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Abstract. Various geoscientific applications require a fast prediction of fracture permeability for an optimal workflow. Hence, the objective of the current study is to introduce and validate a practical method to characterize and approximate single flow in fractures under different stress conditions by using a core-flooding apparatus, in situ X-ray computed tomography (CT) scans and a finite-volume method solving the Navier-Stokes-Brinkman equations. The permeability of the fractured sandstone sample was measured stepwise during a loading-unloading cycle (0.7 to 22.1 MPa and back) to validate the numerical results. Simultaneously, the pressurized core sample was imaged with a medical X-ray CT scanner with a voxel dimension of 0.5 × 0.5 × 1.0 mm 3 . Fracture geometries were obtained by CT images based on a modification of the simplified missing attenuation (MSMA) approach. Simulation results revealed both qualitative plausibility and a quantitative approximation of the experimentally derived permeabilities. The qualitative results indicate flow channeling along several preferential flow paths with less pronounced tortuosity. Significant changes in permeability can be assigned to temporal and permanent changes within the fracture due to applied stresses. The deviations of the quantitative results appear to be mainly caused by both local underestimation of hydraulic properties due to compositional matrix heterogeneities and the low CT resolution affecting the accurate capturing of sub-grid-scale features. Both affect the proper reproduction of the actual connectivity and therefore also the depiction of the expected permeability hysteresis. Furthermore, the threshold value CT mat (1862.6 HU) depicting the matrix material represents the most sensitive input parameter of the simulations. Small variations of CT mat can cause enormous changes in simulated permeability by up to a factor of 2.6 ± 0.1 and, thus, have to be defined with caution. Nevertheless, comparison with further CT-based flow simulations indicates that the proposed method represents a valuable method to approximate actual permeabilities, particularly for smooth fractures (< 35 µm). However, further systematic investigations concerning the applicability of the method are essential for future studies. Thus, some recommendations are compiled by also including suggestions of comparable studies.

As estimated by the International Energy Agency, geothermal power can contribute to 3.5 % of worldwide power and 3.9 % to heat production by 2050. This includes the development of enhanced geothermal systems (EGSs) in low‐enthalpy systems. EGS technology is still in an early stage of development. Pushing EGS technologies towards market maturity requires a long‐term strategic approach and massive investments in research and development. Comprehensive multidisciplinary research programs that combine fundamental and applied concepts to tackle technological, economic, ecological, and safety challenges along the EGS process chain are needed. The Karlsruhe Institute of Technology (KIT) has defined a broad research program on EGS technology development following the necessity of a transdisciplinary approach. The research concept is embedded in the national research program of the Helmholtz Association and is structured in four clusters: reservoir characterization and engineering, thermal water circuit, materials and geoprocesses, and power plant operation. The proximity to industry, closely interlinked with fundamental research, forms the basis of a target‐orientated concept. The present paper aims to give an overview of geothermal research at KIT and emphasizes the need for concerted research efforts at the international level to accelerate technological breakthrough of EGS as an essential part of a future sustainable energy system.

Abstract. The objective of the current study is to investigate and validate stress-dependent single fluid flow in a fractured core sample using in situ X-ray computed tomography (CT) scans and a finite-volume method solving the Navier-Stokes-Brinkman equations. The permeability of the fractured sandstone sample was measured stepwise during a loading-unloading cycle (0.7 MPa to 22.1 MPa and back) to validate the numerical results. Simultaneously, the pressurized core sample was imaged with a medical X-ray CT scanner with a voxel dimension of 0.5 × 0.5 × 1.0 mm3. Fracture geometries were obtained by CT images based on the Missing Attenuation (MA) approach. Simulation results revealed both, qualitative plausibility and a quantitative approximation of the experimentally derived permeabilities. The qualitative results indicate flow channeling along several preferential flow paths with less pronounced tortuosity. Significant changes in permeability can be assigned to temporal and permanent changes within the fracture due to applied stresses. The applied fluid flow simulations also incorporate potential fracture-matrix interaction and permeability anisotropy within the matrix caused by high-porosity layers. The deviations of the quantitative results appear to be mainly caused by the low resolution affecting the accurate capturing of sub-grid scale features and the reproduction of the actual connectivity. Furthermore, the threshold value CTmat (1862.6 HU) depicting the matrix material represents the most sensitive input parameter of the simulations. Small variations of CTmat (±17.7 HU in this study) can cause enormous changes in simulated permeability by up to a factor of 2.6 ± 0.1 and, thus, has to be defined with caution. Finally, our results are also compared with other studies showing similar results. Based on these observations various recommendations to improve CT image quality, model quality, aperture calibration and validation of qualitative fluid flow are provided.

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Dear reviewer, fluid flow simulations were re-simulated with adjusted fluid properties. As expected, new experimental and simulated results are lower than before, however do not affect their relative behavior and, hence, do not affect the general conclusions of the paper.As we stated mistakenly, the experiments were not performed with water but with nitrogen. Indeed, nitrogen is not an incompressible fluid, however experimental conditions were chosen so that fluid flow simulations can be represented by a laminar, incompressible approach. The experiment was conducted at 2.1 MPa pore pressure so that C1

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