Permeability of fractures in shale rocks – Influence of pressure, temperature, stress and fluid chemistry

We conducted fracture permeability experiments on shales at elevated confining pressures, p_c, temperatures, T, and differential stresses, 𝜎, representing in situ conditions (z≈2-3km). Examined rocks were Wissenbach shale, which is of Variscan age, recovered from the `Hahnenklee' drill site (Harz mountains, Germany). Petrophysical (He-pycnometry, Energy dispersive X-ray diffraction) as well as microstructural observations (scanning electron microscopy) reveal a fine grained, anisotropic shale matrix (grain size d ≤ 50 µm) with porosity values of 𝜙_He = 1-2%. Main shale components were identified as mechanically weak phyllosilicates, intermediate strong carbonates and strong quartz minerals. Constant strain rate deformation experiments performed at p_c = 50 MPa and T = 100 °C prior to fracture conductivity tests reveal predominantly brittle deformation behavior. Peak strength was substantially higher for samples loaded perpendicular to the visible bedding orientation compared to bedding-parallel loading. Fracture permeability tests were done on samples prepared with a saw-cut of given roughness, allowing to measure the evolution of fracture permeability with time under pre-defined p_c-T-𝜎 conditions using water and reservoir representative fluids. With increasing p_c and 𝜎, fracture permeability, k, decreases, approaching a minimum value at high p_c (> 20 MPa) and 𝜎 (> 45 MPa), possibly induced by a change from fluid flow through the entire fracture towards flow through localized channels. Comparing the initial and final roughness of the fracture surfaces after experiments reveals that the amount of asperities is reduced. Above T = 40°C, the influence of increasing temperature on permeability is relatively low as k remains nearly constant up to 100 °C, after an initial reduction if temperature was increased from 20 to 40 °C. However, we found a higher concentration of Na⁺ rather than Si⁴⁺ at enhanced temperatures of T = 70°C and T=90°C, respectively. In addition, Na- and Si-bearing minerals exhibited a higher dissolution rate at T=90°C, if compared to T=70°C. Our results suggest that the investigated shales may be considered as a potential host rock for (unconventional) Enhanced Geothermal Systems (EGS) as the influence of mechanical in situ boundary conditions as well as (fluid) chemistry is relatively low.