Abstract Located 160 km NE of the Shetland Islands in the East Shetland Basin, the Dunlin Cluster comprises four produced fields, Dunlin, Dunlin SW, Osprey and Merlin, in addition to some near-field satellite discoveries, Skye and Block 6. Dunlin was discovered in July 1973 and production began in August 1978. The field was developed using a concrete gravity-base platform, Dunlin Alpha, which also served as the production facility for the rest of the Dunlin Cluster. Osprey was discovered in 1974 but not tied-in until January 1991. Dunlin SW was discovered in 1973 but not brought onto production until 1996. Merlin was discovered in February 1997 and tied-in later that same year. Fairfield Energy acquired the Dunlin Cluster in 2008, and a programme of investment and facilities improvements, primarily in fuel gas infrastructure and power generation, sought to boost water-injection rates and bolster production, thereby extending the life of the asset. Ultimately, the Dunlin Cluster ceased production on 15 June 2015 after having maximized economic hydrocarbon recovery. The total Dunlin Cluster production exceeded 500 MMbbl of oil (Dunlin and Dunlin SW, 395 MMbbl oil; Osprey, 92 MMbbl oil; and Merlin, 27 MMbbl oil).

Abstract The Statfjord Field, the largest oil field in the Northern North Sea, straddles the Norway/UK boundary and is located on the southwestern part of the Tampen Spur within the East Shetland Basin. The accumulation is trapped in a 6-8° W-NW dipping rotated fault block comprised of Jurassic-Triassic strata sealed by Middle to Upper Jurassic and Cretaceous shales. Reserves are located in three separate reservoirs: Middle Jurassic deltaic sediments of the Brent Group, Lower Jurassic marine-shelf sandstones and siltstones of the Dunlin Group; and Upper Triassic-lowermost Jurassic fluviatile sediments of the Statfjord Formation. The majority of reserves are contained within the Brent Group; and Statfjord Formation sediments which exhibit good to excellent reservoir properties with porosities ranging from 20-30% permeabilities ranging up to several darcies, and an average net-to-gross of 60-75%. The sandstones and siltstones of the Dunlin Group have poorer reservoir properties where the best reservoir unit exhibits an average porosity of 22%, an average permeability 300mD and net-to-gross of 45%. Structurally, the field is subdivided into a main field area characterized by relatively undeformed W-NW dipping strata, and a heavily deformed east flank area characterized by several phases of ‘eastward’ gravitational collapse. Production from the field commenced in 1979 and as of January 2000, 176 wells have been drilled. The oil is undersaturated and no natural gas-cap is present. The drainage strategy has been to develop the Brent and Dunlin Group reservoir with pressure maintenance using water injection and the Statfjord Formation reservoir by miscible gas flood. However, a strategy to improve recovery by implementing water alternating gas (WAG) methods is gradually being implemented for both the Brent and Statfjord reservoirs. Current estimates indicate that by 2015 a total of 666 x 10 6 Sm 3 (4192 MMBBL) of oil will be recovered and 75GSm 3 (2.66 TCF) gas will be exported from the field.

Abstract The Dunbar, Ellon and Grant oil and gas fields (also known as the Alwyn South area) are located in the southeastern part of the East Shetland Basin, approximately 140 km E of the Shetland Islands. Most of the accumulations lie in Blocks 3/9, 3/14 and 3/15, which are parts of Licence P090 operated by Total Oil Marine plc (33.33%) with Elf Exploration UK PLC as sole partner (66.67%). Ellon was discovered in 1972, Dunbar in 1973 and Grant in 1977. Dunbar consists of a number of generally N-S trending, westerly dipping Mesozoic fault blocks with variable amounts of crestal erosion. Reservoir is provided by fluvial, deltaic and shallow marine sandstones of the Middle Jurassic Brent Group, Lower Jurassic Statfjord Formation and Upper Triassic Upper Lunde Formation. The Brent oil composition of Dunbar varies with depth and evolves from volatile oil at the base of the column to gas condensate at the top without a discontinuity of composition. In addition there is a small gas accumulation within a Paleocene submarine fan reservoir in a compactional structure. Ellon consists of two westerly dipping fault blocks with gas condensate contained within the Brent Group. Grant is one westerly dipping fault block with gas condensate in the Brent Group. In both the Ellon panels and also in Grant, thin waxy oil ‘rims’ are found below the gas. The depth of the shallowest structural crest within the Alwyn South complex is 3100m TVDSS, with the deepest proven hydrocarbon at around 3800m TVDSS. Sealing for the Alwyn South accumulations is provided by various combinations of Cretaceous, Upper Jurassic (Heather and Kimmeridge Clay Formations) and Lower Jurassic (Dunlin Group) mudstones. The source rock for the hydrocarbons is the Upper Jurassic Kimmeridge Clay Formation, which is mature and adjacent to the fields. These accumulations are being developed from a tender-assisted minimally manned fixed platform with a total of 28 well slots located over the Dunbar Field, in a water depth of 145 m. The Ellon and Grant Fields are produced as sub-sea satellites to Dunbar from a well-head cluster located between Ellon and Grant, in a water depth of 135 m. First oil and gas production from Dunbar and Ellon was in December 1994 and gas production commenced from Grant in July 1998. The time lag between discovery and development reflects the complex geology (structure, compartmentalization, reservoir thickness variations, diagenesis and differing hydrocarbon compositions) with a total of 28 exploration and appraisal wells being drilled in the Alwyn South area between 1971 and 1998. Total oil and gas initially in place is in the order of 850 MMBBL and 2.62 TCF respectively, with the current estimate for ultimate recoverable reserves being 200 MMBBL liquids and 1.28 TCF gas.

Abstract The Penguins Cluster is a group of four oil and gas fields in the northern end of the East Shetland Basin. Its structural complexity is caused by the interaction between two or more fault trend populations, fault reactivation and the impact of faulting on the Brent reservoir architecture. This structural picture is further complicated by a NW–SE trending basement lineament interpreted as a Caledonian shear zone. The present day structural configuration is the result of two Mesozoic rifting episodes and their associated thermal subsidence phases. The Permo-Triassic rifting created a number of north–south-trending tilted fault blocks, and was followed by a period of tectonic quiescence until the Middle Jurassic, when a faulting episode coeval with the Brent Group deposition caused footwall rotation, uplift and erosion of the upper Rannoch Formation prior to the deposition of the Etive Formation across the area. The rifting climaxed in the late Jurassic, when the reactivation of pre-existing faults under oblique-slip conditions in the Penguin C Field created small-scale lozenge-shaped transpressional and transtensional fault blocks. The presence of reverse faults in the area is explained with a continuous kinematic model of structural evolution and oblique-slip fault reactivation rather than positive basin inversion.