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It is well known that the complicated channeling of fluid flow and heat transfer is strongly related with the intricate natural fracture system. However, it is still challenging to set up the fracture network model which is strong heterogeneous. Compared with other methods (e.g. equivalent continuum model (ECM), discrete fracture model (DFM), and ECM-DFM), the fracture flow module in the COMSOL Multiphysics simulator is powerful in definition of fractures as the inner flow boundary existing in the porous media. Thus it is selected to simulate the fluid flow and heat transfer in the geothermal-developed fractured granite of Sanguliu area located at Liaodong Peninsula, Eastern China. The natural faults/fractures based on field investigation combined with the discrete fracture network (DFN) generated by the MATLAB are used to represent the two-dimensional geological model. Numerical results show that early thermal breakthrough occurs at the production well caused by quick flow of cold water along the highly connected fractures. Suitable hydraulic fracturing treatments with proper injection rates, locations, etc. can efficiently hinder the thermal breakthrough time in the natural fracture system. Large well spacing helps the long-term operation of geothermal production, but it is highly dependent on the geometrical morphology of the fracture network. The enhancement of reservoir properties at the near-well regions can also increase the geothermal production efficiency. The results in this study can provide references to achieve a sustainable geothermal exploitation in fractured granitic geothermal reservoirs or hot dry rocks at depth.

Understanding the anisotropic creep behaviors of shale under direct shearing is a challenging issue. In this context, we conducted shear-creep and steady-creep tests on shale with five bedding orientations (i.e. 0°, 30°, 45°, 60°, and 90°), under multiple levels of direct shearing for the first time. The results show that the anisotropic creep of shale exhibits a significant stress-dependent behavior. Under a low shear stress, the creep compliance of shale increases linearly with the logarithm of time at all bedding orientations, and the increase depends on the bedding orientation and creep time. Under high shear stress conditions, the creep compliance of shale is minimal when the bedding orientation is 0°, and the steady-creep rate of shale increases significantly with increasing bedding orientations of 30°, 45°, 60°, and 90°. The stress-strain values corresponding to the inception of the accelerated creep stage show an increasing and then decreasing trend with the bedding orientation. A semilogarithmic model that could reflect the stress dependence of the steady-creep rate while considering the hardening and damage process is proposed. The model minimizes the deviation of the calculated steady-state creep rate from the observed value and reveals the behavior of the bedding orientation's influence on the steady-creep rate. The applicability of the five classical empirical creep models is quantitatively evaluated. It shows that the logarithmic model can well explain the experimental creep strain and creep rate, and it can accurately predict long-term shear creep deformation. Based on an improved logarithmic model, the variations in creep parameters with shear stress and bedding orientations are discussed. With abovementioned findings, a mathematical method for constructing an anisotropic shear creep model of shale is proposed, which can characterize the nonlinear dependence of the anisotropic shear creep behavior of shale on the bedding orientation.

As one of the most important ways to reduce the greenhouse gas emission, carbon dioxide (CO2) enhanced gas recovery (CO2-EGR) is attractive since the gas recovery can be enhanced simultaneously with CO2sequestration. Based on the existing equation of state (EOS) module of TOUGH2MP, extEOS7C is developed to calculate the phase partition of H2O–CO2–CH4–NaCl mixtures accurately with consideration of dissolved NaCl and brine properties at high pressure and temperature conditions. Verifications show that it can be applied up to the pressure of 100 MPa and temperature of 150 °C. The module was implemented in the linked simulator TOUGH2MP-FLAC3D for the coupled hydro–mechanical simulations. A simplified three-dimensional (3D) 1/4 model (2.2 km × 1 km × 1 km) which consists of the whole reservoir, caprock and baserock was generated based on the geological conditions of a gas field in the North German Basin. The simulation results show that, under an injection rate of 200,000 t/yr and production rate of 200,000 sm3/d, CO2breakthrough occurred in the case with the initial reservoir pressure of 5 MPa but did not occur in the case of 42 MPa. Under low pressure conditions, the pressure driven horizontal transport is the dominant process; while under high pressure conditions, the density driven vertical flow is dominant. Under the considered conditions, the CO2-EGR caused only small pressure changes. The largest pore pressure increase (2 MPa) and uplift (7 mm) occurred at the caprock bottom induced by only CO2injection. The caprock had still the primary stress state and its integrity was not affected. The formation water salinity and temperature variations of ±20 °C had small influences on the CO2-EGR process. In order to slow down the breakthrough, it is suggested that CO2-EGR should be carried out before the reservoir pressure drops below the critical pressure of CO2.