Fractured reservoirs commonly develop multiscale and geometrically complex fracture networks under geological processes and reservoir stimulation, posing significant challenges for accurate simulation of transient fluid flow. In particular, the coexistence of small-scale fractures and complex fracture geometries (e.g., tips, kinks, branching, and intersections) leads to difficulties in simultaneously achieving computational efficiency and accuracy. To address these challenges, this paper proposes an extended finite element method (XFEM) framework with novel enrichment functions for fluid flow simulation in fractured reservoirs with multiscale and complex morphology fracture networks (MCMFN). The method integrates enriched and explicit discrete-fracture/matrix modeling (EE-DFM) to explicitly represent fractures, while introducing three types (six subtypes) of enrichment functions to enhance the local pressure field approximation. A key innovation in this study is the development of a sharp-corner enrichment function, designed to accurately capture the flow behavior in complex fracture geometries, such as kinked, branching, and intersecting fractures. Additionally, a whole-fracture enrichment function is employed to efficiently simulate small-scale fractures embedded within elements. The proposed enrichment functions enable accurate representation of weak discontinuities in pressure, singularities near fracture tips, and flow redistribution in complex fracture configurations, while allowing efficient simulation of small-scale fractures within coarse meshes. As a result, the method effectively resolves the long-standing trade-off between computational efficiency and accuracy in multiscale fracture systems. Comparisons with conventional finite element solutions demonstrate the accuracy and robustness of the proposed method. Furthermore, several numerical examples, including complex fracture networks, fluid–solid coupling, and fracture propagation in layered media, highlight its strong applicability to practical engineering problems.

In ultra-deep well operations, severe lateral vibration of drill string is a major factor in tool failure and decreased drilling efficiency. To investigate the vibration mechanisms and identify effective mitigation approaches, a dynamic model for lateral vibration in ultra-deep well drill strings was established using Cosserat geometrically exact beam theory. The model systematically examined the effects of rotational speed, WOB, and stabilizer position and size on the vibration behavior. Key findings were validated against downhole measurement data from ultra-deep wells. Additionally, two control strategies leveraging modal competition and transverse wave disturbance were proposed. Results indicate that the bottom hole assembly (BHA) is particularly prone to intense lateral vibrations, with its vibrational modes governed by rotational speed and WOB. When the WOB is below the critical buckling load, increasing either the rotational speed or WOB promotes backward whirling of the BHA, thereby intensifying the vibration severity and bending stress. Conversely, when the WOB exceeds the critical buckling load, the system transitions into a buckling-whirling competition mode, resulting in a significant reduction in the vibration intensity and bending stress. This trend was reasonably verified through field data. Artificially inducing this low-risk modal competition by adjusting the WOB and rotational speed can effectively reduce the probability of drill string failure. The motion of stabilizers shifts from forward whirling to backward whirling as the diameter decreases, which considerably alters the vibration-propagation patterns. The vibration-damping effects of both full-gauge and under-gauge stabilizers initially increase and then decrease as their installation position moves upward. Under-gauge stabilizers exhibit less consistent behavior under non-severe vibration conditions; nevertheless, they can suppress severe whirling by interfering with adjacent drill string vibrations through low-frequency transverse waves. They also demonstrate lower sensitivity to the installation position and enhance drill string safety through stress dispersion. Considering comprehensive vibration suppression, drill string integrity, and engineering applicability, installing under-gauge stabilizers can be a viable BHA optimization measure with significant practical value. This study provides a theoretical basis for vibration control in ultra-deep well drill strings, and the proposed strategy offers valuable insights for improving drilling efficiency and ensuring operational safety. (c) 2026 The Authors. Publishing services by Elsevier B.V. on behalf of KeAi Communications Co. Ltd. This is an open access article under the CC BY license (http://creativecommons.org/licenses/by/4.0/).

Deep Earth TK-1, China's first 10,000 m scientific exploration well, encountered severe wellbore instability during sidetracking at a depth of approximately 9500 m under ultra-deep, high-stress conditions (maximum horizontal stress sigma H = 230 MPa, minimum horizontal stress sigma h = 200 MPa). To clarify how the original wellbore affects the stability of the sidetracked wellbore, single- and dual-well numerical models were established in COMSOL Multiphysics using the solid mechanics module and finite element method. The stress redistribution around the wellbore was analyzed before and after the collapse of the main wellbore, and the influences of well spacing and breakout geometry were quantified. The results show that a stress-relief "safe zone" forms along the direction of maximum horizontal stress before collapse and expands after collapse, allowing safer sidetracking within this range. In the dual-well model, the maximum stress difference around the sidetracked wellbore increases with well spacing and eventually approaches that of a single circular wellbore. The safe zone boundary was quantified for well spacings between 2.0 m and 3.5 m, depending on the major-axis enlargement ratio of the collapsed main wellbore. A larger major-axis enlargement ratio reduces far-field stress interference and expands the safe zone, whereas changes in the minor-axis enlargement ratio have little effect. These findings provide theoretical support for optimizing sidetracking design in ultra-deep wells.

Accurately predicting the mechanical response of ultra-deep dolomite (burial depth > 6000 m) under high in-situ stress and strong heterogeneity is a major challenge for the development of ultra-deep oil and gas resources. Traditional theories and empirical formulas fail to balance prediction accuracy with computational efficiency. This study establishes a framework from high-fidelity simulation to rapid prediction. First, a dual-Weibull distribution heterogeneous model using the combined finite-discrete element method (FDEM) is developed and validated against experimental data to characterize dolomite’s mesoscopic structure. Subsequently, a modified Long Short-Term Memory (mLSTM) deep learning surrogate model is trained on the FDEM dataset to achieve rapid prediction of the complete mechanical process. The study reveals that: (1) The dual-Weibull framework decouples mesoscopic mechanics by independently controlling grain boundary strength (cohesive elements) and grain stiffness heterogeneity (matrix elements), revealing their differentiated effects on peak strength and elastic modulus. (2) Numerical simulations reveal that mechanical behavior is dominated by confining pressure, which governs the transition from microcrack evolution to macroscopic failure patterns. (3) The mLSTM integrates physical initial conditions (e.g., confining pressure, mineral composition) via an initial state encoding mechanism. This suppresses the accumulation of errors in standard LSTMs, significantly improving prediction accuracy. (4) SHapley Additive exPlanations (SHAP) analysis validates the model’s physical reasonableness, as its feature importance rankings match the FDEM sensitivity analysis. Cross-lithology validation confirms strong generalization. This “refined numerical modeling—rapid surrogate prediction” pathway provides an efficient tool for wellbore stability and hydraulic fracturing optimization in ultra-deep drilling.

This study investigates Cambrian and Sinian carbonate outcrops in the Tarim Basin using 19 stratigraphically diverse rock samples. Through integrated X-ray diffraction mineralogical analysis, triaxial compression testing, and Brazilian splitting experiments, we systematically characterized rock mechanical properties and their correlations with microscopic mineral constituents. Key findings demonstrate remarkably distinct mechanical properties across formations: vuggy dolomites from the Xiaqiulitage formation exhibit the lowest compressive strength (minimum 200.0 MPa) and tensile strength (3.85 MPa), while the Yuertusi formation’s Y5 layer dolomites achieve exceptional tensile strength (21.69 MPa). Mineral composition fundamentally controls rock strength: dolomite or quartz concentrations exceeding 90% significantly enhance strength, whereas calcareous minerals (calcite, fluorapatite) degrade mechanical integrity. Most specimens display pronounced brittle failure characteristics; uniquely, basal dolostones of the Awatage formation exhibit distinctive plastic deformation. This research elucidates the synergistic effects of tectonic history, mineral assemblages, and microtextural attributes on rock mechanical behavior, providing critical theoretical underpinnings for deep carbonate reservoir development in overpressured basins.

In this paper, we establish the well-posedness and large-time asymptotic behavior of viscosity solutions to singular/degenerate parabolic p-Laplacian equations with general capillary-type boundary conditions, including Neumann and prescribed contact angle cases, on strictly convex domains. By establishing a gradient estimate independent of the C^0 norm of the solution via the maximum principle, and by analyzing the problem through an approximation procedure together with associated elliptic eigenvalue problems, we prove the existence, uniqueness, and asymptotic behavior of solutions. For the elliptic problem with Neumann boundary conditions, we first focus on flat domains with the zero Neumann condition. By reflecting u across the flat boundary T_1 and then using inf- and sup-convolution arguments in the reflected domain, we obtain the C^1,α result. For the general elliptic case, we obtain sharp global C^1,α regularity by flattening the boundary and employing compactness arguments together with an “improvement of flatness” iteration. With an extra condition in the iteration, we can also deal with the singular case 1<p<2. In the parabolic setting, the spatial Hölder regularity of Du follows from elliptic estimates combined with the Lipschitz continuity of u in time, which in turn yields joint Hölder continuity in (x,t). Extensions to non-convex domains are also discussed by incorporating a suitable forcing term.

The exploration of oil and gas resources is shifting toward ultra-deep and extra-deep reservoirs, including in the Tarim Basin, where various types of carbonate rocks are buried. Owing to the extreme burial depths, the mechanical behavior of these rocks under extra-deep conditions differs significantly from that of shallow formations, making it essential to understand their mechanical responses. This study investigated the mechanical properties and failure modes of carbonate rocks, specifically dolomite, argillaceous limestone, and pure limestone. Samples from extra-deep formations were initially analyzed for mineral composition and microstructure, after which uniaxial and triaxial compression tests were conducted to evaluate strength, static elastic modulus, and axial strain at peak stress. The results indicate that dolomite exhibits the highest mechanical strength and stiffness among the three lithologies. Under conditions of a high confining pressure of 100 MPa and a temperature of 160 °C, its elastic modulus and triaxial compressive strength are 65.4 GPa and 611.2 MPa, respectively, compared with 52.8 GPa and 444.2 MPa for limestone. Strength increases with confining pressure for all lithologies, with dolomite showing the most pronounced strengthening response. Although elevated temperature reduces rock strength, its effect is weaker than that of confining pressure. The failure mode is strongly controlled by confining pressure. At low confining pressures, failure is dominated by localized shear bands and brittle fracturing, whereas increasing confining pressure promotes a transition toward quasi-brittle deformation or ductile plastic flow. Dolomite predominantly maintains a quasi-brittle failure mode, argillaceous limestone exhibits a clear brittle-to-ductile transition, and pure limestone shows the greatest tendency to develop ductile plastic flow under high confining pressure conditions. The results further demonstrate that mineral composition and microstructural characteristics play critical roles in controlling the deformation and failure mechanisms of carbonate rocks. High-calcite pure limestone can exhibit ductile-like deformation behavior due to cataclastic processes, allowing significant strain without localization failure. These insights enhance understanding of carbonate rock behavior under extra-deep formations, informing practical applications in geology science.

The deformation and failure mechanism of deep mudstone under high temperature and high pressure (HTHP) is a critical issue constraining deep-drilling efficiency. Taking an HTHP mudstone formation in the western South China Sea as the research object, this study integrates X-ray diffraction, scanning electron microscopy, nanoindentation, HTHP triaxial compression tests, and FDEM numerical modeling incorporating mineral heterogeneity and Weibull strength distribution. The mudstone is predominantly composed of clay minerals (44.67%) and quartz (32.37%), with low hardness (1.42–2.96 GPa) and moderate elastic modulus (43.9–58.2 GPa). Under ambient conditions, uniaxial compressive strength is approximately 19.5 MPa with axial splitting failure; at 40 MPa confining pressure, strength increases to 121.8 MPa with shear failure; at 150 °C and 40 MPa, peak strength slightly decreases, yield point is delayed, and post-peak decline accelerates. The FDEM model, calibrated against experimental data, reasonably reproduces crack evolution and failure modes. However, due to limited tests (one per condition) and variations in specimen depth, statistical robustness is constrained; thus, this study does not yet establish a generalizable quantitative cross-scale correlation, and the findings are primarily applicable to the specific formation investigated.

Petroleum science stands at a historic turning point: exploration extends to ultra-deep and deepwater frontiers, unconventional resources become dominant, and the dual imperatives of carbon neutrality and artificial intelligence are reshaping the industrial landscape and disciplinary boundaries. Building upon the “100 Grand Challenges in Petroleum Science” initiative launched by Petroleum Science in 2021, this paper presents a curated list of 100 fundamental scientific problems through systematic literature synthesis, expert deliberation, and multi-criteria selection. The challenges span six domains: exploration and development, transport and pipelines, refining and petrochemicals, materials science, carbon capture, utilization and storage (CCUS)-geothermal-hydrogen, and energy economics and digital transformation. In-depth analysis reveals three archetypes: mechanism-oriented problems that seek unified theories of multi-scale coupling, technology-oriented problems that push engineering limits under extreme conditions, and system-level problems that address full-chain integration and energy transition. A key insight is that artificial intelligence has evolved from an enabler to a core driver, and together with the low-carbon transition it is redefining the very paradigm of petroleum science. This roadmap is intended to guide research planning, investment, and talent development over the coming decades and to foster interdisciplinary collaboration on a global scale.

In tight oil reservoir development, hydraulic fracture morphology critically controls post-fracturing flow behavior. However, conventional microseismic monitoring remains limited in real-time characterization of nonplanar fracture geometry. This study proposes a digital twin-driven approach for nonplanar fracture reconstruction and evaluation, enabling real-time fracture characterization in tight reservoirs. The results show that: (1) the reconstructed fracture morphology achieved a normalized relative geometric error of only 3.33% when experimentally validated against high-resolution laser scanning in a true triaxial hydraulic fracturing test, and demonstrated a computational speedup exceeding 700 times compared to the discrete element method under identical experimental conditions and specimen geometry; (2) the reconstructed fracture networks capture nonplanar propagation and fracture–natural fracture interactions, indicating that fracture complexity is jointly controlled by tortuosity and connectivity when the horizontal stress difference is below 5 MPa, but dominated by connectivity when it exceeds 5 MPa; (3) real-time fracture reconstruction enables the identification of potential inter-stage fracture communication, allowing engineers to adjust injection volume and stage spacing to mitigate interference and improve stimulation efficiency. These results demonstrate the proposed digital twin functions both as a monitoring tool and an integrated platform for real-time fracture reconstruction, evaluation, and operational optimization in tight reservoirs.

Shale hydration is a critical factor influencing wellbore stability. However, accurately quantifying hydration strain and tracking the dynamic migration of fluid imbibition fronts in tight matrices remains a significant challenge. To address this issue, we propose a high-spatial-resolution monitoring scheme based on distributed fiber optic sensing (DFOS). By applying a hydrophobic coating to alter the imbibition path, we established a one-dimensional (1D) unidirectional imbibition boundary condition and compared it with semi-immersed free imbibition. Representative shale specimens with varying geological characteristics were tested to capture the continuous spatiotemporal evolution of hydration strain under both conditions. Our results show that under the restricted 1D path, the onset of strain exhibits a regular sequential delay along the fluid invasion direction, successfully mapping the progressive advancement of the imbibition front. The comparison between specimens with and without hydrophobic coating confirms that the coating effectively alters the imbibition path, leading to pronounced spatial lag and amplitude attenuation due to gravity and viscous resistance. Furthermore, we identify a dual characteristic of hydration strain. On one hand, governed by intrinsic properties such as clay content and permeability, different specimens exhibit distinctly different strain morphologies. On the other hand, within the same specimen, strain profiles at different measurement locations display high temporal self-similarity and spatial similarity, reflecting the structural control of the rock matrix. These findings suggest that shale hydration is a highly heterogeneous process, and the morphological differences can, to some extent, reflect variations in rock structure. Overall, this study provides an important methodological reference for improving wellbore stability models and optimizing drilling fluid design in deep shale engineering.

Accurate evaluation of wellbore stability in horizontal wells necessitates a comprehensive approach, considering not only the inherent transverse isotropy in mechanical, strength, and seepage characteristics of sedimentary rock formations, but also the evolving effective stress field arising from anisotropic undrained poroelastic effect and fluid seepage. To accurately constrain a safe operational envelope of wellbore pressure, this study develops three-dimensional (3D) analytical stress solutions near/at the borehole wall for arbitrary horizontal wells under three extreme time domains: instantaneous (undrained), short term, and long term. Subsequently, these solutions are employed in conjunction with anisotropic tensile and shear failure criteria to determine the corresponding safe mud weight window (SMWW). Model results demonstrate that the short-term (which considers anisotropic undrained effect and fluid seepage) and long-term (which considers anisotropic fluid seepage) SMWWs are significantly narrower, than those in both the instantaneous solution (which considers undrained effect) and the common elastic solution that ignores pore pressure variations. Furthermore, the SMWW’s evolution under different time domains exhibits contrasting trends with varying wellbore azimuth and anisotropies of Young’s modulus and permeability, underscoring the importance of selecting appropriate models for wellbore stability prediction in poroelastic formations. Under the specified parameters in this study, with increasing wellbore azimuth and anisotropies of Young’s modulus and permeability, the minimum allowable wellbore pressure gradually shifts from the short-term lower collapse pressure to the long-term one. These analytical solutions can provide mathematical benchmarks for numerical simulations and effectively constrain the evolving wellbore stability of horizontal wellbore in transversely isotropic poroelastic formations.

Due to the presence of highly discrete rock blocks and extensively developed natural fractures in fractured formations, frequent losses of drilling fluid and wellbore instability incidents occur during the drilling process. Meanwhile, for some extremely fractured formations, even after increasing the density of the drilling fluid, the wellbore instability situation shows no obvious improvement, and even the wellbore collapse becomes more severe. Regarding the highly discrete rock blocks in fractured formations, current research mainly focuses on using the discrete element method (DEM) to reveal the mechanism of wellbore instability in fractured formations. However, the DEM emphasizes the representation of the contact behavior of rock blocks and has difficulty effectively representing the multi-field coupling behavior during the actual drilling process in fractured formations. Therefore, in this paper, a combined modeling method of discrete element method (DEM) + finite element method (FEM) is adopted, comprehensively considering the dual-medium seepage effect of fractures and matrix pores, to conduct numerical simulation studies on the wellbore instability after drilling formations with different degrees of fragmentation. The research indicates that as the degree of fragmentation of formation increases, the situation of wellbore instability becomes more severe. Meanwhile, when the degree of fragmentation of formation is low and the occurrence of natural fractures is within the risk range of wellbore instability, due to the large size of discrete rock blocks in the formation, the wellbore instability mainly stems from the secondary fracturing within the discrete rock blocks; while when the degree of fragmentation of formation is high, the initiation of fractures around the wellbore mainly depends on the opening of natural fractures, thereby causing a large amount of shedding of discrete rock blocks and subsequently leading to wellbore instability. Increasing the bottomhole pressure can effectively inhibit the secondary fracturing of discrete rock blocks. For formations with a low degree of fragmentation, the wellbore instability is mainly caused by the secondary fracturing of discrete rock blocks. Thus, increasing the bottomhole pressure can effectively reduce the risk of wellbore instability; while for highly fractured formations, the wellbore instability is mainly caused by the shedding of discrete rock blocks triggered by the opening of natural fractures in the formation. Therefore, increasing the bottomhole pressure cannot effectively reduce the risk of wellbore instability. In terms of drilling fluid loss, the opening of natural fractures is more conducive to the expansion of the range of drilling fluid loss. Therefore, for highly fractured formations, increasing the bottomhole pressure not only fails to effectively reduce the risk of wellbore instability but also exacerbates the situation of drilling fluid loss. By analyzing the influence of the ratio of wellbore size to the size of fractured blocks on wellbore instability, it is concluded that for fractured formations, when the wellbore trajectory cannot avoid it, a small wellbore size should be adopted as much as possible.

The morphology and connectivity of subsurface fracture networks are critical factors controlling wellbore stability and hydraulic fracturing efficiency. Accurate characterization of the three-dimensional complexity of fractures holds significant importance for engineering safety and performance enhancement. A novel image segmentation model is established in this study. It enhances the iterative threshold method by incorporating simple linear iterative clustering superpixels, ResNet50, and a Gaussian mixture model. The model first divides complex computed tomography images into numerous superpixel images using simple linear iterative clustering superpixel segmentation. Subsequently, ResNet50 is employed to classify these superpixel images. Based on the classification results, the iterative threshold segmentation method is applied to segment different categories of superpixel images accordingly. Following preliminary image segmentation, Gaussian mixture module is used for denoising the segmented fracture images, resulting in high-precision segmented images. The two-dimensional segmented images are then reconstructed in three-dimensional space, and the three-dimensional distribution characteristics of fractures are analyzed. This study concludes that the new fracture segmentation method enables high-precision extraction of fracture regions. Compared with threshold segmentation, the morphological analysis noise value in the two-dimensional images segmented by the method proposed in this study was reduced from 0.21% to 0.08%. Fracture distribution in three-dimensional space is complex, and areas with larger fracture networks exhibit greater complexity in their three-dimensional distribution.

Heterogeneous and anisotropic hydration behaviors of shale play a key role in petroleum drilling, which can induce strength degradation and wellbore instability. Herein, we innovatively use the technology of distributed fiber- optics sensing (DFOS) based on Rayleigh frequency shift to strictly monitor the anisotropic hydrational strain of shale with high resolution for the first time. Specifically, we developed a universal experimental framework for measuring hydrational strain under an unconfined free soaking condition combined with distributed fibers and strain gauges, where the shale core sample is immersed in deionized water in a hydrostatic balance and a reserved slack fiber is placed on the surface to measure hydration- induced temperature change. We also conducted a serial fiber winding strategy that included two independent geometric configurations to determine anisotropy. Under the assumption of axisymmetric deformation during hydration, we separated and determined circumferential and axial hydrational strain components after adopting the strain decomposition equation. In addition, we performed two extra tests to validate such axisymmetric assumption. The experimental results indicate that the hydrational strain of shale measured by fibers and gauges showed a good agreement with an average relative error not exceeding 5% and the impact of temperature change caused by hydration on hydrational strain (0.75 mu epsilon) was so slight as to be ignored. Further, the validated tests confirmed the axisymmetric assumption that the circumferential and axial hydrational strain components were not dependent on the azimuth angle. The results also demonstrated that the hydrational strain increased rapidly for the initial 6 hours and then tended to be convergent, with the maximal circumferential hydrational strain (950 mu epsilon) being nearly three times larger than that of the axial one (300 mu epsilon), especially for the central region of shale. These phenomena implied the significant intrinsic hydration anisotropy and the potential boundary effect of shale in such a configuration. A natural parameter eta (the hydration self- similarity ratio) was defined to evaluate and scale the hydration anisotropy. It showed that eta varied at different heights (3.50 0.01) but did not vary much at long- term hydration, which implied heterogeneous hydration. It also showed that eta increased over time in the initial period, while it later became constant, which implied progressive anisotropic hydration dynamics. The constitutive curve of hydrational strain vs. water adsorption revealed that there existed three evolutional regimes during hydrational deformation, including dynamic eta (<= 1 and >1) for the initial time and stable eta for the long- term behavior (due to hydration balance). Another interesting result indicated that two hydrational strain components could be fitted by an exponential law vs. water adsorption. These results highlight the particular advantages and reliable applications of DFOS in sufficient hydrational strain measurement of shale, which can also enhance our understanding of anisotropic hydrational deformation and induced cracking

The testing and evaluation of shale hydration behaviors have always been an essential problem of wellbore stability in drilling. As an excellent distributed measuring method of strain with a high spatial resolution in recent years, distributed fiber- optics sensing (DFOS) technology has been widely applied to wellbore integrity assessment. In this work, we propose a new experimental framework for monitoring the hydrational swelling strain of shale based on DFOS and optical frequency domain reflectometry (OFDR). Initially, we design a scheme of fiber wrapping helically on the shale surface to cover more sensing zones. Then, we carry out laboratory tests in an unconfined free- water soaking environment with a constant temperature to eliminate temperature influence. After several days of soaking and hydration, the hydrational strain of shale sensed by fiber optics can be monitored dynamically in real time with an enough acquisition frequency and a sufficient spatial resolution. We conduct a pretest using waterproof strain gauges and distributed fibers under the same condition, which demonstrates the great ability and sufficient accuracy of DFOS in hydrational strain monitoring. In addition, we establish a strain projection equation by tensor analysis, and for the first time define a convenient relationship of hydrational strain between circumferential and axial directions, called hydration self- similarity. The experimental results show that the hydrational strain growth varies with time and space, which indicates the native progressiveness over time and the significant heterogeneity in space. These typical hydration swelling behaviors of shale can be measured effectively by fiber optics. Such experimental framework and modeling analysis provide new insights into testing behaviors of shale hydration and understanding chemical fracture phenomena that may be further utilized for drilling mud optimization and wellbore stability enhancement.

Depressurization-induced gas hydrate dissociation is widely employed for gas hydrate production but simultaneously introduces substantial geomechanical challenges, including sediment deformation, formation damage, and subsidence. Such issues have significantly limited the duration of field production tests worldwide, typically causing production to cease within around one month. The reliance on time-independent and quasi-static geomechanical assumptions in many existing models may lead to significant underestimation of depressurization-induced irreversible deformation and overlook time-dependent creep effects. This study develops a fully coupled poro-elasto-viscoplastic-dynamic model specifically designed to analyze realistic dynamic geomechanical responses induced by depressurization in gas hydrate-bearing sediments. The novelty of this work lies in incorporating both the inertial effects and a validated time-dependent elasto-viscoplastic constitutive relationship within a unified poromechanical framework, representing one of the first numerical efforts to capture these coupled effects and their impact on progressive irreversible deformation. The numerical framework integrates thermal, hydraulic, mechanical, and chemical processes. Comprehensive validations against established benchmarks and experimental data substantiate the accuracy and reliability of the model. Results demonstrate distinctive dynamic behaviors, capturing stress rebound phenomena at hydrate dissociation fronts, characterized by sudden stiffness reductions followed by transient stress recovery. The model identifies significant tertiary creep deformation occurring rapidly consistent with global field observations where production frequently terminates due to severe geomechanical deterioration. Comparative analyses further indicate that conventional quasi-static and time-independent constitutive models underestimate cumulative irreversible plastic deformation, potentially misrepresenting short-term geomechanical risks. Unique stress path evolution patterns captured by the dynamic model also provide quantification of transient yielding, stress redistribution, and progressive deformation mechanisms. This study explains the geomechanical reasons underlying the un-sustained and limited-duration gas hydrate production commonly observed in field operations. It also quantifies risks often overlooked or underestimated by simplified modeling approaches.

The immediate undrained poroelastic response after drilling is critical for short-term wellbore stability in low-permeability formations. Despite its significance, existing analytical undrained wellbore stress solutions in transversely isotropic formations are limited to special cases where the borehole axis is either perpendicular or parallel to the plane of transverse isotropy. By extending Amadei's elastic framework into the undrained poroelastic regime, this study presents an analytical undrained solution for arbitrarily inclined boreholes in transversely isotropic formations, considering fully anisotropic undrained poroelastic effects. Validation against undrained isotropic and transversely isotropic solutions, as well as anisotropic Biot's effective stress coefficients, demonstrates the robustness of the proposed model. The derived Biot's effective stresses are subsequently applied to evaluate short-term collapse pressure with varying wellbore trajectories. Results show that undrained wellbore stress distributions deviate significantly from drained Amadei solution with varying elastic property anisotropy and wellbore pressure, particularly in terms of axial and shear stress components. Furthermore, estimating the undrained pore pressure response using drained Amadei stress solution introduces substantial errors, highlighting the necessity of adopting a fully anisotropic undrained poroelastic framework. Unlike isotropic formations, the anisotropic undrained pore pressure response exhibits an asymmetrical distribution, reflecting coupled shear-tension and solid-fluid couplings. Polar plots of collapse pressure that incorporate the undrained effect exhibit significant differences compared to those derived from previous models, indicating that the optimal drilling direction may not coincide with the orientation of the horizontal principal stress. This analytical solution establishes a benchmark for fully anisotropic undrained wellbore stress distribution and holds substantial implications for enhancing early-stage wellbore stability assessments in strongly anisotropic poroelastic formations.