Operator Norske Shell’s main alternatives up to a final decision on the plan for development and operation (PDO) of Draugen were the concrete monotower or a floating unit.
Studies found that either a semi-submersible similar to a drilling rig or a tension-leg platform (TLP) would be the cheapest option.
But the final choice was determined by costs associated with operating and maintaining the support structure. A Condeep monotower made it possible to retain the basic topsides configuration without a new round of design and planning work.
The integrated approach yielded a very compact topsides solution with an efficient relationship between weight and capacity.
With a footprint of 78 by 48 metres, including the external gangways, the topsides measure 32 metres in height from the top of the GBS shaft to the upper surface of the helideck.
The derrick adds almost 50 metres more, and the total height from the bottom edge of the GBS skirts to the derrick tip was about 370 metres.
Safety was a key factor from the very start in developing the platform concept, and the threat of explosion in its various areas came to have a big impact on the final solution.
In particular, the choice of an open truss construction and the use of floor gratings rather than deck plating reduced possible overpressures in the event of an explosion.[REMOVE]Fotnote: ockbain, G., Jermstad, A. (1990). Design of the Draugen Topsides for the Effects of Gas Explosions. Paper presentert på OTC 6477. Houston, Texas.
That also made an important contribution to keeping weight down. When the platform came on stream, the topsides had a dry weight of about 18 500 tonnes.
To optimise the topsides design, Kværner Engineering and Shell commissioned special calculations from the Christian Michelsen Institute in Bergen.
These utilised the flame acceleration simulator (Flacs) – a special computer programme developed at the research facility a few years earlier for several large international oil companies.[REMOVE]Fotnote: Gexcon. (2018). Flacs software. Hentet fra https://www.gexcon.com/products-services/FLACS-Software/22/en
Achieving the output planned for the first year depended on being able to drill and produce oil in parallel through the single platform shaft. That was verified in a separate study.[REMOVE]Fotnote: SikteC A/S. (1991. august). Draugen GBS Shaft Safety Study – Management report. Report no. ST-91-CR-018-01.
The drilling equipment was integrated in the topsides, with the derrick movable so that it could be positioned over the relevant well slot. This structure was removed in 1997.
Work on preparing the rig for removal began on 10 April that year, and the last of 26 heavy lifts was completed on 10 May exactly a month later.[REMOVE]Fotnote: Shell UP. (1997). no 5, June: 14.
Injecting water to maintain reservoir pressure was necessary from the start. This liquid has to be entirely free of harmful substances to avoid damaging the oil and gas resources.
Integrated with other seawater systems for cleaning and cooling, Draugen’s water injection system on includes filtration, deoxidisation, pumping, sterilising and chemical treatment.
Seawater enters the shaft at a depth of about 70 metres, where its quality is more than good enough for injection. Harmful seasonal plankton blooms occur much nearer the surface.
As an extra safeguard, a simple filtration system has nevertheless been installed at the platform intake. Chlorine is added to kill all possible organic material in the flow.
Oxygen is removed by passing the water through a vacuum chamber and, as a final precaution, chemicals are added to remove the last residues of undesirable components.
Main process equipment
The main process equipment on the topsides is intended to meet the requirements set for producing, processing and exporting oil and gas. See the separate article for details of the process.
This is a general term for all the systems required to operate the platform which are not directly involved in oil and gas production.
That includes direct process support as well as equipment for power generation and for living and working on a platform, such as safety, process control, heating and ventilation, and communication equipment.
Safety and security
Systems in this category are required for notifying and executing actions to prevent or reduce major or minor damage. They also include systems for emergency evacuation or for retrieving people who have fallen into the sea.
These are intended to warn of incidents which require a coordinated commitment by all personnel to saving life and maintaining platform safety.
Alarms are given over the public address system, either as a signal or as a verbal announcement. Other alarms were located in areas which used to be protected by halon. A combination of sound and flashing lights, they gave personnel 10 seconds to leave.
This is intended to permit speedy evacuation of personnel from the platform in an emergency, or to retrieve people who have fallen overboard.
covered free-fall lifeboats
covered rafts which inflate on contact with the sea
man-overboard boats (MOBs)
chutes for evacuation to the sea
personal survival suits.
Fire and gas detection
All areas of the platform are fitted with fire and gas detectors. Should fires or leaks be registered, the following actions are initiated automatically:
fire pumps start
sprinkler/deluge systems are initiated (halon has been phased out)
fire dampers in the ventilation system are closed
emergency shutdown (ESD) of the platform is initiated.
Fire extinguishing system
This protects personnel, structures and equipment throughout the platform (including the shafts). Two types of system are installed:
wet, using water or foam
dry, using powder (and halon earlier).
The wet system is supplied by the fire water pumps installed on the service deck. Fixed foam extinguishers are positioned in areas with a high risk of oil fires.
Halon was originally used in technical spaces which contain much electrical and electronic equipment, but has been phased out. A large powder system has been installed in connection with the helideck.
In addition, fire extinguishers – both carbon dioxide and powder – have been positioned for quick response throughout the platform.
The platform needs a lot of water for various purposes. Its sea and service water system is designed to supply all the liquid required for drilling, injection and ventilation systems, and to produce fresh water.
Separate systems are installed for fire and ballast water, while supplies for flushing are used to help wash sand out of the vessels used in the separation process.
Fresh water is produced from seawater with a maximum chlorine content of two parts per million (ppm). This is distilled in three evaporators.
Output from that process is cooled before being pumped via two units which regulate its acidity (pH) into storage tanks, which can also receive desalinated or potable (drinking) water pumped from supply ships.
Most of the fresh water is used for drinking, with some also consumed by cleaning and cooling. Potable water is supplied to the living quarters and selected areas elsewhere on the platform.
Desalinated water is pumped from one of the storage tanks via ultraviolet sterilisation units to consumer tanks located in the roof spaces of the living quarters.
Also called raw fresh water, desalinated service water is fresh water of secondary quality stored in a tank on the cellar deck and distributed by pumps for cleaning, drilling and refilling coolant water.
Used in the coolers for gas and recovered oil, coolant water is a mix of three parts fresh water from the distribution system for desalinated water and one part monoethylene glycol from the glycol system, giving a freezing point of -12°C. A small amount of corrosion inhibitor is added.
Hot water is produced to provide a reliable heat source with a constant temperature for the following applications:
desalination of seawater in the evaporators
heating and ventilation systems (except in the living quarters, which have electrical heaters)
supplies of coolant water to the circulation pump for hot medium.
Steam is produced in a generator with a pressure of eight bar for cleaning process vessels and for various other types of cleaning. The steam generator is a heat exchanger.
Heating, ventilation and air conditioning
These functions are split into two separate systems, covering the production area and the living quarters respectively.
The system for the production area is designed to deliver air at a specified temperature and pressure to the platform’s areas. This is intended in turn to reduce risk and accidents in spaces where fire and explosion are hazards (see compressed air below).
Provision of such air is crucial for safe operation of the platform. Should the system fail for any reason, the process plant must be shut down immediately.
Heating and ventilation of the living quarters involve a completely separate system, which functions in the same way as an installation in a normal building on land.
The heating medium system
serves as a heat source for:
the circulating hot water system for desalination of seawater and space heating, with the exception of the electrically heated living quarters
superheating of sludge
The heat source is a refined paraffin circulated to the user sites, where it is heated in furnaces over an open flame and in three recovery units for waste heat.
Air conditioning in the living quarters serves cabins, recreation areas and the galley. Located in the ventilation room on the service floor, it sucks in fresh air and delivers it at a predetermined pressure, temperature and humidity to the whole living quarters.
A helideck heating system keeps the deck free of ice, maintains the temperature of the fuel gas and the process gas piping to prevent formation of condensate and hydrate (hydrocarbon ice) respectively, and prevents the fire and injection water systems from freezing.
Heating cables are located in channels under the helideck, with electrical heating strips installed externally on piping. These activate automatically if the ambient temperature drops below 5°C.
In a process facility where explosive gases could build up, electrical instruments and spaces containing such equipment must be kept at a pressure above the surrounding plant.
This is intended to prevent gas from entering and being ignited by electrical sparks. A dedicated system provides a reliable source of clean compressed air for instrument and working atmospheres.
This system collects all sewage and waste water for treatment and subsequent discharge to the sea. Most of the sewage comes from toilets, showers, washbasins, kitchen sinks and washing machines in the living quarters.
It is conducted by gravity and negative pressure to septic tanks. A filter removes solid particles, which are then sent to mills for grinding to a liquid sludge.
All bacteria in the sewage – particularly coliforms – are killed by chlorine injection before treated waste is discharged to the sea 10 metres below its surface. If necessary, raw sewage can be discharged to a barge through a hose connection for disposal on land.
Two types of fuel are needed on the platforms – helicopter (aviation) fuel and diesel oil for power generation and other specialised machinery.
Supplies are brought in by ships equipped with special tanks for helicopter fuel. These can also pump diesel oil directly via hoses to special storage tanks in one of GBS cells.
This system distributes various types of lube oil to the main systems through a permanent piping network.
From the filling (tote) tanks, they are piped via lube oil distribution tanks to the most important consumers – gas turbines, generators, water injection pumps and fire pumps.
Other types of oils/lube oils are also required on board, but the level of consumption does not warrant a fixed distribution system for them.
A great many different chemicals and chemical compounds are used on the Draugen platform for such purposes as separating oil and water.
Other applications include inhibiting or breaking down oil droplets in the produced water (emulsions), which is separated from the crude oil flow.
Chemicals also prevent or stabilise foaming, or inhibit hydrate (hydrocarbon ice) formation, bacterial growth or corrosion.
These substances are shipped out to the platforms on supply vessels. Among the commonest are the following.
Methanol is used to prevent the formation of hydrate plugs in pipelines, which can halt liquid flow. When gas contains small quantities of water, ice-like clumps can form under special pressure and temperature conditions.
Glycol primarily serves an agent for removing water from rich gas because it acts as an efficient absorber of water. It is also used in coolant systems to reduce the freezing point to -12°C.
Chlorine can be added to seawater to prevent the growth of bacteria in pipelines and ballast water, seawater and fire water systems. Sodium hydrochlorite (NaOCI) or bleach is used to kill unwanted organisms.
Corrosion inhibitor is added to prevent internal corrosion in piping and tanks. The substances used are usually based on organic compounds which form a protective film on metals.
Bactericides are deployed to control the growth of bacteria in water and hydrocarbons. The most serious problem for oil and gas production is provided by sulphate-reducing bacteria which develop hydrogen sulphide (H2S). This substance is not only toxic but also both explosive and extremely corrosive.
Anti-foaming agents are used to prevent foaming in the main process, and are injected ahead of the separator tanks in order to ensure that separation of water, oil and gas is as efficient as possible.
Transfer and metering systems
Crude oil is transferred from the storage cells to loading buoy via a discharging system which includes powerful pumps installed on top of the shaft.
The transfer then passes via smaller export pumps and the fiscal metering system, which measures the quantity being exported before entering a dedicated flowline system.
Accurate fiscal metering is important, since the licensees must feel confident that the quantities registered are correct and the tax authorities also have to be convinced. A special system therefore conducts regular checks.
Electricity required to operate the platform can be generated by three gas turbines which each have the capacity to meet 50 per cent of maximum power requirements on board.
This means that, if one turbine is temporarily out of operation because of repairs and maintenance, sufficient capacity remains to keep the platform running.
Mains electricity is supplied by three 19-megawatt generators as a 13.8 kilovolt, three-phase 60 Hertz current. The generators are driven by gas/diesel turbines.
Emergency power is supplied by three 1.18 MW generators which start up automatically and connect to a 6 kV panel. If both main and emergency power systems fail, supplies of alternating and direct current will be maintained by batteries.
Electricity for the living quarters comprises the normal supply of alternating current, and emergency supplies of both alternating and direct current.
The normal supply is used for air conditioning, galley equipment, heating, hot water, laundry, lifts, lighting, refrigerators, waste units and ventilation.
Emergency supplies are used to maintain necessary lighting and electronic equipment.
Monitoring and control
The monitoring and control systems on Draugen are located in a central control room (CCR), and ensure an efficient, safe and reliable automated process. Placing the whole monitoring system in the CCR reduces personnel exposure to the production area.
Process control monitors and controls all systems on the platform to ensure that hydrocarbons can be produced as safely as possible. The main functions involve maintaining a check on:
data transmission between the production system and the control-room terminals
analogue operating commands
automatic switches and logical sequence control commands
All this information is monitored from the CCR. Printers and displays for alarms and trends are also concentrated there to provide the operators with a good and accurate picture of conditions at all times.
Safety monitoring is a system intended to handle “all” aspects of safety on the platform. Field instrumentation and sensors for fire and gas alarms monitor the whole process and every area.
The purpose of the system is to initiate production ESD when the process monitoring system fails to handle the problems which might occur.
In principle, it comprises two sub-systems.
Process shutdown monitors the process and shuts it down if control is lost, and thereby prevents the plant being operated in a hazardous manner – under pressures higher than the tanks are designed to handle, for example.
ESD is initiated if hazardous conditions arise – such as a gas leak or a fire. This system receives signals from fire and gas detectors as well as from manual alarms.
The metering system for production and consumption meters the quantity of gas and oil exported from the platform as well as the amount of consumption and fuel gas used internally.
This system attracts great attention from all levels of the organisation, since its measurements form the basis for the revenues generated and the tax to be paid on output.
Systems for telecommunications and pollution control have been constantly replaced and improved in line with technological advances and changing regulatory requirements.
The loading/discharging system is designed to handle supplies brought in or taken away by sea.
Cranes on the platform are used for:
lifting from or discharging to supply ships
maintenance and construction lifting over the whole platform and in the equipment shaft
handling pipes and equipment.
Equipment for bulk handling is used to transport, handle and store various liquids, powders, gases and chemicals required for the platform’s process system and utilities. These products are brought out by supply ships and transferred to the platform either in tanks or via hoses.
Tanks and other bulk containers are lifted by crane from the supply ship to the platform’s storage area on the open deck. Liquids used in large volumes are transferred via permanently installed piping to the fixed storage tanks. Empty tanks are discharged for return to land.
Diesel oil, fresh water, barytes, gel and cement are transferred to the platform’s bulk storage tanks with the aid of hoses lowered to the supply ship.
This part of the platform provides accommodation, recreation and catering for all operational phases. About 60 people will be on board during normal operation, but full service can be provided for 150.
To give the best protection against possible incidents in the well area, the quarters are insulated from the rest of the topsides by a high-performance fire and explosion wall.
This covers the full width and height of the quarters, while a similar wall separates the production section from the area where the wellstream reaches the topsides.
Read more in a separate article on the role of the architect.
The original plan for development and operation (PDO) of Draugen had estimated that the field would only remain on stream until 2010.
However, output over a number of years had established that it would be a long time before the platform had to shut down.[REMOVE]Fotnote:Tidens Krav, 3 February 2012, “Draugen lever minst til 2035”. Its producing life had already been extended to March 2013.
Shell’s operations head was confident that an application would be submitted to the Petroleum Safety Authority Norway (PSA) to keep the field on stream until 2035.
People still believed in February 2012 that Linnorm would be tied back to Draugen – only the investment decision remained to be taken.
It was also revealed that a contract had been awarded to drill four additional wells which would help to double production from the field.[REMOVE]Fotnote:Tidens Krav, 4 February 2012, “West Navigator borer nye Draugen-brønner”.
This optimism persisted throughout February. A major contract was awarded at the end of the month to Aibel, which included a new quarters module with 50 cabins and a new lifeboat station.[REMOVE]Fotnote:Tidens Krav, 29 February 2012, “Shell – Store endringer på Draugen”.
The development concept for Linnorm involved two subsea templates tied back to Draugen for processing and export via the new Polarled gas pipeline from the Aasta Hansteen field.
Unfortunately, the field proved to be less promising than the optimists had assumed. When a wildcat on the Onyx South prospect proved virtually dry, the whole project was eventually shelved.[REMOVE]Fotnote: Petro.no, 20 September 2013, “Linnorm-beslutning i høst”.
An application to extend the platform’s producing life was submitted in the spring of 2015, with the cessation date set as 2024 to harmonise with the expiry of the licence.[REMOVE]Fotnote: Section 25, regulations relating to management and the duty to provide information in the petroleum activities, etc.
In May 2015, the PSA announced that it had consented to an extension of Draugen’s producing life until 9 March 2024. This was still the cessation date for the field in the summer of 2018, and the licensees will have to apply again if a further extension could prove profitable.[REMOVE]Fotnote: Petroleum Safety Authority Norway, 20 May 2015, “Draugen får samtykke til forlenga levetid”.
A well drilled in the summer of 2015 came on stream in late 2017, and a new seabed pump has also been installed to boost flow from this and the other subsea wells.
Reduced oil production from the field in recent years means that supplies of associated gas have become inadequate for power generation. Alternative solutions for maintaining electricity supplies are under evaluation.
To achieve the overall oil output expected by the licensees, the producing life of the subsea installations must be extended. That in turn means the platform has to stay on stream beyond the restrictions which applied in 2018.[REMOVE]Fotnote: Norwegian Petroleum Directorate fact pages, 3 March 2018.
Published August 27, 2018 • Updated October 3, 2018
Four years passed before drilling began, but the crew on the Transocean Leader rig could spud the first wildcat in the middle of June 2004. It took almost a year to complete, but work finished on 2 June 2005 with a small discovery.
Several wildcats were drilled in the acreage dubbed the “golden block” of the 16th licensing round, but none resulted in finds large enough to prompt immediate development plans.
Overall, the discoveries added up to less than had been hoped for, and the reservoir contained gas under high temperature and pressure.[REMOVE]Fotnote: Oljedirektoratets Faktasider (2018)
That could be described as unfortunate, since Shell had been hoping to find oil. Its optimistic plans for this Onyx discovery were accordingly toned down, but an appraisal well was drilled in the spring of 2007 to learn more about the reservoir.
More gas discoveries were eventually made further north in the Norwegian Sea. The most promising was Luva, discovered in 1997 and renamed Aasta Hansteen on 8 March 2012.
But substantial development was delayed, partly because the finds were too small and partly because of the need to lay an export pipeline.
Two large gas transport facilities from the Norwegian Sea existed after 2007 – Åsgard Transport and Langeled. However, these lacked the spare capacity to handle additional volumes.
Fresh efforts to come up with a development solution were initiated in 2010. Great optimism prompted a competition to find a new name for Onyx, which was renamed Linnorm in the autumn.[REMOVE]Fotnote: Shell World Norge (1 – 2010) s. 27
In addition to launching the name hunt, the first issue of the Shell World Norge house journal contained several buoyant articles about expectations for the discovery.
Under the headline “Exciting times for Onyx”, project manager Tom Egil Karlsen wrote:
Before Christmas last year, we reached the first major milestone which marked that we had completed a successful feasibility study. This is known in the project world as decision gate (DG) 2. The next step will be to look more closely at how a development can happen in practice. In this round, we’ll be looking together with our partners at all possible solutions for a development. We’re working a little in ‘wide angle’ before narrowing our sights to the options which prove the best.[REMOVE]Fotnote: Shell World Norge (1 – 2010) s. 6
Norske Shell vice presidents Grethe Moen and Knut Mauseth were also quoted about their optimism for Onyx.
A press release the following summer made it clear that the best solution for Linnorm involved a subsea installation tied back to the Draugen platform.
Gas from there and Luva would be piped to Nyhamna for processing and onward transport, together with output from Ormen Lange, through Langeled to Easington in the UK.
That could be accomplished by installing a 3 000-tonne process module on the Draugen facility and by making a number of substantial modifications.
The plans indicated that Linnorm could come on stream in 2017 and Luva a year later, and a detail design project was launched to identify the final configuration.[REMOVE]Fotnote: Helge Hegerberg, Adresseavisen (15.6.2011) Draugen tar Linnorm s. 27
By the early autumn of 2012, Shell and a number of other oil companies – Statoil in particular – appeared to have come up with a possible solution for developing several gas finds in the area.
These would all be tied into a new transport system named the Norwegian Sea gas infrastructure, which is better known today as the Polarled pipeline.[REMOVE]Fotnote: Stein Tjelta, Sysla Offshore (13.01.2012) Shell går videre med Linnorm
At that time, Linnorm and Luva/Aasta Hansteen were regarded as the cornerstones for achieving commercial development of all the gas fields in this part of the Norwegian Sea.
An impact assessment presented by Shell in September 2012 again envisaged a 50-kilometre pipeline tied back to the Draugen platform.[REMOVE]Fotnote: A/S Norske Shell (September 2012) Plan for development and operation of Linnorm, part 2, impact assessment.
The latter would have to be expanded to process 15 million cubic metres of gas per day, which would require the construction and installation of several new modules.
At that time, oil was well over USD 100 per barrel and gas prices were also sky-high. The market looked like stabilising at a three-figure oil price.
A development project for Linnorm was costed at close to NOK 10 billion, and the project management envisaged the licence taking an investment decision in the autumn of 2013.
The plan for development and operation (PDO) of this field was expected in January 2013. On 20 November 2012, however, work was postponed indefinitely in anticipation of results from a well to be drilled further south on the discovery.
Hopes were high that this appraisal would prove gas which increased the reserve base and thereby justified development of the whole field.
In practice, however, the well was declared dry on 5 September and Linnorm seemed to have been definitely abandoned.
The following comment from Terje M Jonassen, Norske Shell’s communication manager for exploration and production, was reported in the press:
This was not what we hoped for when we started drilling. Where Linnorm’s future is concerned, no decision has yet been taken. The way forward will be discussed with the partners in the licence, who will take a joint decision on this.[REMOVE]Fotnote: Toril Hole Halvorsen (20 September 2013), “Linnorm-beslutning i høst”, Petro.no.
Shell has not given up on Linnorm, even though initial efforts to achieve a development were unsuccessful. The area is still being assessed in 2018 on the basis of new solutions which could yield a financially and technically feasible project.
Published August 27, 2018 • Updated October 8, 2018
Finn Harald Sandberg, Norwegian Petroleum Museum
Norwegian blocks first became available above the 62nd parallel (the northern limit of the North Sea) with the fifth licensing round in 1979. And acreage was finally awarded across the whole Norwegian continental shelf (NCS) – from the North to the Barents Seas – during the eighth round in 1984.
— This field lies in block 6407/9 in the Norwegian Sea, where a production licence was awarded on 9 March 1984 as part of the eighth licensing round. Photo: Shadé Barka Martins/Norwegian Petroleum Museum
A/S Norske Shell secured interests in two eighth-round production licences (PLs), including PL 087 in block 16/4 where Norsk Hydro was operator. Two dry wildcats have been drilled there.[REMOVE]Fotnote: Oljedirektoratet: Faktahefte 1987
A/S Norske Shell secured interests in two eighth-round production licences (PLs), including PL 087 in block 16/4 where Norsk Hydro was operator. Two dry wildcats have been drilled there. However, Shell was named operator for PL 093 – which today encompasses the Draugen field – with Statoil and BP as its partners.
This licence proved an immediate success. Its award was announced on 9 March, the first wildcat was already under way on 26 June, and the well had been completed by 7 September.
Clear indications were found of a good-quality and substantial reservoir containing primarily oil. Making a discovery within six months of the licence award was unusual.
Shell also managed to maintain a rapid pace in developing the find. The plan for development and operation (PDO) was approved in 1989, less than five years after the discovery. Moreover, Draugen came on stream within a decade of being found – about five years faster than other NCS fields in the same order of size and during the same period.
A total of 17 blocks were awarded in 1984, with PLs numbered from 86 to 100. Five were in the North Sea, five in the Norwegian Sea between Trondheim and Brønnøysund (including Draugen) and five in the Barents Sea.
The eighth licensing round has proved one of the most successful set of awards made on the NCS with regard to the number of commercial discoveries.
At the time, North Sea block 34/7 attracted the greatest expectations. This acreage was covered by PL 89, which has proved to contain various reservoirs developed under different names. Snorre produces through two platforms, while little Sygna is a subsea field tied back to Statfjord along with the Statfjord East satellite. In addition come two further subsea developments – Tordis and Vigdis. These have been tied back to Gullfaks C and Snorre A respectively.
Licences awarded in addition to PL 34/7 in the eighth round have otherwise resulted in the following field developments:
Heidrun (Norwegian Sea), on stream October 1995
Åsgard (Norwegian Sea), on stream May 1999
Fram (North Sea), on stream October 2003
Mikkel (Norwegian Sea), on stream August 2003
Snøhvit (Barents Sea), on stream August 2007
Tyrihans (Norwegian Sea), on stream July 2009.
In addition, the Peik discovery is under consideration for development in 2018 – more than 30 years after the block was licensed. Four of the licences are considered non-commercial.
Blocks awarded during the eighth round contain recoverable reserves of nearly 11 billion barrels of oil equivalent (1.75 billion standard cubic metres).[REMOVE]Fotnote: Oljedirektoratet. (2018) Faktasider – Felt – Reserver Hentet fra http://factpages.npd.no/factpages/Default.aspx?culture=no Lastet ned 27.04.2018 That corresponds to almost a fifth of all the oil and gas discovered on the NCS.
Published August 24, 2018 • Updated October 17, 2018
Positive news about the field was important in 2000 after seven years on stream and with oil prices low. So Kristiansund’s local paper reported that Shell was fully committed to producing on the Norwegian continental shelf (NCS), and mid-Norway in particular.
This article in Tidens Krav focused on Draugen’s many positive aspects and included the following comment:
A couple of world records have also been set on Draugen. This time, [it] can claim the longest continuous period of production after 176 days without a shutdown. The other record is that one Draugen well has produced 76 775 barrels of oil over a single day. This is the highest daily output from an individual well.[REMOVE]Fotnote:Tidens Krav, 19 January 2000, “Har fullt fokus på midtnorsk sokkel”.
Whether these actually ranked as world records was not perhaps confirmed, but the quote demonstrates the importance of positive news in this period.
These records were also highlighted in the field’s 10th anniversary year. A major article in Trondheim daily Adresseavisen hailed Draugen as the “jewel in the crown”:
When operator company Norske Shell applied to the government in the autumn of 1987 to develop the field, it planned to produce 90 000 barrels per day [b/d]. When it brought Draugen on stream from 19 October 1993, it quickly managed to bring up a lot more. At peak, Shell produced 230 000 b/d. Production has lain at a level of more than 200 000 b/d of treated oil over many years, without water breakthrough. A world record has also been set 150 kilometres north-west of Kristiansund: no individual production well has produced more than 77 000 b/d. These records have meant a lot in value terms. The 77 000 barrels which were the result on 12 October 2003 represented almost NOK 47 million, or more than NOK 32 000 per minute. The single well which set the record on 20 October 2000 contributed NOK 500 000 to profits on that day.[REMOVE]Fotnote:Adresseavisen, 16 October 2003, “Draugen er Norges mest lønnsomme tiåring”.
Small gas deposits close to Draugen generated great optimism in 2010-13. The little Linnorm discovery, in particular, was a hot candidate for tie-back to the platform.
That would allow the latter to stay on stream even longer than the planned production period until 2028 – which had been lengthened from an original extension to 2020.
Although development plans for Linnorm were ultimately shelved, it is worth noting the optimism which prevailed in Draugen’s 20th anniversary year as expressed by Tidens Krav:
Within a few months, the first oil field brought on stream north of Stad [the northern limit of the North Sea] will reach its 20th anniversary. When the plan for development and operation was submitted to the authorities in 1988, Draugen was expected to produce for 17 years and achieve a recovery factor of 38 per cent. Shell’s tough target is now to recover no less than 75 per cent of the resources up to 2036. In the event, that would be a world record for offshore oil fields.[REMOVE]Fotnote:Tidens Krav, 7 May 2013, “Nr. 1.000 fra Draugen”.
In this case, the “world record” claim was perhaps prompted by local patriotism. Shell also issued a more restrained press release, which stated in part:
Draugen has delivered crude oil stably since it came on stream in 1993. The field has delivered a much higher volume than originally expected, and is in position to take the gold medal for recovery factor. According to the original plans, Draugen should have ceased production after 17-20 years, but its producing life will be substantially extended.[REMOVE]Fotnote:Teknisk Ukeblad, 21 October 2013, “Flyttet brønnen en kilometer, fikk et helt oljefelts produksjon tilbake”.
To put this last record in context, Draugen can be considered from a Norwegian perspective. The perception generally prevails that petroleum resources on the NCS have particularly good production properties compared with many other parts of the world.
That has perhaps also made it easy to equate “best in Norway” with “best in the world” – a conclusion which is not always entirely true.
The recovery factor specifies the technically and commercially recoverable petroleum in a reservoir as a proportion of the stock tank oil initially in place (Stoiip) – in other words, the original resources present.
In order to compare fields with different mixes of oil and gas, all petroleum quantities are converted to oil equivalent in order to determine the total quantity in the reservoir.
Compared with all 115 of the fields which are, have been or will soon be in production on the NCS, Draugen occupies 22nd place for recovery – so not quite top of the overall list.
However, a big difference exists between fields which primarily produce oil and those which only yield gas. The oil-gas ratio (OGR) is often used to distinguish between the various categories – the higher the figure, the more the oil.
As figure 1 shows, an oil field more often has a lower recovery factor than one producing primarily gas.
Looking at the most typical Norwegian oil fields (OGR > 0.9) presented in figure 2, the claim that Draugen belongs in the premier division for recovery is pretty clearly established.
At 31 December 2017, Grane was the only field on the NCS which had a slightly higher recovery factor than Draugen – at 67.2 per cent compared with 66.9 per cent.[REMOVE]Fotnote: Norwegian Petroleum Directorate (2018), Fact pages – Fields. Downloaded 30 April 2018. http://factpages.npd.no/factpages/Default.aspx?culture=no.
Published August 24, 2018 • Updated October 10, 2018
The operator planned to place orders worth some NOK 35 billion (equivalent to roughly NOK 65 billion in 2018 money) for these two projects. Draugen accounted for almost a third of this amount.[REMOVE]Fotnote: Dagens Næringsliv. (1989. 27. januar). Shell-kontrakter til 35 milliarder kroner.
That proportion reflects the fact that Shell’s Troll A plans covered the world’s largest offshore gas field, and included a massive concrete gravity base structure (GBS) for the platform.
Plus the topsides, this whole facility would stand 472 metres high at tow-out in 1995. That makes it the world’s tallest structure moved by humans.
Less than six months after Troll A came on stream, Statoil took over as production operator for the gas development in accordance with the terms of the licence agreement.
The award of the NOK 500 million detail design contract for the Draugen topsides to Norway’s Kværner Engineering (KE) was announced on 15 March 1989.
About 450 people would be employed in designing this steel structure, including outfitting, living quarters and drilling facilities.
KE was also responsible for planning the test programme and commissioning for the platform once it was in position on the Halten Bank area off mid-Norway.
Shell was also very keen to ensure competition over building the GBS, a business where Norwegian Contractors (NC) had become a virtual monopoly supplier with its Condeep solution.
The operator worried that this would mean a higher price than if several companies competed for the work, and accordingly invited the Peconor group to submit a tender.
This contractor had done a good job in building the protective barrier for the Ekofisk tank in the North Sea, and Shell thereby felt it could be a viable competitor to NC.[REMOVE]Fotnote: Donoclift, P. (Phillips Petroleum Co. Norway), Gijzel, T.G. (Peconor Ekofisk/VSO), Hjelde, H.G. (Peconor Ekofisk/AVECO) &VeldkampJ.R. (Peconor Ekofisk/VSO. (1990). Transport and Installation of Protective Barrier Ekofisk 2/4 Tank. Paper presentert på OTC-6472–MS.
Norske Shell nevertheless announced on 31 August 1989 that the NOK 1.7 billion contract had gone to NC. Gregers Kure, CEO of the latter, expressed himself “incredibly pleased”.
This job would form an important basis for the GBS specialist’s future activity and for the development of new concepts.
During the period before the Draugen award, NC had been forced to reduce its workforce from 1 500 people to around 700. Now its staffing and technical expertise could be preserved.[REMOVE]Fotnote: NTB. (1989. 31. August). Norwegian Contractors vant konkurransen om Draugen-plattformen.
The three Norwegian fabricators invited to bid for building the 18 000-tonne topsides for the Draugen platform were announced on 28 July.
With no foreign companies included in the list, the deadline for tenders was set to mid-November with the contract award scheduled for early 1990.
The licence terms committed Shell to involve mid-Norwegian industry as much as possible, and the invitation to tender stated that the successful fabricator must inform possible sub-contractors in that part of Norway of its needs at an early stage in the process.[REMOVE]Fotnote: NTB. (1989. 28. juli). Ren norsk konkurranse om bygging av Draugen-dekket.
It emerged on 26 January 1990 that the Kværner Rosenberg yard in Stavanger had landed the NOK 1.1 billion assignment, which was that year’s largest offshore job for Norway’s fabricators.
Tore Nordtun, mayor of Stavanger, declared that this was “a fantastic day for Rosenberg, for the region and for local industry in the town”.[REMOVE]Fotnote: Stavanger Aftenblad. (1990. 26. januar). Rosenberg bygger Draugen-dekket.
Seven months later, it became clear that KE would secure the NOK 150 million contract for engineering services related to following up fabrication of the topsides.
Provision was made for close collaboration between the two Kværner companies, with KE responsible for delivering drawings, materials and equipment to the construction job.[REMOVE]Fotnote: Dagens Næringsliv. (1990. 28. august). Ny kontrakt til Kværner.
In addition to the major GBS and topsides contracts, Shell placed a number of important orders for the procurement of important platform components.
Kværner’s contract for the main power generators was among the very first of these to be clarified in August 1989. Worth NOK 220 million, this job called for the equipment to be supplied to Stavanger in early 1991.[REMOVE]Fotnote: NTB. (1989. 28. juni). Kværner leverer generatorer til Draugen-plattformen.
The following major and more minor contracts were placed during the autumn and winter:
25 August 1989. Deck cranes to Stålprodukter A/S in Molde. Value NOK 30 million.
31 August 1989. Pressure vessels to Orkdal Offshore/Orkla Engineering. Value NOK 1.5 million.
1 November 1989. Equipment for process control and safety systems to EB Industri og Offshore. Value NOK 50 million.
4 December. Lifeboats to Harding Safety A/S at Ølve in Hardanger. Value NOK 25-30 million.
6 December 1989. Construction and outfitting of the quarters module to Hitec-Dreco in Stavanger. Value NOK 165 million.
13 January 1990. Fire doors to Rapp Bomek A/S in Bodø. Value NOK 150-200 million.
23 February 1990. Freight and forwarding in connection with the development to Vestbase in Kristiansund. Value NOK 50 million.
29 March 1990. Actuator-controlled valves to ScanArmatur in Stavanger. Value NOK 20 million.
31 May1990. Telecommunications equipment to EB Industri og Offshore. Value just over NOK 47 million.
In addition to equipment for installation on the platform, the Draugen development also covered separate subsea installations to help recover oil from the field.
The contract for this delivery went to Kongsberg Offshore. Announced on 2 June 1990, it was worth NOK 480 million.[REMOVE]Fotnote: NTB. (1990. 2. juli). Draugen-kontrakt til Kongsberg.
Draugen would also be the first field in the world to feature a special subsea pumping system known as a Shell multiphase underwater booster station (Smubs).
This was intended to pump an unprocessed mix of oil, gas and water (as well as accompanying sand) from the seabed production wells to the platform six kilometres away.The contract with Kongsberg Offshore specified that the equipment should be ready for testing at the company in good time before installation on the field.
Actual fabrication of Smubs had a price tag of just under NOK 16 million, but the equipment was the outcome of a three-year research project which had cost NOK 30 million.At the end of this 18-month procurement drive, Norske Shell had thereby placed contracts worth more than NOK 4.5 billion for the Draugen development.
Published August 24, 2018 • Updated October 4, 2018
It became known in February 1994 that the operator was assessing prospects for increasing daily production from the field by 30-50 per cent.[REMOVE]Fotnote:Dagens Næringsliv, 14 February 1994, “Ekstra mrd. til Draugen-eierne”.
Two new wells and some minor modifications to the platform could boost output by 40 000 barrels per day (b/d). That would greatly improve profitability but was not without problems.
While Shell said Draugen was financially robust, a number of questions had been raised about the field’s profitability after oil prices had fallen steadily from USD 20 per barrel in the summer of 1992 to below USD 15 in the autumn of 1993.
The company claimed that Draugen would continue to do well at this price level, and that it could even survive prices close to USD 10 per barrel.
Raising production above 100 000 b/d would let the government invoke the “sliding scale”, which allowed it to increase the state’s holding in the field by about 15 per cent.
Higher output would thereby be very good for the government, but unprofitable for Draugen partners Shell, Statoil and BP – who threatened to veto an increase if the sliding scale was applied.[REMOVE]Fotnote:Bergens Tidende, 25 August 1994, “Dragkamp om Draugen”.
Although the position remained unclarified, Shell drilled new wells during 1994. A compromise was negotiated the following spring which resulted in a Storting decision on 12 June 1995.
Claims by the licensees that full implementation of the sliding scale would make a production rise unprofitable were only partly accepted.
The upshot was that the government increased Statoil’s interest in the licence by eight per cent while reducing the Shell and BP holdings by 4.8 and 3.2 per cent respectively.
While the change in licence holdings took effect on 1 July, the platform jumped the gun by boosting output to 140 000 b/d from 28 June.
Shell was decidedly unhappy about the new division of interests, but operations head Knut Engebretsen confined his comments to saying: “we can live with this”.[REMOVE]Fotnote: Bergens Tidende, 29 June 1995, “Kraftig økning på Draugen”.See also the article about the licensees on Draugen.
Published August 24, 2018 • Updated October 9, 2018
June 1995: Draugen Upgrade – production capacity increased
The first phase of upgrading the Draugen production facilities was completed over a 10-day period in late June 1995. This work was carried out with the platform shut down, and no problems were encountered during the subsequent restart.
Maximum oil output was thereby increased to 155 000 barrels per day (b/d), which corresponded to an annual average of 140 000 b/d.
Work included correcting inefficient design solutions, replacing control valves, installing larger piping and upgrading the emergency blowdown system on the second-stage separator.
Phase two of the project was carried out the following year to secure a 10 per cent rise in maximum production without affecting operating stability.[REMOVE]Fotnote:EPO info, no 4 1995, “Oppgraderingen på Draugen: Suksess i første fase”.
May 1997: drilling rig removed
The decision to remove the drilling rig on the Draugen platform was taken in January 1997. Although only five wells had been drilled since production started, the facility was not required. Maintenance work would also be reduced.
Work began as early as 10 April, and was completed in exactly a month thanks to the deployment of efficient access techniques.[REMOVE]Fotnote:Shell UP no 5, June 1997, ”Fjerning av boremodulen på Draugen”.
In the early autumn of 2012, Shell – with a number of other oil companies, and Statoil in particular – appeared to have found a way to develop several gas discoveries in the Draugen area.
This involved connecting all of them to a new transport system initially called the Norwegian Sea gas infrastructure, and later renamed Polarled.[REMOVE]Fotnote:Sysla Offshore, 13 January 2012, ”Shell går videre med Linnorm”.
At that time, the Linnorm and Aasta Hansteen discoveries were regarded as the cornerstones for achieving commercial development of all the gas fields in this part of the Norwegian Sea. Shell therefore planned to extend Draugen’s producing life until 2036.[REMOVE]Fotnote:Midt-Norsk Olje & Gass, no 2, 2012, ”Draugen til 2036”.
The original PDO had assumed that the field would stay on stream for 20 years. Its official producing life accordingly expired in 2013.
Shell intended to apply to the Petroleum Safety Authority Norway (PSA) and the Norwegian Petroleum Directorate (NPD) to use Draugen beyond its initial cessation date.
In order to operate the platform safely and prudently after 2013, it was important to be able to demonstrate that good care was taken of system integrity throughout.
Both technical and organisational analyses were conducted so that Shell could demonstrate the acceptability of keeping Draugen on stream.
Its application to the authorities also detailed plans for the measures which were required. In an interview with the journal Midt-Norsk Olje & Gass, operations head Gunnar Ervik commented:
They hoped for a producing life of 17 years, we have now passed 18 and are not going to give up any time soon. We may perhaps be only halfway through the field’s producing life. Regardless of how you measure it, Draugen has always delivered and I’m proud to have been part of that. I regard the fact that the Linnorm licensees chose Draugen as its host platform as proof that we’re on the ball, and competitive.[REMOVE]Fotnote:Midt-Norsk Olje & Gass, no 2, 2012, ”Draugen til 2036”.
Ervik’s comments were followed up by Norske Shell project director Bernt Granås. He noted that the Draugen and Troll A projects had been used in the 1980s and 1990s to build up the company’s project capability.
The new plans for extending Draugen would play a very important part in rebuilding this expertise. An investment decision on Linnorm could hopefully extend the platform’s producing life by 25 years.[REMOVE]Fotnote:Midt-Norsk Olje & Gass, no 2, 2012, ”Draugen til 2036”.
Shell’s ambitious plans for keeping the field on stream led to the award of a 10-year frame contract to Aibel, which would handle design and execution of conversion jobs large and small.
The assignment was one of the most significant in the history of this Norwegian offshore service company, and offered it opportunities for growth in Kristiansund.[REMOVE]Fotnote: Aibel website, 13 November 2013.
Planned project activities on Draugen
Injection of produced water back into the reservoir. Installation of a new loading system. Removal of the former loading buoy. Drilling of four new subsea production wells.
Installation of a subsea booster pump to provide an extra push to the wellstream and thereby help to increase production.
Installation and tie-in of new pipelines and umbilicals.
Installation of new lifeboats.
Modification and upgrading of equipment, both on the platform and subsea – a number of projects fall into this category.
Installation of an additional quarters module with 45 extra berths.
Upgrading to handle gas from Linnorm (conditional on a final investment decision).
Aibel’s first project under this contract was the construction of a new lifeboat station and quarters module – the latter in cooperation with a Dutch fabricator.
But expectations for Linnorm proved over-optimistic in late 2012 and early 2013. Work was postponed indefinitely on 20 November and, after an appraisal well completed on 5 September proved dry, the development was shelved.[REMOVE]Fotnote: Petro.no, 20 September 2013, “Linnorm-beslutning i høst”.
However, the two fabrication projects went ahead. Both structures were lifted into place on 10 November by Heerema’s Thialf heavy-lift ship without damage or accidents of any kind.
The Draugen platform’s strategic location means it has been the candidate for tie-ins of smaller oil and gas fields in the same area.
It became known in November 2014 that the facility was being regarded as a possible host for production from the Pil og Bue and Snilehorn discoveries, operated by VNG and Statoil respectively.[REMOVE]Fotnote:Sysla, 20 November 2014, “Draugen trenger nye funn for å overleve”.
The application to lengthen the field’s producing life was therefore maintained, and the licensees were informed in May 2015 that the production licence had been extended to 9 March 2024.[REMOVE]Fotnote:Offshore Energy Today, 21 May 2015, “Life extension for Shell’s Draugen (Norway)”.
But it became clear during 2016 that both Pil og Bue and Snilehorn would be tied back to “rival” Njord. That put a temporary stop to the many plans for the Draugen platform.
Published August 23, 2018 • Updated October 9, 2018
After four years of wrangling, the outcome was that A/S Norske Shell had to pay a total of NOK 311 million on behalf of the field’s licensees.[REMOVE]Fotnote: NTB. (1996. 12. januar). Shell tapte voldgiftssak om Draugen-dekket.
NOK 2.1 billion had already been paid following delivery of the structure from the Kværner yard in February 1993, but the two sides could not agree on the final amount. They had continued to negotiate on a number of issues related to this settlement, and managed to resolve most of the matters in contention.
However, stalemate was reached in the autumn of 1994. Claims and counterclaims were presented, and one of the biggest arbitration hearings in Norwegian legal history began that August.
Kværner had originally claimed NOK 200 million in compensation for forcing the pace of fabrication work – a demand later reduced to NOK 165 million.
For its part, Shell maintained that the yard had breached the contract either deliberately or through gross negligence, and presented a compensation claim of NOK 1.47 billion. This was later restricted to NOK 576 million on condition that the Draugen licensees were allowed to retain a bank guarantee of NOK 198 million.[REMOVE]Fotnote: Dagens Næringsliv. (1996. 13. januar). Shell tapte mot Kværner.
The final adjudication rejected Shell’s claim, thereby handing Kværner a complete victory. Shell had to pay NOK 113 million for the bank guarantee and as a supplement for extra work. In addition came interest and legal fees.
According to communications vice president Atle Kigen at Kværner, this settlement was worth NOK 225 million to the group in 1995-96.[REMOVE]Fotnote: Aftenposten. (1996. 13, januar). Draugenseier til Kværner.
Published August 23, 2018 • Updated October 4, 2018
They were Statoil, with a 50 per cent interest, BP Norway Limited UA with 20 per cent and A/S Norske Shell with 30 per cent. Shell was appointed operator.
This award was made in Norway’s eighth offshore licensing round, when 14 such production licences were issued covering a total of 16 blocks to various companies and constellations.
These holdings were spread for the first time across the whole Norwegian continental shelf (NCS), from the North Sea in the south the Norwegian Sea, and the Barents Sea in the far north. To the surprise of many, given the “Norwegianisation” policy of the day, foreign companies did well in terms of operatorships. Six of the 14 were secured by international players.
Licence and the award process
The process of awarding a production licence usually begins with the Ministry of Petroleum and Energy (MPE) inviting the oil companies to bid for NCS blocks.
Acreage on offer is determined by the MPE, with the companies putting in bids for the blocks they regard as most attractive – either singly or in partnership with others.
They assess blocks by the probability of making a discovery and how a licence would fit with their strategy. A company could, for example, apply in areas where they already have production.
The MPE decides who gets a licence, and the share each partner will have in it. Costs and revenues are usually divided between the licensees on the basis of their relative equity interest. All fields on the NCS have several partners, with their different roles in the licence determined by the MPE. One is appointed operator.
The latter has the job of organising exploration for petroleum as well as developing and operating a possible discovery – subject to the support and supervision of the other partners.
An operator is usually the most experienced player in a licence. It must also have the resources, expertise and personnel needed to conduct all relevant operations and activities in line with the applicable regulations.
The operator is therefore the partner in a licence with day-to-day responsibility for its activities. As mentioned above, Shell has fulfilled this role on Draugen.
But the other licensees are not freeloaders. Although the operator handles everyday work, its partners are meant to contribute actively in ensuring it complies with the rules.
Norway’s offshore regulations require them to support and challenge the operator, serve as a competent partners and see to it that activities are pursued in a prudent manner.
Holdings in a licence can change over time through purchase and sale (farm in/out) of interests as well as regulatory changes. In Draugen’s case, a political settlement played a key role in the first adjustment of percentage shares in the field.
A broad compromise on oil policy emerged in parallel with the eighth licensing round. This involved the non-socialist coalition between the Conservatives, Christian Democrats and Centre Party under premier Kåre Willoch, and the opposition Labour Party.
It settled a political controversy over the place of state oil company Statoil in Norway’s petroleum sector. Many people, particularly in the Conservative Party, felt it had become over-mighty. They also viewed its cash flow as excessive in relation to the country’s gross domestic product.
The solution was to break up Statoil’s holdings, with a portion of them being transferred to a new legal entity called the state’s direct financial interest (SDFI).
Established with effect from 1 January 1985, this had no direct responsibility for operations. Statoil was to manage the SDFI and handle its operational and commercial functions.
The compromise aimed to create a model which would provide continuity for state participation in the Norwegian petroleum sector regardless of changing political conditions. Statoil’s interests in Draugen were among those split. The state still held 50 per cent, but that was now divided between 30 per cent for the SDFI and 20 per cent for the company.
This change had little significance for the Draugen project during the early years. The government, through the SDFI, still had to meet part of the development costs earlier paid by Statoil. The direct consequence for Draugen operations was first felt in 2002, when another state-owned company took over management of the SDFI’s interest – which had risen to 47.88 per cent by then.
Made necessary by the partial privatisation of Statoil in 2001, this moved transferred responsibility for the SDFI to the newly formed Petoro AS. The latter was given a commercial mandate, but with certain restrictions on its operations. It could not, for example, act as an operator for fields on the NCS.
The first change in licence interests on Draugen came in 1988, when the state’s share in the field – split between Statoil and the SDFI – rose from 50 to 65 per cent. Shell and BP had their holdings reduced to 21 and 14 per cent respectively.
This revision utilised a provision introduced with the third licensing round in 1974, which entitled the government to raise the state’s share in a licence.
Exercisable once a plan for development and operation (PDO) had been approved, this “sliding scale” principle applied to all licences awarded on the NCS from the third round.
Up to the eighth round, when the Draugen licence was awarded, the sliding scale provided that Statoil’s interest should depend on the size of plateau output from a possible field.
Any increase in this level of production would mean that the state company’s share could be increased in accordance with the scale. When a licence was awarded, before exploration drilling began, great uncertainty prevailed about the size of oil and gas reserves a reservoir might contain and how far they could be recovered. These rules changed after the eighth round and the creation of the SDFI. With effect from the ninth round, the sliding scale was replaced by a government option independent of production.
The PDO for Draugen was debated by the Storting (parliament) in the autumn of 1988, after it had been considered by the Ministry of Petroleum and Energy (MPE).
According to a recommendation from the ministry, the plateau production of 90 000 barrels of oil per day (b/d) proposed by operator Shell should be increased to 110 000.
This rise would have lifted the field to a new level on the sliding scale, where the increase in the state’s collective holding (Statoil plus SDFI) would go up from 65 to 75 per cent. That would have had a big negative impact on the private-sector companies in the licence. Shell and BP reacted sharply, and launched an effective lobbying campaign aimed at the Storting’s standing committee on energy and industry.
The latter was chaired by Ole Gabriel Ueland from the Centre Party, which took a sceptical view in general to increasing production from the NCS. Rejecting the MPE’s proposal, the committee recommended instead that the plateau rate for oil output should remain at the 90 000 b/d set by Shell. But it also approved an increase in the state’s share of Draugen to 65 per cent, with 19.6 per cent allocated to Statoil and 45.4 per cent to the SDFI. As noted above, Shell and BP were reduced to 21 and 14 per cent respectively.
The Storting accepted the committee’s recommendation. It voted to increase the state share in line with the approved production profile to 65 per cent at the expense of the foreign licensees. Statoil was therefore not affected.
In its budget recommendation no 8 (1990-1991) to the Storting, the standing committee on oil and industry proposed abolishing the different treatment of Norwegian and foreign licensees.
The sliding scale was later exercised again on Draugen. In recommendation no 197 (1994-1995) to the Storting, its energy and environment committee approved a new MPE proposal to increase the state’s holding from 65 to 73 per cent.[REMOVE]Fotnote: Energy and environment committee. (1995). Innstilling fra energi- og miljøkomiteen om utbygging og drift av Njordfunnet, fastsettelse av statlig eierandel for feltene Draugen og Brage samt orientering om Norsok-arbeidet. (Proposition no 54 to the Storting). Recommendation 197 (1994–1995) to the Storting. Downloaded from https://www.stortinget.no/no/Saker-og-publikasjoner/Stortingsforhandlinger/Lesevisning/?p=1994-95&paid=6&wid=aIb&psid=DIVL622.
Norwegian membership of the European Economic Area now meant that discriminating between foreign and Norwegian companies was no longer possible.
When the sliding scale was exercised in 1995, the SDFI therefore had to compensate the other licensees for past spending based on their percentage shares. The licensees agreed to this. The committee now accepted the government’s proposed increase in the state’s interest. For the sliding scale to take effect, however, plateau production had to rise again to 150 000 b/d.
That was unacceptable to the Centre Party, which accordingly demanded the insertion of a dissenting comment in the committee’s recommendation. According to the party’s members, an overall assessment – including considerations of long-term resource management and the decision to stabilise carbon dioxide emissions – meant that the Storting should reject government plans to raise output.
Members of the Socialist Left party also refused to support the proposal, but this secured the backing of a majority on the committee and later in the Storting.
The government is not the only player who can contribute to changes in licence interests. Holdings in attractive licences can be bought or sold like shares in normal companies. Known as farming in or out of the licence, such transactions may reflect a desire by companies to streamline their operations and to concentrate on certain geographical areas.
These changes in interests are important for improving recovery, since new licensees may see opportunities to extend the producing life of existing fields and reduce their costs. Holdings in licences can be swapped as well as traded, and changes in interests may also occur because licensees pull out, are taken over or merge with others.
Oil companies differ over the potential and profitability of oil and gas fields, and the original licensees may sell their interests to others with a more optimistic view.
The latter may take a different view of the reservoir, cost trends or the application of new technology which they believe will help maintain profitable production.
All farm ins/outs and interest swaps must be approved by the government.
A new company accordingly joined the existing licensees on Draugen in 1998, when Norsk Chevron acquired a 7.57 per cent holding from the government.
In addition to the Chevron stake, Statoil/the SDFI had 57.88 per cent at 31 December that year, Shell was down slightly to 16.2 per cent and BP held 18.36 per cent.
Three years later, Chevron and Texaco merged to form ChevronTexaco. The company’s name was changed back to Chevron in 2005, with Texaco as one of its brands.
An event elsewhere had consequences for the division of interests on Draugen. This began on 20 April 2010 with a gas blowout and subsequent explosion on the Deepwater Horizon drilling rig. Located on the Macondo field in the Gulf of Mexico, this event developed into a fire and caused the deaths of 11 people. Another 15-20 were injured. Oil flowed freely to the sea for 87 days, causing extensive environmental damage until the leak was stopped.
BP was operator on Macondo, and had to pay tens of billions of dollars in compensation after the disaster. To meet this bill, it was forced to sell off assets.
Norske Shell entered into an agreement in 2012 to acquire BP’s 18.36 per cent holding in Draugen, raising its share to 44.56 per cent. That left the division of interests at 31 December 2012, in addition to Shell, at Chevron with 7.56 per cent and Petoro – which secured the Statoil and SDFI holdings in 2002 – with 47.88.
Two years later, it was Chevron’s turn to pull out. Its stake in the Draugen licence was taken over by German-owned VNG Norge as part of a long-term commitment to NCS.
This company had made a conscious decision to strengthen its position on the Halten Bank. It already had interests in Njord and Hyme, and is operator for Pil og Bue (later named Fenja) – the biggest oil discovery on the NCS in 2014.
Royal Dutch Shell launched a USD 70 billion bid for all the shares in BG Group in 2015, seeking to expand at a time when low oil prices were put pressure on the petroleum profitability.
The previous wave of mergers in the international petroleum sector had been in the late 1990s, following the Asian economic crisis, with oil giant ExxonMobil as one of the outcomes. Shell had stood on the sidelines then, despite rumours that it might take over BP. Such acquisitions cost money, and Royal Dutch Shell now found that it needed capital.
Its interest in Draugen went on sale in March 2018, and who will be the buyer and take over as operator remained unclear at the time of writing. Shell’s stake in Gjøa was also put on the market in a sell-off which actually started in 2017 with holdings in several British fields.
During the autumn, the company sold a 9.92 per cent interest in Norway’s Polarled gas pipeline and three per cent of its 15.03 per cent stake in the Nyhamna gas plant.
In the latter case, however, Shell will remain responsible for running the facility in its role as technical service provider to operator Gassco. The Ormen Lange gas field in the Norwegian Sea is not part of these sales. Its operations organisation shares premises with the Draugen team at Råket in Kristiansund. It remains unclear whether and how this collaboration will continue in the future, but Norske Shell has promised to remain in Kristiansund for the time being.
Published August 8, 2018 • Updated October 19, 2018