ABB & Subsea Power discuss plan to put 100 megawatts of power on the seabed
September 27, 2017
ABB discusses progress on the Subsea Power JIP, a plan to put 100 MW of power on the seabed by 2019. Andrew Dykes reports
Electrical engineers are used to big numbers. While it may be no small feat to move hundreds, even thousands of megawatts around from power plants to substations and load centres, it would be difficult to argue that any of it is out of the ordinary. Doing so on the seabed, however, is another feat altogether.
In 2012, as part of its vision for the “subsea factory” of the future, Norwegian NOC Statoil launched a study to investigate how enough power could be supplied to the seabed to make that a reality. Given ABB’s expertise in subsea power – it introduced the world’s first subsea transformer in 1999 – it was a natural fit for the project, and together with operators Total and Chevron, formed the Statoil-led Subsea Power joint industry project (JIP) in early 2013.
At present, the majority of subsea AC power is provided from a platform or topside, and carried to equipment via multiple cables. It frequently means multiple topsides are needed, at considerable cost, all of which must be located within around 50 km of the infrastructure itself. Siting power infrastructure on the seabed itself would therefore offer big reductions on topside capex and opex in terms of staffing and maintaining them. It is here that the big numbers emerge. Statoil’s goal was to transmit 100 MW of power over distances of up to 600km, and depths of up to 3,000m. Those installations also had to be reliable enough to function for 30 years with minimal interventions. To achieve this, the US$100 million project would see the design of entirely new equipment, including medium-voltage switchgear, variable speed drives (VSDs) as well as associated control systems and low-voltage distribution. Yet in doing so, Statoil said at the time that it expected to be able to realise around US$500 million in capex savings for one target project alone, by allowing the operator to link eight loads via a single cable, at distances of around 200 km.
“The project has two main phases,” said ABB’s vice president of oil, gas & chemicals for Norway, Jan Bugge. “The first was to bring the technology to [technology readiness level] TRL 2. Having started in 2013, we focused on the concept and technology development of components, so that we could mature the concept – that stage we passed in April 2015.”
With that milestone behind them, the group is now is now working on the formal qualification of the components that go into the various drives, switchgears and assemblies, before the overall system is put through its paces. If all goes to plan, these systems should reach TRL 4 by 2019.
Handling the pressure The overall system ABB has designed works with an input of 16/50/60 Hz, and typical transmission voltages of 36-145 kV. For distances above 250 km and up to the 600 km desired, the low 16.7Hz frequency is used to ensure transmission. As stated, the system has three main areas of innovation: VSDs, switchgear and controls/low-voltage distribution. Each component not only needs to be pressure-resistant and thermally efficient – using natural convection to cool VSDs housed in oil-filled, pressure-compensated containers, for example, is not the same as cooling drive units onshore – but also reliable enough to run for years at a time. These high-power units are “at the forefront of technology,” Bugge said.
“They have to have redundancies and monitoring to a totally different level from topsides,” he added. “These are the frontiers in a way – understanding the physics of thermal and electrical issues, pressure-compensated designs and high reliability to minimise intervention.”
Understanding the thermal and electrical properties of this equipment at pressure is a challenge in itself. ABB is already using accelerated testing to simulate a 30-year working life – processes which then inform component choice and design. “We’re making a lot of, I would say, ground-breaking designs to make sure we get that reliability, because that’s the biggest aspect of this,” he continued. “It’s a bit like sending a satellite up, once it’s up there it’s very hard to get at – the same when you put things on the seabed. There are no service engineers at 3,000m.”
Achieving reliability over that lifespan also means adding multiple levels of redundancy. “You not only typically have several compressor trains, but we also have redundancy in our own equipment – redundant A-side/B-side controls and low-voltage distribution, as well as in the drive,” Bugge added. The drive units too are comprised of a cell-based structure, allowing the system to bypass specific cells if anything malfunctions or fails. This flexibility also allows variable levels of output. To drive high-power equipment such as compressors, two or three VSD units can be paralleled to drive 12 or 18 MVA loads. By mounting these on a subsea frame, designers have also been able to save on connectors, using just one 3-phase input and output for the combined VSD. The control and low-voltage distribution systems have similar flexibility. Standard oil-filled subsea control modules (SCMs) and nitrogen-filled, low-voltage subsea electronic modules (SEMs) have been used to ensure a familiar form and allow deployment via moon-pools, but each module is also individually retrievable and offers dual-redundancy.
Next steps With the fundamentals understood, the first prototype units are now being built. “We have built the first drive, it has been demonstrated to our key partners, and it was demonstrated to our partners in June in Turgi, Switzerland, where our medium-voltage drive factory is,” Bugge explained. “The next milestone will be in November, when the first shallow-water tests of the 65-tonne drive unit will be conducted at our facility in Vaasa, Finland. Here, power will be circulated from the grid, through the unit and back as part of a “power in the loop” test. This will be run for several weeks, before the project partners meet again for a workshop on the results. In 2018, the project moves into the home straight, with several 3,000-hour tests planned, in order to qualify the units to the desired TRL 4. These include a 3,000-hour pressure vessel tests to simulate the operating conditions of power cells at 300 bar, emulating 3,000m water depth. ABB aims to complete these by around April 2018. The project will culminate towards the end of the year with a system test. This will involve two drives, one switchgear and associated control modules – representing a complete subsea transmission system – tested in shallow water, again over 3,000 hours. If all runs smoothly, this should conclude the JIP with TRL-4 proven technology by 2019. Although the geographical spread of the project partners infers that the initial deployments of the technology will most likely be in the Norwegian Continental Shelf (NCS), North Sea or Gulf of Mexico, Bugge says that the technology will be equally applicable throughout the offshore market, including regions like East Asia and Australia. Having been under development for almost five years, the scope of what the JIP has already achieved is not small. Moreover, Bugge says that the potential gains from high-power subsea electrification have ensured backing from operators, even though low prices had made times tough. “This is in a way a game-changer which allows them to put new technology to use, and which will help them to produce more efficiently,” he noted.
2019 is still a way away, and there are many tests left to run. But with the future of offshore oil and gas production undoubtedly lying in fully electrified subsea facilities, the achievements of ABB and its partners over the next few years are certain to have profound implications for the future of the technology, and of the industry.