The original plan for development and operation (PDO) of Draugen had estimated that the field would only remain on stream until 2010.
However, output over a number of years had established that it would be a long time before the platform had to shut down.[REMOVE]Fotnote:Tidens Krav, 3 February 2012, “Draugen lever minst til 2035”. Its producing life had already been extended to March 2013.
Shell’s operations head was confident that an application would be submitted to the Petroleum Safety Authority Norway (PSA) to keep the field on stream until 2035.
People still believed in February 2012 that Linnorm would be tied back to Draugen – only the investment decision remained to be taken.
It was also revealed that a contract had been awarded to drill four additional wells which would help to double production from the field.[REMOVE]Fotnote:Tidens Krav, 4 February 2012, “West Navigator borer nye Draugen-brønner”.
This optimism persisted throughout February. A major contract was awarded at the end of the month to Aibel, which included a new quarters module with 50 cabins and a new lifeboat station.[REMOVE]Fotnote:Tidens Krav, 29 February 2012, “Shell – Store endringer på Draugen”.
The development concept for Linnorm involved two subsea templates tied back to Draugen for processing and export via the new Polarled gas pipeline from the Aasta Hansteen field.
Unfortunately, the field proved to be less promising than the optimists had assumed. When a wildcat on the Onyx South prospect proved virtually dry, the whole project was eventually shelved.[REMOVE]Fotnote: Petro.no, 20 September 2013, “Linnorm-beslutning i høst”.
An application to extend the platform’s producing life was submitted in the spring of 2015, with the cessation date set as 2024 to harmonise with the expiry of the licence.[REMOVE]Fotnote: Section 25, regulations relating to management and the duty to provide information in the petroleum activities, etc.
In May 2015, the PSA announced that it had consented to an extension of Draugen’s producing life until 9 March 2024. This was still the cessation date for the field in the summer of 2018, and the licensees will have to apply again if a further extension could prove profitable.[REMOVE]Fotnote: Petroleum Safety Authority Norway, 20 May 2015, “Draugen får samtykke til forlenga levetid”.
A well drilled in the summer of 2015 came on stream in late 2017, and a new seabed pump has also been installed to boost flow from this and the other subsea wells.
Reduced oil production from the field in recent years means that supplies of associated gas have become inadequate for power generation. Alternative solutions for maintaining electricity supplies are under evaluation.
To achieve the overall oil output expected by the licensees, the producing life of the subsea installations must be extended. That in turn means the platform has to stay on stream beyond the restrictions which applied in 2018.[REMOVE]Fotnote: Norwegian Petroleum Directorate fact pages, 3 March 2018.
Published August 27, 2018 • Updated October 3, 2018
Four years passed before drilling began, but the crew on the Transocean Leader rig could spud the first wildcat in the middle of June 2004. It took almost a year to complete, but work finished on 2 June 2005 with a small discovery.
Several wildcats were drilled in the acreage dubbed the “golden block” of the 16th licensing round, but none resulted in finds large enough to prompt immediate development plans.
Overall, the discoveries added up to less than had been hoped for, and the reservoir contained gas under high temperature and pressure.[REMOVE]Fotnote: Oljedirektoratets Faktasider (2018)
That could be described as unfortunate, since Shell had been hoping to find oil. Its optimistic plans for this Onyx discovery were accordingly toned down, but an appraisal well was drilled in the spring of 2007 to learn more about the reservoir.
More gas discoveries were eventually made further north in the Norwegian Sea. The most promising was Luva, discovered in 1997 and renamed Aasta Hansteen on 8 March 2012.
But substantial development was delayed, partly because the finds were too small and partly because of the need to lay an export pipeline.
Two large gas transport facilities from the Norwegian Sea existed after 2007 – Åsgard Transport and Langeled. However, these lacked the spare capacity to handle additional volumes.
Fresh efforts to come up with a development solution were initiated in 2010. Great optimism prompted a competition to find a new name for Onyx, which was renamed Linnorm in the autumn.[REMOVE]Fotnote: Shell World Norge (1 – 2010) s. 27
In addition to launching the name hunt, the first issue of the Shell World Norge house journal contained several buoyant articles about expectations for the discovery.
Under the headline “Exciting times for Onyx”, project manager Tom Egil Karlsen wrote:
Before Christmas last year, we reached the first major milestone which marked that we had completed a successful feasibility study. This is known in the project world as decision gate (DG) 2. The next step will be to look more closely at how a development can happen in practice. In this round, we’ll be looking together with our partners at all possible solutions for a development. We’re working a little in ‘wide angle’ before narrowing our sights to the options which prove the best.[REMOVE]Fotnote: Shell World Norge (1 – 2010) s. 6
Norske Shell vice presidents Grethe Moen and Knut Mauseth were also quoted about their optimism for Onyx.
A press release the following summer made it clear that the best solution for Linnorm involved a subsea installation tied back to the Draugen platform.
Gas from there and Luva would be piped to Nyhamna for processing and onward transport, together with output from Ormen Lange, through Langeled to Easington in the UK.
That could be accomplished by installing a 3 000-tonne process module on the Draugen facility and by making a number of substantial modifications.
The plans indicated that Linnorm could come on stream in 2017 and Luva a year later, and a detail design project was launched to identify the final configuration.[REMOVE]Fotnote: Helge Hegerberg, Adresseavisen (15.6.2011) Draugen tar Linnorm s. 27
By the early autumn of 2012, Shell and a number of other oil companies – Statoil in particular – appeared to have come up with a possible solution for developing several gas finds in the area.
These would all be tied into a new transport system named the Norwegian Sea gas infrastructure, which is better known today as the Polarled pipeline.[REMOVE]Fotnote: Stein Tjelta, Sysla Offshore (13.01.2012) Shell går videre med Linnorm
At that time, Linnorm and Luva/Aasta Hansteen were regarded as the cornerstones for achieving commercial development of all the gas fields in this part of the Norwegian Sea.
An impact assessment presented by Shell in September 2012 again envisaged a 50-kilometre pipeline tied back to the Draugen platform.[REMOVE]Fotnote: A/S Norske Shell (September 2012) Plan for development and operation of Linnorm, part 2, impact assessment.
The latter would have to be expanded to process 15 million cubic metres of gas per day, which would require the construction and installation of several new modules.
At that time, oil was well over USD 100 per barrel and gas prices were also sky-high. The market looked like stabilising at a three-figure oil price.
A development project for Linnorm was costed at close to NOK 10 billion, and the project management envisaged the licence taking an investment decision in the autumn of 2013.
The plan for development and operation (PDO) of this field was expected in January 2013. On 20 November 2012, however, work was postponed indefinitely in anticipation of results from a well to be drilled further south on the discovery.
Hopes were high that this appraisal would prove gas which increased the reserve base and thereby justified development of the whole field.
In practice, however, the well was declared dry on 5 September and Linnorm seemed to have been definitely abandoned.
The following comment from Terje M Jonassen, Norske Shell’s communication manager for exploration and production, was reported in the press:
This was not what we hoped for when we started drilling. Where Linnorm’s future is concerned, no decision has yet been taken. The way forward will be discussed with the partners in the licence, who will take a joint decision on this.[REMOVE]Fotnote: Toril Hole Halvorsen (20 September 2013), “Linnorm-beslutning i høst”, Petro.no.
Shell has not given up on Linnorm, even though initial efforts to achieve a development were unsuccessful. The area is still being assessed in 2018 on the basis of new solutions which could yield a financially and technically feasible project.
Published August 27, 2018 • Updated October 8, 2018
Positive news about the field was important in 2000 after seven years on stream and with oil prices low. So Kristiansund’s local paper reported that Shell was fully committed to producing on the Norwegian continental shelf (NCS), and mid-Norway in particular.
This article in Tidens Krav focused on Draugen’s many positive aspects and included the following comment:
A couple of world records have also been set on Draugen. This time, [it] can claim the longest continuous period of production after 176 days without a shutdown. The other record is that one Draugen well has produced 76 775 barrels of oil over a single day. This is the highest daily output from an individual well.[REMOVE]Fotnote:Tidens Krav, 19 January 2000, “Har fullt fokus på midtnorsk sokkel”.
Whether these actually ranked as world records was not perhaps confirmed, but the quote demonstrates the importance of positive news in this period.
These records were also highlighted in the field’s 10th anniversary year. A major article in Trondheim daily Adresseavisen hailed Draugen as the “jewel in the crown”:
When operator company Norske Shell applied to the government in the autumn of 1987 to develop the field, it planned to produce 90 000 barrels per day [b/d]. When it brought Draugen on stream from 19 October 1993, it quickly managed to bring up a lot more. At peak, Shell produced 230 000 b/d. Production has lain at a level of more than 200 000 b/d of treated oil over many years, without water breakthrough. A world record has also been set 150 kilometres north-west of Kristiansund: no individual production well has produced more than 77 000 b/d. These records have meant a lot in value terms. The 77 000 barrels which were the result on 12 October 2003 represented almost NOK 47 million, or more than NOK 32 000 per minute. The single well which set the record on 20 October 2000 contributed NOK 500 000 to profits on that day.[REMOVE]Fotnote:Adresseavisen, 16 October 2003, “Draugen er Norges mest lønnsomme tiåring”.
Small gas deposits close to Draugen generated great optimism in 2010-13. The little Linnorm discovery, in particular, was a hot candidate for tie-back to the platform.
That would allow the latter to stay on stream even longer than the planned production period until 2028 – which had been lengthened from an original extension to 2020.
Although development plans for Linnorm were ultimately shelved, it is worth noting the optimism which prevailed in Draugen’s 20th anniversary year as expressed by Tidens Krav:
Within a few months, the first oil field brought on stream north of Stad [the northern limit of the North Sea] will reach its 20th anniversary. When the plan for development and operation was submitted to the authorities in 1988, Draugen was expected to produce for 17 years and achieve a recovery factor of 38 per cent. Shell’s tough target is now to recover no less than 75 per cent of the resources up to 2036. In the event, that would be a world record for offshore oil fields.[REMOVE]Fotnote:Tidens Krav, 7 May 2013, “Nr. 1.000 fra Draugen”.
In this case, the “world record” claim was perhaps prompted by local patriotism. Shell also issued a more restrained press release, which stated in part:
Draugen has delivered crude oil stably since it came on stream in 1993. The field has delivered a much higher volume than originally expected, and is in position to take the gold medal for recovery factor. According to the original plans, Draugen should have ceased production after 17-20 years, but its producing life will be substantially extended.[REMOVE]Fotnote:Teknisk Ukeblad, 21 October 2013, “Flyttet brønnen en kilometer, fikk et helt oljefelts produksjon tilbake”.
To put this last record in context, Draugen can be considered from a Norwegian perspective. The perception generally prevails that petroleum resources on the NCS have particularly good production properties compared with many other parts of the world.
That has perhaps also made it easy to equate “best in Norway” with “best in the world” – a conclusion which is not always entirely true.
The recovery factor specifies the technically and commercially recoverable petroleum in a reservoir as a proportion of the stock tank oil initially in place (Stoiip) – in other words, the original resources present.
In order to compare fields with different mixes of oil and gas, all petroleum quantities are converted to oil equivalent in order to determine the total quantity in the reservoir.
Compared with all 115 of the fields which are, have been or will soon be in production on the NCS, Draugen occupies 22nd place for recovery – so not quite top of the overall list.
However, a big difference exists between fields which primarily produce oil and those which only yield gas. The oil-gas ratio (OGR) is often used to distinguish between the various categories – the higher the figure, the more the oil.
As figure 1 shows, an oil field more often has a lower recovery factor than one producing primarily gas.
Looking at the most typical Norwegian oil fields (OGR > 0.9) presented in figure 2, the claim that Draugen belongs in the premier division for recovery is pretty clearly established.
At 31 December 2017, Grane was the only field on the NCS which had a slightly higher recovery factor than Draugen – at 67.2 per cent compared with 66.9 per cent.[REMOVE]Fotnote: Norwegian Petroleum Directorate (2018), Fact pages – Fields. Downloaded 30 April 2018. http://factpages.npd.no/factpages/Default.aspx?culture=no.
Published August 24, 2018 • Updated October 10, 2018
It became known in February 1994 that the operator was assessing prospects for increasing daily production from the field by 30-50 per cent.[REMOVE]Fotnote:Dagens Næringsliv, 14 February 1994, “Ekstra mrd. til Draugen-eierne”.
Two new wells and some minor modifications to the platform could boost output by 40 000 barrels per day (b/d). That would greatly improve profitability but was not without problems.
While Shell said Draugen was financially robust, a number of questions had been raised about the field’s profitability after oil prices had fallen steadily from USD 20 per barrel in the summer of 1992 to below USD 15 in the autumn of 1993.
The company claimed that Draugen would continue to do well at this price level, and that it could even survive prices close to USD 10 per barrel.
Raising production above 100 000 b/d would let the government invoke the “sliding scale”, which allowed it to increase the state’s holding in the field by about 15 per cent.
Higher output would thereby be very good for the government, but unprofitable for Draugen partners Shell, Statoil and BP – who threatened to veto an increase if the sliding scale was applied.[REMOVE]Fotnote:Bergens Tidende, 25 August 1994, “Dragkamp om Draugen”.
Although the position remained unclarified, Shell drilled new wells during 1994. A compromise was negotiated the following spring which resulted in a Storting decision on 12 June 1995.
Claims by the licensees that full implementation of the sliding scale would make a production rise unprofitable were only partly accepted.
The upshot was that the government increased Statoil’s interest in the licence by eight per cent while reducing the Shell and BP holdings by 4.8 and 3.2 per cent respectively.
While the change in licence holdings took effect on 1 July, the platform jumped the gun by boosting output to 140 000 b/d from 28 June.
Shell was decidedly unhappy about the new division of interests, but operations head Knut Engebretsen confined his comments to saying: “we can live with this”.[REMOVE]Fotnote: Bergens Tidende, 29 June 1995, “Kraftig økning på Draugen”.See also the article about the licensees on Draugen.
Published August 24, 2018 • Updated October 9, 2018
June 1995: Draugen Upgrade – production capacity increased
The first phase of upgrading the Draugen production facilities was completed over a 10-day period in late June 1995. This work was carried out with the platform shut down, and no problems were encountered during the subsequent restart.
Maximum oil output was thereby increased to 155 000 barrels per day (b/d), which corresponded to an annual average of 140 000 b/d.
Work included correcting inefficient design solutions, replacing control valves, installing larger piping and upgrading the emergency blowdown system on the second-stage separator.
Phase two of the project was carried out the following year to secure a 10 per cent rise in maximum production without affecting operating stability.[REMOVE]Fotnote:EPO info, no 4 1995, “Oppgraderingen på Draugen: Suksess i første fase”.
May 1997: drilling rig removed
The decision to remove the drilling rig on the Draugen platform was taken in January 1997. Although only five wells had been drilled since production started, the facility was not required. Maintenance work would also be reduced.
Work began as early as 10 April, and was completed in exactly a month thanks to the deployment of efficient access techniques.[REMOVE]Fotnote:Shell UP no 5, June 1997, ”Fjerning av boremodulen på Draugen”.
In the early autumn of 2012, Shell – with a number of other oil companies, and Statoil in particular – appeared to have found a way to develop several gas discoveries in the Draugen area.
This involved connecting all of them to a new transport system initially called the Norwegian Sea gas infrastructure, and later renamed Polarled.[REMOVE]Fotnote:Sysla Offshore, 13 January 2012, ”Shell går videre med Linnorm”.
At that time, the Linnorm and Aasta Hansteen discoveries were regarded as the cornerstones for achieving commercial development of all the gas fields in this part of the Norwegian Sea. Shell therefore planned to extend Draugen’s producing life until 2036.[REMOVE]Fotnote:Midt-Norsk Olje & Gass, no 2, 2012, ”Draugen til 2036”.
The original PDO had assumed that the field would stay on stream for 20 years. Its official producing life accordingly expired in 2013.
Shell intended to apply to the Petroleum Safety Authority Norway (PSA) and the Norwegian Petroleum Directorate (NPD) to use Draugen beyond its initial cessation date.
In order to operate the platform safely and prudently after 2013, it was important to be able to demonstrate that good care was taken of system integrity throughout.
Both technical and organisational analyses were conducted so that Shell could demonstrate the acceptability of keeping Draugen on stream.
Its application to the authorities also detailed plans for the measures which were required. In an interview with the journal Midt-Norsk Olje & Gass, operations head Gunnar Ervik commented:
They hoped for a producing life of 17 years, we have now passed 18 and are not going to give up any time soon. We may perhaps be only halfway through the field’s producing life. Regardless of how you measure it, Draugen has always delivered and I’m proud to have been part of that. I regard the fact that the Linnorm licensees chose Draugen as its host platform as proof that we’re on the ball, and competitive.[REMOVE]Fotnote:Midt-Norsk Olje & Gass, no 2, 2012, ”Draugen til 2036”.
Ervik’s comments were followed up by Norske Shell project director Bernt Granås. He noted that the Draugen and Troll A projects had been used in the 1980s and 1990s to build up the company’s project capability.
The new plans for extending Draugen would play a very important part in rebuilding this expertise. An investment decision on Linnorm could hopefully extend the platform’s producing life by 25 years.[REMOVE]Fotnote:Midt-Norsk Olje & Gass, no 2, 2012, ”Draugen til 2036”.
Shell’s ambitious plans for keeping the field on stream led to the award of a 10-year frame contract to Aibel, which would handle design and execution of conversion jobs large and small.
The assignment was one of the most significant in the history of this Norwegian offshore service company, and offered it opportunities for growth in Kristiansund.[REMOVE]Fotnote: Aibel website, 13 November 2013.
Planned project activities on Draugen
Injection of produced water back into the reservoir. Installation of a new loading system. Removal of the former loading buoy. Drilling of four new subsea production wells.
Installation of a subsea booster pump to provide an extra push to the wellstream and thereby help to increase production.
Installation and tie-in of new pipelines and umbilicals.
Installation of new lifeboats.
Modification and upgrading of equipment, both on the platform and subsea – a number of projects fall into this category.
Installation of an additional quarters module with 45 extra berths.
Upgrading to handle gas from Linnorm (conditional on a final investment decision).
Aibel’s first project under this contract was the construction of a new lifeboat station and quarters module – the latter in cooperation with a Dutch fabricator.
But expectations for Linnorm proved over-optimistic in late 2012 and early 2013. Work was postponed indefinitely on 20 November and, after an appraisal well completed on 5 September proved dry, the development was shelved.[REMOVE]Fotnote: Petro.no, 20 September 2013, “Linnorm-beslutning i høst”.
However, the two fabrication projects went ahead. Both structures were lifted into place on 10 November by Heerema’s Thialf heavy-lift ship without damage or accidents of any kind.
The Draugen platform’s strategic location means it has been the candidate for tie-ins of smaller oil and gas fields in the same area.
It became known in November 2014 that the facility was being regarded as a possible host for production from the Pil og Bue and Snilehorn discoveries, operated by VNG and Statoil respectively.[REMOVE]Fotnote:Sysla, 20 November 2014, “Draugen trenger nye funn for å overleve”.
The application to lengthen the field’s producing life was therefore maintained, and the licensees were informed in May 2015 that the production licence had been extended to 9 March 2024.[REMOVE]Fotnote:Offshore Energy Today, 21 May 2015, “Life extension for Shell’s Draugen (Norway)”.
But it became clear during 2016 that both Pil og Bue and Snilehorn would be tied back to “rival” Njord. That put a temporary stop to the many plans for the Draugen platform.
Published August 23, 2018 • Updated October 9, 2018
Transocean Drilling, which had taken over the Aker Drilling company, was commissioned to disassemble and remove the rig. Work began on 10 April and finished a month later.[REMOVE]Fotnote:Shell UP, no 5, June 1997.
Apart from the mud pumps, the whole package was modularised – put together from separate, relatively small units – to simplify removal and reuse.
This solution proved advantageous and meant that the whole job could be done with a limited number of people, using the platform’s own cranes to handle the modules.
No heavy-lift vessel therefore had to be chartered, which made the removal decision much easier to take from a purely financial perspective.
Nor was additional transport needed, since a recent shipping pool agreement (also covering large supply vessels) for the Halten Bank fields allowed components to be sent free as return cargo.
All the work was done without any accidents or other undesirable incidents, and production continued
unabated throughout the disassembly process.
After removal, the drilling rig was held in intermediate storage at Vestbase in Kristiansund before being shipped on to Forus outside Stavanger.
The package has been sold during the spring to the Stavanger-based Hitec company, which had delivered it originally in partnership with Canada’s Dreco.[REMOVE]Fotnote:Stavanger Aftenblad, 16 October 1997, “Hitec kjøper borerigg”.
Hitec had intended to use the rig for a particular project which failed to materialise. Soon after 2000, however, an inquiry was received by RC Consultants in Sandnes south of Stavanger.
Passed on by Hitec from the Norwegian agent of Russian state oil company Rosneft, this involved an invitation to tender for conversion of the Ispolin heavy-lift vessel to a drill ship.
Rosneft therefore needed a rig for the project, which was aimed at drilling the first well in the Russian sector of the Caspian, and the Sandnes company won the job.
This was accordingly a story of exporting Norwegian petroleum expertise, reusing offshore equipment from Norway and Russia’s commitment to increasing its oil production at the time.
RC Consultants’ contract was originally worth NOK 120 million, including the drilling module and engineering services related to its testing, transporting, installing and commissioning.[REMOVE]Fotnote:Stavanger Aftenblad, 4 February 2003, “Russisk borerigg gir kontrakt til Sandnes”.
“This rig only drilled five wells on Draugen from 1993, so I regard it as almost brand new,” Egil Tjelta, CEO of RC Consultants, told local daily Stavanger Aftenblad.
Trial assembly and testing of the package took place at Offshore Marine in Sandnes during the spring of 2003 under the supervision of five Russian engineers.
It was then broken down into two parts and transported to the port of Astrakhan on the Caspian in April. All this work was carried out with no problems of any kind.
Different routes were taken by the rig sections, with one travelling by barge through the Straits of Gibraltar and via the Mediterranean, the Black Sea and canals.
The other was carried by a specially adapted river boat via St Petersburg, the Russian canal system and the Volga, which empties into the Caspian.
Installation on the ship occurred in Astrakhan, which is where the problems started. Nobody had told the Norwegian engineers that drilling would take place in very shallow water.
The ship was actually due to sit in the seabed, because the Caspian in this area is only about five to 10 metres deep. Drawing on experience from Norwegian conditions and international safety standards, all warning lights flashed.
Installing the derrick and equipment presented no difficulties, but the fact that operational safety was not approved meant that a drilling permit could not be obtained.
The drill ship was admittedly renamed by President Vladimir Putin, but that carried no weight with the regulators. The project was shelved, but Ispolin was later used for other drilling jobs in the Caspian.
Finn Harald Sandberg, Norsk Oljemuseum og Ole Gammelsæter, A/S Norske Shell
Oil from Draugen is stored temporarily in the cells at the base of the platform before being pumped via a flowline to a loading buoy. Specially designed shuttle tankers load the crude for shipment to land.
— Illustration from Draugen field Plan for development and operation 1987
It became clear on 3 May 1991 that Aker Verdal was to build the first loading buoy which would ensure that oil from Draugen could be exported via shuttle tankers.
This NOK 345 million contract represented a collaboration between the yard, concrete platform builder Norwegian Contractors and Switzerland’s Single Buoy Moorings Inc (SBM).[REMOVE]Fotnote:Dagens Næringsliv, 4 May 1991, “Aker Verdal bygger lastebøye til Draugen”.
The buoy comprised a 100-metre-high cylindrical column with a maximum diameter of 8.6 metres, to be moored in 250 metres of water with the aid of six anchors.
Thirty metres of the column was visible above the sea and carried a rotatable topside containing a modest living quarters (for emergency overnight accommodation).
In addition came a small instrument room, a generator room, a workshop container and so forth, plus a helideck and loading boom for connecting to the loading system in the shuttle tanker bows.
This topside structure accounted for about 350 tonnes of the total weight of the floating loading platform (FLP), which came to 4 100 tonnes.
It was installed about three kilometres from the production platform, and was connected to the latter by two 16-inch flow lines.
As early as six years after oil production began, however, Shell began to seek a replacement for the FLP which guaranteed a longer working life.[REMOVE]Fotnote: Petro.no, 4 February 2000. “Draugen får ny lastebøye”.
This was rendered necessary by the realisation that the field would remain on stream beyond the 20 years specified in the plan for development and operation (PDO).[REMOVE]Fotnote: A/S Norske Shell (September 1987), PDO, chapter 4.3.1.
The weather in the Norwegian Sea was a challenge which restricted when loading could take place. Shell therefore wanted to improve accessibility for the shuttle tankers.
In 1998, however, no technology was available which could provide the required loading window. More than a decade was to pass before an appropriate solution had been found.
However, an accident occurred in January 2008 while loading oil on Draugen at the same time as a project to expand the capacity of the FLP system was under way.
The Navion Skandia tanker was lifting a cargo destined for a refinery in the North Sea basin when a leak occurred which caused a crude oil spill directly to the sea.
This had no major environmental consequences.[REMOVE]Fotnote: Petroleum Safety Authority Norway, Report “Draugen – brudd i lasteslange 10.01.2008. But a similar accident had occurred on the Statfjord field in the North Sea the year before, when the actual loading hose was damaged.
In the Draugen case, the cause was not the hose itself but activation of a special release coupling which disconnected ship and buoy. Its design meant only a limited volume was discharged.
Shell subsequently intensified its search for an improved loading system, and opted for a solution developed by Norway’s Framo Engineering company.
Despite being untried, this was chosen in preference to several similar designs which were outcompeting the buoy solution which had dominated offshore loading since the early 1980s.
The contract to take away the old Draugen buoy and install the new system was awarded in 2008 to Subsea 7 together with Bukser & Berging.
Removing a simple buoy from the field might seem a fairly straightforward business, but this job turned out to present a few challenges.
Planning was well under way when preparations for installing the new system were halted – in part because of problems with the design requirements. That slowed progress and delayed start-up.
Towing the former Draugen FLP began on 7 October 2012, using all three of the old towrope attachments to ensure a controlled move away from the safety zone around the platform.
As soon as the buoy was outside this mandatory 500-metre area, one of the cables was cast off from its attachment in order to speed up the tow.
When the voyage had got underway, however, a certain amount of swaying was experienced which threatened to put extra strain on the connection between column and topsides.
Such motion was not unexpected once speed, waves and weather picked up, but it began almost immediately. But the tow went well because some compensatory measures had been taken.
The actual topside was installed on a slewing crane bearing, precisely to offset the effect of sea forces even during normal operation.
A brake disc has also been incorporated in the bearing with a governor system (brake callipers) intended to moderate and control such motion.
Exactly a week later, on 14 October, the buoy moored at the town of Stord south of Bergen to be readied for disassembly and recycling.
The Norwegian Coastal Administration had given Scanmet AS permission to moor in a position off Eldøyane for 180 days before the buoy was towed off for scraping.
It became clear in the early spring of 2013 that this operation required more planning, and a temporary mooring permit was obtained up to 1 October.
On 9 September that year, the coastal administration informed Stord local authority that this permit had been extended to 1 June 2014.
This was because planning and preparing for the removal of the submerged part of the buoy proved far more complicated than first thought.
The column stood vertically in the sea, but it needed to be turned on its side. That called in turn for a powerful lifting vessel.
Long planning and finding spare lift capacity meant the job was not ready in September, and the operator could not guarantee that the column would be removed before the spring of 2014.
However, the topside was disconnected from the column and taken ashore during October 2013.[REMOVE]Fotnote:Stord Nytt, 16 September 2013, ”Ny utsetting for hogging”.
The following spring, the column was turned to a horizontal position, lifted and put on a barge. This could then be floated into the dry dock at the Kværner Stord Verft yard.
After being cut into lengths of 10-15 metres, it was taken by a multiwheel transporter to the Scanmet scrapping site for cutting into smaller chunks, sorted and sent to various metal smelters.
The replacement Framo submerged loading system (FSL) comprises a number of components with different functions, including a seabed base supporting a rigid riser.
This base primarily provides a fixed point for two flowlines bringing oil from the platform. The riser has a flexible coupling to the base and is kept vertical by a buoyancy tank located about 75 metres beneath the sea.
Two swivels installed on top of the tank allow a shuttle tanker to weathervane freely in relation to wind and current. The actual pick-up system for the hoses is supported by special buoys.
Components are also installed in the seabed base for tension monitoring of the vertical riser and a radio link with the tanker to monitor its position and avoid hazards during loading.
Although the first FSL components were placed on the field by Subsea 7 in 2009, the new system did not become operational until 2012.[REMOVE]Fotnote:FFU, no 1, 2013, ”Subsea 7 fornyer Draugen Oil Export system”.
The many challenges faced in designing the new solution had delayed equipment deliveries. Plans and the installation method needed to be adjusted several times along the way.
After the base and flexible flowlines from the platform were put in place, the 155-metre-long riser was towed to the field submerged between two tugs.
The tube was supported en route by a combination of buoyancy tanks and chains. On arrival, it was “parked” on the seabed about 500 metres from the old FLP to await the buoyancy tank.
It took almost three years to put all the pieces of the jigsaw in place. Problems with the buoyancy tank led to a two-year delay and almost 12 months was needed for final assembly.
When the tank was loaded out from Kristiansund, it weighed about 210 tonnes. It was then towed horizontally to an inshore mooring site before being ballasted down to a vertical position.
Following tank tow-out to the field and a complex but successful hook-up, the system was ready for use and the old FLP could be disconnected and prepared for removal.
As mentioned above, the new FSL comprises two independent export flowlines. After an early cargo had been lifted, a valve on one of these became stuck in a virtually closed position. It could then no longer be used for loading.
One reason why two flowlines were installed was to allow the system to be pigged – cleaned and inspected by pumping through a spherical device known as a pig.
Unsuccessful attempts were made to open the valve in 2013, after the system had been operating for a year. However, a third attempt later the same year restored full capacity.
Interview with Erik Femsteinevik, Subsea 7, September 2017. Interviewed by Finn H. Sandberg, Norwegian Petroleum Museum