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- ItemA numerical sensitivity study of how permeability, porosity, geological structure, and hydraulic gradient control the lifetime of a geothermal reservoir(Göttingen : Copernicus Publ., 2019) Bauer, Johanna F.; Krumbholz, Michael; Luijendijk, Elco; Tanner, David C.Geothermal energy is an important and sustainable resource that has more potential than is currently utilized. Whether or not a deep geothermal resource can be exploited, mostly depends on, besides temperature, the utilizable reservoir volume over time, which in turn largely depends on petrophysical parameters. We show, using over 1000 (n=1027) 4-D finite-element models of a simple geothermal doublet, that the lifetime of a reservoir is a complex function of its geological parameters, their heterogeneity, and the background hydraulic gradient (BHG). In our models, we test the effects of porosity, permeability, and BHG in an isotropic medium. Furthermore, we simulate the effect of permeability contrast and anisotropy induced by layering, fractures, and a fault. We quantify the lifetime of the reservoir by measuring the time to thermal breakthrough, i.e. how many years pass before the temperature of the produced fluid falls below the 100 ∘C threshold. The results of our sensitivity study attest to the positive effect of high porosity; however, high permeability and BHG can combine to outperform the former. Particular configurations of all the parameters can cause either early thermal breakthrough or extreme longevity of the reservoir. For example, the presence of high-permeability fractures, e.g. in a fault damage zone, can provide initially high yields, but it channels fluid flow and therefore dramatically restricts the exploitable reservoir volume. We demonstrate that the magnitude and orientation of the BHG, provided permeability is sufficiently high, are the prime parameters that affect the lifetime of a reservoir. Our numerical experiments show also that BHGs (low and high) can be outperformed by comparatively small variations in permeability contrast (103) and fracture-induced permeability anisotropy (101) that thus strongly affect the performance of geothermal reservoirs.
- ItemPorosity estimation of a geothermal carbonate reservoir in the German Molasse Basin based on seismic amplitude inversion(Berlin ; Heidelberg [u.a.] : SpringerOpen, 2022) Wadas, Sonja Halina; von Hartmann, HartwigThe Molasse Basin is one of the most promising areas for deep geothermal exploitation in Germany and the target horizon is the aquifer in the Upper Jurassic carbonates. Carbonate deposits can be very heterogeneous even over a small area due to diagenetic processes and varying depositional environments. The preferential targets for geothermal exploitation in carbonate deposits are fault zones, reef facies and karstified areas, since they are expected to act as hydraulically permeable zones due to high porosity and high permeability. Therefore, identifying these structures and characterizing, e.g., their internal porosity distribution are of high importance. This can be accomplished using 3D reflection seismic data. Besides structural information, 3D seismic surveys provide important reservoir properties, such as acoustic impedance, from which a porosity model can be derived. In our study area in Munich we carried out a seismic amplitude inversion to get an acoustic impedance model of the Upper Jurassic carbonate reservoir using a 3D seismic data set, a corresponding structural geological model, and logging data from six wells at the ‘Schäftlarnstraße’ geothermal site. The impedance model and porosity logs were than used to calculate a porosity model. The model shows a wide porosity range from 0 to 20% for the entire reservoir zone and the lithology along the wells reveals that dolomitic limestone has the highest porosities and calcareous dolomite has the lowest porosities. The study area is cut by a large W–E striking fault, the Munich Fault, and the footwall north of it shows higher porosities and more intense karstification than the hanging wall to the south. Considering the entire study area, an increase in porosity from east to west is observed. Furthermore, we identified a complex porosity distribution in reef buildups and pinnacle reefs. The reef cores have mostly low porosities of, e.g., < 3% and the highest porosities of up to 7 to 14% are observed at the reef caps and on the reef slopes. The reef slopes show a characteristic interfingering of the reef facies with the surrounding bedded facies, which indicates a syn-sedimentary reef development with slightly varying build up growth rates. We also assessed the reservoir quality with regard to porosity distribution and determined areas with moderate to good quality for geothermal exploitation by defining porosity evaluation levels. The porosity evaluation maps show that the carbonate rocks of Berriasian to Malm ζ1 are preferential targets for exploitation, especially in the footwall of the Munich Fault and to the west of the hanging wall, because these areas are characterized by high porosities due to intense karstification of bedded and massive facies, although the latter is mainly restricted to reef caps and reef slopes.
- ItemProbability of success studies for geothermal projects in clastic reservoirs: From subsurface data to geological risk analysis(Amsterdam [u.a.] : Elsevier Science, 2020) Schumacher, Sandra; Pierau, Roberto; Wirth, WolfgangIn the realisation of a geothermal project, an important step is the quantification of the geological risk of a well not achieving the economically necessary cut-off values with respect to temperature and flowrate/drawdown. In this paper, we present a new method for calculating this risk via a probability of success study by using all available types of hydraulic data, including porosity values derived from core samples or borehole logs. This method has been developed for geothermal projects in fluvial sandstones of the North German Basin but can be applied to any clastic, not fracture-dominated reservoir worldwide. © 2019 The Authors
- ItemNano- to millimeter scale morphology of connected and isolated porosity in the permo-triassic khuff formation of Oman(Basel : MDPI AG, 2020) Smodej, Jörg; Lemmens, Laurent; Reuning, Lars; Hiller, Thomas; Klitzsch, Norbert; Claes, Steven; Kukla, Peter A.Carbonate reservoirs form important exploration targets for the oil and gas industry in many parts of the world. This study aims to differentiate and quantify pore types and their relation to petrophysical properties in the Permo-Triassic Khuff Formation, a major carbonate reservoir in Oman. For that purpose, we have employed a number of laboratory techniques to test their applicability for the characterization of respective rock types. Consequently, a workflow has been established utilizing a combined analysis of petrographic and petrophysical methods which provide the best results for pore-system characterization. Micro-computed tomography (μCT) analysis allows a representative 3D assessment of total porosity, pore connectivity, and effective porosity of the ooid-shoal facies but it cannot resolve the full pore-size spectrum of the highly microporous mud-/wackestone facies. In order to resolve the smallest pores, combined mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR), and BIB (broad ion beam)-SEM analyses allow covering a large pore size range from millimeter to nanometer scale. Combining these techniques, three different rock types with clearly discernible pore networks can be defined. Moldic porosity in combination with intercrystalline porosity results in the highest effective porosities and permeabilities in shoal facies. In back-shoal facies, dolomitization leads to low total porosity but well-connected and heterogeneously distributed vuggy and intercrystalline pores which improves permeability. Micro- and nanopores are present in all analyzed samples but their contribution to effective porosity depends on the textural context. Our results confirm that each individual rock type requires the application of appropriate laboratory techniques. Additionally, we observe a strong correlation between the inverse formation resistivity factor and permeability suggesting that pore connectivity is the dominating factor for permeability but not pore size. In the future, this relationship should be further investigated as it could potentially be used to predict permeability from wireline resistivity measured in the flushed zone close to the borehole wall. © 2019 by the authors. Licensee MDPI, Basel, Switzerland.