Abstract An integrated tectonic and sequence stratigraphic analysis of the Cretaceous and Danian of the Danish Central Graben has led to significant new insights critical for our understanding of the chalk facies as a unique cool-water carbonate system, as well as for the evaluation of its potential remaining economic significance. A major regional unconformity in the middle of the Upper Cretaceous chalk has been dated as being of early Campanian age. It separates two distinctly different basin types: a thermal contraction early post-rift basin (Valanginian–Santonian), which was succeeded by an inversion tectonics-affected basin (Campanian–Danian). The infill patterns for these two basin types are dramatically different as a result of the changing influence of the tectonic, palaeoceanographic and eustatic controlling factors. Several new insights are reported for the Lower Cretaceous: a new depositional model for chalk deposition along the basin margins on shallow shelves, which impacts reservoir quality trends; recognition of a late Aptian long-lasting sea-level lowstand (which hosts lowstand sandstone reservoirs in other parts of the North Sea Basin); and, finally, the observation that Barremian–Aptian sequences can be correlated from the Boreal to the Tethyan domain. In contrast, the Late Cretaceous sedimentation patterns have a strong synsedimentary local tectonic overprint (inversion) that influenced palaeoceanography through the intensification of bottom currents and, as a result, the depositional facies. In this context, four different chalk depositional systems are distinguished in the Chalk Group, with specific palaeogeography, depositional features and sediment composition. The first formalization of the lithostratigraphic subdivision of the Chalk Group in the Danish Central Graben is proposed, as well as an addition to the Cromer Knoll Group.

Abstract We present a consistent synthesis of palaeothermal (apatite fission track analysis (AFTA) and vitrinite reflectance) data from UK Southern North Sea wells with the regional pattern of exhumation defined from sonic velocity data. Cenozoic exhumation across most of the region began in the Paleocene between 63 and 59 Ma. Amounts of removed section are around 1 km across the offshore platform, increasing to 2 km or more on the Sole Pit axis. Neogene exhumation within this area began between 22 and 15 Ma, and led to removal of up to 1 km of section. Along the eastern flank of the Sole Pit axis, sonic data define a pre-Chalk event, and AFTA data from these wells show that exhumation began between 120 and 93 Ma. This timing correlates with events defined from AFTA data in the Sorgenfrei–Tornquist Zone, further east, presumably reflecting a response to regional tectonic stresses. East of the Sole Pit axis, AFTA and sonic velocities suggest that Neogene exhumation dominates, while further east towards the central parts of the North Sea Mesozoic sediments appear to be at maximum burial today except for local effects related to salt movement. The multiple episodes of exhumation and burial defined here have important implications for exploration.

Abstract 3D basin and petroleum system modelling covering the NW German North Sea (Entenschnabel) was performed to reconstruct the thermal history, maturity and petroleum generation of three potential source rocks, namely the Namurian–Visean coals, the Lower Jurassic Posidonia Shale and the Upper Jurassic Hot Shale. Modelling results indicate that the NW study area did not experience the Late Jurassic heat flow peak of rifting as in the Central Graben. Therefore, two distinct heat flow histories are needed since the Late Jurassic to achieve a match between measured and calculated vitrinite reflection data. The Namurian–Visean source rocks entered the early oil window during the Late Carboniferous, and reached an overmature state in the Central Graben during the Late Jurassic. The oil-prone Posidonia Shale entered the main oil window in the Central Graben during the Late Jurassic. The deepest part of the Posidonia Shale reached the gas window in the Early Cretaceous, showing maximum transformation ratios of 97% at the present day. The Hot Shale source rock exhibits transformation ratios of up to 78% within the NW Entenschnabel and up to 20% within the Central Graben area. The existing gas field (A6-A) and oil shows in Chalk sediments of the Central Graben can be explained by our model.

Abstract The Mid North Sea High (MNSH) is located on the UKCS in quadrants 35–38 and 41–43. It is a large structural high that is flanked by the mature hydrocarbon provinces of the Central North Sea (CNS) to the NE and the Southern North Sea (SNS) to the SE. In the MNSH region, the source and reservoir intervals that characterize the SNS (Westphalian, Lower Permian) are absent and therefore the area is relatively underexplored compared to the SNS Basin ( c . one well per 1000 km 2 ). Nevertheless, two discoveries in Dinantian reservoirs (Breagh and Crosgan) prove that a working petroleum system is present, potentially charged either via lateral migration from the SNS or from within the lower Carboniferous itself. Additionally, gas was found in the Z2 carbonate (lower Zechstein Group) in Crosgan, with numerous other wells in the area reporting hydrocarbon shows in this unit. The results of the interpretation of recently acquired 2D and 3D seismic reflection datasets over parts of UKCS quadrants 36, 37 and 42 are presented and provide insight into both the geology and prospectivity of this frontier area. This study suggests that intra-Zechstein clinoform foresets represent an attractive, hitherto overlooked, exploration target. The Zechstein Group sits on a major unconformity, probably reflecting Variscan-related inversion and structural uplift. Below it, fault blocks and faulted folds occur, containing pre-Westphalian Carboniferous and Devonian sediments, both of which contain potential reservoirs. In the lower Zechstein, a large build-up is observed, covering a total area of 2284 km 2 . This is bounded on its margins by seismically defined clinoforms, with maximum thicknesses of 0.12 s two-way time ( c. 240–330 m). This rigid, near-tabular unit is clearly distinguished from the overlying deformed upper Zechstein evaporites. In map-view, a series of embayments and promontories are observed at the build-up margins. Borehole data and comparisons with nearby discoveries (e.g. Crosgan) suggest this build-up to represent a Z1–Z2 sulphate–carbonate platform, capped by a minor Z3 carbonate platform. Interpreted smaller pinnacle build-ups are observed away from the main bank. The seismic character, geometry, size and inferred composition of this newly described Zechstein platform are similar to those of platforms hosting notable hydrocarbon discoveries in other parts of the Southern Permian Basin. The closest of these discoveries to the study area is Crosgan, which is characterized by the Z2 carbonate clinothem (Hauptdolomit Formation) as a proven reservoir.

Abstract An improved understanding of the controls on reservoir quality is key to ongoing and future exploration of the Central North Sea Triassic play. This paper presents a regional integrated study of 50 000 ft of wireline log data, 10 000 ft of core, 4431 routine core analyses measurements and 377 thin sections from 86 cored wells. Triassic Skagerrak Formation sandstones represent thin-bedded heterogeneous reservoirs deposited in a dryland fluvial–lacustrine setting. Fluvial-channel facies are typically fine–medium grained and characterized by a low clay content, whilst lake-margin terminal splay facies are finer grained, more argillaceous and micaceous. Lacustrine intervals are mud-dominated. Primary depositional textures retain a primary control on porosity evolution through burial. Optimal reservoir quality occurs in aerially and stratigraphically restricted fluvial-channel tracts on the Drake, Greater Marnock, Puffin and Gannet terraces, and the J-Ridge area. These primary textural and compositional controls are overprinted by mechanical compaction, the development of early overpressure and diagenesis. Anomalously high porosities are retained at depth in fluvial sandstones that have a low degree of compaction and cementation, including chlorite. Forward modelling of reservoir quality using Touchstone™ software has been validated using well UK 30/8-3 where reservoir depths are >16 000 ft TVDSS (true vertical depth subsea).

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 More than 46 years of exploration in the Irish offshore has yielded modest commercial success. However, working petroleum systems have been proven in all the offshore basins. The pace of exploration has been controlled by: (a) data quality and technological advances; (b) geological understanding and plays; (c) fiscal and infrastructural environments; and (d) international conditions. Irish offshore exploration drilling started in the Celtic Sea basins in 1970 and the region has seen a recent renewal of exploration interest, stimulated by new and much improved seismic data. In the Atlantic margin basins west of Ireland, there has been a recent significant improvement in the understanding of the geological evolution and petroleum systems, especially in the hyperextended basins such as the Porcupine and Rockall basins. Here the major targets of current exploration are stratigraphic traps at Lower Cretaceous and Lower Cenozoic levels. The application of new and innovative seismic and other geophysical technologies in a number of the Irish offshore basins has led to significant enhancement in data quality and in resolving imaging challenges. Combined with recent geological learnings, they offer renewed hope for exploration success in the Irish offshore basins.

Abstract The exploratory drilling of 200 wildcat wells along the NE Atlantic margin has yielded 30 finds with total discovered resources of c. 4.1×10 9 barrels of oil equivalent (BOE). Exploration has been highly concentrated in specific regions. Only 32 of 144 quadrants have been drilled, with only one prolific province discovered – the Faroe–Shetland Basin, where 23 finds have resources totalling c. 3.7×10 9 BOE. Along the margin, the pattern of discoveries can best be assessed in terms of petroleum systems. The Faroe–Shetland finds belong to an Upper Jurassic petroleum system. On the east flank of the Rockall Basin, the Benbecula gas and the Dooish condensate/gas discoveries have proven the existence of a petroleum system of unknown source – probably Upper Jurassic. The Corrib gas field in the Slyne Basin is evidence of a Carboniferous petroleum system. The three finds in the northern Porcupine Basin are from Upper Jurassic source rocks; in the south, the Dunquin well (44/23-1) suggests the presence of a petroleum system there, but of unknown source. This pattern of petroleum systems can be explained by considering the distribution of Jurassic source rocks related to the break-up of Pangaea and marine inundations of the resulting basins. The prolific synrift marine Upper Jurassic source rock (of the Northern North Sea) was not developed throughout the pre-Atlantic Ocean break-up basin system west of Britain and Ireland. Instead, lacustrine–fluvio-deltaic–marginal marine shales of predominantly Late Jurassic age are the main source rocks and have generated oils throughout the region. The structural position, in particular relating to the subsequent Early Cretaceous hyperextension adjacent to the continental margin, is critical in determining where this Upper Jurassic petroleum system will be most effective.

Abstract The Porcupine Basin, part of the frontier petroleum exploration province west of Ireland, has an extended history that commenced prior to the opening of the North Atlantic Ocean. Lithospheric stretching factors have previously been estimated to increase from <2 in the north to >6 in the south of the basin. Thus, it is an ideal location to study the processes leading to hyper-extension on continental margins. The Porcupine Median Ridge (PMR) is located in the south of the basin and has been alternatively interpreted as a volcanic feature, a serpentinite mud diapir or a tilted block of continental crust. Each of these interpretations has different implications for the thermal history of the basin. We present results from travel-time tomographic modelling of two approximately 300 km-long wide-angle seismic profiles across the northern and southern parts of the basin. Our results show: (1) the geometry of the crust, with maximum crustal stretching factors of up to 6 and 10 along the northern and southern profiles, respectively; (2) asymmetry of the basin structures, suggesting some simple shear during extension; (3) low velocities beneath the Moho that could represent either partially serpentinized mantle or mafic under-plating; and (4) a possible igneous composition of the PMR.

Abstract The UK Rockall Basin is one of the most underexplored areas of the UK Continental Shelf (UKCS), with only 12 exploration wells drilled since 1980. With only one discovery made in 2000 (Benbecula (154/1-1) gas discovery), the general view of the basin from an exploration viewpoint is not positive. However, over the last 15 years, our knowledge of the petroleum systems of the Atlantic Margin has substantially increased. With the recent acquisition of new seismic data by the UK Government as part of the OGA's Frontiers Basin Research Programme, it is a pertinent time to re-examine the prospectivity of the UK Rockall Basin. This paper presents a history of exploration within the UK Rockall Basin, from the first well drilled in the basin in 1980, to the last well, drilled in 2006. We then present new insights into the lack of success during exploration within the basin, in particular by focusing on the extensive Early Cenozoic volcanic rocks within Rockall, to illustrate the wide range of potential interactions with the petroleum system. We also present evidence that points to the potential of a viable intra-basaltic (Rosebank) type play along the eastern flank of the Rockall Basin.

Abstract The margins of the North Atlantic rift are covered by an extensive succession of volcanic rocks, with up to 5 km of continental flood basalts, hyaloclastites and interbedded sedimentary rocks. The volcanic succession deteriorates seismic imaging and has hampered petroleum exploration in these areas. Focused research and pioneering exploration activity, however, has improved the understanding and development of new play models in volcanic-influenced basins. In 2004, the Rosebank discovery finally proved that intra-volcanic siliciclastic sandstones of the Flett Formation may form attractive hydrocarbon reservoirs in the Faroe–Shetland Basin. The Kangerlussuaq Basin in southern East Greenland offers a unique opportunity to study the interaction of siliciclastic sediments with lavas and various volcaniclastic units. It is demonstrated that: (1) laterally extensive siliciclastic sedimentary units are present in the lower part of the volcanic succession; (2) the morphology of the lavas controlled variations in sandstone geometry and thickness; and (3) deposition of the interbedded sediments and lavas occurred in a low-relief environment close to sea level. The mineralogical composition of the intra-volcanic sediments is highly variable, ranging from siliciclastic to purely volcaniclastic. Diagenetic studies suggest that the nature of the volcanic component in volcaniclastic sandstones is more important to reservoir properties than the relative concentration.

Abstract A new reservoir quality model is proposed for the Late Cretaceous Springar Formation sandstones of the Vøring Basin. Instead of a depth-related compactional control on reservoir quality, distinct high- and low-permeability trends are observed. Fan sequences which sit on the high-permeability trend are characterized by coarse-grained facies with a low matrix clay content. These facies represent the highest energy sandy turbidite facies within the depositional system, and were deposited in channelized or proximal lobe settings. Fan sequences on the low-permeability trend are characterized by their finer grain size and the presence of detrital clay, which has been diagenetically altered to a highly microporous, illitic, pore-filling clay. These fan sequences are interpreted to have been deposited in proximal–distal lobe environments. Original depositional facies determines the sorting, grain size and detrital clay content, and is the fundamental control on reservoir quality, as the illitization of detrital clay is the main mechanism for reductions in permeability. Core-scale depositional facies were linked to seismic-scale fan elements in order to better predict porosity and permeability within each fan system, allowing calibrated risking and ranking of prospects within the Springar Formation play.

Abstract We illustrate how the combination of both ‘backward-looking’ and ‘forward-looking’ perspectives serves as a powerful catalyst for profitable exploration. The phrase ‘backward-looking’ refers to a company's discipline to rapidly learn from their past performance. The process utilizes tracking predictive performance to focus on patterns from exploration parameter results relative to forecasts. The learnings are implemented through technology applications and improved forecasts that can lead ultimately to a more predictive (i.e. calibrated) portfolio. This discipline may be viewed as time-consuming, but is a critical part of the role of a professional. Often we observe that a calibrated state of accurately estimating the chance of success was achieved before a company reached a calibrated state of prospect pre-drill size prediction. The phrase ‘forward-looking’ here refers to a company's ability to conduct three tasks. First, exploration from a play perspective that quantifies candidate plays in a comparative sense. Second, integrate quantitative play analysis and an understanding of their risk-tolerance levels in order to build comprehensive models of how different plays can compete to best accomplish the goals of corporate strategy. Third, to apply the same discipline of unbiased, calibrated estimation to the characterization of prospects as they are technically matured to the drill-ready state.

Abstract The UK Oil & Gas Authority carried out post-well failure analyses of exploration and appraisal wells in the Moray Firth and the UK Central North Sea to fully understand the basis for drilling the prospects and the reasons why the prospects failed. The data consisted of Tertiary, Mesozoic and Palaeozoic targets/segments associated with 97 wells drilled from 2003 to 2013. Seal was the primary reason for failure followed by trap, reservoir and charge. Root causes for failure were a lack of lateral seal, the absence of the target reservoir and the lack of a trap. The main pre-drill risk was not accurately predicted in over one-third of the cases and a third of the segments were targeted on the basis of perceived Direct Hydrocarbon Indicators. This study identified a number of interpretation gaps and pitfalls that ultimately contributed to the well failures. These included poor integration, improper application of geophysics, lack of regional play context, and absent or ineffective peer review. Addressing these gaps in a comprehensive and systematic way is fundamental to improving exploration success rates.

Abstract In recent years, stratigraphic and combination traps such as Buzzard (UK North Sea) and Jubilee (Ghana) have attracted much industry attention. Such trap types are generally considered higher risk than structural traps, and understanding them represents a challenge for explorers, as numerous less successful (often amplitude-driven) attempts have demonstrated. Owing to their perceived high risk, stratigraphic traps are often drilled late in a basin's exploration history; however, we assert that consideration of stratigraphic traps should be part of any frontier exploration programme because they occur in all basin types and depositional settings, and allow new plays to be opened up. Additionally, stratigraphic, combination and sub-unconformity traps offer the chance to rejuvenate exploration in mature basins, as recent discoveries like the Edvard Grieg Field (Norwegian North Sea) have shown. Focusing on clastic systems, and using a combination of seismic examples and models, we present two aspects of stratigraphic trap exploration: (1) the regional and local factors that favour the development of stratigraphic trap edges; and (2) a systematic method for defining and risking the trap edges, avoiding the common problem of over-risking. These two methods, used together and applied consistently, allow explorers to focus on the right area of a basin and to risk stratigraphic traps appropriately, for a fair comparison with structural traps.

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 The Cygnus Field, operated by ENGIE E&P UK Limited, is located in UK Southern North Sea blocks 44/11 and 44/12. The reservoir comprises sandstones of the Permian Leman Sandstone Formation and Carboniferous Ketch Formation. Cygnus was first drilled in 1988 by well 44/12-1, which encountered gas shows in sandstones in the Leman Sandstone Formation whilst targeting a Carboniferous objective. The initial evaluation indicated the presence of poor-quality reservoir with conventional log analysis indicating high water saturations. Further appraisal activity ceased until 2002 when a group led by ENGIE E&P UK Limited were awarded the licence in the 20th round having recognized the missed pay potential. Through appraisal drilling, a second reservoir (the Carboniferous Ketch Formation) was discovered and the Leman Sandstone Formation was proven to be capable of achieving stabilized flow rates greater than 30 MMscf/d. The Cygnus discovery now proves that a northern-sourced Leman Sandstone Formation play fairway exists, establishing an extension of the Rotliegend play to the northern feather edge of the Southern Permian Basin. The Cygnus Field's estimated ultimate recoverable volume is forecast to be 760 Bscf, making it the largest field discovered in the UK Southern North Sea in the last 30 years.

Abstract The Bacchus Field, discovered in 2004, is a small borderline high-pressure–high-temperature (HPHT) oil field 6.8 km east of the Forties Alpha Platform. The reservoir is Fulmar Sandstone with a rotated fault-block trap. The reservoir is typically thin (10–50 m) and difficult to image seismically. Compartmentalization was anticipated due to significant in-field faulting. The Bacchus development decision was made when considerable geological uncertainty remained. The key risk-mitigation strategies employed during the development of Bacchus were to drill long horizontal wells, contacting multiple reservoir compartments, while maintaining a flexible development plan. The ability to react to unexpected results was facilitated by optimizing the development data-acquisition programme. Drilling risk and cost were minimized by exploiting existing well control for landing development wells, combined with pilot drilling in untested parts of the reservoir. Development wells were designed to be geometrically robust, minimizing the requirement for geo-steering. This ensured low wellbore tortuosity that did not compromise the completions. Bacchus was successfully developed despite the final distribution of reserves being radically different from the pre-development perception. It is argued that maintaining a flexible development plan was far more effective in maximizing the value of the Bacchus development than more extensive pre-development appraisal or modelling.