, and the small particle mudstone is fully filled in the interface gap, and well cemented, without loose large pores. There is no obvious fracture and pore in the interface between salt crystal particles and non-salt mineral particles. Compared with salt rock crystal, the mineral particles of shale are smaller and loose, and a large number of microns sized intergranular pores are developed.
The typical interface samples are selected, and the direct shear test is carried out to obtain the shear parameters. The micron CT was used to scan the interface. According to the lithologic characteristics, two groups of samples with different interface were divided. The CT scanning is shown in Fig. 7.
The results show that there are two kinds of interface forms, one is the clear interface, which reflects the sudden change in the sedimentary process, and the lithology  difference between the interfaces is large and obvious. The other type is that obvious lamination structure can be observed on the surface, and there is no obvious interface in CT scanning results. The interface reflects the shortterm discontinuous deposition of the same lithology, which is a typical bedding structure in shale, and an unreal lithology interface.
The shear test was carried out by RMT-150C controlled electro-hydraulic servo testing machine. The results are shown in Table 3. Figure 8 is shear stress-shear displacement curve under different normal stress. It can be seen from Fig. 8a that: in the early stage, with the increase in shear stress, the shear displacement gradually increases; when the shear displacement reaches a certain value, a step of slowly increasing stress appears. This is because when glauberite as a polycrystalline material break, the crystal first occurs brittle fracture, and with the increase in shear stress, sliding was inevitably occurred. For polycrystalline materials, the slip is multidirectional, which will lead to the accumulation of dislocations at the grain boundary, resulting in the rapid increase in shear strain and small increase in shear stress. When the shear stress reaches the peak value, it has obvious drop point. The shear displacement at peak shear strength increases with the increase in normal stress. It can be seen from Fig. 8b that the shear displacement increases slowly and the shear stress increases rapidly, approximate linear elastic stage. When approaching the peak shear stress, the shear stress increases slowly and the shear displacement increases continuously. No obvious shear stress drop point was observed. Figure 9 is the relationship between shear stress and normal stress. In general, Coulomb can be used for the shear strength in direct shear test. The cohesion of glauberite shale interface is 0.60 MPa, and the internal friction angle is 49.12°. The cohesion of shale bedding surface is 0.99 MPa, and the internal friction angle is 32.01°. The two types of interface cohesion are relatively low, belonging to the structural weak plane.
The interface characteristics are shown in Fig. 10. For cemented surface specimens, the shear section is serrated with debris. There are a large number of granular grains in the shear position, which shows that the shear failure of  Relationship between shear stress and normal stress glauberite containing calcium is not a plane, but a fracture zone (2834#). After cleaning the scattered grains on the surface, it is found that there are obvious scratches on the local section. It is consistent with the shear direction and is in a neat groove shape. Because the bedding of the shale sample is relatively developed, the bedding was shear damaged during the shearing process, which results in the interactive failure characteristics of the shear plane (1843#). After shear failure, the shear plane is smooth with obvious friction trace. During the shearing process, the fracture surface is ground flat due to the normal stress; it was shown that its shear resistance is weak.

Hydraulic fracturing physical simulation test device and process
Using triaxial rock mechanics experimental machine, a set of cylindrical fracturing physical simulation test system is constructed, and the overall structure is shown in Fig. 11. The test system is mainly composed of rock stress servo loading system, fracturing fluid injection system and acoustic emission detection system. The stress servo loading system is mainly used to provide the real stress. The fracturing fluid injection system mainly injects fracturing fluid into the simulated wellbore. The acoustic emission system is used to detect the micro-fracture signal in the process of hydraulic fracturing. The maximum output axial force is 2000 kN and the maximum confining pressure is 140 MPa. Maximum allowable specimen size is Φ 100 mm × 200 mm, equipped The high-pressure fracturing fluid injection system uses the American Teledyne isco-260hp high-precision, highpressure plunger pump as the power source of fracturing fluid. The maximum capacity of isco-260hp plunger pump is 266 ml; output displacement 0.001-107 ml/min, measurement accuracy ± 0.5% (maximum leakage 0.50 μ l/min). The maximum output pressure is 65.5 MPa, and the measurement accuracy is 0.1%. The acoustic emission preamplifier used is a 2/4/6 amplifier produced by American physical acoustics company (PAC), with a gain of 20, 40, 60 dB. The Phoenix 300 kV/500 W universal X-ray micro-focus CT system produced by General Electric Company (GE) is used to observe and analyze the spatial distribution characteristics of hydraulic fractures.

Fracturing sample preparation and test design
According to the simulation experiment, a simulated borehole with a diameter of 12.00 mm and a depth of 100 mm is drilled in the center of the cylindrical sample, a section of stainless-steel pipe with an outer diameter of 8.0 mm, a wall thickness of 1.5 mm, and a length of 86.50 mm is embedded as the simulated casing, and the casing is sealed with the wellbore with kraft k-9741 epoxy resin sealant. A ring groove is processed at the top of the casing to seal through the high-strength rubber sealing ring. The processed cylindrical sample is shown in Fig. 12. The acoustic emission probe shall be marked with a cross on the outer surface of the sample.
The deep well coring sample is used for hydraulic fracturing test. Three types of fracturing fluid (supercritical carbon dioxide, slick water, and gum guar) are designed. The confining pressure is set at 25 MPa, deviatoric stress is set at 4 MPa, the temperature is 95 ℃, and the displacement is 4.8 ml/min and 7.2 ml/min. The test operation process is as follows: (1) description: visually observe the bedding and natural crack development, and mark the distribution position of weak surface; (2) air tightness inspection: due to the relatively developed bedding, shear dislocation is easy to occur during sample preparation pump a certain amount of fluid into the wellbore, maintain the pressure at about 0.5 MPa for 3-5 min, and observe whether there is fracturing fluid seepage on the outer surface of the sample; (3) installation of acoustic emission probes: as shown in Fig. 12, install 8 acoustic emission probes on the surface of the sample, tightly bound the probes with coupling agent, and gently tap each probe at the same time to ensure that each probe can work normally; (4) stress loading: load the confining and axial stress to the specified value, and maintain it for 10-20 min to ensure uniform stress; (5) fracturing fluid injection: inject fracturing fluid into the sample according to the set displacement, and carry out acoustic emission detection at the same time. When the pump pressure drops obviously, close the plunger pump and acoustic emission detection system; (6) post fractures description: first take photographs to record the surface cracks of the sample, then select some samples to carry out post fractures CT scanning to quantitatively characterize the spatial distribution characteristics of hydraulic fractures, and finally cut the samples, track the hydraulic crack trend through trace display, and summarize the propagation law. Figure 13 is the record of experiment process.

Comparison and analysis of fracturing results
Six inter-salt shale samples, as listed in Table 4, were utilized for hydraulic fracturing experiments under triaxial stress. All the samples were formed obvious hydraulic fractures.

Characteristics of fracturing pump pressure
All the samples were applied to the predetermined value according to the set confining pressure and deviatoric stress. Three typical curves with the injection rate of 4.8 ml/min are shown in Fig. 14. The axial stress σ a = 29 MPa and confining pressure σ c = 25 MPa were applied on the specimens.
These curves reflect the pump pressure with time in the fracturing process, which can be divided into three stages. In Fig. 14a, in the initial stage of fracturing (0-200 s), due to the existence of wellbore cavity and primary fractures, SC-CO 2 enters such large space preferentially. A small number of AE events were generated. Wellbore pressure holding stage (200-1550 s), due to the strong compressibility of carbon dioxide, the growth trend of pressure is relatively flat. There was no AE event until the pump pressure exceeded 7.38 MPa in 1280 s. Under this pressure, CO 2 enters the supercritical state, its diffusion capacity is significantly improved, the primary fractures are continuously generated under the action of CO 2 , accompanied by the generation of new micro-fractures (Stanchits et al. 2014), and the pump pressure increases rapidly after CO 2 enters the supercritical state. In the fracturing failure stage (1550-1980s), the pump pressure increases rapidly to the fracturing pressure, the AE energy counting rate also increases significantly and stacking occurs, indicating that the fractures extend and expand rapidly. In addition, due to the ultra-low viscosity and zero interfacial tension of SC-CO 2 , the peak pump pressure quickly falls to the confining pressure. When the fracturing fluid is slick water and guar gum, the characteristics of the pump pressure curve tend to be consistent, as seen in Fig. 14b, c. The fracturing fluid initially pumped is mainly used to fill the space in the pipeline, and the pump pressure is maintained at a low level. When the pipeline is filled with  fracturing fluid, continue to pump fracturing fluid, the pump pressure increases rapidly to reach the fracture point, and more AE events are generated. After the sample is broken, the pump pressure gradually drops to the confining pressure, and forms a stable seepage channel.

Fracture morphology after fracturing test
The fracture characteristics under different fracturing conditions are shown in Fig. 15. It can be seen from Fig. 15  the primary bedding fracture is low. An uneven gray area is observed, which is considered to be the glauberite filling zone. It can be seen in Fig. 15c, e, multiple bedding fractures along the layer are produced. Glauberite shale (2988#) contains a certain degree of soluble salt components. During fracturing fluid injection, the salt rock dissolves, form a through passage without macroscopic cracks, as seen in Fig. 15d. The fracture morphology of inter-salt shale oil reservoir is mainly affected by the development of shale bedding. For the samples with weak bedding development, it is easy to form multi-fracture characteristics, while for the interval with undeveloped bedding, the fracturing is mainly simple fracture. The lithology diversity of inter-salt shale reservoir brings difficulty to the comparative study of physical simulation fracture propagation.

The propagation characteristics of fracturing fracture
There is generally salt gypsum interaction between the upper and lower shale oil target reservoirs. During hydraulic fracturing of shale oil and gas reservoirs, the expansion of fracture interbedding interface must be solved. In order to accurately describe the initiation and propagation process of hydraulic fractures in inter-salt shale oil reservoirs, it is necessary to study the fracture mechanism of hydraulic fracturing rock mass and the real shape of fractures.
Different shale layers are blocked by salt gypsum layer, resulting in unclear vertical expansion law of pressure fractures. Therefore, in the numerical simulation study, the influence of the mechanical properties and stress difference between the reservoir and the interlayer is mainly considered. There is no sedimentary lamina in the shale layer, and the fracture propagation under the complex fractures will continue to be studied. In order to reveal the influence mechanism of different lithologic characteristics on hydraulic fracture propagation, the fracture propagation characteristics of thin interbedded rock mass under

Theoretical basis of numerical simulation
Hydraulic fracturing is a typical multi-field coupling problem, which involves many disciplines such as seepage mechanics, rock mechanics, fracture mechanics, and damage mechanics (Cheng et al. 2018). When solving hydraulic fracturing problems, the dynamic coupling process of fluid flow and rock mass deformation is required. ABAQUS is realized by solving fluid continuity equation and stress balance equation, respectively. Cohesive element is a damage mechanics model using traction separation law. It can better deal with the singularity of crack tip and consider the fluid flow in the crack. It is the most widely used crack propagation technology at present. The cohesive element with pore pressure is used to simulate the initiation and extension (Carrier and Granet 2012), the laminar flow in the fractures and the filtration into the matrix. The coherent unit has two main functions: (1) Based on the traction separation criterion, the initiation and propagation are simulated; (2) Describe the tangential flow of fluid in the joint and the normal flow perpendicular to the wall.
The damage mechanism of the cohesive element follows the traction strain criterion, and the stress element is mainly used as the basis for the failure. Before the element is damaged, the displacement is directly proportional to the stress. When the stress reaches the ultimate strength of the material, the element begins to destroy, and the allowable stress decreases gradually with the increase in displacement until it is zero. Then, the element fails. Figure 16 shows the damage constitutive model of cohesive element in normal direction. When the normal displacement 0 of the element is less than the initial damage displacement, the normal stress increases with the increase in displacement. At this stage, the element is characterized by linear elasticity; the specific characteristics are controlled by the element penalty stiffness kn. When the normal stress of the cohesive element reaches the strength T max of the material, the element begins to damage. With the increase in normal displacement, the normal stress decreases gradually. The cohesive element is characterized by softening. When the normal displacement reaches the displacement f of complete failure of the element, the stress borne by the element is 0, and the element fails completely. (In Fig. 15, T is the tensile force obtained from the stiffness before the current strain is damaged, Pa; T max is the tensile strength of the material, Pa; T is the actual tensile stress, Pa; D is the damage factor; f , m , and 0 are the displacement when the element is completely damaged, the maximum displacement during loading and the displacement when the element is initially damaged, m.)

Model and parameters
The influence of various factors on fracture height is analyzed by two-dimensional model. According to the cementation of salt shale interface, it can be divided into two cases: one is that the interface is well cemented and there is no slip at the interface. The other interface is not fully cemented, and shear slip may occur between salt shale interfaces. Assuming that the stratum is a horizontal layered homogeneous stratum, the calculation model is shown in Fig. 17. In the model, the vertical direction is set with the cohesive element to simulate the vertical propagation of hydraulic fractures, the horizontal direction is set with the interlayer interface properties of the cohesive element, and the horizontal cohesive element can simulate the tensile and shear failure of the interface. Assuming that the interface between salt rock and shale is well cemented, there is no slip at the interface. The effects of elastic modulus, in situ stress, and tensile strength between salt rock and shale on the fracturing fracture height are discussed. The horizontal width of the model is 40 m, the vertical shale layer is 8 m, and the upper and lower salt rock layer is 7 m. The horizontal minimum in situ stress is applied on the left and right sides, and the vertical stress is applied on the upper and lower boundaries. The initial pore pressure is set at 45.6 MPa and the initial pore ratio is 0.2. Table 5 is rock mechanical parameters of formation. Table 6 is material parameters of cohesive element.

Analysis of the influence of different factors on the propagation of cracks
The influence of mechanical properties on the longitudinal propagation of fractures is not clear. Combined with the characteristics of high-quality target reservoirs, one shale reservoir interlayer geological model is constructed, and four main factors affecting are selected, including elastic modulus, tensile strength, reservoir-compartment stress difference, and pumping rate. In order to focus on the propagation characteristics of fractures when they pass through the interlayer, the laminar characteristics in the shale formation are not set in the geological model, and the following understandings are obtained. The simplified two-dimensional model is used in this calculation, and the crack propagation parameters in the direction of crack height can be obtained. Therefore, there is no analysis on the propagation law of hydraulic fracturing fracture length in this paper.

Elastic modulus
The elastic modulus of shale is taken as 14 GPa, and the elastic modulus of salt layers is taken as 3.0, 4.0, 5.0, 6.0, 7.0, and 8.0 GPa. In order to analyze the influence of the elastic modulus on the longitudinal propagation of fracturing fractures, take the fracture center as the origin (0, 0), and draw the shape of fracture height, as shown in Fig. 18.
As can be seen in Fig. 18, with the decrease in elastic modulus of salt layer from 8 to 3 GPa, the propagation height of the fracturing fractures in the salt layer decreases significantly. The study shows that when the injected fluid     Fig. 19 The fracture morphology under different minimum horizontal in situ stress volume and filtration amount are fixed, the crack width in the salt layer increases with the decrease in elastic modulus, and the fractures height will decrease sharply. Because the elastic modulus of the salt layer is significantly lower than the shale, it is difficult to form a high stress zone at the tip of the fracturing fracture, and it is difficult for the rock to expand forward under the same tensile strength. It can be seen that the salt layer with low elastic modulus is beneficial to the fracture height controlled.

In situ stress
Keep the minimum horizontal in situ stress of shale layer unchanged (77.30 MPa), and change the minimum horizontal in situ stress of salt layer gradually (73.3,75.3,77.3,79.3,and 81.3 MPa,respectively). The influence of the minimum horizontal in situ stress difference on the fracture height is obtained, take the fracture center as the origin (0, 0), and draw the geometric shape of fracture height, as shown in Fig. 19.
As can be seen in Fig. 19, the width and height of internal fracture in salt layer decrease with the increase in horizontal minimum principal stress at the same time; the width of fractures in shale reservoir increases. This is mainly because that the greater the minimum horizontal principal stress of the interlayer, the higher the net pressure in the fracture. On the premise of equal injected fluid volume, the wider the fracture in the reservoir, and more fracturing fluid will remain in the shale formation.

Tensile strength
Keep the tensile strength of shale layer 2 MPa unchanged, change the tensile strength of salt rock gradually (1, 2, 3 and 4 MPa, respectively), and obtain the influence of tensile strength on fracturing fracture height. The result is shown in Fig. 20.
As can be seen from Fig. 20, the crack propagation height decreases with the increase in tensile strength. The analysis shows that the fracture must overcome the tensile strength before it can continue to expand forward. Therefore, the interlayer with high tensile strength will limit the expansion of fracturing fractures.

Pumping rate
Keep other parameters unchanged, gradually change the fracturing fluid injection rate (3.0, 4.0, 5.0, 6.0, and 7.0 ml/min, respectively), and obtain the influence of different fracturing fluid injection rate on the fracture height. The result is shown in Fig. 21.
As can be seen from Fig. 21, when the hydraulic fracturing fracture extends from the shale to salt gypsum interlayer, the propagation distance of the fracture in the fracture height direction is different. With the increase in fracturing fluid injection displacement from 3.0 to 7.0 ml/min, the vertical penetration and expansion height of hydraulic fracture increases significantly, and the fracture width in the reservoir increases significantly. This is mainly due to the sharp increase of wear resistance along the way with the increase in fracturing fluid discharge. At the same time, on the premise of certain filtration loss, the total amount of injected fluid increases significantly, resulting in the increase in net pressure in the fracture, and the increase in hydraulic fractures width. However, with the increase in injection, there is no obvious continuous propagation feature in the fracture height direction, which is equivalent to the propagation along the fracture length direction.

Discussion
In this paper, MTS815.04 rock mechanics test system was used to study the characteristics of rock mechanics parameters and fracture modes of different sublayers of inter-salt shale oil in Qianjiang depression. There are two types of shale oil sublayers, one is shale with laminar development, and the other is argillaceous dolomite. The peak strength of rock mechanical parameters and the elastic modulus are obviously lower than that of shale gas reservoir (Wang et al. 2021). Hydraulic fracture propagation is closely related to the brittle plasticity of rocks. Therefore, the propagation of hydraulic fracturing fracture in inter-salt shale mass is affected. We have studied and observed the visible surface fractures and main fracture surfaces produced by hydraulic fracturing experiments in drilling core shale. Due to the limited number of downhole cores and the small size of specimen, no more hydraulic fracturing tests were carried out, and only qualitative understanding of fracture propagation characteristics under three different fracturing media was obtained. The complexity of the formed fracture is mainly related to the development of the inner lamina of the sample. The numerical simulation is used to simulate the fracture propagation in the reservoir, the simplified two-dimensional model is used in this calculation, and the effects of elastic modulus, in situ stress, and tensile strength between salt rock and shale on the fracturing fracture height are discussed. The longitudinal fracture propagation characteristics are mainly considered, and the crack propagation parameters in the direction of crack height can be obtained. Therefore, there is no analysis on the propagation law of hydraulic fracturing fracture length.

Conclusions
This paper studies the technical problems of fracture propagation in thin interbedded shale oil reservoir in Qianjiang depression. The differences of mechanical properties between different lithology are compared and analyzed, and a number of hydraulic fracturing experiments and numerical simulation were carried out to study the characteristics of fracture propagation; the following conclusions can be drawn.
1. The mechanical characteristic and failure modes with different rhythms are quite different. Under uniaxial and triaxial compression, glauberite mudstone and shale have high strength, while salt rock shows obvious plastic deformation characteristics.
2. The interbedded rock mass has clear interface characteristics. The cohesion of glauberite mudstone and shale bedding surface obtained from direct shear test is 0.60 MPa and 0.99 MPa, respectively. 3. The mechanical parameters, in situ stress difference between shale and interlayer, and the displacement of pumped fracturing fluid have an important impact on the longitudinal propagation of fracturing fractures. 4. The width and height of fracture propagation decrease, with the increase in the minimum horizontal principal stress in the salt layer, and the fracture width in shale increases. The crack propagation height of the interlayer decreases with the increase in the tensile strength. 5. With the increase in fracturing fluid injection displacement from 3.0 to 7.0 ml/min, the vertical penetration and expansion height of hydraulic fracture increases, and the fracture width in shale increases significantly.
Funding This work is supported by the National Natural Science Foundation of China (No. 52104046).

Conflict of interest
The authors declared that they have no conflicts of interest in this work. We declare that we do not have any commercial or associative interest that represents a conflict of interest in connection with the work submitted.
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