Improving Recovery From the Dunlin Field, U.K. Northern North Sea
Authors: Braithwaite C. I. M. , Marshall J. D. , Holland T. C. 
Published: December 2007

The Dunlin Field lies 160 km north-east of the Shetland Islands at the western edge of the Viking Graben. Located in 150 m of water, it extends from Shell/Esso's licence block 211/23a into Conoco/Chevron/Britoil's 211/24a acreage. The oil accumulation is trapped by a heavily-faulted horst block within the Middle Jurassic Brent Group sequence. The field was discovered in 1973 and development drilling began in 1977.

A 2D seismic survey shot in 1974 was used for field development planning despite poor definition of the reservoir configuration. The advent of 3D seismic helped address this limitation and a survey covering the entire field was acquired in 1977-79. The Top Brent could then be mapped across the whole field and major faults properly defined resulting in immediate changes to planned development well locations. As drilling progressed, well results in the complex eastern flank indicated the need for improved resolution of fault positions and in 1983 the survey was reprocessed which enhanced definition of the flank area. The survey itself was, however, limited by the early 3D technology, and a new 3D survey was acquired in 1988 to allow optimum siting of the remaining wells and sidetracks required for field management.

Extensive shales divide the deltaic Brent Group sands into separate producing intervals and by July 1989 33% of the 825 MMstb [131 × 106 stock-tank m3] ST0IIP has been produced, principally from the high permeability Tarbert and the channel/barrier sands of the Ness and Etive Formations. A geological review is currently underway in parallel with the seismic interpretation in an effort to improve recovery from these sands. The bulk of the remaining oil, however, is located in the low permeability Rannoch Formation, directly underlying and in good pressure communication with the flooded Etive. An integrated petroleum engineering study was carried out to determine the viability of dedicated development.

The Rannoch is a coarsening-upward shoreface sequence of mica-rich sands. It is characterised by low-angle cross-bedding that is interpreted as Hummocky Cross Stratification (HCS). The formation is thickest in the south-west of the field. To support single-well simulations aimed at evaluating Rannoch recovery techniques a model of permeability distribution in HCS sands was developed from core and log data which included the effects of impermeable concretions which occur sporadically.

Single-well simulation studies were carried out focusing on wells within the defined target area. The historical imbibition of water by gravity drainage from the flushed Etive into the Rannoch was matched, together with historical production behaviour. The calibrated models predicted that Rannoch recovery could be increased by dedicated producers and, with optimal well spacing, incremental recoveries of between 1.5 and 2.0 MMstb [0.2 and 0.3 × 106 stock-tank m3] per well would be achieved with a relatively slow build-up of watercut.

Encouraged by these results a development programme was initiated in mid 1988. Recent well results from this campaign have so far been favourable. Oil production rates of more than 3000 stb/d [477 m3/d] are being experienced and watercuts are as expected. A horizontal well is being considered and the scope for additional activity will be evaluated following review of the results of the current campaign.