ABSTRACT: Casing deformation induced by fault activation severely constrains the safety and effectiveness of shale gas hydraulic fracturing, yet current detection methods lack real-time accuracy. Therefore, this study investigates shut-in pressure characteristics to establish a real-time early-warning method based on log–log pressure derivative curves for identifying fault activation risks. Based on fracturing data from the Luzhou block, two typical fault activation patterns—network-like and strip-like fractures—were identified and characterized using a physics-based well-testing interpretation model established. Following model calibration and parameter sensitivity analysis, an integrated warning workflow was developed, in which fault-activation risk is diagnosed through interpretation of pressure response and log–log pressure-derivative morphology, with microseismic data used for validation. Results indicate that network-like fractures exhibit significant pressure drops (>5 MPa) with prominent "hump-and-valley" derivative signatures (peak >2), whereas strip-like fractures show moderate drops (3–5 MPa) with smoother derivative responses (1–2), distinguishing them from the matrix baseline. Sensitivity analysis further reveals that wellbore storage mainly affects the early-time response, while skin factor, fracture conductivity, porosity, and permeability mainly influence the intermediate-time morphology of the pressure-derivative curve. Field validation in the Lu203 block demonstrated the method's strong applicability, successfully predicting fault activation events with high accuracy. This study demonstrates that shut-in pressure analysis serves as an effective diagnostic tool for characterizing complex subsurface fault geometries and activation dynamics. By addressing the time-lag limitations of conventional approaches, the proposed early-warning system provides a practical basis for dynamic fracturing-parameter optimization and safer, more efficient field operations.

CO2 Geological storage and enhanced oil recovery (CO2-EOR) are key pathways for the low-carbon energy transition. In fractured shale reservoirs, however, injection-induced pore-pressure buildup and stress redistribution may reduce fault stability and threaten storage safety. To quantitatively evaluate fault stability, this study develops a three-dimensional numerical model including injection wells, hydraulic fractures, and high-angle faults, incorporating CO2 adsorption-desorption effects. Fault slip tendency (ST) is adopted as the activation criterion to characterize fault-stability evolution. Sensitivity analyses are conducted for key engineering parameters, including injection rate, cumulative injection volume, injection location, fault-well distance, and fracture half-length. Grey relational analysis is used to identify the main controlling factors. Results demonstrate a pronounced nonlinear response of fault stability to injection parameters. Under the investigated scenarios, the maximum fault slip tendency varies from 0.35 to 0.91, and a warning threshold of ST = 0.8 is used to identify potential fault activation risk. Specifically, increasing the injection rate from 3000 to 12,000 m(3)/d raises the maximum ST from 0.60 to 0.91, while bottom injection yields a maximum ST of 0.81, higher than top injection (0.52) and middle injection (0.35). Increasing fracture half-length from 90 to 180 m raises the maximum ST from 0.45 to 0.81. Grey relational analysis shows that the relative influence of the investigated parameters is ranked as cumulative injection volume > injection location > fracture half-length > injection rate > fault-well distance.

Fluid injection in fractured rock reservoirs can induce fault slip, potentially compromising subsurface integrity and triggering seismic events. Field observations in shale gas development suggest that the relative orientation between the wellbore and nearby faults influences the injection-induced fault reactivation behavior, but the controlling pattern remains unclear. This study develops a site-scale, three-dimensional, distinct-element model calibrated to the Luzhou region in Southwest China. Single-stage hydraulic fracturing is simulated to interact with a preexisting fault under nine intersection angles between the wellbore and the fault. The simulations show a consistent sequence of fluid penetration, stable sliding, and unstable stick–slip. The initial unstable slip is driven by pore-pressure-induced reduction in effective normal stress near the intersection region and by poroelastic stress redistribution during fracture growth. Elevated shear stress develops near the edges of the slipped patch and tends to advance ahead of the overpressure front. The results show a clear dependence of reactivation potential and slip consequences on fault orientation relative to the wellbore. The dependence is broadly consistent with Mohr–Coulomb predictions under the strike-slip stress regime considered here. Moderate intersection angle cases produce larger slipped areas and greater shear displacement. When the intersection angle is below 30°, unstable slip may be accompanied by borehole pressure surges and relatively larger microseismic events. These findings advance the mechanistic understanding of injection-induced fault reactivation and support more targeted prefracturing risk assessment and warning strategies during stimulation.

The presence of bedding planes (BPs) in shale gas reservoirs is considered as one of the main factors for contained hydraulic fracture (HF) height and understanding this mechanism is still open. In this paper, HF crossing BPs is modeled as nucleation of a new fracture at BP interface based on the dual criterion, which satisfies simultaneously a strength and a toughness condition. The fracture-nucleation size (FNS) is generated to allow subsequent fracture growth on the opposite side of the BP. Using a two-dimensional fracture-nucleation model, the small, finite FNS was first obtained through a predictor–corrector method against the known results for fracture growth in homogeneous rocks and shows its dependence on the rock properties and stress conditions. It was then employed in case studies with numerical results showing how the BP conditions affect the progressive growth of a nucleated fracture. The growth of an HF crossing BPs occurs with an intermittent growth speed. Under a vertical stress level of 100 MPa, the FNS is 2 mm, and numerically, this causes large computational cost and requires adaptive element sizes. When the BP aperture characterizing its pre-existing fluid conductivity is less than 10–7 m, the fracture crosses the BP, while for a BP aperture of 10–5 m, the fracture deflects into the BP. HF crossing becomes more difficult after it penetrates more layers and the modeled fracture height is comparable to that inferred from microseismic measurements. The difficulty in fracture nucleation can provide a useful model for height growth and containment.

Low-permeability coal seams are widely distributed in China, where gas drainage remains difficult and coal and gas outburst disasters are severe. To address the low efficiency of gas extraction and the limited stimulation range of single-hole fracturing, this paper establishes a model of multi-hole synchronous fracturing based on the three-dimensional discrete lattice method. The injection sequence, hole spacing, cluster spacing, and coal-rock Young's modulus are analyzed to investigate non-uniform fracture propagation and fracture network formation. The results demonstrate that the non-uniformity of fracture propagation is primarily governed by stress shadow effects and competitive fluid partitioning. The injection sequence affects fracture uniformity. Simultaneous fracturing yields relatively uniform fractures, whereas sequential fracturing enhances local complexity but entails the risk of frac hits. Excessively small hole spacing of 10 m to 15 m can generate complex fracture networks but induces intense stress interference. Conversely, excessively large hole spacing of 30 m to 40 m results in prominent unstimulated blank zones. Increasing cluster spacing facilitates the activation of more effective fracture clusters but diminishes inter-hole connectivity. Fracturing in low-modulus soft coal readily forms complex fracture networks yet exhibits weak fracture extension capacity. In high-modulus hard coal, fractures extend considerably along the principal stress direction but are less prone to propagate along horizontal planes, leaving unstimulated regions. On this basis, two comprehensive evaluation indices are proposed, namely the Coverage Matching Degree and the Well-Network Matched Fracture Area, and diagnostic charts for fracturing effectiveness applicable to different coal types are constructed. Based on the charts, optimization recommendations are put forward. For soft coal seams, a hole spacing not exceeding 20 m and a cluster spacing of 5 m to 8 m are advised to enhance fracture network complexity. For hard coal seams, a hole spacing not less than 20 m and a cluster spacing of 3 m to 5 m are recommended to ensure effective fracture propagation. The field tests show that the time required to achieve gas extraction in accordance with the standards was reduced by 46% by using multi-hole synchronous fracturing technology. These results verify the engineering reliability of the numerical model and the evaluation system. The research findings provide a theoretical basis and technical support for the optimal design, dynamic regulation, and effectiveness assessment of multi-hole synchronous fracturing in low-permeability coal seams.

Casing deformation induced by fault slippage, which leading by hydraulic fracturing, poses a significant challenge in shale oil and gas development in China, adversely affecting well productivity and operational longevity. To mitigate this issue, a novel rubber composite casing was engineered, comprising a conventional casing encased in an outer rubber sleeve designed to absorb shear displacement and safeguard the inner casing. Comprehensive indoor experiments were conducted using an Unconventional Gas Wellbore Simulation Test System (UGT) to replicate downhole conditions and evaluate the casing's response to fault slippage-induced shear stresses. The experimental results revealed that, under a 40 mm displacement load, the rubber composite casing exhibited no deformation, whereas conventional casings experienced deformations of up to 15 mm. The rubber composite casing demonstrated exceptional capacity to absorb displacement loads, enduring forces ranging from 98 to 115 tons. These findings substantiate the efficacy of the rubber composite casing in mitigating shear displacement, offering a robust technical solution for preventing casing deformation and enhancing the sustainable development of shale oil and gas resources.

Tight gas reservoirs are a key component of the global unconventional energy supply, yet their development is significantly challenged by inter-well interference. Quantitative methods for analyzing interference are scarce, and existing models often rely on idealized fracture assumptions. This study presents an inter-well interference model for tight gas reservoirs with complex fracture networks using the transient embedded discrete fracture model (tEDEM). The model incorporates heterogeneous hydraulic fractures, stochastic natural fractures, and coupled interflow between matrix and fracture systems, while considering reservoir stress sensitivity and gas-water two-phase flow. Four conceptual interference models are established based on fracture connectivity: matrix (Type I), natural fracture (Type II), hydraulic fracture (Type III), and hydraulic fracture-wellbore interference (Type IV). The degree of production interference (DPI) is defined as a quantitative measure. Sensitivity analysis shows that stress sensitivity and hydraulic fracture half-length significantly impact interference. An actual case study in the ZT tight gas block demonstrates intermediate interference (DPI = 0.11) due to natural fracture interactions. This study enhances the understanding of inter-well interference mechanisms, provides strategies to mitigate interference, and supports sustainable unconventional gas production.

Lost circulation of drilling fluid is one of the most common and costly problems in drilling operations. This highlights the importance of wellbore strengthening treatment sthat can utilize lost circulation materials (LCMs) to seal fractures associated with the wellbore. In this work, a numerical model accounting for the deformation of surrounding rock, fluid flow in the fracture, fracture propagation, and the transport of LCMs is presented to investigate the wellbore strengthening, from the fracture initiation to the fracture arrest, due to plugs formed by LCMs. The equations governing the rock deformation and fluid flow are solved by the dual boundary element method and the finite volume method, respectively. The transport of LCMs is solved based on an empirical constitutive model in suspension flow, and several characteristic quantities are derived by dimensional analysis. It is found that two dimensionless parameters, dimensionless toughness and normalized initial particle concentration, control the migration of LCM particles. The numerical results show that the dimensionless toughness influences the entrance and bridging of LCMs while the initial concentration controls the location of the particle bridging. When the initial concentration is larger than 0.8, the particle bridging tends to occur near the fracture entry. Conversely, when the initial concentration is less than 0.8, the particle bridging occurs near the fracture tip. This work provides an effective tool to predict the LCM transport and plugging in the wellbore strengthening process.

A good knowledge of in situ stresses, including their orientations and magnitudes at depth, is of critical importance in extracting unconventional oil and gas resources. In this paper, an efficient semi-analytical model is developed for accurately predicting the maximum horizontal principal stress magnitude based on the wellbore breakout shapes, which, unlike the vertical and minimum horizontal stresses, cannot be measured directly. In this paper, a semi-analytical model is developed based on the complex variable method to calculate the stresses and displacements around a non-circular wellbore and the Mohr–Coulomb criterion is used to evaluate the failure zones around the wellbore. The non-circular wellbore shape is directly used in the model for stress calculation, and the model requires only the outline coordinates of the hole, the elastic modulus of the material, and the magnitude and direction of the far-field stresses. The stresses obtained from the proposed semi-analytical model based on the complex variable method are compared against those obtained from the commercial finite element package ABAQUS, and the model is in excellent agreement with the finite element model for stress fields, showing its accuracy and efficiency. In addition, the model runs in a few seconds on a laptop computer, thus providing an effective technique for calculating stresses and displacements around a non-circular wellbore. It can be found that the stress distribution around the non-circular wellbore predicted from this model is different from those around a circular wellbore, especially when the wellbore has a large elongation. The proposed method will be useful to study the effect of the wellbore shape on the stress distribution around the wellbore and predict the evolution of wellbore breakout.

The fracture containment caused by the bedding planes (BPs) inside one deep pay zone is studied numerically by a hydraulic fracture simulator, with a focus on the effects of the frictional and conductive behaviors of the bedding plane on fracture nucleation on it and subsequent growth. The dual criterion proposed by Leguillon (2002, Eur. J. Mech. - A Solids 21, 61-72) is used for finding the fracture nucleation size (FNS), beyond which a mature fracture can develop. Like the size of the fracture process zone measured experimentally, the FNS is also on the order of millimeters. The numerical results for a field situation revealed that, under the conditions of in-situ stress of approximately 100 MPa, the FNS is around 2 mm, although it slightly increases with an enhancing injection rate. Using such an FNS, a smaller BP conductivity with an aperture less than 10-7 m generates vertical transverse fracture propagation, but for one with an aperture of 10-5 m, fracture deflection into the BP constrains fracture height. A small coefficient of friction can play a role in limiting fracture height when the BP is permeable. The existence of many permeable BPs with a relatively large conductivity in a pay zone would be likely to constrain the fracture height as found in the field.

During the hydraulic fracturing of shale gas in the southern Sichuan Basin, China, field monitoring data have shown that hydraulic fracture (HF) propagation is restricted by height and cannot sufficiently cover vertical pay layers. The geomechanical behavior of gas shale in this region creates heterogeneity between the layers, which is responsible for the height restriction of HF propagation and limits the safe and efficient development of shale gas reservoirs in this region. To study vertical HF propagation, we conducted a series of laboratory hydraulic fracturing experiments under true triaxial loading. Three kinds of heterogeneity factors were tested: stress, elasticity, and interface strength. Analysis of fracture morphology and injection pressure curves resulted in several findings: (1) four types of vertical HF shapes emerged: I-shape, restricted I-shape, T-shape, and H-shape; (2) HF was induced by weakly cemented interface(s) with height limitations, while a layer under larger stress (e.g., 6 MPa) restricted fracture propagation in the middle layers, and heterogeneous elasticity was resistant; (3) regarding the geomechanical status of Changning middle-deep gas shale, interface strength may be more significant than fracture height. This study demonstrates the role of vertical heterogeneity in limiting fracture height and provides theoretical support for hydraulic fracturing optimization in this region.

The study of fracture propagation in heterogeneous shale is a crucial prerequisite for the investigation of heterogeneous cluster and perforation parameters optimization. In this paper, we conduct a physical simulation fracturing experiment on heterogeneous shale to investigate the effects of various influencing factors, such as shale bedding, near-wellbore fractures, lithological changes, and the presence of fractures surrounding the perforation hole, on fracture propagation law and morphology. Our research demonstrates that during shale fracturing, shear dislocation typically occurs between layers, resulting in the separation of different layer planes. The main fracture primarily propagates through layers in a stepped manner. The presence of sandstone in heterogeneous shale significantly impedes fracturing fractures, causing significant distortion and deviation. As the scale of natural fractures increases, it tends to cause the fracturing fracture to twist and change direction. The natural fractures network can also lead to the distortion of fracturing fractures, albeit to a lesser extent than large-scale natural fractures. The presence of micro fractures parallel to the perforation axis surrounding the perforation hole enhances the ability of the main fracturing fractures to pass through natural fractures.

The discrete element method (DEM) is ideally suited for the study of mechanical behavior of particulate media. While serial DEM codes can readily handle models containing thousands of regularly shaped particles, the computational demands increase significantly once the problem size increases to hundreds of thousands or millions of particles. In our study of the mechanical properties of naturally deposited sands we adopted the Level-Set DEM (LS-DEM, Kawamoto et al. (2016)) which captures the kinematics and mechanics of a system of arbitrarily shaped 3D particles using level set function as geometric basis. Herein, we present a parallel, binning algorithm, which has been implemented and optimized based on the existing LS-DEM framework using C++. The binning algorithm effectively reduces the computational complexity from 0(n2) n 2 ) to 0(n). n ) . The code maps relationship between bins and particles with linked-list like data structure and manages MPI communication in two major phases: border/ghost exchange and across-block migration. Many performance- critical implementation details are managed optimally to achieve high performance and scalability. The new code shows excellent weak scalability, with a negligible serial fraction and a low parallel overhead, requiring only 5% of the computational resources used by the original LS-DEM code.

Hydraulic fracturing is crucial for extracting shale oil and gas. This technique involves creating fractures in rock formations to enhance reservoir development efficiently. Due to the complexity of shale rock, it is important to conduct multiscale investigations into the fracturing process. Despite extensive research, the technology for deep-underground shale hydraulic fracturing continues to advance as it moves deeper underground. This paper explores the existing technical challenges of shale fracturing, review the current status of physical experiments and numerical simulations, and highlight the importance of multiscale numerical simulation methods. Meanwhile, an integrated approach to optimizing fracturing designs for field cases is introduced. Finally, this paper summarizes the challenges and opportunities in shale hydraulic fracturing, aiming to provide fresh insights into the advancements of hydraulic fracturing technology. Document Type: Perspective Cited as: Huang, L., Liao, X., Fan, M., Wu, S., Tan, P., Yang, L. Experimental and numerical simulation technique for hydraulic fracturing of shale formations. Advances in Geo-Energy Research, 2024, 13(2): 83-88. https://doi.org/10.46690/ager.2024.08.02

Hydraulic fracturing operation as an effective enhancing coalbed gas production method is widely used in ultralow permeability coal seam. However, complex geo-stresses and high heterogeneity between natural cleats structure lead to difficulty predicting hydraulic fracture patterns. Fracture evolution behavior for fracturing operation in coal seams requires a better understanding. In this study, a 2D model of hydraulic fracture propagation was built based on the cohesive zone model of finite element method. The effect of orthogonal cleat system, in-situ stress, dig angle and construction parameters on fracture geometries were main investigated. The main conclusions were as follows: (1) According to the interaction types between hydraulic fracture and cleat system, ladder-shaped fracture and H-shaped fracture geometry was summarized. The difference between them was whether there were continuous and small pressure fluctuation stages. (2) When the horizontal stress difference coefficient was lower and larger than 3/12, fracture geometry was prone to present & Ncy; shape and ladder shape respectively. Besides, the dimensionless fracture length and the dimensionless fracture extension aspect ratio of fracture were increasing with larger horizontal stress difference coefficient. (3) The favorable condition for fracture extension was that the dig angle was 45 degrees. Hydraulic fracture tended to propagate along face cleats direction. (4) Larger fracture fluid displacement was beneficial to form more balanced hydraulic fracture geometry and promote large extension scale. As fracture fluid viscosity increased, the fracture geometries transformed from ladder shape to H shape.

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.

The first Geo-Energy Frontier Forum with the theme of u201Copportunities and challenges for geo-energy exploration and developmentu201D was successfully held in Wuhan, recently. The forum included 32 sessions, mainly focused on four directions: geo-energy development and reserve, petroleum geophysical exploration, oil and gas geology, and field development engineering. This paper summarizes the key findings in the 22nd session titled u201CReservoir stimulation for unconventional oil and gas resourcesu201D. A total of 17 experts and scholars participated in the presentations, covering a wide range of topics in unconventional oil and gas resources development. This research collectively highlighted the significance of reservoir stimulation techniques in unconventional oil and gas resource development, including research progress in fracture network modeling techniques, fluid pressure, rock mechanics, fracture propagation, and proppant migration in hydraulic fracturing.

Hydraulic fracturing has become the main technology for the efficient development of geothermal energy in hot dry rock (HDR), however, few studies on the propagation behavior and mechanism of HDR hydraulic fractures under high-temperature conditions have investigated. In this paper, a large-size high-temperature true triaxial hydraulic fracturing physical modeling apparatus is designed, and hydraulic fracturing experiments with it are performed to investigate the fracture initiation and propagation behavior in natural granite samples collected from Gonghe Basin, the first HDR site in China. The experimental results show that the designed high-temperature apparatus provides a constant-temperature condition during the whole hydraulic fracturing process and the maximum temperature can reach 600 °C, showing its ability to simulate realistic temperatures and pressures in both ultra-deep and HDR formations. Although the tensile strength of the rock samples remains almost unchanged at a temperature of 200 °C, the cooling effects of the fracturing fluid in high-temperature rock can induce the formation of microfractures and significantly reduce the rock strength, thus lowering the breakdown pressure and increasing the complexity of the hydraulic fracture morphology. Compared with traditional oil and gas reservoirs, the hydraulic fractures in HDR are rougher and the specific surface area of a single fracture is larger, which can be helpful for heat extraction. This study provides a basis for understanding hydraulic fracture geometries and field construction design in HDRs.