Fluid flow in low-porosity/permeability reservoir rocks such as tight carbonates is mostly restricted to structural discontinuities (e.g. faults, fractures, karstified zones). Fault zones, in particular in such rocks, offer both suitable fluid flow pathways, but may also act as impermeable barriers. The heterogeneous permeability structure of fault zones, however, impedes pre-drilling investigations of exploration targets by numerical models. A better understanding of the factors that control the fluid flow and the heterogeneity of permeability distribution along fault zones in tight reservoirs is a pre-requisite for the definition of drilling targets. In this study, a hydraulic field laboratory with a volume of 30 m x 30 m x 20 m was set up in a quarry in SE Germany to investigate the influence of fault zones on the general permeability structure of tight carbonates. The test field contained three WNW-ESE-striking, repeatedly reactivated normal faults with offsets in the order of <1 m and two roughly perpendicularly oriented NNE-SSW-striking fracture corridors. Fault zones and fracture corridors were targeted by 62 wells. Wells that exhibited a decent hydraulic connection the to the overall conductive fracture network were logged (e.g. borehole image logs, FWS, etcs.) and in selected wells hydraulic tests were conducted. Water levels were measured both during static conditions and during testing. Due to the density of wells we were able to constrain the controlling factors for fluid flow along and across the fault zones. Damage zones were considered as conduits while the fault core was expected to be impermeable. These general assumptions could be confirmed by our tests, however we found some exceptions. While fluid flow in general is restricted to few, well-connected fractures, the majority of the fractures are dead ends, solely serving as storage for fluids. With increasing displacement and complexity of the fault zone, enhanced permeability parallel to the fault zone could be inferred. At larger offsets, where a thicker fault core develops, fhe fault core itself acts as barrier and fractures and fracture corridors do not penetrate the faults. We think that this is related to the presence of the much less competent fault core of a certain thickness which is able to accommodate the brittle deformation. Where the faults offset is less than ~0.4 m, the integrity of the fault seal is breached by fracture corridors, cross cutting the faults. This is clearly shown by the pressure distribution in static and transient conditions. Faulting, hence leads to a compartmentalization of the reservoir, where the compartments do either communicate or interact with significant delay. The information and data received from the conducted field tests furthermore serve as input parameters and validation for a newly developed numerical approach that aims to simulate fluid flow in this type of geological settings, results of which will be presented in an additional presentation by our project partners.

Quantifying the effective permeability structure of fault and fracture zones is crucial for numerous geo-energy applications, especially at sub-seismic scales. However, the multi-scale presence of fractures and the structural heterogeneity of faults and host rocks often cause highly non-stationary and anisotropic hydraulic properties. This usually impedes the definition of representative elementary volumes and complicates the upscaling process. Thus, progressively integrating these multi-scale complexities into 3D numerical models of exploration targets has gained increasing scientific interest in recent years and is crucial to make predictions of flow and transport through reservoirs.Here, we aim to reproduce multiple drawdown curves obtained in analog field pumping tests with numerical models of fluid flow in order to develop a proof of concept for generating correct hydraulic representations of fault and fracture zones in numerical models with the final goal to upscale their effective permeabilities for numerical simulations above the sub-seismic scale.The test subject is a 30- by 30-meter-wide area in a quarry in the Franconian Alb, Germany, featuring an intensively deformed Upper Jurassic limestone formation, frequently explored for geothermal energy production in the southern German Molasse Basin. First, an initial 3D structural model of the main faults, fractures, and layer surfaces, based on multiple borehole logs and pavement traces is constructed with the GemPy software. In the next step, we employ a newly developed discretization method to convert the initial 3D GemPy model into various equivalent continuum models of the test field by parameterizing fracture, fault, and rock matrix permeabilities/porosities, resulting in high-resolution 3D voxel models with individual, anisotropic permeability tensors. Those serve as input for numerical simulations of a pumping test, where we solve for transient, unsaturated/saturated Darcy-flow using a newly developed parallel, 3D finite element code that utilizes a van Genuchten approximation for the arising non-linearities, i.e., relative permeability and water content. As a final step, we compare the drawdown curves logged in three observation wells in an analog constant-head hydraulic test in the field to the ones obtained from the numerical simulations by computing a cumulative misfit. While changing the parameters of the employed permeability-porosity parametrizations for faults, fractures, and rock matrix in a classical forward-approach manner, we can determine a range of best-fitting models. Preliminary results show that with some educated initial guesses on the hydraulic properties of the reservoir, we could reproduce the drawdown curves in two observation wells with a relative error below one percent after a couple of tens of simulations. The uniqueness of those results will be assessed during the discussion.

Tight carbonate rocks are important hydrocarbon and potential geothermal reservoirs, for example, in CO 2 -Enhanced Geothermal Systems. We report a study of outcrop samples of tectonically undeformed tight carbonates from the upper Jurassic “Malm ß” formation in Southern Germany near the town of Simmelsdorf (38 km NE of Nuremberg) to understand bulk petrophysical properties in relation to microstructure and to compare models for permeability prediction in these samples. We applied Archimedes isopropanol immersion, Helium pycnometry, mercury injection, gamma density core logging, and gas permeability measurements, combined with microstructural investigations and liquid metal injection (LMI-BIB-SEM). In addition, ultrasonic velocity was measured to allow geomechanical comparison of stratigraphically equivalent rocks in the South German Molasse Basin (SGMB). Results show only small variations, showing that the formation is rather homogeneous with bulk porosities below 5% and argon permeabilities around 1.4E−17 m 2 . The presence of stylolites in some of the samples has neither a significant effect on porosity nor permeability. Pores are of submicron size with pore throats around 10 nm and connected as shown by Mercury injection and Liquid Metal injection. Samples have high dynamic Young’s Modulus of 73 ± 5 GPa as expected for lithified and diagenetically overmature limestones. Moreover, no trends in properties were observable toward the faults at meter scale, suggesting that faulting was post-diagenetic and that the matrix permeabilities were too low for intensive post-diagenetic fluid–rock interaction. Petrophysical properties are very close to those measured in the SGMB, illustrating the widespread homogeneity of these rocks and justifying the quarry as a reasonable reservoir analog. Permeability prediction models, such as the percolation theory-based Katz-Thompson Model, Poiseuille-based models, like the Winland, the Dastidar, the capillary tube, and the Kozeny-Carman Models, as well as several empirical models, namely, the Bohnsack, the Saki, and the GPPT Models, were applied. It is shown that the capillary tube Model and the Saki Model are best suited for permeability predictions from BIB-SEM and mercury injection capillary pressure results, respectively, providing a method to estimate permeability in the subsurface from drill cuttings. Matrix permeability is primarily controlled by the pore (throat) diameters rather than by the effective porosity.

Fluid flow in low-porosity/permeability reservoir rocks such as tight carbonates is mostly restricted to structural discontinuities (e.g. faults, fractures, karstified zones). Fault zones, in particular in such rocks, offer both suitable fluid flow pathways, but may also act as impermeable barriers. The heterogeneous permeability structure of fault zones, however, impedes pre-drilling investigations of exploration targets by numerical models. A better understanding of the factors that control the fluid flow and the heterogeneity of permeability distribution along fault zones in tight reservoirs is a pre-requisite for the definition of drilling targets. In this study, a hydraulic field laboratory with a volume of 30 m x 30 m x 20 m was set up in a quarry in SE Germany to investigate the influence of fault zones on the general permeability structure of tight carbonates. The test field contained three WNW-ESE-striking, repeatedly reactivated normal faults with offsets in the order of <1 m and two roughly perpendicularly oriented NNE-SSW-striking fracture corridors. Fault zones and fracture corridors were targeted by 62 wells. Wells that exhibited a decent hydraulic connection the to the overall conductive fracture network were logged (e.g. borehole image logs, FWS, etcs.) and in selected wells hydraulic tests were conducted. Water levels were measured both during static conditions and during testing. Due to the density of wells we were able to constrain the controlling factors for fluid flow along and across the fault zones. Damage zones were considered as conduits while the fault core was expected to be impermeable. These general assumptions could be confirmed by our tests, however we found some exceptions. While fluid flow in general is restricted to few, well-connected fractures, the majority of the fractures are dead ends, solely serving as storage for fluids. With increasing displacement and complexity of the fault zone, enhanced permeability parallel to the fault zone could be inferred. At larger offsets, where a thicker fault core develops, fhe fault core itself acts as barrier and fractures and fracture corridors do not penetrate the faults. We think that this is related to the presence of the much less competent fault core of a certain thickness which is able to accommodate the brittle deformation. Where the faults offset is less than ~0.4 m, the integrity of the fault seal is breached by fracture corridors, cross cutting the faults. This is clearly shown by the pressure distribution in static and transient conditions. Faulting, hence leads to a compartmentalization of the reservoir, where the compartments do either communicate or interact with significant delay. The information and data received from the conducted field tests furthermore serve as input parameters and validation for a newly developed numerical approach that aims to simulate fluid flow in this type of geological settings, results of which will be presented in an additional presentation by our project partners.

The Franconian Alb of SE Germany is characterized by large-scale exposures of Jurassic shallow marine limestones and dolostones, which are frequently considered to be outcrop analogues for deep geothermal reservoir rocks in the North Alpine Foreland Basin farther south. However, the burial history of the Franconian Alb Jurassic strata is not well known as they were affected by emersion, leading to extensive erosion and karstification with only remnants of the original Cretaceous and Cenozoic cover rocks preserved. To estimate the original thicknesses of the post-Jurassic overburden we investigated the petrophysical properties and the thermal history of Lower and Middle Jurassic mudstones to constrain their burial history in the Franconian Alb area. We measured mudstone porosities, densities, and maturities of organic material and collected interval velocities from seismic refraction and logging data in shallow mudstone-rich strata. Mudstone porosities and P-wave velocities vertical to bedding were then related to a normal compaction trend that was calibrated on stratigraphic equivalent units in the North Alpine Foreland Basin. Our results suggest maximum burial depths of 900–1700 m, 300–1100 m of which is attributed to Cretaceous and younger sedimentary rocks overlying the Franconian Alb Jurassic units. Compared to previous considerations this implies a more widespread distribution and increased thicknesses of up to ∼900 m for Cretaceous and up to ∼200 m for Cenozoic units in SE Germany. Maximum overburden is critical to understand mechanical and diagenetical compaction of the dolostones and limestones of the Upper Jurassic of the Franconian Alb. The results of this study therefore help to better correlate the deep geothermal reservoir properties of the Upper Jurassic from outcrop to reservoir conditions below the North Alpine Foreland Basin. Here, the Upper Jurassic geothermal reservoir can be found at depths of up to 5000 m.

Abstract Tight carbonate rocks are important potential although unconventional geothermal and hydrocarbon underground storage reservoirs and prospective CO 2 -EGS sites. We study these rocks by using the Upper Jurassic “Malm ß” in Southern Germany as an outcrop analog example to understand bulk properties in relation to microstructure and to test a variety of models for permeability prediction. Bulk petrophysical methods (Archimedes isopropanol immersion method, Helium pycnometry, mercury injection capillary pressure, gamma density core logging, gas permeability measurements) combined with microstructural investigations (BIB-SEM) are applied. Samples are macroscopically undeformed limestones collected from a tectonically overprinted quarry wall near the town of Simmelsdorf (38 km NE of Nürnberg city). Bulk porosities are below 5% and argon permeabilities are on average 1.4E-17m 2 . The presence of stylolites in some of the samples has neither a significant effect on porosity nor permeability. Pore sizes are in the submicron range and the diagenetically lithified stiff limestones are characterized by a relatively high Young’s Modulus averaging 73±5 MPa. Moreover, no trends in properties were observable towards the faults, indicating that faulting was post-diagenetic and that the matrix permeabilities were too low for intensive post-diagenetic fluid-rock interaction. Petrophysical properties are very close to those measured in stratigraphic equivalent rocks of the South German Molasse Basin, illustrating the widespread homogeneity of these rocks and justifying the quarry scale (500 x 580 m) as a reasonable reservoir analog for these rocks in the subsurface. The application of various permeability prediction models showed that the Capillary Tube model and the Saki Model are very well suited for predicting permeabilities from BIB-SEM and mercury injection capillary pressure results, respectively. We thereby found that the matrix permeability is primarily controlled by the pore throat diameters rather than the effective porosity.

In geothermal reservoir systems, changes in pore pressure due to production (depletion), injection or temperature changes result in a displacement of the effective stresses acting on the rock matrix of the aquifer. To compensate for these intrinsic stress changes, the rock matrix is subjected to poroelastic deformation through changes in rock and pore volume. This in turn may induce changes in the effective pore network and thus in the hydraulic properties of the aquifer. Therefore, for the conception of precise reservoir models and for long-term simulations, stress sensitivity of porosity and permeability is required for parametrization. Stress sensitivity was measured in hydrostatic compression tests on 14 samples of rock cores stemming from two boreholes of the Upper Jurassic Malm aquifer of the Bavarian Molasse Basin. To account for the heterogeneity of this carbonate sequence, typical rock and facies types representing the productive zones within the thermal reservoir were used. Prior to hydrostatic investigations, the hydraulic (effective porosity, permeability) and geomechanical (rock strength, dynamic, and static moduli) parameters as well as the microstructure (pore and pore throat size) of each rock sample were studied for thorough sample characterization. Subsequently, the samples were tested in a triaxial test setup with effective stresses of up to 28 MPa (hydrostatic) to simulate in-situ stress conditions for depths up to 2000 m. It was shown that stress sensitivity of the porosity was comparably low, resulting in a relative reduction of 0.7–2.1% at maximum effective stress. In contrast, relative permeability losses were observed in the range of 17.3–56.7% compared to the initial permeability at low effective stresses. Stress sensitivity coefficients for porosity and permeability were derived for characterization of each sample and the different rock types. For the stress sensitivity of porosity, a negative correlation with rock strength and a positive correlation with initial porosity was observed. The stress sensitivity of permeability is probably controlled by more complex processes than that of porosity, where the latter is mainly controlled by the compressibility of the pore space. It may depend more on the compaction of precedented flow paths and the geometry of pores and pore throats controlling the connectivity within the rock matrix. In general, limestone samples showed a higher stress sensitivity than dolomitic limestone or dolostones, because dolomitization of the rock matrix may lead to an increasing stiffness of the rock. Furthermore, the stress sensitivity is related to the history of burial diagenesis, during which changes in the pore network (dissolution, precipitation, and replacement of minerals and cements) as well as compaction and microcrack formation may occur. This study, in addition to improving the quality of input parameters for hydraulic–mechanical modeling, shows that hydraulic properties in flow zones largely characterized by less stiff, porous limestones can deteriorate significantly with increasing effective stress.

In the field of the efficiency of very shallow geothermal energy systems, there is still a significant need for research activity. To ensure the proper exploitation of this energy resource, the decisive geophysical parameters of soil must be well-known. Within this study, thermal conductivity, as a fundamental property for evaluating the geothermal potential of very shallow geothermal systems, was analyzed and measured with a TK04 device. A dataset, consisting of various geophysical parameters (thermal conductivity, bulk density, water content, and porosity) determined for a large range of different textural soil classes, was collated. In a new approach, the geophysical properties were visualized covering the complete grain size range. The comparison between the measured and calculated thermal conductivity values enabled an investigation with respect to the validity of the different Kersten equations. In the course of this comparison, the influence of effective bulk density was taken into account. In conclusion, both Kersten formulas should be used as recommended and regular bulk density corresponded better to the reference dataset representing the outcomes of the TK04 laboratory measurement. Another objective was to visualize the relation of thermal conductivities within their corresponding textural classes and the validity of Kersten formulas for various bulk densities, depths, and soils. As a result, the accessibility to information for expedient recommendations about the feasibility of very shallow geothermal systems will be improved. Easy, accessible know-how of the fundamentals is important for a growing renewable energy sector where very shallow geothermal installations can also cover heating and cooling demands.