Category: Operations: Further Development

The wide-ranging job of preparing the Ekofisk I cessation project began in 1994, with the plans submitted to the government in October 1999 and various revisions in April 2001. Particular attention was paid in this context to that concrete giant, the Ekofisk tank, and its associated breakwater, and separate proposals for its future were delivered in January 2002.[REMOVE]Fotnote: Proposition no 51 (2001-2002) to the Storting, Om disponering av Ekofisk-tanken med beskyttelsesvegg.

Ekofisk 2/4 T had been installed on the field in 1973. It was originally intended to store crude, but that role disappeared when the oil pipeline to Teesside in the UK opened. The tank has subsequently had various applications, including as the base for process facilities and a treatment plant for produced water.

A breakwater was installed in 1989 to protect the structure against increased wave forces after its freeboard had been reduced by seabed subsidence on Ekofisk. Various disposal options were identified through a brainstorming process. An extensive programme of technical and scientific studies reduced them to three:

• tank and breakwater remain standing on the field, but the superstructure is removed and the interior cleaned
• the superstructure is removed, and tank and breakwater are towed to a suitable site for scuttling in deep water
• tank and breakwater are brought to land for recycling.

In order to identify the most relevant of these ideas and come up with a recommended solution, the Ekofisk licensees assessed each proposal in relation to a set of criteria. These were the technical feasibility of the plans, the safety risk involved, their environmental impact, the economics and the impact on society. It quickly became clear that the technical challenges and financial cost of removing such an installation meant these options would face substantial opposition. On the other hand, many people questioned whether safety against oil spills could be guaranteed. The environmental organisations were particularly sceptical. Operator Phillips accordingly carried out a detailed study of the options in a separate impact assessment which took several years to complete. The conclusion was very clear – leaving behind the concrete tank, its integrated superstructure and the breakwater represented the best option.[REMOVE]Fotnote: Phillips Petroleum, Epoke – Informasjon om sluttdisponering av Ekofisk I, no 10, April 2001.

On behalf of the Phillips group of licensees as well as A/S Norske Shell and Norpipe Oil AS, Phillips submitted a report on 22 October 1999 to the Ministry of Petroleum and Energy.[REMOVE]Fotnote: Phillips Petroleum, Avvikling og disponering av Ekofisk I, Konsekvensutredning, 1999.

The latter presented its recommendations in a separate proposition (Bill) to the Storting (parliament), which approved leaving the tank and breakwater in situ. Two integrated decks, one above the other, needed be retained in order to stabilise the structure and ensure helicopter access for future inspections. The tank had to be marked on navigational charts, and signal equipment to safeguard shipping and helicopter traffic to the Ekofisk field had to be installed.[REMOVE]Fotnote: Proposition no 51 (2001-2002) to the Storting, Om disponering av Ekofisk-tanken med beskyttelsesvegg.

A separate study to see whether it would be feasible to refloat the tank had been conducted by RaKon, a specialist in inspection, monitoring and rehabilitation of concrete structures.[REMOVE]Fotnote: RaKon website, accessed 29 March 2019.

This quickly established that the best option was to tie tank and breakwater together and then tow them to land as a unit. Removing the breakwater first meant the tank would have to stand unprotected for a whole winter season. The structure would very probably suffer damage from tough North Sea storms in this period. It was therefore agreed to look at a “combined” solution using a special “floor” structure to ensure buoyancy during a tow. A dedicated team of technical experts risk-assessed the operation. Their results were also checked by Det Norske Veritas (DNV), Norway’s most reputable specialist in this field. These evaluations showed that all the options had a probability of failure with serious consequences which exceeded the acceptable limits set for such possibilities.

DNV also carried out an impact assessment of the three options in terms of their environmental effect, which took seven factors into account. Two in particular were found to have negative consequences for option 1 compared with removal from the field – lack of resource utilisation of the steel and concrete materials, and the pollution aspect of leaving behind something alien to the site. However, letting the tank stay on the field was considered advantageous in terms of energy consumption (almost a halving) and emissions to air compared with the removal options. Together with project execution specialist Asplan Viak in Stavanger, DNV moreover assessed the social consequences of the three main options.

Leaving the structures in place would have little or no influence on fishing or shipping in the area. The cost was also minimal compared with either of the removal proposals.

NOK 2.5-3.5 billion would be needed for both of the latter. Moreover, scuttling in a fjord would be unacceptable to various organisations in several countries around the North Sea basin.[REMOVE]Fotnote: Phillips Petroleum, Epoke – Informasjon om sluttdisponering av Ekofisk I, no 10, April 2001.

Before a discussion could even begin on removal or not, Phillips had to clarify the actual contents of the storage tank – a job which took three years from 1998 to 2000. Cores and water samples were taken from several of the cells and annular spaces, and sent continuously to land for analysis. The key question was how clean is clean enough. Phillips based its answer on guidelines issued by the Norwegian Pollution Control Authority (SFT), which categorised levels of pollution in five classes.

This guidance and classification were amended in 2007. In consultation with the SFT, Phillips chose to set the limit for an acceptable level of pollutants in the bottom sediments at class 2. Should pollution exceed this limit in certain areas, a special assessment was to be made of whether measures had to be taken and what these should be. Results from the sampling showed that the concentration of PAH[REMOVE]Fotnote: Polycyclical aromatic hydrocarbons (PAH) are organic compounds of carbon and hydrogen built up from two or more five- and six-membered rings. and several heavy metals – particularly mercury and zinc – was as high as class 5 in some areas. According to the analyses, too, volumes of PCBs[REMOVE]Fotnote: Polychlorinated biphenyls (PCB) are a group of chemical compounds derived from biphenyls, where two or more of the hydrogen atoms in the molecule are replaced by chlorine atoms. which corresponded to class 4 were to be found in the inner and outer annular spaces.[REMOVE]Fotnote: Phillips Petroleum, Epoke – Informasjon om sluttdisponering av Ekofisk I, no 10, April 2001.

The conclusion was that the Ekofisk tank had to be cleaned before it could be allowed to remain on the field, and Phillips launched a study to answer the following questions:

• how was hydrogen sulphide to be handled?
• what was the best way to access the cells?
• what should be done with oil/wax deposits in the cells?
• would anything need to be done with the internal walls in the cells?
• how should bottom sediments in the cells and annular spaces be treated?
• how should the water be treated?

The work was done as an internal exercise in three stages, which also drew on information from many different external companies. More than 50 different options were presented in all. These methods were then assessed in relation to criteria which covered personnel safety, environmental impact, costs, technical feasibility and assessments of public opinion. After several rounds of consideration, an overall solution was proposed which rested on several possible approaches. These in turn were subject to a detailed technical assessment. The final step was to rank measures in relation to the specified criteria, which yielded a total solution involving a specific method for each of the main factors in the clean-up.

In the proposed solution, the questions were tackled one by one. Hydrogen sulphide was to be pumped out through manholes in the top of each storage cell, for instance. Part of the topside equipment had to be removed to access these entry points, while the water in the cells had to be treated to reduce its content of hydrogen sulphide. This treatment consisted of adding a nitrate blend – a process which was time consuming and also had to be kept under careful control.

Once the hydrogen sulphide had been reduced to an acceptable level, work could begin to remove the oil/wax deposit at the top of each cell. The narrowness of the access called for the development of special equipment to handle this job. It had to both clean the ceiling and remove the coating by skimming the water. Because the tank cells had been filled with only water since the mid-1970s, oil deposited during storage was assumed to have been washed out and replaced with a new biological film. No technical or chemical solutions were recommended, because this film would probably decay over time without damaging side-effects.

Sediments in the cells and the annular spaces were removed with the aid of remotely-operated sludge suction. While remotely-operated vehicles (ROVs) could operate in the annular spaces, special equipment developed for shutting down and disassembling nuclear power stations was used in the cells. Water and sludge were sucked up to the deck, where a treatment plant had been installed. This comprised cyclones, separators and filter units. After removing sludge and hydrocarbons, the water could be recirculated or discharged overboard – providing it was sufficiently clean. The separated sludge and hydrocarbons were collected in a dedicated tank before being transferred to the Ekofisk 2/4 X platform for injection back into the sub-surface.

Proposition no 51 (2001-2002) was considered by the Storting on 11 June 2002, and the government’s recommendation was unanimously accepted without debate. ConocoPhillips (as the operator had now become) could thereby start awarding the necessary contracts for preparing the tank and taking away its superstructure.

Removing the latter, which weighed just over 24 000 tonnes, was assigned to AF Decom. The offshore work started once the clean-up has been finished.

The tank superstructure was demolished with the aid of excavators fitted with cutters – an approach used for a number of such jobs on land, including the Sola refinery in Tananger. Structures were cut into pieces and roughly sorted offshore before being placed in containers. These were carried by supply ships to Raunes for final sorting. Finally, the scrap was shipped to a recycling facility or for possible deposition. The goal of achieving a recycling factor of 97-98 per cent was met.[REMOVE]Fotnote: ConocoPhillips, “Anlegg for landdisponering blir klargjort”, Nordsjø-Pioner,  December 2004.

The demolition job finished on 11 May 2007, when the final consignment of scrap from the steel superstructure was shipped to AF Decom’s facility at Vats north of Stavanger.[REMOVE]Fotnote: ConocoPhillips, “Pionér også i sistevers”, Nordsjø-Pioner, no 3, April 2007.[REMOVE]Fotnote: ConocoPhillips, “Slutt på Ekofisk-tanken”, Nordsjø-Pioner, no 5, June 2007.

Cleaning the tank was carried out in two phases, starting with the storage cells and followed by the extensive job of removing the superstructure. Cell cleaning began in the summer of 2004 and was completed in the course of a year. Structural demolition then started in the summer of 2005 and took almost two years.

The second cleaning phase, covering the annular spaces, got under way in the second quarter of 2007, and was finished in late 2008. It was not until the summer of 2009 that the Ekofisk tank was finally declared to be in resting condition – after serving ConocoPhillips and Norway for more than 30 years since 1973.

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.

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 chairing a research programme on offshore safety, which led to legislation enacted by the Storting (parliament) and a bigger research effort. 

Joining Phillips

Åm secured a job with Phillips in 1982 and was soon sent to the head office at Bartlesville in Oklahoma to get better acquainted with the company and its corporate culture. 

After a year in the USA, he returned to the company’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 Basins at 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 for a 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. 

Optimist

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