Heat production from enhanced geothermal system (EGS) requires a successful stimulation. Cold water is injected into hot rocks to enhance reservoir permeability. During injection, pore pressure, temperature and the stress field in the reservoir change significantly. Most geothermal reservoirs are to some extent naturally fractured at various scales. Fractures could dilate and slip in shear possibly and propagate as a result of stress changes, increasing reservoir permeability. The objective of this work is to analyze the response of naturally fractured reservoirs to water injection. A fully-coupled thermo-poromechanical finite element model is developed and used to describe the interaction between fluid flow, rock deformation, and heat transfer within the reservoir. A fracture network model is generated based on field data and introduced to the coupled model. The model is used to simulate and analyze reservoir stimulation in the Newberry EGS Demonstration. In particular, the Phase 2.2 stimulation is modeled using field data on the fracture network, in-situ stress and lab data on rock and fracture properties. The simulated injection profile, evolution of permeability and induced micro-seismic events agree with field observations. Simulation results show that injection induced stress state change occur around the injection well which plays a critical role in many aspects of field development.


Geothermal energy production from enhanced geothermal system (EGS) requires successfully stimulated a reservoir by cold water injection. During stimulation, large volumes of water are injected into low permeable hot formations to enhance reservoir permeability and to create fluid pathways for water circulation. Most geothermal reservoirs have some natural fractures, with discontinuities such as faults and joints occurring at various scales. A stimulation job usually intends to connect natural fractures to create a permeable zone. Natural fractures are usually stress sensitive, and they deform and slip/open due to injection induced stress changes. As fluid injection reduces the effective normal stress acting on the fracture, fracture aperture increases and reservoir permeability is increased. When the shear strength is exceeded, fractures could slip in shear. Shear slippage induces dilated aperture and can cause fracture extension, and the hydraulic conductivities of the reservoir will be further enhanced.

To simulate the response of an EGS to injection, two models are required: a 3D coupled thermal-poromechanical model describing the coupling between rock deformation, fluid flow and heat flow, and a fracture network model describing the fracture geometry and fluid transport within the fractures. One could use a boundary element method (BEM) (e.g., Safari and Ghassemi, 2015) or a finite element method (FEM) (e.g., Wang and Ghassemi, 2011, 2012 and 2013). A finite element approach is used in this work. The fracture network is generated based on field data and is introduced to a coupled THM model. The equivalent permeability concept used in Wan and Ghassemi (2011, 2013) approach is used to estimate the overall permeability of the fractured medium. The simulation outcome, spatial distribution of pressure changes, permeability evolution and injection induced microseismicity can be used to evaluate the stimulation process and to calibrate the simulation model.

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