Hydraulic fracture apertures predominantly control fluid transport in fractured rock masses. Hence, the objective of the current study is to investigate and compare three different laboratory-scale methods to determine hydraulic apertures in fractured (Fontainebleau and Flechtinger) sandstone samples with negligible matrix permeability. Direct measurements were performed by using a flow-through apparatus and a transient-airflow permeameter. In addition, a microscope camera permitted measuring the mechanical fracture apertures from which the corresponding hydraulic apertures were indirectly derived by applying various empirical correlations. Single fractures in the sample cores were generated artificially either by axial splitting or by a saw cut resulting in hydraulic apertures that ranged between 8 and 66 µm. Hydraulic apertures, accurately determined by the flow-through apparatus, are used to compare results obtained by the other methods. The transient-airflow permeameter delivers accurate values, particularly when repeated measurements along the full fracture width are performed. In this case, the derived mean hydraulic fracture apertures are in excellent quantitative agreement. When hydraulic apertures are calculated indirectly from optically determined mechanical apertures using empirical equations, they show larger variations that are difficult to compare with the flow-through-derived results. Variations in hydraulic apertures as observed between methods are almost certainly related to differences in sampled fracture volume. Overall, using direct flow-through measurements as a reference, this study demonstrates the applicability of portable methods to determine hydraulic fracture apertures at both the laboratory and outcrop scales.

The hydromechanical properties of single self-propping fractures under stress are of fundamental interest for fractured-rock hydrology and a large number of geotechnical applications. This experimental study investigates fracture closure and hydraulic aperture changes of displaced tensile fractures, aligned tensile fractures, and saw-cut fractures for two types of sandstone (i.e., Flechtinger and Fontainebleau) with contrasting mechanical properties, cycling confining pressure between 5 and 30 MPa. Emphasis is placed on how surface roughness, fracture wall offset, and the mechanical properties of the contact asperities affect the self-propping potential of these fractures under normal stress. A relative fracture wall displacement can significantly increase fracture aperture and hydraulic conductivity, but the degree of increase strongly depends on the fracture surface roughness. For smooth fractures, surface roughness remains scale-independent as long as the fracture area is larger than a roll-off wavelength and thus any further displacement does not affect fracture aperture. For rough tensile fractures, these are self-affine over a larger scale so that an incremental fracture wall offset likely leads to an increase in fracture aperture. X-ray microtomography of the fractures indicates that the contact area ratio of the tensile fractures after the confining pressure cycle inversely correlates with the fracture wall offset yielding values in the range of about 3–25%, depending, first, on the respective surface roughness and, second, on the strength of the asperities in contact. Moreover, the contact asperities mainly occur isolated and tend to be preferentially oriented in the direction perpendicular to the fracture wall displacement which, in turn, may induce flow anisotropy. This, overall, implies that relatively harder sedimentary rocks have a higher self-propping potential for sustainable fluid flow through fractures in comparison to relatively soft rocks when specific conditions regarding surface roughness and fracture wall offset are met.

Temperature changes and variations in pore fluid salinity may negatively affect the permeability of clay‐bearing sandstones with implications for natural fluid flow and geotechnical applications alike. In this study these factors are investigated for a sandstone dominated by illite as the clay phase. Systematic long‐term flow‐through experiments were conducted and complemented with comprehensive microstructural investigations and the application of Derjaguin‐Landau‐Verwey‐Overbeek (DLVO) theory to explain mechanistically the observed permeability changes. Initially, sample permeability was not affected by low pore fluid salinity indicating strong attraction of the illite particles to the pore walls as supported by electron microprobe analysis (EMPA). Increasing temperature up to 145°C resulted in an irreversible permeability decrease by 1.5 orders of magnitude regardless of the pore fluid composition (i.e., deionized water and 2 M NaCl solution). Subsequently diluting the high salinity pore fluid to below 0.5 M yielded an additional permeability decline by 1.5 orders of magnitude, both at 145°C and after cooling to room temperature. By applying scanning electron microscopy (SEM) and mercury intrusion porosimetry (MIP) thermo‐mechanical pore throat closure and illite particle migration were identified as independently operating mechanisms responsible for observed permeability changes during heating and dilution, respectively. These observations indicate that permeability of illite‐bearing sandstones will be impaired by heating and exposure to low salinity pore fluids. In addition, chemically induced permeability variations proved to be path dependent with respect to the applied succession of fluid salinity changes.

Hundreds of geothermal wells have been drilled in Hungary to exploit Pannonian Basin sandstones for district heating, agriculture, and industrial heating projects. Most of these sites suffer from reinjection issues, limiting efficient use of this vast geothermal resource and imposing significant extra costs for the required frequent workovers and maintenance. To better understand the cause of this issue requires details of reservoir rock porosity, permeability, and mineralogy. However, publicly available data for the properties of reservoir rocks at geothermal project sites in Hungary is typically very limited, because these projects often omit or limit data acquisition. Many hydrocarbon wells in the same rocks are more extensively documented, but their core, log, or production data are typically decades old and unavailable in the public domain. Furthermore, because many Pannonian sandstone formations are poorly consolidated, coring was always limited and the collected core often unsuitable for conventional analysis, only small remnant fragments typically being available from legacy hydrocarbon wells. This study aims to reduce this data gap and to showcase methods to derive reservoir properties without using core for flow experiments. The methods are thin-section analysis, XRD analysis and mercury intrusion porosimetry, and X-CT scanning followed by numerical flow simulation. We validate our results using permeability data from conventional production testing, demonstrating the effectiveness of our method for detailed reservoir characterization and to better constrain the lateral variation in reservoir properties across the Pannonian Basin. By eliminating the need for expensive bespoke coring to obtain reservoir properties, such analysis will contribute to reducing the capital cost of developing geothermal energy projects, thus facilitating decarbonization of global energy supply.

The long-term sustainability of fractures within rocks determines whether it is reasonable to utilize such formations as potential EGS reservoirs. Representative for reservoirs in Variscan metamorphic rocks, three long-term (one month each) fracture permeability experiments on saw-cut slate core samples from the Hahnenklee well (Harz Mountains, Germany) were performed. The purpose was to investigate fracture permeability evolution at temperatures up to 90 °C using both deionized water (DI) and a 0.5 M NaCl solution as the pore fluid. Flow with DI resulted in a fracture permeability decline that is more pronounced at 90 °C, but permeability slightly increased with the NaCl fluid. Microstructural observations and analyses of the effluent composition suggest that fracture permeability evolution is governed by an interplay of free-face dissolution and pressure solution. It is concluded that newly introduced fractures may be subject to a certain permeability reduction due to pressure solution that is unlikely to be mitigated. However, long-term fracture permeability may be sustainable or even increase by free-face dissolution when the injection fluid possesses a certain (NaCl) salinity.