Finn Harald Sandberg, Norwegian Petroleum Museum
Stavanger’s Rosenberg Verft yard won the job of assembling the Draugen topsides in early 1990. This massive jigsaw formed an integrated structure, with components and equipment packages put together at the construction site.
— The construction of Draugen topside takes place at the Aker Rosenberg Shipyard at Buøy in Stavanger. Photo: A/S Norske Shell/Norwegian Petroleum Museum
The topsides were originally intended for a floating production platform, which meant they were much lighter than a traditional complex used on a fixed installation.
That in turn proved appropriate for a concrete gravity base structure (GBS) with a single support shaft, since it would keep stability during towout within safety requirements.
The topsides were 79 metres long, 59 metres wide and 15 metres high (figure 1). Their quarters section was almost 23 metres tall and contained 130 berths.
During earlier projects, the Rosenberg yard – part of the Moss Rosenberg Verft (MRV) company – had used four specially built concrete cylinders to support the topsides structure.[REMOVE]Fotnote: Statfjord industrial heritage – Building the Statfjord B topside
Standing in the water alongside the dock, these pillars were intended to imitate the shafts of the GBS which the topsides would rest on – as with the Statfjord and Gullfaks structures.
However, the Draugen platform only had one shaft. In addition, the top of this monotower was larger than earlier points of contact and virtually square.
That presented a challenge which had to be overcome before assembly work could begin. The answer proposed was a kind of both-one-thing-and-another solution.
To accommodate barges to float the completed topsides to nearby Vats for mating with the GBS, two of the four concrete cylinders had to be placed at the seaward edge of the structure.
These stood immediately beneath the quarters section, and were supplemented by smaller concrete blocks supported by steel tubes and positioned on the seabed to imitate the top of the monotower.
Similar blocks were also spaced along the edge of the support frame to distribute the topside weight and thereby avoid damage. They could easily be removed to let the barges in (figure 2).
The detail engineering job for the Draugen topsides had been awarded in 1989 to Kværner Engineering. Like MRV, this company was a member of the Kværner fabrication group.
Covering the drawings used in tendering for and building the topsides, this contract was signed by project director Mahdi Hasan for Shell and senior executive Hans Jørgen Frank for Kværner.[REMOVE]Fotnote: Interview with project director Mahdi Hasan, 11 August 2018.
This pair also put their names to the construction and outfitting assignment for the topsides when it was awarded to MRV in early 1990.
Since both design and construction were to be carried out by companies in the same family, the prospects for a positive outcome looked promising.
Computers at the engineering and fabrication firms talked the same language, allowing them to communicate. With such intimate collaboration, the job should have presented no problems.
Nevertheless, this proved yet another offshore development where the design drawings were less than perfect – as had been the case in several projects off Norway during the 1980s.
The latter had experienced major cost overruns, in part because of variation orders (VOs) during the construction phase. On Draugen, the flow of these amendments seemed endless.
The yard faced problems dealing with all the changes to the drawings, with disruptions and discontinuities affecting assembly. Both time and costs became difficult to control.[REMOVE]Fotnote: Nerheim, Gunnar, Jøssang, Lars Gaule and Utne, Bjørn Saxe (1995). I vekst og forandring – Rosenberg Verft 100 år: 442-443.
In fact, awarding these two contracts to companies in the same group may have contributed to the disagreements which arose during the construction period.[REMOVE]Fotnote: Interview with Sigbjørn Ellingsen, production vice president, Rosenberg Verft, 19 January 2017.
The topside was originally costed at NOK 1.1 billion, but the bill had almost doubled to NOK 2.1 billion when Shell took delivery at the towout in February 1993.[REMOVE]Fotnote:Stavanger Aftenblad, 13 January 1996, “Pinlig for Shell, verst for Kværner”.
MRV’s contract was a pure construction job. This meant that all proposals for variations from the design drawing – from minor improvements to major conversions – had to be approved by Shell.
The Rosenberg yard accordingly sent such suggestions to the client, who then had to pass them to the engineering company for redrafting.
However, Shell’s project team took the view that these proposals should go directly to Kværner Engineering and be sorted out between the two group companies.
That approach would have been similar to the one used in the integrated engineering, procurement and construction (EPC) assignments which had become common in Norway’s offshore sector.
This was precisely what Shell had envisaged and hoped would happen when it awarded both contracts to two companies in the same group.
These two different interpretations of the contractual relationship meant that VOs piled up without being dealt with, and work at the yard was delayed by the absence of a response.
Although this bottleneck was eventually resolved, a lot of critical time had been lost and it became important to speed up the remaining work.
But disagreement over the contract persisted, and the final bill had to be settled by arbitration. This process dragged out, and took three years to bring to an end on 11 January 1996.[REMOVE]Fotnote:Stavanger Aftenblad, 13 January 1996, “Pinlig for Shell, verst for Kværner”.
On behalf of the licensees, Shell had originally claimed NOK 1.47 billion from Kværner. This was later reduced to NOK 576 million.[REMOVE]Fotnote:Aftenposten, 13 January 1996, “Draugenseier til Kværner”.
Shell based this demand on allegations of intentional or grossly negligent material breaches of the contract by Kværner, but these were dismissed by the arbitration tribunal.
Kværner secured extra compensation of NOK 113 million because Shell had demanded an acceleration of the work, which meant the yard had to take on more personnel than originally planned.[REMOVE]Fotnote:Dagens Næringsliv, 13 January 1996, “Shell tapte mot Kværner”.
Although the hearing ended in victory for Kværner, local daily Stavanger Aftenblad still headlined a comment by journalist Arnt Even Bøe: “Embarrassing for Shell, worst for Kværner”.
He wrote that this case and others still to be resolved meant that the group had earned itself a reputation as the company which took legal action against its customers.[REMOVE]Fotnote: Stavanger Aftenblad, 13 January 1996, “Pinlig for Shell, verst for Kværner”.
 Statfjord industrial heritage – Building the Statfjord B topside
 Interview with project director Mahdi Hasan, 11 August 2018.
 Nerheim, Gunnar, Jøssang, Lars Gaule and Utne, Bjørn Saxe (1995). I vekst og forandring – Rosenberg Verft 100 år: 442-443.
 Interview with Sigbjørn Ellingsen, production vice president, Rosenberg Verft, 19 January 2017.
Stavanger Aftenblad, 13 January 1996, “Pinlig for Shell, verst for Kværner”.
Stavanger Aftenblad, 13 January 1996, “Pinlig for Shell, verst for Kværner”.
Aftenposten, 13 January 1996, “Draugenseier til Kværner”.
Dagens Næringsliv, 13 January 1996, “Shell tapte mot Kværner”.
 Stavanger Aftenblad, 13 January 1996, “Pinlig for Shell, verst for Kværner”.
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.
Many of the field’s personnel have worked there for many years, making them thoroughly familiar with the installation and allowing close ties to be developed between colleagues.
When Draugen came on stream in 1993, 43 people per shift were expected to be sufficient for normal operation. Their jobs covered managing the process, maintenance, catering and cleaning, medical care and safety.
Most of these personnel are employed by Norske Shell or the catering company. The workforce can expand considerably when major maintenance or conversion work is underway.
Draugen employees work offshore for two weeks, followed by four weeks off on land. They do 12-hour shifts, either day or night, and their working hours over a year compare with those of an industrial worker on land.
Generally speaking, a shift runs from 07.00 to 19.00, and from 19.00 to 07.00. Work is planned so that as much as possible is done by the day shifts. Three shifts, each working two weeks at a time, are needed to get the tour rotation to work.
Since a new team takes over responsibility and jobs every other week, logging and documentation of work done, irregularities and plans are crucial.
When a different person comes out to work, they need to know what has happened over the four weeks since their last tour. So time was devoted to recording and reporting.
During the early years on stream, this could take the form of logbooks kept on the platform. Logs have subsequently become computerised, making them also available to the land organisation.
As communication via radio links and data transfer has improved, computerisation has provided enhanced support in ensuring the continuity of work at shift changes.
The team on land has access to the same computer systems used offshore, and follow up activities on the platform through such technologies as videoconferencing.
During their offshore tours, employees are part of a community which lives and works in one place. Draugen is a 24-hour society, in that workers also spend their leisure hours there.
The latter are largely devoted to eating meals and getting enough sleep. But some time is available for talking with colleagues and reading the papers.
A number of leisure activities are also provided on the installation, with a welfare committee made up of enthusiasts elected by the workforce.
This organises film shows, golf in a simulator, computer games, song and music, arts and crafts and angling.[REMOVE]Fotnote: A/S Norske Shell (2005) Shell Drift Draugen, brochure. The gym is the most popular leisure provision on Draugen.
Personnel travelling out to the platform are now allowed to bring their mobile phone. This can only be used in the living quarters, but has made it easier to keep in touch with family and friends on land. A dedicated wireless network has been installed to cover the living quarters.[REMOVE]Fotnote: http://www.draugen.in/velferdsnett/
At one time, mobile phones were prohibited on all Norway’s offshore facilities because they could interfere with helicopters, or exploding batteries could serve as an ignition source.
Control of the information flow provided another important reason for the restriction. The company was concerned about what information – or disinformation – could be sent ashore and create uncertainty and needless fears.
Mobile phones are still banned from the production area, precisely because of concern about possible battery explosions and disruption of electronic instrumentation.[REMOVE]Fotnote: Teknisk Ukeblad 7 November 2013, Derfor må mobilene bo på hotell,. https://www.tu.no/artikler/derfor-ma-mobilene-bo-pa-hotell/233850.
The central control room (CCR) is the platform’s heart and nervous system, and can monitor, govern and regulate the whole production process with the aid of a comprehensive computer system.
It runs the process and safety systems, which involves continuous supervision of operational equipment – including fire and gas detection as well as safety systems such as fire pumps and emergency power.
A minimum of two operators must be in the CCR at all times to facilitate planned work on the production facilities as well as responding to messages and alarms.
These personnel are also responsible for monitoring and controlling the loading of oil into shuttle tankers.
The CCR has a number of work stations, allowing operators to monitor and work on several systems simultaneously. More than two of them can be on duty when things get hectic.
Handover procedures between day and night shifts are just as important as they are when tours are being rotated offshore and to land. When the night shift is due to take over, meetings are held with the day shift before it stands down. Held in a room adjacent of the CCR, these review jobs done and planned, and the work permits (WPs). The WP represents an important document on offshore facilities. They are designed to ensure that all risk-related aspects have been taken into account. That covers the planning, approval, preparations, execution and completion phases. All activities are thereby coordinated, with information given on hot work or closed areas/equipment and taken into account when doing other types of jobs.
All WPs must be approved by the operations supervisor or the offshore installation manager (OIM).
Most of the process on the platform is automated – not least shutdowns. If abnormal values are measured by the detectors, the whole process plant will automatically cease running.
If such an emergency shutdown (ESD) or other crisis occurs, the CCR operators are trained to handle them. That plays an important role in safety and risk management work on Draugen.
A number of closed-circuit TV (CCTV) cameras are installed on the platform, allowing the CCR operators to follow physical events out in the process.
Since the platform came on stream, the CCR has been converted and upgraded a number of times. Bigger computer monitors and newer control software have been installed.
These upgrades have been carried out in consultation with the CCR operators in order to ensure that they provide the best possible workflow.[REMOVE]Fotnote: Raaen, Stine N (2015), Team Situation Awareness in Practice, MSc theses in cybernetics and robotics, Norwegian University of Science and Technology (NTNU): 60.
The meeting room is linked to the CCR, and contains systems for videoconferencing and collaboration with the land organisation. It also serves as an emergency response centre.
Screen capture from the film 1-2-3 Vi er med! produced for a campaign launched by the Draugen operations organisation in 1994.
The operations team on land is structured to support work on the platform, and performs the administrative duties which do not need to be done offshore.
It includes experts on the various activities pursued on the field, and additional capabilities can be acquired as and when required. The specialists on land can decide on the action to be taken in meetings with the offshore organisation.
One factor which attracted particular attention in the first phase after the field came on stream was the challenges faced in getting sea and shore to collaborate.
These problems could be related to the slow performance of computer systems and lines of communication, and inappropriate reporting structures.
One approach to improving collaboration and understanding between the two sides has been to post offshore personnel to the operations office on land for periods.[REMOVE]Fotnote: Conversation between production technician and acting chief safety delegate Jan Atle Johansen and Gunleiv Hadland from the petroleum museum on the Draugen platform, 7 March 2017.This means staff in Kristiansund have practical experience of working conditions on the platform, allowing them to conduct planning and administration related to work offshore.
Since the operations centre on land was opened in 2007, provision has been made for monitoring Draugen production from there – particularly on the night shift.
Should unusual incidents occur on the platform during these hours, key personnel from the day shift are called out until the position has been clarified.[REMOVE]Fotnote: A/S Norske Shell, 10 April 2003, Draugen organisasjonsendring. Konsekvensvurdering – Produksjonsleder Natt.
The land organisation has departments for logistics, contracts and procurement, human resources, maintenance, production support, and filing and document management.[REMOVE]Fotnote: A/S Norske Shell (2005) “Driftsavdelingen i Kristiansund”, Shell Drift Draugen brochure.
One example of a function which has been transferred from field to land is the switchboard for handling external telephone calls to the platform.
The work of planning personnel resources in connection with sickness, leave of absence and extra activities has also been moved ashore.
Sea-shore collaboration has been boosted by the process simulator at the Kristiansund office, which was included in the development plans as early as 1987 for personnel training.[REMOVE]Fotnote: Draugen impact assessment, September 1987: 22.
This facility was constructed with control systems which mimicked those in Draugen’s CCR, and it could be used before the field came on stream to test management of the process.[REMOVE]Fotnote: Draugen magasinet, no 2 1993, “Simulatoren brukt som testverktøy”, A/S Norske Shell E&P operations department.
Everyone employed as a production operator was trained in the simulator, and had to demonstrate at the end of the course that they could shut down and restart the wells.
A training plan was tailored for each person. Using the simulator, they could make mistakes and practise until they were proficient.
Operators could only start working on the platform after their competence had been approved by the instructors attached to the simulator.
Day courses have also been organised so that operators on their way out to the platform can be informed about updates since they were last at work.
When changes were made out on Draugen, the simulator was updated accordingly and, if necessary, the alterations could be tested before being introduced offshore.[REMOVE]Fotnote: Interviews between Nils Gunnar Gundersen and Gunleiv Hadland from the Norwegian Petroleum Museum, 27 October 2016 and 1 November 2017.
Training in this facility has played an important role in educating the production operators, and has been extended through their work out on the platform.
Reviewing the process on the platform in the simulator at Råket in Kristiansund. Training supervisor Geir Solberg is in the foreground. Photo: Engvik/Norske Shell/Norwegian Petroleum Museum NOM (NOMF-02784.046)
Maintenance and turnarounds
As much maintenance work as possible on a platform like Draugen is preventive, and planned to avoid the need to take corrective action – in other words, repair a fault after it has occurred.
Maintenance based on fixed intervals includes such activities as replacing seals, filters and other components exposed to wear and tear.[REMOVE]Fotnote: Pedersen, Vikse and Tingvold (2017): Vedlikeholdsanalyse RCM hos Shell, BSc thesis, Molde University College: 9.
This is the same approach as the one taken with a car which gets serviced at regular points, where parts are replaced after a specified number of kilometres driven or time passed.
Roughly 150 different safety valves are in use on Draugen, for example, tailored to various sizes and pressures. These get replaced during production shutdowns or maintenance campaigns.[REMOVE]Fotnote: Pettersen, Victoria C F and Sæter, Karina L, 1 July 2014, RFID-merking av sikkerhetsventiler: Forbedring av informasjonsflyt i vedlikeholdsprosesser på Nyhamna, BSc thesis in petroleum logistics, Molde University College.
Maintenance work on Draugen is organised on the basis of an inspection programme which specifies equipment checks at certain intervals and is coordinated by computer systems.
The programme lists components where critical faults could arise and which must receive particular attention during maintenance. Other items can be assessed as safe to leave until they fail, and are only replaced then.
An initial version of the inspection programme was established in the spring of 1993, even before the field came on stream, in a collaboration between Møre Engineering, Liaaen and CorrOcean.[REMOVE]Fotnote:TidensKrav 12 May 1993. “Møre Engineering: Fra bygging til drift”. Supplement on industry in Nordmøre.
Much of the equipment is continuously supervised by a computerised condition monitoring system (CMS). Analysing data from the process plant can detect whether something is wrong.
Also set up to notify abnormal temperatures, this condition-based maintenance (CBM) solution avoids having to open up the equipment to check for faults.
Once the CMS has provided such notification, the load on the relevant component can be reduced until it can conveniently be replaced.
The operator on the platform reports to the technical supervisor, who contacts the responsible manager on land in turn.[REMOVE]Fotnote: A/S Norske Shell (2005) Shell Drift Draugen, brochure. They can then jointly assess the action to be taken.
Production operators on Draugen routinely tour the process areas with the emphasis on identifying anything abnormal, and experienced people can detect leaks early simply by the smell.[REMOVE]Fotnote: Werner Frøland, team coordinator at Draugen in film Norske Shell 100 years. 1912 -2012
Planning maintenance tasks has made it possible to concentrate such work at times when production from Draugen is shut down. These periods are known as “turnarounds”.
Production from the platform has been suspended for roughly 14 days every other year – or once a year in the event of major projects.
This shutdown is partly intended to make it possible to perform inspection and maintenance in areas of the platform which are difficult to access during production.[REMOVE]Fotnote: NRK Møre og Romsdal (10 May 2011) Bruker milliarder på produksjons-stans https://www.nrk.no/mr/draugen-stenger-i-19-dager-1.7626438
A dedicated team in the operations organisation on land will have been responsible for planning the work to be carried out during a turnaround. Equipment, extra personnel and required materials need to be ordered well in advance in order to be available at the right time.[REMOVE]Fotnote:Shell Drift Info Draugen and Ormen Lange no 5, 2006, “Vedlikeholdsstans krever ett års forberedelse”: 9.
A turnaround is usually scheduled for the summer season so that weather conditions are as good as possible during this period of concentrated work.
The scope of maintenance grows as a platform ages, and doing it takes longer. Wear and tear can lead to failures and faults, and cause accidents or unwanted shutdowns if not detected in time.
With the need to replace all or part of equipment items increasing over time, the attention devoted to continuous improvement and maintenance efficiency also rises.
Contracts have been awarded to Aker Solutions and Aibel for work on maintenance and modifications, and these companies provide additional personnel to help carry out such work.
The platform’s catering personnel are responsible for such activities as food preparation and cleaning, and are employed by external contractors. Nevertheless, they have been incorporated in the permanent offshore organisation, shown on organograms and included in presentations of the workforce.
That has reflected a desire to minimise the distinction between Shell employees and catering personnel,[REMOVE]Fotnote: Interviews between Nils Gunnar Gundersen and Gunleiv Hadland from the Norwegian Petroleum Museum, 27 October 2016 and 1 November 2017.and the latter have felt an integrated part of the team from the start.[REMOVE]Fotnote: SSP.OKS’EN no 3, 1994, “Draugen- Min Arbeidsplass”, Mai Breivik, catering assistant
In collaboration with the platform nurse, catering staff also have roles in first aid, emergency response and drills for this.[REMOVE]Fotnote: Conversation with nurse Carina Løvgren on the Draugen platform, 7 March 2017. A small organisation means people have supplementary duties, particularly if a crisis occurs.
Once a year, personnel practise establishing an emergency sick bay in the mess. Installed in cooperation with the nurse, this facility is dimensioned for up to seven injured people.
From offshore to onshore
The operations organisation has been split between platform and land, but a trend in working life on Draugen is the transfer of jobs to the onshore team. This has meant a gradual reduction in permanent staffing offshore. Heavy-duty maintenance and major projects are assigned to limited periods during the summer, when extra personnel and specialists on the relevant work are sent offshore.
Kristin Øye Gjerde, Norwegian Petroleum Museum
Draugen was the first field to begin production on the Halten Bank in the Norwegian Sea. Its oil could be loaded into shuttle tankers and shipped to refineries, but finding a commercial solution for the gas was less simple.
When the field came on stream in 1993, it was estimated to contain a lot of oil (575 million barrels or 92 million cubic metres)
and small quantities of natural gas (three billion cubic metres)
No export infrastructure for gas was immediately available. Shell’s proposal to flare the gas in situ was rejected by the government on resource management and environmental grounds.
Injecting the gas into Husmus, a satellite reservoir, offered a temporary solution. This was permitted for six years while a permanent export system was put in place.[REMOVE]Fotnote:Norsk Oljerevy, no 11, 1993, “Draugen-prosjektet vekket Midt-Norge”.
Haltenpipe right past
Problems with gas were not confined to Shell and Draugen. After exploration drilling was permitted above the 62nd parallel (the northern limit of the North Sea) in 1980, a number of discoveries were made on the Halten Bank.
Saga Petroleum found gas in the Midgard field in 1981 with its third well in the area, while Statoil and Shell discovered Smørbukk and Draugen respectively in 1984.
Statoil then proved Smørbukk South in 1985, when Conoco also found Heidrun. And Norsk Hydro discovered the Njord field the following year.
Success on the Halten Bank accordingly came quickly. All three Norwegian oil companies and international operators Shell and Conoco became involved in development assignments there.
Several of these fields contained natural gas in addition to oil, and opportunities for shared pipelines to bring this ashore were discussed on several occasions.
Heidrun’s gas reserves were larger than those in Draugen, and flaring these was again excluded by Norwegian emission standards. Nor was injection relevant.
Since no gas transport network existed this far north, Statoil and operator Conoco resolved to lay the Haltenpipe gas line to Tjeldbergodden and to build a methanol plant there.
As the state oil company, Statoil was particularly concerned to meet the political goal that Norway’s petroleum production should create spin-offs and jobs on land.
Haltenpipe would pass within a few kilometres of Draugen, so a gas tie-in from that field seemed sensible. Statoil/Conoco therefore proposed that the Draugen partners should become co-owners of both pipeline and methanol plant.
Negotiations were pursued in 1992 between Shell/BP for Draugen and the methanol group on delivering gas to Tjeldbergodden. But the former felt the methanol project was too expensive. Nor were they interested in producing this chemical.
They offered their gas free of charge, but Statoil/Conoco declined.[REMOVE]Fotnote: Lerøen, Bjørn Vidar (2012): Energi til å bygge et land. Norske Shell gjennom 100 år, 177–78. The negotiations accordingly foundered, and Haltenpipe passed Draugen without a tie-in.
Draugen Gas Export
As noted above, permission to inject Draugen gas in Husmus was limited in duration. 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 (ATV): 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: Kristoffer Evensen, Kjetil Nøkling, Martin Richardsen, Kamil Martin Sagberg and Marius Haara Tjemsland (2011): Gasstransportkapasitet fra Haltenbanken til Europa. Project assignment in subject area TPG4140 natural gas, Norwegian University of Science and Technology (NTNU)
Published April 27, 2018 • Updated October 2, 2018
Kristin Øye Gjerde, Norwegian Petroleum Museum
When Shell planned the Draugen development, the project included the installation of various subsea facilities and other work in 250 metres of water.
— Signing the Draugen underwater installation services (DUIS) contract on 30 April 1992. Seated from left: Per Olaf Hustad from Shell and Stolt Nielsen Seaway’s Kåre Johannes Lie. Standing from left: Jim Seavar, David Cooke and an unidentified person (all Shell), and Arnfinn Vika, Joar Gangenes and Magne Vågslid (all Stolt Nielsen Seaway). Photo: A/S Norske Shell/Norwegian Petroluem Museum
This included positioning a subsea pump and manifold as well as modules from Kongsberg Offshore, opening and shutting valves in deep water, connections and maintenance jobs of various kinds.
The Draugen underwater installation services (DUIS) contract was won in 1992 by Stolt-Nielsen Seaway, a specialist with diving and remotely operated vehicles (ROVs).
Based in Haugesund north of Stavanger, this company had to make a rather unusual acquisition in order to satisfy Shell’s technical specifications for the work.
Plans called for ROVs to be used to carry out subsea work for the platform, since saturation diving by humans was not feasible at these water depths.
Several types of such vehicles were relevant, including crewed systems which kept the person doing the seabed job under atmospheric pressure no matter how far down they were.
The other principal solution was an ROV operated from a control room on a rig or ship without any people needing to go underwater.
Stolt-Nielsen Seaway had an ROV on its diving support vessel (DSV), but Shell wanted a back-up in case this vehicle ran into problems.
Diving could be an option, and successful test dives had already been conducted down to 250 metres and beyond. But demonstrating (qualifying) that descents to these depths could be conducted safely was both expensive and very demanding.[REMOVE]Fotnote:Joar Gangenes by email to Kristin Øye Gjerde, 13 October 2017.
Instead, Shell specified that the company must have an atmospheric diving suit (ADS) available as a back-up in order to secure the contract.
An ADS was an armoured diving suit suspended from a cable and provided with lifting equipment on the DSV. The operative/diver stood inside it like an astronaut, with a transparent dome for vision. Although able to walk on the seabed, he lacked the mobility of a diver.
Having won the job, Stolt-Nielsen Seaway had to invest in this system. It was purchased from a Canada-based company via Draeger and proved extremely expensive.[REMOVE]Fotnote:Joar Gangenes by email to Kristin Øye Gjerde, 13 October 2017.
A test programme established that getting a person inside this suit to do effective work was almost impossible. It was accordingly never used.
Fortunately for Stolt-Nielsen Seaway, Shell proved willing to bear the whole cost of both investment and testing. It regard this as research and development work.
Kåre Johannes Lie, who followed up this acquisition from the contractor’s side, found the whole business unfortunate and felt spending money on an unnecessary system was a bit of a waste.[REMOVE]Fotnote: Kåre Johannes Lie in an interview with Kristin Øye Gjerde and Arnfinn Nergaard, 9 August 2017.
Subsea installation work was performed with the aid of the module handling system on the DSV, which had been developed earlier by Stolt-Nielsen Seaway in collaboration with Elf.
During the 1990s, the contractor also used the newly developed and powerful Perry Tritec Triton ROV from Oceana Subsea Ltd Perry Inc in Florida.
The most popular ROV on the Norwegian continental shelf in the 1990s, this unit could descend to 1 000 metres and perform subsea observation, sonar searches, seabed surveys and mechanical jobs.
With a deployment cable (umbilical) which incorporated the necessary communication lines, the Triton was able to remove and replace components on the seabed.
It featured two powerful manipulator arms developed by Shilling in the USA and remotely operated via a fibreoptic cable in the umbilical.
The package also included a cable drum, winch, power transmission unit and control room. Its control system ran an electric pump which drove the propellers and other gear.
Hydraulically powered thrusters provided propulsion in the sea. In addition came dedicated systems for lifting the ROV and its basket from the deck and into the sea.
Kristin Øye Gjerde, Norwegian Petroleum Museum
When the Draugen platform arrived on the field in 1993, it had to be connected to production tubing, umbilicals (control cables) from satellites, export pipelines and so forth. This job went to Subsea Dolphin.
— The Draugen platform being towed to the field offshore. Photo: A/S Norske Shell/Norwegian Petroleum Museum
All the hatches at the bottom of the Condeep concrete gravity base (GBS) structure were to be opened with the aid of remotely operated vehicles (ROVs).
The lower part of the GBS had been cast at Hinnavågen in Stavanger, while slipforming of the tall monotower shaft took place in the deep fjord at Vats further north.
Subsea Dolphin was involved as early as the latter stage. Arild Jenssen, one of the company’s ROV pilots, remembers this phase well.[REMOVE]Fotnote: Arild Jenssen in conversation with Kristin Øye Gjerde, 31 March 2016.
These devices were used inside the GBS because the shaft was filled with seawater once the platform had been installed on the field, and they could therefore move around as required.
Preparing for internal ROV work while readying the platform for tow-out proved a special experience because of the motion in the shaft, which was several hundred metres tall.
That meant the tubing which ran from the base of the structure through holes in the intermediate decks banged against the sides of these apertures. This in turn generated vibrations and a “bong, bong” sound almost like church bells.
The ROV pilots wanted to insert wooden wedges in the holes to prevent the slamming, but the engineers from builder Norwegian Contractors maintained that this motion was as it should be.
“We Subsea Dolphin operators were on board during the towout [in 1993],” recalls Jenssen. “It was a fantastic experience. The view was great while deballasting the platform in calm and beautiful weather.”
Like the other Condeep concrete platforms, the Draugen GBS had cylindrical storage tanks clustered around the central shaft. The latter contained about 70 metres of water during towout, while a big tank also held ballast water.
A concrete pipe with a square cross-section ran down the centre of the shaft to a “mini-cell” at the base of the platform. This extended upwards from a depth of 250 metres to 180 metres.
The mini-cell contained piping positioned beneath the other storage cells for pumping out grout in order to fill the spaces beneath the GBS and stabilise the ground.
Installed in 250 metres of water, the platform ended up 0.3 degrees out of true – which added up to a horizontal offset of 1.5 metres at the topside height of 300 metres.
Although this was a very small deviation, it was enough to create a few problems for guiding the ROVs through the narrow aperture in the various intermediate decks.
Another issue was that the platform started to sway once it was finally in place. It had been known that skyscrapers could oscillate many metres in strong winds, and the Draugen structure was expected to behave similarly in response to wind and waves.
But this platform was the first design of its kind, with only a single shaft, and the swaying created a good deal of concern among control room staff.
“A plumb line hung from the ceiling there, and moved in big figures of eight,” Jenssen relates. Since it made people nervous and had no practical significance, the plumb was eventually removed and the workforce became used to the motion.
The ROV pilots had to familiarise themselves with the GBS design before the shaft was water-filled, so that they would be able to guide their vehicles down at the bottom.
To reach the base of the structure, they first had to take a lift through the narrowest section of the shaft to the deck where the mini-cell started.
They then transferred to a lift inside the mini-cell itself to the bottom of the shaft, where they could see the pipes which extended beyond the concrete wall. “To seawater”, the sign read.
Hatches in the shaft were to be opened with the aid of ROVs once the space was water-filled in order to pull in the conductor tubing.
These in turn were where flowlines with oil and gas, umbilicals and control lines would enter the platform before passing up the shaft to the topsides.
Work could start as soon as the mini-cell was filled with water. Two ROVs were used in the shaft – a Sprint observation model with cameras and a big Scorpio with manipulator arms.
But the problems posed by the 0.3-degree slant now manifested themselves, since the Scorpio could no longer be easily lowered as intended through the square holes in the various shaft decks.
The machine suffered considerably from the buffeting it got on the way up and down because it was difficult to hit the openings exactly.
In the lowest spaces, which were water-filled, the pilot had to use the propellers to manoeuvre the ROV into position to pass through the holes.
If things went really badly, the umbilical could be damaged and the machine would shut down. The only option then was to haul on the cable to get the ROV out.
A big framework containing cylinders and cabling meant the lifting point on the Scorpio could be moved to the best possible position before and after dives.
The pilot sat safe and dry high up in a container on a topside deck and controlled the ROVs as they removed the temporary hatches used to seal the platform during construction and towout.
But the work was demanding. The machines had to be manoeuvred through a jungle of pipes, bracings, cables and decks in very poor visibility.
The pilots usually “flew” with the aid of sonar images as they hunted for the hatches to be removed. In many cases, the space available was only just enough for the ROV to work.
Flexible risers connected the platform to the subsea installations, and entered the GBS through J tubes which opened at the seabed. Pulling the risers into these tubes was accomplished using a wire lowered down the shaft with the aid of the ROVs.
Once everything had been hooked up, the contract for subsea work during the production phase was awarded to Stolt Comex Seaway and its machines replaced the Subsea Dolphin ROVs.
They conducted annual inspection and maintenance work. And several years of repair work were required inside the shaft after cracks had been found in the GBS base around the conductors.[REMOVE]Fotnote: Arild Jenssen in conversation with Kristin Øye Gjerde, 16 April 2016.
Tropical reefs are found in shallow seas with clear water and good light conditions – perfect for observation by diving or snorkelling.
The banks found off Norway grow in colder seas with plenty of current in 100-500 metres of water. They can also be colourful and beautiful, and serve as centres of diversity for marine species.
However, they are far harder to observe. Photographing or filming them usually requires special equipment mounted on a remotely operated vehicle (ROV).
As a result, it is only in recent years that knowledge of these coldwater coral communities has become more detailed.
Coral reefs are built up from calcareous “skeletons” formed by tiny polyps living in colonies. Photosynthesising algae which live inside the polyp cells need sunlight to function, which is why most corals are found in clear shallow water.
Reefs will not form off the mouths of big rivers such as the Amazon, for example, because of all the particles carried in their water from erosion of the hinterland.[REMOVE]Fotnote:Store norske leksikon, https://snl.no/korallrev.
Coral reefs off Norway are built by the coldwater coral Lophelia pertusa. This grow along most of the Norwegian coast, apart from its southern end, Sogn og Fjordane county and the northernmost part of Finnmark county.
Currents and environmental factors are the most likely reasons for the absence of reefs along these sections of the coast. The flow of Atlantic water is particularly important for growth.
Since Norway’s corals account for 30 per cent of the global total of L pertusa, its seas are regarded as a core area for this species. All coral reefs off Norway are now covered by a general conservation order which prohibits any harm to them.
When it became known in the 1990s that some of these communities had been damaged by bottom trawling, such fishing was banned in the most vulnerable zones from the winter of 1992.[REMOVE]Fotnote:Store norske leksikon, https://snl.no/korallrev.
A number of new reefs have been identified in recent years, and the Norwegian Institute of Marine Research found in 2015 that they needed special protection.[REMOVE]Fotnote: Jan Helge Fosså, Tina Kutti, Pål Buhl Mortensen and Hein Rune Skjoldal (2015): Vurdering av norske korallrev. Report from the Norwegian Institute of Marine Research no 8. This has since been introduced by the Ministry of Fisheries.
Coral reefs off mid-Norway
The seas off mid-Norway contain the largest number and greatest density of reefs. Some large coral banks discovered there are estimated to be around 7 000 years old.
Some reefs grow along the outer margin of the continental shelf, while others are found on the shelf itself and in the fjords.
The Sula Ridge is special in that countless small reefs have coalesced into continuous structures of unique size. This area contains the world’s largest coldwater coral bank in deep seas.
Located in 280-300 metres of water, this reef is 13 kilometres long, up to 35 metres high and 700 metres wide. The complex grows on long ridges raised high above the surrounding seabed.
A reef complex comprises hundreds or thousands of corals which are so closely packed that they have combined into great continuous units.
Currents in the areas of reef growth can vary and flow from various directions, which provides good growth conditions on all sides.
None of the reefs are entirely similar in shape or size, and vary from tear-shaped to long banks. More or less circular reefs stand apart, with living colonies atop a zone of crushed coral on the surrounding seabed.
Generally speaking, reefs flourish on sites a little higher than the general sea bottom – on ridges, for example, the edges of fishing banks, atop iceberg ploughmarks or on fjord thresholds. L pertusa also thrives along steep cliffs in the fjords.
The deepwater reefs are home to a great variety of other species, and appear to be a preferred habitat for such fish as redfish and cusk. Blackmouth catshark and rabbit fish can also be found more often over reefs than elsewhere on the seabed.
Furthermore, corals are important in the carbon cycle and thereby play a significant role for fauna and the ecosystem over a wider area than their actual physical extent.[REMOVE]Fotnote: Jan Helge Fosså, Tina Kutti, Pål Buhl Mortensen and Hein Rune Skjoldal (2015): Vurdering av norske korallrev. Report from the Norwegian Institute of Marine Research no 8.
Halten Bank and Draugen
One of the most distinctive L pertusa reefs lies a couple of kilometres east of the Draugen field. It was found in 1994 when Statoil was mapping the Haltenpipe gas pipeline route.
This exciting discovery prompted the Institute of Marine Research to conduct detailed mapping in collaboration with the Geological Survey of Norway using multibeam echosounding.
That in turn has prompted the rerouting of pipelines and the relocation of anchors for floating units.[REMOVE]Fotnote: http://www.geo365.no/olje-og-gass/tralfisket-har-odelagt-korallrev/ Haltenpipe was rerouted past the Husmus reservoir, part of the Draugen area.
Lying a few kilometres from the field, these “Haltenpipe reefs” are typical examples of a coral complex. Standing five to 30 metres high, they measure up to 50 metres across.
A Shell study of threatened marine fauna on Draugen in the autumn of 2011 indicated that some coral structures exist in the area around Draugen, close to existing pipelines and the G-3 well.
Det Norske Veritas analysed acquired videos and photographs in 2012, and concluded that there were no red-listed sponge species or habitat types. But red-listed corals were observed in places.
No good topographical maps of the seabed exist in the Husmus area, where the Draugen water injection well sits, other than some data acquired in connection with Haltenpipe. These show a few scattered reefs.
Limited visual inspections of the area by the Institute of Marine Research found indications of reefs about a kilometre directly south of well A57. This is also the counter-current outlet for the umbilical and production flowline.[REMOVE]Fotnote: http://docplayer.no/9567021-Shellexploration-production.html
The seabed along the Haltenpipe route comprises soft clay and its topography is flat in a water depth of 290 metres. Numerous depressions measuring 100 metres wide and 10 deep are found there.
A few kilometres north of the pipeline, the terrain changes to a seascape characterised by ridges and the water depth reduces to 280 metres.
L pertusa reefs close to Husmus are found on the tops and sides of some of these strange ridges. Only two of the reefs have been documented visually.
Seismic surveys suggest that deposits of frozen methane (hydrate) are found beneath the seabed around the ridges, which melt as they rise to the ridge tops.
But it remains to early to say whether the phenomenon has any special significance for the marine biology of the area.
Shell has issued its own coral guideline in accordance with the Oslo-Paris convention for the protection of the marine environment of the north-east Atlantic (Ospar). This is used in planning new activities in areas where corals are found.
Published April 27, 2018 • Updated October 2, 2018
Kristin Øye Gjerde, Norwegian Petroleum Museum
Draugen was the first field developed on the Norwegian continental shelf (NCS) above the 62nd parallel. There was no infrastructure for export of oil or gas from the area. That created some challenges.
Norske Shell was operator for this groundbreaking project in block 6407/9.
This acreage was covered by production licence 093, awarded in 1984 as part of the eighth licensing round.
Norske Shell owned 30 percent, Statoil 50 percent and BP 20 percent.
— Sunset flaring. Photo: A/S Norske Shell/Norwegian Petroleum Museum
That part of the Norwegian Sea where Draugen was discovered has a distinctive geology. In the exploration phase, a lot of geologists thought no hydrocarbons had formed there but could have migrated from areas of the Halten Bank where discoveries were already made.
Strata of interest lay at shallow depths in the sub-surface. Attention was concentrated on an area where seismic surveys showed signs of a heightening.
These assumptions proved correct, and Draugen was found in a reservoir rock with good production properties. It was primarily an oil field, but with small quantities of associated gas.[REMOVE]Fotnote: Lerøen, B., & Norske Shell. (2012). Energi til å bygge et land : Norske Shell gjennom 100 år. Tananger: A/S Norske Shell.: 173–74.
Oil could be shipped from the field by shuttle tankers, but the question was how the gas should be dealt with in an area entirely without pipeline infrastructure.
This question will be addressed in more detail in this article.
Collective Halten Bank solution?
A study of transport solutions for oil and gas from the Halten Bank area of the Norwegian Sea was initiated in 1985. Draugen was assessed for development at the same time as Heidrun, operated by Conoco.
The Halten Bank had a number of proven gas resources – Midgard, Tyrihans, Smørbukk, Smørbukk South and Njord – and more were possible. So the basis existed for a degree of coordination.
In a letter of 24 February 1987, the Ministry of Petroleum and Energy (MPE) asked the five operators in the area to produce a joint study of the landing issue. This was presented in September.
Offshore loading was recommended by Statoil, Saga Petroleum, Conoco and Shell as the most favourable solution in financial terms for oil.
Based on its own studies of the opportunities for such a solution, Norsk Hydro recommended pipeline transport of crude oil to a terminal on land.
Where gas was concerned, the companies would eventually have to come up with a landing solution for the Halten Bank. But it was uncertain when this might happen and what the choice would be.
Shell and the MPE had several discussions in 1988 on how to deal with the associated gas in Draugen.
The ministry wanted to order the licensees to find a long-term solution based on a gas-gathering system for a number of Halten Bank fields, including Heidrun. Each company’s investment should be proportional to the capacity required.[REMOVE]Fotnote: Letter of 14 December 1988 from the MPE to the standing committee on energy and industry of the Storting (parliament).
Another issue was how the gas would be used. Statoil, who had played a leading role in the work on developing the pipeline network on the NCS, led studies on the gas market and where a possible terminal should be located.
Statoil and the Norwegian Water Resources and Energy Directorate (NVE) had already collaborated for a time on studying a possible gas-fired power station in mid-Norway.[REMOVE]Fotnote: NTB, 6 March 1986, “Statoil og NVE vurderer gasskraftverk”.
If built, such a facility would rank as the biggest in Europe – and 30 times larger than the hydropower station at Alta in northern Norway, completed in 1987 after extensive protests.
It could have an annual capacity of 15 terawatt-hours (TWh). Both the Swedish and Finnish state power companies showed great interest in imports, and discussed this with the NVE management. [REMOVE]Fotnote:Aftenposten, 27 November 1986, “Gasskraftverk planlegges i Midt-Norge”.
Where the gas should be landed was a key question. Five options were identified, spread between three counties: Nord-Trøndelag, Sør-Trøndelag and Møre og Romsdal.
How much gas would be landed was still unclear, so three of possibilities were investigated – including a minimum option involving 0.7 TWh of electricity capacity for local consumption.
The others were a large 2.5 TWh gas-fired power station with exports to Sweden, and a maximum option which included gas exports to potential markets as well as electricity generation.
These solutions were based on one, 3.5 and eight billion cubic metres of gas per year respectively. [REMOVE]Fotnote: Norske Shell AS, Draugen – konsekvensutredning, 1987: 56.
Storting proposition (Bill) no 56 (1987-88), based in part on this study, assumed a gas pipeline from Heidrun and Draugen with an annual transport capacity of one to 1.5 billion cubic metres.
Running to a land terminal and feeding a gas-fired power station, this option was costed at NOK 2.5 billion. One billion cubic metres of gas per annum could lay the basis for 4.5 TWh.
Another solution was to use the gas as feedstock and energy for industrial production. In the longer term, selling gas to Sweden through a pipeline via eastern Norway was one option.
Sales of gas-based electricity to Finland/Sweden offered an alternative, while a tie-in to existing pipelines in the North Sea and sales of liquefied natural gas were also discussed.[REMOVE]Fotnote: Storting proposition no 56 (1987–88) Innfasing av feltutbygginger i årene fremover. Utbygging og ilandføring av olje og gass fra Snorrefeltet. Item 17.
Norway’s gas negotiating committee (GFU), comprising domestic oil companies Statoil, Hydro and Saga, held talks in 1989 with the Swedish authorities on gas deliveries from the Halten Bank.
These negotiations concerned 2.5 billion cubic metres of gas per annum from 1995. However, the Swedes set demands which were difficult for the GFU to concede.
They wanted at least one of the fields supplying their gas to be below the 62nd parallel. But the relatively modest volumes involved from the mid-1990s made pipelines from both the Halten Bank and the North Sea uneconomic, so the talks failed.
Sweden’s demand reflected the fact that deliveries from the Halten Bank alone would provide insufficient security of supply – particularly for power stations intended to use part of the gas.
The Swedes took the view that delivery regularity would be much better from the North Sea. Halten Bank gas via a land terminal to the Gothenburg area would be too vulnerable when maintenance was required, and shutdowns might occur at several of the hubs along the way.
Developments based on subsea solutions did not reduce the risk. The Swedes felt the North Sea had more fields and delivery options. They turned their attention instead to alternative deliveries both from the Soviet Union and from or via Denmark. [REMOVE]Fotnote:Dagens Næringsliv, 14 October 1989, “Svenskene vil ikke ha Haltenbanken”.
From flaring to reinjection
Shell’s original plan for Draugen involved controlled gas flaring during the initial production years. That was clearly stated in the plan for development and operation (PDO) submitted to the government on 22 September 1987.
The company noted that associated gas from the field could be landed through a gas-gathering pipeline and used for electricity generation.
However, it would be a long time before the necessary gas-fired power station was ready and the best and cheapest solution in the interim was flaring on the field.
The Draugen licensees had also conducted studies which showed that the gas could be injected in a separate formation, but this was regarded as too expensive.
A solution involving gas reinjection could moreover only be possible for about three years before having a negative impact on oil production.
The flaring proposal attracted criticism. Daily paper Bergens Tidende presented it under the headline “Energy corresponding to six Alta power stations to be burnt on Draugen”.
According to the accompanying story, “Key players in Norway’s oil community characterise … Shell’s plans for the Draugen field as pure madness, and propose that this development be postponed until the second half of the 1990s”.
The MPE was unsparing, and its comments about Shell in the Storting proposition were fairly cutting:
“Were the licensees at a later time to oppose participation in a gas transport system on terms which the government found it needed to set, production from Draugen could be halted by the authorities to avoid wastage of petroleum”.[REMOVE]Fotnote: Storting proposition no 1. Supplement no 2. Utbygging av Draugenfeltet og lokalisering av drifts- og basefunksjoner for feltene Draugen og Heidrun: 35.
Uncertainty over the choice of a gas solution for Draugen meant that the ministry wanted to postpone a development decision for up to a year. [REMOVE]Fotnote: Storting proposition no 56 (1987-88) Innfasing av feltutbygginger i årene fremover. Utbygging og ilandføring av olje og gass fra Snorrefeltet. Item 17.
Shell was not happy with that. Delay was the last thing it wanted, and the company quickly revised its plans for flaring.
Bergens Tidende could now report: “Shell will be withdrawing its own proposal to base development of the Draugen field on flaring the gas. Instead, [it] will return the gas to the reservoir. In that way, the company hopes to move up the Norwegian Petroleum Directorate’s development queue”.[REMOVE]Fotnote: Lerøen, Bjørn Vidar, Energi til å bygge et land. Norske Shell gjennom 100 år, 2012: 176–77.
Gas flaring was no longer a relevant option in the 1988 recommendation from the Storting’s energy and industry committee on developing Draugen.
The committee emphasised that, even though the quantities of gas involved were relatively small, flaring them would not be permitted for environmental and resource management reasons.
Its recommendation assumed that, until the gas could be sent ashore through a pipeline from the Halten Bank, it would be injected in the Husmus aquifer about 10 kilometres from Draugen.
This process could continue for about three years, and calculations indicated that 75 per cent of the gas could be produced later.
Moreover, opportunities existed to extend gas injection for a further three years by utilising a neighbouring formation.[REMOVE]Fotnote: Budget recommendation to the Storting no 8. Supplement no 2. (1988–89) Innstilling fra energi- og industrikomiteen om utbygging av Draugenfeltet og lokalisering av drifts- og basefunksjoner for feltene Draugen og Heidrun.
Published April 27, 2018 • Updated October 2, 2018