Statoil is targeting 2020 to deploy a subsea factory, or a fully-functioning process plant atop the sea floor, according to a technology briefing held by some of the Norwegian company’s top executives at its Houston headquarters in mid-November.
Image, right, of Gullfaks courtesy Statoil
“We are recognized for exploration, but I believe we are courageous in technology implementation and development,” Margareth Øvrum, executive vice president, technology, projects and drilling (TPD) said.
As Statoil’s projects go further offshore and occur in more frontier areas, the visiting team of executives acknowledged that the company’s technology needed to be able to handle the harsher environments as well.
“We’re going longer, deeper, colder,” Øvrum said.
Statoil also aims to increase production by 2.5 MMboe/d by 2020.
The company is investing in subsea technology because of its environmentally-friendly nature, and to increase profitability and production efficiency – particularly in recovery rates.
Øvrum, who called the factories “business critical,” pointed to the Gulf of Mexico (GOM), Tanzania and the Arctic as potential places for installations.
Statoil, which currently has 500 subsea wells, is building on its existing subsea toolbox for the technology necessary to advance its subsea factory. The company’s first foray into subsea was in 1997, with the South China Sea’s Lufeng field. At that time, Statoil turned to the space industry for the technology necessary for HPHT subsea materials during its first subsea installation project, a move the company echoed through its recent research partnership with NASA.
“As of 10-15 years ago, no one could imagine having a complete compressor on the sea floor,” Øvrum said. Statoil currently has two subsea gas compressors slated, both with 2015 start dates: Åsgard, which it called a world-first, and Gullfaks.
Faced with Åsgard’s reservoir decline, Øvrum said that the alternative to subsea compression would be to construct a new platform roughly the size of a soccer field with conventional surface compression.
Image, right, of Åsgard field courtesy Statoil
Åsgard’s platform is currently leveled to .3 degrees, which lead Øvrum to jokingly refer to her “baby” as “the best real estate in the whole Norwegian shelf.”
She explained that subsea compression will increase its production by 280 MMboe, which translates to a projected US$30 billion in revenue, making it a “roadmap” for all factories characterized as brownfield.
“Moving compression to the seabed gives both improved energy efficiency and lower costs compared with keeping it on a platform or on land,” Øvrum said at the time of Åsgard’s subsea compression announcement. “The closer to the well we compress the gas, the higher the efficiency and the production rates.”
Statoil announced in May 2012 that subsea compression on the Gullfaks South field added 22 MMboe to production and increased the sustainability of Gullfaks plateau production. Statoil firmly believes that subsea factories will open up many areas not currently available for production and increase recovery.
“Is it challenging? Of course it is, but I think we have proven ourselves,” Øvrum said. “I am sure we will succeed with our stepwise approach.”
Statoil is currently targeting a brownfield project for its first subsea factory; Øvrum said the company was still examining location options, but that it would “probably” be in the NCS. She could not yet identify if Statoil’s partnership with Rosneft would come into play.
“We have to test one thing at a time,” she said. “[The first subsea factory] could be far north of Norway, but we have to see.”
According to its website, Statoil has been developing the concept of subsea compression since 2008 in the Norwegian Continental Shelf (NCS), which Lars Høier, senior vice president, TPD research, development and innovation referred to as “[Statoil’s] laboratory.”
Increased recovery
As it currently stands, Statoil has an average worldwide recovery rate of 35%. Høier said that the company’s ambition is to boost its rate to 60%.
Labeling such an increased oil recovery (IOR) rate as a “tough ambition,” Høier explained that Statoil was developed IOR toolboxes to apply them to different fields.
He identified the GOM, in which Statoil has 240 licenses, as an area with huge potential for increased recovery, saying that Statoil looked to increase recovery from 10% to 20% through a better understanding of the reservoir, and by looking to water and gas injection.
“It is a key offshore area,” Høier said, adding that Statoil was “confident to increase recovery.”
“We are doing the same things in the NCS and implementing them in the GOM,” he said, pointing to seawater injection as one example.
According to Høier’s presentation, Statoil aims to determine specialized methods to optimize and produce, even in areas that other companies have passed on.
The deepwater Troll field offshore Bergen, he explained, was one such field previously “deemed unproduceable” by other operators” due to its shallow gas column. Through Statoil’s horizontal well technology breakthrough, the company now labels Troll as one of the largest oil fields on the Norwegian Continental Shelf.
New Statoil standard
Geir Tungesvik, senior vice president, TPD drilling and well, said that Statoil would be changing its standard subsea trees from horizontal (HXT) to vertical (VXT).
According to Statoil, VXT usage reduces well fatigue loading, increases well integrity and well control robustness, and reduces installation costs. Replacement, plugging and abandonment could be done through the use of a vessel as opposed to a rig, which Tungesvik identified as “the most expensive part of operations.”
The Johan Castberg field in the Norwegian Barents Sea will be the first field to use VXT.
Although both tree shapes offer their own respective sets of pros and cons, Tungesvik said that his team “saw we had to make up our minds to make our wells more efficient.”
To read OE's past coverage on the Åsgard project, see:
OE June 2013: Asgard subsea compression on track
OE June 2013: Asgard first comes a step closer
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