Harald Tønnesen, Norwegian Petroleum Museum
The Statfjord reservoir lies 2 330-2 830 metres down, and measures six kilometres wide by 24 long. It comprises two large sandstone structures – the Brent group and the Dunlin formation – and a smaller one – the Statfjord formation.
— Statfjord A in production. Illustration: Alf Magne Pettersen
Containing 75 per cent of the stock tank oil originally in place (Stooip), Brent is the uppermost component. The Statfjord formation is the lowest, with 24 per cent of the Stooip. Sandwiched between them, Dunlin contains almost no hydrocarbons. The three formations are separated by layers of impermeable shale. Oil from both Brent and Statfjord is very good quality, with a low sulphur content. Recoverable reserves originally present in the field are put at 3 570 million barrels of oil, 80 billion standard cubic metres (scm) of gas, 20 million tonnes of propane and butane (natural gas liquids – NGL) and 6.3 million barrels of condensate (light oil). Hydrocarbon-bearing strata in Brent and Statfjord were deposited in the middle Jurassic and the lower Jurassic/upper Triassic respectively – in other words, about 170-210 million years ago. The structure containing these reservoirs is tilted six-seven degrees towards the west and bounded on the east by a system of faults. The cap rocks keeping the oil and gas in place are upper Jurassic/Cretaceous shales.
The Brent group comprises sandstones and is divided into five smaller formations, which are grouped in turn into the upper and lower Brent. Permeability – how easily the oil and gas flows through the rock – is best in the Tarbert and Etive formations, while average porosity – how much of the rock is made up of pore spaces – is very good. The Statfjord formation, moving from the bottom up, contains a mix of sandstone, siltstone and shale. Divided into three zones, its porosity is generally good but permeability is best in the upper part of the Nansen zone.
Initial production strategy
During the first 28 years of production from Statfjord, the strategy was to maintain reservoir pressure with the aid of water or gas injection while draining the main field structure. Water injection began in the upper and lower Brent in 1981 and 1982 respectively. This was assisted by water alternating gas (WAG) injection from 1997 until 2008, when Statfjord late life production began. Production wells were placed in the uppermost part of the formation’s eastern section. Before the gas export pipeline became operational, associated gas produced with the oil was injected back into the Statfjord formation. Oil production was kept at a high level to provide space for this gas. The gas began to be exported in 1986 via Statpipe and the British Flags pipeline. To compensate for the loss of pressure support from injecting gas, water injection combined with WAG was also initiated in the Statfjord formation in 1997. As time passed, the challenge became to drill new production wells in order to tap pockets of oil further to the east, where the field was broken up by small faults.
Other fields phased in
As Statfjord output declined, spare processing capacity became available on the platforms which could be used to process production from nearby fields. As a result, the Snorre A platform has been tied back to Statfjord A while the Statfjord North, Statfjord East and Sygna satellites are linked to the C platform.
Statfjord late life
The production strategy on Statfjord has been revised in order to extend the field’s producing life. All available gas is to be recovered by reducing reservoir pressure. Named the Statfjord late life project, this new approach is intended to improve recovery factors from 53 to 74 per cent for gas and from 65 to 68 per cent for oil. At the same time, the field’s producing life will be extended by 20 years to 2030. This solution was approved by the partners and the government in 2005, and was implemented for the Statfjord formation in 2007 and for the Brent group in 2008. Roughly 80 wells are due to be drilled or recompleted as part of Statfjord late life. Many of these wells will be sidetracks drilled from existing wells to tap new areas of the reservoir. In order to produce at lower reservoir pressure, both gas lift and sand control are needed in virtually all the wells. Downhole electric pumps will be installed towards the end when gas lift ceases to function. A new Tampen Link pipeline runs from Statfjord B to tie into Britain’s Far North Liquids and Associated Gas System (Flags) in order to export the greater gas volumes to St Fergus in Scotland.
Main considerations in develoment of Statfjord Field, H. Ager-Hansen, Statoil and J. Medley, Mobil
Statfjord Field: Field and Reservoir Management Perspectives, Atle Aadland, Olav Dyrnes and S.R. Olsen, SPE and O.M. Drønen, Statoil A/S. SPE Reservoir Engineering , August 1994
Increasing economic recovery by synergetic development of neighbouring fields in the Norwegian Continental Shelf. Adolfo Henriquez, Øystein Arvid Håland, Stein Børre Torp (Statoil) 2001
Turning a North Sea Oil Giant into a Gas Field – Depressurization of the Statfjord Field, R. Boge, SPE, S.K.Lien, A. Gjesdal and A.G. Hansen, SPE, Statoil. SPE 96403 2005
The use of sea water tracer as a tool for history matching of the Statfjord Fm simulation Model. Master Thesis, Henriette Strøm, 2010
Triassic lithostratigraphy of the Northern North Sea Basin. Kjell-Sigve Lervik – Norwegian Journal of Geology 2006
By Harald Tønnesen and Finn Harald Sandberg, Norwegian Petroleum Museum
The Statfjord A platform stands in 145.3 metres of water in the centre of the field. It ranks as the fourth Condeep to be built. This installation comprises a concrete gravity base structure (GBS) supporting a steel topside . The topside was fabricated by Aker Stord in western Norway and was mated with the GBS in the adjacent Digernessund sound before tow-out to the field.
— Statfjord A platform with the two flotels Nortrym and Polymarines. Photo: Statoil on behalf of the Statfjord Group.
Built by Norwegian Contractors at Hinnavågen in Stavanger, the GBS comprises 19 cells arranged in a concentric formation. Most of these are used for oil storage. Three have been extended upwards as shafts to carry the topside. The platform, which measures 254 metres in height from the seabed to the top of the drilling derrick, was towed to the field in 1977 and came on stream in November 1979.
Oil was exported via a loading buoy located a few hundred metres away. The original articulated loading platform (ALP) was later replaced by a specially developed Ugland-Kongsberg offshore loading system (Ukols).
The rig comprises a derrick, modules for such functions as mud mixing, and pipe storage. Wells are drilled through two of the concrete shafts supporting the topside. A total of 42 slots are provided. Both production and gas/water injection wells have been drilled, with an average depth of 2 500-2 800 metres. The derrick stands on skids which allow it to be positioned over the various wells with the aid of hydraulic jacks.
Oppkobling og ferdigstilling,
The topside measures 86.2 metres long by 83.6 wide, providing a surface area of 5 000 square metres and total deck space of 21 000 square metres. Total height to the helideck is 43.2 metres, while the base is 28 metres above the sea at its lowest point.
The lowest of the steel decks, the cellar deck is built into the module support frame (MSF) which carries the rest of the superstructure. Divided into individual sections with double bulkheads, it forms an integrated steel structure. The flare boom extends for 116 metres at an angle of 45 degrees from its eastern end to burn off all associated gas for brief periods.
Located above the cellar deck, this has acquired its name because it is partly composed of prefabricated modules. The south-western corner, with the M11, M12, M14,M15, M17 and M18 units, forms part of the cellar deck’s integrated steel structure.
Upper module deck
With the exception of UM7, this deck is built up entirely of modules and lies immediately above the module deck. UM7, which is part of the drilling module, has been constructed as an integrated steel structure together with the cellar deck and the south-western part of the module deck.
The living quarters provide 100 cabins. These were originally two-berth but converted for single occupancy in 2000-2003. The six-storey structure comprises three modules. A partial seventh floor is provided by the helideck, radio shack and helicopter fuel tanks. The marine control centre was positioned there in the early years, but later moved to Bergen. In addition to the cabins come a canteen and recreation rooms. A lift and internal staircase connect the floors, while external staircases serve as emergency exits. The illustration shows the layout of a typical cabin in the living quarters.
The tops of the uppermost modules form the weather deck. This area is used for storage and for loading/discharging cargo by the large platform cranes.
The lower section of the GBS comprises 19 concrete cells. Sixteen of these are used for storage, while three extend upwards to form the shafts supporting the topside.
With an internal diameter of 19 metres and a height of 67 metres, the storage cells are individual concrete cylinders which each have a capacity of 80 000 barrels.
Fifteen of the cells are used to store crude oil, and can collectively hold about 1.2 million barrels. Cell 6 is equipped with an internal cylindrical tank to store up to 21 750 barrels of diesel oil. The annulus between the internal cylinder and the cell wall provides 63 500 barrels of storage space for the oil-water emulsion (sludge) which forms during platform operation. All 16 of the cells are partly filled with sand ballast covered by a concrete lid. They are kept filled with liquid at all times. When oil is exported, the cells take in water to maintain their liquid content.
One of the three shafts supporting the topside, this contains a series of decks carrying pumps for fire, ballast and sea water, ballast water tanks and pumps for crude oil loading.
These are completely filled with conductor tubing for a total of 16 wells in each shaft. The illustration shows the distribution between production and water/gas injection wells.