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In recent years, the rapid expansion and development of the shale gas industry in the Sichuan Basin has coincided with a series of unexpected moderate-sized earthquakes. Given that the Sichuan Basin is situated within a stable interior block, the focal mechanism of the 2019 earthquake sequence (ML4.7, ML5.4, and ML5.2) in the Weiyuan-Rongxian area remains a subject of debate. In this study, we propose a joint InSAR- and PCA- based inversion method utilizing the distributed Mogi model to investigate the spatial-temporal characteristics of a gas reservoir and evaluate the induced Coulomb stress change. The surface deformation derived from Sentinel-1 data between 2015 and 2021 was consistent with the spatial distribution of production wells, and it correlated with the temporal changes in reservoir volume associated with the shale gas operating process. The Coulomb stress loading on the regional faults suggests that human activities associated with shale gas operation likely triggered the three moderate earthquakes. Furthermore, our results indicate Coulomb stress loadings of 10 kPa, 15 kPa, 5 kPa, 3 kPa, and 87 kPa on the Dongxingchang fault, Gaoqiao fault, Dayaokou fault, Niujingao fault, and Lijiachang fold, respectively. Consequently, fluid injection and extraction during shale gas development could be contributing to the elevated seismic activity in the Weiyuan-Rongxian area. [ABSTRACT FROM AUTHOR]

Evaluating the physical mechanisms that link hydraulic fracturing (HF) operations to induced earthquakes and the anticipated form of the resulting events is significant in informing subsurface fluid injection operations. Current understanding supports the overriding role of the effective stress magnitude in triggering earthquakes, while the impact of change rate of effective stress has not been systematically addressed. In this work, a modified critical stiffness was brought up to investigate the likelihood, impact, and mitigation of induced seismicity during and after hydraulic fracturing by developing a poroelastic model based on rate-and-state fraction law and linear stability analysis. In the new criterion, the change rate of effective stress was considered a key variable to explore the evolution of this criterion and hence the likelihood of instability slip of fault. A coupled fluid flowedeformation model was used to represent the entire hydraulic fracturing process in COMSOL Multiphysics. The possibility of triggering an earthquake throughout the entire hydraulic fracturing process, from fracturing to cessation, was investigated considering different fault locations, orientations, and positions along the fault. The competition between the effects of the magnitude and change rate of effective stress was notable at each fracturing stage. The effective stress magnitude is a significant controlling factor during fracturing events, with the change rate dominating when fracturing is suddenly started or stopped. Instability dominates when the magnitude of the effective stress increases (constant injection at each fracturing stage) and the change rate of effective stress decreases (the injection process is suddenly stopped). Fracturing with a high injection rate, a fault adjacent to the hydraulic fracturing location and the position of the junction between the reservoir and fault are important to reduce the Coulomb failure stress (CFS) and enhance the critical stiffness as the significant disturbance of stresses at these positions in the coupled process. Therefore, notable attention should be given to the injection rate during fracturing, fault position, and position along faults as important considerations to help reduce the potential for induced seismicity. Our model was verified and confirmed using the case of the Longmaxi Formation in the Sichuan Basin, China, in which the reported microseismic data were correlated with high critical stiffness values. This work supplies new thoughts of the seismic risk associated with HF engineering. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing operations possess the capacity to induce the reactivation of faults, increasing the risk of fault slip and seismic activity. In this study, a coupled poroelastic model is established to characterize the distribution and movement of fluids within rock formations in the Shangluo region of Sichuan province, China. The effect of hydraulic fracturing projects on the variations of pore pressure and Coulomb effective stress within a high-permeability fault is analyzed. The potential fault-slip mechanism is investigated. The results show that the fault plays different roles for fluid movement, including the barrier, fluid transport channel, and diversion channel, which is related to injection–production schemes. In addition, fluid injection leads to a high probability of fault reactivation. We find that increasing the injection time and fluid injection rate can result in larger slip distances. The injection production scenarios influence the fault-slip mechanism, resulting in a normal fault or reverse fault. However, the arrangement of production wells around the injection can effectively reduce the risk of fault reactivation. [ABSTRACT FROM AUTHOR]

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The 2019 MS6.0 Changning earthquake occurred in the tectonically stable Sichuan Basin, where the epicenter and its adjacent areas are important shale gas and salt mine production fields, resulting in hot debates on whether the seismogenic mechanism of the 2019 Changning earthquake is related to human activities. As source characteristics and fluid pressure can provide important constraints on whether an earthquake is induced, we investigate the seismogenic mechanisms of the mainshock and 9 MW⩾4.0 aftershocks. In overall, the mainshock and the majority of the aftershocks are characterized by relatively shallow focal depths (1–4 km) and significant non-double-couple (non-DC) components. However, the mainshock and the aftershocks differ in two aspects: (1) the compensated-linear-vector-dipole components dominate the non-DC components of the mainshock, whereas the isotropic components dominate the most aftershocks; (2) the fluid overpressure of the mainshock is over 30 MPa, whereas the fluid overpressure of the most aftershocks is less than 10 MPa. Thus, we propose that the mainshock is triggered by weakened fault strength with long-term fluid injection, and that its large non-DC components are associated with complex rupture processes. Comparatively, the aftershocks may be triggered by postseismic stress transfer by combining the Coulomb failure stress changes in the poroelastic medium. Our results highlight the possible role of fluid in the occurrence of the Changning earthquake sequence. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

On 17 June 2019, an Ms6.0 earthquake occurred in Changning, Sichuan, China (Changning event), which was the largest earthquake on record within 50 km of the area. It attracted great attention as the area has the largest shale gas production in China as well as significant mineral salt production. Using the Interferometric Synthetic Aperture Radar (InSAR), we extract the coseismic deformation of the Changning event and two earlier Ms > 5.0 earthquakes which occurred in the same region (16 December 2018 Ms5.7 and 3 January 2019 Ms5.3) from the Sentinel-1 and ALOS2 data. We use nonlinear and linear methods to invert the fault models of the three earthquakes based on the deformation fields. The final model shows that the Changning event was caused by a fault with left-lateral strike and thrust slip. The strike is 124.3° with a dip angle of 43.4°. The seismic moment obtained by inversion is 5.28 × 1017 Nm, corresponding to Mw 5.78. Based on the fault models, we analyze the cause of the Changning earthquake considering the local tectonic setting, Coulomb stress change, mining, and fluid injection. We consider that the event may be related to salt mining. The two earlier Ms > 5.0 earthquakes may also play an important role in advancing the Changning earthquake. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The frictional stability of rocks is fundamental in controlling the instability and activation of faults. Given the strong correlation between seismic events in the Sichuan Basin of China and hydraulic fracturing for shale gas extraction, we conducted a series of velocity-stepping friction experiments with Longmaxi shale from the Changning shale gas extraction block under fluid injection. The experimental results indicate that the frictional process of Longmaxi shale can be divided into four distinct stages and the effective normal stress can demonstrate the influence of injection pressure. Additionally, the phenomenon of a decreasing friction coefficient μ with increasing effective normal stress can be explained by the frictional adhesion theory and a competitive mechanism between the deformation of asperities and microscopic dilatant slip. As the injection pressure increases, the friction state of Longmaxi shale transitions from velocity-strengthening to velocity-weakening, which is beneficial for potential seismic slip. After friction, the fracture surface experiences wear, and the surface morphology of the left and right parts exhibits a symmetrical distribution. With increasing effective normal stress, the morphological evolution of fractures becomes more prominent, which is related to the variation in the effective contact area. Based on the experimental results, we propose that the uneven distribution of fluid pressure on the Longmaxi shale fracture may also contribute to the transformation of frictional stability. When studying the frictional properties of rocks under fluid injection, it is also necessary to focus on the evolution of fluid pressure distribution on the fracture surface during the frictional process. • The frictional process of Longmaxi shale under fluid injection can be divided into four stages. • Pressurized fluid can accelerate the transition of Longmaxi shale from the V-strengthening state to the V-weakening state. • The morphological evolution of Longmaxi shale fracture is related to the variation in the effective contact area. • Uneven distribution of fluid pressure is also a presumable factor changing the frictional stability of Longmaxi shale. [ABSTRACT FROM AUTHOR]

The parameters of fractures, such as fracture geometries, placement, and conductivity, are critical for the production of horizontal wells in tight gas reservoirs. Current studies on fracture parameter optimization, especially those using the optimization algorithms, are often based on the assumptions that the fractures are uniformly placed with equal length and conductivity. However, non-uniform designs of fracture spacing have been proved to be effective in reducing fracture interference as well as increasing the well production, especially with strong rock heterogeneity. In addition, most of the current literature focuses on identifying optimal hydraulic fracture geometries without considering the fracture propagation process, which may oversimplify the evaluation of completion cost and result in fracture geometries that cannot be realized in practice. In this paper, an automatic optimization process, which could efficiently couple the fracture propagation, is proposed to optimize the fracture parameters. The genetic algorithm (GA) with penalty function method is used to optimize the constraint and non-linear problem. A modified PKN fracture propagation model is established to quickly predict the hydraulic fracture geometries. Fracture locations and fluid injection volume are sequentially optimized with consideration of heterogeneous rock properties. Model parameters are taken from typical tight gas horizontal wells in Jinqiu gas field in Sichuan Province, China. The results show the importance of permeability on both fracture length and production in tight gas well. The lower the permeability, the more significant the production increase after fracture location optimization. More fractures tend to be placed in area with small permeability and fewer fractures are required in highly permeable regions. With an increase in rock heterogeneity, the distribution of fractures becomes more uneven. Conversely, increasing the number of fractures can lead to a more even distribution of fractures. More fluid should be injected in low-permeability regions according to the optimization results. The optimization method is applied to a practical tight gas well in Sichuan Basin and the cumulative gas production can be increased by 6.5% to 8% when compared with the initial uniform designs. • A modified PKN model is proposed for quick prediction of fracture propagation, validated against numerical simulations. • GA is used to optimize fracture locations by considering rock heterogeneity's impact on fracture propagation and production. • Sequential optimization of fracture placement and injection volume is conducted with its reliability verified. [ABSTRACT FROM AUTHOR]

Accurate documentation of the location and geometry of seismogenic faults are critical for understanding strong seismicity and seismic hazard mitigation. A rising concern worldwide is induced seismicity caused by hydraulic fracturing, yet the geological characteristics and mechanisms of such seismogenic faults remain insufficiently understood. In particular, a first-order issue is whether the strong (M ≥ 5.0) induced earthquakes are caused directly by the slip of shallow faults near shale reservoirs or indirectly by deep basement faults. The September 16, 2021 Ms 6.0 (Mw 5.4) Luxian earthquake in the Sichuan Basin, China is one of the world's greatest induced earthquakes related to shale gas exploitation. Here we constrain the geometry of the seismogenic fault of this earthquake using three-dimensional seismic reflection data and a dense seismic array. Pre-existing faults in the sedimentary cover are clearly visible in seismic coherence slices. However, these shallow faults do not match the seismological parameters of the Luxian earthquake. High-resolution seismic reflection profiles combined with relocated earthquakes indicate that the seismogenic fault is located in the Precambrian basement. The results suggest that the mainshock is most likely caused by the poroelastic effects due to fluid injection. Hydraulic fracturing could have reactivated a large-scale basement fault and triggered the strong earthquakes under a relatively high geo-stress conditions in the study area. The basement fault slipped upward and ruptured the sedimentary cover, resulting in a significant difference between the focal and centroid depths of the mainshock. Our findings emphasize the importance of investigating regional tectonic and geological settings, local stress fields, and pre-existing faults for studying potential induced seismicity in shale gas fields. • High-resolution seismic reflection and seismological data indicate that a pre-existing basement fault triggered the Ms 6.0 Luxian earthquake. • Local stress conditions of pre-existing faults and fluid injection control moderate-size earthquakes directly. • Reactivation of pre-existing faults increases seismic risks associated with industrial activities in the Sichuan Basin. [ABSTRACT FROM AUTHOR]

Despite the ubiquity of hydrothermal fluid circulation in the crust, its timing is difficult to precisely determine using traditional thermometric dating due to strongly disturbed geothermal fields. We present a case study from the mid-Permian hydrocarbon-bearing dolostone reservoirs, situated proximally to strike-slip faults in the central Sichuan Basin (China), to highlight the utility of carbonate in-situ U-Pb geochronology in delineating the timing of hydrothermal fluid flow. Matrix and void-filling cement dolomite phases were identified in the porous Maokou Formation carbonates. Predominantly manifesting as saddle dolomites along fractures, these cements yielded statistically homogeneous U-Pb ages (242.5 ± 3.1 Ma, 238.9 ± 8.2 Ma, 244 ± 15 Ma, and 239.2 ± 6.5 Ma), slightly postdating the established stratigraphic timeline (ca. 273 to 259 Ma). The narrow temporal span suggests early emplacement following a short burial, compatible with the petrographic observation of burial stylolites crosscutting saddle dolomites. Integrating shallow emplacement depths inferred from a comparison between the dolomite U-Pb ages and a published burial history, with fluid-inclusion microthermometry, elucidates the hydrothermal system that was once present in this field. The pervasive occurrence of hydrofracturing, along with dolomite geochemical indicators represented by bell-shaped (REE + Y) PAAS patterns and elevated Y/Ho ratios, provide additional evidence for the hydrothermal fluid injection and resulting dolomitization. The dolomites' positive Eu anomalies and the parent fluids' 18O enrichment indicate a source from deeper basinal pore waters that have interacted significantly with ambient rocks. The overlying Triassic evaporites may have provided Mg-rich brines, mixing into the circulating hot fluids responsible for hydrothermal dolomitization. Our dolomite U-Pb ages coincide with the seismically estimated timing of transtensional strike-slip fault activation. This temporal correspondence, combined with spatial associations and lateral slickensides along fracture planes, suggests that the hydrothermal fluid movement is highly relevant to the active strike-slip faults. This observation reveals a previously unrecognized early-middle Triassic, structurally controlled hydrothermal activity in the region. We propose that this episode of hydrothermal circulation was driven by extensional tectonism in response to the spreading of the Proto-Tethys Ocean. This finding is not in line with the earlier research that considered late Permian Emeishan volcanism to have been the main trigger for hydrothermal fluid influx. The long-standing view regarding hydrothermal dolomitization in this region may need to be re-evaluated. • Dating hydrothermal circulation and associated dolomitization with carbonate U-Pb geochronology. • A previously unknown hydrothermal event in the Sichuan Basin. • Hydrothermal fluid circulation driven by strike-slip faulting. [ABSTRACT FROM AUTHOR]

The Lg-wave spectra are investigated for the 2019 Changning M L 6.0 earthquake and its 94 aftershocks with magnitudes above M L 2.8, which occurred in the southern Sichuan Basin, Southwest China. This earthquake sequence is potentially related to the water injection from nearby salt mining activities. Based on an established regional high-resolution broadband Lg-wave attenuation model, we correct the observed spectra for the attenuation effect along the propagation path. By fitting the observed spectra from the Changning earthquake sequence with the theoretical source model, we estimate seismic moments and corner frequencies, from which the stress drops are calculated for the entire earthquake sequence. The results show that the stress drops are rather scattered, ranging from 0.16 MPa to 32 MPa with a median value of 0.78 MPa. Spatiotemporal variation of stress drops reflects strong fault heterogeneity and a complex stress release process, which is likely influenced by water injection and diffusion. Positive trends are observed between the stress drop and focal depth and between the stress drop and seismic magnitude. Relatively lower stress drops for most shallow events are possibly the indication of lowered normal stress by long-term fluid injection. No apparent relation is observed between the stress drop and the distance to the Shuanghe salt mine, where water was injected. Combining the actual water injection data and previous numerical simulation studies, we suggest that the salt mining-related water injection may lead to elevated pore pressure beyond the source region of the 2019 Changning earthquake. The increasingly cumulated underground water may have created pathways linking multiple fault systems, thus the possibility of future large induced-earthquakes cannot be ruled out. • The Lg-wave source spectra are revised for the 2019 Changning earthquake sequence. • Stress drops are obtained by fitting source spectra based on the Brune's source model. • The lowered normal stress by long-term injection may lower the stress drops of most shallow events. [ABSTRACT FROM AUTHOR]

Accurate design of fracturing parameters in shale gas reservoirs does not only increase the productivity and profitability of wells but also minimize the damage fracturing fluids cause to fluid-sensitive formations. However, obtaining a highly accurate and optimized fracturing parameters with rapid as well cost-effective simulation run is difficult to achieve. This study proposed a framework for optimizing shale gas fracturing parameters based on least squares support vector regression (LSSVR) prediction model and non-dominated sorting genetic algorithm-II (NSGA-II). This framework was named the multi-objective optimization prediction model (MOO-PM). In the proposed framework, the flowback ratio of fracturing fluid (FBR) and first month gas production (PROD) were considered as the objective functions while the fracturing parameters including horizontal length, number of fractured sections, fractured length, fracturing fluid injection rate, fracturing fluid viscosity, volume of fracturing fluid and proppant amount were chosen as the optimization variables. Firstly, based on field data the LSSVR prediction model was established. Secondly, the accuracy of the model was verified by the remaining field data. Subsequently, the Latin Hypercube method was used to construct a sample set of fracturing parameters within a predetermined range of variables and the corresponding objective functions were calculated by the LSSVR method. Finally, Pareto front was used to generate flowback ratio and first-month production by the NSGA-II algorithm. To the best of our knowledge, this is the first time that LSSVR prediction model and multi-objective method are applied simultaneously to optimize shale gas fracturing parameters. Furthermore, the novel multi-objective optimization framework was applied to data from the Weiyuan as well as the Changning shale gas reservoirs in Sichuan basin, southwest China. It was concluded that this framework could optimize fracturing parameters of shale gas reservoirs with higher accuracy and efficiency. [Display omitted] • A multi-objective optimization method for fracturing parameters of shale gas is established. • LSSVR prediction model and NSGA-II algorithm are proposed to obtain the optimal scenario. • MOO-PM framework could obtain optimized results with higher efficiency. [ABSTRACT FROM AUTHOR]

As one of the most promising shale gas reservoirs in China, the Lower Silurian Longmaxi formation in the Sichuan Basin has produced a large amount of shale gas during the last few years. However, two significant concerns have been raised during the contemporary shale gas development in this area: dramatic increases in well depths and potential induced seismicity. The extreme depths have resulted in higher in-situ stress and reservoir breakdown pressures. The other concern is whether recent earthquakes are related to hydraulic fracturing operations since they are close in space and time. An advanced fluid injection protocol-cyclic fluid injection has been proposed and used to lower the breakdown pressure of reservoirs and mitigate the potential seismic risks caused by hydraulic stimulations. In this study, we combine a series of laboratory experiments and a numerical simulation model to investigate the breakdown mechanism, seismic risks, permeability enhancement performance of cyclic fluid injection. The results indicate that the cyclic injection method decreases the shale breakdown pressure by ∼25% compared with the conventional monotonic rate injection, which is the result of fatigue failure near the fluid injection borehole induced by pore pressure fluctuations lagging behind the periodical injection pressure changes. Even though more acoustic emission events are observed during and post-the cyclic injection, the maximum acoustic emission amplitude decreases by 26%, which is equivalent to transforming AE events with large amplitudes to more AE events with small amplitudes. Moreover, fracture morphology and permeability measurement results indicate that cyclic injection creates hydraulic fractures with higher fracture tortuosity but smaller aperture and lower permeability, which contributes to the fatigue mechanism of rock breakdown. Our experimental results and theoretical analysis initially validate the potential of using cyclic injection methods to perform hydraulic fracturing stimulation in shale reservoirs to lower breakdown pressure and mitigate seismic risks. [ABSTRACT FROM AUTHOR]

To evaluate the risk of induced seismicity due to hydraulic fracturing, a detailed stress analysis in a seismically active region, i.e., the Changning shale-gas field in the southern Sichuan Basin, was conducted utilizing sonic wave velocity logs and high-resolution electrical resistivity image logs of shale gas wells. Wells with relatively higher magnitudes of horizontal stresses are spatially located in the vicinity of thrust faults, in agreement with the stress concentration at the upper tip of the basement-involved thrust fault. The prevailing orientation of maximum horizontal principal stress (S Hmax) is N110°–120°E on the southwestern Changning anticline, which aligns with the motion of the Sichuan Basin, as driven by the continuous eastward extrusion of the Tibet plateau, which initiated at approximately 50 Ma. However, the S Hmax orientation is N30°–70°E along the northern Changning anticline, implying an inheritance of the N–S geodynamic compression during the Jurassic to Late Cretaceous. Drilling-induced tensile fractures primarily appear in compliant layers that are rich in clay or organic matter in wells located adjacent to thrust faults, suggesting that stiff layers can efficiently inhibit the hydrofracture growth height owing to more intense tectonic stress near thrust faults. A natural fault with a strike of approximately 30° to the S Hmax orientation can be more easily activated by extreme pumping pressure in wells that are weakly affected by the stress concentration along the thrust fault. Nevertheless, a cyclic injection of fracturing fluid with a gradually increasing target pressure may effectively reduce the magnitude of induced seismicity. • Detailed stress analysis of Changning shale-gas field using geophysical data. • Wells with higher horizontal stresses spatially located near thrust faults. • Drilling-induced tensile fractures appear in layers rich in clay or organic matter. • Stiff layers inhibit hydrofracture growth due to more intense tectonic stress. • Cyclic fluid injection with increasing target pressure may reduce seismicity. [ABSTRACT FROM AUTHOR]

Industrial production activities associated with salt mining, hydraulic fracturing, or geothermal exploitation can induce pore pressure and stress field changes, thus inducing seismic activity. Most of the events are not disastrous due to limited energy radiated. Here we report a Mw 5.8 damaging event that occurred in Changning, China on June 17, 2019, probably the largest induced event by industrial exploitation ever recorded. The earthquake is located within the Changning anticline, and it raises great concerns on why and how the event occurred in a relatively quiescent area in terms of tectonic activity. Moreover, it has been debated whether this earthquake ruptured solely on the fold-accommodation faults or also involved a deep-rooted fault under the anticline. By using InSAR data from two satellites, we investigate the detailed rupture and slip pattern of this earthquake. We propose a cascade rupture mode of the fold-accommodation faults, through poroelastic modeling of excess pore pressure by fluid injection and pumping operations and static Coulomb stress calculation on the pre-stressed faults. We argue that water injections may have triggered this event. The result highlights the importance of reassessing seismic hazard over similar tectonic environments with intensive industrial exploitation. • The Changning earthquake ruptured an oblique-thrust and a sinistral slip faults. • The complex rupture is due to multiple shallow fold-accommodation faults. • The event was likely triggered by fluid injection linked to salt mine exploitation. • The large rupture shows interaction between industrial activities and natural faults. [ABSTRACT FROM AUTHOR]

A multi-scale numerical investigation for fault slip and casing deformation is carried out by combining a large-scale distinct element model to simulate the hydraulic fracturing and fault slip and a small-scale finite difference model to analyze casing deformation. The result of large-scale model shows that the pore pressure elevation causes the slippage of fault and thus the deformation of an intersected wellbore and casing. Both fluid viscosity and injection rate have significant impacts on the shear displacement while the effect of injection volume is determined by the number of natural fractures in the reservoir. The result of small-scale model shows that the fault sliding causes the stress concentration near the fault plane and thus gives rise to the casing yielding. Casing grade, casing sheath thickness and cement sheath thickness have limited impacts on casing deformation while the countermeasure of no cementing is effective on mitigating casing deformation. Moreover, optimizing the well trajectory can help to decrease casing deformation. The field data in Sichuan Basin demonstrates that decreasing the injection rate could effectively mitigate the casing deformation. But the effect of total injection volume is less significant probably due to the fact that the shale reservoir is intensively fractured. • A large-scale distinct element model is utilized for simulating hydraulic fracturing and fault slip. • A small-scale finite difference model is applied for analyzing casing deformation. • Casing grade, casing sheath thickness and cement sheath thickness have limited impacts on casing deformation. • Casing deformation can be mitigated by optimizing well trajectory or decreasing injection rate. [ABSTRACT FROM AUTHOR]