Geothermal resources of the North German Basin: exploration strategy, development examples and remaining opportunities in Mesozoic hydrothermal reservoirs

Matthias Franz, Gregor Barth, Jens Zimmermann, Ingmar Budach, Kerstin Nowak and Markus Wolfgramm
Geological Society, London, Special Publications, 469, 193-222, 13 April 2018, https://doi.org/10.1144/SP469.11

Abstract

The North German Basin yields enormous geothermal resources of more than 13 000 EJ (exajoule: 1 EJ = 1 × 1018 J) heat in place bound to Paleozoic petrothermal and Mesozoic hydrothermal reservoirs. So far, these resources are only exploited at a few localities. Thus, geothermal energy is considered an underutilized energy resource. Despite long-term experience in exploiting Rhaetian hydrothermal reservoirs, the exploration risk remains high, which is mainly related to high expectations on reservoir thickness and quality. Previous exploration campaigns have identified potential hydrothermal reservoirs in six Mesozoic reservoir complexes. But, as high-resolution subsurface maps are not available, the reliable prediction and targeting of reservoirs remains an unsolved problem.

As such, an exploration strategy integrating methods of sedimentology, palaeontology, petrography and reservoir characterization was applied to a large database of cores and wireline logs. This contribution details the key results of the exploration of Upper Keuper and Middle Jurassic reservoir complexes, including high-resolution subsurface facies, sandstone thickness and reservoir quality maps. Sets of these maps enable the reliable prediction and targeting of individual hydrothermal reservoirs, and, thus, make a significant contribution to a lowered exploration risk.

Considering its thick basin fill and geothermal gradients of 32–90 K per km of depth, the North German Basin yields enormous geothermal resources (Fig. 1) (Wolfgramm et al. 2014). Following an intense phase of hydrocarbon exploration, the exploration of geothermal resources started in the early 1970s. Based on these campaigns, significant resources were identified in (1) Paleozoic sedimentary and volcanic rocks, and (2) Mesozoic sedimentary rocks but, mainly for economic reasons, the exploration was focused on Mesozoic hydrothermal reservoirs (see Feldrappe et al. 2008). The exploitation of geothermal energy started with operating Rhaetian reservoirs at the sites of Waren (in 1986) and Neustadt-Glewe (in 1994). Based on this experience, an economically successful operation of hydrothermal reservoirs requires the following key parameters: >65°C reservoir temperature, >20 m reservoir thickness and >500 mD permeability (Rockel et al. 1997).

Fig. 1.
Fig. 1.

Overview map of the main German basins: the North German Basin, Molasse Basin and the Upper Rhine Graben. These basins may yield considerable geothermal resources. The isopachs refer to the total sedimentary thickness of the Upper Rotliegend–base Quaternary succession; compiled after Ziegler (1982, 1990). The black squares are geothermal facilities or localities referred to as in the text: 1, Waren; 2, Prenzlau; 3, Neustadt-Glewe; 4, Neuruppin; 5, Velten; 6, Neubrandenburg; 7, Berlin; 8, Bad Wilsnack; 9, Belzig; 10, Binz; 11, Templin; 12, Burg; 13, Bad Saarow (for details see Table 2); 14, Parchim 1; 15, Hamburg-Allermöhe.

Soon after, the development of hydrothermal reservoirs at other localities in North Germany failed. For example, at the planned site of Belzig, the thickness of an identified Rhaetian reservoir was too limited; while at the planned site of Hamburg-Allermöhe, the limited quality (permeability) inhibited the development of another Rhaetian reservoir. These, and other failures, demonstrate the high exploration risk of Mesozoic hydrothermal reservoirs, which is mainly related to the lateral variability of reservoir thickness and quality.

Jung et al. (2002) estimated the total geothermal resources of Germany for electricity production to be about 2100 EJ (exajoule: 1 EJ = 1 × 1018 J). Considering the total geothermal energy production (heat, electricity) of 8962 TJ (terajoule: 1 TJ = 1 × 1012 J) in 2015, geothermal energy is an underutilized energy resource of Germany (AGEB 2015). About 96% of the total geothermal resources are bound to so-called petrothermal reservoirs (2016 EJ) which require stimulation techniques to be developed (Enhanced or Engineered Geothermal Systems: EGS), 4% are bound to faults (84 EJ) and only 1% (21 EJ) is bound to hydrothermal reservoirs which can be exploited by, for example, conventional Doublet systems (Jung et al. 2002). But it is important to note that hydrothermal operations in North Germany have generally been more successful than petrothermal reservoir projects.

Numerous previous studies have evaluated Mesozoic hydrothermal reservoirs of the North German Basin (e.g. Katzung 1984; Diener et al. 1988–1992; Wormbs et al. 1988; Katzung et al. 1992; Scholle 1992; Beutler et al. 1994; Schulz & Röhling 2000; Kabus et al. 2003; Feldrappe et al. 2008). These studies employed existing databases of well data in order to evaluate either individual localities or reservoir complexes. However, reliable reservoir prediction is hampered by a lack of high-resolution subsurface facies mapping (see Feldrappe et al. 2008, fig. 5c). Following an overview of geothermal resources, including development examples in Mesozoic hydrothermal reservoirs, this contribution details the key results of the exploration of Upper Triassic Rhaetian and Middle Jurassic reservoir complexes. The employed exploration strategy combines classical methods of sedimentology, palaeontology, petrography and reservoir characterization, and was applied to a large database of cored and logged wells. The resulting high-resolution GIS-based subsurface facies, sandstone thickness and reservoir quality maps make significant contributions to improving reservoir prediction, and, thus, lower the exploration risk for Mesozoic hydrothermal reservoirs. The set of maps is currently implemented into the Geothermal Information System (GeotIS: Agemar et al. 2014).

Geological evolution

The Central European Basin (CEB) is a large epicontinental sag basin (e.g. Bally & Snelson 1980; Bachmann & Grosse 1989; Ziegler 1990). In terms of structure, the CEB is composed of several subbasins, with the North German Basin as the largest one (Gast et al. 1998). Following the Variscan Orogeny, the CEB initiated in the Late Carboniferous and has been active up to recent times. During this long time span, a thick volcano-sedimentary basin fill accumulated, with the greatest thickness in the North German Basin (NGB). For example, the sedimentary succession of the Upper Rotliegend I–Tertiary exceeds a thickness of 8000 m in NW Germany (Bachmann & Grosse 1989).

The complex basin history comprises phases of high subsidence alternating with phases of basin reorganization and tectonic pulses (Nöldeke & Schwab 1977; Schwab 1985; Kley et al. 2008; Scheck-Wenderoth et al. 2008; Bachmann et al. 2010). Accordingly, the Upper Carboniferous–Upper Cretaceous basin fill is herein subdivided into three stages: (1) basin initiation; (2) basin fill; and (3) basin differentiation/inversion (Fig. 2). This subdivision partly resembles the subdivision of Nöldeke & Schwab (1977) and Schwab (1985).

Fig. 2.
Fig. 2.

Basin fill of the NGB. The example of well Parchim1/68 (for the location see Fig. 1) shows Mesozoic and Paleozoic reservoirs separated by the Zechstein. High-permeable Mesozoic reservoirs are operated using conventional hydrothermal methods, whereas low-permeable to tight Paleozoic reservoirs are operated using unconventional petrothermal methods considered under the term Enhanced Geothermal Systems (EGS). SG, Sub-Group; UR, Unterrotliegend; OR, Oberrotliegend; the temperatures are from Hoth (1997) the subsidence curve is modified from Hoth (1997), Friberg (2001) and Wolfgramm (2005).

Basin initiation in the Late Carboniferous started with the formation of smaller intra-Variscan basins and a larger foreland basin to the north of the Variscan Mountains. The initiation stage was characterized by strong volcanism resulting in accumulation of a 3000 m thick volcano-sedimentary succession (Lower Rotliegend) between the Altmark area and the island of Rügen (Marx et al. 1995; Plein 1995; Benek et al. 1996; Breitkreuz & Kennedy 1999; Breitkreuz et al. 2008) (Fig. 2). The oldest post-volcanic sediments of the Upper Rotliegend I Müritz Subgroup (Artinskian–Kungurian) are restricted to fault-bounded graben-like structures, where up to 600 m thick successions of conglomerates, fluvial sandstones and playa deposits were accumulated (Plein 1993; Hoffmann et al. 1997). In the Middle Permian (Guadalupian), continued crustal stretching and intrusions resulted in thermal updoming and partial erosion (Saalian Unconformity: Stille 1924; Ziegler 1990; Bachmann & Hoffmann 1995) of the stratigraphic succession accumulated during the initiation stage of the basin evolution.

Above this unconformity, the onset of the Upper Rotliegend II (Capitanium–Wuchiapingium) marks the change to the second phase of the basin evolution, the basin fill stage. This approximately 100 myr long stage of basin evolution was characterized by high subsidence initially (265–240 Ma) and lower subsidence rates subsequently (240–140 Ma) (Fig. 2). Basin expansion and reorganization formed the Northern and Southern Permian Basins, separated by the Mid North Sea and Ringköbing-Fyn High (Seemann 1982). Following separate development during the depositional periods of the Rotliegend and Zechstein groups, both basins merged into the Central European Basin in the Early Triassic. The succession accumulated during the basin fill stage spans from the Upper Rotliegend II to the Upper Jurassic, and comprises both continental and marine strata. The deposits of the early part of this stage, including the Upper Rotliegend II (Permian)–Buntsandstein (Germanic Triassic) succession, are considerable thicker compared to the deposits of the later part of this stage, including the Muschelkalk (Germanic Triassic)–Upper Jurassic succession (Fig. 2).

During the third basin evolution stage, the basin differentiation and inversion stage, Atlantic rifting and the collision of the African and European plates triggered the inversion of parts of the basin (e.g. Ziegler 1990; Kley & Voigt 2008). Accordingly, salt tectonics attained a maximum intensity during this stage (Jaritz 1974, 1987). This resulted in repeated uplift and erosion of both, the pre- and synkinematic basin fill. As a consequence, stratigraphic units of the differentiation and inversion stage are not always preserved in the North German Basin. In particular in NE Germany, Upper Jurassic and Lower Cretaceous strata are only present in the form of isolated erosional remnants.

Geothermal resources of the North German Basin

In the North German Basin, temperatures increase with increasing depth resulting from underlying heat flow values of 50–90 mW m−2 (average 70 mW m−2: Lotz 2004; Wolfgramm et al. 2014). Due to variations of basin fill thickness and structure, geothermal gradients are subject to regional variations. Accordingly, reported values of average geothermal gradients vary from 33 K per km depth (Katzung 2004) to 45–50 K per km depth (Hoth 1997). Locally, for example, at the top of salt structures, elevated geothermal gradients of up to 90 K per km depth were observed (Ziegenhardt et al. 1980; Hoth 1997; Katzung 2004).

The geothermal resources of the North German Basin are subject to several subdivisions. In terms of depth, the geothermal resources are subdivided into shallow resources from 0 to 500 m depth, and deep resources below 500 m depth. The shallow geothermal resources, mainly hydrothermal reservoirs, are increasingly used for the heating/cooling of buildings. The deep geothermal reservoirs may be further subdivided into Mesozoic and Paleozoic geothermal resources, with the Zechstein as a natural barrier in-between (Fig. 2). The Mesozoic geothermal resources are mainly bound to hydrothermal resources, whereas the Paleozoic geothermal reservoirs are mainly bound to petrothermal reservoirs. In terms of temperature, hydrothermal reservoirs may be subdivided into hot (>100°C), warm (60–100°C) and thermal (>20°C) reservoirs, as suggested by Agemar et al. (2014).

Paleozoic geothermal resources

Paleozoic geothermal resources are mainly bound to Rotliegend Group sediments and volcanic rocks. Jung et al. (2002) estimated a geothermal potential of 13 000 EJ heat in place for Rotliegend-age volcanic rocks, and 340 EJ heat in place for Rotliegend siliciclastic sediments. At least parts of these enormous potentials are available at almost any location in North Germany since the Upper Rotliegend II is regionally distributed. Resulting from a deep burial depth of 2500 m to more than 5500 m (base Zechstein Group) and a complex diagenetic history, potential reservoirs of the basin-initiation stage and early basin fill stage are low permeable to tight, and therefore need EGS techniques to be developed. However, so far, only preliminary experiences have been made with EGS in the North German Basin.

Hydrothermal resources in Mesozoic reservoir complexes

Mesozoic hydrothermal resources are bound to sandstone reservoirs, which are grouped into complexes of the: (1) Middle Buntsandstein; (2) Lower--Middle Keuper; (3) Upper Keuper; (4) Lower Jurassic; (5) Middle Jurassic; and (6) Lower Cretaceous (Fig. 3). With increasing depth, Mesozoic reservoir complexes are characterized by decreasing pore volumes and increasing salinity of the pore fluids. For burial depths up to 1000 m, the decrease in pore volumes is mainly related to increasing sediment compaction. At depths over 1000 m, diagenetic cement precipitation results in further reduction of pore volumes. As an estimate, a burial depth of 1000 m results in the lowering of pore volumes by about 20% (Fig. 4a; Table 1). The salinity of pore fluids is mainly related to: (1) primary fluids salinity (e.g. freshwater or seawater); (2) secondary processes, such as diagenetic mineral alteration; and/or (3) mixing with other saline fluids. On average, the salinity of pore fluids increases by about 10 g l−1 per 100 m depth (Fig. 5) (Wolfgramm et al. 2014). Within reservoirs that are influenced by highly saline brines related to either in situ salt layers (e.g. Lower Triassic Röt Formation) or to Zechstein salt structures, the pore fluid salinity increases by up to 20–25 g l−1 per 100 m depth.

Fig. 3.
Fig. 3.

Mesozoic reservoir complexes with examples of the Rhaetian Deltaic System (RDS) and Toarcian–Bajocian Deltaic System (TBDS). RDS with examples of Rhaetian reservoirs A–F (but D is not shown) and palynomorph zonation: CE Zone, Cerebropollenites–Enzonalasporites Zone; RL Zone, Rhaetipollis–Limbosporites Zone; RP Zone, Ricciisporites–Polypodiisporites Zone; DC Zone, Deltoidospora–Concavisporites Zone; PT Zone, Pinuspollenites–Trachysporites Zone (Lund 1977; Barth et al. 2018a) – for the locations see Figure 11. TBDS with examples of reservoirs: A, Lower Toarcian; B, Upper Toarcian; C, Upper Aalenian 1 (alo 1); D, Upper Aalenian 2 (alo 2); E, Upper Bajocian; Ha 1, Hagenow 1; Zlh 1, Zechliner Hütte 1 – for the locations see Figure 14. Hagenow 1 and Kettelsdorf 1 are modified from Brand & Mönnig (2009).

Fig. 4.
Fig. 4.

(a) Porosity v. depth and (b) mineralogical maturity v. provenance. Increasing depth results in decreasing porosities of Mesozoic reservoirs. Note the average porosities of 28 and 18% at depths of about 600 and 2500 m, respectively. Porosities refer to gas porosities of core samples. Mineralogical maturity and provenance indexes (Pettijohn 1957) of Palaeozoic and Mesozoic reservoirs obtained from point counting of thin sections (modified after Franz et al. 2015).

Fig. 5.
Fig. 5.

Salinity v. depth. Increasing depth results in increasing salinities of fluids; c. 550 fluid analyses of Mesozoic and Paleozoic reservoirs (modified after Wolfgramm et al. 2014).

View this table:
Table 1.

Decreasing porosity with increasing depth, exemplified by initial porosities of 10–40%

Middle Buntsandstein reservoir complex

In the North German Basin, the base Triassic is located at a depth between 1000 and 5500 m (Bachmann et al. 2010). In contrast to south and central Germany, where the Buntsandstein is predominantly composed of sandstones, the basinal facies of the North German Basin is mainly composed of shales and siltstones (Röhling 1991, 2013). Only strata from the Middle Buntsandstein Subgroup yield potential sandstone reservoirs, which are located at the southern and northern margins of the North German Basin. Fed by Variscan sources to the south, sandstone reservoirs of the Volpriehausen to Solling formations form a 50–100 km wide sandy depositional belt stretching from the Weser-Ems area, via Hannover, up to northern Brandenburg (southern Buntsandstein). A corresponding sandy depositional belt stretches from the Darß via Stralsund up to the island of Usedom, which was fed by Scandinavian sources from the north (northern Buntsandstein). Within these sandy depositional belts, individual reservoirs are locally more than 60 m thick, such as: (1) the Doethlingen Sandstone between the towns of Bremen and Celle (Schulz & Röhling 2000); or (2) the Detfurth Sandstone in the vicinity of the town of Karlshagen (Wolfgramm et al. 2008).

The geothermal potential of the Middle Buntsandstein reservoir complex has been subject to previous investigation. Beutler et al. (1994) and Schulz & Röhling (2000) evaluated the reservoirs of the southern Buntsandstein, whereas Katzung (1984) and Wormbs et al. (1988) evaluated reservoirs of the northern Buntsandstein. Reservoirs of the Middle Buntsandstein are composed of fine- to medium-grained sandstones of low to intermediate maturities (Fig. 4b). Detrital composition of quartzes, feldspars and lithics result in lithic arkoses, feldspatic litharenites and lithic subarkoses compositions. In the area between the Darß and Usedom, reservoirs of the Detfurth to Solling formations are characterized by an average thickness of more than 20 m, an average porosity of more than 20% and an average permeability of more than 500 mD (Fig. 6a) (Wolfgramm et al. 2008). Locally, diagenetic processes contributed to a significant lowering of the primary porosity. The development of Middle Buntsandstein reservoirs is hampered by the limited prediction of reservoir thickness and quality of individual localities. The northern Buntsandstein is currently under evaluation by the ‘GeoPoNDD’ project (http://www.sandsteinfazies.de), which is being carried out by the authors with the goal of producing detailed subsurface maps in the near future.

Fig. 6.
Fig. 6.

Porosity (phi) distribution of Mesozoic reservoir complexes. Hatched bars refer to the mean value (modified after Wolfgramm et al. 2014).

Lower–Middle Keuper reservoir complex

Fluvio-deltaic sandstones of the Ladinian Lower Keuper (Erfurt Formation) and the mid-Carnian Schilfsandstein (Stuttgart Formation) are intercalated within the mainly shaly succession of the Keuper (Fig. 3). The Schilfsandstein and its geothermal potential were recently evaluated (Franz et al. 2014, 2015). Sandy channel fills and levee–crevasse splay complexes of the Lower and Upper Schilfsandstein were identified as main targets for further geothermal exploration. For the Lower Schilfsandstein, these reservoirs are 8–31 m thick (average 22.6 m), and are characterized by porosities of 0.9–37% (average 27.3%) and permeabilities of 0.3–3058 mD (average 1060 mD). For the Upper Schilfsandstein, these reservoirs are 8–35 m thick (average 17.7 m), and are characterized by porosities of 23–32% (average 29.2%) and permeabilities of 488–2972 mD (average 1799 mD: Franz et al. 2015). The quality of potential reservoirs is limited by the generally low maturity of the sandstones being lithic arkoses and feldspatic litharenites, the high content of shaly matrix within pores, and substantial diagenetic cementation (Fig. 4b) (Förster et al. 2010). A further limitation is given by rapid lateral facies shifts within the Stuttgart Formation. Due to the limited reservoir quality and the uncertainties in reservoir prediction, the potential of the Stuttgart Formation was considered to be rather low (Franz et al. 2015).

Upper Keuper reservoir complex

The Upper Keuper or Rhaetian reservoir complex comprises distributive fluvial and deltaic depositional systems (Fig. 3) (Franz & Wolfgramm 2008; Bachmann et al. 2010; Barth et al. 2014; Gaupp 1991). Both systems are from Scandinavian provenance to the north, and stretch across the eastern part of the North German Basin. In general, Rhaetian successions are sand-dominated in NE Germany, successively becoming more shaly towards NW Germany. To the west of Hamburg, the Rhaetian is dominantly composed of shales. The fine- to medium-grained clean sandstones of both depositional systems are characterized by high maturity, high porosities and permeabilities, and form excellent reservoirs (Figs 4b & 6c). Therefore, these have been the main targets for previous geothermal exploration (e.g. Scholle 1992; Beutler et al. 1994; Feldrappe et al. 2008). The Rhaetian distributive fluvial system forms the Rhaetian reservoirs A and B (previously the Postera Sandstone). At the town of Neubrandenburg, the municipal supplier operates these reservoirs for seasonal heat storage (Table 2) (Kabus et al. 2009; Obst & Wolfgramm 2010). The Rhaetian deltaic system forms the Rhaetian reservoirs C–F (previously the Contorta Sandstone). In the towns of Neustadt-Glewe and Waren, municipal suppliers operate these reservoirs for district heating (Table 2). So far, uncertainties in the prediction of reservoir thickness and quality have contributed to significant exploration risks hampering the development of Rhaetian reservoirs at other localities. More recently, Franz et al. (2015) contributed to a lowering of the exploration risk underlining the high potential of Rhaetian hydrothermal reservoirs. Key results of this Rhaetian deltaic system reservoir are detailed in a following subsection.

View this table:
Table 2.

Geothermal heating stations, plants and facilities in northern Germany operating hydrothermal reservoirs with selected key parameters

Lower Jurassic reservoir complex

The base Jurassic is located at depths of between 800 and 4000 m (Lott et al. 2010). In terms of depositional environments, the Lower Jurassic resembles much of the Rhaetian deltaic system. Due to a general transgressive trend throughout the Liassic, the coastal and deltaic environments were successively shifted toward the basin margins in the NE (Barth et al. 2018a, b).

Accordingly, the western limit of potential geothermal reservoirs shifted from the area around the town of Schwerin in the Hettangian to the area around the town of Neubrandenburg in the Pliensbachian. Performance wise the Lower Jurassic reservoirs are comparable to Rhaetian reservoirs because of their high reservoir qualities (Figs 4b & 6d) (Rauppach et al. 2008; Wolfgramm et al. 2008). The Lower Jurassic reservoir complex was previously evaluated by Katzung (1984), Wormbs et al. (1988) and Scholle (1992), and is currently under evaluation by the authors in the GeoPoNDD project (http://www.sandsteinfazies.de). In the past, uncertainties in the prediction of reservoir thickness and quality have hampered the development of Lower Jurassic reservoirs.

Middle Jurassic reservoir complex

Following the second-order maximum flooding in the Early Toarcian Tenuicostatum Ammonite Zone, the Toarcian–Bajocian Deltaic System successively prograded from Pomerania (late Early Toarcian) up to the Weser-Ems area (Bajocian). As individual deltas of the Toarcian, Aalenian and Bajocian are genetically related, forming the Toarcian–Bajocian deltaic system, the reservoirs of Toarcian deltas are included in the Middle Jurassic reservoir complex (Zimmermann et al. 2018). The Middle Jurassic was largely affected by post-sedimentary erosion due to a phase of basin inversion (Ziegler 1990). In particular in the western part of the North German Basin, only the Middle Jurassic strata present in rim synclines along salt structures were protected from erosion (Jaritz 1974). Recent evaluations of the Toarcian–Bajocian deltaic system have contributed to improved predictions in the reservoir thickness and quality (Franz et al. 2015; Zimmermann 2015); key results are detailed in a following subsection.

Lower Cretaceous reservoir complex

The base of the Cretaceous is located at depths of between 300 m in NE Germany to 4000 m in NW Germany (Vejbæk et al. 2010). The Lower Cretaceous, in particular the Berriasian (Wealden) and Valanginian, was affected by intense basin reorganization during inversion (Fig. 2) (Ziegler 1990). This resulted in a patchy distribution of Lower Cretaceous strata within large and small sub basins (Kemper 1979; Voigt et al. 2008). Synsedimentary tectonics and salt diapirism resulted in large variations in stratigraphic thickness. Whereas in larger parts of the North German Basin the thickness of the Lower Cretaceous does not exceed 200 m, thicknesses locally increase to more than 1800 m in southern Lower Saxony (Vejbæk et al. 2010).

In the North German Basin, the number and quality of potential Lower Cretaceous reservoirs varies strongly from west to east. At the SW margins of the Lower Saxony Sub basin, fluvio-deltaic reservoirs are present in the Berriasian (Bückeberg Formation), and coastal-marine reservoirs occur throughout the Valanginian–Albian (Mutterlose & Bornemann 2000). Towards the north, coastal siliciclastics interfinger with shales and marls but have no reservoir potential. Towards the east and NE, potential reservoirs are limited to the Berriasian–Hauterivian, such as the Wealden Sandstone in Mecklenburg or the Dichotomiten Sandstone in Lower Saxony (Valanginian).

Lower Cretaceous sandstone reservoirs are locally of high quality: in particular, the coastal-marine sandstones of the Valanginian–Albian (Beutler et al. 1994; Schulz & Röhling 2000). For example, Kuder et al. (2014) reported an average permeability of 1837 mD for the Bentheim Sandstone (Valanginian) in the western Lower Saxony Sub basin. In contrast, Rauppach et al. (2008) reported an average permeability of only 226 mD for reservoirs of Wealden-type facies in the eastern part of the North German Basin (Fig. 6f). So far, the uncertainties in distribution of Lower Cretaceous reservoirs and their quality have resulted in significant exploration risks. Lower Cretaceous reservoirs of the eastern part of the North German Basin are currently under evaluation in the GeoPoNDD project (http://www.sandsteinfazies.de).

Development examples in the North German Basin

The exploitation of geothermal energy in northern Germany started in 1986 with the exploitation of a Rhaetian hydrothermal reservoir at 1540 m depth below the city of Waren. The municipal supplier of Waren installed a geothermal doublet and provided thermal energy to customers via district heating (Fig. 7). Since then, many different geothermal facilities have been developed (Table 2). In general, a distinction is made between closed and open systems. The deep borehole heat exchanger operated in the town of Prenzlau is an example of a closed system. Open systems are the ‘conventional’ geothermal doublets operated in the towns of Waren, Neustadt-Glewe, Neubrandenburg (from 1989 to 1998) and Neuruppin, the geothermal heat storage site operated in Neubrandenburg (since 2003) and Berlin (parliamentary buildings), as well as balneological applications.

Fig. 7.
Fig. 7.

Conventional operation of hydrothermal reservoirs in the North German Basin using a doublet system (modfied after Rockel et al. 1997). The minimum productivity index of 50 m3 (h × MPa)−1 requires high reservoir qualities (for an explanation see the text).

Geothermal doublets consist of an injection well and a production well (Fig. 7). Hot or warm saline waters are produced from the hydrothermal reservoir by a submersible pump, filtered, passed through a heat exchanger and reinjected into the reservoir. In order to avoid corrosion and scaling, the thermal loops are pressurized with nitrogen. At Waren, 60 m3 h−1 of warm reservoir water with a temperature of c. 61°C is produced from the 1540 m deep Rhaetian reservoir (Fig. 8). The reservoir water is passed through a heat exchanger where the thermal energy is transferred to the secondary or supply cycle. The annual heat production of 2.4 GWh a−1 is used to heat 1700 residential units. The reinjection temperature of the thermal cycle is about 40°C. The heating station at Neustadt-Glewe operates with a production rate of 100 m3 h−1 of reservoir water at a 98°C temperature produced from the Rhaetian reservoir F at 2200 m depth (Contorta sandstone). The Neustadt-Glewe heating station had an annual heat production of 18.33 GWh a−1 in 2015 (Table 2).

Fig. 8.
Fig. 8.

Example of Rhaetian reservoir. (a) Litholog of cored well Waren 1/81 showing the 23.7 m thick levee/crevasse splay reservoir type operated at the Waren site (Table 2). (b) GR and SP logs (left), and calculated and measured porosity data of well Waren 5/90 (middle and right). The calibration of the different porosity (phi) calculation models with measured core porosities suggests that the Phi [LL] and Phi [GG] are probably the most realistic calculation models.

The heat storage concept, currently in operation at Neubrandenburg or at the Reichstag in Berlin, is, however, slightly different. For example, the heat storage of the Reichstag is developed via two wells at a distance of about 300 m (warm side, RT Gt1; cold side, RT Gt 2). Both wells are used for production and injection based on the operational mode. During the summer, excess heat generated by the Reichstag heating power station is stored in a Lower Jurassic reservoir (Hettangian). By means of this, warm water at a temperature of 70°C is injected, stored and produced during the winter (Seibt & Kabus 1997). Since the beginning of the heat storage process, the warm well RT Gt 1 has heated up from around 20°C to about 65°C. The storage is then regenerated again during the summer of the next year by producing water from the cold well RT Gt 2, heating it up and reinjecting it into the warm well RT Gt1. Since 1996, a total of more than 1.5 × 106 m3 of fluid has been stored (approximately 870 000 m3 for regeneration and 550 000 m3 for heating).

The geothermal heating station at Neubrandenburg was reconstructed from a conventional station running a doublet system to a heat storage facility. The excess heat of the power station is stored during the summer and used for heating in the winter. For each storage cycle, approximately 3.0 MW are injected and 2.5–3.0 MW are recovered.

Exploration strategy for Mesozoic reservoir complexes

Mesozoic sandstone reservoirs are preferred for conventional operation: in particular, those of the Jurassic and the Rhaetian (Fig. 3). The following parameters should be fulfilled in order to use these sandstones as geothermal reservoirs. For the long-term operation of a geothermal heating station using a doublet system, temperatures of >65°C (direct heat generation) and circulation rates of 50–100 m3 h−1 are required (Fig. 7). By using heat pumps, operation at even lower temperatures is possible: however, much higher circulation rates are needed for compensation. Warm reservoir water with a temperature of >65°C is usually found in reservoirs at a minimum depth of 1300 m. In order to achieve the required circulation rates, with a reasonable drawdown of the water level, a productivity index of at least 50 m3 (h × MPa)−1 is necessary. According to the Darcy–Dupuit well equation, the productivity index is primarily dependent on the thickness and permeability of the sandstone (Wolfgramm et al. 2014). Therefore, permeability has to be higher than 500 mD and the effective thickness of the aquifer should exceed 20 m, corresponding to an effective permeability thickness of 10 Dm. A lower reservoir thickness has to be compensated by higher permeability, and vice versa (Fig. 7).

So far, the evaluation of hydrothermal reservoirs has been focused on the depth of reservoirs and thus their temperatures (e.g. Katzung 1984; Wormbs et al. 1988; Beutler et al. 1994; Feldrappe et al. 2008). The depth of reservoirs and their temperature were collected for the Mesozoic reservoir complexes and are available in the form of classical maps, and online at http://www.geotis.de (Agemar et al. 2014). In addition, numerous contributions focused on the quality of reservoir complexes: for example, the hydraulic parameters (e.g. Beutler et al. 1994; Rauppach et al. 2008; Wolfgramm et al. 2008; Kuder et al. 2014). Apart from these rather generalized studies on reservoir complexes, detailed studies on individual reservoirs are missing. This refers, in particular, to high-resolution subsurface facies and sandstone thickness maps. As such maps provide the basis for improved reservoir predictions and reduction of the exploration risk, the exploration strategy designed for Mesozoic hydrothermal reservoirs has a strong focus on the reconstruction of depositional environments. The approach explained below was applied to a large database of cored and logged wells in order to construct large-scale subsurface maps. In the years 2011–15, this approach was employed to investigate the Keuper and Middle Jurassic reservoir complexes (Franz et al. 2015). It is currently applied to the Middle Buntsandstein, Lower Jurassic and Lower Cretaceous reservoir complexes

First, cored wells and outcrops are subject to detailed litho- and biofacies analyses. Based on grain size and physical bedding structures, primary and secondary lithofacies types are defined, and together with biofacies analyses, macro- and micropalaeontology, palynology and ichnology, grouped into facies associations. These facies associations are employed to reconstruct the depositional environments of reservoir complexes. Palaeontological data are employed for biostratigraphic dating of sections: in particular, dating of individual reservoirs (Fig. 9). Following this, biostratigraphically dated sections are used to reconstruct stratal pattern architectures along basin axis–basin margin transects, and to define and date genetic surfaces, such as maximum flooding and regression surfaces. Biostratigraphy supplemented by sequence stratigraphy is then employed to define time lines for construction of subsurface maps: for example, the maximum regression surface of a delta progradation. In order to evaluate the quality of dated reservoirs, their petrography, diagenesis and hydraulic parameters are investigated by means of microscopic methods, geochemistry and laboratory measurements. These results are then added to a database.

Fig. 9.
Fig. 9.

Simplified exploration workflow applied to Mesozoic hydrothermal reservoirs of the North German Basin, partly modified from Zimmermann et al. (2015).

To allow the construction of subsurface maps from investigated cored wells and outcrops, the motifs of wireline logs are used to abstract from core facies to electrofacies. This knowledge is then applied to a database of several hundred logged wells. The analyses of net-sandstone thickness and facies for each time line resulted in a set of GIS-based subsurface sandstone thickness and facies maps (see Franz et al. 2015; Zimmermann et al. 2018).

For the herein detailed Rhaetian and Toarcian–Bajocian deltaic systems, channel belts of distributaries and associated levee/crevasse splays, as well as distributary/mouth bar complexes, were identified as key targets for geothermal exploration. In order to control the mapped courses of channel belts and to characterize their palaeohydraulics, the width of distributary channel belts (wdcb) was calculated using empirical equations (see later) (Franz et al. 2015; Zimmermann et al. 2018).

The integration of reservoir quality and subsurface maps resulted in the identification of which reservoir thickness and quality most probably exceeds the required 20 m and 500 mD, respectively. These maps are herein referred to as reservoir quality maps. However, it is important to note that these maps do not illustrate a possibility of commercial success.

So far, the identification of an individual hydrothermal reservoir body, such as a channel belt, could not be demonstrated from conventional 2D seismic data (Fig. 10). In the future, the acquisition of 3D seismic data should contribute to an improved reservoir exploration if reservoir geobodies can be identified and imaged.

Fig. 10.
Fig. 10.

Interpreted 2D seismic exploration profile. Seismic line HH1001 (Hamburg–Wilhelmsburg), modified from Wolfgramm et al. (2010); for the location see Figure 1. m bsl, metres below sea level.

Exploration example 1: the Rhaetian deltaic system

A late Triassic transgression resulted in the brackish/marine Rhaetian Sea, a large inland sea covering the western half of the Central European Basin (e.g. Fischer et al. 2012; Barth et al. 2018a). This inland sea received siliciclastic detritus from surrounding source areas. In particular, Scandinavian source areas supplied large volumes of sediment via southern Sweden to the North German Basin, feeding a large fluvial-dominated deltaic system (Franz & Wolfgramm 2008). This deltaic system, herein referred to as the Rhaetian deltaic system, stretched from Schonen southwards up to North Brandenburg, and westwards up to the Weser-Ems area (Fig. 11).

Fig. 11.
Fig. 11.

Subsurface sandstone thickness map of the Rhaetian deltaic system. The high constructive fluvial-dominated deltaic system is composed of four subsequently formed deltaic complexes. The reservoir thickness refers to the total net-thickness of sandstone reservoirs assigned to the interval of the RL to DC Zones; post-sedimentary erosion not shown (see Fig. 12b); cored wells: 1, Neustadt-Glewe 1 and 2; 2, KSS 5; 3, Waren 1–Waren 5; 4, Neubrandenburg 1–Neubrandenburg 6; 5, Gartz 1; RL, Rhaetipollis-Limbosporites Zone; RP, Ricciisporites-Polypodiisporites Zone; DC, Deltoidospora-Concavisporites Zone; PT, Pinuspollenites-Trachysporites Zone, for details see Barth et al. (2018a).

Database

The exploration of the Rhaetian deltaic system was based on: (1) facies analysis of more than 2000 m cored intervals from 23 wells of the North German Basin; and (2) five outcrop analogue studies from the southern margins of the basin. High-resolution time control on the Rhaetian deltaic system is provided by palynomorph biostratigraphy (Lund 1977, 2003; Heunisch 1999). Numerous palynostratigraphic datasets were generated during previous subsurface mapping campaigns and exploration for hydrocarbons, geothermal resources or underground storage sites. The majority of these data are present in the form of unpublished core reports, only a few data have been published (e.g. Lund 1977, 2003; Heunisch 1996a, b; Heunisch et al. 2010). The unpublished data are owned by geological state surveys (subsurface mapping) or private companies (exploration) and are available upon request or permission, respectively. In addition to these data, a larger dataset of 158 rock samples from nine wells and several outcrops was recently collected and studied in terms of palynomorph biostratigraphy (Barth et al. 2018a).

The results of palynomorph biostratigraphy and facies analysis were calibrated to a large database of 515 logged wells (Fig. 11). The petrography and granulometry of Rhaetian reservoirs were studied by means of 110 grain size and 215 thin sections analyses (Fig. 4). The quality of Rhaetian reservoirs of the Neustadt-Glewe, Gartz and KSS 5 deltaic complexes were evaluated using a database of 740 porosity and 262 permeability measurements.

Palynostratigraphic control on the Rhaetian deltaic system

The Rhaetian deltaic system is composed of four individual deltaic complexes that can be assigned to palynomorph zones (Lund 1977; Barth et al. 2018a). The evolution of the Rhaetian deltaic system started with the deposition of the Neustadt-Glewe and KSS 5 deltaic complexes assigned to the middle Rhaetipollis–Limbosporites (RL) Zone (Barth et al. 2018a). Abandonment of these complexes and the northwards shift of deltaic sedimentation contributed to the formation of the Rødby deltaic complex assigned to the upper RL Zone (Lund 1977). Due to a transgression resulting in the maximum extension of the Rhaetian Sea in the uppermost RL Zone (Barth et al. 2018a), deltaic sedimentation shifted to the east. The Gartz complex is assigned to the Ricciisporites–Polypodiisporites Zone, and parts of the KSS 5 deltaic complex are assigned to the Deltoidospora–Concavisporites Zone (Fig. 11) (Barth et al. 2018a). Thus, the Rhaetian deltaic system study is a particularly good example of high-resolution palynostratigraphy contributing to detailed reconstructions of a deltaic system, such as deposition and abandonment of deltaic complexes.

Based on the correlation of the Rhaetian palynomorph zonation with the chronostratigraphic standard (Ogg 2012), the evolution of the Rhaetian deltaic system is believed to have formed over a 2.5 myr long time interval of the latest Triassic (Barth et al. 2018a). In terms of sequence stratigraphy, the Rødby, Neustadt-Glewe and parts of the KSS 5 deltaic complexes were formed around the maximum regression of Rhaetian 3rd-order sequence Rh 1 (mrs Rh1) and the Gartz and parts of the KSS 5 deltaic complexes were formed around the maximum regression of Rhaetian sequence Rh2 (mrs Rh2: Fig. 11) (Barth et al. 2018a).

Morphology of the Rhaetian deltaic system

The progradation of the Rhaetian deltaic system resulted in the deposition of up to 80 m-thick delta plain deposits (Fig. 11). The overall progradational architecture and the elongate shape of individual deltaic complexes correspond to the elongate high-constructive delta type according to Fisher et al. (1969).

The consecutive formation of deltaic complexes resulted in a compound delta plain estimated to be 47 000 km2 in size. The Neustadt-Glewe, Rødby and KSS 5 deltaic complexes were mainly fed by drainage systems located to the west of the island of Rügen; only the Gartz deltaic complex was fed by a drainage system to the east of this island (Fig. 12a). Based on the occurrence of marine phytoplankton, such as acritarchs and dinoflagellate cysts (Barth et al. 2018a), the Rhaetian delta plain is subdivided into a lower delta plain of about 21 000 km2 and an upper delta plain of about 26 000 km2 in size.

Fig. 12.
Fig. 12.

The Rhaetian deltaic system. (a) Subsurface facies map of the high-constructive fluvial-dominated Rhaetian deltaic system; red lines represent the margins of the upper and lower deltaic plains; post-sedimentary erosion not shown. (b) Reservoir quality map in terms of thickness and permeability, average of lab data are only shown for mapping and geothermal wells; post-sedimentary erosion according to Baldschuhn et al. (2001) and Müller & Reinhold (2011).

Each of the four deltaic complexes was fed by a single distributary channel. Increasing bifurcation in a downstream direction indicated repeated lobe switch and abandonment during the formation of a deltaic complex. The angles between bifurcated channels vary from 25° to 55°.

The upper delta plain is composed of distributary channels, levee/crevasse splay complexes, sheetsands and wetland facies associations (Table 3). The sandy fills of lateral-migrating distributary channels are recognized by up to 30 m thick successions of single to multiple stacked point-bar deposits. As dated by palynomorphs, the distributary channels of the Gartz, KSS 5 and Neustadt-Glewe deltaic complexes demonstrate up to 30 m of incision into older Rhaetian strata. The incision rates decrease downstream and distributaries are only slightly incised at the lower delta plain (Barth et al. 2018a). The lower delta plain is composed of distributary channels, levee/crevasse splay complexes, sheetsands and interdistributary bay facies associations (Table 3). At the distal end of the lower delta plain, the delta front is composed of terminal distributary channel and mouth bar facies associations forming distributary/mouth bar complexes. Distributary/mouth bar complexes are up to 30 m thick and have a lobe-shaped bar-finger architecture. Lobe switching and increased bifurcation at the distal end of distributaries resulted in lateral associations of sandy distributary/mouth bar complexes and shaly fills of interdistributary bays.

View this table:
Table 3.

Facies associations of the Rhaetian deltaic system and their reservoir quality

In terms of hydrothermal exploration opportunities, distributary channels and associated lateral levee/crevasse splay complexes are the most relevant morphological units. Based on subsurface facies and sand thickness mapping, these facies associations form up to 20 km broad sandy belts. Accordingly, the calculated medians of meander belt widths are 0.8–9.8 km, roughly corresponding to these values if lateral associated stacked sheetsands are taken into account (Fig. 13). Downdip, towards the prodeltaic environment, sand content deceases and marine conditions prevail, as indicated by the presence of marine phytoplankton and macrofauna with Rhaetavicula contorta. Marine processes, responsible for resedimentation of delta front silts and sands, contributed to thin intercalations within laminated shales in the proximal prodelta. The distal prodelta is predominantly formed of successions of laminated shales that are up to decametres thick.

Fig. 13.
Fig. 13.

Thickness distribution plots of distributary channel fills (Td) and channel belt complexes, as well as calculations of channel belt widths (wdcb) for the Rhaetian and Toarcian--Bajocian deltaic systems. Model 1 (Embedded Image) according to Fielding & Crane (1987); Model 2 (Embedded Image) according to Fielding & Crane (1987) and Miall (1996); Model 3 (Embedded Image) according to Collinson (1978).

Reservoir types and reservoir quality

Individual high-quality reservoirs up to a few metres thickness may be present in any of the sand-prone facies associations. However, taking the minimum thickness of 20 m required for long-term operation of hydrothermal reservoirs into account, only compound reservoir types formed of stacked individual reservoirs are considered viable exploration targets. Such compound reservoir types are represented by up to 95 m thick channel belts, resulting from vertical stacking of a distributary channel fill and lateral associated levee/crevasse splay complexes, and by up to 30 m thick progradational distributary/mouth bar complexes (Table 3). Total net-thicknesses of sandstone reservoirs range from 7 m to 56 m for channel belts and from 5 m to 25 m for distributary/mouth bar complexes.

In terms of petrography, granulometry and reservoir quality, the compound reservoir types of the Neustadt-Glewe, Gartz and KSS 5 deltaic complexes are comparable and do not show significant variations. The reservoir types are characterized by fine- to medium-grained, moderately to well sorted and mainly clean quartzarenites (Fig. 4b). The high median permeabilities of 602 mD for channel belts and of 688 mD for levee/crevasse splay complexes are mainly related to high median porosities of 19.7% for channel belts and of 22.3% for levee/crevasse splay complexes (Table 3). Wolfgramm et al. (2008) emphasized the dominance of pores larger >5 µm (70%), and reported 13 µm as the median radius of all intergranular pores.

In many cases, the porosity was not significantly affected by authigenic cementation (Franz & Wolfgramm 2008). However, in a few cases, the porosity of Rhaetian reservoirs was partly to completely destroyed by authigenic cementation close to salt structures (Baermann et al. 2000).

Reservoir prediction

In the eastern and northern part of the North German Basin, channel belt reservoirs are present and form up to 20 km broad belts trending N–S to NE–SW across the delta plain (Fig. 12b). Based on the evaluated well data, these belts are recorded in 31 wells of the Neustadt-Glewe deltaic complex (Rhaetian C), 11 wells of the Rødby deltaic complex (Rhaetian D), eight wells of the Gartz deltaic complex (Rhaetian E) and 19 wells of the KSS 5 deltaic complex (Rhaetian C–F). According to their broad distribution, the channel belt reservoirs represent the key exploration target. The subsurface facies and sand thickness maps enable an improved reservoir prediction for underexplored localities along the mapped courses of channel belts (Fig. 12b). Lateral to these courses, the reservoir thickness decreases rapidly and, thus, the exploration risk increases, although permeabilities may still be high.

The distributary–mouth bar reservoir type is present in the form of falciform reservoir bodies fringing the distal ends of delta lobes. This reservoir type has been recorded in 25 wells of the Neustadt-Glewe deltaic complex (Rhaetian C), five wells of the Rødby deltaic complex (Rhaetian D), two wells of the Gartz deltaic complex (Rhaetian E) and eight wells of the KSS 5 deltaic complex (Rhaetian C/F). As the occurrence of distributary–mouth bars is limited to the delta front, this reservoir type is restricted to central parts of the North German Basin (Fig. 12b).

Exploration example 2: the Toarcian–Bajocian deltaic system

Following basin-wide deposition of the Lower Toarcian Posidonia shale and equivalents during a second-order sea-level highstand in the Tenuicostatum ammonite Zone, the successive retreat of the Jurassic sea enabled the progradation of coastal-deltaic environments. Fed by Scandinavian sources to the north, subsequent progradation of genetically related deltas from the Lower Toarcian to the Upper Bajocian resulted in the formation of the Toarcian–Bajocian deltaic system (Fig. 14) (Zimmermann 2015; Zimmermann et al. 2018).

Fig. 14.
Fig. 14.

Subsurface sandstone thickness maps of the Toarcian--Bajocian deltaic system, modified from Zimmermann (2015) and Zimmermann et al. (2018): The reservoir thickness refers to the total net-thickness of sandstone reservoirs assigned to the Upper Toarcian (Reservoir B), Upper Aalenian (Reservoirs C and D) and Upper Bajocian (Reservoir E) intervals; post-sedimentary erosion not shown (see Fig. 16); 1, JOmb 1; 2, JOmb 3; 3, JOmb 10; 4, Zechliner Hütte 1A; 5, Neuruppin 2; 6, Hagenow 1; 7, Kettelstorf 1.

Database

The assessment of the Toarcian–Bajocian deltaic system was based on facies analysis of c. 2000 m of cored interval in 15 wells of the North German Basin and an outcrop analogue study in SE Lower Saxony (Zimmermann et al. 2014). High-resolution biostratigraphic time control is available in the form of numerous unpublished core reports from the 1960–80s (see the database of the RDS). All data were added to a large database of biostratigraphically calibrated wells (Zimmermann et al. 2015). The petrography, granulometry and quality of Toarcian–Bajocian reservoirs were evaluated based on 108 grain size analyses, about 200 thin sections, and a database of 1704 porosity and permeability measurements (Zimmermann 2015).

Biostratigraphic on the Toarcian–Bajocian deltaic system

Biostratigraphic control on the Lower and Middle Jurassic is based on a high-resolution framework of ammonite, ostracod, foraminifer and palynomorph zonations (Klingler & Neuweiler 1959; Triebel & Klingler 1959; Plumhoff 1963; Störmer & Wienholz 1965; Malz 1966, 1971; Michelsen 1975; Sivhed 1980; Brand & Mönnig 2009; Luppold 2012). In a previous study, Zimmermann et al. (2015) calibrated a large set of more than 450 wells to zones (and subzones) of the NW European ammonite zonation, and introduced a sequence stratigraphic framework of third- and fourth-order sequences (Fig. 14). According to this high-resolution chronostratigraphic control of Jurassic ammonite zones, delta formation in the Lower Toarcian (Bifrons), Upper Toarcian (Thouarsense), Upper Aalenian (Murchisonae–Bradfordensis) and Upper Bajocian (Garantiana) could be calibrated to 1.0–2.1 myr long intervals (Zimmermann 2015; Zimmermann et al. 2018).

Morphology of the Toarcian–Bajocian deltaic system

During the 14.4 myr long Toarcian–Bajocian interval, third-order sea-level fluctuations triggered the subsequent formation of four individual delta systems. As these deltas are genetically related, they have been treated as one Toarcian–Bajocian deltaic system. High-resolution basin-scale mapping of sandstone thickness and facies enabled the detailed description of delta morphology, and the interpretation of sedimentary processes and their controls (Zimmermann 2015; Zimmermann et al. 2018). The following description is focused on the deltas formed in the Upper Toarcian Thouarsense Zone, and the Upper Aalenian Murchisonae–Bradfordensis and Upper Bajocian Garantiana ammonite zones (Fig. 15).

Fig. 15.
Fig. 15.

Subsurface facies maps of the Toarcian–Bajocian deltaic system, modified from Zimmermann et al. (2018); post-sedimentary erosion not shown (see Fig. 16).

The Upper Toarcian elongated river-dominated delta comprises up to 40 m thick delta plain successions in the eastern part of the North German Basin, stretching about 200 km from northern basin margins (Fennoscandian Border Zone) up to the east Prignitz and north Brandenburg areas. The delta plain, covering an area of about 20 000 km2, was fed by a network of distributary channels of meandering to anastomosing channel type. Calculated medians of meander belt widths range between 0.5 and 6.4 km, and mapped widths of meander belts are up to 15 km (Figs 13 & 15). The Upper Toarcian distributive channel network shows angles of 30°–70° between successive distributary channel belts, and increasing frequency of bifurcation and decreasing channel belt fill from about 40 m to about 10 m in a downstream direction. Distally, towards the basin, the progradational delta front is composed of 10–50 m thick distributary/mouth bar complexes characterized by bar-finger architecture (Zimmermann 2015; Zimmermann et al. 2018).

The Upper Aalenian lobe-shaped river-dominated delta stretches from the northern basin margin up to the Altmark area (Fig. 14). The delta plain, characterized by up to 100 m thick successions, covers an area of about 40 000 km2. The substantial enlargement, compared with the older Toarcian deltas, resulted from successive shallowing of the Jurassic Sea from Toarcian to Aalenian times (Zimmermann et al. 2015). Based on sandstone thickness and facies mapping, at least three deltaic complexes (northern, eastern and western) can be defined (Figs 14 & 15). Here, the focus is on the western and eastern deltaic complexes since much of the northern deltaic complex was subject to later erosion (Fig. 16). The delta plain of the western complex is up to 100 m thick and the delta plain of the eastern complex is up to 30 m thick. The distributive channel networks of both complexes show angles of 50°–100° between bifurcated distributary channels and increasing bifurcation in the downstream direction. An outcrop analogue situated in SE Lower Saxony revealed the lateral shift and stacking architecture of a meandering distributary channel system (Zimmermann et al. 2014). For the western deltaic complex, the lateral shift of distributaries resulted in up to 85 m thick successions of distributary channel fills and associated levee/crevasse splay complexes (Fig. 17; Table 4). These channel belts yielded sandstone reservoirs of up to 70 m net-thickness. Locally increased thicknesses of >100 m result from salt tectonics (Fig. 14). Calculated medians of meander belt widths range between 1.1 and 12.0 km, and mapped widths of meander belts range up to 15 km (Figs 13 & 15). Delta fronts comprise up to 70 m thick distributary/mouth bar complexes with up to 50 m thick (net-thickness) sandstone reservoirs of bar-finger sand architecture (Zimmermann 2015; Zimmermann et al. 2018). The morphology of the eastern margin of the Upper Aalenian delta reveals an increasing influence of marine processes (Fig. 15).

Fig. 16.
Fig. 16.

Reservoir quality map in terms of thickness and permeability, average of lab data are only shown for mapping and geothermal wells, modified from Zimmermann (2015); post-sedimentary erosion according to Baldschuhn et al. (2001), Brand & Mönnig (2009).

Fig. 17.
Fig. 17.

Reservoir types of the Toarcian–Bajocian deltaic system (core examples). (a) Upper Aalenian, Neuruppin 2/86; (b) Upper Toarcian, JOmb 3/66; (c) Upper Bajocian, JOmb 1/65; and (d) Upper Toarcian, JOmb 10/66. For the location see Figure 14. mfs, maximum flooding surface; mrs, maximum regression surface (modified from Zimmermann et al. 2018).

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Table 4.

Facies associations of the Toarcian–Bajocian deltaic system and their reservoir quality; locally increased thicknesses due to salt tectonics not considered

The Upper Bajocian mixed river-dominated and wave-modified delta stretches from the Fennoscandian Border Zone up to the Ems-Weser area. In accordance to the Aalenian delta, at least three deltaic complexes can be subdivided (Fig. 14). The western deltaic complex shows a cuspate and slightly oblique to elongate overall morphology, differing greatly from the eastern deltaic complex which was reshaped by marine processes (Fig. 15). The western deltaic complex was fed by a main distributary channel network characterized by increasing bifurcation in a downstream direction and angles of 50°–100° between bifurcated channels. Up to 30 m thick distributary channel fills form together with lateral associated levee/crevasse splay complexes up to 50 m thick sandy successions of channel belts (Fig. 13). The delta front comprises 30–50 m thick amalgamated distributary/mouth bar complexes of lobate sand bodies with bar-finger sand architecture (Zimmermann 2015; Zimmermann et al. 2018).

Reservoir types and reservoir quality

Similar to the Rhaetian deltaic system, compound reservoirs of channel belts and distributary/mouth bar complexes represent the key targets for hydrothermal exploration opportunities (Fig. 17). The channel belt reservoir type is composed of almost univariate medium- to fine-grained sandstone characterized by high maturity (Fig. 4b). A high median porosity of 25% relates to a high median permeability of 1426 mD (Fig. 6; Table 4). The distributary/mouth bar complex reservoir type is composed of fine- to medium-grained sandstone characterized by bivariate to multivariate grain-size distributions due to a greater amount of fine particles resulting in a median permeability of 498 mD (Table 4) (Zimmermann 2015). In general, diagenetic modifications of grains in Aalenian sandstones are rare, and diagenetic cement content is low. Only in local areas (e.g. close to salt structures) has fluid migration contributed to formation of authigenic cements, mainly quartz or patchy dolomite.

Reservoir prediction

For the Toarcian–Bajocian deltaic system, the channel belt reservoir type is present and forms up to 15 km wide depositional belts trending across the delta plains (Fig. 15). The reservoir type was proven by numerous wells for the Lower Toarcian delta (reservoir A, not shown in Figs 15 & 16), the Upper Toarcian delta (reservoir B, Figs 15a & 16a), the Upper Aalenian delta (reservoirs C and D, Figs 15b & 16b) and the Bajocian delta (reservoir E, Figs 15c & 16c). Laterally, in the up to 85 m thick sand-prone channel belts, the thickness of reservoirs decreases rapidly and exploration risk subsequently increases. Up to 40 m thick falciform-shaped reservoirs of distributary/mouth bar complexes mark the distal ends of delta lobes. The reservoir quality maps of the Toarcian–Bajocian deltaic system enable an improved reservoir prediction for both reservoir types (Fig. 16a–c).

However, in contrast to the Rhaetian deltaic system, the presence of reservoirs is limited by later erosion. This refers, in particular, to the Upper Aalenian and Upper Bajocian deltas as both were subject to widespread erosion in Schleswig-Holstein, and in larger parts of Mecklenburg-Vorpommern and Lower Saxony (Fig. 16c). A further limitation is given by the shallow burial depths of often less than 1000 m, as the reservoir temperatures are too low.

Discussion

Controls on Mesozoic reservoir complexes

The formation of Mesozoic hydrothermal reservoirs was controlled by tectonic and climatic processes. In the Triassic and Jurassic, the general tectonic regime changed to E–W and NE–SW directed extension (Ziegler 1982; Kockel 2002; Kley et al. 2008). Accordingly, the low, but continuous, subsidence rates resulted in generally small thicknesses of hydrothermal reservoirs. As demonstrated herein, Triassic and Jurassic hydrothermal reservoirs exceeding 20 m thickness are not regionally distributed. The present-day distribution of Triassic and Jurassic reservoir complexes may be limited by post-depositional erosion due to erosional unconformities: for example, the Norian Early Cimmerian Unconformity (Beutler & Schüler 1978) or the Aalenian mid-Cimmerian unconformity related to thermal updoming in the North Sea area (Hallam & Sellwood 1976; Underhill & Partington 1993). It is noteworthy that these unconformities are not of basin-wide occurrence, but locally up to some 100 m of strata may be missing (Beutler & Schüler 1978; Barnasch et al. 2005; Stollhofen et al. 2008; Beutler et al. 2012). The change to compressional tectonics in the Cretaceous resulted in complex patterns of uplift and subsidence. Post-depositional erosion during the Cretaceous affected the present-day distribution of the Lower Cretaceous reservoir complex and, in places, also older reservoir complexes (Fig. 2) (Ziegler 1990; Kley & Voigt 2008; Voigt et al. 2008; Vejbæk et al. 2010).

Besides variabilities in thickness and the presence of strata, the general tectonic regime and basin evolution is reflected by successively increasing maturities of sandstones. Rotliegend sandstones of the early basin fill stage are characterized by low mineralogical maturity (Fig. 4b) (Wolfgramm 2005). Although the evolution of the Permo-Carboniferous climate was complex (Roscher & Schneider 2006), the low maturity of Rotliegend sandstones can be explained simply by an arid to semi-arid climate (e.g. Glennie 1972, 1983). Buntsandstein and Rhaetian to Lower Cretaceous sandstones of the late basin fill stage are characterized by intermediate and high mineralogical maturities, respectively (Fig. 4b). The high maturities of Rhaetian and younger sandstones are in agreement with Upper Triassic–Jurassic increased onshore precipitation reconstructed from clay mineral assemblages (Ahlberg et al. 2002; Feist-Burkhardt et al. 2008; Dera et al. 2009). Sandstones of the Lower–Middle Keuper reservoir complex are exceptional as they are characterized by very low mineralogical maturities (Fig. 4b) (Förster et al. 2010; Franz et al. 2015). Apart from the rather general discussion whether the Schilfsandstein represents a humid climate event (see Simms & Ruffell 1989; Visscher et al. 1994; Kozur & Bachmann 2010), the very low maturity – in particular, the high content of lithics – seems not to be controlled by climate fluctuations (Franz et al. 2014). Kozur & Bachmann (2010) suggested a provenance association with rift shoulder uplift in the area of the Scandinavian Caledonides but further constraints are required.

The North German Basin comprises numerous salt walls, diapirs and pillows of Rotliegend and/or Zechstein salt (Ziegler 1990; Reinhold et al. 2008). Salt diapirism started in the early Triassic and attained maxima in the late Triassic–early Jurassic and early Cretaceous intervals (Trusheim 1957; Kootz & Schumacher 1967; Jaritz 1974). As detailed by Hansen et al. (2007) and Scheck-Wenderoth et al. (2008), salt diapirism resulted in local differences in subsidence and sedimentation patterns in the NGB, whereas a general impact on depositional environments of Triassic and Jurassic reservoir complexes is not indicated (Franz et al. 2014, 2015; Zimmermann et al. 2015, 2018; Barth et al. 2018a). The role of halokinesis in influencing Lower Cretaceous reservoir distribution is subject to an ongoing study.

Reservoir prediction and exploration risk

For the herein detailed Rhaetian and Middle Jurassic reservoir complexes, the compound reservoirs of channel belt and distributary/mouth bar types have been identified as key targets of geothermal exploration (Tables 3 & 4). Only these two reservoir types meet the required key parameters of reservoir quality: >20 m thickness and >500 mD permeability (Rockel et al. 1997). The reservoir temperature depends on the local geothermal gradient and, thus, the burial depth. As such, this parameter is not related to the depositional environment of the reservoir.

Subsurface facies mapping of the Rhaetian and Toarcian–Bajocian deltaic systems revealed larger areas covered by the channel belt reservoir type compared to the distributary/mouth bar type for both systems (Figs 12 & 15). Considering the successful operation of the channel belt reservoir type at Neustadt-Glewe and Waren (Fig. 8), further geothermal exploration should focus on this reservoir type. Within the Rhaetian and Toarcian–Bajocian deltaic systems, up to 20 km wide sand-prone strings, herein considered channel belts, have been mapped whose positions were mainly controlled by distributary channels (Fig. 18). Lateral migration and shifting of distributary channels resulted in vertical stacks of sandy channel fills and lateral associated sand-prone levee/crevasse splay complexes. The general high potential of the channel belt reservoir type may be limited by the following aspects. (1) Channel belts are not characterized by a uniform large sandstone thickness. The sandstone thickness often exceeds 20 m but this is not necessarily the case for each point within the channel belt. It is important to note that this aspect cannot be addressed in basin-scale sandstone thickness maps. (2) Laterally, channel belts show facies shifts with delta plain environments often dominated by shaly lithologies. With increasing distance from the distributary channel, the sandstone thickness also decreases and shaly intercalations become more abundant. This is important as substantial shaly intercalations are negatively influencing the productivity and injectivity of the hydrothermal reservoirs: for example, due to the mobilization of fine-grained particles.

Fig. 18.
Fig. 18.

Potential of the channel belt reservoir type. Synopsis of subsurface facies, sandstone thickness and reservoir quality along a synthetic cross-section.

Conclusions

Basin-scale subsurface facies, sandstone thickness and reservoir quality maps of the Rhaetian and Toarcian–Bajocian deltaic systems enable the improved exploration of Rhaetian and Middle Jurassic hydrothermal reservoirs for individual areas. These maps have already been used to help plan ongoing and future projects in Lower Saxony and Mecklenburg-Vorpommern.

In the next step, basin-scale subsurface maps should be substantiated by detailed mapping studies. Regional- to local-scale subsurface facies, sandstone thickness and reservoir quality mapping studies will contribute to a further reduction of exploration risks and exploration strategies for individual localities. Such regional- to local-scale studies should routinely implement the acquisition of 3D seismic data. The successful targeting of geobodies by means of 3D seismic campaigns will further contribute to a significant reduction in exploration risks and costs.

Acknowledgements

The authors acknowledge funding by the Bundesministerium für Wirtschaft und Energie (https://doi.org/10.13039/501100006360: grant numbers 0325285 and 0325920 to Matthias Franz and Markus Wolfgramm) BMWi and Bundesanstalt für Geowissenschaften und Rohstoffe (BGR). Karsten Obst, Juliane Brandes (Landesamt für Umwelt und Naturschutz Mecklenburg-Vorpommern), Michael Göthel (Landesamt für Bergbau, Geologie und Rohstoffe Brandenburg), Thomas Koch, Karl-Heinz Friedel (LAGB Sachsen-Anhalt), Joachim Schubert (†TLUG), Heinz-Gerd Röhling (Landesamt für Bergbau, Energie und Geologie Niedersachsen) and Robert Lippmann (RWE DEA) kindly provided access to well data and core material. The reviews of Renaud Bouroullec (TNO) and an anonymous reviewer, and the editorial handling of Harmen Mijnlieff (TNO) and Ben Kilhams (Shell), are gratefully acknowledged.

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