Abstract The Gryphon Field was discovered in 1987 in Quadrant 9 in the Beryl Embayment. Oil was encountered in a thick Balder Formation sandstone, and the reservoir was interpreted as lobes of a submarine fan system, such as many of the prolific early Tertiary fields in the North Sea. After an extensive appraisal phase, oil production started in 1993 through the Gryphon floating production, storage and offloading vessel. After a successful initial development phase, the integration of production data, improved and regularly acquired seismic data, and a better geological understanding resulted in the identification of sandstone intrusions. These have since been interpreted to form a volumetrically significant part of the Gryphon reservoir. The drilling of further infill wells, and the development of satellite fields Maclure, Tullich and the future Ballindalloch, ensued from this change to the geological model. To date, the Gryphon, Maclure and Tullich fields have produced more than 200 MMbbl of oil compared to an initial reserve estimate of 151 MMbbl. Although the current and mid-term focus remains on maximizing oil production, the final phase of the wider Gryphon area fields’ development should see the production of the regional gas cap.

Abstract The Beryl Field is one of the largest oil fields in the UK Continental Shelf. Mobil commenced production in 1976 via the Beryl Alpha platform. Production peaked at approximately 200 000 BOE/day in 1993 before declining to around 50 000 BOE/day in 2012. Apache assumed operatorship in 2012 and, along with partners Shell, has arrested and reversed production decline on platform production through investment in 3D seismic data, drilling, workovers and improvements to operational efficiency. Redevelopment to date by the Beryl area partnership has focused on strategic wells across multiple play types and fields. These wells have realized an 88% success rate and have led to the delineation of additional, lower risk, drill locations. Drilling flexibility, a deep target inventory and effective partner relationships help to expedite the most valuable opportunities and maintain the drilling campaign. In the future, production growth is anticipated through cost-effective developments of new and existing near-field opportunities, including the recently discovered Callater Field with first oil planned in 2017. Three case studies will illustrate: the importance of structural compartmentalization in under-developed fields; the opportunities remaining in mature fields as a result of historical field management practices; and the value of near and new field opportunities for extending field life.

Abstract The Beryl Field is located within Block 9/13 in the UK North Sea, in the west central part of the Viking Graben. The block was awarded in 1971 to a Mobil operated partnership, and the 9/13-1 discovery well drilled in 1972. The Beryl A platform was installed in 1975 and oil production started up the following year. The Beryl B platform was added in 1983 and production and gas re-injection pressure support commenced in 1984. The first 3D seismic survey was shot over the field in 1986, and the most recent in 1997. As of January 1999, 133 wells have been drilled into the field and development drilling is expected to continue well into the twenty-first century. Commercial hydrocarbons occur in sandstone reservoirs ranging in age from Triassic to late Jurassic, with the primary reservoir being the Middle Jurassic Beryl Formation (1.4 billion barrels of oil originally in place). Total ultimate recovery for all reservoirs in the field is expected to be about 960 million barrels of oil (MMBBL) and 2.1 trillion cubic feet (TCF) of gas. As of January 1999, the field has produced nearly 710 MMBBL of oil, or almost 75 % of the ultimate oil recovery. The field has been described previously by Knutson and Munro (1991) , and Robertson (1993) . Recent drilling data (more than 30 new wells) and new 3D seismic have updated the initial field descriptions. These data allow the mapping of two key unconformities, the Mid Cimmerian (Jt) event and a Base Callovian (Jb3) event. Reservoir facies models and isochore maps have also been developed, which together with the refined structural model, allow a better understanding of the reservoir distributions and will guide future production strategies.

Abstract The Nevis South Field is an outstanding field in a number of respects. It contains four stacked reservoirs, two contrasting oil types, a high quality Triassic reservoir and a Beryl reservoir of such quality that one of the producing wells held the North Sea’s record for productivity index. The field is operated by Mobil North Sea Limited (ExxonMobil) with co-venturers Amerada Hess Limited, Enterprise Oil Limited and OMV (UK) Limited. It is a sub-sea development tied back to the Beryl Alpha platform that lies 7 km to the east-northeast. First oil was produced in 1996 but the field is still actively being drilled to new reservoirs and to maximize recovery from already producing reservoirs. Structurally the field is a relatively simple rotated fault block with beds dipping to the southwest and a crestal depth of 8700 ft. The Base Cretaceous Unconformity cuts down into the crest of the fault block such that strata are progressively eroded towards the northeast. Consequently, the core of the field contains Triassic strata with younger, Jurassic, strata on the flank. The oldest reservoir in the field is the Triassic Lewis I sequence of fluvio-lacustrine origin. It contains an unusual heavy oil which is currently being produced via a single, high-angle well. Above this unit lies the Lewis III/IV reservoir which contains the bulk of the hydrocarbons in the field. These sediments are ephemeral stream deposits which are exploited via four producers and a pair of water injectors. The Middle Jurassic Beryl reservoir is a high net:gross tidal delta succession of multi-Darcy permeability. Drainage of the Beryl oil rim is by three horizontal wells with pressure support supplied by the large aquifer. A Beryl gas blowdown phase of development is scheduled for 2005. Drilling and workover activity is guided by fine-scale geological modelling and accompanying simulation. The youngest reservoir comprises mass-flow sandstones of the Middle-Late Jurassic Heather Formation. These relatively thin sandstones contain a comparatively small volume of oil and gas which it is currently uneconomic to develop.