Predictability of properties of a fractured geothermal reservoir: the opportunities and limitations of an outcrop analogue study

Abstract

Minimizing exploration risk in deep geothermics is of great economic importance. Especially, knowledge about temperature and permeability of the reservoir is essential. We test the potential of an outcrop analogue study to minimize uncertainties in prediction of the rock properties of a fractured reservoir in the Upper Rhine Graben. Our results show that although mineralogical composition, clay content, grain size, and fabric type are basically comparable, porosity and quartz cementation are not. Young’s modulus, as observed in the outcrop closest to the reservoir is about twice as high (~ 64 GPa) as observed in the reservoir (~ 34 GPa). Most importantly, however, the parameters that describe the fracture system, which are essential to predict reservoir permeability, differ significantly. While the outcrops are dominated by perpendicular fracture sets (striking NE–SW and NW–SE), two different conjugate fracture sets (striking NW–SE and N–S) occur in the reservoir. Fracture apertures, as reported from the FMI, are one order of magnitude wider than in the outcrop. We conclude that our outcrop analogue study fails to predict important properties of the reservoir (such as permeability and porosity). This must be in part because of the tectonically complex setting of the reservoir. We propose that analogue studies are important, but they must be treated with care when attempting to predict the controlling parameters of a fractured reservoir.