Search

Abstract: The paper presents an approach for the interpretation of hydraulic tests of a CO2 storage reservoir. The sandstone reservoir is characterised by a fluviatile channel structure embedded in a low-permeability matrix. Pumping tests were carried out in three wells, with simultaneous pressure monitoring in each well. The hydraulic parameters (permeability and storativity) and the boundary configurations were calibrated using three different approaches: (i) parameter calibration and type curve interpretation for single-hole tests, (ii) calibration of the entire build-up phase for cross-hole tests, and (iii) calibration of the initial pressure response for cross-hole pumping tests. In addition, the arrival time of the pressure response was determined and provides additional information about the pathways of hydraulic connection. The measured pumping test permeabilities of the formation were much lower than those measured on the cores, which is very unusual. The pumping test permeabilities are mainly between 50mD and 100mD (millidarcy), while core samples show a mean aquifer permeability of 500–1100mD. Based on this it was concluded that some kind of continuous low-permeability structure exists, which was supported by core material. Three possible aquifer configurations were considered. The first and second were derived from traditional pumping test analysis and were conceptualised using flow boundaries. Each of the analyses provides a different result. A method was developed in which these differences were resolved by interpreting the pressure response with respect to its spatial and temporal sensitivity. This solution lead to a third configuration which was mainly based on spatially-variable permeabilities. Taking into account the pumping test results, the geological background and the behaviour of injected CO2, we consider only the third configuration to be realistic. The results are in good agreement with modelled CO2 arrival times and pressure history. [Copyright &y& Elsevier]

Abstract: Fluid samples have been collected between 2001 and 2009 from the two geothermal wells at the Groß Schönebeck site (North German basin). The samples were taken at 4100–4235m depth (∼150°C/∼45MPa) and analyzed for their chemical composition, with special focus on parameters relevant to scaling and corrosion. The fluids have very high salinity (193–265g/L total dissolved solids) and, typical for fluids from lower Permian (Rotliegend) sandstones, contain a complex mixture of aqueous compounds and dissolved gases. The aqueous phase is nearly saturated with respect to CaCl2 and NaCl, which together represent 98% of its salt content. Due to high chloride concentrations, the fluids can be considered highly corrosive. Various minerals, such as sulfates of the alkaline earths, are theoretically oversaturated and could precipitate due to changes in pressure and temperature conditions. Furthermore, even a slight change in pH and/or redox conditions could result in the formation of iron, manganese or lead scales. The fluid contains high amounts of dissolved gases (volume ratio of gas:liquid is about 1:1 at standard conditions), mainly consisting of nitrogen (∼80vol%) and methane (∼15vol%). Additional gases (hydrogen, carbon dioxide, helium, C2+) approach 5vol%. This study compares changes in fluid chemistry (of gas and solution), measured over eight years, with the history of geothermal well/reservoir activities (e.g. stimulation). It was found that changes occur mainly due to dilution of the formation fluid with the solutions used for stimulations (e.g. water-fracs) consisting mainly of shallow groundwater of low ionic strength. Some solutes (iron, lead, barium, sulfate, and bicarbonate), however, showed a different behavior as compared to the bulk (sodium, calcium, etc.), indicating that precipitation-, dissolution-, and/or redox reactions took place. Since the composition of the Groß Schönebeck fluid is a good example of many saline geothermal fluids worldwide, the insights gained into potential geochemical reactions will be crucial for general corrosion/scaling risk assessments. [Copyright &y& Elsevier]

Abstract: The geothermal research well GtGrSk4/05 at Groß Schönebeck, Germany, was hydraulically stimulated to develop an Enhanced Geothermal System in the Upper Rotliegend sandstones. Gel–proppant stimulation was selected to enhance reservoir productivity and to maintain it over the long term. Before the field tests, laboratory experiments were carried out to study embedding effects and long-term hydraulic conductivity changes in intermediate- and high-strength proppant types. Based on the laboratory results it was decided to place in the stimulated fractures large concentrations of a high-strength proppant. The success of the stimulation of GtGrSk4/05 was confirmed by production test and flowmeter log data. [Copyright &y& Elsevier]

Abstract: The design and results of a cyclic hydraulic fracturing experiment performed to enhance the productivity of the geothermal research well at Groß Schönebeck (Germany) are presented. The stimulation carried out in the low-permeability volcanics of the Lower Rotliegend (Lower Permian) included alternating stages with cyclic changes of low and high flow rates with up to 150L/s over six days in conjunction with the addition of quartz sand to support fracture opening. There was rapid water level increase in an adjacent well due to the stimulation (i.e. water injection). The subsequent production test showed the success of the fracture treatment, with the overall productivity of the treated well being increased by a factor of four. [Copyright &y& Elsevier]

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 the crustal stress state is important for the assessment of subsurface stability. In particular, stress magnitudes are essential for the calibration of geomechanical models that estimate a continuous description of the 3-D stress field from pointwise and incomplete stress data. Well established is the World Stress Map Project, a global and publicly available database for stress orientations, but for stress magnitude data only local data collections are available. Herein, we present the first comprehensive and open-access stress magnitude database for Germany and adjacent regions, consisting of 568 data records. In addition, we introduce a quality ranking scheme for stress magnitude data for the first time. [ABSTRACT FROM AUTHOR]

Abstract: A slip tendency analysis is used to assess the reactivation potential of shear and dilational fractures in a deep geothermal reservoir in the Northeast German Basin, based on the notion that slip on faults is controlled by the ratio of shear to normal stress acting on the plane of weakness in the in situ stress field. The reservoir rocks, composed of Lower Permian sandstones and volcanics, were stimulated by hydraulic fracturing. A surprisingly low microseismic activity was recorded with moment magnitudes M W ranging from −1.0 to −1.8. The slip tendency analysis suggests a critically stressed reservoir exists in the sandstones, whereas the volcanic rocks are less stressed. Rock failure first occurs with an additional pore pressure of 20MPa. Presumed failure planes form a conjugate set and strike NW and NE. Slip failure is more likely than tensional failure in the volcanic rocks because high normal stresses prevent tensional failure. These results from slip tendency analysis are supported by the spatial distribution of recorded microseismicity. Source characteristics indicate slip rather than extension along presumed NE striking failure planes. This suggests that slip tendency analysis is an appropriate method that can be used to understand reservoir behavior under modified stress conditions. [Copyright &y& Elsevier]

This study addresses the thermal–hydraulic–mechanical and chemical (THMC) behaviour of a research well doublet consisting of the injection well E GrSk 3/90 and the production well Gt GrSk 4/05 A(2) in the deep geothermal reservoir of Groß Schönebeck (north of Berlin, Germany). The reservoir is located between 3815 and 4247 m below sea level in the Lower Permian of the North German Basin (NGB). Both wells were hydraulically stimulated to enhance productivity. For the production well three stimulation treatments were performed in 2007: these three treatments result in a productivity increase from 2.4 m 3 /(h MPa) to 14.7 m 3 /(h MPa). The injection well was stimulated four times in 2002/2003, resulting in a corresponding productivity increase from 0.97 m 3 /(h MPa) to 7.5 m 3 /(h MPa). The necessary infrastructure for production and subsequent injection of geothermal fluid was established in June 2011. Between June 8, 2011 and November 8, 2013, 139 individual hydraulic tests were performed with produced/injected volumes ranging from 4.4 to 2567 m 3 . The productivity index decreased non-linearly from 8.9 m 3 /(h MPa) on June 8, 2011 to 0.6 m 3 /(h MPa) on November 8, 2013. Five possible reasons for the productivity decrease are discussed: wellbore fill, wellbore skin, the sustainability of induced fractures, two phase flow and compartmentalisation. For all hydraulic tests, the injectivity index remains almost constant at 4.0 m 3 /(h MPa). During 17 of 139 hydraulic tests a sudden increase of the productivity was observed. Possible reasons for this effect are discussed: accumulation of free gas and/or fines and scales within the fracture as well as changing hydraulic properties due to changing mechanical load on the fracture. [ABSTRACT FROM AUTHOR]