## 2 General Framework of Geomechanical Modeling
The general steps of developing a numerical model for coupled THM simulation start with building a conceptual geological model with existing geological and geophysical data and then creating a numerical model with proper constitutive relations and scaled rock properties obtained through analytical approaches. To calibrate the numerical model it needs to run the coupled THM simulation for history matching of the monitoring data by adjusting the input parameters, such as pore pressure (\(P_{p}\)), temperature (\(T\)), water saturation (\(S_{w}\)), and rock property. An accurate numerical model can be useful for long-term prediction of geomechanical integrity of a reservoir-caprock system. Geological formations contain heterogeneities at scales down to the pore and grain scale; however, a practically useful model cannot fully account for this level of detail. There are practical needs to deal with a scaled-up model that accounts for most of the important physics in subsurface geoscience. In a scaled-up model, an element represents a volume containing heterogeneities and fractures at scales smaller than the scale of the element, down to the pore and grain scale, and these features may distribute uniformly or in a patchy fashion. Because there are uncertainties in scaling up such models, probability-based uncertainty analysis and prediction are also necessary. Within the geomechanical modeling framework, the coupled THM simulation, which predicts injection- or production-induced changes in the rock properties, rock mass deformation, stress distribution, and the fracture or fault stability, is the key element to ensure safety of the operations. There are a number of choices of research-oriented or commercial software for reservoir simulation and/or stress analysis. In this study, TOUGH2 and FLAC3D were selected for these purposes. TOUGH2 is a package of programs for multiphase reservoir simulation, and FLAC3D [26] is a commercial software for geotechnical analysis. With sequential couplers [27], this combined TOUGH-FLAC approach has proven useful in the analysis of deformation coupled with fluid flows within hard and soft rocks in injection-induced seismicity in shale gas production [5], geological CO2 storage [28; 29; 30], geothermal and natural analog studies [31; 32]. The permeability of rock mass may change greatly as a result of deformation and fracturing [12; 33]. In previous works, the permeability has been expressed as a function of volumetric strain \(\varepsilon_{v}\) or shear strain \(\varepsilon_{s}\)[32; 34; 35] as  
\[\frac{dm_{\theta}}{dt}+\
abla\cdot f_{\theta}=q_{\theta} \tag{2}\]0  
\[\frac{dm_{\theta}}{dt}+\
abla\cdot f_{\theta}=q_{\theta} \tag{2}\]1  
where \(\phi\) is porosity, \(k\) (m\({}^{2}\)) is permeability, \(\phi_{i}\) and \(k_{i}\) are their respective initial value, and \(n\) is constant integer. \[\frac{dm_{\theta}}{dt}+\
abla\cdot f_{\theta}=q_{\theta} \tag{2}\]2 Framework of geomechanical modeling with coupled thermal, hydrological, and mechanical (THM) simulation and history matching using distributed strain data, for which no geophysical post processors are required.