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The Ormen Lange Field is a gas reservoir offshore mid-Norway, developed in a combined structural–stratigraphic–hydrodynamic trap. The lobe-dominated turbidite deposits are mostly of excellent quality, but show a significant deterioration trend towards the fan fringe at its northern margin. Axial parts of the fan contain amalgamated sand-rich deposits, which pass laterally into layered sequences characterized by intercalation of low-permeability heterolithic drapes. Along its 40 km length, the field contains in excess of 400 linked polygonal faults attributed to de-watering of underlying shales. Despite pervasive faulting, reservoir connectivity on a geological timescale is proved by a common pressure gradient in pre-production wells and depletion seen in all later development wells. Recent appraisal drilling of the fan fringe, occupying the crest of the field, encountered only residual gas saturations, despite being located in an area delineated by a seismic direct hydrocarbon indicator. A hydrodynamic aquifer concept is the most plausible explanation for the fluid distribution, in which the gas from the crest of the structure is displaced, leaving behind a northward-thickening prism of residual gas. Dynamic simulation of the fluid-fill evolution over geological time showed the hydrodynamically tilted contact depends on rate of water flow across the aquifer, stratigraphic baffling and faulting, and reservoir quality, i.e. clean sand fraction and effective permeability. Optimal development of this deep-water reservoir depends on understanding the relationship between reservoir quality, connectivity, and the position of the free water level (FWL) in the field. A range of FWL in the north of the field, only weakly constrained by the wells, was empirically established from the hydrodynamically initialized models. This allowed a robust test of the production wells planned to drain the margin of the field. Modelled predictions of reservoir quality and pressures were confirmed by subsequent drilling.

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