The field was discovered in 1984 in a highly permeable structure which has since proved to be an extremely productive reservoir. It soon became a candidate for development at a time when new discoveries had to queue up to secure official authorisation.
The Norwegian government had only opened the Norwegian Sea to oil and gas operations relatively recently, and a number of partnerships were drilling wildcats in the area.
Many groups had been against extending exploration to new areas of the Norwegian continental shelf (NCS), and thereby crossing the barrier represented earlier by the 62nd parallel.
This opposition reflected fears – which have since proved groundless – that the rich fisheries in the Halten Bank area could be harmed.
In fact, the fishing and petroleum industries have demonstrated that they are able coexist harmoniously in the Norwegian Sea.
When Draugen began producing oil on 19 October 1993, it was expected to yield almost entirely oil – some 430 million barrels or 68 million standard cubic metres of oil equivalent (scm oe).[REMOVE]Fotnote: Norwegian Petroleum Directorate, Facts, 1983.
Since then, the recoverable amount has been increased to about 140 million scm oe.[REMOVE]Fotnote: Norwegian Petroleum Directorate website, fact pages fields, 1 October 2018.
Operator A/S Norske Shell has also made changes to its production facilities over these years.
The upshot of these alterations is that daily output has been significantly increased since the field first came on stream. Read more about capacity increases and updating.
Figure 1. Annual production peaked in 2001, the year after gas output and export was included.[REMOVE]Fotnote: Norwegian Petroleum Directorate website, fact pages fields, 1 October 2018
Figure 2. Draugen has produced assets worth almost NOK 250 billion in all since 1993. These revenues are calculated on the basis of a production profile obtained from the Norwegian Petroleum Directorate’s fact pages in the autumn of 2018 and an annual average oil price taken daily from Norwegian business newspaper Dagens Næringsliv.
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, 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.
Kristin Øye Gjerde, Norwegian Petroleum Museum
The plan for development and operation (PDO) of Draugen submitted to the Storting (parliament) in 1988 gave the field a producing life until 2012 and a recovery factor of 37 per cent. When it came on stream in 1993, however, operator Shell was already working to both extend and increase output.
— Draugen field layout. Illustration: A/S Norske Shell/Norwegian Petroleum Museum
By 2017, Draugen’s producing life had been extended to 9 March 2024 and its expected recovery factor was put at 75 per cent. These forecasts have changed gradually, as technological advances in the oil industry permitted production improvements.
But the reservoir has nevertheless yielded surprises along the way.
Reserves up, producing life and recovery factor extended
Shell could report in 2001 that recoverable reserves in Draugen were larger than earlier thought.
Use of four-dimensional seismic surveys improved geological understanding of the reservoir, which was also behaving better than expected. A number of the wells were producing very well.
Draugen’s producing life was extended to 2016 and the expected recovery factor increased to 67 per cent. In the longer term, the goal was to recover at least 70 per cent – assuming that the field remained commercial beyond 2016.[REMOVE]Fotnote:Adresseavisen, 5 February 2001, “Draugen leverer olje helt til 2016”.
New subsea wells in south and west
To increase production from and producing life for the Draugen area even further, Shell now planned development of the Garn West and Rogn South subsea wells.
These would be tied back to the Draugen platform and increase reserves by about 81 million barrels or 13 million standard cubic metres (scm) of oil. That was nine per cent of the field’s 144.2 million scm in recoverable oil.[REMOVE]Fotnote:http://factpages.npd.no/factpages, 26 October 2017.
This decision built on rapid improvements during the 1990s in the methods for tying subsea wells back to fixed and floating offshore installations.
Discoveries too small to justify their own process platform could use relatively cheap, standardised subsea systems tied back to a fixed platform, a floater or even land. And unprocessed wellstreams could be sent over ever longer distances with advanced multiphase flow technology.
Development of small satellite fields had become a profitable business, which proved a boon for oil companies around 2000 when oil prices slumped towards USD 10 per barrel. An advantage of subsea wells was that they were quick to install and start up.
Located at the westernmost edge of the Draugen area, Garn West was the first to be tapped with the aid of two seabed wells tied back by a 3.3-kilometre pipeline in the summer of 2001.[REMOVE]Fotnote:Adresseavisen, 5 February 2001, “Draugen leverer olje helt til 2016”.
The Rogn South development was approved in the spring of that year, and Transocean Winner drilled and installed two subsea wells in 2002 so that they could come on stream the following January. Their wellstreams are routed via Garn West (see map).
These satellites helped to increase and extend oil production from Draugen – which was advantageous as oil prices staged yet another recovery after 2002.
Norske Shell could report in 2001 that it was investing NOK 1.5 billion in developing Garn West and Rogn South.[REMOVE]Fotnote:Adresseavisen, 30 May 2001, “Draugen større”. Among those winning contracts were Kværner Oilfield Products AS at Lysaker outside Oslo, which delivered the subsea systems.[REMOVE]Fotnote: NTB, 6 June 2000, “Draugen utvides for 130 millioner kroner”.
The Kristiansund business community also did well, with Aker Møre Montasje and Vestbase – the biggest local suppliers – securing work in the order of NOK 70-90 million.
Coflexip Stena Offshore won the pipelaying job, while the new water treatment system on Draugen was produced by Aker Offshore Partner at Stord.[REMOVE]Fotnote:Adresseavisen, 30 May 2001, “Draugen større”.
Water, water and more water
Production from Draugen was highly promising in 2001. It was at its highest-ever level of 12.87 million scm of oil equivalent (oe) per year – almost too good to be true.
This annual output of oil, gas and condensate equalled as much as the total expected recovery from Garn West and Rogn South combined.
The field nevertheless showed some signs of production weaknesses. As the oil was produced, the level of water in the reservoir rose and its proportion of output (or cut) increased. In June 2002, Shell reported that the water cut had risen to 35 000 cubic metres per month – a trebling from six months earlier.
Well A1, which only contained 10 per cent water in its oil output at 30 March 2002, increased this cut to 30 per cent over a three-month period.
With a record output of 77 000 barrels of oil per day (bod) making it the best of Draugen’s wells, A4 had to be shut down because of the salts being precipitated. These threatened to block the pores in its walls – a sign that the area being produced was approaching depletion. Production from the field was nevertheless not particularly reduced, since the other wells were increasing their output.[REMOVE]Fotnote:Adresseavisen, 11 June 2002, “…mens vannet stiger i Draugen”.
All the same, it transpired over the years which followed that the amount of oil and gas produced went down as the water cut rose.
By 2010, production had fallen 20 per cent or 2.6 million scm oe from the peak year of 2001 and water output was approaching eight million scm.
Something had to be done if Draugen was to stay on stream. As part of Shell’s environmental improvement programme, a project for produced water and reinjection on the field had been launched. The reinjected fluid would be used for pressure support.
Advanced new seismic surveys identified a number of oil pockets in the area. That led in 2012 to a plan for drilling a further four new wells.
These would help to produce fuel gas for power generation on the platform, operations head Ervik explained.[REMOVE]Fotnote:Tidens Krav, 3 February 2012, “Langt liv for Draugen”. The electricity was intended partly to drive a new pressure support pump.
Shell contracted with Seadrill to use West Navigator for the subsea wells in this Draugen infill drilling programme to help boost oil production from the field.