Statoil’s subsea process intervention challenge

As subsea production systems are entering a new era, Statoil is finding that designing, qualifying and installing the subsea factory is just the start—the future will require a new breed of vessel, Elaine Maslin explains.

The Åsgard subsea compression template was installed in June using the Saipem 700. Credit: Oyvind Hagen/ Statoil.Earlier this summer, one of the key building blocks to creating what will be the world’s first subsea compression project was installed in 300m (984ft) of water, about 200km offshore Norway.

By late 2014, the 74m-long, 45m-wide and 26m-high Åsgard subsea compression station frame will contain multiple modules.

Nearby will also be the manifold frame. Together, they will house 22 modules, including a two compressor modules, at 289-ton and 12x8x11m each.

The project, which will enable the recovery of an additional 280MMboe from the Midgard and Mikkel satellite reservoirs at Åsgard, has involved years of research and qualification.

Now, with first production approaching (early 2015), operator Statoil is addressing the next challenge: future intervention and maintenance needs on the field.

North Sea Shipping’s multipurpose vessel North Sea Giant will be used to install the modules into the Åsgard subsea frames.So far, Statoil’s conclusion is that the type of vessel it needs to remove and redeploy modules on Åsgard, particularly the compressor modules, is not currently available.

Statoil is not alone. As part of its own assessment of the potential future use of subsea compression on the Ormen Lange field, which came on stream in 900m (2853ft) water off Norway in 2007, Shell Norske also concluded current IMR (intervention, maintenance and repair) vessels would not meet requirements.

Speaking at Underwater Technology Conference 2013 (UTC) in Bergen in June, Raimund Bjordal, technical lead, subsea processing intervention, at Statoil, says: “We are moving towards a complete subsea factory and we need to take the next step, we need an intervention vessel that can handle what is needed for the subsea compression plant and also for future subsea templates.”

Jarand Rystad, managing partner, Rystad Energy, says that the time has already come, however.

“Now [existing] subsea installations are starting to mature, we are starting to see all of the problems we have already seen on the topsides for a number of years,” he told UTC attenees in Bergen.

The Åsgard subsea compression frame with its modules installed, illustration. Credit: Statoil“To be honest, the [subsea] industry has not been ready for this. It needs to move more from a greenfield industry to a maintenance industry, and that requires quite a different mindset.” An “interim solution” will be used for the installation of the compressor train modules on Åsgard next year, Bjordal says. Technip, the installation contractor, will use the DP3 North Sea Giant, built in 2011 with 2900sq m of deck space, a 400-ton crane and an over-the-side, subsea handling system designed specifically for the Åsgard project

For future intervention work—lifting and replacing modules—both Statoil and Shell have looked at the use of a monohull vessel, with a focus on deck space and a large moonpool. Shell has looked at existing construction and IMR vessels and their capacities, including the Skandi Achiever, the Island Constructor and the Viking Poseidon.

Mathias Owe, Ormen Lange subsea compression project manager, says the options are to agree to a contract for use of a newbuild, or conversion, with a vessel operator such as Subsea 7, or to build a new ship, potentially cooperating, or sharing it, with Statoil. In case it decides to use subsea compression on Ormen Lange, Shell has based a potential design (able to handle modules on the project) on the Subsea 7 vessel Seven Atlantic. It would be 133.4m long, 28m wide, able to carry up to six modules on deck, and incorporating a moonpool that could take 12m by 6m by 12m modules.

Statoil has done a similar exercise. It says the vessel it requires, described as a subsea processing intervention (SPI) vessel, would need to be able to work year round, in up to 4.5m waves, and lift modules of up to 400-ton and 15m-long by 12m-wide by 12m high.

It would also need to be able to execute subsea processing-related activities, including handling hydrocarbons, nitrogen gas, and MEG. This would require MEG and nitrogen pumping spreads, a reclaimed oil sump, and a cold flare system.

Potential options assessed by Statoil include a construction vessel with over-the-side handling system or a newbuild vessel with a large moonpool.

However, Statoil, which has plans to have a complete subsea factory by 2020, says that any new vessel would still work in tandem with a standard IMR vessel to ensure fast turnaround of a module replacement.

First, an IMR vessel would mobilize to the field to perform preparatory work, including displacing with MEG, any hydrocarbons within the module that needed to be removed.

During this time, the SPI vessel would mobilize from a base at Kristiansund, on the coast of Norway, with a replacement module.

Upon arrival in field, the SPI vessel will lift out the disconnected module and place it on a subsea “parking frame,” outside the compression station. The replacement module would then be installed into its slot in the compression station and commissioned.

Each module will be fitted using vertical connections to a cassette base frame within the subsea compression station and interconnected to other modules using sliding spools.

Raimund Bjordal, technical lead, subsea processing intervention, Statoil. Credit: UTC2013.The replacement module would be landed using a water-dampening system and would then be landed out on extended hydraulic cylinders. Final mating of the vertical connections is then performed by retracting cylinders, all controlled using an ROV at a hydraulic power panel.

Once the installation and commissioning is complete, the SPI vessel would recover the module, waiting to be refurbished, up to surface and then transport it back to Kristiansund.

If it is a compressor module, further work would be required before it could be removed, freeing it of hyrdocarbons and residual pressure before it is brought to surface.

The contents of the compression module would be displaced with MEG and then nitrogen, with the displaced MEG removed to the scrubber module. The compression module would then be lifted over to the subsea parking frame, while the new module is lowered into position and commissioned.

Any residual hydrocarbons in the compression module would be diluted with nitrogen and then flared off via a hose connected to the SPI vessel process system topside, until the contents no longer pose an explosion risk. During recovery through the water column, pressure in the compressor would be balanced by means of check valves, enabling the compressor to be at an ambient pressure before it is lifted on deck.

“Results of feasibility studies we’ve done show it is possible to do this from monohul vessels,” Bjordal says.

If such a vessel was also used by Shell on Ormen Lange, project economics would improve further. Statoil and Shell say they are “cooperating” on the issue, but it is not yet clear what the solution will be.

Shell, as Ormen Lange operator, has not yet concluded on the future infield compression solution. In addition to subsea compression, a conventional tension leg platform is also an alternative for future infield compression.

In case the subsea solution is chosen for Ormen Lange, Owe says that Shell would need a new vessel in 2020, at the earliest.

Bjordal concludes: “We think having a new service for subsea process intervention is a key enabler to make this Statoil subsea factory a success in the future.” OE

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