The Garn West and Rogn South producers would add some 81 million barrels (13 million standard cubic metres) or nine per cent to Draugen’s recoverable oil reserves as then calculated.
Shell’s decision reflected the fact that the technology for tying subsea wells back to fixed or floating surface installations had advanced by leaps and bounds during the 1990s.
Discoveries which had previously been too small to justify their own platform could now be developed instead with relatively cheap standardised seabed facilities.
These could be tied back to a fixed processing platform, a floating production facility or even to a processing plant based on land.
Advances with multiphase flow technology made it possible to send unprocessed wellstreams through pipelines over ever-longer distances.
Developing small satellite fields had become a profitable business, which was very welcome for the oil companies around 2000 when crude prices fell towards USD 10 per barrel. Subsea wells could also be installed and brought on stream quickly.
Garn West, on the westernmost flank of the Draugen area, was the first to be developed. Two subsea wells were tied back to the platform by 3.3-kilometre flexible flow line.
The NOK 130 million contract for the subsea part of this project was awarded on 31 May 2000 to Kværner Oilfield Products AS at Lysaker outside Oslo.[REMOVE]Fotnote: NTBtekst. 06.06.2000, «Draugen utvides for 130 millioner kroner». Installation was completed in July 2001.[REMOVE]Fotnote: Adresseavisen, 05.02.2001, «Draugen leverer olje helt til 2016».
The Rogn South development was approved in the spring of 2001 as the last drainage wells planned for Draugen.[REMOVE]Fotnote: NTBtekst. 06.06.2000, «Draugen utvides for 130 millioner kroner».
Kværner Oilfield Products had an option to deliver to this project as well.
Drilling rig Transocean Winner drilled and completed the two subsea wells in 2002, and the satellite came on stream in January 2003. The flowline carrying its wellstream runs to Garn West.
These two developments helped to increase and extend oil production from Draugen – which proved beneficial when crude prices began to recover seriously after 2002.
Shell invested a total of NOK 1.5 billion in these projects, and Kværner was not the only company to benefit from this spending.
Kristiansund also did well out of it, with the biggest local suppliers – Aker Møre Montasje and Vestbase – securing contracts in the order of NOK 70-90 million. Coflexip Stena Offshore landed the job of installing the flowlines, while the new water treatment system on the Draugen platform was supplied by Aker Offshore Partner at Stord.
Published July 30, 2018 • Updated October 18, 2018
The field had been shut down for a week and a half while these new facilities were tied in. When it resumed, daily production was up from about 100 000 barrels to 138 000. This was in line with a decision by the Storting (parliament) on 12 June, which set a new output ceiling for Draugen of 143 000 barrels per day on average.[REMOVE]Fotnote: Recommendation from the standing committee on energy and the environment on development and operation of the Njord discovery, determination of the state share in the Draugen and Brage fields and briefing on Norsok work. https://www.stortinget.no/no/Saker-og-publikasjoner/publikasjoner/Innstillinger/Stortinget/1994-1995/inns-199495-197/.
It was naturally good news for operator Shell, but with a bitter aftertaste – even with such a sharp increase, the company could not expect more money in the bank.
That was because Jens Stoltenberg, petroleum and energy minister in the Labour government, aimed to exercise the sliding scale provision on increasing state participation.
Put simply, Shell’s share of 100 000 barrels of oil per day was about 21 000 barrels. Once output passed that level, however, the government could boost the state’s holding in the licence.
This was done by taking over shares from licensees Norske Shell, Statoil and BP in June 1995 – which meant the operator still received only 21 000 barrels per day.
The government basically had the right to an additional 10 per cent share of the licence, but the principle of the sliding scale had become very controversial in the early 1990s. [REMOVE]Fotnote: Norsk Oljerevy Nr. 8, 1992, «Sannsynlig at glideskala faller, men: Ny type statsdeltagelse viktigste prinsipp-reform».
After negotiations with the oil companies, who maintained that full exercise of the scale would make a production rise unprofitable, the proportion taken over was cut to eight per cent.
Shell’s holding thereby fell from 21 to 16.2 per cent, while BP lost 3.2 per cent and kept 10.8 per cent. Statoil and the state’s direct financial interest (SDFI) rose from 65 to 73 per cent.
As an international company on the Norwegian continental shelf (NCS), Shell had to be diplomatic in its language.
“I’d say we’re happy to have achieved a resolution,” operations head Knut Engebretsen commented in June 1995.[REMOVE]Fotnote: Bergens Tidende, 29 June 1995, “Kraftig økning på Draugen”. “We can live with this.”
But Shell was nevertheless far from satisfied. It had invested NOK 300-340 million to achieve the big output rise. Two-thirds of that went on drilling new production and injection wells.
To prevent this spending and the production increase from cutting its return, Shell had to reduce its operating costs by about 20 per cent.
Measures to achieve savings were already under way, so that spending was down to about NOK 600 million in 1995. A further cutback to NOK 500 million by 1996 would be pursued.
So the operator was uninterested in any further increase in production from Draugen in the immediate future. This would require such substantial investment that it would be unprofitable.
While Shell and Draugen had to struggle with the results of exercising the sliding scale, the government decided to drop this system for all future developments. That made application of the principle to Draugen particularly hard to swallow for Shell.[REMOVE]Fotnote: Bergens Tidende, 29 June 1995, “Kraftig økning på Draugen”.
A member of the Storting (parliament) and his party’s candidate for prime minister, Bondevik was paying his first visit to the installation on the Halten Bank off mid-Norway.
“All I had to do was move a small lever and it responded,” said Bondevik. “I’d have liked to shift the electorate as easily as I manoeuvred this crane. That would have been something.”
During his guest performance as a crane operator with the opportunity to lift 45 tonnes, he displayed big interest in equipment on the platform manufactured by Molde Kran. [REMOVE]Fotnote: NTBtekst. 07.08.2001, «Bondevik høyt oppe på Draugen».
Like Bondevik, this company was rooted in the town of Molde south of the Draugen base in Kristiansund. Both communities lie in Møre og Romsdal county.
“My boyhood dream has been realised,” the politician told the press afterwards. “Sitting so high up, feeling the excitement, and operating such a big crane is actually great fun.”
But he was not alone in enjoying the experience. Roald Lekve, the crane operator who showed him how to lift and lower with the crane, also had a point to make.
“Now you’ve been allowed to try out the highest job on board here, it’s only reasonable that I should try out yours when you become prime minister,” he told the politician![REMOVE]Fotnote: Historier fra Draugen av Per Sælevik, 2017.
The occasion for the visit was an invitation from the Confederation of Norwegian Enterprise (NHO) and Norske Shell to the three top Christian Democrat candidates in Møre og Romsdal.
In addition to Bondevik, these were May-Helen Molvær Grimstad and Modulf Aukan. The NHO representatives included director general Finn Bergesen Jr.
During the six hours the politicians spent on the field, they toured the platform and were briefed in detail about Shell’s operations by the company management.
Bondevik also had a town hall meeting with the workforce, which had decided in a preliminary session that pensions and working time arrangements were the issue.
Gunnar Sembsmoen was deputed to ask about this on their behalf, and explained that life offshore was tough both physically and mentally.
The Christian Democrat was asked if he would help reduce the retirement age on the Norwegian continental shelf (NCS). But he refused on the grounds that the country had a labour shortage.
“All the same, though, we have special provisions which mean that the age limit can be lowered for certain occupational categories,” he noted.
“That could be an option, but we then need sufficient data to demonstrate that many platform workers have to quit before reaching retirement age because they’re worn out.”[REMOVE]Fotnote: NTBtekst. 07.08.2001, «Bondevik høyt oppe på Draugen».
The workforce was not entirely satisfied with that response, and Sembsmoen responded by characterising the politician as follows:
“You know when you see a Sunnmøre native from behind, they’ve got two big bulges in their back pockets – one from a hymnbook and the other from a wallet – and the wallet is always bigger.”
The room fell completely silent. Bondevik, who was standing by the coffee machine, looked stiffly at the floor until the mood lifted again.[REMOVE]
Fotnote: Historier fra Draugen av Per Sælevik, 2017.
Published July 4, 2018 • Updated September 6, 2018
Finn Harald Sandberg, Norwegian Petroleum Museum
The Draugen platform comprises a round concrete monotower and an almost square steel topside. Putting drilling and oil transport functions in a single shaft posed a range of safety challenges. Moving from circular to square cross-section also proved testing.
— Top of the shaft with gliding formwork. Photo: Eivind Wolff/Norwegian Petroleum Museum
A technique known as “gliding formwork” or “slipforming” was used to construct the vertical sections of the concrete gravity base structures (GBSs) built in Stavanger and elsewhere. This was a special form of a “climbing formwork”, where a form is constructed and then disassembled once casting has been completed. It can then be reinstalled to cast the next section. That approach is preferred when constructing vertical sections of limited height, such as in residential properties or foundations.
Such cases involve a limited number of disassembly/reassembly operations. The method is advantageous where many cutouts – such as windows – are involved. Slipforming was the best approach for the big concrete GBSs because it permitted continuous construction with few joints and cost-efficient working.
Figure 2 shows how this is typically built up. The actual formwork comprises a vertical sheet installed to ensure that wall thickness and shape meet the design specifications.
Gangways are installed on both sides of the wall around the whole circumference to provide a work space and access for such jobs as installing reinforcement bars (rebars) and cutouts. Other tasks here include pouring concrete into the forms, applying epoxy, inspecting the finished result and repairing possible surface blemishes.
Formwork and gangways are attached to frames hung from hydraulic jacks, which move up as the structure rises. If the design requires changes in diameter, the formwork radius can be adjusted with a horizontal jacking system.
As concrete is cast, the whole formwork get raised by activating the jacks simultaneously. Adjusted to the curing time of the concrete, the speed of the glide will vary with complexity and volume and is normally 1.5 to four metres per day.
The jacks are constantly adjusted to adapt the formwork to the desired shape of the concrete wall and to correct possible variations without exceeding tolerances specified in the chosen building standard.
Careful control of shaft geometry is exercised with the aid of laser measurements to ensure that all dimensions meet the tolerances throughout.
The conical shaft in the Draugen GBS has its narrowest diameter at the sea surface, where it measures just over 15 metres compared with more than 22 metres down at the storage cells.
That reduces wave forces acting on the platform and thereby allows its base section to be reduced, as well as securing a more efficient design.
However, a circular cross-section with a relatively small diameter was not the optimal solution for the transition to the square topside.
The top of the shaft was accordingly designed as a box structure with a square cross-section measuring 22 metres to a side.
Designing and operating a slipforming process where the cross-section gradually changed from circle to square therefore presented a challenge in construction terms.
This required both a variation in wall thickness and an increase in external dimensions – squaring the circle in practice.[REMOVE]Fotnote: Tegning GS D 2001-001 GENERAL VIEW
The solution involved a system which made it possible to add additional formwork sheets as the slipformed area increased, and creating a frame with arms which stuck out from the centre.
A horizontal jacking system controlled the distance from the centre to the formwork, and this approach provided a successful outcome.
The formwork could be raised so that the shaft wall became a double arc with its external dimensions tailored to a favourable solution for designing and attaching the topsides.
One result of this building technique was that a checked pattern emerged on the transition piece, which gives the Draugen platform a characteristic appearance.
Based on an e-mail from Dag N Jensen, former head of engineering design at Norwegian Contractors.
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