Abstract Much of the future hydrocarbon exploration potential in the North Sea lies in locating stratigraphic traps and discrete reservoir intervals. This study assesses the potential for Lower Cretaceous reservoirs, with particular focus on the Norwegian Central Graben and methods to identify future prospects over a wider area. Seismic interpretation and well data reveal the structure and sedimentology of the study area. Although the region was isolated from a large hinterland in the Early Cretaceous, potential local sediment sources, sediment transport routes and areas with possible reservoir development are identified. The greater Mandal High area, where Lower Cretaceous shoreface deposits and submarine fan systems are postulated, is suggested for primary focus. Similar deposits may have developed around the other exposed highs in the region, although several were drowned towards the end of the Early Cretaceous. Detailed seismic and stratigraphic analysis will be necessary to identify individual reservoir units. Since comparable settings may have occurred in the adjacent South Viking Graben and Southern Permian Basin regions during the Early Cretaceous, further reservoir assessment is recommended for the North Sea in general.

Abstract Paleocene deep-water deposits of the Norwegian sector of the North Sea Basin are prospective for oil and gas, although little is known about their sedimentology and distribution, or the controls on their stratigraphic evolution. To help unlock the potential of this poorly explored interval, we integrate 3D seismic reflection, well logs and core data from the eastern North Viking Graben, offshore Norway. We show that thick (up to 80 m), high net to gross (N:G) (up to 90%), sandstone-rich channel-fills and sheet-like, likely lobe deposits occur on the slope–proximal basin floor, forming part of an aerially extensive fan system. Sediment dispersal and the resultant stratigraphic architecture are controlled by slope morphology. Bypass occurred on the northern, passive margin-type slope; whereas, in the south, sediment gravity currents were deflected around, and deep-water sandstones onlap and pinch-out onto an exposed rift-related fault block that generated intra-basin bathymetric relief. Pinchout of deep-water sandstone into mudstone suggests that future exploration should focus on identifying subtle stratigraphic traps on fault block flanks or at the fan fringe. This trapping style contrasts with that encountered in the UK sector of the Northern North Sea, where most Paleocene fields and discoveries are in structural traps related to the flow of Zechstein Supergroup salt.

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: A branch line is the line of intersection between two hard-linked fault planes, or between two parts of a single fault plane of more complex geometry. Of interest is whether they provide any information about the kinematic development of the fault system to which they belong. Analysis of branch lines from a variety of normal fault networks, interpreted on seismic reflection datasets, shows that the branch lines are generally aligned parallel to the extension direction. This relationship is shown to be a feature of polymodal (orthorhombic) fault systems produced by three-dimensional strain. Branch lines between bimodal faults (conjugate, with opposing dip) tend to be perpendicular to the slip direction.