One of the highest profile projects currently underway is operator Statoil’s Johan Sverdrup development, for which Kvaerner recently clinched a letter of intent (LoI) to build the field’s first two steel jackets.

However, with the operator now moving into the construction phase for what is the largest project on the Norwegian Continental Shelf (NCS) for 40 years and one of the biggest ever (behind Ekofisk and Statfjord), there are still some unanswered questions over the development. Kvaerner signed its LoI with the state-owned major to build the first two of four planned steel jackets for the Sverdrup field center in June in a deal worth approximately $486 million.

While another two steel jackets are still needed for the planned field hub, a political question mark remains to be settled over whether the entire Utsira High area, including Sverdrup, should use power from shore—something that the Norwegian government initially demanded.

Massive long-term project

The project itself will become Norway’s latest major offshore field center to exploit recoverable reserves estimated at between 1.8 Bboe and 2.9 Bboe (with the upper figure recently reduced from 3.6 Bboe). Although the onstream date also was deferred a year to 2019, Johan Sverdrup remains a massive long-term project with production expected to extend to 2050.

Over the past year the field partners have worked to understand this giant discovery, made in 2010 via the 16/2-6 well on the Avaldsnes prospect by Lundin Petroleum in Production License 501, followed by Statoil’s 2011 Aldous discovery in neighbouring PL 265. They were later confirmed as being the same field located in a water depth of 140 m (460 ft). In 2012 the decision was made to unitize and rename it after the 19th century Norwegian lawyer and political pioneer Johan Sverdrup, the liberal Prime Minister of Norway from 1884 to 1889.

Johan Sverdrup spans three licenses—PL265, PL501 and PL502—and encompasses 200 sq km (77 sq miles). Statoil and its partners Petoro (representing the Norwegian state), Lundin Petroleum, Maersk Oil and Det norske are aiming to finalize a plan for development and operation (PDO) by early 2015.

The first phase development is planned to produce between 315,000 boe/d and 380,000 boe/d via up to 50 production and injection wells in the Utsira High area of the Norwegian North Sea. The initial phase is based on a four-platform, bridge-linked field center with subsea installations. Surface facilities will comprise a wellhead and drilling platform in addition to separating riser, process and living quarters platforms supported by steel jackets.

Sverdrup also features two export lines: a 274-km (171-mile), 36-in. oil export line to the Mongstad terminal and a 165-km (103-mile), 18-in. gas export line to the Karsto gas terminal.

Total forecast capex is $16.75 billion to $20 billion.

Bumpy progress on NCS

Elsewhere on the NCS there also has been other less-than-smooth progress. A research program to pioneer subsea gas processing for a future phase of the deepwater Ormen Lange Field was dropped in April because the field partners felt it was uneconomic.

Work at a test plant in Nyhamna where a 14-m (46-ft) deep test pit was created to test subsea compressors was halted. Field operator Shell said the project was not economic based on the required capital investment—put at $410 million—and the expected production levels. “Significant new information both on reservoir behavior and technology developments will become available in the next few years and provide [the] basis to reevaluate new options,” said Odin Estensen, chairman of Shell’s Ormen Lange management committee, at the time.

Johan Castberg doubts

Another cost casualty is the Johan Castberg project, comprising the Skrugard and Havis fields which lie 240 km (150 miles) northwest of Hammerfest in the Norwegian Barents Sea. This is another project operated by Statoil, and the company wants to tap an estimated 400 MMbbl to 600 MMbbl of oil, with the crude to flow via a proposed 250-km (150-mile) pipeline to a new oil terminal at Veidnes in northern Norway.

In 2012 Sevan Marine received a contract to study the use of its circular-hulled design on the field, while the field partners also agreed on the new oil pipeline and reception terminal at Veidnes. Aker Solutions also won an early field concept study for Castberg.

However, at present the project’s schedule is uncertain. Citing a cut in the level of allowances within the Norwegian petroleum tax system, Øystein Michelsen, Statoil's executive vice president for Norwegian development and production, said in May that the tax changes had made future projects, particularly marginal fields that require new infrastructure, less attractive.

The operator also has confirmed that a year-long five-well exploration campaign at multiple reservoir depths has been disappointing, with fewer new oil resources proven in the Castberg area than expected.

Tax uncertainty

Michelsen also said there was uncertainty over the level of state tax support for energy infrastructure projects, placing a further question mark over Castberg's viability. Originally Statoil and its partners Eni and Petoro had planned to select a concept for the project during 2013, deliver a PDO this year and start production by 2018.

Wood Mackenzie recently examined the project and suggested it could still be viable after evaluating three separate development scenarios. One was the original concept, designed to accommodate up to 1 Bbbl of reserves using a semisubmersible platform, up to 38 development wells and the Veidnes oil export pipeline.

Wood Mackenzie’s study then highlighted what it said was a lower cost option using a lower specification semisubmersible production platform with approximately 30 development wells. The number of subsea templates was cut from 16 to 12.

Finally, it modeled an FPSO-based development with offshore loading instead of the oil export line. “Offloading offshore would remove the need for the expensive pipeline and onshore terminal development but would require export by specialist tankers. A semisub with offloading capabilities could also be used, but analogue developments globally suggest an FPSO [unit] could be preferred in this scenario given the requirement for storage,” said the consultancy.

Marginal economics

“Given the marginal economics of Johan Castberg, it is understood the partners are lobbying the government for a tax break,” Wood Mackenzie went on in its report. “This could be similar to the incentive granted to the Snøhvit development, which allowed faster depreciation over three years instead of the standard six.”

Wood Mackenzie suggests the FPSO development is the most likely Castberg scenario. “However, future exploration success and/or fiscal incentives could promote the viability of a pipeline development,” said James Webb, Wood Mackenzie's European upstream analyst.

Most recently, Statoil signaled that it would continue to evaluate options for Castberg until the summer of 2015, focusing on maturing the FPSO-based solution while also continuing to evaluate the semisub option in parallel. More effort will go into further evaluating the financial basis for an oil terminal at Veidnes and the export line against offshore oil loading, and further cost savings are to be sought while the nearby Drivis oil discovery will also be incorporated, it said. Statoil also added in the same press statement that government support practices for this type of infrastructure “also remain unclear.”

Pending project queue

Despite the relatively downbeat atmosphere on Johan Castberg, which has tended to dominate the news headlines, there are several other major new Norwegian fields still going ahead.

The frontier Aasta Hansteen deepwater project in the Barents Sea is progressing well, with the pioneering spar design to be the first ever fitted with a condensate storage tank. Also featuring the 480-km (300-km) Polarled gas export pipeline to Nyhamna, the project to exploit the Luva field is a typical pioneering project for Statoil. It will sit in 1,300 m (4,264 ft) of water, use steel catenary risers and cost an estimated $5.19 billion.

The Lundin Petroleum-operated Edvard Grieg development, meanwhile, comprises a cluster of discoveries, including the 1997 Luno find and the 2011 Tellus discovery.
Investment is forecast at $4.13 billion to provide a fixed platform to tap 186 MMboe of recoverable reserves from the field, which is scheduled to start production in late 2015. This will be the first major project operated by the Swedish company on the Norwegian Shelf, although not the first.

A steel jacket is under construction at the Kvaerner Verdal yard, while Kvaerner Stord is building the 20,800-mt topsides for the platform after a FEED study carried out by Aker Solutions. Development of Luno in PL338 is based on 15 production wells, according to the PDO submitted to the Norwegian Ministry for Petroleum and Energy by Lundin.

Fixed platform trend

Due onstream in 2017 is the Gina Krog project (formerly known as Dagny), which is planned for development via another fixed platform, an increasingly prevalent trend once more on the NCS.

It will produce an estimated 225 MMboe of recoverable reserves—16.6 Bcm (586 Bcf) of gas and 73 MMbbl of condensate. Gas will be exported to the Sleipner A platform 30 km (18.75 miles) away, with development approval granted in May last year.

Heerema is building the 16,500-mt jacket, and South Korea's DSME is building the 17,500 mt of topsides for the Gina Krog platform.

Another first-time operator on the NCS will be Det norske, with its development of the Ivar Aasen project. This will produce the Hanz and West Cable fields via another fixed platform, for which Wood Group Mustang won detailed engineering work in February 2013. Singapore's Sembcorp Marine is building the 13,700-mt platform topsides, while Italy’s Saipem is building the steel jacket.

Ivar Aasen will produce an estimated 143 MMboe, with capex forecast at $4.5 billion and the field due onstream late in 2016. Oil production will be exported 10 km (6.2 miles) for final processing at the Edvard Grieg platform, which will also supply electrical power for Aasen via seabed cables.

Martin Linge

Total is to operate another fixed platform offshore Norway, developing its Martin Linge Field in the northern North Sea. Discovered some 150 km (93 miles) west of Kollsnes, it will cost an estimated $4.5 billion to exploit 189 MMboe of recoverable reserves.

Due onstream in the fourth quarter of 2016, just four years after development approval, Martin Linge will produce the field via the fixed platform with the liquids produced and stored in a floating storage unit for offloading. Kvaerner is building the platform jacket, while Technip and Samsung are constructing the 25,000-mt platform topsides comprising process, utilities and living quarters.

In the short term, first oil will flow later this year from the BG Group-operated Knarr Oil Field. Discovered in 2008 and formerly known as Jordbaer (Strawberry), Knarr received development approval in June 2011. Estimated to cost around $2 billion to produce around 80 MMboe of recoverable reserves in total, the project will use a newbuild floating production system supplied by Teekay.

Also due onstream later this year is the relatively small Brynhild development, Lundin's first operated Norwegian development, which will exploit 80 MMboe of recoverable reserves via a two-well tieback to the Haewene Brim FPSO vessel stationed on the Pierce Field on the U.K. side of the border and operated by Bluewater on behalf of Shell. Lundin says Brynhild should achieve production of 50,000 boe/d by 2015.

Expenditure curve rising

With the above queue of projects at varying stages of development, Wood Mackenzie's view of the capex curve on the NCS is that it will continue to rise.

In real terms, it estimates capex, excluding decommissioning costs, to be $130 billion on Norwegian fields over the next five years. This is a 19% increase on the $109 billion spent during the last five-year period, it told E&P.

The spending cutbacks by some operators offshore Norway have not apparently yet dampened the pace of exploration, with a total of 33 wells drilled in the first six months of this year—five more than in the same period last year.

A total of 23 exploration and 10 appraisal wells were spudded, with 13 discoveries made. In the North Sea, seven small finds were made close to existing fields, three were made in the Norwegian Sea and another three in the Barents Sea.

In the Norwegian Sea the most significant was southwest of the Njord Field, where VNG Norge's 6406/12-3 S Pil well discovered 226 m (741 ft) of pay comprising a 135-m (442.8-ft) oil column with good reservoir flow. According to the Norwegian Petroleum Directorate, Pil’s recoverable reserves are put at 37 MMbbl to 132 MMbbl of oil and 2 Bcm to 6 Bcm (70 Bcf to 212 Bcf) of gas, making it the largest NCS discovery so far this year.