As giant oil fields mature, the flow of results from development drilling and production history, as well as interpretations of new seismic data, provide an evolving view of in-place volumes, reservoir architecture and fluid movement through the reservoir. Often, such changes can trigger modifications to asset development plans and, together with economic conditions, revisions to estimates of ultimate recovery.

The development of the Alba Field – a relatively heavy oil (19° API) accumulation lying in an Eocene deep-water channel complex in Block 16/26 of the UK's Central North Sea – has followed a similar pattern. With an estimated 900 mmbbl of oil in place, the reservoir is characterized by thick, high net-to-gross (NTG) sands with extremely favourable reservoir properties. Because of the less favourable mobility ratio, Alba has been developed exclusively by horizontal production wells, with pressure support provided by a series of seawater injectors.

By mid-2012, after 18 years of production, more than 390 mmbbl of oil had been recovered. During production, several key seismic and drilling technologies were applied to address reservoir complexities and reservoir management concerns that emerged as field development progressed. The most significant of these include the following:

1. a dramatic uplift in imaging the depositional architecture was provided by converted shear wave seismic data (1998), revealing an extremely irregular top reservoir and hinting at greater internal complexity than initially modelled;

2. advances in extended reach drilling technology enabled a greater number of infill targets to be accessed, while geosteering techniques allowed better well placement, and horizontal completions using gravel packs improved well reliability;

3. spectacular images of production cones beneath horizontal production wells extracted from a dedicated 4D monitor survey (2008) addressed the field's key dynamic uncertainty – where is the remaining oil?