Abstract The North German Basin yields enormous geothermal resources of more than 13 000 EJ (exajoule: 1 EJ = 1 × 10 18 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.

Abstract 3D basin and petroleum system modelling covering the NW German North Sea (Entenschnabel) was performed to reconstruct the thermal history, maturity and petroleum generation of three potential source rocks, namely the Namurian–Visean coals, the Lower Jurassic Posidonia Shale and the Upper Jurassic Hot Shale. Modelling results indicate that the NW study area did not experience the Late Jurassic heat flow peak of rifting as in the Central Graben. Therefore, two distinct heat flow histories are needed since the Late Jurassic to achieve a match between measured and calculated vitrinite reflection data. The Namurian–Visean source rocks entered the early oil window during the Late Carboniferous, and reached an overmature state in the Central Graben during the Late Jurassic. The oil-prone Posidonia Shale entered the main oil window in the Central Graben during the Late Jurassic. The deepest part of the Posidonia Shale reached the gas window in the Early Cretaceous, showing maximum transformation ratios of 97% at the present day. The Hot Shale source rock exhibits transformation ratios of up to 78% within the NW Entenschnabel and up to 20% within the Central Graben area. The existing gas field (A6-A) and oil shows in Chalk sediments of the Central Graben can be explained by our model.

Abstract In 2011, two discoveries were drilled by PA Resources in the Danish sector. The Broder Tuck 2/2A wells were drilled on a thrusted anticlinal structure, downdip of the apparently small U-1X gas discovery. The wells found an excellent quality gas reservoir within an interpreted Callovian lowstand incised valley containing braided fluvial and marginal-marine sandstones. A top and base seal are provided by mudstones of the over- and underlying transgressive systems tracts respectively. The development of a base seal is key to the presence of a potentially commercial resource downdip of a relatively unpromising old well. The Lille John 1/1B wells were then drilled on a salt diapir on which 1980s wells had encountered shallow oil shows. Lille John 1 found slightly biodegraded 34° API oil in Miocene sandstones at the uncommonly shallow depth of −910 m true vertical depth subsea (TVDSS). The reservoir is full to spill, whilst the trap developed intermittently through latest Miocene–Late Pleistocene times. It is interpreted that a deeper Chalk accumulation temporarily lost seal integrity owing to glacially induced stress or overpressure triggering top-seal failure or fault reactivation during and after latest Pleistocene diapir inflation. The wider hydrocarbon exploration implications of glaciation on stress, pore pressure and trap integrity appear to be underappreciated.

Abstract: Many siliciclastic reservoirs contain millimetre-scale diagenetic and structural phenomena affecting fluid flow. We identified three major types of small-scale flow barriers in a clastic Rotliegend hydrocarbon reservoir: cataclastic deformation bands; dissolution seams; and bedding-parallel cementation. Deformation bands of various orientations were analysed on resistivity image logs and in core material. They are mainly conjugates, and can be used to validate seismically observable faults and infer subseismic faults. Bedding-parallel dissolution seams are related to compaction and post-date at least one set of deformation bands. Bedding-parallel cementation is accumulated in coarser-grained layers and depends on the amount of clay coatings. Apparent permeability data related to petrographical image interpretation visualizes the impact of flow barriers on reservoir heterogeneity. Transmissibility multiplier calculations indicate the small efficiency of the studied deformation bands on flow properties in the reservoir. Deformation bands reduce the host-rock permeability by a maximum of two orders of magnitude. However, host-rock anisotropies are inferred to reduce the permeability by a maximum of four orders of magnitude. The relative timing of these flow barriers, as well as the assessment of reservoir heterogeneities, are the basis for state-of-the-art reservoir prediction modelling.

Abstract Shale gas is produced from fine-grained siliciclastic sediments that are typically rich in organic carbon. Nearly all shales contain thermal gas generated in situ at mature to overmature levels of thermal alteration, although gas of biogenic origin is also produced from some shales. While shale gas production in the USA began in 1821, it is only in the last few years that it has become widely significant (currently about 8% of the domestic gas). In contrast, European shale gas exploration is still in its infancy. In general, European sedimentary basins offer the best potential for shale gas occurrence because thick, organic matter-rich sediments occur in nearly all Phanerozoic strata. Even so, there is little knowledge about the factors controlling shale gas generation and, more importantly, shale gas production in European basins. These factors are not necessarily the same as those that control commercial shale gas production in the USA. Palaeozoic sediments of Cambrian to Ordovician age are currently being tested for their shale gas potential and productivity in Sweden, as are those of Silurian age in Poland. Moreover, Lower and Upper Carboniferous sedimentary successions from England in the west to Poland in the east probably contain shale gas, but their depth, thickness and thermal maturity may be limiting factors for exploration in continental regions. Lower Carboniferous black shales in the Dniepr–Donets Basin of the Ukraine may also hold a significant potential. Moreover, organic-rich sediments of Oligocene/Miocene age in the Paratethyan Basin may offer shale gas potential, for example in the Pannonian Basin. At present, Upper Jurassic black shales are currently being tested for their shale gas potential in the Vienna Basin. European analogues of known biogenic shale gas systems may occur locally in organic-rich Lower Cretaceous sediments in the North German Basin with gas generation being related to Pleistocene glaciation/deglaciation cycles.