It shows the development of the Ekofisk area from year to year from the start with the first production in 1971 until 2001.
To follow the development of the field further from 2008 to 2017 click here.
To follow the development of the field further from 2008 to 2017 click here.
The aim of this facility – an extension to the Ekofisk South project – was to increase waterflooding on the southern flank of the Ekofisk reservoir in order to maintain oil and gas production.
An amended plan for development and operation (PDO) of Ekofisk South was approved by the Ministry of Petroleum and Energy on 7 September 2017.
This involved installing a new seabed template with four water injection wells, and represented a continuation of the well-established Ekofisk production strategy based on waterflooding.[REMOVE]Fotnote: https://www.regjeringen.no/no/aktuelt/okt-utvinning-pa-ekofiskfeltet/id2570011/.
The template was installed in September 2017, with a technical solution similar to that used on the seabed facilities already installed – Ekofisk 2/4 VA and 2/4 VB.[REMOVE]Fotnote: Pionér, no 2, ConocoPhillips, 2018.
In addition to the structure itself, including wellheads and Xmas trees, the installation comprised control modules with umbilicals connected to the existing waterflooding system.
The 2/4 VC facility receives injection water from Eldfisk 2/7 E, while power and control signals come from Ekofisk 2/4 M. It is run from the Ekofisk 2/4 K control room.
When fully developed, overall injection capacity for this subsea installation will be 80 000 barrels per day through the four wells.
The water pipeline and umbilical to 2/4 VB were extended to 2/4 VC. Well operations on the latter began on 24 May 2018 with a view to starting injection before the end of the year.
This platform rests on a steel jacket built by Dragados at Cadiz in Spain. The module support frame (MSF) and topsides were fabricated by Energomontaz at Gdansk in Poland and completed at Kværner Egersund.
The topsides were installed in July 2013. Petroleum and energy minister Tord Lien performed the official inauguration of 2/4 Z and the Ekofisk South project on 29 October 2013,13 just four days after the platform came on stream.14
No control room is provided on 2/4 Z, but it has a local equipment room (LER) which is not permanently manned. The platform is monitored and remotely controlled from the control room on Ekofisk 2/4 J, but can also be run from the operations centre in Tananger.
So successful had the 2/4 VA facility proved to be that it was copied for 2/4 VB as an eight-well template, also delivered by FMC at Kongsberg.
Similarly, the wells on 2/4 VB were drilled by Maersk Innovator. The well operation department completed installation of the template, manifolds and casing for the eight subsea wells.
Seabed installations carried out by Subsea 7 comprised a five-kilometre pipeline for water from the Eldfisk Complex as well as a diver-installed T piece welded into the existing pipeline from Eldfisk 2/7 E to Ekofisk 2/4 K.
This assignment also covered laying three kilometres of umbilicals combining hydraulic lines and fibreoptic cables from 2/4 VA, so that 2/4 VB could also be remotely operated from land.
Primarily located in production licence PL 018, along with Ekofisk, the other seven fields are West Ekofisk, Tor, Eldfisk, Albuskjell, Edda, Cod and Embla.
Furthermore, six of the eight – with Embla and Cod as the exception – comprise two geological formations. One is known as the Ekofisk formation, with the Tor formation as the other. See the article on sea scurf.
The graph in figure 2, which presents collective production of oil, gas and condensate over time in million standard cubic metres of oil equivalent (scm oe), shows Ekofisk’s dominant position – both historically and today.
With the exception of four years, overall output from the seven other fields has never achieved the same volume as Ekofisk’s own production.
The effect of waterflooding on Ekofisk, which got going seriously in 1987, can be clearly seen in the production curve. This rose from less than 10 million scm oe per annum to more than 20 million.
On 1 July 2019, operator ConocoPhillips submitted a plan for development and operation (PDO) which covered reopening the Tor field (Tor II).
This will involve the investment of about NOK 6 billion, with a planned production start in late 2020, and is expected to yield an estimated 10 million scm oe.
Furthermore, the licensees have initiated concept studies for further development of the northern flank of Eldfisk (Eldfisk II). Both subsea solutions and a simple unmanned platform are under consideration.[REMOVE]Fotnote: https://petro.no/nyheter/conocophillips-vurderer-a-bygge-ny-plattform-pa-eldfisk-nord
Development of the Tommeliten Alpha formation, which has only ranked as a discovery so far, is also being assessed.[REMOVE]Fotnote: https://petro.no/nyheter/forbereder-mulig-utbygging-tommeliten-alpha
Known as coccoliths, these plates are so minute than 30 of them laid side by side would be no wider than a strand of hair. But what they lack in size, they make up for in numbers.
Their colossal accumulation is helped by the fact that coccolithophores reproduce asexually. When one dies, its coccoliths sinks to the seabed at a rate of about 15 centimetres per day.
If conditions are right, the scales remain lying and are eventually buried in their billions of billions.
Estimates indicate that coccolithophores globally produce more than 1.5 million tonnes of calcium carbonate per annum – equal to the weight of the Gullfaks C platform, which ranks as the heaviest structure ever moved by humans.
Three things must be in place for an oil and/or gas field to form – a source rock, a reservoir rock and a cap rock which prevents the petroleum from escaping.
In the case of Ekofisk, we know quite a bit about how these three components originated.
The Ekofisk source rock dates from the Jurassic period, 161-145 million years ago, and comprises organically rich black shales known as the Draupne formation.
In Norse mythology, Draupne was the gold ring worn by the god Odin which formed another seven rings every ninth day – in other words, an endless source of prosperity.
So the name is appropriate for a formation found over most of the Norwegian continental shelf (NCS), which has put huge volumes of petroleum into most of Norway’s fields – including Ekofisk.
The Cretaceous period followed the Jurassic and lasted for 145-66 million years, with the last 10 million of these forming the Campanian and Maastrichtian stages.
Conditions then were favourable for coccolithophores over much of the southern and central North Sea as well as England, Denmark and France.
Countless coccoliths were deposited on the seabed. Since the latter was neither flat nor stable, they were moved around by small slips, landslides and/or mud flows which could be activated by earthquakes, before being finally buried by their successors.
The Cretaceous ended in a mass extinction event, when up to 70 per cent of all life on Earth vanished – including the dinosaurs.
This wipe-out was unleashed by a massive asteroid strike in what is now the Gulf of Mexico, where the Chicxulub crater is about 150 kilometres in diameter and 20 kilometres deep. The asteroid itself may have measured 80 kilometres.
That impact nevertheless failed to destroy all marine life, and the “sea scurf” continued to rain down in the following Palaeocene period.
During its first million years, known as the Danian stage, further tens of metres of calcium carbonate were deposited. But changed seabed conditions and a colder climate had an impact.
The amount of reworking which the material experienced varied and decreased, while the content of silica derived from microscopic diatoms and radiolarians increased.
Lower sea levels also meant an increased influx of sediments from land (terrigenous material) in the chalky plates heaping up on the seabed.
These sediments usually have up to 50 per cent porosity (cavities) when deposited. But this will be considerably reduced by burial and diagenesis (the physical, chemical and biological changes which occur during conversion from sediment to stone).
In some case, that reduction can be down to well below 10 per cent. However, the good conditions around the Greater Ekofisk Area (GEA) meant that much of the porosity in the chalk was retained.
It has been calculated at 25-40 per cent. By comparison, a good sandstone reservoir – which is the kind usually found on the NCS – has a porosity of 30 per cent.
Permeability is also needed to get much oil out of a rock, and the “primary permeability” of Ekofisk chalk is low since the connections between its pores is poor/constricted.
But the field has enjoyed another stroke of luck here. A large number of fractures in the reservoir have improved its permeability and provide good production properties – at least initially. See water injection.
After the deposition of the Ekofisk formation, conditions changed so that the overlying sediments lost all their porosity when buried and became tight (impermeable).
That allows them to function as a cap rock which seals the reservoir formed by the Tor and Ekofisk formations.
The fractures mentioned above were created at the same time as the rocks were subject to movement when large quantities of underlying salt shifted. This also produced large domes and thereby created trap structures where oil and gas can accumulate.
In other words, the oil migrating from the source rocks has gathered in the reservoir formations under the cap rock – and in amounts which can be difficult to imagine.
The Ekofisk reservoir is as thick as the Eiffel tower is tall and covers an area of 40 square kilometres – the same size as 5 500 football pitches.
Recoverable oil in Ekofisk totals 3.5 billion barrels, which would be sufficient to supply the whole world with crude for 35 days.
Roughly 1.1 billion standard cubic metres (scm) of oil (about 6.9 million barrels) and 300 billion scm of gas were present in Ekofisk when production began.
That corresponds to twice Norway’s annual water production. It also represents more than 100 times annual Norwegian energy consumption and just over 100 days of global oil usage.
It is impossible to get all the oil out of a reservoir, and a distinction is therefore drawn between reserves in place and recoverable reserves.
However it is measured, though, Ekofisk ranks as one of the very largest fields on the NCS. The original estimate for petroleum recovery from the field was 17 per cent. It is now expected to exceed 50 per cent – in part through waterflooding.
Figure 1 Oil quantities produced and remaining in fields on the NCS. Source: norskpetroleum.no.
Figure 2 Coccoliths, which collectively form a coccosphere to surround the coccolithophore. A single coccolith measures 1-10 µm (0.001-0.01 mm) and is invisible to the naked eye. This photograph has been taken using an electron microscope. Photo: Alison R Taylor, University of North Carolina Wilmington Microscopy Facility
Figure 3 A bloom of phytoplankton and the coccolithophore Emiliana huxleyi, which has coloured the Barents Sea pale blue. Photo: Nasa Earth Observatory
Halbout, Michel T, Giant Oil and Gas Fields of the Decade: 1968–1978. AAPG Memoir 30, 1980.
Ivar B. Ramberg – Inge Bryhni – Arvid Nøttvedt – Kristin Rangnes (ed.’s), The Making of a Land, NGF 2008
So it is more appropriate to ask which companies hold and have held rights from the state to explore for and exploit the natural resources in Ekofisk.
More specifically, that relates to interests in production licence (PL) 018. This was awarded in the first licensing round on the NCS in 1965.
The Phillips name has always been included among the licensees. But that is the only constant presence in the list of participants.
This article addresses how the licence composition has altered and how far these changes have been affected by developments in the oil industry generally and on the NCS in particular.
A single company, A P Møller, was given a sole concession in 1962 to explore for and produce oil on the Danish continental shelf for 50 years.
It is unlikely that anything similar could have happened in Norway, even though America’s Phillips Petroleum Company applied to the Norwegian government in 1962 for a similar licence.
In exchange, it offered to carry out seismic surveys worth NOK 1 million on the NCS. However, consideration of this request was put on hold.
The experience gained by the Norwegian authorities from giving hydropower concessions to domestic and foreign companies since the early 20th century meant nobody was going to get a sole licence.
Instead, the government announced a first licensing round on the NCS on 9 April 1965. The outcome on 17 August was that nine of 11 applicant groups were awarded a total of 74 blocks.
Norwegian industrial interests were then kept at arm’s length from the expensive and risky business of oil exploration, with two exceptions.
One was Norsk Hydro, which participated in the French-led Petronord group, and the other was the Norwegian Oil Consortium (Noco) in the Amoco-Noco team.
The Phillips group comprised the US company (51.74 per cent) with Fina Production Licenses AS (30 per cent) and Norsk Agip (18.26 per cent). It applied for and secured PLs 016, 017 and 018.
Exploring for oil was initially a very uncertain and expensive business. In addition to seismic surveys, the Phillips group had to charter a drilling rig.
That was required for a certain number of wells which the partners were committed to drill under the licence terms. They also had to pay the government an annual fee of NOK 50 000.
But the group had little idea that it had hit the jackpot. PL 018 covered blocks 1/5, where nothing has admittedly been found, 2/4 containing Ekofisk, 2/7 with Eldfisk, and 7/11 holding Cod.
A production licence on the NCS gives its holders the exclusive right to conduct exploration drilling for and production of petroleum deposits within a specified area. A production licence on the NCS gives its holders the exclusive right to conduct exploration drilling for and production of petroleum deposits within a specified area. Such licences are awarded by the Ministry of Petroleum and Energy to sets of licensees. These are comprise oil companies, with one designated as the operator to conduct operations on behalf of each group. Each licensee owns its proportionate share of the petroleum produced from the licence area. If a commercial discovery is made in the licence area, it can be developed by the licensees. This must be done on the basis of an approved plan for development and operation (PDO), which has been drawn up in accordance with the provisions of Norway’s Petroleum Act. Oil and gas which have not been produced remain the property of the Norwegian state.
The Phillips group pursued talks in 1967 with the Petronord group on a closer collaboration aimed at spreading risk more widely on the NCS.
These negotiation were initiated after other companies had drilled dry wells and spent a lot of money without seeming to have anything to show for it.
The outcome in 1968 was a swap of licence interests – a fairly common practice in the international oil industry. Phillips and Agip transferred 20 per cent of their holdings to Petronord in exchange for a similar proportion of the latter’s licences.
At the same time, agreement was reached that the two groups would share the cost of the Ocean Viking drilling rig and use it turn and turn about.
This brought a number of new licensees to PL 018 – Elf Norge AS (7.1 per cent), Total Norge (5.325 per cent), Aquitaine Norge AS (3.55 per cent) and Norsk Hydro Produksjon AS (2.5 per cent).
In addition, the minor French companies Eurafrep Norge AS, Coparex Norge AS and Cofranord AS each held a tiny fraction.
Fina retained 30 per cent, while Phillips reduced its share from 51.74 per cent to 36.96 per cent and Norsk Agip was cut from 18.26 to 13.04 per cent.
Rumours of a big discovery began to circulate in the autumn of 1969, with 25 October taken as the date when the geologists were sure a major find had been made in block 2/4. But Phillips did not officially report it to the government until 23 December.
This success was a good start for everyone who now held a stake in the licence, including Hydro. However, the interests Petronord passed to the Phillips group never yielded anything – which nobody could have predicted when the swap was made.
A press release on the Ekofisk discovery was finally issued on 2 June 1970. Meanwhile, the Norwegian government was seeking to secure a stronger involvement in NCS operations.
In deepest secrecy, the government bought up shares in Hydro on 9-15 December 1970 which ensured a majority state holding in the company.
This acquisition was officially approved by the Council of State on 22 January 1971, and gave the state a small stake in Ekofisk.[REMOVE]Fotnote: Hanisch, Tore Jørgen and Nerheim, Gunnar, Fra vantro til overmot?, Norsk oljehistorie, volume 1, Oslo, 1992: 165-166.
The Petronord deal had given Hydro an option to acquire 12 or 24 per cent of the group’s interest in a discovery.[REMOVE]Fotnote: Ibid. Holdings in PL 018 were therefore redivided again on 1 January 1971.
While the Phillips group retained its previous shares, Norsk Hydro Produksjon AS purchased interests from its Petronord partners which left it with 6.7 per cent of PL 018.[REMOVE]Fotnote: Elf Norge AS went down to 5.396 per cent, Total Norge to 4.047 per cent, Aquitaine Norge AS to 2.698 per cent, Eurafrep Norge AS to 0.456 per cent, Coparex Norge AS to 0.399 per cent and Cofranord AS to 0.304 per cent.
The next change in licensee composition occurred on 1 July 1977, when Elf and Aquitaine merged to form Elf Aquitaine Norge AS and thereby had an 8.094 per cent holding.
After the creation of Statoil in 1972, Norway’s state oil company built up a dominant position on the NCS with the right to a 50 per cent interest in new licences.
But many years were to pass before it secured a foothold in PL 018. That did not occur until 1988, when both international politics and major economic interests were involved.
The Troll gas sales agreement with a European consortium was the spark. Swapping licence interests between Statoil and France’s Elf and Total could provide the basis for this deal.
Estimated to contain 60 per cent of Norway’s gas reserves, Troll was proven in 1981 and declared commercial two years later. Nailbiting sales talks with continental gas buyers in 1985 were essential for developing the field.
These negotiations made slow progress, with the French particularly lukewarm. Something had to be done to persuade them to take a more positive view.
Elf and Total wanted licence interests in Troll and the Sleipner gas field. Could that be achieved, it might make the authorities in France more receptive to an agreement.
Statoil was therefore ready to enter into a swap which gave the French companies holdings in the two gas fields in exchange for a one per cent stake in Ekofisk.
Since it was difficult to estimate the value of this exchange, a net profit deal was also agreed – if revenues from one field exceeded a set value, the other party would be compensated.
The NOK 800 billion Troll gas sales agreement was entered into in May 1986, with the swap of licence interests coming into force on 1 April 1988.
This deal was considered important for securing French government approval of the sales agreement with Gaz de France, which was needed for a Troll go-ahead.[REMOVE]Fotnote: Reported by Ole-Johan Lydersen, a participant in negotiating the agreement, on 20 August 2019.
The advantage for Statoil of securing an interest in Ekofisk was the right this conferred to attend management committee meetings, providing it better insight into licence developments.
It gave the company control over the whole transport chain for gas exports, something which had concerned it ever since the Norpipe link from Ekofisk to Emden was installed in the 1970s.
During the 1980s, the Ekofisk Complex represented an important hub for Norwegian gas exports. The Ekofisk 2/4 S riser platform, operational from 1985, tied the Statoil-operated Statpipe transport system into Norpipe.
This installation was owned by Statoil but operated by Phillips. In 1998, the Statpipe-Norpipe line was relaid to bypass the Ekofisk Complex.
Another but less important reason why the state oil company wanted to know what was going on in PL 018 was the relationship between Tommeliten and Edda.
The former was a condensate field operated by Statoil which produced to the Phillips-operated Edda oil and gas field 12 kilometres away.
Following the oil price slump in 1985-86, Phillips – which had a 25 per cent interest in Tommeliten – became sceptical about developing it and withdrew from the project.
Statoil nevertheless secured acceptance in 1986 for a cheaper development solution based on subsea templates – which gave it useful experience with underwater technology.
Although Phillips had pulled out, it still wanted the Tommeliten wellstream to flow to Edda – not least because this field had proved half the size originally estimated.
That provided spare gas processing capacity. Moreover, the Tommeliten gas could be injected into the Edda reservoir to increase oil production.
The tie-in to Edda was implemented. According to Statoil, however, negotiating tariff terms between the Tommeliten and Ekofisk licences proved difficult.[REMOVE]Fotnote: Reported by Håkon Lavik, 15 August 2019.
Statoil’s interest in PL 018 changed again on 1 January 1999, when the government secured a five per cent stake for the state’s direct financial interest (SDFI) on the NCS.
Part of the Ekofisk II agreement with the Phillips group, this gave Statoil 5.95 per cent[REMOVE]Fotnote: Norwegian Petroleum Directorate, Facts, 2000. and resulted in a corresponding reduction in the holdings of the other licensees.
For the first time since 1968, Phillips saw its share of the licence reduced – but only from 36.96 per cent to 35.112 per cent.
Several reforms related to Norwegian state ownership in the petroleum sector were under way at this time. Plans for part-privatising Statoil to achieve greater flexibility internationally were initiated in 1999 and approved in 2001.
Another change was that administration of the SDFI, which had lain with the state company since 1985, was transferred in 2001 to a separate company called Petoro.
The latter took over various Statoil holdings in fields. Where the Greater Ekofisk Area was concerned, it acquired five per cent in PL 018 on 10 May 2001. That left Statoil with 0.95 per cent.
Crude prices slumped to a record low at the end of the 1990s, leaving the oil companies with acute profitability problems. They responded with mass redundancies and restructurings.
Larger entities provided greater strength in the market, improved cost control and better positioning in relation to the competition for reserves.
The turmoil which followed in the wake of these restructurings also affected the purchase and sale of interests in the Ekofisk licence.
Saga Petroleum, which acquired Norminol’s holding on 1 January 1995, disappeared on 11 January 2001. Its stake was taken over by Norsk Hydro Produksjon, which thereby rose to 6.654 per cent.
The French interests were gradually consolidated, with Eurafrep, Coparex and Cofranord being acquired in 1990 by Elf Rep, Elf Rex and Norminol respectively.
Elf Rep and Elf Rex then merged in the summer of 1992, and this company was incorporated in 1997 in Elf Petroleum – which thereby acquired 8.449 per cent of PL 018. Elf was merged into TotalFinaElf in the summer of 2000.
Just before Christmas that year, Total and Fina’s licence interests were merged with Total Norge’s holdings and thereby amounted to 31.87 per cent.
When these shares were then incorporated with TotalFinaElf’s, the result was a combined holding of 39.896 per cent. From 6 May 2003, TotalFinaElf was renamed Total E&P Norge AS.
This company then ranked as the largest licensee in PL 018, with the operator – now ConocoPhillips Skandinavia AS following the 2002 merger – in second place with 35.112 per cent.
Since Conoco had no stake in Ekofisk from before, its union with Phillips Petroleum did not contribute to increasing the company’s combined holding.
In addition, Italy’s Eni Norge AS took over Agip’s interests in the Greater Ekofisk Area on 15 December 2003.
After Petoro had acquired the bulk of Statoil’s interest in PL 018, a new change occurred in 2007 when the state company merged with Hydro’s petroleum and energy division.
From 1 October that year, StatoilHydro ASA held 0.95 per cent of the licence while StatoilHydro Petroleum had a 6.654 per cent interest.
These holdings were combined from 1 January 2009 into a 7.604 per cent stake held by StatoilHydro Petroleum AS. The company was renamed Statoil Petroleum AS on 2 November 2009.
The final change of name for this licensee occurred on 16 May 2018, when Statoil became Equinor. This was intended to signal that it embraced not only fossil fuels but also renewable energy sources such as solar and wind power.
A similar concept underlies the new company formed on 10 December 2018 by Eni Norge and Point Resources under the name Vår Energi AS.
“Vår” has a double meaning in Norwegian, denoting not only “Our Energy” but also springtime as a season of youth, freshness and greening.
On the 50th anniversary of the Ekofisk discovery in 2019, ConocoPhillips Skandinavia is operator for the field with a 35.11 per cent holding.
The other licensees at this time are Total E&P Norge AS (39.90 per cent), Vår Energi AS (12.39 per cent), Equinor Energy AS (7.60 per cent) and Petoro AS (five per cent).[REMOVE]Fotnote: Norwegian Petroleum Directorate fact pages, 13 August 2019.
|Date of award||1 September 1965|
|Duration until||31 December 2028|
|Original area (square kilometres)||1 752.704|
|Current area (square kilometres)||851.767|