Lighting the way

Sending electricity to offshore installations from onshore has been proven on the Norwegian Continental Shelf, but cost is a factor. Elaine Maslin reports.

Total’s Martin Linge development. Image from Siemens.

Norway has a unique dilemma - the country is producing more electricity than it needs, predominantly through hydropower plants.

In a normal year, the country uses 120 terawatt (TW) hours, with production about the same. Ola Elvstuen, chairman, Energi og miljokomiteen, says there will be excess green energy in future. But, as a major offshore oil and gas producer, the country is also producing tonnes of CO2 from platforms and process plant each year.

According to Auke Lont, president and CEO of state-owned Statnett, which runs Norway’s onshore power grid, Norway’s offshore oil and gas production facilities account for some 25% of the country’s CO2 emissions. The situation, against a back drop of government climate agreements to reduce emissions to 52.9 million tonnes by 2013, and to 47 million by 2020, has put offshore emissions under the spotlight.

“For the petroleum sector to move on, we think it needs electrifying. Statoil’s vision is platforms on the bottom of the sea, where there is not much space for large gas turbines, so you need electricity,” Lont told a Centre Court session at Offshore Northern Seas 2014 (ONS) in Stavanger.

Powering platforms from onshore, via cables out to sea, has already been proven on the Norwegian Continental Shelf (NCS). However, the economics have so far struggled to make it work. In 2010, the operators of the Edvard Grieg, Ivar Aasen and Gina Grog fields started a study to look at a common power from shore solution for the fields. At the time, it concluded that it was technically feasible using high voltage direct current (HVDC), but too costly. Using alternating current (AC) was ruled out due to high transmission loss, according to Statoil’s Environmental Impact Assessment (EIA) for Johan Sverdrup, submitted in November 2014.

A proposal for a region-wide power from shore policy put forward by the Norwegian government has also proved not so easy. But, the discovery of Johan Sverdrup (originally known as Aldous/Avaldsnes) changed the baseline and the options were reassessed.

Last year, Norway’s government also “pushed through” a proposal to electrify all future developments on the Utsira High area, which includes Statoil’s Johan Sverdrup development, and the Gina Krog, Edvard Grieg, and Ivar Aasen developments, through power from shore, amounting to a 250MW power requirement. But, a date for when this should be implemented has yet to be agreed and there have been concerns that such a scheme would push up costs and delay the project.

Lont says Norway’s grid would be able to handle the 250MW requirement, in addition to an aluminum smelter being considered in the same area, onshore, but that the addition of the 500MW smelter would require grid investment, he added, which would have a longer lead time than field developments.

Statoil’s current concept for powering Johan Sverdrup, according to the EIA, is via a phased approach. Phase 1, due on stream in 2019, would be based on 200km HVDC subsea cables and a power module on the Johan Sverdrup riser platform. For future power requirements on Johan Sverdrup and the nearby Gina Krog, Edvard Grieg and Ivar Aasen developments, an offshore converter and distribution platform would be required, connected to the Johan Sverdrup facilities. ABB is doing the front-end engineering on the Johan Sverdrup HVDC (high voltage direct current) link to shore. A single connection to Johan Sverdrup has also been looked at.

Oistein Johannessen, VP communications, DPN, Statoil.

The technology is established, Svein Knudsen, vice president at ABB, told ONS centre court. “There are two ways to send power offshore (AC and DC),” Knudsen says. “But, there is always a limit for AC (due to transmission loss). If the power requirement is too big and the distance too far, the only solution is HVDC. The technology of DC is of course more complicated than traditional AC, it has more power electronics, but it has been used onshore and offshore since the early 1950s, so it is a mature technology that’s continuously developed upwards in power.”

AC can stretch to about 150km, depending on power requirements, Knudsen says. However, AC power is being stretched beyond 150km for Total’s Martin Linge development, which will use a 161km-long high voltage AC cable (145kV/55MW) from Kollsenes, Norway.

In 2005, power from shore via ABB’s “HVDC Light” link was launched on Troll A for pre-compression. ABB is now working to provide a further 100MW to Troll using its HVDC Light to power two compressor drive systems.

A 98km-long, 90kV AC cable was used to provide 40MW of power to the Gjøa platform, which was developed by Statoil and now run by GDF Suez. It started up in 2010 and was the first floating platform to be supplied with power from shore. ENI’s Goliat, also a floating facility, will get 75MW via a 105km, 123kV AC cable.

In 2013, BP’s Valhall field was the first 100% powered from shore offshore platform, via a nearly 300km, 150kV, HVDC cable from Lista, with conversion to AC at Valhall to provide 80MW.

BP had investigated power from shore in 2000, initially as a regional solution, supporting UK and Norwegian North Sea platforms. But, the project resulted in just Valhall having power from shore. “We have been involved for 13-14 years,” Olav Fjellsa, director of communications, BP Norge said at ONS. “The first estimates were really very high and there was a large debate to drive down costs to get the cost we ended up with. The Valhall power from shore decision was based on economics.”

Statoil had also already decided to electrify Johan Sverdrup from day one, said Oistein Johannessen, VP communications, DPN, Statoil. “The (additional) decision was about how to provide energy to other fields in the Utsira region.” He said Statoil looked at electrification as a technology concept for all of its fields, taking into considering the broader cost benefit, as well as the price of gas and electricity. The final decision on how Johan Sverdrup, and neighboring fields, is powered is due to be made early this year.

For Knudsen, power from shore is established, not just in Norway, and efficient. Knudsen cites the Saudi Aramco’s Safaniyah project, powered by 230kV and 115vK cables from Nexans. “This is not because they have a parliament which says it (should do this),” Knudsen says. “We shouldn’t forget the number of wind farms out in the North Sea from Germany driven by the same technology.”

According to Knudsen, power from shore energy efficiency is about 90%. In comparison, he says, offshore gas turbine efficiency is about 25-35%, or 35-40% using heat recovery technologies. An added benefit is that it can reduce offshore man-power requirements because you no longer need to manage rotating equipment, as well as reducing noise.

Hans Erik Horn, director, Energi Norway.

A survey commissioned by Energi Norway and Norwegian Petroleum Directorate found that Valhall, Troll and Gjøa all experienced improved economic performance from power, improved reliability, plus reduction in noise and vibration and reduced maintenance, which improved economics, by using power form shore,

So why was a regional approach such a problem? Hans Erik Horn, director Energi Norway, says the debate around a regional power from shore scheme may have been complicated by the complexity of licensees in the Utsira High. There has also been a lot of doubt around costs, and project timing.

Another issue is that there is no system architect, he said at ONS. “If it had been onshore, an optimal network would have been designed,” Horn says. “But no such system architect exists offshore and everyone suggests their own, which means a suboptimal system for each. A process needs to be carried to find one (a system architect).”

“If we are to reach our goals, there is no doubt that to a large degree new installations must get power from land,” Elvstuen says. He suggests, to overcome the hurdles, incentives might be needed, and or CO2 tax increased.

For Knudsen, there is room for improvement in the technology itself, by duplicating subsystems, such as cooling, and cabling, to offer higher reliability. “Use industrial standards, get contractors to suggest solutions, and there is no need to use gold-plated nuts if you do not need them,” he adds.

“In the future I would like might be space for subsea equipment synergies with offshore wind,” Knudsen says, also suggesting a power link between Norway to the UK.

Johannessen agrees. An ultimate goal would be a linked North Sea power system, collaborating with offshore wind projects, he says. “If we are able to find a cost efficient solution for infrastructure that doesn’t jeopardize power supply for different regions anything can happen.”

Case study - Gjøa

Gjøa was developed and started up by Statoil in 2010, at which point GDF Suez took over. Gjøa was discovered in 1989, 45km offshore Norway, and developed using a semisubmersible production platform and five subsea templates, with power from shore.

Ola Elvstuen, chairman, Energi og miljokomiteen.

“It was the first floating platform with power from shore,” Hilde Adland, head of operations, GDF Suez E&P Norge told delegates at ONS 2014. “(Power from shore at) Gjøa has resulted in reducing emissions and a better working environment, with regularity and reduced maintenance.”

The power comes from Mongstadt via a subsea cable, including 98.5km of static cable and 1.5km of dynamic cable up to the floater. “Due to the distance from Gjøa to Mongstadt we were able to use AC. If it was longer, then the requirement would have been DC and things would have looked quite different. We would have needed transformers from DC to AC at Gjøa.”

“The project meant the development of dynamic cables, by Statoil, during the project phase. Without power from shore, Gjøa would have needed four N2520 gas turbines. It still needs one, for gas export, but waste heat recovery is used on this unit.

“When we started it, there was uncertainty about how much downtime there would be due to power from shore. Nearly four years in and operationally, we have had a very good experience with reliability. We have had two shutdowns due to power from shore. The first one we were warned up front about. This was for testing at Mongstadt. The other was due to thunder and lightning onshore and we were able to have an immediate re-start.

The project had planned for 30-40MW power. “After start-up we realized we would be able to produce up to 65MW giving us future capacity,” Adland says. “The biggest risk is if we have failure on the power cable. That could give a relatively long shut down.”