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.

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 spite of the simplistic submarine-fan models (emphasizing turbidite channels and lobes) that have dominated the literature since the late 1960’s, deep-water processes and their deposits (facies) are quite complex. Recognition of deep-water facies using detailed process sedimentology is critical in reservoir characterization because depositional processes are the primary controls on the dimensions, geometries, and ultimately the quality of deep-water reservoirs. Classification of sediment-gravity flows into Newtonian flows (turbidity currents) and plastic flows (debris flows), based on fluid rheology and flow state (turbulent and laminar), is still the most practical and meaningful approach. This is because the boundary between Newtonian and plastic flows can reasonably be established using sediment concentration values of about 20 to 25 percent by volume. In general, low-concentration, sandy turbidity currents tend to emplace fan-shaped deposits of finegrained sand in unconfined environments by suspension settling. In contrast, high-concentration, sandy debris flows tend to emplace tongue-shaped deposits of fine- to coarse-grained sand in unconfined environments by freezing. The tongue-shaped deposits of sandy debris flows may be surrounded by fan-shaped deposits of muddy turbidity currents because of surface-flow transformation of basal laminar flows into upper and frontal turbulent flows. Sandy debris flows are considered to be the dominant process transporting and depositing reservoir sands into the deep sea. The concept of “high-density turbidity current” is confusing because the high density (that is, high sediment concentration) of these flows tends to damp the turbulence, the very property that defines turbidity currents. If the existing three turbidite models (Bouma Sequence, Lowe Sequence, Stow-Shanmugam Sequence) are meaningful, then a complete turbidite bed should contain a total of 16 divisions. However, no one has ever documented such a complete turbidite bed. The plethoric family of “traction carpets” has proliferated into nine models (flowing-grain layers, inertia-flow layer, laminar sheared layer, fluidized flowing grain layer, avalanching flow, etc.). In spite of this multiplicity of models, many fundamental problems still remain in recognizing deep-water facies. Recognition of units deposited by deep-water bottom currents (also known as contour currents) is difficult. Bottom-current-reworked sands are thin and lenticular at core scale but may also exhibit sheet-like geometry on seismic scale. Submarine-fan models with turbidite channels and lobes have controlled our thinking for nearly 30 years, but many of us now know that these models are obsolete. The suprafan lobe concept was influential in both sedimento-logic and sequence stratigraphic circles because it provided a basis for constructing a general fan model and for linking mounded seismic facies with sheet-like turbidite sandstones. However, this concept recently was abandoned by its proponent on the grounds that a suprafan lobe is not a discrete mappable unit. This has left the popular sequence stratigraphic fan models, based primarily on seismic geometries, with a shaky foundation. Although depositional processes cause the development of different seismic geometries, the notion that depositional facies can be inferred from seismic geometries is not fully supported because a single facies (sandy debris flows) can generate multiple seismic geometries (mounded/bidirectional downlap, mounded/hummocky, mounded/chaotic, sheet/parallel-continuous, etc.) and multiple wireline log motifs (upward-fining, upward-coarsening, and blocky), as seen in examples from the North Sea, Gulf of Mexico, and Equatorial Guinea. As a counterpart to turbidite-dominated fan models suited for basinal settings, a slope model is herein proposed that is representative of debris-flow-dominated systems. The strength of this model is that it includes a variety of processes, such as slumping, debris flows, turbidity currents, and bottom currents, that are common to the slope settings. Deposits of sandy debris flows, analogous to turbidite fan deposits, are capable of developing sheet-like geometries in the rock record. The conventional notion that sandy debris-flow reservoirs do not have good reservoir properties is not true because the lower Eocene sands of the Frigg Formation (Frigg field, Norwegian North Sea), which are interpreted to be of sandy-slump and sandy-debris-flow origin, exhibit extremely high porosities (27 to 32 percent) and permeabilities (900 to 4,000 mD). In contrast, sands deposited from turbulent turbidity currents in deep-water environments are poorly sorted and include large amounts of silt and clay. In the 21st century, a paradigm shift is in order. This shift will involve the emergence of a new paradigm that will be more inclusive in terms of slope processes and products than just basinal turbidity currents and fan models. Science is a journey, whereas facies models are the final destination.

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.