person Norwegian Petroleum Museum
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
© Norsk Oljemuseum

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.

Roughnecks at work. Photo: ConocoPhillips/Norwegian Petroleum Museum

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.

Phillips' drilling operations manager was stationed on Ekofisk 2/4 H. Photo: Husmo Photo/Norwegian Petroleum Museum

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.

Drilling supervisor

Drilling supervisor Ken Jetton. Photo: Husmo Foto/Norwegian Petroleum Museum

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)

arbeidsliv, boring, borer,
Previously, the driller operated the equipment from the drillers cabin. It was important to always have a good grip on the brake leveler. Photo: Husmo Photo/Norwegian Petroleum Museum

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

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On the drillfloor. Photo: ConocoPhillips/Norwegian Petroleum Museum

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.

Cementers/well operators

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.

Ekofisk 2/4 B, boring,
Cement and mud tanks at Ekofisk 2/4 B. Photo: Kerem Floor/Norwegian Petroleum Museum

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.

Casing operator

The drillfloor. Photo: ConocoPhillips/Norwegian Petroleum Museum

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.

Well loggers

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.

Well testing

var med på funnet av Ekofisk, engelsk, boring,
Flare at Ocean Viking. Photo: Unknown/Norwegian Petroleum Museum

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
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Base operations

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All the supplies needed to ensure that the offshore platforms can do their job of producing oil and gas pass through the base at Tananger outside Stavanger. Warehouse operation at the base covers five main functions: goods reception, spare parts store, accounting, pipe store and goods dispatch.
— Phillips is about to establish themselfs at the Norsco base,1972 Photo: Norsk fly og flyfoto/Norwegian Petroleum Museum
© Norsk Oljemuseum

Dusavik base, 1966-73

The contract for Phillips’ first supply base in Norway was signed with Stavanger-based tanker company Smedvig Tankrederi on 25 April 1966.

It covered the hire of outdoor storage and quay areas as well as a new combined warehouse and office building which was modest by today’s standards.

Located at Dusavik just outside Stavanger, Phillips ranked as the first tenant at what was to become one of the two big offshore supply bases in the district.

The drilling operations which led to the discovery of Ekofisk were served from Dusavik. While the lease ran until 1981, it only functioned as the main base for the Stavanger area until 1973.

Rapid organisational growth made the premises in Dusavik too small by that year, and additional space was obtained by taking a clearly creative approach.


So Phillips secured premises in a soap factory, a Chinese restaurant and the bar and other areas of Stavanger’s Alstor Hotel. And many of those hired in 1973 are sure to remember that they were interviewed at the city’s Atlantic Hotel.

basevirksomhet, engelsk,
Hotel Atlantic. Photo: Asbjørn Jensen/Norwegian Petroleum Museum

Phillips base, 1973-81

Some activity had been established at the Aker Norsco base in Tananger during 1972, but it was not until the autumn of 1973 that the headquarters for Ekofisk was transferred from Dusavik.

basevirksomhet, 1976, engelsk,
The "H-building" (lower right corner), at Tananger. Photo: Unknown/Norwegian Petroleum Museum

That occurred with the occupation of the H Building at Tananger, where Phillips had signed a lease with the base company the year before.

This covered the hire of outside storage areas, quays, warehousing, a canteen and an office building – a complete supply base. All the buildings were purpose-built.

The lease gave Phillips an option to acquire the whole facility at a later date, which the company duly exercised in the summer of 1979.

To varying degrees since 1973, the operator has needed to lease both warehousing and offices from Aker Norsco – partly in temporary structures and partly in permanent premises.

From 1973 to 1976, exploration operations with the Ocean Viking rig continued to be run from the Dusavik base. The charter then expired, and remaining activities were moved to Tananger.

Lack of space at the latter premises meant that the training department was transferred to Dusavik and remained there until the lease expired in 1981.

Similar shortages meant extra premises had to be leased around Stavanger. This growing problem led to plans being laid from 1978 for a significant expansion at Tananger.

Phillips base since 1981

The new building was gradually occupied from December 1980 and formally opened in August 1981. Once it had been finished, the old H Building was completely refurbished to the same standard.

This expansion marked a significant improvement in working conditions for many employees, and helped to enhance efficiency by gathering much of the organisation under one roof.

The development was originally intended to meet all needs for office space, with the exception of the project department’s requirements.

However, it became clear even before the new building was occupied that this goal would not be reached. But it proved possible by and large to cease hiring space outside Tananger.

Løfteskipet Uglen i aksjon ved Norscobasen i juli 1980. Foto: NOM/Norsk Fly og Flyfoto Løfteskip, Uglen, Norscobasen,1980, phillips, sola, olje, inntekter
The crane barge Uglen in action at the Norsco base in July 1980. Photo: Norsk Fly og Flyfoto/Norwegian Petroleum Museum

To deal with developments in the supply services for Ekofisk, Phillips entered into a contract with Aker Norsco on the construction of a larger and more modern warehouse.

This building and associated offices were occupied in late 1982/early 1983, and were regarded as a model example for the purpose.

The waterflooding project on Ekofisk received a green light in 1983, which created the need for more office space to accommodate the project department.

Since a quick start was important, the new building in Tananger was ready three months after the contract with Aker Norsco had been signed.

Premises utilised by Phillips in the Stavanger area by 1988 comprised 20 000 square metres of offices, 10 000 square metres of storage space and 850 square metres of workshops. In addition came the offices at Munkedamsveien in Oslo.

Another new building opened at the Tananger base in July 1996, which meant the whole workforce was assembled on one site in two connected premises.

While the old offices covered 14 000 square metres, the new seven-storey building has an area of 11 300 square metres and provides 420 additional office spaces.

It also accommodates a 600-square-metre conference centre, as well as a gym and a swimming pool measuring eight by 12.5 metres in the basement.

The Tananger base was sold in July 1996 to Aker Base, including buildings, furniture and fittings, and the deepwater quay.

Activities at the base

The Phillips base at Tanager plays a central role in operating the Greater Ekofisk platforms. All necessary supplies allowing these installations to do their job pass through it.

Warehouse operation at the base covers five main functions: goods reception, spare parts store, accounting, pipe store and goods dispatch.

The spare parts store is managed with the aid of a comprehensive computer system with full information for offshore personnel to log on directly and check availability.

When goods are received at the warehouse, they are marked with a purchase number and all data concerning the order is entered. They are packed out, checked and sent for shipment offshore.

The workshop, located in the same building as goods reception, deals with such jobs as mechanical repair of diesel engines, pumps, valves, heat exchangers and compressors.

It also repairs base equipment, like forklift trucks, cranes and fire-extinguishing systems. In addition, the shop produces pipework, pressure tanks and other structural welding.

The head office for Phillips’ activities in Norway stands alongside the supply base for the platforms in the Greater Ekofisk Area.

basevirksomhet, engelsk,
In November 2004 ConocoPhillips opened its OOC (Onsore Operation Center) at Tananger. Photo: Kjetil Alsvik/ConocoPhillips
Published 29. July 2019   •   Updated 22. October 2019
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The oil and gas terminals

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Oil and gas from the Greater Ekofisk Area is piped to Teesside in the UK and Emden in Germany respectively, where the pipeline terminals formed part of the field development. ConocoPhillips still operates the oil terminal in Teesside, while the facility in Emden has been taken over by Norwegian state-owned company Gassco.
— Gassterminalen i Emden. Foto: Husmo Foto/Norsk Oljemuseum
© Norsk Oljemuseum

Oil terminal in Teesside

Olje- og gassterminalene, engelsk,
Teesside terminal. Brian Henderson Thynne takes samples of refrigerated propane. Photo: Husmo Foto/Norwegian Petroleum Museum

The terminal at Teesside in north-east England receives oil and natural gas liquids (NGL) by pipeline from the Ekofisk field. It comprises stabilisation, NGL fractionation, storage tanks for crude oil and an export port.

After arriving through the Norpipe Oil line, crude and NGL are separated and the oil goes through a stabilisation process before reaching the 10 storage tanks, which each hold 750 000 barrels.

The NGLs go to the fractionation facility, with a daily capacity of 64 000 barrels, for separation into methane, ethane, propane, and normal and iso butane.

While the methane (natural gas) is used to fuel the plant, the other products (now known as liquefied petroleum gases – LPG) are made liquid by cooling and stored for export by sea.

One reason for the choice of Teesside as the landfall for the Ekofisk pipeline was the opportunity it offered to install deepwater quays.

The terminal has four of these, with those for crude oil able to handle tankers up to 150 000 deadweight tonnes. The LPG quays can accept carriers loading as much as 60 000 cubic metres.

Two of the crude oil quays lie on the main channel of the River Tees, while the others have been installed in dredged docks.

Gas terminal in Emden

olje- og gassterminalene, engelsk,
Photo: Husmo Foto/Norwegian Petroleum Museum

Gas arriving at the Emden terminal from the Ekofisk Complex enters nine parallel treatment trains for cleaning, metering and onward distribution to the buyers.

The North Sea gas is very clean, and needs only limited treatment to remove small amounts of sulphur compounds using an absorption process. Impure molecules from the gas accumulate on the surface of small particles, which act as filter spheres.

Each of the nine trains comprises four process columns and a process oven. The gas enters the top of a column and leaves through the base after passing through the filter spheres.

That leaves the gas ready for sale, and it is piped to the fiscal metering station before entering the buyer receiving pipelines and distribution network.

Three separate commercial pipeline systems connect to the terminal, operated by Ruhrgas, BEB and Gastransport Services (previously Gasunie) respectively. They pipe the gas away on behalf of the gas buyers.

The Norsea Gas Terminal in Emden was officially opened in September 1977 by Norwegian industry minister Bjartmar Gjerde and Phillips executive Gordon Goerin.

Ranking as the first gas sales deal for the Norwegian continental shelf, the Ekofisk agreement paved the way for later contracts covering other fields off Norway.

Regularity at the Emden terminal has been very high, with its own equipment never causing shutdowns. Maintenance takes place when other parts of the system are off line.

The terminal has a daily capacity of about 2.1 million cubic feet of gas per day.

Gas transport restructured

Norpipe AS owned the gas pipeline from Ekofisk to Emden until the transport system for the Norwegian offshore sector was restructured at 1 January 2003.

Norsea Gas A/S furthermore served as the formal owner of the Emden facility, with Phillips Petroleum and then ConocoPhillips as operator for both pipeline and terminal.

olje- og gassterminalene,
Teesside gas terminal. Photo: Husmo Foto/Norwegian Petroleum Museum

Since 2007, Norway’s state-owned Gassco company has been responsible for technical operation of the facilities on behalf of their owners.

That included operator responsibility for the H7 and B11 booster platforms along the gas pipeline, which were shut down in 2007 and 2013 respectively and have since been removed.

The Gassled partnership is a project collaboration embracing 10 companies which collective own large parts of the gas infrastructure on the Norwegian continental shelf (NCS).

A substantial proportion of Norway’s gas deliveries to Germany continues to arrive at the Emden terminal, including the volumes piped from Ekofisk.

Preliminary planning for a new terminal in the German port began in 2011, with Gassled taking the investment decision for this development in the autumn of 2012.

Construction work began in the following year, with the new facility being built on an unused part of the existing terminal site.

The new terminal has not expanded export capacity. But its functionality is well adapted to future processing needs for fields in the Greater Ekofisk Area and other parts of the NCS sending gas through the Norpipe system.

It was officially opened on 24 May 2016 by Elisabeth Aspaker, the Norwegian government minister for the EU and the European Economic Area. That closed a chapter in Ekofisk’s history.

Source: ConocoPhillips Norge

Published 29. July 2019   •   Updated 12. October 2019
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Two export pipelines run from the Ekofisk Complex. The one for gas has an external diameter of 36 inches and extends 443 kilometres to the German coastline. With an external diameter of 34 inches, the oil pipeline runs for 354 kilometres to Teesside in north-east England.
— Gas pipes at Ekofisk. Photo: Husmo Foto/Norwegian Petroleum Museum
© Norsk Oljemuseum

In addition to ConocoPhillips’ own production from Ekofisk, these pipelines carry gas and oil from the company’s fields in the UK sector and from other fields on the Norwegian and British continental shelves.

The three fields in the Greater Ekofisk Area are also tied together by pipelines.

Oil pipeline to Teesside

rørledningene, engelsk,
Pipes and oil tanks at the Teesside plant. Photo: ConocoPhillips/Norwegian Petroleum Museum

The pipeline linking Ekofisk with the terminal for oil and natural gas liquids (NGL) at Teesside on the north-east English coast became operational in October 1975.

Pumps raise the pressure of the oil and NGL before they start their journey to land. Two pumping stations – 37/4 A and 36/22 A ­– originally stood along the pipeline to maintain this pressure, but have now been disconnected and removed.

The pipeline was installed with the ability to carry a million barrels per day. However, that much capacity has never been required.

In the UK sector, a 24-inch pipeline has been tied in with a Y connection to receive input from several British fields – including the J block developments operated by ConocoPhillips.

Output from the Greater Ekofisk Area is supplemented by crude from Valhall, Hod, Ula and Gyda heading for Teesside, optimising pipeline utilisation and thereby boosting value creation.

The pipeline is owned by Norpipe Oil AS and operated by ConocoPhillips.

Gas pipeline to Emden

rørledningene, engelsk,
Sandbags and gravel were used to cover Norpipe to Emden. Photo: Unknown/Norwegian Petroleum Museum

This pipeline became operational in September 1977. The starting pressure of around 132 bar is provided by compressors on the Ekofisk Complex.

The 443-kilometre distance to Emden was split into three equal sections, with platforms B11 and H7 located at the intermediate points to provide boosting if required.

However, additional compression was seldom needed on the final stage to Emden. H7 was shut down in 2007 and B11 in 2013, and both have since been removed.

These two booster platforms were located in the German sector of the North Sea, while the pipeline also crosses the Danish sector.

The pipeline has been trenched or covered with sand. Its final section passes the island of Juist before making landfall on the coast of East Friesland to the north of Emden.

Its daily capacity is roughly 59.4 million standard cubic metres (2.1 billion cubic feet). In addition to gas from the Greater Ekofisk Area, it carries output from Valhall, Hod, Ula, Gyda and the Statpipe system (primarily Statfjord and Gullfaks).

Source: ConocoPhillips Norge

Published 29. July 2019   •   Updated 12. October 2019
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Embla 2/7 D

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This unmanned wellhead facility is remotely controlled from Eldfisk 2/7 S located 5.2 kilometres to the north, where oil and gas output from the platform is also processed.
Brief facts:
  • Unmanned and remotely operated wellhead platform
  • Installed in 1992
  • On stream 12 May 1993
— Embla 2/7 D. Photo: ConocoPhillips
© Norsk Oljemuseum
sokkelkart, illustrasjon, blokker, lisens, forsidebilde, engelsk,
Hand-colored map of the licenses of the first licensing round on the Norwegian continental shelf. Norwegian Continental Shelf Map, 1965.

The Phillips group was awarded block 2/7 as early as 1965, and the Embla reservoir lies in the southern part of this acreage. Drilling began there in 1974 to depths of 4 500-5 000 metres, but pressure and temperature in the wells were too high for testing with the available equipment.

The first production well was not drilled and tested until 1988, followed by a second in 1990. Both yielded very promising results, and the field came on stream in May 1993.

Embla comprises a sandstone reservoir at least 250 million years old. The other fields in the Greater Ekofisk Area comprise fine-grained carbonate rocks deposited about 70 million years ago.

The Embla reservoir has a temperature of 160°C compared with the 125°C normally found in the chalk formations 1 000 metres higher up, and its pressure is almost twice as high.

Fabricated by Heerema in the Netherlands, the Embla 2/7 D jacket (support structure) was installed by the M 7000 crane vessel. It stands 84 metres high and weighs 2 300 tonnes.

A 5.2-kilometre subsea umbilical from Eldfisk comprises three power cables for electricity supply and eight fibreoptic lines handling data transmission and telecommunication.

Eldfisk 2/7 S, embla,
Eldfisk 2/7 S. Photo: ConocoPhillips

The platform has six production wells and an average daily output of roughly 7 000 barrels of oil. All processing and metering took place on Eldfisk 2/7 FTP until 2015, and has now been switched to Eldfisk 2/7 S.

A 14-inch flowline linked 2/7 D with 2/7 FTP and runs today to 2/7 S. Produced at Wick in Scotland, this line was floated out to the field in one piece.

Topside equipment includes the wellhead area, helideck (built by Vindholmen Services in Arendal), crane, control room, workshop, test separator and glycol pump.

Normally unmanned, the platform is maintained as and when required and therefore incorporates a simplified accommodation module with lounge, mess, coffee room, galley, changing room, WC and 12 emergency beds.

Published 24. June 2017   •   Updated 25. October 2019
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Developing the field

person By Norwegian Petroleum Museum
The temporary Gulftide platform was ready to start producing oil from Ekofisk on 15 June 1971, just over 18 months after the field had been discovered in October 1969.
— Gulftide with Ekofisk 2/4 A in the background. Photo: Aker Mek. Verksted/Norwegian Petroleum Museum
© Norsk Oljemuseum

Gulftide was converted to cope with conditions on Ekofisk in the Åmøy Fjord near Stavanger. This jack-up drilling rig was equipped with process equipment and its derrick, helideck, hangar and legs were reinforced.

To win time, it was decided that the discovery well and three appraisals drilled on Ekofisk by Ocean Viking would be completed for production.

Principles for producing from Gulftide were relatively simple. Output flowed from the subsea wellheads to the platform, where it went through two-stage separation to remove gas and water.

With pressure also reduced, the gas was flared off and the oil sent on by flowlines to two loading buoys where shuttle tankers moored to take on cargo.

Tankskipet Donovania laster olje fra lastebøyen på Ekofisk. I bakgrunnen skimtes så vidt Gulftide. Foto: ConocoPhillips/Norsk Oljemuseum

Production could only continue while ships were loading. As soon as one tanker had been filled, the oil stream was diverted to the vessel waiting at the other loading buoy.

The problem with this approach was manifested when weather conditions ­– strong winds and/or high waves – forced the tankers to leave the buoys.

If that happened, production from the wellheads had to be suspended immediately. Given the prevailing weather on Ekofisk, that happened regularly. Output was halted for 20 per cent of the time during the first year.

Fixed platforms

Gulftide was replaced as the temporary production installation in 1974 by the permanent Ekofisk 2/4 A (Alpha) and 2/4 B (Bravo) platforms for production, drilling and quarters.

In addition came the Ekofisk 2/4 C (Charlie) production, drilling and compression facility, the Ekofisk 2/4 FTP (field terminal platform) for production and risers, and Ekofisk 2/4 Q for accommodation.

Oil and gas were produced by 2/4 A, B and C through their own wells for processing in their separation plants and piping on the 2/4 FTP for a three-stage separation process.

At the same time, the tanker loading buoys were moved further from the platforms and the Ekofisk 2/4 T oil storage tank became operational.

This facility was extremely advantageous, because it allowed production to continue virtually regardless of whether bad weather prevented tankers from connecting to the buoys.

Ekofisktanken ble satt i drift i 1974. Foto: ConocoPhillips/Norsk Oljemuseum

The 2/4 FTP platform, where oil and gas from the three producing facilities was processed, had been planned to handle the level of output estimated for the main field.

Clear restrictions had been imposed by the Norwegian government on the amount of gas Phillips was allowed to flare. That also set a ceiling for oil production, since gas accompanies it up from the reservoir.

The solution was to install two powerful compression packages on 2/4 C in order to inject the gas under pressure back into the producing formation.

Accommodation facilities had to be provided on the two first platforms, 2/4 A and B. Where 2/4 C and FTP were concerned, however, they were tied together with bridges and to 2/4 Q.

Published 1. September 2019   •   Updated 8. October 2019
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person Norwegian Petroleum Museum
This four-leg jack-up drilling rig was built in Glasgow during 1967 for Ocean Drilling & Exploration Co.
Kjappe fakta:
  • Jack-up drilling rig
  • Built 1967 in Glasgow for Ocean Drilling & Exploration Co.
  • Began test production on Ekofisk 15 June 1971
  • Produced on Ekofisk until 1974
— Gulftide at theEkofisk field. Photo: Terje Tveit/Norwegian Petroleum Museum
© Norsk Oljemuseum
Gulftide. Photo: Unknown/Norwegian Petroleum Museum

A mere 17 months after the Ekofisk discovery was announced in December 1969, Gulftide was ready to come on stream as a temporary production platform.

Its official inauguration took place on 9 June, with initial test output commencing on 15 June. Full production began on 8 July.

The rig was chosen because it was available on the market. Established equipment for processing oil and gas was tailored to the limited space on board. Separate flowlines carried wellstreams from four subsea wells. Oil, gas and water were separated on board, with the gas flared and the oil piped to two buoys for loading into shuttle tankers.

Work on the process equipment was relatively simple. The problem was to tailor it to the rig. The subsea wellheads had to be reinforced to meet the demands posed by the North Sea, and a buoy loading system needed to be developed for waters where this technology had never been used before.

To gain time, it was decided that the three appraisal wells drilled by Ocean Viking to map the extent of the field – in addition to the discovery well – would be completed for production.

The producers would be topped with hydraulically controlled wellheads. Such equipment had been tried out on the seabed earlier, but on a limited scale and not in the deep and rough waters found on Ekofisk. This challenge was overcome by having the wellheads manufactured and then reinforced at the Phillips base in Dusavik outside Stavanger. Flowlines and control cables would also be laid from each well to Gulftide, with production comingled in a single riser to the topsides.

Weather conditions also represented a major problem when designing the loading buoys. Phillips itself had experience with such facilities, but the concept had only been used before in harbour-like conditions and waters no deeper than 27 metres. They were now to stand in 70 metres in the middle of the North Sea.

Gulftide was converted in the Åmøy Fjord outside Stavanger to cope with conditions on Ekofisk. The processing facilities were installed and reinforcements made to the derrick, helideck, hangar and leg structures.

Gulftide, Ekofisk 2/4 A, boretårn, flare, 1971, utbygging,
Gulftide with Ekofisk 2/4 A in the background. Photo: Aker Mek. Verksted/Norwegian Petroleum Museum

Planning began in late 1970, when Phillips received approval to begin laying the flowlines between wellheads and rig. Brown & Root won this contract, with the first oil pipelines on the Norwegian continental shelf laid by the Hugh W Gordon laybarge.

The production principle on Gulftide was relatively simple. Output flowed from the subsea wellheads to the rig, where it passed through two separation levels to be split into oil and gas while the huge pressure was reduced.

Gas was flared off and the oil was piped to one of the loading buoys where a shuttle tanker was moored. Production could only take place when a ship was present.

Offisiell åpning av norsk oljeproduksjon,
The Greek tanker, Theogennitor, unloads crude oil from loading buoys on the Ekofisk field. Gulftide in the background. Photo: ConocoPhillips/Norwegian Petroleum Museum

As soon as one tanker had become fully laden, the oil flow was switched to the other buoy where another ship was waiting to take on cargo.

The problem with this approach arose when weather conditions meant the tankers had to cast off from the buoys because of strong winds or high waves. The rig then had to shut down production from the wellheads immediately.

Given the weather conditions found on Ekofisk, output regularly had to cease. Production was suspended for 20 per cent of the first year for this reason.

Output began cautiously on 8 July 1971 from a single well. The second producer came on stream that September, the third was ready the following month and all four were producing by February 1972. They each flowed 10 000 barrels of oil per day.

Source: Kvendseth, Stig, Giant discovery, 1988.

Published 9. April 2019   •   Updated 25. October 2019
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Ekofisk in a nutshell

person By Norwegian Petroleum Museum
The Greater Ekofisk Area lies at the southern end of Norway’s North Sea sector, roughly 280 kilometres south-west of Stavanger, and encompasses Ekofisk – the first Norwegian oil field – as well as Eldfisk and Embla.
— Sunset over Ekofisk. Photo: Husmo Foto/Norwegian Petroleum Museum
© Norsk Oljemuseum

The three are operated by ConocoPhillips on behalf of the Ekofisk licensees. The area also embraces former producers Albuskjell, Cod, Edda, Tor, West Ekofisk and Tommeliten G.

These fields all lie within production licence 018 apart from Tommeliten G, which was operated by Statoil from 1976 to 2003.

In all, 31 installations have been positioned in the Greater Ekofisk Area.

First Norwegian offshore field

Ekofisk began production on 15 June 1971, following its discovery in the autumn of 1969. Development of the field has occurred in several phases.

Its central facilities were installed during the early 1970s, with oil initially being buoy-loaded into tankers. From 1975, it has been piped to Teesside in the UK. The gas has been landed by pipeline at Emden in Germany from 1977.

ekofisk i et nøtteskall, engelsk
Photo: Husmo Foto/Norwegian Petroleum Museum

Jacked up six metres

The water depth in the Greater Ekofisk Area is 70-75 metres. However, declining pressure in the Ekofisk reservoir over the years has caused the seabed to subside.

Efforts began as early as 1985 to safeguard the installations against the effects of this development, and the steel platforms in the Ekofisk Complex were jacked up by six metres in 1987.

In addition, a protective breakwater was installed around the Ekofisk tank in 1989. The rate of seabed subsidence has declined sharply in recent years.

Waterflooding improves recovery

The Ekofisk 2/4 K water injection platform became operational in December 1987 as part of efforts to improve Ekofisk’s recovery factor – the share of petroleum in place actually produced.

Waterflooding capacity on the field to help maintain reservoir pressure was later expanded several times, and had reached just over 500 000 barrels per day by 2019.

Measured in barrels of oil equivalent, the recovery factor on Ekofisk has risen from an original estimate of 17 per cent to over 50 per cent.

Ekofisk I and II plus licence extension

The first phase of development and production on Ekofisk began with initial oil output from the converted Gulftide jack-up rig in 1971 and ended with the start-up of Ekofisk II in 1998.

Large parts of the Greater Ekofisk Area were restructured in the latter year, leading to plans for removing 15 installations – 14 steel platforms and the process facilities on the Ekofisk tank.

plattformer, historie, 2004, driftsenter åpnet,
Embla 2/7 D. Photo: ConocoPhillips/Norwegian Petroleum Museum

Designated Ekofisk I, these redundant structures include Ekofisk 2/4 A, 2/4 B, 2/4 FTP, 2/4 Q, 2/4 H, 2/4 R, 2/4 P and 2/4 T.

In addition come the Edda 2/7 C, Albuskjell 1/6 A, Albuskjell 2/4 F, Cod 7/11 A, West Ekofisk 2/4 D, Norpipe 36/22 A and Norpipe 37/4 A installations.

The concrete part of the tank – Ekofisk 2/4 T – will remain. Gulftide was removed as far back as 1974. Two platforms owned by other companies –  Ekofisk 2/4 G and 2/4 S – have also gone.

A new plan for development and operation (PDO) of the field (Ekofisk II) was approved in 1994, at the same time as the Ekofisk licence was extended to 2028.

This creates a new Ekofisk Complex with two structures – the Ekofisk 2/4 X wellhead unit installed in the autumn of 1996 and the Ekofisk 2/4 J processing and transport platform in 1997.

Ekofisk II became operational in August 1998 and is intended to produce until 2028. Ekofisk, Eldfisk and Embla are tied back to the new complex, as was Tor until it shut down in December 2015.

Ekofisk West

historie, forsidebilde, 2003, ekofisk vekst godkjent i statsråd
Ekofisk Growth. Illustration: Ståle Ådland

In December 2002, soon after the Conoco-Phillips merger had been announced, the Ekofisk West project was presented to improve oil and gas recovery. Process capacity and reliability on Ekofisk were also to be enhanced.

This development primarily involved the construction and installation of a new platform, Ekofisk 2/4 M, with processing facilities and 24 new wells drilled over five years.

The latter could contribute to improved recovery both because there were more wells and because they would tap new locations in the reservoir. On stream in 2005, 2/4 M was linked to the Ekofisk Complex with a bridge.

Process capacity for produced water was also to be increased through upgrading on Ekofisk 2/4 J and Eldfisk 2/7 E. A third measure concerned laying a power cable from the Ekofisk Complex to 2/4 K in order to make electricity supplies more efficient.

New developments: Eldfisk II and Ekofisk South

Eldfisk 2/7 S løft
The deck of Eldfisk 2/7 S being mated with the steel jacket. Foto: Øyvind Sætre/ConocoPhillips

The plan for development and operation (PDO) of Eldfisk II, approved by the Storting (parliament) on 9 June 2011, includes a new wellhead, process and accommodation platform – Eldfisk 2/7 S.

In addition come 42 new wells as well as upgrades to existing platforms which extend their commercial life.

The PDO for Ekofisk South involves the construction of a new wellhead platform – Ekofisk 2/4 Z – as well as a new subsea water injection facility and 44 additional wells.


ConocoPhillips Norge, 2004.
Ministry of Petroleum and Energy, press release, “Vekstprosjekt på Ekofisk godkjent”, 6 June 2003.

Published 1. October 2019   •   Updated 12. October 2019
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Norpipe H-7

person Norwegian Petroleum Museum
This platform served as a pumping/compressor station to maintain pressure in the 443-kilometre Norpipe gas pipeline from Ekofisk to Emden in Germany, which became operational in September 1977.

Kjappe fakta::
  • Compressor platform on Ekofisk-Emden gas pipeline
  • Installed 1976
  • Operational 1977
  • Shut down 29 October 2007
  • Removed 2013
— Norpipe GNSC-H7. Photo: Husmo Foto/Norwegian Petroleum Museum
© Norsk Oljemuseum

Gas received initial compression to 132 bar at the Ekofisk Complex. The pipeline was divided into three equal lengths, with Norpipe GNSC B11 positioned at the end of the first third to maintain pressure as and when required.

From there, the gas then travelled the next third of the distance to the second and virtually identical compressor platform, H7.

This was also responsible for maintaining pressure, but additional compression was seldom required on this final leg of the journey to Emden.

Both platforms stood on the German continental shelf, but 48 kilometres of the pipeline also ran across the Danish North Sea sector.

The pipeline is trenched or covered with sand. On its final approach to the coast of East Friesland, it passes beneath the island of Juist before making landfall north of Emden.

Capacity in Norpipe is about 60 million standard cubic metres (scm) or 2.1 billion cubic feet per day. In addition to output from the Ekofisk-area fields, it carries gas from Valhall, Ula and the Statpipe system – primarily Statfjord and Gullfaks. Gas was also transported for a time from Hod and Gyda, but that has ceased.

fritid, Norpipe GNSC-H7,
Magnus Refsland and Werner Hein have pulled the crab trap (full of starfish) on the Norpipe H-7 platform. Photo: Husmo Foto/Norwegian Petroleum Museum

Built in 1976, the B11 platform had six decks. Its permanent staffing totalled 14 people, but various service personnel were also often on board. The regular crew included three in catering.

The 11 Phillips employees comprised the offshore installation manager, the nurse/radio operator, eight operators and a roustabout.

In addition to their direct function, the operators covered various other trades which meant the crew was self-sufficient in most circumstances.

Both platforms obtained a satellite antenna in 1986 which allowed them to received Norwegian TV, while the 24-bed accommodation were redecorated in 1981 and upgraded in the summer of 1990.

Work on the upgrading largely comprised converting all cabins to doubles with shower and WC. The galley and changing rooms were renewed and changing facilities for women provided.

A new module with a lounge for non-smokers, a smoking room, gym and pool room was also installed. During this work, the West Gamma accommodation rig was positioned alongside.

Upgrading equipment on the platform was also initiated in 1990. While the pipeline’s original daily capacity had been estimated at 2 100 million standard cubic feet, this was found to have declined after a number of years to 1 975 million.

To return to the original capacity, the compressors needed to be upgraded and power supply from the turbines increased. This was done both on the Ekofisk tank and on the H7 and B11 platforms. Gas coolers on the tank were replaced as well.

Norpipe GNSC-H7, yrker, radiooperatør,
Radio operator Torleif Førland on the platform Norpipe H-7, with his amateur radio. Photo: Husmo Foto/Norwegian Petroleum Museum

The control systems were also upgraded in parallel. Control panels on turbines and compressors were replaced and metering instruments installed to conduct measurements in this equipment.

While the nearest neighbour to B11 was a Danish oil field, H7 stood in the middle of the shipping channel. M/S Hero broke down 15 nautical miles west of the latter platform at around 13.00 on 12 November 1977.

By 21.00, the ship was still adrift and heading directly for H7, and all 14 crew on the platform made ready to evacuate by helicopter – the waves were too high for the lifeboats. The wreck passed at 21.40 with a clearance of 400 metres.

German cargo carrier Reint collided with H7 on 30 September 1995, despite efforts by the standby ship to avert the threat. Production was halted as a safety measure, but the platform luckily suffered only minor damage. The collision was caused by inadequate watchkeeping on the ship’s bridge.

Operator responsibility for B11 and H7 was transferred at the beginning of 2003 to Norway’s state-owned Gassco company, which runs the Norwegian gas transport network.

This change had little significance for operation of the platforms, since the actual work was still carried out by ConocoPhillips as a technical service provider to Gassco.

H7 was shut down in 2007, and removal had been completed in 2013. In connection with preparations to remove the structure, operator responsibility was transferred to Statoil as the company in charge of the project on Gassco’s behalf.

Published 24. August 2016   •   Updated 22. October 2019
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Phillips inundates Sola with oil revenues

person by Kristin Øye Gjerde
Stavanger and neighbouring Sola were the first Norwegian local authorities to experience fantastic oil-related growth after the award of the first exploration licences in 1965.
— Phillips er i ferd med å etablere seg på Norscobasen nederst til høyre Ca 1972 Foto: Norsk fly og flyfoto/Norsk Oljemuseum
© Norsk Oljemuseum

The Shell refinery at Risavika in Sola was completed two years later, while the Norsco base in Tananger became operational as early as 1966.

But things really took off once the Ekofisk field had been discovered in the autumn of 1969 and started trial production on 14 July 1971.

Operator Phillips Petroleum Company moved its offices from the Dusavik base outside Stavanger to Tananger in Sola, and Shell could finally start refining Norwegian rather than imported crude.

Sola’s population now rose steadily from 8 400 in 1965 to 15 000 two decades later, and jobs grew even faster – from about 2 000 in 1970 to almost 8 000 in 1985. That averages 10 per cent annually.

Phillips and Shell became cornerstone companies. A large part of their workforce, particularly in Phillips, worked offshore. In addition came newly established oil supply firms.

More jobs were also created in retail, public administration, education, health and social care, personal services and so forth.

Although traditional agriculture remained important for the local authority, the number of farmers gradually declined as a result of mechanisation.[REMOVE]Fotnote: This article is based on the chapter “Elverket i Oljealderen” in I det regionale spenningsfelt. Sola Energi 1913-1999, Kristin Øye Gjerde.

Boreskipet Drillship ligger ved kai på Norscobasen i Tananger (1968). Foto: NOM/Norsk Fly og Flyfoto Boreskipet Drillship ligger ved kai på Norscobasen i Tananger (1968). Foto: NOM/Norsk Fly og Flyfoto
Boreskipet Drillship ligger ved kai på Norscobasen i Tananger (1968). Foto: Norsk Fly og Flyfoto/Norsk Oljemuseum

The “agio tax”

The sharp rise in Sola’s revenues was attributable entirely to the oil industry, and it found itself in an enviable position during this period. Tax revenues rose even faster than population and jobs.

To give an indication, the local authority’s overall income from wealth and income taxes rose from NOK 9.3 million in 1966 to NOK 198 million in 1990. The biggest growth came in 1978-82, when it averaged 39 per cent a year.[REMOVE]Fotnote: Sola local authority, plans.

The secret behind this sharp increase was the tax paid by the oil companies – primarily Phillips – on agio, or the percentage fee charged when exchanging one currency for another.

Under Norwegian law at the time, the companies paid tax on their interest income to the local authority where they had their head office. In making this rule, however, the government had failed to take account of the considerable sums involved.

As operator of the Greater Ekofisk Area, Phillips had placed capital to be used for new investment in banks around the world – particularly the UK.

These deposits yielded substantial interest payments, and tax was payable on converting this income into Norwegian kroner.[REMOVE]Fotnote: Toralv Torstenbø, former chief executive officer in Sola local authority, interviewed by Kristin Øye Gjerde, 22 February 2001.

Sola council is said to have almost gone into shock the first time Phillips paid this agio tax. It suddenly had more money than it could spend.

During the 1970s and early 1980s, Sola’s municipal income always exceeded the budgeted amount. Large sums could be transferred every year to a capital fund.

Since the local authority was in a growth phase, additional funding was needed for the big developments it faced. While the rest of Norway experienced a slump in the late 1970s, Sola continued in top gear without a sign of unemployment.

Net income tax revenues came to NOK 55.5 million in 1978, while net spending was NOK 31.9 million. And these fantastic results went on improving.

By 1982, wealth and income taxes yielded NOK 203.4 million – compared with a budget of NOK 146 million, which was upgraded to NOK 190 million during the year.

According to Toralv Torstensbø, the financial controller, agio tax accounted for almost half this amount – in other words, as much as the tax paid by all other enterprises, private individuals and industry in Sola.

Its chief executive officer became a little overweening. In his comments on the 1982 budget, he declared that it would be “natural for Sola local authority to feel a strong regional responsibility and not to be too strict about the traditional division of costs between state, county and local authority.”

In line with this open-handed policy, Sola paid for both road projects and an upper secondary modern school which the county council was supposed to fund.[REMOVE]Fotnote: Chief executive officer’s budget proposal for Sola local authority covering 1974-85.

Tightening up petroleum tax

This unexpected prosperity undoubtedly created some jealously in the neighbouring local authorities, and the media began to show an interest in the issue.

Local daily Stavanger Aftenblad interviewed Sola’s chief executive and controller in 1981, when its photographer took a shot which illustrated the boundless wealth – Torstensbø stood  showering hundred-krone notes over his colleague.

This story was not only read by the paper’s regular subscribers. The following day, 150 copies were distributed to members of the Storting (parliament).

That in turn prompted Centre Party representative Lars Velsand to make a passionate speech in which he described the position as a misuse of tax revenues.

He called on the government to intervene so that individual local authorities were unable to benefit in this way. Nor was he alone in finding it unreasonable that a small community like Sola should get so much money.

The result was an amendment to the Petroleum Tax Act on 11 June 1982, which specified that the proceeds from the agio tax should be transferred in future to central government.

Løfteskipet Uglen i aksjon ved Norscobasen i juli 1980. Foto: NOM/Norsk Fly og Flyfoto Løfteskipet Uglen i aksjon ved Norscobasen i juli 1980. Foto: NOM/Norsk Fly og Flyfoto
Løfteskipet Uglen i aksjon ved Norscobasen i juli 1980. Foto: Norsk Fly og Flyfoto/Norsk Oljemuseum

Unfortunately, however, Sola had got used to consuming these revenues. It is easy to learn expensive habits, but not so straightforward to shrug them off again.

Matters had become a little unusual when the council’s executive board adopted the style of the oil company chiefs and took a helicopter outing during an ordinary budget meeting.[REMOVE]Fotnote: Oskar Goa, former chief technical officer in Sola local authority, interviewed by Kristin Øye Gjerde, 23 October 2000.

However, most of the tax money benefitted the general public. Paying for Sola upper secondary school and new national and county highways is an example of this.

The council also invested on local authority school buildings and community facilities such as the big sports complex at Åsen, with an outdoor athletics ground and two modern indoor arenas. Dysjaland and Tananger also acquired new sports arenas.

A new cultural centre built in central Sola has a distinctive architecture in brick and glass, with a grassed roof to blend with the surrounding Jæren landscape. With two stages and a public library, this became the community’s main venue for events and so forth.

The local authority thereby built up a very good infrastructure. Power cables were laid in the same trenches as water and sewage pipes, a network of cycle lanes was built and street lighting installed.

On the downside, virtually all these investments boosted operating expenses. The council’s running costs rose by an annual average of 30 per cent in 1978-84, with the biggest growth in the last three years of the period.

So the calls by Storting representatives to transfer agio tax receipts from councils to central government represented a real threat to local politicians.

Sola joined forces with other local authorities in the same position, including Stavanger, Oslo and Bærum as well as Rogaland county council.

A delegation met the Storting’s standing committee on finance to present their case, and secured a commitment to accept a phased reduction in revenues over four years.

The local authorities would receive 80 per cent of agio tax receipts during the first year, then 60 per cent, 40 per cent and finally 20 per cent.[REMOVE]Fotnote: Amendment to the Petroleum Tax Act adopted on 14 May 1982.

In reality, however, the run-down percentages were adjusted to extend over five years in annual steps of 80, 60, 20, 20 and 20 per cent. The total amount going to the local authorities was the same.

The arrangement was controversial to the last, and also uncertain because it had to be approved in each annual government budget.

Living within its means

After the tax change, Sola’s chief executive officer saw the writing on the wall. It seemed “to be unquestionable that [Sola] has seen its best days in purely financial terms and must return to setting tougher priorities for various assignments,” he asserted in connection with the budget process for 1983.[REMOVE]Fotnote: Chief executive officer’s budget proposal for Sola local authority, 1983.

It took the politicians a little longer to accept this reality, but they were forced to reduce investment and operating expenditures in the years which followed.

Cutting back on the new sports arenas and cultural centre was not very desirable. Nor was it pleasant to have to slow down. But savings had to be made, and long-terms spending plans were removed from the budget for possible reintroduction later.

A raft of measures were stripped from the budget in 1985, such as extensions to and modernisation of schools, sports arenas and swimming pools, a new somatic nursing home, housing for the intellectually disabled and sheltered housing. Grants for national and county roads were reduced.[REMOVE]Fotnote: Chief executive officer’s budget proposal for Sola local authority, 1985.

Once the government’s compensation scheme had ended, Torstensbø – now chief executive officer – told Stavanger Aftenblad that he did not want to paint too gloomy a picture.

“But it’s clear that we must set much more moderate financial priorities than we’ve been used to. To sum up the position, we were previously flush with cash and poor in facilities. We’re now flush with facilities and poor in cash.”[REMOVE]Fotnote: Stavanger Aftenblad, ”Alt blir dyrere i det rike Sola”, 19 May 1987.

Sola kulturhus fotografert vinteren 2004 Sola kulturhus fotografert vinteren 2004
Sola kulturhus fotografert vinteren 2004

Rogaland county council also raised the question of whether it would be possible to establish a permanent arrangement which allowed local authorities and counties to benefit from some of the tax revenues paid by local oil companies.

The council pointed out that it was otherwise normal practice for Norwegian companies to pay taxes to the local communities they were based in.

This request was turned by Labour finance minister Gunnar Berge because the councils concerned still benefitted from bigger tax payments by oil company employees and on property.[REMOVE]Fotnote: Stavanger Aftenblad, “Rogaland reiser skattekrav på ny”, 16 January 1988.

According to Torstensbø, this was only partly true. The big oil companies were not so significant for Sola’s income once the agio tax was excluded.

About NOK 2 million was received annually from Phillips, primarily in property tax. The most important taxpayers in the local authority were the roughly 90 companies at Aker Base. These were service providers such as Halliburton, Schlumberger and Baker Hughes.

At the same time, Sola acquired a steadily growing number of affluent residents and a growing share of its revenue came from income tax. Despite the cut-backs, it remained prosperous.

Published 29. July 2019   •   Updated 29. July 2019
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