We integrate observations of lithospheric extension over a wide range of spatial and temporal scales within the northern North Sea basin and critically review the extent to which existing theories of lithospheric deformation can account for these observations. Data obtained through a prolonged periodofhydrocarbon exploration and production has yielded a dense and diverse data set over the entire Viking Graben and its anking platform areas. These data show how syn-rift accommodation within the basin varied in space and time with sub-kilometer-scale spatial resolution and a temporal resolution of 2{3 Myr. Regional interpretations of 2D seismic re ection, refraction and gravity data for this area have also been published and provide an image of total basin wide stretching for the entire crust. These image data are combined with published strain rate inversion results obtained from tectonic subsidence patterns to constrain the spatio-temporal evolution of strain accumulation throughout the lithosphere during the 40 Myr (170{130 Ma) period of Late Jurassic extension across this basin. For the rst 25{30 Myr, strain localisation dominated basin development with strain rates at the eventual rift axis increasing while strain rates over the anking areas declined. As strain rates across the whole basin were consistently very low (< 3x10 ;16 s ;1 ), thermally induced strength loss can not explain this phenomenon. The strain localisation is manifest in the near-surface by a systematic migration of fault activity. The pattern and timing of this migration are inconsistent with exural bending stresses exerting an underlying control, especially when estimates of exural rigidity for this area are Preprint submitted to Elsevier Science 31 January 2005 considered. The best explanation for what is observed in this time period is a coupling between near-surface strain localisation, driven by brittle (or plastic) failure, and the evolving thermal structure of the lithosphere. We demonstrate this process using a continuum mechanics model for normal fault growth that incorporates the strain rate-dependence of frictional strength observed in laboratory studies. During the nal 10 Myr of basin formation, strain accumulation was focused within the axis and strain rates declined rapidly. Replacement of weak crust by stronger mantle material plus crustal buoyancy forces can adequately explain this decline.

Seismic mapping of the Faroe–Shetland Basin from three-dimensional surveys provides striking evidence for uplift of the southern Faroe–Shetland Basin in the late Palaeocene and rapid subsidence in the early Eocene. The seismic reflector at the base of the Balder Formation follows a regional unconformity surface, which records erosion of a major branching drainage network into the underlying Palaeocene section, following a major base level fall. The topography of this surface was subsequently in-filled following marine transgression, and deep-water conditions returned to the basin in the early Eocene. We attribute base level changes to the influence of the proto-Iceland mantle plume beneath the lithosphere, providing support until continental break-up west of the Faroe Islands.

The Nelson Field has been in production since 1994 and is at the mid-mature stage of field life. The current management strategy has focussed on identifying infill well locations with the aim of recovering bypassed oil. An increasingly detailed reservoir description is required in order to locate these opportunities and to help screen them for their economic viability. A systematic workflow has been followed through to localize those areas of the Nelson Field where the target oil volumes are most likely to be found. This workflow is given the name ‘locate the remaining oil’ within Shell. The aim of this workflow is to understand the relationship between sweep and the geological framework of the reservoir. On this basis, drainage cells are defined within the reservoir. Rather than behaving as a single ‘tank’ of oil with a common rising oil–water contact, the Nelson Field produces from nine discrete drainage volumes, each with separate producing oil–water contacts. The drainage cells have been defined on the basis of sedimentology, oil and water geochemistry in combination with quantitative volumetric analysis. Screening of the nine drainage cells in the reservoir has identified four cells that contain significant remaining volumes of mobile oil. These have then been investigated in further detail with a view to locating any stranded oil volumes that are unlikely to be produced by the existing well stock, and to determine if these are large enough to justify infill well drilling.

Drainage cells are localized reservoir volumes that are bounded both laterally and vertically by permeability barriers. The subdivision of a reservoir volume into drainage cells provides a framework that allows a mature producing field to be screened for remaining oil volumes. Nine drainage cells have been defined in the Nelson field. The lateral edges of these drainage cells are stratigraphic in nature and correspond to the boundaries between individual macroforms, for instance, between channel complexes and interchannel sediments.A very large dataset of produced water chemical analyses has been used to help define the extent of the drainage cells. Provinciality, shown by areal variations in produced water compositions, is consistent with the inferred location of the cells. The Nelson field shows variation in the chloride ion concentration of produced water both vertically and laterally. Vertical variation can be detected by changes in produced water chemistry after water shut-off events at shale horizons which are thought to be laterally extensive within the reservoir. Lateral variation corresponds to patchwork areas that are consistent with individual macroforms such as channel complexes.An additional technique has been used to confirm the location and extent of drainage cells within the field. This involves the compilation of drainage charts, a quantitative volumetric method that involves comparing theoretical and actual oil–water contact changes within particular field areas.

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