Both exploration and production drilling are pursued in the Greater Ekofisk Area. As their names imply, the first type is involved in finding resources and the other in getting them out. Positioning production wells correctly is important for optimising recovery.
— The derrick man in the drill tower grabs hold of the stand. Photo: Transocean / Norwegian Petroleum Museum
The first wells drilled on Ekofisk were relatively primitive compared with today’s examples. They were good in terms of the available knowledge and equipment, but not up to “vacuuming” the reservoir. Drilling horizontally was not possible, for example. Once the well had reached an angle of 70 degrees from the vertical, it was earlier considered almost horizontal. Today, wells are drilled not only with horizontal sections but even angled upwards. The technological trend which made this possible began in the 1980s.
Drilling work on Ekofisk has been conducted by a number of different contractors over the years. Their personnel were responsible for operating the actual rig. The companies used to begin with remained, but changed their names. A case in point was Moran Brothers, which became Morco, Norcem Drilling, Aker Drilling and finally Transocean Drilling during its time on the field.
In 2001, drilling contractors Deutag Norge Drilling, Smedvig Offshore and Mærsk Drilling – now Mærsk Contractors – were involved in the Greater Ekofisk Area (GEA). They had some 500 people working for Phillips in the GEA or on land.
Modern computer technology and fibreoptic cables today allow the operator company to follow offshore activities from its offices in real time.
Dowell, Halliburton og BJ Services have been used for cementing services, while Eastman, Sperry Sun or Target Drilling (part of Aker Drilling) provided directional drilling. Pathfinder was engaged in the latter activity in 2001.
Other drilling-related contractors have included Schlumberger or Atlas for logging and Weatherford for casing services, while Milchem, Ceca, MI and Anchor Drilling Fluids have been among those involved with drilling fluids.
Drilling operations manager
A distinctive feature of the Phillips organisation in the 1970s and 1980s was the presence of a central drilling operations manager for all the installations. Employed by the company, they served on Ekofisk 2/4 H in a coordinating role. They collated reports from all the drilling supervisors and passed them on to the drilling department ashore.
The drilling team was led by the Phillips supervisor. During the early years on Ekofisk, the company only had a single person in this role on board who was on call around the clock. This meant they had a bed in their office and lived and worked there. Following the Bravo blowout in 1977, however, a junior drilling supervisor was introduced who worked the night shift – and was usually called the “night man”. Members of the drilling team were drawn from several contractors specialising in various services. They included the toolpusher, drillers, derrickmen, roughnecks and roustabouts, with support from electricians, mechanics, materials providers and – initially – crane operators.
The toolpusher is the head of the drilling team, where everyone is employed by the contractor which has been hired for the specific platform. This person supervises the crew and ensures compliance with routines – particularly matters related to safety. Drilling must be conducted as specified in the plans drawn up by the operator in Tananger and approved by the Norwegian Petroleum Directorate.
In close consultation with the drilling supervisor, the toolpusher monitors, collects and registers technical drilling data and stays in constant touch with the operator’s drilling operations manager on Ekofisk. Engineers are called from land for special operations.[REMOVE]Fotnote: Kvendseth, Stig S, Giant Discovery. A History of Ekofisk Through the First 20 Years, 1988. The toolpusher can also relieve the driller during lunch breaks and participates to a varying extent in the work being done.
Driller (drilling and maintenance operator)
The driller is responsible for day-to-day work in accordance with the toolpusher’s instructions. From the driller’s cabin, they operate the equipment used to drill wells. That includes maintaining control of the various drilling parameters, such as pressure, drillability, torque and mud flow, and ensuring that everything functions as it should. When Norwegian drilling contractors entered this business, they extended the drilling team with the addition of an assistant driller function.
One trend from early exploration drilling off Norway down to the present time has been that less and less of overall rig time is devoted to running the drill string in and out the well. Not only is the bit not replaced as often as before, but it has also become possible to carry out downhole measurements during drilling. Although the whole string must still be pulled to replace the bit, the latter is now more durable thanks to improved knowledge of how it wears and the improved quality of this product.
Today, much of the work is conducted from a modern driller’s cabin with chairs designed on physiological principles to be occupied for 12 hours. The drilling equipment has become computer-operated with the aid of the joystick and keypads on the arm rests.
Much of the work previously done on the drill floor by the roughnecks, roustabouts and derrickmen has been automated through the use of robots.
Drilling represents the main activity up to the stages of completion for production, test output, pressure support and/or well plugging. A qualified drilling and maintenance operator should be able to participate in all phases of drilling, including managing and maintaining drilling mud and mud systems and doing first-line maintenance on pressure control systems and equipment.
Directional drilling and MWD
Directional drilling of production wells makes it possible to drain more extensive areas of an oil or gas reservoir from a single installation. This technology for diverting the well from a vertical path began to be developed in the late 1980s. Specialists in utilising it are usually operator company employees.
The method starts out like normal rotary drilling, but then transitions to a phase where a specified angle from the vertical is built up. During this stage, the drill string is not rotated. The bit is turned instead by a turbine installed immediately behind it, with the vanes driven by the mud pumped down the string. Rotary drilling resumes once the desired angle is reached.
Horizontal drilling is a further development of the directional approach which makes it possible to reach all parts of a reservoir. This method is important in some formations where the oil may be located in thin layers, and allows the recovery factor for the field to be substantially increased.
Baker Hughes Inteq has developed a solution called AutoTrack, where the bit is guided by a steerable system which allows direction and angle to be adjusted continuously while drilling. Sensors on the drill string analyse the rocks being drilled, and computerised commands then steer the bit into the correct geological structures.
A measurement while drilling (MWD) engineer uses the equipment required, and processes, presents, evaluates and quality-assures the data acquired and sent back to the surface. Directional measurements provide information on the direction (azimuth) and angle (inclination) of the well to help the driller steer the well along its planned path.
A number of different sensors measure various aspects of the formation being drilled. Presented as curves in the logs, these data are used in formation evaluation. This means they are interpreted to determine the type of rocks involved (such as sandstone, claystone or carbonates), what they contain (water, oil or gas) and other properties such as permeability.
The logs are interpreted both by the MWD engineer and by geologists offshore, as well as petrophysicists and geological specialists on land. Along with analyses of the drill cuttings – rock chips removed from the well – collected by the mud logger, these data provide a good picture of the formation surrounding the well.
MWD information is often used actively by geologists to keep the well concerned in the desired formation layer. This is known as “geosteering”. Measurements transmitted to the surface can be utilised to optimise well parameters and reduce damage to the downhole equipment. Pressure readings could also indicate if the well is being cleaned properly – whether cuttings are being transported out or are accumulating downhole and may cause equipment to get struck.
Introducing AutoTrack from the mid-1990s allowed the string to be rotated and steered simultaneously and opened completely new opportunities in directional drilling and geosteering. This is an example of the rapid advances made with MWD equipment in recent decades. New technology and applications for the information acquired are continuously being developed.
This person had two main jobs – participating in tripping (pulling out the drill string and running it back in) and ensuring that the drilling mud was correctly blended. During tripping, the derrickman worked in the derrick with the driller and roughnecks on the drill floor. The string was pulled out of the well and broken down into stands – lengths of three drill pipes screwed together. The derrickman’s job was to receive these stands and secure them in a “fingerboard” high up inside the derrick, and then to release them when the string was to be made up again.
This was fairly heavy work, conducted from a small platform measuring a square metre located 30 metres above the drill floor. He had to lean over the edge, with a rope to prevent him falling. Mechanisation and automation of drill-floor work began in the mid-1970s. That include mechanising the derrickman’s duties during tripping. He now controls a mechanical pipehandling system which grips each stand and positions it in the fingerboard as the string is pulled out – and vice versa.
When the derrickman is not involved in tripping, he works in the mud room to ensure that drilling fluid is always blended in accordance with the drilling engineer’s instructions.
The roughnecks did the heavy manual labour on the drill floor and the cellar deck below. When making up and breaking out drill pipe, they attached the tongs used for this work by the driller.
At the beginning of the 1970s, the roughnecks went over to using a “spinner”, a hydraulic device used to screw together and unscrew lengths of drill pipe.
Two-three roughnecks worked on setting the slips – a moveable wedge-shaped locking device which weighs between 40-50 kilograms. This holds the drill string in the rotary table when it is not suspended from the
derrick’s travelling block (crane).
The roughnecks were also responsible for cleaning and maintenance on the drill floor (which was washed with caustic soda and diesel oil). In addition, they could be drawn in to help the service companies in their various activities. Various equipment units were installed and readied by the roughnecks on the cellar deck under the supervision of their superiors or specialists. This work included installing various sizes of blowout preventers (BOPs). The cellar deck was also where risers were attached.
Various dimensions of casing were hung off, Xmas trees (valve assemblies) installed and high-pressure hoses attached to conduct hydrocarbons to the outside of the rig during testing. Otherwise, the roughnecks helped to blend drilling mud and to keep an eye on the shale shaker – a vibrating screen which cleans mud returning from the well.[REMOVE]Fotnote: Kvendseth, Stig S, Giant Discovery. A History of Ekofisk Through the First 20 Years, 1988.
A lot of this work is now being handled by an “iron roughneck” – a robot controlled by the driller from their cabin. But the human roughnecks must still move about the drill floor – partly to lubricate various items of equipment.
Cementing forms part of the whole process from exploration drilling, via completion for production, to subsequent downhole maintenance work. Well operators involved with cementing are the last people to leave a platform after the wells have ceased production and been plugged with cement. The cementer’s job is varied and makes big demands on theoretical and practical skills. It can be split into three main areas: cementing, pressure testing and use of downhole tools.
Drilling a well starts with large bits (75-90 centimetres in diameter), which are progressively replaced with smaller ones as the borehole advances. The smallest is usually 15 centimetres.
When changing to a smaller bit, the whole drill string is pulled out and the borehole is lined with steel tubes called casing. A casing string can be several hundred metres long.
Before drilling resumes, cement is pumped into the annulus (gap) between the well wall and the casing in order to anchor the latter solidly in place. The cement prevents the borehole from collapsing, and stops any uncontrolled flow of oil and gas reaching up to the surface outside the casing string.
Cementing is normally a straightforward job. The volume to be filled gets calculated in advance, and all that then remains is to pump down that quantity. Since the work has to be done quickly, being well prepared is important. The person leading the cement job previously had to know the pump more or less intimately. This pump has to work efficiently (in terms of the number of pump strokes) the whole time in order to be certain that the whole annular space around the casing is cement-filled. Problems would otherwise arise in the well later.
Today’s cementing pumps are electrically powered and their pumping efficiency can be determined with the aid of instruments. Drilling mud is needed to pump cement. When changing from one tank to another, valves have to be closed and opened. That creates a pressure.
As the well advances, casing is run into it and cemented in place. The diameter of this steel tubing diminishes with increasing borehole depth. Casing is intended to prevent the well from collapsing, and it also provides an important return channel for the mud which has been pumped down inside the drill string. In addition, it isolates problematic zones in the rock formations – such as areas where the pressure is particularly high or low.
Casing is delivered by specialist companies, which calculate how many lengths of each tube type will be required for a well and ensures that the equipment is in place at the right time. The casing operator handles the tubes, but this job has become more automated in recent years.
Mud loggers and geologists
The job of the mud logger or engineer is to acquire well data from instruments located either on the surface or down the borehole in order to determine pressure in the rock’s pores. Parameters monitored include well depth, drilling speed, weight on the bit, rotation speed, mud density, gas content in the mud, and how fast drill cuttings move from bit to rig.
Continuous observation of this information can identify unstable downhole conditions, and possibly prevent accidents such as uncontrolled blowouts or a well collapse which traps the drill string. These parameters can also indicate geological variations. If drilling speed suddenly picks up while drilling through a shale layer, for example, this could mean that the bit has entered sandstone – which is a reservoir rock. Among the mud logger’s jobs are the collection and washing of drill cuttings for analysis by the rig’s geologist in order to obtain an overview of the rocks drilled through.
Logging involves running instruments into the well in order to measure various physical properties of the reservoir strata or their contents (oil, gas or water). Examples of the information sought include natural radioactivity, rock density, the speed of sound, electrical resistivity and temperature.
Logging can be conducted under various conditions:
logging while drilling (LWD) – using instruments attached to the drill strong
open-hole logging – after drilling but before the casing and production tubing has been set
production logging – to measure such parameters as fluid flow from various parts of the reservoir.
If logging and possible rock cores extracted from the well show that some of the rock strata deep below ground contain oil and gas, the usual practice is to conduct a production test. This is done by allowing the oil and/or gas to flow up to the surface under controlled conditions. Such parameters as how fast the well flows are measured and samples of the oil/gas taken.
The work is usually led by a reservoir engineer, and normally takes place after exploration drilling ends. The well is then plugged with cement, the seabed cleaned up, and the site left.
Published 31. July 2019 • Updated 25. October 2019
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.
Published 15. October 2019 • Updated 15. October 2019
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.
by Gunleiv Hadland, Norwegian Petroleum Museum
The 2/4 VB subsea installation began injecting water in May 2013, three kilometres south of the Ekofisk Complex. It formed part of the Ekofisk South project approved by the Storting (parliament) in 2010.
Ekofisk 2/4 VB was a part of the Ekofisk South project
Producing May 16. 2013
Also called “Victor Bravo”
— Ekofisk 2/4 VB (Victor Bravo) lowered into the sea. Photo: Bob Bartlett/ConocoPhillips
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.
Published 23. September 2019 • Updated 7. February 2020
Confusion can easily arise over the terms used in connection with Ekofisk, where the Greater Ekofisk Area (GEA) is a collective designation for a cluster of no less than eight fields. The largest of these is Ekofisk itself.
— Older poster showing The Greater Ekofisk area. Illustration: ConocoPhillips/Norwegian Petroleum Museum
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.
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.
Source rock – Draupne
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.
Cretaceous reservoir rock – Tor formation
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.
Palaeocene reservoir rock – Ekofisk formation
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.
Porosity and permeability
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.
Cap rock and trap formation
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 therebycreatedtrap 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 – ArvidNøttvedt – Kristin Rangnes (ed.’s), The Making of a Land, NGF 2008
Published 23. September 2019 • Updated 16. October 2019
by Kristin Øye Gjerde, Norwegian Petroleum Museum
The question of who “owns” Ekofisk is not straightforward. In simple terms, however, the field and the rest of Norway’s continental shelf (NCS) belongs to the Norwegian state. This was determined on 14 June 1963, when the Storting (parliament) passed the Act Relating to Exploration for and Exploitation of Submarine Natural Resources. This permits licences to be awarded on certain terms.
— The Norwegian state "owns" Ekofisk, but many companies have had the rights to explore and exploit the natural resources at Ekofisk.
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.
First licensing round, 1965
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.
Statoil in and out
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.
Total becomes biggest licensee
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.
Statoil merges with Hydro
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.
Licence interest in 2019
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
31 December 2028
Original area (square kilometres)
Current area (square kilometres)
Published 23. September 2019 • Updated 7. October 2019
Åm was born at Årdal in the Sogn district of western Norway in 1944, and grew up in Oppdal and Volda/Ørsta where he proved an able pupil at school.
He opted to study mining engineering at the Norwegian Institute of Technology (NTH) in Trondheim, graduating with honours in 1967.
Åm’s first job was with the Norwegian Geological Survey (NGU), again in Trondheim, where he worked and conducted research for six years.One of his jobs was to interpret aeromagnetic measurements of sub-surface rocks made from the air, which provide valuable information on geology and prospects for finding petroleum.In a series of publications, he described the big sedimentary basins identified in the Skagerrak between Norway and Denmark and in the Norwegian and Barents Seas.
He joined the Norwegian Petroleum Directorate (NPD) in 1974, serving as a section head in the resource department and a principal engineer in the safety department.
That was followed by three years with Statoil, where he became the state oil company’s first vice president for research and development.His appointments at the time included chairinga research programme on offshore safety, which led to legislation enacted by the Storting (parliament) and a bigger research effort.
Åm secured a job with Phillips in 1982 and was soon sent to the head office at Bartlesville in Oklahoma to get better acquainted withthe company and its corporate culture.
After a year in the USA, he returned to thecompany’s Tananger office outside Stavanger and became the first Norwegian to serve as offshore manager for the Greater Ekofisk Area (GEA).
That put him in charge of 23 platforms, with responsibility for the waterflooding programme as well as the project to jack up a number of the installations.These major developments extended the producing life of the GEA and sharply increased estimates for recoverable reserves from its fields.
Åm led this work during difficult times, with low oil prices and the need to implement cost savings and overcome substantial financial challenges.As if that were not enough, he also taught at the University of Bergen from 1985 to 1990 as an adjunct (part-time) professor of applied geophysics.
First Norwegian chief executive
After heading operations in the Permian and San Juan Basinsat Odessa, Texas, from 1988-91, Åm became the first Norwegian president and managing director for Phillips Petroleum Norway.
That put him in charge of 3 000 employees in the GEA as well as in Tananger, Oslo, Teesside and Emden. This was when a redevelopment of Ekofisk was planned, along with the future cessation and removal of old platforms.[REMOVE]Fotnote: https://www.fylkesmannen.no/globalassets/fm-rogaland/dokument-fmro/felles-og-leiing/brev-og-artiklar/fm-tale-til-knut-am.pdf
By 1996, Åm was back in Bartlesville – now as vice president and head of all exploration and production in Phillips. He stayed in that job until retiring in the USA during 1999.
Offices and committees
But his working life did not end there. Appointments from 1999 to 2007 include membership of the Statoil board – and many similar posts can be mentioned.
Åm has been president of the Norwegian Geological Council and the Norwegian Petroleum Society, and chair of the Norwegian Oil Industry Association (now the Norwegian Oil and Gas Association).
He led the exhibition committee of the 1996 ONS oil show in Stavanger, and has chaired Bergen’s Christian Michelsen Research institute as well as the industrial council of the Norwegian Academy of Science and Letters.
In addition to chairing Hitec ASA, he has been a director of several technology companies.
Mention must also be made of the improved recovery committee appointed by the Ministry of Petroleum and Energy with Åm as chair.This produced a report in September 2010 which presented 44 specific measures for improving the recovery factor on the Norwegian continental shelf (NCS).
Through his work and many appointments, Åm has been acclaimed fora combination of expertise, creativity and determination. He also demonstrated the ability to tackle the requirements of Norway as a nation as well as the industry and its employees – not least with regard to the working environment and safety in a demanding and risky offshore industry.
In retirement, Åm is an optimist – with regard to the climate as well. “I’m very concerned with nature, but believe we should extract the resources it’s given us,” he told Otium in 2016.
“Norway could have a long and good future in the oil and gas industry if people give it more support. Exploring for new deposits is important, but we should also seek to achieve a far better recovery factor from both new and existing fields.”
“You can naturally concentrate on life’s negative aspects. Then everything’s simply awful. I think you’ll be a far happier person if you prefer to see the positive side of life. I call that self-motivation. We need more of that in the energy sector.”[REMOVE]Fotnote: https://api.optimum.no/sites/default/files/PDF/optimum-magasinet-2016.pdf
Published 21. October 2019 • Updated 21. October 2019
Different systems for rotating personnel between work and leisure functioned in parallel on the drilling rigs during the early years of oil exploration in the Norwegian North Sea. The most common practice was nevertheless one week on and one off. To get a holiday, people carried on working offshore until they were entitled to three weeks free in one go.
However, this arrangement proved impractical – particularly for workers who going offshore or returning home on a Saturday or Sunday. They never got a full weekend off. To stagger such change-overs, the schedule was extended to eight days offshore with eight days free. One work period in five was also dropped, so every fifth free spell was 24 days long.[REMOVE]Fotnote: This gave a working time which averaged 38 hours per week and 1 824 hours per year after holidays. That corresponded to shift work on land.
When Norway’s Working Environment Act (WEA) came into force in 1977, the permitted length of a continuous shift on land was cut. But there was no assurance that this would be applied offshore. In its original form, the Act did not permit the 12-hour working day normal on all offshore installations. So amendments were needed to adapt the legal provisions to fixed platforms.[REMOVE]Fotnote: The Act specified that working time was 36 hours over seven days for work carried out around the clock throughout the week. That represented 1 877 hours a year on average. Adjusting this for four weeks of holiday gave a net working time of 1 733 hours.
The Norwegian Petroleum Directorate argued that reducing working time offshore was impractical, with the “special character” of the oil industry requiring exemptions.[REMOVE]Fotnote: Ryggvik, H, 1999, “Fra forbilde til sikkerhetssystem i forvitring: Fremveksten av et norsk sikkerhetsregime i lys av utviklingen på britisk sokkel”, Working Paper, Volume 114, Centre for Technology and Culture, University of Oslo, printed edition. Oslo: Centre for Technology, Innovation and Culture (TIK), University of Oslo: 16. As early as 1975, however, Ekofisk operator Phillips Petroleum had agreed to working hours for its own personnel which accorded with the provisions proposed for the new Act. A royal decree of 9 July 1976 extended the existing Worker Protection Act, with certain exceptions, to the fixed installations offshore on a temporary basis.
The WEA was then applied to these facility in 1977.[REMOVE]Fotnote: Ryggvik, H, 1999, “Fra forbilde til sikkerhetssystem i forvitring: Fremveksten av et norsk sikkerhetsregime i lys av utviklingen på britisk sokkel”, Working Paper, Volume 114, Centre for Technology and Culture, University of Oslo, printed edition. Oslo: Centre for Technology, Innovation and Culture (TIK), University of Oslo: 18. This meant that offshore workers had their working time regulated and acquired legal safeguards against unfair dismissal. After long discussions, the North Sea schedule was by and large established as two weeks working offshore and three weeks free on land.
But the WEA was not applied to floating units such as rigs, and working time in that part of the oil industry continued to be regulated by Norway’s Ship Labour Act.
An extra day
Norway’s legislation on paid holidays was amended in 1981 to give everyone a legal right to four weeks and one day off. The latter was nicknamed the “Gro Day” after Gro Harlem Brundtland, the Labour premier of the day. This meant the two weeks on/three weeks off schedule now imposed too many working hours. It was decided that the extra would be compensated as 25 hours of overtime per year.[REMOVE]Fotnote: Working time was reduced from 1 752 to 1 727 hours.
Agreement was reached in the 1986 collective pay negotiations on a 7.5-hour normal working day and a 37.5-hour week. Personnel both on land and offshore working a continuous shift also had their weekly hours cut 33.6.[REMOVE]Fotnote: Net working hours after deducting holidays were reduced from 1 752 to 1 727. To comply with these new terms, the offshore schedule was altered to two weeks at work, three weeks ashore, two weeks at work and four weeks on land.
When the Gro Day was introduced in 1981, the Labour government originally proposed introducing a full week’s extra holiday in stages over three years. But that failed to materialise. In 2000, the Norwegian Confederation of Trade Unions (LO) proposed a fifth holiday week for all employees, which would thereby reduce the number of hours in a work-year.[REMOVE]Fotnote: That involved an additional four free days of 7.5 hours offshore (32 hours). The hours to be worked were then reduced from 1 612 to 1 580. That demand was accepted, and most workers could thereby enjoy five weeks off. This naturally had consequences offshore, but implementing it there was not a straightforward matter.
A schedule of two weeks at work and three/four weeks at home had been 19 hours short of a normal work-year. That was overcome by deducting this time from pay or leaving the first 11 hours of overtime unpaid.[REMOVE]Fotnote: Sande, Leif, “Arbeidstiden på sokkelen”, Sysla – meninger, 11 March 2015.
The new holiday deal meant that an offshore worker would be doing 12 extra hours per year. This was initially paid as overtime, which the unions found unsatisfactory. They demanded the full holiday entitlement awarded to everyone else through the introduction of a schedule of two weeks on and four off. In 2002, the Norwegian Oil Industry Association (OLF – today the Norwegian Oil and Gas Association) allowed local deals under the offshore agreements to adopt this two-four scheme. All the companies subject to these agreements introduced the new schedule. ConocoPhillips was among the operators to do this, in its case covering the Greater Ekofisk Area.
However, the two-four system meant workers were falling short of a work-year by 122 hours.[REMOVE]Fotnote: Working 12 hours a day for 14 days, followed by four weeks off, means that an employee works 168 hours every six-week period. That adds up to 1 460 hours per year. Annual pay was thereby cut by 7.71 per cent to take account of the reduced time worked.[REMOVE]Fotnote: Norwegian Official Reports (NOU) 2016:1, Arbeidstidsutvalget — Regulering av arbeidstid – vern og fleksibilitet. https://www.regjeringen.no/no/dokumenter/nou-2016-1/id2467468/sec16. Other conditions were also set on Ekofisk. The whole offshore organisation was to be reviewed to find efficiency gains, and the agreement specified that the change would not lead to an increase in the workforce.[REMOVE]Fotnote:Pioner, “2-4-ordningen innføres”, March 2003.
Published 21. October 2019 • Updated 21. October 2019