Frigg Field Research Articles

The environmental impact assessment process for offshore oil and gas exploration and development in Norway

The appl ica t ion of environmental impact assessment (EIA) reflects the economic and political system of each country that uses it. Before present ing and discussing how EIAs are carried out in Norway, it is appropria te to first out l ine the Norwegian oil and gas s i tuat ion and the nai tonal policies regarding it. The history of Norway's pe t ro leum industry is brief. It started in 1962 when a mul t ina t iona l oil company approached the Norwegian Government with a request for sole rights to explore for and produce oil and gas on the Norwegian cont inental shelf. In 1963, Norway procla imed sovereignty over the cont inental shelf, and commenced seismic surveys of the North Sea basin. The first round of l icensing took place in 1965, when 278 blocks were pu t on bid. Of these, 70 were allocated to 22 licenses. The first field (Cod) was discovered in 1968, but it was not unt i l the Ekofisk Field was discovered in 1969 that the area was found to be commercial ly viable (Figures 1 and 2). T h e Frigg Field was discovered in 1971 in a block awarded in the second round. The Stat[jord Field blocks conta in ing both oil and gas were awarded i n 1973 after a discovery had been made in adjacent blocks on the British side of the North Sea. M o r e t h a n 400 wells have been drilled on the Norwegian Cont inental Shelf. Approximately three-quarters of these have been wildcat wells, the rest appraisal wells. The area currently under license to oil companies is about 2.7 mi l l ion ha (hectares) (January 1983). The current product ion of oil and gas in Norway is approximate ly 50 MTOE per year. Half of the produc t ion is oil, the other half gas. The ul t imately recoverable reserves of the Norwegian North Sea are estimated to be 4,700 MTOE, of which about 2,700 M T O E have already

Hydrocarbon generation and migration from Jurassic source rocks in the E Shetland Basin and Viking Graben of the northern North Sea

In the E Shetland Basin oil generation began 65 Ma ago; peak oil generation maturity occurs today at 3250 m (0.7% R 0 ) and was first reached 40–50 Ma ago; the oil generation threshold is at 2500 m. Highest oil saturations in the Kimmeridge Clay occur at 0.8% R 0 ; oil expulsion efficiencies are >20–30%. 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 4500 m; oil and peak oil generation began 7C–80 and 55–65 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 5000 m, and began 40 Ma ago. The Frigg Field gas, probably generated from late Jurassic source rocks, migrated through microfractures in overpressured mudstones below 3500 m; above 3500 m methane probably migrated in aqueous solution and was exsolved in the early Tertiary aquifer.

Inspection of Concrete Offshore Structures

Summary The planning and inspection procedures used on Total Oil Marine Ltd.'s MCP-01 (manifold compression platform) minimize time spent offshore and ensure that the retrieved information accurately describes the structure's condition. Procedures include preparing a detailed field specification; visual, photographic, and nondestructive inspection photographic, and nondestructive inspection techniques; and a report designed for easy access to detailed information. Current research on underwater repair techniques is outlined. Introduction The Offshore Installation (Construction and Survey) Regulations 19741 require that a thorough examination (major survey) of an installation be undertaken to ensure compliance with Schedule 2 of that document before the 5-year certificate of fitness is renewed. In addition, annual surveys are required of a sufficient number of selected parts of the structure to give reasonable evidence of continued compliance with Schedule 2.Schedule 2 of the regulations outlines the factors to be considered for structural integrity of a platform.The first certificate of fitness ensures that the design and construction requirements are satisfied. Therefore, subsequent inspections need only to consider changes in the structure's state. For dead and live loading, these changes must be taken into account in the design limits. Consequently, both annual and major inspections are concerned primarily with material deterioration, with accident primarily with material deterioration, with accident damage included where a separate inspection is not required.The inspection program for Total's MCP-01 satisfies these regulations while minimizing the interference with platform operations and providing detailed, quickly accessible information in annual reports on the structure's condition. This program is considered in two parts:the planning approach to cover the major and annual inspection requirements andvisual inspection and nondestructive test methods.In the event of a deterioration rate that could lead to an unacceptable structural state in the design life or to damage caused by ship impact, dropped objects, fire, or explosion, repairs will be necessary. Although methods of repairing small scale concrete damage underwater exist, there are no techniques for undertaking major repairs.To fill this gap in the offshore industry's capability, a research program aimed at developing such techniques, particularly where reinforcing and prestressing are involved, is underway. prestressing are involved, is underway. Description of MCP-01 The intermediate manifold platform, MCP-01, was positioned as the intermediate station between the positioned as the intermediate station between the Frigg field and the St. Fergus shore-terminal treating facilities in July 1976.MCP-01 (Fig. 1) is a concrete gravity platform, designed by C.G. Doris, comprising a solid raft 101 m in diameter with six tunnels radiating from a hollow central core. The core, 9 m in diameter, extends from the raft through the full height of the structure, which is 147.5 m and houses the 32-in. riser piping with two risers per pipeline. Each radial tunnel contains a seal caisson which provides the watertight sealing joint through the concrete lobed wall for riser entry.At approximately 30-m radius from the core there is a concrete caisson wall (lobed wall) which extends above the waterline. The grillage of concrete deck beams is supported off the core from columns located on top of the lobed wall. JPT P. 2243

Frigg Field--Large Submarine-Fan Trap in Lower Eocene Rocks of North Sea Viking Graben

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 lat. 60°N. 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 underlined by a typical flat spot on seismic sections and the gas column lies on a heavy oil disk. Chromatographic analysis shows that both oil and gas could be coming from underlying Jurassic source rocks. 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.

Petroleum Exploration and Production in Europe in 1973

During 1973 the general decline in oil production from older onshore fields in Europe continued and was not yet offset by output from the giant oil fields being developed in the North Sea. The North Sea fields were projected for large-scale production to start in 1975. The Amposta Marino oil field off the Spanish coast went on production. European gas production increased, but less than in recent prior years. Large gas fields already had reached their peak rates. In 1973 new giant oil fields producing from Jurassic sandstone reservoirs were discovered in the British sector of the northern North Sea, and major extensions were made to fields found in 1971 and 1972. In the Norwegian area important extensions were made to the Paleocene oil reservoirs of the Ekofisk group of f elds, and gas was discovered east of the Frigg field. A major extension to the Kinsale Head gas field off the south coast of Ireland indicated that the field was commercially significant. Oil discoveries were made in France, Germany, and offshore Spain; in addition, new gas fields were found in northwest Germany and both on- and offshore in the Po basin of Italy. Exploration activity, chiefly geophysical surveys, increased in the various basins of the continental shelf off western Europe, from the Barents Sea to Portugal. In the Soviet Union production of oil was 8,420,000 b/d and of gas 22.8 Bcf/d. Most of the increased oil production was from the West Siberian basin, which became the foremost producing region of the USSR. Production from the giant gas reserves of the northern West Siberian basin reached a significant level for the first time. Exploration in the Caspian Sea was intensified. New oil discoveries were made in the central West Siberian basin in the Caspian Sea, in the Pechora basin west of the northern Urals, and near the Baltic coast. Gas was found in the Karakum Desert of Middle Asia, on the Siberian platform, and on the shores of the Sea of Azov.