Deep Shale Reservoirs Research Articles

Determination and Application of Stress States Based on Finite Element Techniques: A Case Study of the Longmaxi Formation in the Luzhou Block, Sichuan Basin.

Knowledge of the present-day in situ stress field (PIS) has important theoretical and practical significance for shale gas exploration and development. The Wufeng-Longmaxi Formation in the Luzhou Block serves as the main reservoir of marine shale production in southern China. However, there is no clear understanding of PIS in the Luzhou area, which leads to a series of production problems. To investigate the PIS of deep shale reservoirs in Luzhou, experimental and finite element methods (FEMs) were used. Data obtained from imaging logging data, well deviation data, multipole array acoustic logging (XMAC), and world stress map were used to determine the orientation of the horizontal maximum principal stress (S Hmax). Additionally, acoustic emission experiments were employed to determine the magnitude of three principal stresses. Based on FEM, with the stress of a single well as a constraint, a three-dimensional (3D) stress field model was developed. The results show that the orientation of S Hmax varies from 90 to 120 °E. Further, there are significant differences in stress regimes across the region, with strike-slip/reverse faulting stress regime (S Hmax > S v ≈ S hmin) in the northern region and strike-slip stress regime in the southern region (S Hmax > S v > S hmin). In addition, geomechanical evaluations of wellbore stability and natural activation of fractures were performed. The Luzhou Block mainly develops two groups of natural fractures (NE-SW trending and NW-SE trending), with NW-SE trending being the dominant fracture development orientation. During the fracturing operation, a pore pressure increment larger than 50 MPa is conducive to maintaining a high opening ratio of the reservoir and improving the gas production efficiency. Horizontal wells drilled in the direction of maximum horizontal principal stress in the Wufeng-Longmaxi Formation reduce the probability of wellbore instability. The research results provide a reference for the effective development of deep shale gas reservoirs in southern Sichuan.

Molecular insights into dual competitive modes of CH4/CO2 in shale nanocomposites: Implications for CO2 sequestration and enhanced gas recovery in deep shale reservoirs

CO2 enhanced shale gas recovery has significant potential for improving the recovery rate of adsorbed gas and facilitating the geological sequestration of CO2. Nevertheless, the feasibility and microscopic mechanisms of CO2 enhanced gas recovery in deep shale gas reservoirs remain to be elucidated. In this study, a quartz-kerogen slit model was constructed to represent the shale composite nanopores of deep shale reservoirs. Utilizing the grand canonical Monte Carlo and molecular dynamics methods, the adsorption and diffusion behavior of CH4, CO2 and their mixtures was investigated under high-temperature and high-pressure conditions representative of deep shale reservoirs. The influences of temperature, pressure and aperture size were analyzed. The microscopic mechanisms governing the CH4/CO2 competitive adsorption in deep shale nanopores were uncovered by considering the competitive interactions between different rock constituents and quantifying the various gas storage states. The results show that the adsorption capacity of CO2 is greater than that of CH4 under the deep shale reservoir conditions. The replacement efficiency of CH4 by CO2 is higher in small shale pores. High temperature has a more significant negative impact on the adsorption of CO2 compared to that of CH4. Compared to mid-deep shale reservoirs, the nanopores of deep shale reservoirs have a higher proportion of free CH4/CO2 states. Quartz exhibits greater affinity for CH4/CO2 than kerogen, but kerogen possesses a larger specific surface area, resulting in a higher adsorption capacity per unit volume. The hierarchy of CH4/CO2 diffusion capacity in various storage states is as follows: dissolved gas in the kerogen matrix < adsorbed gas on the quartz surface < adsorbed gas on the kerogen surface < free gas in the pore center. This study improves the understanding of CO2 enhanced gas recovery in deep shale gas reservoirs.

Insight into the dynamic tensile behavior of deep anisotropic shale reservoir after water-based working fluid cooling

During deep shale gas production, flowing water-based working fluid inevitably cools shale reservoirs around boreholes and some fractures, and possible extraction methods induce dynamic stresses. To understand the dynamic tensile behavior of deep anisotropic shale reservoir after water-based working fluid cooling, a split Hopkinson pressure bar was used for performing the dynamic Brazilian tests on shale samples with bedding angles of 0°, 30°, 45°, 60° and 90° after reservoir temperature realization (25–200 °C) and water cooling. The results illustrate that dynamic tensile strength of shale samples decreases gradually as reservoir temperature increases under the loading rates 100–1000 GPa/s. From room temperature to 200 °C the most strength deterioration appears on samples with the bedding angle of 90°. A dynamic tensile strength deterioration model for deep shale reservoirs after water-based working fluid cooling is proposed considering the influence of loading rate and bedding angle. Geometrical trajectories of the main failure cracks are separated into three types, i.e., fully central tensile failure, tensile-shear failure and fully shear failure (sliding of bedding planes). For samples with bedding angles of 30°, 45° and 60°, increasing reservoir temperature encourages tensile failure to change into shear failure. The roles that bedding planes play in interacting with failure crack growth are summarized as IP mode (intersecting propagation), TP mode (turning propagation) and PP mode (promoting propagation). Anisotropic dynamic tensile strength responses are systematically discussed by using thermal stress simulation in ABAQUS, microstructure analyses, crack interaction conditions and the one-dimensional stress wave propagation theory. Based on experimental observations, field implications in borehole stability and fracturing of deep shale reservoirs are proposed under medium and high loading rates. This work is instrumental in providing valuable information and technology assistance for real deep shale gas production projects.

Analysis of Critical Instability Conditions for Solid-Phase Plugging of Natural Fractures during Temporary Plugging and Fracturing.

Hydraulic fracturing has become a key technology for the development of unconventional oil and gas resources, such as deep shale. Due to the development of natural fractures in deep shale reservoirs, the opening of natural fractures during the fracturing process can cause a significant loss of fracturing fluid, resulting in a reduction in the width of the main fracture and construction risks, such as sand plugging. It is important to improve the fracturing effect of deep shale reservoirs by plugging natural fractures with solid phases, reducing filtration, and improving the efficiency of the fracturing fluid. Ensuring the effectiveness of solid plugging is key to optimizing the fracturing design and improving the stimulation effect after fracturing. In this study, solid plugging technology is introduced into the filtration control process of natural fractures. By setting a plugging zone with a certain length and permeability inside the natural fracture, a stability prediction model for the plugging zone of natural fractures is established, and the instability conditions of the plugging zone are analyzed. The simulation results indicate that the instability of the plugging zone is related to permeability and there is a critical permeability. When the permeability of the plugging zone is greater than this value, expansion instability will occur, and when it is less than or equal to this value, shear slip instability may occur. The strength of shear slip instability is mainly determined by the length of the plugging zone, the friction angle of the natural fracture surface, the friction angle between the plugging particles, and the porosity of the plugging zone. The friction angle of natural fracture surfaces affects only the strength of slip instability, while the friction angle of plugging particles and porosity mainly affect the strength of shear instability. The research results provide a theoretical basis for the optimization of fracturing construction parameters in deep shale reservoirs.

A Study on Three-Dimensional Multi-Cluster Fracturing Simulation under the Influence of Natural Fractures

Multi-cluster fracturing has emerged as an effective technique for enhancing the productivity of deep shale reservoirs. The presence of natural bedding planes in these reservoirs plays a significant role in shaping the evolution and development of multi-cluster hydraulic fractures. Therefore, conducting detailed research on the propagation mechanisms of multi-cluster hydraulic fractures in deep shale formations is crucial for optimizing reservoir transformation efficiency and achieving effective development outcomes. This study employs the finite discrete element method (FDEM) to construct a comprehensive three-dimensional simulation model of multi-cluster fracturing, considering the number of natural fractures present and the geo-mechanical characteristics of a target block. The propagation of hydraulic fractures is investigated in response to the number of natural fractures and the design of the multi-cluster fracturing operations. The simulation results show that, consistent with previous research on fracturing in shale oil and gas reservoirs, an increase in the number of fracturing clusters and natural fractures leads to a larger total area covered by artificial fractures and the development of more intricate fracture patterns. Furthermore, the present study highlights that an escalation in the number of fracturing clusters results in a notable reduction in the balanced expansion of the double wings of the main fracture within the reservoir. Instead, the effects of natural fractures, geo-stress, and other factors contribute to enhanced phenomena such as single-wing expansion, bifurcation, and the bending of different main fractures, facilitating the creation of complex artificial fracture networks. It is important to note that the presence of natural fractures can also significantly alter the failure mode of artificial fractures, potentially resulting in the formation of small opening shear fractures that necessitate careful evaluation of the overall renovation impact. Moreover, this study demonstrates that even in comparison to single-cluster fracturing, the presence of 40 natural main fractures in the region can lead to the development of multiple branching main fractures. This finding underscores the importance of considering natural fractures in deep reservoir fracturing operations. In conclusion, the findings of this study offer valuable insights for optimizing deep reservoir fracturing processes in scenarios where natural fractures play a vital role in shaping fracture development.

Multi-fractal characteristics of pore system in deep organic-rich shales of the Wufeng-Longmaxi formation in the Sichuan Basin and their geological significance

The heterogeneity of pore system of deep shale reservoir determines the occurrence, enrichment and migration behavior of shale gas within shales. In this study, multi-fractal analysis was applied to analyze CO2 and N2 adsorption data for obtaining multi-fractal parameters including Hurst index and multi-fractal spectrum (D5--D5+) of the deep Wufeng-Longmaxi shales collected from the Sichuan Basin, China, in order to study the connectivity and heterogeneity of micropore pores and meso-macropores as well as their influencing factors. The results showed that pore system of the Wufeng-Longmaxi deep shale exhibits distinct multifractal nature. There exists significant differences in the pore volume (PV) of micropores (&amp;lt;2 nm), mesopore (2–50 nm), and macropore (&amp;gt;50 nm) across different shale lithofacies due to their differences in TOC content and mineral composition. The heterogeneity and connectivity of micropores and meso-macropores within deep shales in the Sichuan Basin are controlled by multiple factors including shale lithofacies, burial depth, and pressure coefficients. Notably, siliceous shale (SL) and calcareous/argillaecous siliceous shale (C/ASL), known as sweet spot for current shale gas exploitation, exhibits characteristics such as relative low micropore connectivity, high micropore heterogeneity, high micropore PV and low meso-macropore connectivity. These suggest that isolated pressure-sealing compartment is easier formed within the overpressured SL and C/ASL. Thus, pressure in these shales is less likely to release during the Yanshanian-Xishanian tectonic uplift process, favoring the preservation of organic matter (OM) pores and residual interparticle pores, which is conducive to the accumulation of deep shale gas dominated by free gas.

Thermal dynamics in deep shale reservoirs: Influences of the kerogen microstructural behavior on the gas adsorption/desorption capacity

In shale gas extraction projects, an investigation into the mechanisms of energy/mass transfer associated with shale gas adsorption/desorption in organic matter (kerogen) microstructure under high temperature and stress condition is crucial for improving the efficiency of shale gas production. This study presents a coupling thermo-hydro-mechanical model based on an improved fractal method that could explain the microstructural evolution of the kerogen system and the resultant alterations during the gas adsorption/desorption process under varying thermal conduction, gas seepage, and stress conditions. The influence of porosity, diameter, and tortuosity on the abundance, length, and complexity of kerogen networks under coupled multi-field effects is evaluated. The significance of this study is it could address the following aspects quantitively: (1) the spatiotemporal evolution of kerogen fractal dimensions following various extraction timelines; (2) the influence of shale temperatures on kerogen structures; (3) the influence of the kerogen fractal dimension on the shale gas desorption capacity and production efficiency; and (4) under different temperatures, when the fractal dimension/tortuosity fractal dimension of kerogen changes due to extraction disturbances, the volumetric deformation induced by gas adsorption increases by a maximum of 26.1%/decreases by 28.1% and in the later stages of extraction, the maximum gas pressure decreases by 44.7%/increases by 47.1%. The proposed fractal method adeptly reveals shale gas desorption behaviors under multi-field coupling conditions from a microscopic perspective, which cannot be found in the literature.

Evaluation of the combined influence of geological layer property and in-situ stresses on fracture height growth for layered formations

Fracture geometry is important when stimulating low-permeability reservoirs for natural gas or oil production. The geological layer (GL) properties and contrasts in in-situ stress are the two most important parameters for determination of the vertical fracture growth extent and containment in layered rocks. However, the method for assessing the cumulative impact on growth in height remains ambiguous. In this research, a 3D model based on the cohesive zone method is used to simulate the evolution of hydraulic fracture (HF) height in layered reservoirs. The model incorporates fluid flow and elastic deformation, considering the friction between the contacting fracture surfaces and the interaction between fracture components. First, an analytical solution that was readily available was used to validate the model. Afterwards, a quantitative analysis was performed on the combined impacts of the layer interface strength, coefficient of interlayer stress difference, and coefficient of vertical stress difference. The results indicate that the observed fracture height geometries can be categorized into three distinct regions within the parametric space: blunted fracture, crossed fracture, and T-shaped fracture. Furthermore, the results explained the formation mechanism of the low fracture height in the deep shale reservoir of the Sichuan Basin, China, as well as the distinction between fracture network patterns in mid-depth and deep shale reservoirs.

Model for fracture conductivity considering particle size redistribution caused by proppant crushing

Clarifying the dynamic evolution and control mechanisms of fracture conductivity is crucial for optimizing hydraulic fracturing design. Previous studies on fracture conductivity mechanisms in deep shale reservoirs have been insufficient, particularly when considering proppant crushing, rendering existing models inapplicable. Therefore, in this study, the coupled effects of particle size redistribution caused by proppant crushing were considered. A particle crushing model based on fractal theory was introduced. It was combined with the Kozeny–Carman equation, and equations were derived for the evolution of the equivalent diameter of the proppant pile gradation curve and permeability, establishing a new model for predicting the fracture conductivity considering the particle size redistribution caused by proppant crushing. Furthermore, it provides an optimized chart of conductivity that matches the supply conductivity of the reservoir. The results of the study reveal that the fracture conductivity decreases owing to proppant rearrangement, compaction, and crushing, with a more significant decline in the initial compression stage, where the rate of conductivity reduction is 2.5 times that of the compaction stage. Proppant crushing shifts the gradation curve leftward, reducing the equivalent particle diameter and, consequently, the fracture conductivity. By adjusting the crushing ratio, apparent Young's modulus, looseness factor, and proportion of large-particle components of the proppant, the fracture conductivity can be controlled. This provides a theoretical basis for the development of proppant properties and fracturing optimization in deep shale reservoirs.

Experimental study of hydraulic fracturing for deep shale reservoir

Compared with shallow reservoirs of shale gas, the high stress and plasticity of shale reservoirs under deep conditions significantly impact the propagation of hydraulic fractures. The study investigates the characteristics of hydraulic fracture propagation in deep shale reservoirs by conducting true triaxial fracturing tests at different stress levels and combinations under circumstances close to the original in-situ stress of the target reservoir. Specifically, it includes comparative experiments under high and low-stress levels, variable stress combinations with equal stress differences, and experiments on the influence of maximum and minimum horizontal in-situ stress, respectively. Through a series of experimental studies, it has been shown that the fracture roughness is relatively low at high stress levels. Fractures can still generate complex and multiple fractures when subject to high-stress conditions. Amongst, natural fissures or weak surfaces still dominate the complex fracture morphology. In the case of a higher in-situ stress level with the same stress difference value brings about a more complex hydraulic fracture morphology as a result of a smaller stress-difference coefficient. The Intersection of hydraulic fractures with multiple parallel weak surfaces creates hydraulic fractures in stepped shape, which can cause drastic fluctuations in injection pressure. The research results provide a reference for on-site deep shale reservoir stimulation and optimization of a fracturing design.

Integrated Analysis of Two-Phase Production Data in Hydraulic Fractured Deep Shale Reservoirs: Coupling Multiple Fluid Transport Mechanisms

Integrated Analysis of Two-Phase Production Data in Hydraulic Fractured Deep Shale Reservoirs: Coupling Multiple Fluid Transport Mechanisms

Multiple hydraulic fracture propagation simulation in deep shale gas reservoir considering thermal effects

Deep and ultra-deep shale gas will gradually become the focus of unconventional oil and gas resources in the petroleum industry. In the development of shallow shale reservoirs, the multi-cluster hydraulic fracturing of horizontal wells is the commonly applied technique to create a network of fractures and achieve reservoir stimulation. However, for deep shale reservoirs, the behavior of multiple hydraulic fracture propagation is affected by stress interference between fractures. On the other hand, it is also influenced by the temperature disturbances caused by the injection of low-temperature fracturing fluids into high-temperature formations and the resulting thermal effects. Currently, most research on multiple hydraulic fracture propagation in shale only considers the interaction between fluids and solids while neglecting thermal effects. Therefore, based on the displacement discontinuity method, finite volume method, and finite difference method, this study established a numerical model for the non-planar propagation of multi-cluster hydraulic fractures in deep shale, considering the thermal effects. And the model was validated through numerical solutions of the temperature field and double-fracture propagation. Moreover, the number of fracture clusters, pumping rate, and formation temperature were selected as influencing factors, and the differences in multiple hydraulic fracture propagation with and without considering thermal effects were analyzed. The results show that as the formation temperature increases, the thermal effects become more significant, leading to greater differences in the morphology of multi-cluster fractures. Moreover, the thermal effects are more significant when the formation temperature exceeds 90 °C. Additionally, appropriately reducing the number of fracture clusters or increasing the pumping rate can to some extent mitigate stress interference between fractures and promote uniform fracture propagation. The findings of this study contribute to understanding the influence of thermal effects on multiple hydraulic fracture propagation and provide theoretical basis for the efficient development of deep shale gas.

Numerical analysis of hydraulic fracture propagation in deep shale reservoir with different injection strategies

Deep shale reservoirs are characterized by elevated breakdown pressures, diminished fracture complexity, and reduced modified volumes compared to medium and shallow reservoirs. Therefore, it is urgent to investigate particular injection strategies that can optimize breakdown pressure and fracturing efficiency to address the increasing demands for deep shale reservoir stimulation. In this study, the efficiency of various stimulation strategies, including multi-cluster simultaneous fracturing, modified alternating fracturing, alternating shut-in fracturing, and cyclic alternating fracturing, was evaluated. Subsequently, the sensitivity of factors such as the cycle index, shut-in time, cluster spacing, and horizontal permeability was investigated. Additionally, the flow distribution effect within the wellbore was discussed. The results indicate that relative to multi-cluster simultaneous fracturing, modified alternating fracturing exhibits reduced susceptibility to the stress shadow effect, which results in earlier breakdown, extended hydraulic fracture lengths, and more consistent propagation despite an increase in breakdown pressure. The alternating shut-in fracturing benefits the increase of fracture length, which is closely related to the shut-in time. Furthermore, cyclic alternating fracturing markedly lowers breakdown pressure and contributes to uniform fracture propagation, in which the cycle count plays an important role. Modified alternating fracturing demonstrates insensitivity to variations in cluster spacing, whereas horizontal permeability is a critical factor affecting fracture length. The wellbore effect restrains the accumulation of pressure and flow near the perforation, delaying the initiation of hydraulic fractures. The simulation results can provide valuable numerical insights for optimizing injection strategies for deep shale hydraulic fracturing.

Analysis of Fracture Network Formation Mechanisms and Main Controlling Factors of Methane Explosion Fracturing in Deep Shale Reservoir

Analysis of Fracture Network Formation Mechanisms and Main Controlling Factors of Methane Explosion Fracturing in Deep Shale Reservoir

Study on the induced effect of bedding weakness in deep shale gas reservoir on hydraulic fractures propagation

Shale gas, as an important unconventional oil and gas resource, plays an important role in energy supply. Due to the strong mechanical heterogeneity and compactness, which requires the use of fracturing to crush the formation to obtain industrial production capacity. Therefore, it is very important to analyze shale’s mechanical properties and fracturing propagation laws. In this paper, the shale numerical model is established by adopting discrete element method (DEM). The mesoscopic constitutive parameters of shale with different matrix and bedding strength are determined based on rock samples tests. The reliability of the model is verified by finite element method. And the fracture propagation laws under the influence of shale beddings are studied. The results show that the existence of bedding fractures leads to the nonuniformity of fractures propagation in shale reservoirs. The stress difference of 5 MPa and the approach Angle of 75° are the key factors affecting the interaction between hydraulic fractures and natural fractures. As the bedding number increases, the borehole pressure increases and the total number of fractures’ propagation decreases. The results provide a theoretical basis for further understanding of fractures’ propagation in deep shale reservoirs, and have important guiding significance for optimization and improvement of fracture complexity in the subsequent construction.

Study on Proppant Transport and Placement in Shale Gas Main Fractures

In this paper, based on the background of a deep shale reservoir, a solid–liquid two-phase flow model suitable for proppant and fracturing fluid flow was established based on the Euler method, and a large-scale fracture model was established. Based on field parameters, a proppant transport experiment was conducted. Then, on the basis of the experimental fracture model, proppant transport simulation under different influencing factors was carried out. The results show that the laboratory experiment was in good agreement with the simulated results. The process of proppant accumulation in fractures can be divided into three stages according to the characteristics of sand banks. The displacement mainly affects the sedimentation distance of the proppant in the first stage, and the viscosity of the fracturing fluid represents the strength of the fluid sand carrying performance. Compared with 40/70 mesh proppant, 70/140 mesh proppant is more easily fluidizable, the fracture width has less influence on proppant migration and placement, and the perforation location only affects the accumulation pattern at the fracture entrance, but has less influence on proppant placement in the remote well zone.

A thermal–mechanical coupled DEM model for deep shale reservoir: the effects of temperature and anisotropy

A thermal–mechanical coupled DEM model for deep shale reservoir: the effects of temperature and anisotropy

Shale brittleness evaluation under high temperature and high confining stress based on energy evolution

Deep and ultra-deep shale gas reservoirs are crucial targets for future natural gas development. Extensive research has shown the shale brittleness is closely associated with the hydraulic fracture network quality. However, the shale brittleness may be altered in deep reservoirs due to the high temperature and high geo-stress. At present, commonly used shale brittleness evaluation methods cannot distinguish the differences in energy evolution caused by different mineral components in shale rock. In order to distinguish this difference, this study innovatively proposes a shale brittleness evaluation method that considers mineral composition based on energy evolution. A high-temperature triaxial compression experiment was carried out on the Longmaxi Formation shale, its fracture mode was analyzed, and the brittleness of the shale was evaluated based on this innovative method. The results indicate that with increasing confining stress, the shale fracture mode transitions from brittle tensile-shear multi-crack penetrating fracture to brittle-plastic shear single-crack fracture, and the brittleness of shale shows a decreasing trend. Under low confining stress, the shale brittleness decreases with temperature. Under high confining stress, temperature is the non-main controlling factor of shale brittleness. This study provides valuable guidance for the design and optimization of hydraulic fracturing in deep shale reservoirs.

Quantitative characterization of the brittleness of deep shales by integrating mineral content, elastic parameters, in situ stress conditions and logging analysis

Deep shale reservoirs (3500–4500 m) exhibit significantly different stress states than moderately deep shale reservoirs (2000–3500 m). As a result, the brittleness response mechanisms of deep shales are also different. It is urgent to investigate methods to evaluate the brittleness of deep shales to meet the increasingly urgent needs of deep shale gas development. In this paper, the quotient of Young’s modulus divided by Poisson’s ratio based on triaxial compression tests under in situ stress conditions is taken as SSBV (Static Standard Brittleness Value). A new and pragmatic technique is developed to determine the static brittleness index that considers elastic parameters, the mineral content, and the in situ stress conditions (BIEMS). The coefficient of determination between BIEMS and SSBV reaches 0.555 for experimental data and 0.805 for field data. This coefficient is higher than that of other brittleness indices when compared to SSBV. BIEMS can offer detailed insights into shale brittleness under various conditions, including different mineral compositions, depths, and stress states. This technique can provide a solid data-based foundation for the selection of ‘sweet spots’ for single-well engineering and the comparison of the brittleness of shale gas production layers in different areas.

Influence of Engineering Parameters on Fracture Vertical Propagation in Deep Shale Reservoir: A Numerical Study Based on FEM.

The geometry of hydraulic fractures in deep shale facies is significantly affected by the longitudinal inhomogeneity of rock physical properties and stresses. Numerous studies have been conducted on the influence of the longitudinal inhomogeneity of rocks on fracture morphology. However, there is still a lack of research that simultaneously considers the reservoir dip, bedding plane interface, and longitudinal inhomogeneity of the reservoir. To fill this gap, a three-dimensional (3D) numerical model of multireservoir hydraulic fracturing, which takes into account the bedding plane interface, was developed using the finite element method (FEM). The Drucker-Prager elastic-plasticity criterion was incorporated to accurately represent the plasticity of deep shale. The research revealed the influence of the formation dip angle on fracture morphology. Additionally, the perforation layer position and pump rate were optimized based on the actual geological parameters in North Jiangsu shale reservoir. The study findings indicate that reservoir fractures with a formation dip are easily detected by the interface. However, it is not necessarily true that the larger the formation dip, the easier it is for fluids to enter the interface. Fracturing from high-strength and stress reservoirs to lower reservoirs promotes the propagation of fracture height and the connectivity of multiple reservoirs. On the other hand, fractures initiated from low-strength and stress reservoirs tend to be confined to adjacent reservoirs more easily. The pump rate significantly affects the vertical propagation of fractures. At high interface strength, fractures with pump rate below 2.4 m3/min can only propagate at the perforation layer. The limited fracture height in shale reservoirs is likely due to substantial energy consumption by the fracturing fluid at the bedding plane interface. These studies offer theoretical guidance for understanding the vertical propagation of fractures in a deep multilayer reservoir.