3D numerical modeling of hydrothermal processes during the lifetime of a deep geothermal reservoir

Understanding hydrothermal processes during production is critical to optimal geothermal reservoir management and sustainable utilization. This study addresses the hydrothermal (HT) processes in a geothermal research doublet consisting of the injection well E GrSk3/90 and production well Gt GrSk4/05 at the deep geothermal reservoir of Gros Schonebeck (north of Berlin, Germany) during geothermal power production. The reservoir is located between −4050 to −4250 m depth in the Lower Permian of the Northeast German Basin. Operational activities such as hydraulic stimulation, production (T = 150°C; Q = −75 m3 h−1; C = 265 g l−1) and injection (T = 70°C; Q = 75 m3 h−1; C = 265 g l−1) change the HT conditions of the geothermal reservoir. The most significant changes affect temperature, mass concentration and pore pressure. These changes influence fluid density and viscosity as well as rock properties such as porosity, permeability, thermal conductivity and heat capacity. In addition, the geometry and hydraulic properties of hydraulically induced fractures vary during the lifetime of the reservoir. A three-dimensional reservoir model was developed based on a structural geological model to simulate and understand the complex interaction of such processes. This model includes a full HT coupling of various petrophysical parameters. Specifically, temperature-dependent thermal conductivity and heat capacity as well as the pressure-, temperature- and mass concentration-dependent fluid density and viscosity are considered. These parameters were determined by laboratory and field experiments. The effective pressure dependence of matrix permeability is less than 2.3% at our reservoir conditions and therefore can be neglected. The results of a three-dimensional thermohaline finite-element simulation of the life cycle performance of this geothermal well doublet indicate the beginning of thermal breakthrough after 3.6 years of utilization. This result is crucial for optimizing reservoir management. Geofluids (2010) 10, 406–421