A number of factors prompted this initiative, including the fact that all the discoveries made on the Halten Bank in the Norwegian Sea since the 1980s were in relatively deep water.[REMOVE]Fotnote: www.npf.no/nyheter/kristiansund-onsker-subsea-aktivitet-vil-bli-best-pa-bunnen-article3328-193.html
Depths of 300 metres or more had encouraged a preference for subsea development solutions, and a number of fields in this part of the NCS utilised these during the 1990s.
Seabed wells for oil and gas production as well as for water and – temporarily – gas injection were already installed on Draugen when it came on stream in 1993.
Heidrun, with Statoil as operator once production began in 1995, had a concrete-hulled tension-leg platform (TLP) positioned over a subsea well template. The northern part of this field was also developed later with seabed installations.
And Smørbukk, Smørbukk South and Midgard – operated by Statoil as the unitised Åsgard field – were brought on stream in the 1990s with the aid of seabed wells.
These are tied back to the Åsgard A floating production, storage and offloading (FPSO) unit and the semi-submersible Åsgard B platform for processing gas and condensate.
All these projects called for base facilities and subsea technology expertise. So did laying the Haltenpipe gas pipeline from Heidrun to Tjeldbergodden north of Kristiansund in 1996-97.
Even more extensive was the huge Ormen Lange development in 850-1 100 metres of water, where unprocessed production is piped directly to Nyhamna between Kristiansund and Molde to the south.
After processing there, gas from the field is transported on through the Langeled export pipeline to the UK, which was completed in 2007.
Subsea at Vestbase
Kristiansund’s Vestbase offshore supply facility was perfectly positioned to support exploration operations on the Halten Bank when these began in the 1980s.[REMOVE]Fotnote: Hegerberg, 2012: 79–82.
Harbour conditions were good, and the base was the closest point on land from the fields in this part of the NCS. It provided supply, logistics and servicing for units in the Norwegian Sea.
Securing the operations organisation for Draugen and the base function for Heidrun meant that Kristiansund could truly call itself an oil centre.
That was reinforced when Norsk Hydro decided to position its operations organisation for Njord in the town. This field came on stream in 1997 from a semi-submersible drilling and processing platform tied to subsea wells.[REMOVE]Fotnote: Hegerberg, 2012: 84–86. Statoil took over this organisation after merging with Norsk Hydro’s oil division in 2007.
But Shell was much more important for Kristiansund, with 60 employees at its Råket office and 120 working an offshore rotation on Draugen.[REMOVE]Fotnote: Project assignment on value creation in the Draugen operations organisation, management programme, BI Norwegian Business School, 1998. Hydro’s local team totalled just 15-20 people.
Developments on the Halten Bank in the 1990s and beyond called for relatively substantial support, and suppliers in the town specialised in underwater services – such as pipelaying and advanced subsea technology.
Companies at Vestbase provided servicing and maintenance for subsea facilities, while large service firms opted to open branch offices and workshops there.
Subsea 7 was one of the earliest players to become established at the base, and had been operating in Kristiansund since 1985 until the oil slump in 2016 put a temporary halt to its business.
Kongsberg Offshore Subsea, now TechnipFMC, opened service shops in the early 1990s to provide installation and operational support for Draugen.
Vestbase was later expanded to handle maintenance of subsea equipment for Statoil’s Norne, Åsgard, Kristin, Heidrun and Mikkel fields, including mobilisation and demobilisation of equipment.
Subsea facilities for the Ormen Lange field operated by Shell have also been maintained from TechnipFMC’s service shop in Kristiansund.[REMOVE]Fotnote: Iris report 2013/031: 134.
Stavanger-based Subsea Services established a workshop as well as plant and coating services at the base, offering surface treatment to the strictest Norsok standards.
This company has a big storage area covering 8 000 square metres and its own quay able to handle supply ships up to 120 metres long.[REMOVE]
Up to 2014, great optimism prevailed about what subsea technology could bring to Kristiansund in the form of commercial activity. A feeling prevailed that easy money was to be made here.
That impression was entrenched after two entrepreneurs, Olav Kvalvåg and Terje Fagervold, sold GTO Subsea to America’s Oceaneering for NOK 210 million in 2008.
This Kristiansund company delivered solutions for trenching and moving bottom sediments to development projects in water depths right down to 1 700 metres.
Based on a rock suction device with its own seabed pump, GTO Subsea started modestly in an attic room at Leira in Aukra local authority near Kristiansund in 1999. It had developed into one of the world’s leading suppliers in its speciality.[REMOVE]Fotnote:Tidens Krav, 5 March 2008, “GTO solgt”.
Disappointment locally was great when Oceaneering moved the whole business and its associated jobs to Stavanger.[REMOVE]Fotnote:Tidens Krav, 3 September 2009, “Mister unik teknologibedrift”. But so many projects were under way in the Norwegian Sea that Kristiansund’s subsea community saw little reason to grieve for long.
Statoil’s Tyrihans oil and gas field came on stream in July 2009, for example, as a complete subsea development tied back to existing Halten Bank facilities on the Kristin and Åsgard fields.
The full impact of the crisis sparked by the oil price slump had still not made itself felt when the Norwegian Petroleum Society held an evening session on subsea in Kristiansund.
Staged in February 2014, the menu for this meeting promised presentations, dinner and good conversation fronted by the following assessment:
Progress in subsea technology lays the basis for developing oil and gas fields commercially in ever deeper waters. Norwegian industry currently meets no less than 50 per cent of global demand for subsea equipment for the petroleum sector, and this market could double by 2020. The number of subsea-related companies in Møre og Romsdal is also growing, and many of tomorrow’s jobs will precisely be linked to this sector.[REMOVE]Fotnote: https://www.npf.no/nyheter/subsea-helaften-i-kristiansund-article4676-193.html
The petroleum industry had little premonition of how low oil prices were about to sink, and of the scale of the downsizing and company mergers required in order to remain competitive.
In the prevailing optimistic mood, the subsea business was expected to need many new people. Bergen’s Western Norway University of Applied Sciences, for instance, set up a separate underwater technology department in Kristiansund.
It was intended to supplement existing engineering courses provided in this field both in Bergen and the offshore centre of Florø in Sogn og Fjordane county.
Educating students in close collaboration with the industry and bases was seen as an advantage. The first student cohort started at the University College Centre in Kristiansund in 2015.
As early as the following year, however, the number of applicants for this course was so low that it became too expensive to accept another cohort.
To make it more attractive, the curriculum has been widened to ocean technology rather than an exclusive concentration on the subsea aspect – a decision not simply snatched out of the blue.[REMOVE]Fotnote: https://www.tk.no/nyheter/kristiansund/skole/hiksu-tilbyr-forkurs-i-julegave/s/5-51-387658
The focus can easily be shifted towards maritime operations, fish farming in closed facilities, renewable energy offshore, shipping, aquaculture and seabed mining as well as oil.[REMOVE]Fotnote: http://panorama.himolde.no/2016/05/12/tar-ikke-opp-subsea-studenter-i-kristiansund/
This shift in the educational sector is typical of the subsea industry in general during 2014-17. After the euphoria of the 2000s, the sector has cooled considerably and shed many jobs.
Faith in the future
Nevertheless, subsea activity is likely to persist for many years to come. All the existing underwater wells in the Norwegian Sea will need maintenance, for a start.
Moreover, a number of new developments currently in the pipeline will need assistance and competent personnel in the years to come.
Student Serine Åndahl in Kristiansund, who is due to graduate in 2018, puts it this way:
When we’re qualified, they’re screaming for our expertise. Subsea is also the future. Underwater installations are less vulnerable to wind and weather. They’re controlled from land, so you then need engineers rather than people like mechanics, for example.
That view is supported by fellow student Daoud Musagoni. He points out that subsea is an international sector, and says he could well imagine working outside Norway.
And Trygve Maridal Olsen, who has served as an operator at Vestbase, agrees. “Everything’s being put underwater now, so this is the future.”[REMOVE]Fotnote: http://panorama.himolde.no/2015/11/11/nar-vi-er-ferdige-sa-skriker-de-etter-var-kunnskap
Subsea students Trygve Maridal Olsen (left), Daoud Musagoni and Serine Åndahl take a positive view of the future. Photo: Arild J Waagbø, independent webzine at Molde University College.
Published September 11, 2018 • Updated October 17, 2018
The rupture was discovered when no pressure rise could be observed in the injection well. A colorant was added, and the coloured water was observed on the sea surface.
Draugen had two water injectors, positioned at the southern and northern fringes of the reservoir respectively so that water pumped down would drive oil towards the production wells.
After the flowline rupture, only the northern water injector was in use. It was uncertain how this temporary disruption to injection would affect the reservoir.[REMOVE]Fotnote:Tidens Krav, “Brudd i vannrør ved plattformen”, 17 July 1995.
An investigation team, including French flowline manufacturer Coflexip, was established to identify the causes of the failure.
Produced and installed in 1992-94, the flowline was built up of five main layers – an innermost plastic liner, a tension ring, double tensile reinforcement and an outer sheath.
A friction coating was also incorporated between the reinforcement layers, but no outer layer able to resist collapse from external pressure had been provided.
The team concluded that the rupture was caused by a manufacturing fault in the inner plastic liner which had allowed water under high pressure to penetrate the reinforcement layers.
Since the latter were not designed to withstand direct water pressure, they became deformed when powerful forces arose locally in the flowline.[REMOVE]Fotnote: Draugen technical committee, section for marine technology, division for safety and the working environment, Norwegian Petroleum Directorate, 1 February 2000.
Repairs were carried out which allowed water injection through the SWIT to resume at full capacity from the beginning of September. This work cost some NOK 53 million.[REMOVE]Fotnote: Norwegian Petroleum Directorate. Management committee meeting, PL 093, Draugen, 3 July 1995.
Kristiansund daily Tidens Krav asked whether any risk existed of something similar occurring with the oil flowlines on Draugen, but Shell said this was very unlikely.
The flowlines used had been approved and cleared for oil production, it noted, and safety requirements for such clearance were strict.[REMOVE]Fotnote:Tidens Krav, 17 July 1995, “Brudd i vannrør ved plattformen”.
Nevertheless, a similar but more dramatic incident occurred with a Coflexip flowline in 2000. See the separate article on “2000 – second injection flowline failure”.
Published September 11, 2018 • Updated October 18, 2018
Kristin Øye Gjerde, Norwegian Petroleum Museum
A second 10-inch flexible flowline ruptured on 13 January 2000. While the previous incident in 1995 had involved Draugen’s southern water injection template (SWIT), the new break happened with the link to the northern template (NWIT).
— Illustration: A/S Norske Shell/Norwegian Petroleum Museum
The cause was the same as before – a manufacturing error which permitted high local pressure to cause a collapse. See the article on “1995 – first injection flowline failure”.
On this second occasion, however, the incident was assessed to have posed the risk of serious consequences.
After the rupture had occurred, a remotely operated vehicle (ROV) was sent down to document the extent of the damage. Images showed that the flowline to the NWIT had fractured inside a J-tube leading out from the Draugen platform.
As the name implies, such tubes have a sharp bend at the base which penetrates the platform wall. A number of them are available to conduct piping to the seabed – known as pipe-in-pipe.
After further investigations using X-rays, it was determined that the break had occurred close to the end connection. About 180 metres of internal piping had been driven out of the J-tube, while the end and 50-70 metres remained inside.
The flowline had crumpled in a big heap only about 30 metres from the outlet. A lot of gravel and sandbags were displaced, and the flowline lay partly between other piping and control cables. None of these showed visible signs of damage.
Clearing up after the big rupture was a hazardous business, not least because the gas injection riser ran through a nearby J-tube.
The latter would lose its barrier against the platform if the tube carrying the flowline to the NWIT was opened – risky since the gas riser tube was not designed to cope with full internal explosive pressure.
It was therefore thought safer to cover the damaged flowline with rocks and switch to one of the many other J-tubes on the platform. The drawbacks of this approach were regarded as minimal.
The Norwegian Petroleum Directorate (NPD) feared that the cessation of water injection after the incident could have a big impact on reservoir pressure and oil production from Draugen.
Just two weeks after the rupture, wells A4 and A5 were showing a steady decline in pressure. The drop was expected to be 16-18 bar over an estimated injection downtime of two months.
Reducing reservoir pressure posed the threat of more sand in the wellstream and earlier-than-expected water breakthrough in the wells. In the worst case, Draugen could risk coming off plateau production and seeing its output fall sooner than forecast.[REMOVE]Fotnote: Draugen technical committee, section for marine technology, division for safety and the working environment, Norwegian Petroleum Directorate, 1 February 2000.
Despite the failures, flexible flowline manufacturer Coflexip has faith in its product. The pipeline type it had delivered in 1991 was still being produced in 2000.
But the company would not exclude the possibility that fabrication faults might be the cause, and reported that manufacturing methods had been greatly improved in recent years. Shell had not used the flowlines “incorrectly”, it was stressed.
The flowline to the NWIT had been laid in five 1 200-metre lengths, joined with connectors. Only the section closest to the platform was replaced and connected to the rest of the line.
It was therefore convenient that Shell had a 1 200-metre flowline section stockpiled at Vestbase in Kristiansund which could be used. The repair cost was put at NOK 120-170 million.
To prevent a repetition of the incident, Shell was asked by the NPD to present a programme for replacing the flowlines in the longer term.[REMOVE]Fotnote: Draugen technical committee, section for marine technology, division for safety and the working environment, Norwegian Petroleum Directorate, 1 February 2000.
The failure of the water injection line to the NWIT occurred at a time when Shell was giving high priority to the Draugen gas export development.
Involving a tie-in with the Åsgard Transport gas pipeline, this project was pursued in parallel with the repair job, and cross-utilisation of vessels and equipment was explored.
The NWIT flowline repair had top priority in the spring of 2000, without compromising the schedule for the gas export pipeline. Shell succeeded in accomplishing both tasks.
Published September 11, 2018 • Updated October 18, 2018
Offshore could announce in March 1998 that Norske Shell had finally found a buyer for the gas. Development of fields and transport solutions from the Norwegian Sea had now made several strides. In connection with its Åsgard development, Statoil was planning a new gas pipeline to Kårstø north of Stavanger.
This would pass within 78 kilometres of Draugen and laying a spur from that field to a T-joint on the Åsgard line would allow its gas to be sent to Kårstø.
There it could be processed and transported on to consumers in continental Europe.[REMOVE]Fotnote:Offshore, 1 March 1998, “Offshore Europe”. This solution was fully in line with what Shell wanted.
A plan for installation and operation (PIO) of a pipeline to link Draugen with the Åsgard Transport system was submitted to the Ministry of Petroleum and Energy in May 1999.
In the consultation process on this Draugen Gas Export facility, politicians in Møre og Romsdal county council expressed some dissatisfaction.
They wanted clarification of the regional spin-offs from this project, and called for measures to secure more work for mid-Norwegian players in all new Norwegian Sea developments.[REMOVE]Fotnote: Møre og Romsdal county executive board, 16 September 1999, item U-162/99 A: Konsekvensutgreiing for Draugen Gasseksport.
That demand fell on stony ground. The priority was to ensure that Norwegian Sea gas reached the market, and calls for local jobs took second place. The PIO was approved in April 2000.
Draugen Gas Export became operational in November 2000.[REMOVE]Fotnote: Norwegian Petroleum Directorate, 1 October 2007: Helhetlig forvaltningsplan for Norskehavet. Statusbeskrivelse for petroleumsvirksomhet i Norskehavet. Its diameter of 16 inches offered opportunities to tie in several other discoveries in the area.
Once the pipeline was in place, therefore, surplus gas was no longer a challenge for Draugen and new satellite fields were developed.
The Garn West discovery came on stream in December 2001, while Rogn South was approved in the spring of 2001 and began production in January 2003.[REMOVE]Fotnote: Norwegian Petroleum Directorate, 1 October 2007: Helhetlig forvaltningsplan for Norskehavet. Statusbeskrivelse for petroleumsvirksomhet i Norskehavet.
Draugen Gas Export
Total investment: NOK 1.15 bn (2007 value)
Technical operating life: 50 years
Capacity: about two bn standard cubic metres (scm) per annum
Operations organisation: Kristiansund
Length: 707 kilometres
Diameter: 42 inches
Available technical capacity (ATC): 70 million scm/day
Technical service provider: Statoil
Åsgard Transport and connected fields
Statoil was accustomed to taking a leading role in the development of the pipeline network on Norway’s continental shelf (NCS), and did so again when the Norwegian Sea-North Sea link was realised. Growing demand for gas in continental Europe made it possible.
The Midgard discovery operated by Saga and the Statoil-operated Smørbukk/Smørbukk South finds were unitised in 1995 to create a new licensee structure with Statoil in the driving seat.
Renamed Åsgard, this area became the subject of the biggest single development on NCS, which made extensive use of increasingly tested and reliable subsea technology.
An oil production ship, Åsgard A, and the floating Åsgard B gas/condensate platform were tied to 63 subsea-completed production and injection wells split between 19 seabed templates. The gas/condensate satellites Mikkel and Yttergryta were also tied back to Åsgard B through seabed templates and associated flowlines.
With water depths of 240-310 metres across the area, plans called for oil from Åsgard A to be shipped ashore by shuttle tankers. The big reserves discovered in the Norwegian Sea created the basis for tying this area to Norway’s existing gas transport system in the North Sea. Operational in 2000, the 42-inch Åsgard Transport pipeline is 707 kilometres long from a starting point on the seabed beneath Åsgard B to the Kårstø processing plant.
Gassco is the operator of this system today, with Statoil as the technical service provider. Åsgard Transport can carry 25 billion cubic metres of gas per annum.
All the fields in the Norwegian Sea except Ormen Lange and Heidrun (part) export their gas through the pipeline. In addition to Åsgard, that includes Statoil-operated Njord, Heidrun (part), Kristin and Norne, BP-operated Skarv, and Draugen.
The Njord oil field lies due west of Draugen and came on stream in 1997. Associated gas was initially injected in parts of the reservoir to maintain its pressure. Gas exports began from Njord in 2007, reducing the quantity available for injection. The gas travels through the 40-kilometre Njord export pipeline, which is tied into Åsgard Transport.
Heidrun, on stream since 1993, still sends the bulk of its associated gas to Tjeldbergodden. Opening Åsgard Transport also made it possible to transport part of the gas to Kårstø, but little use is made of this opportunity.
Like Njord, the Norne oil field came on stream in 1997 and its associated gas was injected as pressure support until 2005. Part of the gas was exported via Åsgard Transport from 2001, and all this output from 2005 when gas injection ceased.
The Alve gas/condensate and Urd oil fields pipe their production to Norne for processing and onward transport.
Kristin is a gas/condensate field just to the south-west of Åsgard, which came on stream with a tie-in to Åsgard Transport in 2005.
Tyrihans was tied back to Kristin as a subsea development in 2009. Some gas from Åsgard is injected into this field to improve oil recovery.[REMOVE]Fotnote: Evensen, K., Nøkling, K., Richardsen. M., Sagberg, K.M. & Tjemsland, M.H. (2011. November). Gasstransportkapasitet fra Haltenbanken til Europa. Prosjektoppgave i emnet TPG4140 naturgass. Institutt for patroleumsteknologi og anvendt geofysikk. NTNU. Trondheim. Hentet fra https://docplayer.me/19623826-Gasstransportkapasitet.html
Published September 11, 2018 • Updated October 3, 2018
That focus included strengthening its position on the Halten Bank, where VNG already had holdings in Njord and Hyme and served as operator for Fenja (previously known as Pil og Bue).[REMOVE]Fotnote: The field has been named for the giantess Fenja in Norse mythology. She and her sister Menja were the only workers strong enough to use a magic mill which could grind whatever one wanted. The king ordered them to grind salt, and they were so industrious that the sea has been saline ever since.
Parent company Verbundnetz Gas AG has its roots in the former East Germany, where Technische Leitung Ferngas was created in 1958 as part of power supplier VEB Verbundnetz West in Dessau.
In its early years, the company produced town gas from lignite (brown coal). It expanded operations in 1973 to include importing Russian natural gas.
The present VNG emerged after the fall of the Berlin Wall in 1989. It became the first fully privatised East German on 29 June 1990 – ahead of German reunification on 3 October that year.
International expansion began at the company in the mid-1990s, with operations in Poland, the Czech Republic, Slovakia, Austria and Italy, and it was involved in gas imports and power supply.
With more than 50 years of experience in the energy sector, VNG established a Norwegian subsidiary in Stavanger during 2006. It prequalified as a licensee on the NCS in the same year.
Agreement was reached in April 2009 with US exploration and production company Endeavour International Corporation on acquiring Endeavour Energy Norge AS.
The latter had extensive operations on the NCS, including interests in 21 production licences and the operatorship for several of these. Acquiring Endeavour Energy Norge expanded VNG’s Norwegian exploration and production activities to 19 licences and provided its first involvement in producing fields on the NCS.
Through the awards in predefined areas (APA) round in 2009, the company secured interests in three licences. The next round in 2010 yielded two operatorships and three more partnerships.
It won its first operatorship in the Norwegian Sea through a regular licensing round in 2011, plus interests in six new licences – including four operatorships – in the same year’s APA round.
All four of the APA operatorships and one licence were in the Norwegian Sea. Two further operators and two partnerships were secured in the 2012 APA round. Six new licences – three as operator – were offered to VNG in the 2013 APA round.
Acquiring Chevron’s holding in Draugen reinforced VNG’s position on the Halten Bank. Norske Shell remained operator with a 44.56 per cent holding, while Petoro held 47.88 per cent.
This acquisition doubled the German company’s daily production on the NCS to more than 4 000 barrels of oil equivalent. Atle Sonesen, CEO of VNG Norge, commented:
We are very pleased with this agreement, which supports our long-term commitment to the NCS. We are not only increasing our production and reserve base considerably, but also taking a conscious step to strengthen our position on the Halten Terrace. We have earlier stated that it is natural for VNG Norge to play a prominent future role in this area. Acquiring Chevron’s interest in Draugen represents a new and substantial contribution in this respect, and we are looking forward to getting to grips with the job as an active and competent partner in the licence.[REMOVE]Fotnote: VNG Norge, 19 June 2014. “VNG Norge styrker sin posisjon ytterligere i Norskehavet og dobler produksjonen sin”. Downloaded on 5 April 2018. http://www.vng.no/news/no/vng-norge-styrker-sin-posisjon-ytterligere-i-norskehavet-og-dobler-produksjonen-sin/.
The company secured interests in six new licences, including three as operator, in the 2014 APA round. These holdings were in the North and Norwegian Seas.
VNG was awarded the Gold Crown (Gullkronen) as Explorer of the Year by Norwegian consultant Rystad Energy for the Pil og Bue discovery.
The prize is presented to companies, teams or individuals who have achieved a very good performance and demonstrated outstanding results on the NCS.
Draugen was long a relevant tie-back candidate for a Fenja development. Its production was declining, and the platform could have used the additional supplies of oil and gas.
Nevertheless, VNG ultimately rejected this solution and opted to tie Fenja back to the Njord field.
Published September 4, 2018 • Updated October 2, 2018