When it comes to mega natural gas projects that push the technology envelope, they don’t come much larger and more state of the art than the three projects on the Norwegian and Russian continental shelf described by Lars Hvalbye, StatoilHydro senior advisor, technology, at the Resource Development Council’s annual conference in Anchorage on Nov. 14.
StatoilHydro, which is about 62.5 percent owned by the Norwegian State, is the world’s largest offshore operator, followed in order by Shell, Petrobras, BP, ExxonMobil, Woodside Energy, Chevron, Total, Eni, Hess and ConocoPhillips.
The massive Ormen Lange field off Norway’s west coast and the Snohvit field in the Norwegian Barents Sea went into production in October, while the Shtokman mega gas field in the Russian Barents Sea is in the presanction phase.
The scope of each of these huge projects includes a long value chain extending from subsea well completions through to an appropriate transportation system for shipping product to market, Hvalbye said.
And the field designs are breaking new ground in terms of subsea production technology. The fields use subsea templates that can operate independently of water depth. The templates could connect to either an offshore platform or an onshore facility, Hvalbye said.
Ormen LangeThe Ormen Lange field lies on the Atlantic margin 90 miles offshore, in difficult terrain on the site of a submarine slide that occurred about 8,000 years ago. Subsea templates in a water depth of about 3,000 feet tie wells into a pipeline to an onshore plant. There are no offshore platforms. (This field has been operated by StatoilHydro, but as of Dec. 1, Shell will be the operator. See sidebar with this story.)
From the onshore plant a long subsea export gas pipeline crosses the North Sea from Norway to Easington on the east coast of England. From Easington the Ormen Lange gas flows into the UK gas grid. An offshore pipeline connection in the North Sea would also enable gas to be delivered into markets in continental Europe.
The subsea template design facilitates a phased field development, Hvalbye said. And StatoilHydro is testing a subsea compressor system for future maintenance of reservoir pressure as the field depletes.
Seabed preparation included excavating pipeline trenches through the rugged seabed, with the pipeline to shore having to negotiate a 30-degree slope. The onshore facility separates condensate and prepares sales gas. Gas production is 780 billion cubic feet per year, Hvalbye said.
“It is the largest industrial project ever done in Norway,” Hvalbye said. “The investment is approximately US$10 billion. … It’s a 14 tcf reserve project.”
The subsea pipeline that ships the sales gas to the United Kingdom was a major project in itself.
“It’s a million tons of steel in that pipeline,” Hvalbye said. “… It was a massive logistical challenge to do this, putting it all together.” Ten thousand sections of 42-inch and 48-inch pipeline were required, he said.
The entire Ormen Lange project, in which StatoilHydro partnered with Shell, Petoro, Dong Energy and ExxonMobil, took 10 years to complete.
SnohvitDevelopment of the US$7.5 billion StatoilHydro-operated Snohvit field in the Barents Sea north of the Arctic Circle was also a major technical achievement. The field has reserves of about 8 trillion cubic feet of natural gas.
“It was the first export facility for LNG in Norway and Europe,” Hvalbye said. “It was the first project in the Barents Sea region.”
Snohvit has faced the dual issues of implementing new technologies and shipping products to new markets — Snohvit gas is shipped as liquefied natural gas to Spain and the United States.
A subsea production system in water depths of 800 to 900 feet connects with a pipeline that carries gas from the field about 100 miles to an onshore LNG plant. As at Ormen Lange, there are no offshore structures at the water surface — mobile, floating drilling rigs drilled the wells.
Development challenges included the long distance to shore and laying the pipeline on a seabed scarred by ice. Construction in the Arctic required barging in pre-fabricated modules and dealing with issues such as freezing sea spray. Future challenges will include the need for compression facilities to maintain production as the field depletes, Hvalbye said.
The LNG plant for Snohvit sits on an island just outside the town of Hammerfest on the north coast of Norway. The plant exports both LNG and liquefied petroleum gas or LPG. The plant can also extract carbon dioxide from the field products, for reinjection into field reservoirs, Hvalbye said.
ShtokmanThe Shtokman gas field in the Russian Barents Sea is also situated in a remote offshore Arctic environment. Shtokman involves the additional challenge of working in a different business culture — it took several years to negotiate involvement in the project, Hvalbye said.
“Shtokman is again a large, large gas accumulation,” Hvalbye said.
Water depth is about 900 feet and, with gas reserves of about 100 tcf, the field is about seven times the size of Ormen Lange. StatoilHydro and Total are partnering with Gazprom, the main field owner, in developing the field.
“We are working with them on the first phase of this one and there will be two products, LNG and piped gas, to Europe,” Hvalbye said.
But, as at Snohvit, field development will not be easy in the remote Arctic environment — developing fields like these involves dealing with different types of ice, working in extreme weather in remote locations, coping with limited support and difficult logistics, and also having to deal with strict environmental conditions, Hvalbye said.
“We all know that field developments in the Arctic are challenging,” he said.