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Most of the potential sandstone reservoirs within the Namurian and lower Westphalian succession of the Southern North Sea Basin are originally feldspathic sands in which the feldspar has mainly been altered to microporous kaolinite clays. The sandstones provide a moderate porosity (typically 8‐15%, depending mainly on grain size), but permeability is severely limited owing to the microporous nature of much of the porosity. Permeability is typically 1 mD or less, rising to a few tens of millidarcies in occasional coarse‐ and very coarse‐grained sands. Predicting the presence of higher‐permeability reservoir zones is therefore a critical exploration problem in these successions. Quartzitic sands have been discovered in places, especially for example in the Trent field (block 43/24), where physical reworking of sands during the transgressions that preceded the deposition of marine bands removed much of the feldspar, so that less clay was formed during burial diagenesis. Although these sandstones display moderately elevated permeabilities, commonly several to several tens of millidarcies, they are usually fine‐grained, which limits their reservoir potential. A particular type of quartzitic sandstone reservoir has been identified quite widely within the Namurian and lower Westphalian succession of the Southern North Sea. This type is indistinguishable in terms of sedimentology and inferred detrital composition from the originally feldspathic facies which now form the widespread kaolinite‐rich, low‐permeability sandstones. However, it has a very low kaolinite content (commonly 1‐2%, compared with a more usual 5‐20%) so that these sandstones display permeabilities of the order of several hundred millidarcies. Wireline log data from nineteen wells within UK Quadrants 43 and 44 have been examined, and all relevant core logged in order to compare the depositional settings of the quartzitic and non‐quartzitic sandstones. Existing data from over 500 petrographic thin sections from the area have been reviewed and 78 new thin sections analysed to determine the petrographic controls on reservoir quality in both sandstone types. The diagenetic histories of each type have been interpreted. The dissolution of feldspars during diagenesis of the quartzitic sandstones, without a substantial residue of kaolinite or other aluminium‐rich mineral, is attributed to the mobilisation of aluminium within organic complexes. This is thought to require the presence of certain organic acids. [ABSTRACT FROM AUTHOR]

Nine Mesozoic and Cenozoic palaeogeographic maps are presented to illustrate the petroleum prospectivity of the South Caucasus from a fresh perspective and as part of the wider Caucasus region. Previously, elements of petroleum systems – reservoir, source and sealing lithologies, and the timing of their formation – have mostly been examined within individual sub‐basins or licence blocks, and regional understanding has been limited. Emphasis is placed here on the onshore prospectivity of Georgia and Azerbaijan; the well‐known Pliocene Productive Series of eastern Azerbaijan and the southern Caspian is not considered. The Great Caucasus Basin (GCB) formed in the Early Jurassic following closure of PalaeoTethys, and remained a significant feature, despite structural modifications, until end‐Eocene underthrusting and uplift converted the basin into the Greater Caucasus mountains. By the Toarcian a major delta system had developed along its northeastern margin, while the Transcaucasus block to the south was mostly covered by a shallow sea with limited sediment supply. Bajocian volcanism across the South Caucasus was accompanied by modification of the structure of the Great Caucasus Basin with the intrusion of tholeiitic dykes, possibly associated with onset of northward NeoTethyan subduction. Rising sea levels led to the abandonment of the GCB delta system. Relative uplift of the South Caucasus in the Bathonian created lowlands surrounded by marginal settings in which paralic deposits and coals were laid down. Jurassic hydrocarbon source rocks include deep‐marine shales deposited within the Great Caucasus Basin together with coals; their potential is confirmed by numerous seeps within both Georgia and Azerbaijan. Various Middle Jurassic sandstones are potential reservoirs. Carbonates dominated by the late Callovian, with widespread development of Oxfordian reefs and of Late Jurassic evaporite basins in the North Caucasus. Bedded anhydrites in Georgia comprise potential seals. Shallow‐marine clastics again became widespread across the Caucasus in the Cretaceous, later replaced by carbonates including chalk‐like limestones. Deeper‐marine conditions persisted in the Great Caucasus Basin, which became less well‐defined and split into separate depocentres. Fractured chalks are known reservoirs in the North Caucasus and prospective reservoirs in the South Caucasus. Uplift of the southern South Caucasus during the Paleogene led to northward transport of sediment into evolving E‐W to ESE‐WSW basins in eastern Georgia and western Azerbaijan. Marine deposits within these basins form reservoirs, including thick fractured volcanogenic turbidites in eastern Georgia. Reduced sediment supply here at the start of the Late Eocene allowed organic‐rich restricted‐marine source rocks to accumulate. Rapid uplift of the GCB associated with underthrusting at the end of the Eocene led to emergence of the Greater Caucasus mountains. The prolific Maikopian source rocks were deposited in restricted‐marine conditions during the Oligocene and Early Miocene over the North Caucasus, parts of Azerbaijan and western Georgia, but they are diluted by coarser clastics in eastern Georgia where the Late Eocene source is more significant. Later Miocene uplift of the entire Caucasus region resulted in progressive marine regression, and the formation of potential reservoirs in alluvial and shallow‐marine sands. [ABSTRACT FROM AUTHOR]

Exploration efforts around the Greater Caucasus region started towards the end of the 19th century and established a wide range of petroleum play types in various basin segments around the orogen. All these plays are associated with the flanks of the inverted thrust‐fold belt and the adjacent foreland basin systems, but display significant variation among the basin segments depending on the tectonostratigraphic units involved and the degree of exploration maturity. Whereas the same main source rocks have generated most of the hydrocarbons in all the basins (namely organic‐rich shales in the Oligocene – Lower Miocene Maykop Group and the Eocene Kuma Formation), it is primarily the trapping style, both proven and speculative, which is responsible for the broad spectrum of play types observed. Eleven play type diagrams across six main petroleum provinces of the Greater Caucasus region are presented in this paper and summarize the current exploration understanding of the existing discoveries and potential new play targets. These play cartoons offer a prospect‐scale summary of both mature producing and underexplored basin segments in a coherent visual manner, and are therefore intended to promote future exploration efforts in the Caucasus region. The testing of new play types requires the proper risking of the two most critical elements in the region: hydrocarbon kitchen effectiveness, and post‐charge trap modification. The de‐risking of these factors will require properly designed, fit‐for‐purpose acquisition of modern geological and geophysical data sets. [ABSTRACT FROM AUTHOR]