In most geothermal reservoirs fluid flow is largely controlled by the permeability of the fracture system in the host rock. Both for the direct use of reservoirs, as well as for effective stimulation, the geometry of the existing fracture system and its likely future development need to be known as accurately as possible. Here I review manifold elements of multidisciplinary approaches, altogether aiming at reliable estimations of potential fluid flow in geothermal reservoirs. Focus is on parameters and methods useful for fluidflow estimations in geothermal reservoirs, and their interdependencies. Examples include the following: 1) Field studies in fracturecontrolled paleo-geothermal reservoirs in fault zones in Great Britain and in outcrop analogues of Mesozoic rocks that could be used to host geothermal reservoirs in Germany. 2) Numerical models of local stress fields that provide the basis for numerical models of fracture propagation and fluid flow in geothermal reservoirs. The presented studies increase our understanding of fluid flow in geothermal reservoirs. Considering all relevant parameters and processes for reliable estimations of the existing fracture system and potential fluid flow in geothermal reservoirs contributes to maximize the likelihood of success of geothermal wells.

We present a field-study based workflow to develop 3D-numerical models on local stress fields within fault zones hosted in layered rocks at reservoir depths. As an example we use the carbonate successions of the Upper Muschelkalk (Middle Triassic) in the Upper Rhine Graben, Southwest Germany, that form a reservoir for deep geothermal energy. Steps of the workflow include (A) characterization of fault-zone units and mechanical layering, (B) estimations of rock mechanical properties and (C) assumptions on the in situ stress regime. Results of 3D-numerical models of fault-zone local stress fields at reservoir depth of 2900 m show pronounced differences depending on (1) fault-zone orientation, (2) impact of maximum horizontal stress SH in the given stress regime (normal faulting, strike-slip faulting or transitional normal to strike-slip faulting), (3) fault-zone scale and (4) contrast in mechanical properties. Soft fault damage zones and fault cores trending at a minor angle to SH (0°–30°) concentrate less stress than comparable units at higher angles to SH (60°–90°), in particular in the strike-slip regime. The impact of mechanical layering increases with horizontal compression. This may result, for example, in formation of barriers to fracture propagation and thus lower probability of forming well-interconnected fracture networks necessary for fluid flow in reservoirs. Comparisons to estimated fault-zone stress states such as dilation and slip tendencies, show that their prediction in the study area is difficult because of the current transitional stress regime (normal to strike-slip faulting) and, in addition, varying orientations of SH.

Close to the western Upper Rhine Graben Main Fault, Alsace, a NNE–SSW-striking fault zone, crosscutting porous, thick bedded Lower Triassic Bunter sandstone was investigated in detail, including its architecture, discontinuity system, mechanical rock properties and implications on its permeability structure and fault zone type. Field observations indicate a three-part fault zone structure including core-, transition- and damage zone. The at least 14m thick fault core is composed of various slip surfaces and deformation bands, which encompass fractured host rock lenses. When connected, host rock lenses may transport fluids through the core zone. Adjacent transition zones are highly fractured in R1-orientation, show folded beds and contain P1-oriented deformation bands. R1 and P1-fractures are synthetic shear fractures and project with an acute angle (10–20°) toward the fault plane. Only in the damage zone, fault-parallel striking fractures occur. Here, increasing fracture apertures and connectivity may increase the permeability toward the fault core. Mechanical rock properties from 12 rock samples (Young's modulus, uniaxial compressive strength, tensile strength) measured in all the parts of the fault zone, show highest values within the transition zone. In-situ measurements of rebound-hardnesses with a Schmidt-Hammer and analytical approaches, however, indicate that effective Young's moduli are two to sixteen times lower than the Young's moduli of intact rock. Values clearly decrease toward the fault core, even in the transition zone and are in average lower than effective Young's moduli in the damage zone. Although many fault zones in sandstone are sealing structures these field study show, that fault zones in porous sandstone may allow fluid flow.

Fault zone structure and lithology affect permeability of Triassic Muschelkalk limestone-marl-alternations in Southwest Germany, a region characterized by a complex tectonic history. Field studies of eight fault zones provide insights into fracture system parameters (orientation, density, aperture, connectivity, vertical extension) within fault zone units (fault core, damage zone). Results show decreasing fracture lengths with distances to the fault cores in well-developed damage zones. Fracture connectivity at fracture tips is enhanced in proximity to the slip surfaces, particularly caused by shorter fractures. Different mechanical properties of limestone and marl layers obviously affect fracture propagation and thus fracture system connectivity and permeability. Fracture apertures are largest parallel and subparallel to fault zones and prominent regional structures (e.g., Upper Rhine Graben) leading to enhanced fracture-induced permeabilities. Mineralized fractures and mineralizations in fault cores indicate past fluid flow. Permeability is increased by the development of hydraulically active pathways across several beds (non-stratabound fractures) to a higher degree than by the formation of fractures interconnected at fracture tips. We conclude that there is an increase of interconnected fractures and fracture densities in proximity to the fault cores. This is particularly clear in more homogenous rocks. The results help to better understand permeability in Muschelkalk rocks.

Abstract. Information about geomechanical and physical rock properties, particularly uniaxial compressive strength (UCS), are needed for geomechanical model development and updating with logging-while-drilling methods to minimise costs and risks of the drilling process. The following parameters with importance at different stages of geothermal exploitation and drilling are presented for typical sedimentary and volcanic rocks of the Northwest German Basin (NWGB): physical (P wave velocities, porosity, and bulk and grain density) and geomechanical parameters (UCS, static Young's modulus, destruction work and indirect tensile strength both perpendicular and parallel to bedding) for 35 rock samples from quarries and 14 core samples of sandstones and carbonate rocks. With regression analyses (linear- and non-linear) empirical relations are developed to predict UCS values from all other parameters. Analyses focus on sedimentary rocks and were repeated separately for clastic rock samples or carbonate rock samples as well as for outcrop samples or core samples. Empirical relations have high statistical significance for Young's modulus, tensile strength and destruction work; for physical properties, there is a wider scatter of data and prediction of UCS is less precise. For most relations, properties of core samples plot within the scatter of outcrop samples and lie within the 90% prediction bands of developed regression functions. The results indicate the applicability of empirical relations that are based on outcrop data on questions related to drilling operations when the database contains a sufficient number of samples with varying rock properties. The presented equations may help to predict UCS values for sedimentary rocks at depth, and thus develop suitable geomechanical models for the adaptation of the drilling strategy on rock mechanical conditions in the NWGB.

Fades and diagenetic heterogeneities in carbonate reservoir rocks affect both, fracture distribution and fracture permeability. Many studies focussed on fracture patterns in limestone-marl alternations, as e.g. fluid flow models, are based on laterally continuous beds. Here we examine 4010 fractures in multiple layers of limestone-marl alternations using a modified scan-line method. The studied successions belong to the Blue Lias Formation (Hettangian-Sinemurian), exposed on the coast of the Bristol Channel, United Kingdom. We combine methods of sedimentology and structural geology with rock physics to gain a better understanding of the role of fades, diagenesis and petrophysical properties (tensile and compressive strength, hardness, porosity) on the distribution of fractures (fracture orientation, density, spacing and height). Fracture distribution varies significantly despite similar bed thicknesses, indicating that planar bedding planes (i.e. well-bedded limestones, WBL) and beds with bedding plane irregularities (i.e. semi-nodular limestones, SNL) must be distinguished. SNL show higher percentages of non-stratabound fractures (67%) while they are more stratabound in WBL (57%). Additionally, beds with variable bed thicknesses (in scale of 15 m long beds) exhibit a wide range of fracture spacing, whereas fractures in beds with more continuous bed thicknesses are more regularly spaced. Considering all lithologies, the percentage of non-stratabound fractures increases proportionally with CaCO3 content. Three subsections studied in detail reveal different main sedimentological and diagenetic features (from early lithified over differentially compacted to physically compacted). All of them are characterised by dissimilar percentages of stratabound and non-stratabound fractures in limestone beds and marl interbeds. Our findings demonstrate that the distribution of fractures in individual well-bedded limestones is not necessarily representative for successions of limestone marl alternations; multiple layers should therefore be studied in outcrop analogues as basis for fluid flow models of reservoirs composed of such lithologies. (C) 2014 Elsevier Ltd. All rights reserved.

Magma transfer, i.e., dike propagation, is partly controlled by Young's modulus (elasticity) contrasts (ratio upper layer to lower layer modulus) in the host rock. Here we try to better constrain the elasticity contrasts controlling the propagation velocity of dikes and their arrest. We simulate dike propagation in layered elastic media with different elasticity contrasts. Salted gelatin and water represent host rock and magma, respectively. For common density ratios between magma and host rock (1.1), velocity variations are observed and a critical threshold in the elasticity contrast between layers results in the Young's modulus ratio of 2.10.6. Naturally occurring elasticity contrasts can be much higher than this experimental threshold, suggesting that dike arrest due to heterogeneous elastic host rock properties is more frequent than expected. Examples of recently deflected or stalled dikes inside volcanoes and the common presence of high-velocity bodies below volcanoes suggest that better defining elasticity contrasts below volcanoes helps in forecasting eruptions.

We present a new solution for estimating the fluid overpressure (driving-pressure or net-pressure) acting on the walls of a fracture with an arbitrary opening displacement. In the paper, we first present a forward modeling solution, using Fourier cosine series, for the opening displacement of a fracture subject to an overpressure that varies irregularly along the length of a fracture. By changing the form of the solution, we provide a matrix equation for estimating the Fourier coefficients and thereby obtain the overpressure variation from the fracture geometry. As numerical tests of this inverse analysis, we estimated the overpressure variation from fracture-opening displacements given by well known analytical solutions, and found that this method can be used for overpressure estimates for a variety of fluid-driven fractures. We apply our solutions to a mineral vein hosted by gneiss (West Norway) and conclude from the aperture variation that, at the time of vein formation, the overpressure increased toward the vein tip. We also discuss the physical meaning of the Fourier coefficients by applying our results to man-made hydraulic wing fractures. The results indicate that the coefficients of n = 0 and n = 1 relate to the fluid overpressure and the critical stress intensity factor.

Fractures generated by internal fluid pressure, for example, dykes, mineral veins, many joints and man-made hydraulic fractures, are referred to as hydrofractures. Together with shear fractures, they contribute significantly to the permeability of fluid reservoirs such as those of petroleum, geothermal water, and groundwater. Analytical and numerical models show that – in homogeneous host rocks – any significant overpressure in hydrofractures theoretically generates very high crack tip tensile stresses. Consequently, overpressured hydrofractures should propagate and help to form interconnected fracture systems that would then contribute to the permeability of fluid reservoirs. Field observations, however, show that in heterogeneous and anisotropic, e.g., layered, rocks many hydrofractures become arrested or offset at layer contacts and do not form vertically interconnected networks. The most important factors that contribute to hydrofracture arrest are discontinuities (including contacts), stiffness changes between layers, and stress barriers, where the local stress field is unfavourable to hydrofracture propagation. A necessary condition for a hydrofracture to propagate to the surface is that the stress field along its potential path is everywhere favourable to extension-fracture formation so that the probability of hydrofracture arrest is minimised. Mechanical layering and the resulting heterogeneous stress field largely control whether evolving hydrofractures become confined to single layers (strata¬bound frac¬tures) or not (non-stratabound fractures) and, there¬fore, if a vertically intercon¬nec¬ted fracture system forms. Non-stratabound hydrofractures may propagate through many layers and generate interconnected fracture systems. Such systems commonly reach the percolation threshold and largely control the overall permeability of the fluid reservoirs within which they develop.