Subsea technology is set to reach new depths in the North Sea by 2007 when Norsk Hydro aims to have the giant Ormen Lange gas field onstream. Under consideration is a lengthy subsea tie-back to shore, involving a steep climb up a subterranean cliff face.

Norsk Hydro recently suggested its preferred development scenario for Ormen Lange: installing a deepwater subsea production center with two main export pipelines carrying gas 75 miles (120 km) directly back to the beach - over some of the worst subsea terrain in the northern hemisphere.
Second in size only to the huge Troll gas field, Ormen Lange was discovered in 1997 when the 6305/5-1 exploration well drilled 87.5 miles (140 km) off Kristiansund.

Subsequent appraisal drilling further defined the extent of the find, which straddles four blocks, 6305/4,5, 7 and 8, and three production licenses, PL 208, 209 and 250. Licenses 208 and 209 were awarded in 1996 and PL 250 in 1999.

Saipem's Scarabeo 5 semisub completed a fifth appraisal on the field earlier this year. It drilled the Norwegian block 6305/4-1 well to a target depth of 9,760 ft (2,975 m) and proved up the estimated reserves base of around 14.124 Tcf (400 Bcm) of gas.

Although Hydro is operator of the field, it has to consider the views of its license partners, which include Shell, BP, Statoil and ExxonMobil, as well as Petoro, the company that now controls Norwegian state offshore interests.

Already, BP and ExxonMobil have shown some dismay about how Hydro publicized its preferred solution before finalizing it with field partners.

There is still some debate about whether a large offshore floating production facility is the best technical solution to develop Ormen Lange. Both BP and ExxonMobil have indicated that publicizing the direct-to-shore option limits their freedom of choice; both have filed letters of complaint to Hydro's Chief Executive Eivend Reiten.

Interestingly, Shell, which is due to take over as operator of Ormen Lange once it has come onstream, did not comment on Hydro's announcement.

Hydro defended its decision to make its preference public by saying that it feared the information would be leaked. A Hydro spokesman explains that although the company was due to submit its views to partners in confidence, it was also scheduling a briefing where it would have been very difficult to keep its own views confidential, "...knowing that it would possibly leak anyway."

Since Hydro's preference is now public knowledge, a wider debate likely will take place. "Onshore processing is as profitable as a solely offshore development," said Reiten of his company's choice. "Besides the financial aspect, our recommendation is also based on a total evaluation of technology, health, environment, safety and social issues."

Options

Apart from exporting gas from a subsea installation spread directly to the shore, another alternative is a major offshore production facility. Hydro says this means it is unlikely Ormen Lange gas would be landed in Norway. Alternatively, a smaller scale production platform could be selected, with main processing onshore.

But as longer-distance subsea tie-backs of gas fields are becoming possible worldwide, fixed platform solutions are looking less likely.

Building an offshore floating production facility entails a major cost outlay, plus the added complexity of a deepwater mooring system and production risers. All of this would have to be achieved at a location well known for its difficult seabed soil conditions.

ABB already has suggested a design for a single-column, spar-type structure, which might provide a fixed offshore processing facility for Ormen Lange gas. But despite all the publicity generated for the direct-to-shore option, a spokesman for Hydro stresses, "We have not chosen the concept yet."

In fact, the current project operator has promised a twin-track approach to further concept development. "Until a final decision has been made, Norsk Hydro will continue developing the two alternative concepts in parallel, in order to avoid any delay in the concept selection phase," the company promises.
On the plus side, the floating production facility would offer the advantage of offshore gas processing, and allow gas to be exported - via two 28- or 30-in. pipelines - directly to a market.

For Ormen Lange, this could mean using the Sleipner or Draupner installations further south. From either of these platforms, Ormen Lange gas could be taken via a new 42-in. trunk line to a chosen market.
Already Hydro is considering a new trunk line to a southern UK landing point, possibly the Bacton terminal. Estimates by Hydro suggest this 42-in. trunk line could carry up to 2.118 Bcf/d (60 MMcm/d) of gas.

This suggested line could cost between US $800 million and $934 million (NKr 6-7 billion) Hydro suggests, and would stretch a distance of 375 miles (600 km) if it were to land in the UK.

"A new Norway/United Kingdom pipeline can be completed by the end of 2006, starting at Sleipner or Draupner," Hydro suggests. "The preferred landing site will be determined by the end of 2002."
Another option is to take Ormen Lange gas through existing pipelines to the UK, or to mainland Europe. There are several choices:

• Europipe I, a 412-mile (660-km), 40- and 42-in. system from Draupner landing at Dortmund in Germany, with a capacity for 459 Bcf/y (13 Bcm/y);
• Europipe II, a 406-mile (650-km), 40- and 42-in. line from the Norwegian Karstø terminal via Draupner landing at Dortmund in Germany, with a capacity for 741 Bcf/y (21 Bcm/y);
• Norpipe, a 275-mile (440-km), 36-in. line from Draupner via Ekofisk to Emden, also in Germany, with a capacity of 494 Bcf/y (14 Bcm/y);
• Franpipe, a 525-mile (840-km), 42-in. line from the Draupner E riser platform to Dunkirk in France, with a capacity for 529 Bcf/y (15 Bcm/y); and
• Norway's Zeepipe, a 508-mile (814-km), 30- to 40-in. line from the Kollsnes terminal in Norway via Sleipner East to Zeebrugge in Belgium, with a capacity for 459 Bcf/y (13 Bcm/y).

Any one of these main gas trunk lines could serve Ormen Lange.

Reserves

Ormen Lange is estimated to contain recoverable reserves of between 13.242 Tcf and 14.124 Tcf (375 Bcm and 400 Bcm) of gas, making it the second biggest gas find on the Norwegian Continental Shelf to date after Troll (which was estimated to contain between 42.374 Tcf and 45.905 Tcf (1,200 Bcm and 1,300 Bcm).

And just for the record, Ormen Lange also lays claim to another milestone as the deepest proposed development offshore Norway so far, since the water depths at the field location range between 2,624 ft and 3,280 ft (800 m and 1,000 m).

In order to tap this huge Norwegian Sea resource, between 75 miles and 87.5 miles (120 km and 140 km) off Kristiansund in mid-Norway, Hydro wants to see two new 28-in. or 30-in. pipelines bringing production directly to an onshore processing plant.

At the plant - which Hydro suggested could be built at Nyhamna in Aukra municipality in mid-Norway - Ormen Lange gas could be processed to sales quality and from there, re-exported via a 42-in. trunk line to one or several markets.

Those markets could either be in the UK and possibly Europe.

But first, Hydro and its development partners have to find a way to install those 28-in. or even 30-in. export pipelines from the field location to an onshore processing plant, along a seabed which has staggeringly spectacular subsurface topography.

The reason is geological: About 8,000 years ago, the seabed at the field location in the Storegga area underwent substantial change during a subterranean slide. That resulted in the creation of a very uneven seabed. Ormen Lange is at the base of that area, now known as the Storegga slide, at depths of around 2,952 ft (900 m). The gas cannot be reached from outside the slide area.
"The Storegga slide seabed is undulating, with local elevations of up to approximately 50 m to 60 m (164 ft to 197 ft) above seabed level," Hydro notes. Furthermore, the uneven seabed soil varies between hard and soft.

Any new export pipeline from the subsea field location has to traverse this seascape and rise up the seabed escarpment to a higher plane - a height of at least 1,640 ft (500 m). Effectively, it means building a pipeline up a subsea cliff face.

"A pipeline route out of the slide area and up the escarpment was identified in early 2002. The planning and design of a reliable and safe pipeline route proved to be a significant feat of engineering," Hydro says.

Now that Hydro knows where it wants the pipeline to go from the field location, the next challenge is to find an offshore pipeline contractor willing to handle the risk, one which the likes of Allseas, Saipem and European Marine Contractors (EMC) probably will be best placed to compete for. Pipeline installation up the gradient of the Storegga slide will require a J-lay technique; once any installation barge moves into shallower water, more conventional pipeline techniques can be applied.

Engineering the pipeline for the deepwater environment will present a second major challenge. At the field, the seabed temperature is 0°C in the first 984 ft to 1,312 ft (300 m to 400 m) of water column above the field location.

Clearly, flow assurance is going to be a very live issue for the partners. "This will make special demands on multiphase flow technology," Hydro says.

Furthermore, the weather at the field location is extremely hostile. "High waves, a lot of wind and strong ocean currents," says Hydro.

Surveying

Efforts to study the Storegga area have been made since the early 1990s, and Hydro has been acquiring data to survey potential pipeline routes for some time. Thales Geosolutions last year installed survey equipment along potential routes through its environmental and metocean services division, which mobilized the MV Guard Alerta vessel to deploy current meters in the field area and beyond, in water depths ranging between 164 ft and 1,574 ft (50 m and 480 m). These survey beacons carry temperature, pressure and conductivity meters. In three locations, RDI Instruments' acoustic Doppler current profilers have been used to collect data on currents throughout the water column. Wave height measurements at various points along proposed routes at water depths between 229 ft and 1,574 ft (70 m and 480 m) also have been taken with Datawell directional waverider instruments.

Whatever the environmental challenges, Hydro appears confident it can overcome them after encountering similarly hostile conditions on its Njord, Visund and Troll Oil projects, also offshore Norway.
Hydro aims to finalize the concept decision for Ormen Lange by next month. "Planning and development of this field is one of the most challenging assignments any oil company has tackled - not just off Norway, but in a global context," said Hydro.

Hydro and its partners have set Dec. 19 as the deadline for final concept selection. By then, BP and ExxonMobil, plus the other license holders, should all be on one side. But having nominated a long subsea tie-back to shore as its preferred choice, it might take some persuading to convince Hydro to do otherwise.

Whatever the final decision, forward planning for the field involves submitting a Plan for Development and Operation to the Norwegian Petroleum Directorate and government for approval towards the end of 2003.

Offshore and onshore construction work is scheduled to start in 2004.
Major contracts for work on Ormen Lange are likely in 2004 for long lead items such as processing equipment - whether for on or offshore service - and for steel.

Others items like line pipe will be put out to the market for contract bids later in the project schedule.
Hydro aims to have Ormen Lange onstream by October 2007.

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