Fast geomechanical simulations of fault reactivation induced by the exploitation of porous subsurface reservoirs play an important role in (upfront) screening, seismic hazard assessment, and data assimilation approaches. Here, a 2D semi-analytical model framework is presented to compute stress changes on faults offsetting two depleting reservoir compartments, building on existing closed-form expressions for stress changes. The model was extended by incorporating a simplified vertical pressure diffusion function to the seal and base formations. The closed-form expressions were further extended to include thermo-elasticity and vertical temperature diffusion. The model was applied to generic depleting and cooling reservoir offset by a fault, and the effect of diffusion on different fault reactivation metrics was assessed. It was shown that diffusion regularized the stress distribution along the fault, smoothing the stress concentrations at the reservoir boundaries and eliminating cell-size dependence of the results. It was also shown that the assumed depletion of the fault zone itself had a fundamental effect on the stress path, with lower fault zone depletion than the reservoir compartments leading to more unstable fault stresses. Depending on the assumed fault zone depletion, cooling can have a similar (in case of no fault zone pressure change) or fundamentally different (in case of full fault zone depletion) stressing effect compared to depletion. In the latter case, cooling resulted in higher stressing rates due to the reduction in effective normal stress. Furthermore, we used a gradient-boosted machine-learning tree regression to fit the model results, creating a surrogate model that was used to rank the relative influence of input parameters on fault reactivation metrics. For stressing rates the most important parameters were reservoir height, fault throw, and the poro-elastic or thermo-elastic parameters, but for reactivation metrics relating to the absolute state of stress on the fault, the initial horizontal stress, fault dip, and fault strength became the dominant parameters. Both the semi-analytical and the surrogate model are useful tools for probabilistic screening methods or hazard assessment.
The occurrence of flotation phenomena during trench backfilling remains a well-recognized threat to the successful installation of offshore pipelines, with direct implications for both safety and cost. This study developed and assessed a simplified model based on Kynch’s batch sedimentation theory to predict the buoyant response of pipelines during sand–water backfilling. The formulation couples the temporal evolution of solid concentration with the dynamic equilibrium of the pipe, accounting for both buoyancy and Bingham-type drag forces. The model was assessed through comparison with a set of small-scale laboratory test results, and good agreement was found in terms of concentration evolution, uplift onset time, and pipe displacement evolution. The results of numerical parametric studies provide insight into the influence of pipe specific gravity, revealing its impact on the evolving balance between driving and resisting forces—from the onset of flotation to eventual resettlement. The results confirm that, despite the simplifying assumptions, the formulation captures the fundamental physics of pipe flotation and resettlement. The model offers a sound theoretical framework that can support future design-oriented studies aimed at identifying safe combinations of pipe density, trench geometry, and backfilling conditions in offshore installations.
F. Cecinato, G. Della Vecchia, P. Eikhout et al.· Journal of Geotechnical and...· 0 citations
Fluid injection in deep reservoirs can induce fault reactivation and seismicity, posing challenges for geothermal and subsurface energy development. This study investigates the mechanical interaction between two adjacent non-intersecting faults under fluid injection using a pseudo-three-dimensional thermo-hydro-mechanical (THM)-coupled numerical model. The results show that injection first triggers slip on F2, which then redistributes stress onto F1. The response of F1 is strongly heterogeneous: some segments are stabilized due to a decrease in Coulomb failure stress, whereas other segments are destabilized due to an increase in Coulomb failure stress. Stress-path analysis indicates that the immediate response of F1 to F2 slip is mainly governed by changes in effective normal stress and shear stress, rather than abrupt pore pressure changes on F1. These findings demonstrate that fault slip can act as a mechanical stress source that either promotes or inhibits adjacent fault reactivation. Therefore, slip-induced stress transfer should be explicitly considered when assessing fault stability in reservoirs containing multiple closely spaced faults.
Reservoir-triggered seismicity (RTS) is commonly associated with stress perturbations induced by reservoir loading and pore-pressure diffusion within fractured rock masses. Shortly after the initial impoundment of the Irapé Hydropower Plant (Minas Gerais, Brazil), a sequence of induced earthquakes was recorded, providing an opportunity to investigate the compatibility between reservoir loading and the observed seismic response. This study presents a first-order hydromechanical assessment integrating finite element modelling, analytical elasticity solutions, and pore-pressure diffusion theory to evaluate the spatial distribution of stress perturbations and the characteristic diffusion times associated with reservoir impoundment. A two-dimensional elastic model was developed to simulate stress redistribution induced by the maximum reservoir load, while a parametric diffusion analysis was performed for representative hydraulic diffusivities and hypocentral depth scenarios between 1 and 6 km. Numerical results showed excellent agreement with the analytical elasticity solution (RMSE = 14.36 kPa, MAE = 11.08 kPa, mean relative error = 1.38%, and R2 = 0.999), supporting the reliability of the numerical model. The simulations indicate that vertical stress perturbations decrease from approximately 1.8–2.0 MPa immediately beneath the reservoir to about 0.01–0.1 MPa at kilometer-scale depths, where the recorded seismicity is presumed to occur. The diffusion analysis indicates that pore-pressure propagation to these depths generally requires substantially longer times than the interval between reservoir filling and the onset of seismic activity. Nevertheless, owing to uncertainties in hydraulic diffusivity, fracture connectivity, and hypocentral depth estimates, the diffusion results are interpreted as a first-order sensitivity analysis rather than a site-specific prediction. Overall, the results support the temporal compatibility and physical plausibility of rapid elastic stress redistribution as a potential triggering mechanism, while recognizing that the available geological and seismological data are insufficient to establish a direct causal relationship or demonstrate fault reactivation.
Iarly Vanderlei da Silveira, Gilberto Gomes· Géosciences· 1 citation
Coal-measure gas co-production is a critical strategy for enhancing the single-well productivity of unconventional natural gas. However, the pronounced vertical heterogeneity and complex combinations of co-existing reservoirs create substantial asynchronous propagation behaviors during hydraulic fracturing, fundamentally limiting the accurate prediction of multi-reservoir stimulation outcomes. This study employs numerical simulation to investigate fracture development, using the reservoir combinations of the Linxing area on the northeastern margin of the Ordos Basin as a geological model. Our results show that the thickness ratio and mechanical properties of individual rock layers are primary controls on fracture propagation. Specifically, a higher coal seam thickness ratio reduces fracture half-length but increases width, while a greater sandstone layer thickness ratio decreases width and increases height. We further propose the novel concept of the fracture propagation coefficient to characterize the heterogeneity of the fracturing process. It is found that fracture development is closely related to the distance from the injection point, the physical properties of rock layers, and the mechanical property differences between adjacent strata. The distribution of fractures is governed by the coupling effect between injection point location and reservoir mechanical properties. The reservoir–fracture response relationships established in this study provide a scientific basis for optimizing reservoir selection and fracturing parameters in coal-measure gas development.
Hao Chen, Guozhang Li, Chen Li et al.· Energies· 0 citations
The bottom-hole pressure (BHP) directly affects the stress state in formation, which in turn affects the productivity of hydraulically fractured horizontal wells. In this study, the porosity and permeability stress sensitivity experiments were conducted on different marine-continental transitional shale samples. The relationships between permeability, porosity and stress were discussed, and three-dimensional (3D) response surfaces based on grid interpolation were established for a more intuitive understanding. The results were then imported into numerical simulations to analyze the impact of permeability sensitivity on gas production at the reservoir scale and to optimize the BHP management strategy. A hysteresis effect in the changes of porosity and permeability has been observed during stress variation. Stress sensitivity of permeability leads to a significant decrease in production in the later stage. Ignoring the shale stress sensitivity would lead to an overestimation of 10-year cumulative gas production by 7.8% for organic-rich dark massive shale (ORDMS) reservoir. By using particle swarm optimization (PSO) algorithm, it is proposed that quickly reducing pressure to critical desorption pressure with subsequently maintaining pressure is critical for long-term stable production and cumulative production maximization.
Unknown authors· Journal of Energy Engineerin...· 0 citations
In this study, a rapid analytical framework is developed for reconstructing transient formation-pressure distributions in sparsely connected fractured-vuggy carbonate reservoirs using well-test-derived fracture–cave geometry and source allocation. Pressure–flow relationships are established for caves, fractured bodies, and finite line-source fractures; unit-source solutions are combined via spatial superposition and Duhamel convolution for variable-rate production; and the framework is evaluated by comparing Well EX-1 against a PEBI-grid simulation. Cave response is derived from mass conservation and effective compressibility, while point- and line-source Green’s functions describe pressure diffusion. For the 30-day EX-1 case, analytical and PEBI pressures at four locations show close internal agreement, with a mean absolute error of 0.070 MPa, a root-mean-square error of 0.083 MPa, and a maximum absolute error of 0.13 MPa. This method is applicable mainly to single-phase, slightly compressible, linear-flow conditions with a constrained fracture–cave topology. It provides a rapid screening tool for deep carbonate reservoirs with sparse well control, while multiphase, strongly nonlinear, reactive, or geomechanically coupled cases require conventional numerical simulation.
