*2.3. Coupled Thermal-Hydraulic-Mechanical (THM) Modelling*

The coupling of a reservoir simulator with a geomechanics module is an integral component for analysing hydrocarbon reservoirs in petroleum, underground gas storage, and the geothermal industry. A conventional geomechanical simulator provides surface

subsidence, which is often estimated using a simple mechanical formula without knowing the full geomechanical response. The only geomechanical parameter considered may be the pore compressibility, which is not sufficient to reproduce the changes in pore volume caused by complex pressure and temperature variations [15,16]. For some problems, such as primary production and linear elastic responses of reservoirs, subsidence calculated by a reservoir simulator alone can produce results comparable to coupled solutions [16,17].

In a coupled simulator, flow can be strongly influenced by the stress and strain distributions that lead to changes in porosity and permeability, but effective stress changes are ignored in conventional simulation methods. Such approaches cannot provide adequate predictions when considering a stress-sensitive reservoir (e.g., underground gas storage reservoir) [15,18]. There are two main components of coupling: volume coupling and fluid flow coupling according to [15,17].

In volume coupling, the changes in pore volume occur in response to variations in stress, pressure, and temperature. For convergence, the calculated pore volume changes should be the same in both the fluid flow model and the geomechanical model. The pore volume changes of the geomechanical model are usually more accurate than those of the fluid flow model because they are calculated by volumetric strain via a more realistic complex material constitutive model. This method is well suited to shear and plastic deformation, which involve large changes in pore volume or porosity. These problems are common in unconsolidated heavy oils and oil sands, North Sea chalk, Californian diatomite, and possibly some other materials [15,17].

In case of fluid flow coupling, the changes in permeability and relative permeability are related to the changes in stress, shear stress, and compaction. Material parameters, such as permeability, relative permeability, compressibility, and others, change when conditions encounter a shear fracture. This fact is important in some reservoirs where the rock compressibility does not play a significant role in volumetric behaviour, such as gas reservoirs where volume coupling is not important. Another example is cold water/fluid injection, which leads to a thermally-induced decrease in horizontal stress until the injection pressure increases the minimum horizontal stress [19].

To achieve the stress states of the reservoir and surrounding formations throughout history, as well as during future gas storage operations, the fluid flow and the geomechanical simulation must be coupled. The pore pressure controls the effective stresses and, hence, deformation, in turn changing rock porosity and permeability, which again affect fluid flow.
