Up to the present, exploration of the UK Lower Cretaceous deep-water sandstone play has been confined largely to the Moray Firth basins. The Lower Cretaceous of the Central Graben area has been modelled previously as predominantly shale-prone, and hence unattractive to exploration. There is a growing realization that this may not be the case. Since seismic imaging of Lower Cretaceous sandstones is known to be poor whether hydrocarbon-bearing or water-wet, a robust depositional model must be constructed from well and regional geological data in order to predict sandstone distribution and geometry, and hence to aid identification of potential hydrocarbon traps. Of the hundreds of wells drilled in the Central Graben area that targeted deeper Jurassic-Triassic reservoirs, virtually all have been located on the flanks of the graben, or on intra-graben highs. However, 71 of these wells have proved sandstones or traces of sandstone within the Lower Cretaceous, giving grounds for optimism that more substantial deep-water sandstone developments may be present within the graben depocentres. Twenty-six leads have been identified within these depocentres; most of these are located within stratigraphic traps in interpreted detached basin floor fans.

This paper integrates interpretations of modern long-offset seismic datasets with potential field anomalies derived from dense grids of 2D gravity and magnetic data to present a regional-scale synthesis of Devonian, Carboniferous and Early Permian basin development beneath the UK Central North Sea. The 95 000 km2 study area has had little modern exploration for petroleum systems beneath the Upper Permian. Seismic interpretation and potential field modelling confirm that along the southern fringe of the Central North Sea, as in northern England, Lower Carboniferous basin development was strongly influenced by the disposition of granite-cored Lower Palaeozoic basement blocks – Farne Block, Dogger Block and Devil's Hole High. This study adds a previously unidentified WNW–ESE trending pre-Devonian basement block, the Auk–Flora Ridge, that exerted a profound control on Late Devonian to Mesozoic structural evolution of the south-Central North Sea. From the Flora Field, where it is overlain by relatively thick mid-Devonian to earliest Permian strata, the sub-Permian relief of this block becomes progressively shallower towards the NW. On its southern flank lies a parallel half-graben, akin to the Stainmore Trough in northern England, and interpreted as also containing several thousand feet of Lower Carboniferous strata. As indicated by the coal measures section in well 39/7-1, these strata are likely to include prolific source rocks, which have been modelled as being fully mature for oil generation in Quadrant 29. Potential field modelling extends this interpretation beyond the current seismic coverage, and suggests that Carboniferous to earliest Permian basin development in the Central North Sea was strongly influenced by an underlying Scottish–Norwegian SW–NE trending Caledonoid structural fabric. An earliest Permian, Lower Rotliegend unit thickens southwards towards the Auk–Flora Ridge, and rests unconformably on one or more undrilled NE–SW trending Carboniferous basins. Red-bed fluvial facies akin to those at Flora are likely to dominate the substantial post-Dinantian fill of these basins, but significant thicknesses of Westphalian coal-measure source rocks may also be present locally. As in central Scotland, the Dinantian strata underlying a widespread mid-Carboniferous unconformity in these basins are likely to contain further coal-measure intervals and local developments of oil-shale source rocks. These Westphalian and Dinantian source rocks are key elements of a Carboniferous petroleum system that remains largely untested across large areas of the Central North Sea.

The 40-yearhistory ofthe pre-Cretaceous high-pressure-high-temperature(HPHT)plays ofthe UK CNS isdescribed.The exploration andexploitation ofthisbasinhasbeenachieved byremarkabledevelopments inseismic, drillinganddevelopment technologies. Theseadvanceshaveprovided predictivegeologicalmodels to address significant multipleriske lements,a ndthe ability to drill andd evelop reservoirs safely inHPHT conditions withtemperaturesinexcess of3008 F, reservoirp ressuresexceeding10 000 psia ndsurface to reservoirpressuregradients inexcess of0.8psi/ft. UK ContinentalShelfexploration acreage wasfirst awarded in 1964inthe First Licence Round.Atthistimeseismic datadid not image the BaseCretaceous surface andearly drillingactivity focused on the Tertiary andon obvioussalt supported anticlinesormajor basement ridges. The subsequent periodfrom 1968-1972 sawthe discovery ofthe first hydrocarbons inthe pre-Cretaceous ingraben margins tructureso ro nm id-grabenhighs,b ut the deeperHPHT realm remained untested.Int he 1970s the discovery ofthe Auk, Argyll andFulmarFieldsestablished potentially significant plays aroundthe fringesofthe basin. However,e xploration for pre-Cretaceous reservoirs int he deeperp arts ofthe basinw hereH PHT conditions occurred faced significant operationalobstacles. Asthesewereovercomethe 1980s sawthe extension ofpre-Cretaceous plays into the HPHT realm,withdeep,high-quality reservoirs occurringatdepthsinexcess of 15000 feet. Thisexploration phaseresulted int he discovery ofsignificant reservesatt he Elgin,F ranklin, Shearwater,Jade andETAP fields. Throughoutthe exploration history ofthe CNS, the accurateprediction ofdeep reservoirdistribution andquality andtop sealintegrity haveb eencrucialt os uccess. Innovativeseismic technologieswill playakeypart inreducingthe remaininguncertaintiesintheseplayelements.