All subsea options

Most of the building blocks are in place for the all-subsea solution. But do they offer an attractive proposition? Elaine Maslin looks at DNV GL’s current thinking.

Operations during the Åsgard subsea compression project installation campaign this year. Image from Statoil.

Last month, a huge milestone in the history of subsea production was reached. Statoil, operator on the Norwegian Sea Åsgard development, brought the world’s first subsea gas compression system online, a project that will help boost recovery from the Mikkel and Midgard fields by some 306 MMboe.

Statoil hails subsea compression as one of the key stepping stones towards the industry being able to create an all-subsea production system – i.e. one without topsides – enabling the industry to move into harsher, deeper and more remote environments while boosting recovery rates.

There are strong drivers to make this technology work. According to DNV GL, although over 50% of the giant oil discoveries in the last six years are in waters deeper than 2000m, only a handful have been brought onstream.

But, while Statoil has been boldly going where others have yet to tread, with its subsea factory concept, launched in 2010, is the technology for a full subsea system ready yet, how viable and economical is it and where does it offer the greatest benefits?

DNV GL decided to find out. Its study, All Subsea – Creating value from subsea processing, published during the Underwater Technology Conference earlier this year, compares a benchmark FPSO set-up with a hypothetical all-subsea pipeline to shore field development. However, instead of making a direct comparison between the two alternatives, it moves the various main processing components to the seabed in nine steps; multiphase boosting, heating of pipelines, subsea water injection, subsea separation, subsea compression, power transmission from shore, power distribution and control, and, finally, oil export by pipeline (eliminating the FPSO).

As a result of its work, DNV GL says subsea processing is now a real alternative to conventional solutions. But, it is brownfield projects that currently offer the best business cases for this technology, at least in the short-term.

“For brownfield projects, the various technologies may be used alone or in combination with other technologies. In contrast, an all-subsea solution has more limited applicability,” DNV GL says. “The most likely future all-subsea applications are oil and gas field developments in mature geographies, gas discoveries that only a few years ago were assumed to be developed with subsea compression to onshore LNG liquefaction are instead moving in the direction of floating liquefaction, FLNG.”

DNV GL says that while some of the technology steps it looked at were clearly enhancing or enabling, other parts of the concept “severely limit its overall applicability.” Subsea compression for gas export, for example, saves risers, however, the subsea equipment is expensive and availability is uncertain relative to topside solutions, the report says. Subsea power from shore, using HVAC, is limited to 200km step out and other options are immature, it says, and have limitations around equipment size and control. Subsea power equipment would move less reliable but critical components into a hostile environment and export by pipeline is expensive for long distances, unless volumes are large.

In theory, deepwater projects should favor the all-subsea solution, due to the sheer size and multi-decade revenue streams they offer creating some of the most cost-effective barrels available. But, deepwater capex, especially in today’s low oil price environment, could make such projects prohibitive.

There could be ways to get around some of these issues, such as having stepped step outs from shore, say, placing the field center 100km from shore, with a 100km step out from it, to reduce weight, complexity and cost of separation and power equipment. Building projects on a hub basis, that facilitate future tie-ins would also bring flexibility to the development, the report suggests.

Principal researcher and lead author of the paper, Tore Kuhnle says brownfield applications offer the best short-term application for subsea processing technologies. “The technology is there within certain limits. Engineers have done their job. Now it is how you can capitalize them, i.e. coming to commercial agreements around putting different oil grades in to existing pipelines. In brownfield applications, you need to be able to make modifications on the vessel offshore to put on a power module, for example. It is not a technology risk anymore, it is building the case in this environment.”

In the short-term, for greenfield projects, the best candidates are mature-area, midsize oilfields, rather extreme deep water, long-range fields, Kuhnle says.

DNV GL is planning to follow-up this report with a further study, which will address systems approaches to subsea processing. Despite the business case for all-subsea being limited, DNV GL thinks that all the pieces of the puzzle are there and that the industry needs to address the next step – setting out the final requirements for the all subsea case and how to qualify it as a system, not just at the component level.