Abstract The Frigg submarine fan complex (Ypresian) is composed of five m ajor depositional sequences (fan lobes) defined by lap-out relationships on seismic sections. The West Frigg and Odin lobes were sourced from the southwest and the East Frigg, Lower and Upper Northeast Frigg lobes were probably sourced from the east and northeast. The major gas reservoir in the Frigg field consists of the West Frigg and East Frigg lobes. The gas reservoir at the Odin field consists of the Odin and Upper Northeast Frigg lobes. Even though the lobes are of slightly different ages, they form a single, laterally continuous reservoir. Reservoir continuity is provided by stacking and extensive lateral migration of channel sands during deposition as well as downcutting of channels into prograded sheet sands. Channel sands and prograded sheet sands form two distinct facies that can be recognized on seismic sections and that have distinctive well-log characteristics. The channel sand facies is expressed on seismic sections as a high-frequency, low-amplitude, mounded to discontinuous reflections. The facies tends to occur in the thicker portions and near the top of individual lobes, mostly above the gas/oil contact. Channel sands in well logs have a “blocky”, low gamma response, range in thickness from 10 to 100 m (33 to 328 ft), and are separated by 2- to 5-m (6.6- to 16.4-ft) thick shales. The sands are interpreted as amalgamated channel-fill grain flow deposits or turbidites. Prograded sheet sands are expressed on seismic sections by concordant and downlapping low-frequency, continuous, medium- to-high amplitude reflections. The facies occurs in fan fringe and outer fan environments where individual sheet shands, 5 to 20 m (16.4 to 65.6 ft) thick, are separated by equally abundant but thinner shale and calcareous shale beds. Groups of sheet sands may display a coarsening upward gamma response (that is, lower gamma values in upper sands of the group), interpreted to result from fan progradation.

Abstract In the East Shetland Basin oil generation began 65 Ma ago; peak oil generation maturity occurs today at 3,250 m (0.7 percent R 0 ) and was first reached 40 to 50 Ma ago; the oil generation threshold is at 2,500 m. Highest oil saturations in the Kimmeridge Clay occur at 0.8 percent R 0 ; oil expulsion efficiencies are > 20 to 30 percent. Oil phase migration has probably occurred through oil wet kerogen laminae, and through interconnected large pores aided by low oil/water interfacial tensions. Oil migrated along strong lateral fluid pressure gradients, from overpressured source rocks in half grabens to Jurassic reservoirs in tilted fault blocks. In the Viking Graben the Kimmeridge Clay is at oil floor maturity below 4,500 m; oil and peak oil generation began 70 to 80 and 55 to 65 Ma ago respectively; 40 Ma ago the Kimmeridge Clay passed through peak generation, and gas generation by cracking of oil had begun. Peak dry gas generation from Brent coals occurs today below 5,000 m, and began 40 Ma ago. The Frigg Field gas, probably generated from late Jurassic source rocks, migrated through microfractures in overpressured mudstones below 3,500 m; above 3,500 m methane probably migrated in aqueous solution and was exsolved in the early Tertiary aquifer.

Abstract In the deepest, axial part of the Viking subbasin of the North Sea, the Frigg Field, one of the world′s largest offshore gas fields, straddles the border of the British and Norwegian continental shelf at 60° Ν lat. The discovery well was drilled in 1971 on Norwegian block 25/ 1 in 100 m of water. Gas was discovered at a depth of 1,850 m in a lobate submarine fan representing the ultimate phase of a thick Paleocene deposit. Sealed by middle Eocene open-marine shales, the structure is mainly submarine-fan depositional topography enhanced by draping and differential compaction of sands. The area of structural closure is underlain by a typical “flat spot” on seismic sections, and the gas column lies on a heavy oil disc. Chromatographic analysis shows that source of both the oil and gas could be the underlying Jurassic section. Recoverable gas reserves are estimated to be about 200 billion cu m (7 Tcf). Production began September 15, 1977; the gas is brought ashore at St. Fergus in Scotland by a 360-km pipeline.