Search

The static and poroelastic moduli of a porous rock, e.g., the drained bulk modulus, can be derived from stress-strain curves in rock mechanical tests, and the dynamic moduli, e.g., dynamic Poisson's ratio, can be determined by acoustic velocity and bulk density measurements. As static and dynamic elastic moduli are different, a correlation is often required to populate geomechanical models. A novel poroelastic approach is introduced to correlate static and dynamic bulk moduli of outcrop analogues samples, representative of Upper-Malm reservoir rock in the Molasse basin, southwestern Germany. Drained and unjacketed poroelastic experiments were performed at two different temperature levels (30 and 60 $$^\circ$$ C). For correlating the static and dynamic elastic moduli, a drained acoustic velocity ratio is introduced, corresponding to the drained Poisson's ratio in poroelasticity. The strength of poroelastic coupling, i.e., the product of Biot and Skempton coefficients here, was the key parameter. The value of this parameter decreased with increasing effective pressure by about 56 $$~\%$$ from 0.51 at 3 MPa to 0.22 at 73 MPa. In contrast, the maximum change in P- and S-wave velocities was only 3 % in this pressure range. This correlation approach can be used in characterizing underground reservoirs, and can be employed to relate seismicity and geomechanics (seismo-mechanics). [ABSTRACT FROM AUTHOR]

Pore pressure changes in a geothermal reservoir, as a result of injection and/or production of water, result in changes of stress acting on the reservoir rock and, consequently, changes in the mechanical and transport properties of the rock. Bulk modulus and permeability were measured at different pressures and temperatures. An outcropping equivalent of Rotliegend reservoir rock in the North German Basin (Flechtinger sandstone) was used to perform hydrostatic tests and steady state fluid flow tests. Permeability measurements were conducted while cycling confining pressure; the dependence of permeability on stress was determined at a constant downstream pressure of 1 MPa. Also, temperature was increased stepwise from 30 to 140 °C and crack porosity was calculated at different temperatures. Although changes in the volumes of cracks are not significant, the cracks control fluid flow pathways and, consequently, the permeability of the rock. A new model was derived which relates microstructure of porosity, the stress-strain curve, and permeability. Porosity change was described by the first derivative of the stress-strain curve. Permeability evolution was ascribed to crack closure and was related to the second derivative of the stress-strain curve. The porosity and permeability of Flechtinger sandstone were reduced by increasing the effective pressure and decreased after each pressure cycle. [ABSTRACT FROM AUTHOR]

During geothermal power production using a borehole doublet consisting of a production and injection well, the reservoir conditions such as permeability k, porosity φ and Skempton coefficient B at the geothermal research site Gross Schoenebeck/Germany will change. Besides a temperature decrease at the injection well and a change of the chemical equilibrium, also the pore pressure p p will vary in a range of approximately 44 MPa ± 10 MPa in our reservoir at −3850 to −4258 m depth. This leads to a poroelastic response of the reservoir rocks depending on effective pressure p eff (difference between mean stress and pore pressure), resulting in a change in permeability k, porosity φ and the poroelastic parameter Skempton coefficient B. Hence, we investigated the effective pressure dependency of Flechtinger sandstone, an outcropping equivalent of the reservoir rock via laboratory experiments. The permeability decreased by 21% at an effective pressure range from 3 to 30 MPa, the porosity decreased by 11% ( peff = 6 to 65 MPa) and the Skempton coefficient decreased by 24% ( peff = 4 to 25 MPa). We will show which mechanisms lead to the change of the mentioned hydraulic and poroelastic parameters and the influence of these changes on the productivity of the reservoir. The most significant changes occur at low effective pressures until 15 to 20 MPa. For our in situ reservoir conditions peff = 43 MPa a change of 10 MPa effective pressure will result in a change in matrix permeability of less than 4% and in matrix porosity of less than 2%. Besides natural fracture systems, fault zones and induced hydraulic fractures, the rock matrix its only one part of geothermal systems. All components can be influenced by pressure, temperature and chemical reactions. Therefore, the determined small poroelastic response of rock matrix does not significantly influence the sustainability of the geothermal reservoir. [ABSTRACT FROM AUTHOR]

A series of stimulation experiments were carried out at the geothermal research well in Groß Schönebeck (EGrSk 3/90) located in the northeastern part of Germany. The intended purpose of these experiments was to develop concepts for a productivity increase of the geothermal well to create an Enhanced Geothermal System (EGS). Two different kinds of stimulation types were performed. Hydraulic gel-proppant stimulations were conducted in sandstone sections with high initial permeability. Then a different fracturing concept was applied injecting high amounts of water. This waterfrac stimulation was realized in the entire open section including sandstones and volcanic rocks. Evidence of the creation and properties of a very long vertical fracture was retrieved from pressure response analyses demonstrating a bilinear flow regime. The production efficiency of the produced artificial fractures shows a strong dependence on reservoir pressure. At increased reservoir pressure the artificial fractures of all stimulated intervals are highly conductive and subsequently become less conductive during pressure decline. Hence the range of a suitable reservoir pressure is constrained by this fracture efficiency and limits the usage of this well as an injection well for geothermal power production. [ABSTRACT FROM AUTHOR]

The Rotliegend of the North German basin is the target reservoir of an interdisciplinary investigation program to develop a technology for the generation of geothermal electricity from low-enthalpy reservoirs. An in situ downhole laboratory was established in the 4.3 km deep well Groβ Schönebeck with the purpose of developing appropriate stimulation methods to increase permeability of deep aquifers by enhancing or creating secondary porosity and flow paths. The goal is to learn how to enhance the inflow performance of a well from a variety of rock types in low permeable geothermal reservoirs. A change in effective stress due to fluid pressure was observed to be one of the key parameters influencing flow properties both downhole and in laboratory experiments on reservoir rocks. Fluid pressure variation was induced using proppant-gel-frac techniques as well as waterfrac techniques in several different new experiments in the borehole. A pressure step test indicates generation and extension of multiple fractures with closure pressures between 6 and 8.4 MPa above formation pressure. In a 24-hour production test 859 m3 water was produced from depth indicating an increase of productivity in comparison with former tests. Different depth sections and transmissibility values were observed in the borehole depending on fluid pressure. In addition, laboratory experiments were performed on core samples from the sandstone reservoir under uniaxial strain conditions, i.e., no lateral strain, constant axial load. The experiments on the borehole and the laboratory scale were realized on the same rock types under comparable stress conditions with similar pore pressure variations. Nevertheless, stress dependences of permeability are not easy to compare from scale to scale. Laboratory investigations reflect permeability variations due to microstructural heterogeneities and the behavior in the borehole is dominated by the generation of connections to large-scale structural patterns. [ABSTRACT FROM AUTHOR]

— Knowledge of rock properties controlling the fluid movement is a basic prerequisite to understand the dynamical processes and the temperature and stress regime of the upper crust. Fracture networks were investigated on different scales to obtain quantitative results of fracture geometry like fracture length, orientation and fracture frequencies. Due to the scale effect, these parameters differ in several orders of magnitude in dependence of the scale of investigation. On the microscopic scale, fluorescent thin sections from cores were analysed and permeability was estimated for 2-D hydraulic networks. On the macroscopic scale, fracture parameters were determined from images of structural borehole measurements. The vicinity of the drill site represents the megascopic scale, where seismic reflectors were assumed as active hydraulic structures for construction of a fracture network. Compiling the fracture densities from all investigated scales and taking into consideration only the networks above the percolation threshold, the fracture length distribution follows a power law with an exponent of -1.9 ± 0.05. Besides the scale differences of the geometric parameters like fracture density and length and the hydraulic parameters like permeability, the connectivity of the networks seems to be a confining characteristic. This is quantitatively described by the percolation parameter and the mean number of intersections per fracture. When assuming a macroscopic hydraulic system at the percolation threshold for the KTB site, the macroscopic mean fracture length can be estimated to approximately 30 m. This stands in agreement with the hydraulic experiments on site. [ABSTRACT FROM AUTHOR]