Shore power reduces emissions

Norway sees huge environmental gains in terms of sharply reduced CO₂ and NO_x emissions if it could supply electric power to offshore platforms from onshore bases, but the economics just won’t cooperate in most cases.

The basics are simple. Offshore power generators on platforms work at up to 25% efficiency and produce a lot of emissions in the process. Onshore combined-cycle plants, which use fuel for primary burning and use the heat from that process for additional power generation work at up to 80% efficiency.

Unfortunately, the latest report from the Norwegian Petroleum Directorate and other state agencies calculates the cost of projects to convert existing offshore production platforms from platform power to shore power at a minimum US $295.23 per tonne (metric ton) of CO₂ for the Southern North Sea. The cost in the Northern North Sea would be closer to $878.97 per tonne, according to a Reuters report. That’s a substantial cost when a large field can produce 300,000 tons of CO₂ a year. Conversion costs much more than the combined emissions taxes now in effect for CO₂ and NO_x. A company can buy a credit for a tonne of CO₂ on the European Union exchange for about $35.

Offshore installations

Offshore Norway had 30 fields that regularly used power for processing at the end of 2006. The other 22 fields were linked to those main hubs.

The government must balance the cost of converting those existing fields with the fact that the nation’s petroleum industry generates a fourth of the nation’s greenhouse gases. Even if the industry and the government did undertake the project for existing facilities, it would be 2015 at the earliest before it would reach platforms in the Norwegian Sea.

Another stumbling block stands in the way. Norway simply doesn’t have enough shore power to supply its offshore industry. New plants would have to be built or it would have to import more electricity. It has used up the electricity potential of its waterways, so gas would have to power the new plants, and that would mean more shore emissions. If the nation could handle the project, the result would be a substantial net reduction in emissions.

In spite of the high costs and supply obstacles, conversions of existing platforms to shore power are taking place, new installations using electricity from shore are in the planning stages and the industry is looking at other alternatives.

Alternatives

One of those alternatives comes from technology developed by the Norwegian University of Science and Technology (NTNU) and the Foundation for Scientific and Industrial Research at the Norwegian Institute of Technology (SINTEF).

They reason, if a combined-cycle plant is more efficient onshore, it should be more efficient offshore. Using Alstom Power equipment, combined-cycle installations at Snorre B, Oseberg field center and Eldfisk emit 25 to 30% less CO₂ and NO_x per kilowatt-hour of electricity produced than most traditional power plants offshore Norway, an emissions reduction equivalent to the elimination of 100,000 automobiles, according to NTNU’s Gemini magazine.

Under another alternative, Statoil is investigating the potential of an offshore floating wind farm to provide electricity in remote areas of offshore Norway.

Troll

The first and only installation of a shore-power electricity system in an existing field is in Norwegian waters. In this case, the field was Troll, an installation with a capacity of 353 MMcf/d of gas that supplied 40% of Norway’s natural gas. As the reservoir pressure declined Statoil found it needed more compression on the Troll A platform to keep the gas moving.

It set up a precompression plan in 2002 with completion set for late 2005. Conventional gas turbines would have put out some 230,000 tonnes of CO₂ and 230 tonnes of NO_x a year.

Statoil opted for $185 million for compression equipment and $85 million for an electric drive system from ABB in a synergistic system.

Troll produces natural gas used by the Kollsnes processing plant which condensate, gas and electricity.

Some of that AC electricity goes into ABB’s HVDC (high-voltage DC) Light rectifier system which converts it to DC power. DC power isn’t nearly as vulnerable to line losses as AC power. The power travels through an HVDC Light subsea cable to another rectifier on the platform which reconverts two 41-MW installations to AC to run the compressors.

The systems had been used previously onshore, but this was the first offshore conversion.

Valhall

Norway already approved the next HVDC installation for BP’s Valhall field where it will save the company millions of dollars and cut offshore CO₂ emissions by 300,000 tonnes and NO_x emissions by 250 tonnes a year.

The installation is one of the farthest from land at 181 miles (292 km). It includes five bridge-linked platforms and wellhead platforms for Valhall North, Valhall South and Hod, each about 3.7 miles (6 km) from the main complex. Since the area is compacting and lowering the level of the platforms by almost 10 in. (25 cm) a year, BP plans to replace the compression and production platform and the living quarters platform in 2009.

Valhall is BP’s field of the future in the North Sea. Even though it’s 25 years old, the company would like to keep it going for another 40 years, but it will need 78 MW of power when it goes onstream in 2009.

BP estimated it will save $44 million, because it won’t have to install generating equipment on the platform. It also will lower operating and maintenance costs by some $7 million a year, not only from the elimination of the generating equipment but from the cost of crews needed to maintain that equipment.

In addition, it will be able to sell the natural gas it otherwise would have to use to power the generating equipment. Those revenues, at current gas prices, will exceed the cost of importing electricity from the mainland, according to ABB.

The company also cites lower risk of fire and explosion and less noise and vibration from the HVD converter than from the traditional equipment.

In this case, AC power is converted to DC from the Elkem sub-station at Lista on Norway’s southwestern coast and transmitted by HVDC Light cable to the platform for reconversion to AC. The rectifier plant on the platform remains under pressure at all times to prevent natural gas from entering. If the detection system discovers gas, it can shut down the system.

Gjøa

The third project was approved earlier this year, but this is a little different. In this case, the Gjøa field is only 61 miles (98 km) off the Norwegian coast and it doesn’t need the AC to DC to AC conversion system.

Instead, ABB will install a power cable from a new power plant at Mongstad, north of Bergen, to the platform. It plans to begin running cable in 2009 and tie in to the field the following year. The contract price is $92.5 million.

On completion, it will be the world’s longest transfer of high-voltage AC to a floating installation, according to Bjorn Midttun, head of subsea and pipelines technology for Gjøa. “A solution with power supply from land via cable will have less of an environmental impact compared to a traditional solution with electricity produced at sea,” he said.

Before Statoil’s merger with Hydro, Gjøa was its second largest project after Snøvit. The field in blocks 35/9 and 36/7 holds 82 million bbl of oil and condensate and 1.4 Tcf of gas reserves. Under the development plan, the company will tie back the Vega and Vega South fields to the semisubmersible platform.

Statoil will build the platform and Gaz de France will take over production operations. The gas will go to the UK Flags pipeline to St. Fergus, Scotland, while the oil will move by pipeline to the Troll II pipeline to shore at the Mongstad refinery.

These are early steps in Norway’s effort to reduce pollution from it oil and gas production operations. The country also has a mandate that every new offshore installation built within its boundaries will at least consider onshore power instead of generators.