Anders Mathiesen

This study presents the tectonostratigraphic evolution of the Danish onshore and coastal inshore area constituting the Danish Basin and the northern part of the North German Basin, separated by the Ringkøbing–Fyn High, based on seismic, wireline log and lithologic data. The study area covers the northern part of the Central European Basin System which was characterised by repeated tectonic episodes since the Late Carboniferous. Based on well and seismic data released prior to 2022, 20 regional seismic horizons defining 17 stratigraphic units are interpreted. The composition of the units is determined from wireline log interpretation and lithological information by tying the seismic horizons to the wells. Gravity data compiled as Bouguer and free air anomaly maps supplemented the seismic interpretation. A layered digital elevation model in metres, composed of 17 grids with a cell size of 400 × 400 m, forms the basis for 17 depth and 16 isochore maps. The maps represent the Upper Permian – Cretaceous deposits by integrating seismic profiles, wireline and lithological data from the deep wells. Selected seismic reference sections with ties to the relevant wells illustrate the interpreted unit boundaries. Eight cross-sections augment the presented depth and isochore maps. The tectonic evolution of the study area took place in four stages: 1). Late Carboniferous – earliest Permian strike-slip, doming and igneous activity. 2). Early–Middle Permian domal subsidence followed by Late Permian – Triassic thermal subsidence and minor rift phases. 3). Jurassic – Early Cretaceous subsidence and minor rift phases. 4). Late Cretaceous –Danian deposition during a long-lasting major eustatic sea-level high. Mobilisation of Zechstein evaporites into salt structures greatly influences the depth and isochore maps in Jylland and the two islands south of Sjælland (Lolland and Falster). The study has established a general structural–stratigraphic framework for further studies and interpretations of the geological development of the area. The depth and isochore maps, together with eight cross-sections, provide a robust foundation for future exploration activities, such as storage of CO2, hydrogen, natural gas, radioactive waste etc., as well as utilisation of geothermal resources. Some of the results of the present study have been used as basic input for the Web-based Geographic Information System geothermal portal hosted by the Geological Survey of Denmark and Greenland.

This study presents a first-order assessment of reservoir pressure regimes across onshore Denmark, focusing on hydrostatic conditions and occurrences of natural overpressure. Using a newly compiled database of brine salinity measurements from 28 wells, hydrostatic pressures were estimated based on salinity-derived density profiles. Validation against in situ pressure measurements confirms the reliability of this approach. Additional analysis of historical artesian deep wells documents local overpressured reservoirs within specific units such as the Zechstein Group, Bunter Sandstone and Ørslev Formations. These overpressured compartments suggest that reservoirs may be hydraulically isolated, potentially impacting storage capacity in CO2 sequestration projects. Overpressure is also observed in the overburden within the Chalk Group. We suggest that regional Neogene uplift has further shaped hydraulic heads in the Chalk Group, introducing semi-regional pressure compartments. The main objective of this study was to establish a robust regional baseline for hydrostatic pressure conditions while highlighting historically underappreciated overpressure phenomena relevant to risk assessment in subsurface CO2 storage, geothermal utilisation and underground energy storage. We calculate the pressure required to lift brine to the surface, potentially allowing interaction with groundwater and thereby providing practical constraints for risk assessments and subsurface pressure management in prospective CO2 storage sites. In order to distinguish between open versus closed aquifer behaviour and identify potential brine discharge pathways, the sealing capacity of the Quaternary cover above the sparse natural outcrops of the Gassum and Skagerrak Formations, together with the conductivity of fault systems, must be assessed. These results establish a pressure baseline and provide critical input for future pressure communication models, supporting site selection, operational safety and coordinated subsurface resource management during Denmark’s green energy transition.

CO2 storage presents new risks and challenges, where the properties of formation water play an important role. These challenges include reduced injectivity and storage capacity due to salt precipitation, viscous fingering caused by viscosity contrasts between CO2 and brine and diminished CO2 solubility in formation waters. Understanding these factors and developing predictive models for pressure distribution are essential for successful CO2 storage projects. This study presents salinity (Cl and total dissolved solids), density, temperature, pressure, halite (NaCl) saturation, CO2 solubility and viscosity of formation waters across five CO2 storage sites in Denmark (Stenlille, Gassum, Rødby, Lisa and Inez), covering eight reservoirs (one in the Frederikshavn Formation, four in the Gassum Formation and three in the Bunter Sandstone and Skagerrak Formations). Salinity assessments are based on existing brine data or, where unavailable, a reference salinity model developed from a water chemistry database with 77 analyses from 28 wells in the Danish Basin and adjacent regions. The model was created using Partial Least Squares regression, accounting for local geological developments and subsurface salts. We report high chloride levels (182 000–202 000 mg/L) and densities (1.21–1.23 kg/L) in the Bunter Sandstone and Skagerrak Formations, while the Gassum and Frederikshavn Formations are undersaturated with halite, exhibiting lower chloride levels (99 000–148 000 mg/L) and densities (1.11–1.17 kg/L). These differences suggest a higher risk of mineral precipitation due to brine evaporation in dry CO2, and a higher risk of density override due to significant density contrast, which will hamper filling efficiency in older reservoirs. Modelling shows that CO2 solubility reaches 33.9 g CO2/L, with a 37% reduction due to chemical and pressure–temperature variations. Conceptual fluid flow modelling is recommended to further assess brine–rock–CO2 interactions. The salinity model has implications for geothermal reservoir assessment and can be applied regionally.

In June 2021, a novel Danish national carbon capture and storage strategy was ratified by the Danish Parliament, and this was followed by the initiation of the project ‘CCS2022–2024’, led by the Geological Survey of Denmark and Greenland. In collaboration with other institutions, we acquired and interpreted new 2D seismic data between 2022 to 2024 to investigate and mature eight sites for potential subsurface storage of CO2 in Danish onshore and offshore areas. This Bulletin contains a series of papers that present important results of the work. In this introduction paper, we provide an overview of seismic acquisitions and the interpretation of seismic data together with existing deep wells. The study sites selected are large subsurface structures located in onshore Jylland, Sjælland and Lolland and offshore Denmark in the eastern North Sea. The onshore targets are the Gassum, Havnsø, Rødby, Stenlille and Thorning structures, while the offshore sites comprise the Inez, Jammerbugt and Lisa structures. The project work comprises a series of reports regarding extensive seismic acquisition, processing and interpretation of the new and pre-existing seismic data as well as other publications emanating from the project. This Bulletin and the technical reports present an improved understanding of the formation, composition and geometry of the investigated structures. The studies include the mapping of the reservoir and seal formations, identification of principal faults, interpretation of the stratigraphic and structural development, reservoir and seal characterisation and estimates of the static storage capacity. Hence, this research provides a significant step forward concerning characterisation of the geology and maturation of the potential storage sites. In addition, it has inspired new ideas, including an updated regional stratigraphic interpretation of the Triassic succession of the Danish Basin and correlation with adjacent basins.

Large‐scale carbon capture and storage (CCS) is essential for reducing CO ₂ emissions, and Denmark’s initial efforts targeted depleted oil fields in the outer North Sea. More recently, focus has shifted to saline aquifers located outside the established North Sea oil province. Unlike hydrocarbon (HC)‐bearing reservoirs, saline aquifers do not pose risks of reservoir clogging from heavy oil residues or unintended HC migration and pollution beyond the storage structure. The Jammerbugt structure, situated in eastern Skagerrak beyond the oil province, remains undrilled but is located in a unique geological setting where an active petroleum system has been speculated. This study aims to de‐risk the presence of petroleum in the Jammerbugt structure by applying basin and petroleum system modelling (BPSM). The model is calibrated to actual vitrinite reflectance (VR) data to constrain the tectonic and geothermal history of the area, that is, the thermal history is constrained by the measured %VR _o values and their quantified uncertainties. The overall calibration is evaluated through calculated root mean squared (RMS) errors, which shows good performance within the potential kitchen area, and a less good performance along the model margins. A two‐case scenario was developed to test the generation and migration of petroleum from the Lower Jurassic Fjerritslev Formation (Fm) into the Jammerbugt structure: A best‐fit (BF) and a high‐end (HE) cases. The BF case represents the most likely geological conditions, that is, the burial depth, timing and magnitude of uplift and exhumation and paleo heatflow, and applying a four‐phase petroleum kinetics model. The HE case incorporates the upper bounds for these variables, constrained by the uncertainties, to create a “what‐if” scenario together with a conventional two‐phase petroleum kinetics model. Both the BF and the HE scenarios indicated the potential presence of a working petroleum system within the Fjerritslev Trough; however, petroleum was not expelled from the source rock (Fjerritslev Fm) in either of the scenarios, due to poor source rock quality. The findings of this study de‐risk expulsion of petroleum from a working petroleum system into the Jammerbugt structure and in the Skagerrak region in general, emphasising the Jammerbugt structure as a future potential CCS candidate.

The Danish part of the Central Graben (DCG) is one of the petroliferous basins in the offshore region of north-western Europe. The source rock quality and maturity is here reviewed, based on 5556 Rock-Eval analyses and total organic carbon (TOC) measurements from 78 wells and 1175 vitrinite reflectance (VR) measurement from 55 wells, which makes this study the most comprehensive to date. The thermal maturity is evaluated through 1-D basin modelling of 46 wells. Statistical parameters describ-ing the distribution of TOC, hydrocarbon index (HI) and Tmax are presented for the Lower Jurassic marine Fjerritslev Formation, the Middle Jurassic terrestrial-paralic Bryne, Lulu, and Middle Graben Formations and the Upper Jurassic to lowermost Cretaceous marine Lola and Farsund Formations in six areas in the DCG. For the Farsund Formation the source-rock richness is presented for selected stratigraphic sequences. The upper part of the Farsund Formation is immature in the southern part of the Salt Dome Province, and late oil mature in and near the Tail End Graben and in the Søgne Basin. The lower part of the Farsund Formation is immature in local areas, yet post-mature in the Tail End Graben and in the Salt Dome Province. The Lower and Middle Jurassic shales are gas-prone in most of the DCG. The depth of the oil window, as defined by a VR of 0.6% Ro, ranges between 2200 and 4500 m. The variations are ascribed to heat flow differences in the DCG and can be modelled by a simple depth model, which includes the thickness of the Cretaceous to Palaeo-gene Chalk and Cromer Knoll Groups. According to the model, a thick Chalk Group offsets the oil window to deeper levels, which likely can be attributed to the thermal properties of the highly thermally conductive chalk compared to the underlying less thermally conductive clays. The DCG is an overpressured basin, and high-pressure, high-temperature conditions are expected to occur deeper than 3.8 km except for the Feda and Gertrud Grabens where such conditions, due to generally lower tem-peratures, are expected to occur deeper than around 4.7 km.

We have seismically characterized a Triassic-Jurassic deep geothermal sandstone reservoir north of Copenhagen, onshore Denmark. A suite of regional geophysical measurements, including prestack seismic data and well logs, was integrated with geologic information to obtain facies and reservoir property predictions in a Bayesian framework. The applied workflow combined a facies-dependent calibrated rock-physics model with a simultaneous amplitude-variation-with-offset seismic inversion. The results suggest that certain sandstone distributions are potential aquifers within the target interval, which appear reasonable based on the geologic properties. However, prediction accuracy suffers from a restricted data foundation and should, therefore, only be considered as an indicator of potential aquifers. Despite these issues, the results demonstrate new possibilities for future seismic reservoir characterization and rock-physics modeling for exploration purposes, derisking, and the exploitation of geothermal energy as a green and sustainable energy resource.

This has now been corrected online and in print.