This is a combined production, drilling and accommodation platform which was installed during 1972 in 70 metres of water, 2.3 kilometres north of the central Ekofisk Complex. The platform came on stream in 1974.
Combined production, drilling and accommodation platform
Installed in 1972
On stream 1 October 1974
Also called Ekofisk Bravo and known for the Bravo blowout in 1977
— Ekofisk 2/4 B. Photo: Husmo Foto/Norwegian Petroleum Museum
Collision damage to one of the jacket legs delayed the installation process. It was not until May 1973 that the jacket had been fully piled and was ready to accept the topside modules.
However, progress was then rapid and all the modules were lifted on board during June-July. Three months of hook-up and commissioning followed before the first of the two derricks – rig 41 – spudded the first production well. The second derrick required more work, and first became operational in December.
A trial project for water injection in the Cretaceous formation began via well 2/4 B-16 in April 1981. The aim was to assess whether waterflooding across the whole field could improve oil recovery. Positive results from the trial led to a decision to adopt this approach.
In April 1985, it was also decided to extend waterflooding to the Danian structure using the same equipment as with the Cretaceous formation.
Ekofisk 2/4 K was installed alongside 2/4 B in 1986 to inject water in the northern part of the reservoir, and Ekofisk 2/4 W was installed on a bridge support south of Ekofisk 2/4 FTP for injecting water in the southern area.
Ekofisk 2/4 B and 2/4 K were integrated operationally in January 1995 as Ekofisk 2/4 K-B. Both platforms were thereafter run from the 2/4 K control room.
One of the 2/4 B derricks was removed first, followed by the second in 1997. The 68-bed accommodation module was taken away after 2/4 K had been installed. A bridge now connects the two platforms.
Three oil and gas pipelines of 10, 18 and 22 inches respectively connected 2/4 B to 2/4 FTP. An eight-inch Coflexip umbilical was laid to 2/4 C in 1985. The platform weighs about 12 000 tonnes.
An uncontrolled blowout of oil and gas occurred from 2/4 B in April 1977. Well B-14 needed a workover, which meant pulling out the 3 000 metres of production tubing. The blowout preventer failed during this operation, and it took a week to bring the well back under control. See the article on the Bravo blowout in the history section.
The process comprises two identical production separators (each 12.2 by three metres) in parallel and a test separator (6.1 by 2.1 metres). This equipment was designed with a view to supplying crude oil from the reservoir to 2/4 FTP.
Of the 24 well slots on the platform, 22 were drilled and completed for this purpose and two held in reserve. These wells delivered a mix of crude oil and natural gas through the production manifolds or a test manifold. Output was piped directly to 2/4 FTP.
With each of the 22 production wells, casing and production tubing was set from the wellhead and through the reservoir. Seated on the casing, the wellhead provided a system for controlling pressure in the tubing.
Driven by pressure either from the reservoir or provided by injection support, the crude oil and gas flowed up through the tubing to the wellhead.
On top of the latter was a set of production and work valves known as an Xmas tree, which controlled the wellstream as it flowed to the manifolds and was also used to shut in production.
Each wellhead was equipped with the following valves.
Downhole safety valve
This hydraulically operated ball valve stood far down in the production or injection well. It closed automatically (fail-safe) if the hydraulic pressure was lost.
A line for hydraulic fluid accordingly ran from the wellhead to provide the pressure required to open the safety valve. When the latter closed, the well was shut in and all equipment on the platform was isolated from the pressure in the well.
Faulty installation of such a ball valve was one of the reasons for the Bravo blowout in 1977.
Manual and automatic master valves
These sat in the vertical section of the Xmas tree. The automatic (upper) master valve was kept open by hydraulic pressure. Supported by the manual (lower) master valve, it formed the second barrier against pressure in the well. During the Bravo blowout, this valve was also incorrectly installed and was a direct reason why the well could not be shut.
utblåsning, blow-out, 1977, ulykke,
Manual and automatic wing valves
Flow wing valves for production were positioned in the four-inch horizontal section of the tree and connected to the choke. These are the valves normally used to shut down a well.
These were designed to cope with a substantial pressure drop. They were used to regulate oil flow and pressure to the production and test manifolds.
Kill wing valve
This allowed diesel oil to be injected into the wellhead in order to increase pressure in the production tubing above the downhole safety valve. It could also be used to inject various chemicals during maintenance of the wellhead and the main pipelines.
A pressure gauge was installed on the Xmas tree to measure well pressure.
Three manifolds were used on 2/4 B to integrate flows from the various wells for delivery to the main pipelines. Two had larger diameters in order to accommodate the main production stream, while the third was narrower since it received the flow from a single well for testing.
During normal operation, output from all the wells was conducted to the two production manifolds and on to the two main seabed pipelines connected to 2/4 FTP. The flow from a well being tested was diverted to the test manifold and through the platform’s test separator.
This system was designed to import gas by pipeline from 2/4 FTP. Its pressure was then raised for continuous injection into the wells in order to “lift” the oil and boost the production flow.
Two different operational settings were built into the system – initial compression and gas lift. The first was used to initiate lift and required higher pressure than the ongoing operation. Once initial compression was completed in a well, the latter switched to continuous gas lift. This required less pressure but more gas. The settings could be used simultaneously.
The system comprised two gas scrubbers to remove possible residual liquid, a four-cylinder compressor for raising gas pressure, a motor fuelled by natural gas to power the compressor, and separate manifolds for initial compression and gas lift.
Production from each well had to be tested to monitor reservoir/well conditions and to check separation/treatment. A good monitoring programme was also needed for waterflooding, so a permanent test separator was installed. Its design was based on a vertical cyclone principle.
Utilities on 2/4 B included systems for telemetry and communication, safety, hydraulics, electricity generation, fuel and lube oil, instrument and work air, and chemical injection.
Other facilities covered pig launching, seawater, jetting and fire water, untreated seawater and drinking water, gas flaring and venting, oil recycling, steam generation, and cranes and lifting.
Published 30. March 2019 • Updated 23. 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
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