Abstract Carboniferous rocks within the Cumbria and northern Pennines region are bound by the Maryport-Stublick-Ninety Fathom Fault System, which forms the northern boundary of the Lake District and Alston blocks (Fig. 37). In the Pennines, the succession occupies the Alston and Askrigg blocks and the intervening Stainmore Trough, a broadly east-west trending graben. Carboniferous strata also flank the Lake District Block, occurring at outcrop in north Cumbria, Furness and Cartmel (south Cumbria) and the Vale of Eden, and in the subsurface in west Cumbria. The Askrigg Block succession is separated from that of the Craven Basin (Chapter 11), to the south, by the Craven Fault System. All of the stages of the Carboniferous, with the exception of the Stephanian, are present at outcrop. The oldest Tournaisian strata occur at outcrop along the flanks of the Lake District Block and within the Stainmore Trough. They are represented by continental and peritidal deposits (Ravenstonedale Group), and locally associated with volcanic rocks (Cockermouth Volcanic Formation of north Cumbria). The Ravenstonedale Group is diachronous, occurring later on the structural highs, with deposition during Chadian times on the Askrigg Block and Holkerian times on the Alston Block. The Ravenstonedale Group is overlain by upper Tournaisian to upper Visean platform carbonate rocks (Great Scar Limestone Group), which initially developed on the flanks of the Lake District Block, but by late Asbian times extended across the entire region (Mitchell 1978).

Abstract 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 km 2 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.

Abstract Organic-rich shale contains significant amounts of gas held within fractures and micropores and adsorbed onto organic matter. In the USA shale gas extracted from regionally extensive units such as the Barnett Shale currently accounts for 6% of gas production and is likely to reach 30% by 2015. Shale gas prospectivity is controlled by the amount and type of organic matter held in the shale, its thermal maturity, burial history, microporosity and fracture spacing and orientation. Potential targets range in age from Cambrian to the late Jurassic, within the main UK organic-rich black shales: younger shales have been excluded because they have not reached the gas window, but they may possess a biogenic gas play. A geographic information system, showing the distribution of potential reservoir units, has been created combining information on hydrocarbon shows, thermal maturity, fracture orientation, gas composition, and isotope data to identify potentially prospective areas for shale gas. Some of these data are shown as graphs and maps, but crucial data is lacking because earlier exploration concentrated on conventional reservoirs. The prospects include Lower Palaeozoic shale basins on the Midland Microcraton (a high risk because no conventional gas has been proved in this play), Mississippian shales in the Pennine Basin (the best prospect associated with conventional fields and high maturity), Pennsylvanian shales in the Stainmore and Northumberland Basin system (high risk because no conventional gas discoveries exist) and Jurassic shales in Wessex and Weald basins (small conventional fields signify potential here).