The Wandel Sea Basin in eastern North Greenland comprises Upper Palaeozoic-Paleogene sediments. Most stratigraphic units are well dated but new palynological analyses of the 85-100 m thick succession at Kap Rigsdagen, North Greenland have revealed two stratigraphically significant dinoflagellate cyst assemblages which change the earlier age assignment of the succession. The lower assemblage suggests a late Barremian age for the sediments. These sediments and the underlying, coarse-grained sediments (barren of dinoflagellate cysts) show similarities to the upper LadegArdsfien Formation in Peary Land, also of late Barremian age. Consequently, this part of the Kap Rigsdagen succession is herein referred to the LadegArdsaen Formation. The upper part of the Kap Rigsdagen succession yielded a diverse dinoflagellate cyst assemblage dominated by reworked Lower and Upper Cretaceous species but includes Lower to Middle Eocene taxa. Alterbidinium? aff. . bicellulum is the only abundant Eocene species in these strata. This part of the succession is referred to the Thyra empty set Formation based on lithology and paralic depositional environment of Early to Middle Eocene age. Similar rich reworked Cretaceous dinoflagellate cyst assemblages in Paleogene deposits have previously been reported from North and East Greenland. In all cases, this magnitude of reworking responds to regional uplift events in connection with the North Atlantic break-up and sea-floor spreading.

Carboniferous strata of the Wandel Sea Basin unconformably overlie the Laurentian Precambrian crystalline rocks of the Caledonian hinterland at its northernmost exposures in Holm Land (similar to 80 degrees N). Complex zircon from an intermediate gneiss gives an upper-intercept age of 1878 +/- 71 Ma, a protolith age which fits with the regional 1.8-2.0 Ga calc-alkaline arc. A strongly deformed pegmatite was intruded at 435 +/- 17 Ma, and it is a rare example of Caledonian magmatism in the northern sector of the orogen. Omphacite confirms the presence of eclogite (sensu stricto) lenses in the basement complex, thus documenting the northern extent of the North-East Greenland eclogite province formed during the Caledonian collision with Baltica. Holm Land lies in the eastern block of the eclogite province, where an ultrahigh-pressure (UHP) meta-morphic event took place at 365-350 Ma. Zircon from a Holm Land -eclogite lacks a Eu anomaly, has a flat heavy rare earth element pattern, and gives a sensitive high-resolution ion microprobe U-Pb age of 423 +/- 7 Ma, and it is thus interpreted as the time of high-pressure (HP) metamorphism. This age overlaps with the established age of widespread HP metamorphism for the eclogite province (i. e., 415-395 Ma), rather than the younger UHP metamorphism. Westward thrusting of the North-East Greenland eclogite province onto the Laurentian margin after 395 Ma and subsequent exhumation of this uppermost thrust sheet provided a substrate for Carboniferous deposition. Detrital zircon age spectra from arkosic sandstones of the late Visean (ca. 330-340 Ma) Sortebakker and early Moscovian (ca. 310-315 Ma) Kap Jungersen Formations record the progressive unroofing of the North-East Greenland Caledonides. All seven samples have a major peak at 1.8-2.0 Ga, and five also have a 1.75 Ga peak, matching the Paleoproterozoic arc and later anorogenic granitoids that comprise the crystalline basement. Paleozoic grains are sparse in the Sortebakker sandstones, but they constitute a pronounced 400 Ma peak in the younger Kap Jungersen Formation. The composition of the detritus-including garnet clasts, the high amount of discordant zircon (40%), and the large numbers of grains with metamorphic rims that cluster around 410 Ma-reflects a local provenance sourced in the North-East Greenland eclogite province, with some input from the overlying thrust sheets. Other Devonian and Carboniferous basins within and peripheral to the Caledonides also show distinct signatures, demonstrating that there is not a simple, representative detrital zircon signature for the Caledonian orogen.

The paper demonstrates how a potential site for CO2 storage can be evaluated up to a sufficient level of characterization for compiling a storage permit application, even if the site is only sparsely explored. The focus of the paper is on a risk driven characterization procedure. In the initial state of a site characterization process with sparse data coverage, the regional geological and stratigraphic understanding of the area of interest can help strengthen a first model construction for predictive modeling. Static and dynamic modeling in combination with a comprehensive risk assessment can guide the different elements needed to be evaluated for fulfilling a permit application. Several essential parameters must be evaluated; the storage capacity for the site must be acceptable for the project life of the operation, the trap configuration must be efficient to secure long term containment, the injectivity must be sufficient to secure a longstanding stable operation and finally a satisfactory and operational measuring strategy must be designed. The characterization procedure is demonstrated for a deep onshore aquifer in the northern part of Denmark, the Vedsted site. The site is an anticlinal structural closure in an Upper Triassic – Lower Jurassic sandstone formation at 1 800-1 900 m depth.

We assessed the synergetic benefits of simultaneous formation fluid extraction during CO2 injection for reservoir pressure management by coupled hydro-mechanical simulations at the prospective Vedsted storage site located in northern Denmark. Effectiveness of reservoir pressure management was investigated by simulation of CO2 storage without any fluid extraction as well as with 66% and 100% equivalent volume formation fluid extraction from four wells positioned for geothermal heat recovery. Simulation results demonstrate that a total pressure reduction of up to about 1.1 MPa can be achieved at the injection well. Furthermore, the areal pressure perturbation in the storage reservoir can be significantly decreased compared to the simulation scenario without any formation fluid extraction. Following a stress regime analysis, two stress regimes were considered in the coupled hydro-mechanical simulations indicating that the maximum ground surface uplift is about 0.24 m in the absence of any reservoir pressure management. However, a ground uplift mitigation of up to 37.3% (from 0.24 m to 0.15 m) can be achieved at the injection well by 100% equivalent volume formation fluid extraction. Well-based adaptation of fluid extraction rates can support achieving zero displacements at the proposed formation fluid extraction wells located close to urban infrastructure. Since shear and tensile failure do not occur under both stress regimes for all investigated scenarios, it is concluded that a safe operation of CO2 injection with simultaneous formation fluid extraction for geothermal heat recovery can be implemented at the Vedsted site.

Pore pressure variation resulting from geological CO2 storage may compromise reservoir, caprock and fault integrity. Therefore, we investigate the mechanical impact of industrial-scale CO2 storage at a prospective Danish site by coupled 3D hydro-mechanical simulations carried out by two independent modelling groups. Even though the two chosen modelling strategies are not identical, simulation results demonstrate that storage integrity is maintained at any time. Vertical displacements are mainly determined by hydraulic fault conductivity influencing spatial pore pressure elevation. The introduced fault zone implementation in the hydro- mechanical model allows for localization of potential leakage pathways for formation fluids along the fault plane.

The Fjerritslev Formation in the Norwegian–Danish Basin forms the main seal to Upper Triassic–Lower Jurassic sandstone reservoirs. In order to estimate the sealing potential and rock properties, samples from the deep wells Vedsted-1 in Jylland, and Stenlille-2 and Stenlille-5 on Sjælland, were studied and compared to samples from Skjold Flank-1in the Central North Sea. Mineralogical analyses based on X-ray diffractometry (XRD) show that onshore shales from the Norwegian–Danish Basin are siltier than offshore shales from the Central Graben. Illite and kaolinite dominate the clay fraction. Porosity measurements obtained using helium porosimetry–mercury immersion (HPMI), mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) techniques on the shale samples show that MICP porosity is 6–10% lower than HPMI or NMR porosity. Compressibility, from uniaxial loading, and elastic wave velocities were measured simultaneously on saturated samples under drained conditions at room temperature. Uniaxial loading tests indicate that shale is significantly stiffer in situ than is normally assumed in geotechnical modelling. Permeability can be predicted from elastic moduli, and from combined MICP and NMR data. The permeability predicted from Brunauer–Emmett–Teller (BET)-specific surface-area measurements using Kozeny’s formulation for these shales, being rich in silt and kaolinite, falls in the same order of magnitude as permeability measured from constant rate of strain (CRS) experiments but is two–three orders of magnitude higher than the permeability predicted from the 1998 model of Yang & Aplin, which is based on clay fraction and average pore radius. When interpreting CRS data, Biot’s coefficient has a significant and systematic influence on the resulting permeability of deeply buried shale.

When injecting CO2 in to a subsoil aquifer for permanent CO2 storage the pressure build up in the regional area encircling the site can extend far beyond the site delineation and mitigation procedures must be considered. The pressure build up can be controlled by production of water from the aquifer. In that context the synergy effect by combining CCS with geothermal energy production (GE) is obvious; i.e. the injection site for CCS may be surrounded by several GE plants, where the GE plants are operated so the net production of water cart balance the injected CO2 from the CCS operation sufficiently. Furthermore, the CO2 plume migration may be controlled by operating the different sites as pressure sinks and sources. The paper illustrates the concept for an area in the northern part of Denmark, where a potential CCS site is characterized together with four prospective locations for GE plants. The GE plants are located in a radius of up to 10 km from the CCS site but still outside the closure of the CCS site. The Eclipse 100 reservoir simulator is used for simulations. (C) 2013 The Authors. Published by Elsevier Ltd.

This paper describes a site investigation study that has been performed on the Vedsted structure in NW Denmark, where upper Triassic and Lower Jurassic sandy formations are considered potential reservoirs for large-scale CO2 injection. The study presents the updated version 1.0 model using new 2D seismic data from the site and compares to results from the screening stage where only existing vintage data were used for the geological modelling.In this early stage of site investigation, the regional geological model and sequence stratigraphic interpretation are important contributors to the construction of a realistic geo-model. The facies interpretation is critical for understanding the geometry and connectivity of the reservoir layers.The main reservoir is at depths of 1700 to 2000 m, and therefore the CO2 is injected at supercritical conditions. The reservoir rocks are mainly constituted of fluvial to nearshore deposits including shoreface sandstones, interfingering with marine offshore mudstones. The maximum thickness of the sandstone layers of ca. 30 m will restrict the potential for convection of the brine caused by density contrast instability. Therefore the dissolution enhancement normally assumed to be associated with convection must be modified for this geological setting. This is in contrast to the performance predicted for the Sleipner injection site, where convection is interpreted to happen over time, and it therefore illustrates that site specific evaluation is necessary in order to qualify the contribution from enhanced dissolution as storage mechanism. The interpretation of the new 2D seismic data and the resulting revision of the structural model influence the further plans for data collection, drilling planning and injection strategy. (C) 2011 Published by Elsevier Ltd.

Vattenfall is a major operator on the energy market in Europe and have a broad portfolio of energy production from nuclear power, biomass and coal fired power plants together with a growing amount of wind turbines. Large research programs are looking into optimizing production and reducing environmental impact from the different units. It is Vattenfall vision to be CO2 neutral in the Nordic countries in 2030 and for the entire group in 2050. To obtain these goals Vattenfall is very active in developing technologies for carbon capture and storage (CCS). In Denmark Vattenfall operates three coal-fired power plants and a screening survey in 2007, matching power plant and storage site location source sink matching - pointed towards Nordjyllandsvaerket near the city of Aalborg as the most obvious plant with safe onshore storage opportunities only 30 km away. It was decided to develop the project into a full scale demo project with post-combustion capture, pipeline transport and onshore storage in an aquifer. The whole project has been driven by a very firm time schedule in order to meet the 2015 deadline. When the CCS project on the Vattenfall operated power plant Janschwalde in Germany was granted funding through the European Commission the CCS project at Nordjyllandsvaerket was turned into an early commercial project aiming at 2020 for commissioning. The site characterization is still ongoing on the Danish site. (C) 2011 Published by Elsevier Ltd.

The Cooperation Action Carbon Capture and Storage China-EU project (COACH) is a three-year EC Framework 6 co-funded collaborative project with Chinese and EU partners investigating geological storage options in the Bohai Basin, China. This paper discusses interim assessments of storage potential for the Dagang oilfield complex (Tianjin Municipality), deep saline aquifers in the Jiyang depression (Shandong province) and the Kailuan coalfield (Hebei Province). Source-sink matching options are also discussed using large ‘point source’ data collected for the Shandong Province.

The focus of the GeoCapacity project is GIS mapping of CO2 point sources, infrastructure and geological storage in Europe. The main objective is to assess the European capacity for geological storage of CO2 in deep saline aquifers, oil and gas structures and coal beds. Other priorities are further development of methods for capacity assessment, economic modelling and site selection as well as international cooperation, especially with China. The results of GeoCapacity will include 25 countries and comprises most European sedimentary basins suitable for geological storage of CO2. (C) 2009 Elsevier Ltd. All rights reserved.

The quality, thermal maturity and distribution of potential source rocks within the Palaeozoic–Mesozoic succession of the Danish part of the Norwegian-Danish Basin have been evaluated on the basis of screening data from over 4000 samples from the pre-Upper Cretaceous succession in 33 wells. The Lower Palaeozoic in the basin is overmature and the Upper Cretaceous – Cenozoic strata have no petroleum generation potential, but the Toarcian marine shales of the Lower Jurassic Fjerritslev Formation (F-III, F-IV members) and the uppermost Jurassic – lowermost Cretaceous shales of the Frederikshavn Formation may qualify as potential source rocks in parts of the basin. Neither of these potential source rocks has a basinwide distribution; the present occurrence of the Lower Jurassic shales was primarily determined by regional early Middle Jurassic uplift and erosion. The generation potential of these source rocks is highly variable. The F-III and F-IV members show significant lateral changes in generation capacity, the best-developed source rocks occurring in the basin centre. The combined F-III and F-IV members in the Haldager-1, Kvols-1 and Rønde-1 wells contain 'net source-rock' thicknesses (cumulative thickness of intervals with Hydrogen Index (HI)> 200 mg HC/g TOC) of 40 m, 83 m, and 92 m, respectively, displaying average HI values of 294, 369 and 404 mg HC/g TOC. The Mors-1 well contains 123 m of 'net source rock' with an average HI of 221 mg HC/g TOC. Parts of the Frederikshavn Formation possess a petroleum generation potential in the Hyllebjerg-1, Skagen-2, Voldum-1 and Terne-1 wells, the latter well containing a c. 160 m thick highly oil-prone interval with an average HI of 478 mg HC/g TOC and maximum HI values> 500 mg HC/g TOC. The source-rock evaluation suggests that a Mesozoic petroleum system is the most likely in the study area. Two primary plays are possible: (1) the Upper Triassic – lowermost Jurassic Gassum play, and (2) the Middle Jurassic Haldager Sand play. Potential trap structures are widely distributed in the basin, most commonly associated with the flanks of salt diapirs. The plays rely on charge from the Lower Jurassic (Toarcian) or uppermost Jurassic – lowermost Cretaceous shales. Both plays have been tested with negative results, however, and failure is typically attributed to insufficient maturation (burial depth) of the source rocks. This maturation question has been investigated by analysis of vitrinite reflectance data from the study area, corrected for post-Early Cretaceous uplift. A likely depth to the top of the oil window (vitrinite reflectance = 0.6%Ro) is c. 3050–3100 m based on regional coalification curves. The Frederikshavn Formation had not been buried to this depth prior to post-Early Cretaceous exhumation, and the potential source rocks of the formation are thermally immature in terms of hydrocarbon generation. The potential source rocks of the Fjerritslev Formation are generally immature to very early mature. Mature source rocks in the Danish part of the Norwegian–Danish Basin are thus dependent on local, deeper burial to reach the required thermal maturity for oil generation. Such potential kitchen areas with mature Fjerritslev Formation source rocks may occur in the central part of the study area (central–northern Jylland), and a few places offshore. These inferred petroleum kitchens are areally restricted, mainly associated with salt structures and local grabens (such as the Fjerritslev Trough and the Himmerland Graben).

A detailed geophysical mapping project has been carried out by the Geological Survey of Denmark and Greenland (GEUS) in the offshore region south-west and west of Disko and Nuussuaq, central West Greenland as part of the preparations for the Disko West Licensing Round in 2006 (Fig. 1). The main purpose of the study was to evaluate the prospectivity of this almost 100 000 km2 large region, and to increase knowledge of basin evolution and the structural development. Results of the work, including a new structural elements map of the region and highlights of particular interest for hydrocarbon exploration of this area, are summarised below. Evidence of live petroleum systems has been recognised in the onshore areas since the beginning of the 1990s when seeps of five different oil types were demonstrated (Bojesen-Koefoed et al. 1999). Oil seeps suggesting widely distributed marine source rocks of Mesozoic age are particularly promising for the exploration potential (Bojesen-Koefoed et al. 2004, 2007). Furthermore, possible DHIs (Direct Hydro carbon Indicators) such as gas-clouds, pock marks, bright spots and flat events have been interpreted in the offshore region (Skaarup et al. 2000; Gregersen & Bidstrup in press). The evaluation of the region (Fig. 1) is based on all public and proprietary seismic data together with public domainmagnetic and gravity data. The seismic data (a total of c. 28 000 line km) are tied to the two existing offshore exploration wells in the region (Hellefisk-1 and Ikermiut-1). The study also incorporates information on sediments and volcanic rocks from onshore Disko and Nuussuaq (Fig. 2). Ten seismic horizons ranging from ‘mid-Cretaceous’ to ‘Base Quaternary’ (Fig. 2) have been interpreted regionally. Large correlation distances to wells, varying data quality and a thick cover of basalt in the north-eastern part of the region, add uncertainty in the regional interpretation, especially for the deeper horizons such as the ‘mid-Cretaceous’ equivalent to Santonian sandstone interval drilled in Qulleq-1 far south. Based on the seismic interpretation (Fig. 3) structural elements maps, horizon-depth maps and isopach maps have been produced; these maps, together with general stratigraphic knowledge on potential reservoirs, seals and source rocks (Fig. 2), provide important information for discussions of critical play elements including kitchens and structures.The existence of many large structures combined with the evidence of live petroleum systems has spurred the recent major interest for hydrocarbon exploration in the region.

Although the structural framework of the subsurface offshore West Greenland has been well documented based on comprehensive seismic analysis (cf. Dalhoff et al. 2003), the stratigraphy of the region is less well known. The oldest documented sedimentary rocks drilled offshore West Greenland are Santonian sandstones reached at TD in the 6354/4-1 well (Fig. 1) although reworked palynomorphs of Carboniferous, Triassic and Jurassic (Kimmeridgian) age have been reported from a number of wells in the region. In order to obtain better constraints on the pre-Upper Cretaceous stratigraphy, a preliminary screening was undertaken to identify inversion structures and erosional canyons where such deeper stratigraphic levels crop out at the seabed (Nielsen et al. 2001). Sea-floor sampling at selected sites between 62° and 67°N (Fig. 1) was undertaken during the summers of 2003 and 2004. Other objectives of these cruises were to seek direct evidence of active petroleum systems, to establish further constraints on tectonic and stratigraphic models, and to obtain a better understanding of the Neogene and Pleistocene history of the region (Dalhoff et al. 2005). The most promising seabed features identified by Nielsen et al. (2001) were investigated in more detail using a wide range of techniques in order to optimise sampling positions. In 2003, these techniques included echo sounder, side-scan sonar, single-channel seismic and video inspection before sampling either by dredge, gravity corer, or by video-controlled grab. In 2004, comprehensive data acquisition with a deep-water sparker system was undertaken before sampling by dredge or gravity corer, supplemented by grab samples at selected stations.

Greenland petroleum geological activities at the Geological Survey of Denmark and Greenland (GEUS) during 2001 were focused mainly on the preparation of the 2002 licensing round offshore West Greenland. Promotion of the exploration opportunities in the licensing round area between 63° and 68°N has played an important role together with launching of new seismic and geological projects. Critical evaluation of the results from the Qulleq-1 well drilled in 2000 has continued in this context. The Statoil group relinquished the eastern subarea of the Fylla licence at the end of April 2000, making all the Qulleq-1 data available for promotion purposes (see Christiansen et al. 2001a). The entire remaining area was relinquished by the end of the year. However, as part of outstanding working commitments, the Statoil group acquired approximately 1000 km of new seismic data, mainly from the western part of the licence area. These data have proven to be of great interest for companies evaluating West Greenland. The Phillips group relinquished the entire Sisimiut-West licence area by the end of the year, without entering the next phase of exploration which called for a firm commitment well.

A project with the aim of amalgamating an interpretation of reflection seismic data from offshore southern West Greenland with a new interpretation of well data was finalised at the Geological Survey of Denmark and Greenland (GEUS) in 2001 (Chalmers et al. 2001b). As part of this study, seismic and depositional sequences between major regional unconformities of Danian and mid-Eocene age were delineated and dated. New palaeoenvironmental and sedimentological interpretations using dinoflagellate cyst, microfossil and nannoplankton stratigraphies and palaeoenvironmental interpretations from the five exploration wells drilled offshore West Greenland in the 1970s have been combined with a revised interpretation of lithology and correlated with the aid of seismic stratigraphy. The Qulleq-1 well drilled in 2000 was relinquished late in the project period (Christiansen et al. 2002, this volume), and it has therefore only been possible to incorporate biostratigraphic information from this well into the project.

The summer of 2000 was exciting for everyone interested in the petroleum geology and exploration of West Greenland. The first offshore well in more than 20 years was drilled by the Statoil group in the Fylla licence area, and seismic acquisition activity offshore West Greenland was more intense than previous years with four new surveys being carried out (Fig. 1). Expectations were high when drilling of the Qulleq-1 well was initiated in July 2000, not only with the licensees and the authorities, but also with the public. The well was classified as highly confidential, but nevertheless all information available was closely followed by the press, especially in Greenland and Denmark, but also internationally (see Ghexis 2000). Disappointment was equally high when the press release in September 2000 reported that the well was dry. Since that time much technical work has been carried out by Statoil and its consultants (Pegrum et al. 2001) and by the Geological Survey of Denmark and Greenland (GEUS), and a more balanced view of the positive and negative surprises from the well can now be presented.