The Johan Sverdrup offshore field is located 160 km west of Stavanger, Norway. The field will have an estimated production peak of about 660,000 barrels of oil equivalents per day. To compare, today’s production on the Norwegian Continental Shelf is less than 2 million barrels. The first phase of the oil field development consists of four platforms.

For the first phase of the Johan Sverdrup offshore field development, the HVDC-system supplied by ABB has a capacity of 100 megawatts. The power link will operate at +/- 80 kilovolt and is scheduled for operation by year-end 2018.

AC or DC?

The decision on whether to opt for AC or DC supply from shore is often dictated by distance. AC cables have a certain capacitance per unit of length. The applied voltage generates so called reactive current due to the capacitance. If the cable is very long, eventually the generated reactive current will equal the rated current of the cable, and at that point no rating is left for useful active current.

Logically, the cable length must be kept significantly shorter than that limit. However, by skillful use of reactive compensation and/or reduced operating cable voltage against nominal voltage, one can achieve longer AC cable distances. With DC voltage the reactive current phenomena does not apply.

“Only about 10 years ago we thought that the limits for AC were 20 km, then it went to 50 and 100 and right now the longest distance from shore with AC is at the Martin Linge at 163 km,” said Borghild Lunde, senior vice president of oil, gas and chemicals for ABB in Norway. “The technology hasn’t changed much, but the understanding of limitations has developed quite a lot over the past 10 years.”

AC power is used most places in Norway for powering offshore installations at sites such as Martin Linge, Goliath and Ula. But when longer distances are reached, DC is the solution.

“AC is the preferred power source and at present all subsea distribution is, for now, AC because of the challenge of having a converter subsea, the equipment is simply not there,” Lunde said. “That will be for the future. The advantage with AC transmission is that the large DC/AC convertor is not required on the platform. The flipside is that the AC cables are more expensive, but AC is generally at the lower cost and that is why you would prefer it.”

History Of DC Power

Over the past 10 years the industry has been pushing the limits for AC—both in the subsea arena and topside—to see how far it can go and still have a stable, reliable system because that is the only option for subsea.

But DC is not new, ABB has been supplying DC offshore for some time. The first was Troll about 13 years ago. At that time, the main driver was that they had limited space to add gas turbines to drive new compressors. “There are different reasons to adopt DC power, not always distance; sometimes it can be space or even environmental issues,” Lunde added. “Lately adoption has been a combination of environmental issues and cost; the business cases behind some of the recent installations are very strong. You get a very stable system, with less equipment offshore.

“It is also a frame of mind for operators. They have traditionally used gas turbines on the platforms and they think that this is the way to do it. Using DC from shore is a different operational model, and it’s taken some time to mature. When you are familiar doing something a certain way it takes time to open up and consider other solutions.”

Eliminating Turbines

With AC not an option without the DC power to Sverdrup, operator Equinor would have needed gas turbines on the platform to generate the electricity. “If it is gas driven it takes space, it needs maintenance and it would come offline for service frequently,” Lunde said. “You can have a power outage with shore to platform cables, but it is generally a very stable system.”

The technology has been refined over 15 years to make it more compact. But more important than that is the greater understanding of how the system will behave on long step-outs driven by advanced simulating and modeling. Understanding how the system will behave when it is started, stopped and then restarted.

The first phase will go into operation in late 2019 but that is not the end of the project.

“The second phase is to step up production even more and not only for Johan Sverdrup,” Lunde said. “There are also other fields in the Utsira Height area. The second phase will also service other platforms; some of them are already in operation such as Edward Greig for Lundin and Aker BP’s Ivar Aasen. At that stage you could say that Johan Sverdrup will be an offshore hub for several fields.”

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