Abstract The NE Atlantic volcanic rifted margins include vast underexplored basin areas neighbouring mature petroleum-producing regions. We appraise the cross-border prospectivity of the outer and central Faroe–Shetland, Møre and southern Vøring basins and present insights from extensive new 3D seismic surveys. Regional seismic surfaces are used to compile a cross-border seismic profile highlighting key discoveries from the UK Rosebank field in the SW to the Norwegian Ormen Lange field in the NE. Cretaceous to Paleocene reservoirs remain the main exploration focus seaward of the platform areas, and the presence of several large untested structures presents important exploration targets in the mid-Norway region. Improved imaging of the areas affected by Paleogene igneous rocks reveals major untested sub-basalt structures including some regions on the marginal highs where the basalt cover has been entirely removed by erosion, revealing sub-basalt stratigraphy and structures with pre-Cretaceous potential prospectivity. The influence of igneous rocks on both discovered and prospective hydrocarbon systems is discussed. Neogene sand injectite fields and Quaternary glacial sand bodies are extremely well imaged in the Møre Basin, documenting shallow prospectivity supported by the presence of successful regional analogue plays. New 3D seismic data are revealing previously unseen prospectivity in frontier and underexplored regions.

Abstract Onshore exposures of the North Atlantic Igneous Province have been studied in detail for over 200 years, whereas the more extensive offshore volcanic stratigraphy is significantly less well constrained with the exception of a small number of boreholes. Within this study we integrate seismic and well data across the northern Faroe–Shetland Basin and Møre Marginal High to improve understanding of the volcanic stratigraphy and its relationship to rifting in the NE Atlantic. Volcanic seismic facies, including compound and tabular lavas and hyaloclastites (representing subaerial and subaqueous emplacement), are interpreted across the study area, calibrated by the Lagavulin borehole. The volcanic sequence was erupted between c. 56.1 and 55.2 Ma, when subaerial conditions dominated in the region, but extensive lava deltas developed in a seaway east of the main lava field. Geochemical and thickness variations within the volcanic pile have important implications for the regional rifting history. MORB-like lavas at the base of Lagavulin, which thicken substantially northward, support an early onset of rifting near the Møre Marginal High prior to major thinning associated with continental breakup to the south and north. Following a period of erosion, smaller-degree melting caused the eruption of higher-TiO 2 /Zr lavas, marking the final ‘pre-breakup’ volcanism before emplacement of seaward-dipping reflectors.

Abstract Exploration drilling activity, discovery history and creaming curves in the offshore UK are analysed for each UK Continental Shelf (UKCS) basin and each play in the North Sea from the earliest wells drilled in 1965 until the end of 2017. Around 52 Bboe of commercially recoverable oil and gas has been discovered, with around half of this volume found in the first 10 years of exploration. UKCS exploration plays are generally at a mature or super-mature stage and the exploration challenges reflect this. Although technical success rates have steadily increased since the 1990s, pool sizes are becoming smaller. In the last 10 years the average commercial discovery size has been 27 MMboe recoverable, and since 2010 only 10% of discoveries have been bigger than 43 MMboe recoverable. The UK Oil and Gas Authority's 6 Bboe mid-case yet-to-find estimate, as published in 2018, would take 40 years to unlock at the current rate of discovery. Future exploration in the mature UKCS is intertwined with prolonging the life of production infrastructure and is increasingly dependent on the development of new low-cost development concepts. Increased focus on the search for subtle traps, and more reliable pre-drill risk and volume estimation through improved benchmarking and calibration will be key to future exploration success.

Abstract The Clair Field is a giant oilfield containing in the region of 6–7 Bbbl of stock tank oil initially in place, located approximately 75 km west of the Shetland Islands. As such, it represents the single biggest hydrocarbon accumulation on the UK Continental Shelf. Clair was discovered in 1977, but first production did not occur from Phase 1 until 2005, after a lengthy appraisal period. The major appraisal milestone occurred in 1991 after well 206/8-8 proved up fractured clastic red beds of the Devonian Lower Clair Group. This was followed up with an extended well test on 206/8-10Z, which demonstrated the longer-term performance of the reservoir. Further appraisal on Clair Ridge led to the sanction of the Clair Ridge, which came on stream in November 2018. Following the Greater Clair appraisal programme in 2013–15, development options are currently being worked for Clair South, which will develop the Lower Clair Group reservoirs together with overlying shallow-marine reservoirs of the Cretaceous and Jurassic.

Abstract The Edradour Field, located in Licence P1453 on Block 206/4a of the Faroe–Shetland Basin, was put on production in August 2017. It lies c. 50 km NW of the Shetland Islands in a water depth of c. 300 m, and consists of one subsea well that produces gas condensate from the Albian Black Sail Member of the Commodore Formation. It is part of a joint development scheme along with the Glenlivet Field that sees the commingled multiphase production transported to the Shetland Gas Plant via tieback to the pre-existing Laggan–Tormore flowlines. The Edradour single well development has reserves of 21 MMboe from a gas initially-in-place of 142 bcf. It is operated by Total E&P UK Ltd under the P1453 licence with Ineos E&P (UK) Ltd and SSE E&P UK Ltd as partners.

Abstract The Glenlivet Field, located in Block 214/30a within the Faroe–Shetland Basin, was put on production in August 2017. It lies approximately 70 km NW of the Shetland Islands, in a water depth of c. 440 m. The development consists of two subsea wells that produce gas condensate from the Paleocene Vaila Formation, which comprises deep-water turbidite deposits with excellent petrophysical properties. It is part of a joint development scheme along with the Edradour Field that sees the commingled multiphase production transported to the Shetland Gas Plant via tie-back to the pre-existing Laggan–Tormore flowlines. Glenlivet is operated by Total E&P UK Ltd under the P1195 licence since September 2014 with Ineos E&P (UK) Ltd and SSE E&P UK Ltd as partners.

Abstract The Laggan and Tormore fields are found within the Flett sub-basin of the Faroe–Shetland Basin. Situated 120 km west of the Shetland Islands in 600 m water depth, they are part of the deepest subsea development in the UK to date with a 143 km subsea tie-back to onshore facilities. The reservoirs are found within the T35 biostratigraphic sequence of the Paleocene Vaila Formation and comprise sand-rich turbiditic channelized lobes with good reservoir properties, separated by metric to decimetric shale packages. Laggan is a gas-condensate field, whereas Tormore fluid is a richer gas with a saturated oil rim. Seismic reservoir characterization is a key to the field development where differentiation of fluid type proved challenging. Both fields came on stream in 2016 as part of the Greater Laggan area development scheme.

Abstract The Rosebank Field is located primarily in Block 213/27a in the Faroe–Shetland Basin, c. 130 km west of the Shetland Islands in water depths of c. 1100 m (3600 ft). Hydrocarbons are trapped within an elongate, SW–NE-trending four-way anticlinal structure. The principal Colsay Sandstone Member reservoir consists of several vertically stacked, Late Paleocene to Early Eocene fluvial and deltaic reservoirs separated by volcanic sequences. Well log and core data indicate that reservoir quality is high, with porosities in the range of 19–23% and average permeability of c. 3 D. Oil quality is also high, with average oil gravity of 37°API and in-situ viscosity of c. 1 cP at a mean reservoir temperature of 175°F. The field holds a substantial resource and is currently under evaluation for development.

Abstract The Schiehallion subsea development comprises two fields, Schiehallion and Loyal, which are located approximately 200 km to the west of the Shetland Islands in the UK Continental Shelf. The Schiehallion and Loyal fields were discovered in late 1993 and 1994, respectively, with a combined oil-in-place of more than 2.3 Bbbl. The fields are developed under waterflood and were on production from 1998 to 2013. After an extended shut-in, the fields were brought back on line in 2017, through new floating production facilities. Most of the production to date has been from the Paleocene Vaila Formation deep-water turbidite, in the T31 and T34 reservoir intervals. The ongoing Quad 204 redevelopment drilling programme commenced in April 2015, has drilled and completed 21 wells to date, and is expected to continue for several more years. The campaign includes new producer–injector pairs and stand-alone wells to support existing well stock, targeting stacked turbidite reservoir intervals, including the youngest T35–T34 interval, the main T31 interval and the previously under-developed T28–T25 fairway. In addition to an active drilling programme, a 4D seismic survey was acquired and processed in 2018, and its interpretation is key to unlocking further potential sources of value in this mature field.