Detailed Fluid Inclusion and Stable Isotope Analysis on Deep Carbonates from the North Alpine Foreland Basin to Constrain Paleofluid Evolution

Abstract

The recent interest on environmentally friendly energy resources has increased the economic interest on the Upper Jurassic carbonate rocks in the North Alpine Foreland Basin, which serves as a hydrogeothermal reservoir. An economic reservoir use by geothermal fluid extraction and injection requires a decent understanding of porosity–permeability evolution of the deep laying Upper Jurassic strata at depths greater than 2000 m. The analysis of paleofluids caught in cements of the rock mass helps to determine the postdepositional reservoir evolution and fluid migration. Therefore, the high- and low-permeability areas of the Upper Jurassic in the North Alpine Foreland Basin referred to as Molasse Basin were analyzed by means of encountered postdepositional cements to determine the reservoir evolution. The cements were sampled at different hydrocarbon and geothermal wells, as well as at outcrops in the Franconian and Swabian Alb. To determine the composition and temperature of the paleofluids, fluid inclusions and cements of the Upper Jurassic carbonate rocks were analyzed by microthermometry and stable isotope measurements. Since drill cuttings are a rather available sample material compared to drill cores, a new microthermometry measurement method was achieved for the around 1 mm drill cuttings. Salinity and formation temperature of paleofluids in fluid inclusions and isotope data are consistent with previous studies and reveal a 5-stage evolution: the main cementation phases are composed of (I) the early diagenesis in limestones (200-400 m, 40-50°C), (II) early diagenetic dolomitization, and (III) burial dolomitization (1-2 km, II: 40-90°C; III: 70-100°C; 40 g/L NaCl equiv.), and (IV) late burial calcification (IIIa: 110-140°C, IIIb: 140-200°C) linked to tectonic features in the Molasse Basin. In the outcrop samples, a subsequent (V) cementation phase was determined controlled by karstification. In the southwest, an increase in salinity of the fluid inclusions in vein calcites, above the salinity of the Jurassic seawater, highlights the influence of basin fluids (diagenetic, evaporitic). In the other eastern wells, vein calcites have precipitated from a low saline fluid of around 10-20 g/L NaCl equiv. The low salinity and the isotope values support the theory of a continuous influence of descending meteoric fluids. Consequently, the Upper Jurassic seawater has been diluted by a meteoric fluid to a low saline fluid (<1 g/L), especially in areas with high permeability. Here, we show how a better understanding of cementation trajectory at depth can help to generate a better understanding of geothermal usability in deep carbonate reservoirs.

Geothermal play typing in Germany, case study Molasse Basin: a modern concept to categorise geothermal resources related to crustal permeability

“…Geothermal exploration results show that faults, depositional facies, karst, diagenesis and dolomitisation control porosity, permeability and hence reservoir productivity (Dussel et al, 2016;Mraz et al, 2019), which has also been shown for carbonates in the Alberta Basin (Drivet & Mountjoy, 1997;Mountjoy et al, 2001).…”

“…Ingebritsen & Manning, 1999;Ehrenberg & Nadeau, 2005;Stober & Bucher, 2007, 2015Stober, 2011), and most likely diagenetic processes such as pressure solution and precipitation might impair porosity and permeability with depth. Mraz et al (2019) show in an extensive study of the Upper Jurassic in the Molasse Basin that depth-related processes, notably compaction and diagenesis, have a significant effect on porosity and reservoir productivity. Certain facies types such as reef or reef detritus become less relevant for reservoir production while compaction and diagenesis come to control permeability variability with depth (Mraz et al 2019).…”

“…Lüschen et al, 2014;Hartmann et al, 2017), well log data, hydraulic test data (e.g. Birner et al, 2012;Stober et al, 2014;Dussel et al, 2016), drill core and cutting analysis (Mraz et al, 2018(Mraz et al, , 2019 and hydrochemistry studies (e.g. Birner et al, 2011;Stober et al, 2013aStober et al, , 2014Stober, 2014).…”

“…Similar to the definitions for hydrocarbon exploration plays, we define these geological controls on reservoir productivity as play segments (Table 1), while the 'Malm' formation as a stratigraphic unit is a play level (Table 1). Besides the primary geologic controls such as deposition or faults, also compaction and diagenesis, and hence episodes of basin subsidence and burial, have a strong effect on reservoir productivity (Drivet & Mountjoy, 1997;Mountjoy et al, 2001;Mraz et al, 2019). This is especially relevant in foreland basins, where one play level is located at increasing depth towards the orogenic belt (Sinclair & Allen, 1992;Mraz et al, 2018).…”

“…The ratio of porosity to permeability in conduction-dominated geothermal plays is variable, reflecting different grades of compaction, diagenesis and brittle failure proceeding in different types of lithology (Moeck, 2014). Carbonate rock exhibits characteristically vast ranges of permeability and porosity caused by the manifold petrophysical properties and determined by fabric, mud content, facies, fossils and mineralogy (Mraz et al 2019). In sum, carbonate reservoirs are of heterogeneous and anisotropic nature due to primary factors from biochemical sedimentation in different depositional environments and due to secondary processes such as pressure solution, precipitation, fracture formation and dissolution (karst).…”