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One of the most important projects in the national grid upgrade involves the new HVDC converter stations for the inter-island link at Benmore substation in the South Island and Haywards substation near Wellington. By Alan Titchall.
High-voltage, direct current (HVDC) electric power transmission systems are the proven way for the transmission of large amounts of electrical power, in contrast with the more common alternating current (AC) systems used on world networks. Our HVDC link was first commissioned in 1965, upgraded in 1992, and is currently going through its third major upgrade. Stretching from Benmore hydro power station in the lower South Island to the Haywards’ substation just north of Wellington, the DC link exhibits two separate circuits (Poles) with one converter station at each end. These Poles convert the AC voltage to DC voltage (and back again) before the electrical power is transmitted between the islands via overhead lines running from Benmore dam to the top of the South Island and across the Cook Strait via three undersea cables. The first HVDC converter stations (Pole1) were built in 1962 (commissioned 1965) using static mercury arc valves of the type that first saw commercial service overseas in 1954. At the time, Pole 1 was the most ambitious, and longest high voltage direct current scheme in the world. Another circuit (Pole 2), with upgraded ‘solid state’ technology, was commissioned in 1992 and is still in use. Pole 1 was stood down in late September 2007, but is still maintained as an emergency back-up for when the HVDC link is under heavy load. Mercury arc valves were common in systems designed up to 1975, but since then line-commutated converters (LCC) using thyristor valves have been used. Most of the old mercury arc rectifiers around the world have already been dismantled or replaced with thyristor valves with just two exceptions – our Pole 1 and the Pole 1 linking Vancouver Island with the Canadian mainland. Our Pole 1 will not be decommissioned until late 2011, after the World cup, so it can act as an emergency back-up to Pole 2 incase there’s an embarrassing blackout while the eyes of the world are following the sporting event. Pole 3, with its state-of-the-art thyristor valve converter units at Benmore and Haywards and 700MW capacity (up to 1000MW for short term overload), will be fully commissioned in April 2012, followed by the commissioning of a Statcom in 2013 that will help regulate the voltage of the AC network in the Wellington region and lift the north flow transfer capability of the bi-pole inter-island HVDC link to 1200MW. The seismic challengeConstruction work on the new converter stations at each end of the link began in May this year by Siemens as principal contractor on this project with Mainzeal as one its key subcontractors. International companies that specialise in this field of long distance transmission are Siemens, Alstom, and ABB. The project director for Siemens is Dr Guenther Wanninger (pictured above), based in Wellington, who concedes that the project represents an ambitious technical and logistical challenge, but also is “very exciting”. Part of the project , says Wanninger, is also the replacement of the control and protection system of Pole 2 after the new Pole 3 is in operation. While a lot of the high voltage outdoor equipment, such as circuit breakers, have a good shelf-life and are good for many more years, the focus is on the “brain” with its control panel and protection system. This primary plant will be installed by December 2011 and will include three thyristor valve towers, weighing 17 tonnes each, suspended from the ceiling of the 19 metre high valve hall. Six-metre long bushings will transfer electricity between the valves and the outside converter transformers, which weigh up to 330 tonnes each. The major challenge at Haywards is earthquake proofing the new Pole housing structure and all equipment installed. Haywards substation sits just 300 metres from a major fault line and Wanninger says the seismic requirements for the buildings are likely to be the highest ever applied worldwide to a new building. “We had to design this structure to survive a one in 2500 year earthquake, and that is a massive earthquake.” Even hospitals in Wellington are only designed for a one in 500 year earthquake. “If such a large earthquake happens – Wellington may not exist, but this station will still be in operation, as Auckland will still need power,” he adds. Using a design similar to that used in Wellington’s Te Papa museum, which uses base isolators, the foundations of the substation will be connected to rock base with concrete columns and, using the principals of ‘stress reduced base isolation’, the building will sit on two bases separated by foundation sliders.
Although the design is replicated at Benmore, the seismic requirements at the southern end are not as servere. While the buildings and transformers at each Pole are identical, the outdoor equipment and AC filters that provide the connection to the AC network are different, as the network conditions and voltage fluctuations are different at each end of the link. Another challenge at the Haywards site are the space constraints in the existing converter station in order to accommodate the new equipment for pole 3, even after Transpower removed its properties - an old NZED-built village where the author spend some of his early childhood. Asked what he thinks of the antiquated Pole 1 technology that few modern HVDC engineers would get to view in their lifetime, Wanninger uses the word ‘museum’ with a lot of reverence. “This is one of the two last working HVDC links in the world using mercury arc valves. As an old system it requires a lot of maintenance and it has been well looked after.” The technology used in Pole 3 is similar in principle to that used with Pole 2, but represents the evolutions and innovations of the past 20 years, e.g. the advantage of a “huge step up” in electronic thyristor technology that Siemens has developed using the concept of ‘light-triggered’ thyristor valves. “Thyristors are semi conductors and in order to make them conductive they need a signal to trigger them. We achieve this by generating an optical signal from the control panel that travels through fibre optics to the valves, without needing to convert it at the valve level into an electronic signal to trigger the thyristor. This way we cut out a lot of electronics with the philosophy that a component that is not needed, cannot fail.” It also equates to increased reliability and up to 80 percent less equipment inside the valve housing, compared to previous valve equipment or what Siemens’ competition is using today, adds Wanninger. Asea, now ABB, was the principal contractor for the previous two Poles, so this is a coup project for Siemens whose most recent HVDC project in this region was Basslink – a 295 kilometre submarine cable, with 70 kilometres of overhead line and up to 600MW capacity, connecting Tasmania and Victoria. New Zealand’s HVDC capacity will be much higher than Basslink. Taking Pole 1 (200MW) out of the equation, Pole 2 already has a nominal rating of 700MW and Pole 3 will add another 700MW - providing a maximum capacity of 1400MW. However, the three Cook Strait cables currently have a limit of 1200MW, which means an additional cable, as well as equipment at each end of the link, would be needed to make full use of the transmission capacity. Trasnpower says there are currently no immediate plans for this. Good for renewable generation
The nature of the direct current link means it can accommodate invariable power generation, such as that produced by wind farms - unlike networks which use alternating current where the power, like water in a pipe network, flows down the easiest path. “The HVDC link can react very quickly to power flows, exporting less or more, and can contribute to minimising voltage fluctuations and help keep the frequency of the network more stable,” says Wanninger. It is a feature of the modern ‘smart grid’ system, he says. Long distance transmission and the AC/DC relationshipCompetition between the direct current (DC) technology of Thomas Edison and the alternating (AC) current of Nikola Tesla and George Westinghouse was known as the ‘war of currents’, with AC emerging victorious. However, when it comes to transmitting large amounts of power over long distances, high-voltage, direct current (HVDC) electric power transmission systems are less expensive and suffer lower electrical losses than the more common alternating current (AC) systems used on networks. Because DC operates at a constant maximum voltage, this allows existing transmission line corridors with equally sized conductors and insulation to carry 100 percent more power into an area of high power consumption than AC, so is ideal for undersea cables, stabilising unsynchronised AC distribution systems (especially AC produced by renewable energy sources), and connecting a remote generating plant to the distribution grid (as is the case in New Zealand). The disadvantages of HVDC are in current conversion, switching, control, and maintenance. Operating a HVDC scheme also requires storing many spare parts, usually exclusively for one system as HVDC systems are not as standardised as AC systems. Practical manipulation of DC voltages only became possible with the development of high power electronic devices such as mercury arc valves (which first saw commercial service in 1954), and later semiconductor devices, such as thyristors (both technologies are currently used on New Zealand HVDC link between the islands). The first HVDC-connection was constructed by ASEA (now ABB) between the mainland of Sweden and the island Gotland. The longest HVDC link in the world is a 1700 kilometre-long, 600MW link connecting the Inga Dam to the Shaba copper mine in the Democratic Republic of Congo, but the construction of a 2500 kilometre HVDC link is underway in China.
Energy NZ Vol.4 No.5 September-October 2010 |
The HVDC inter-island link is a key part of our national grid, providing the South Island with access to the north’s gas and coal generation and, more importantly, the North Island with access to the south’s large hydro generation capacity.
“We had to apply a diversity of seismic designs to the project and ones different than that used in Pole 2 so the buildings can’t all collapse for the same reason.”
The improved capacity, upgrading and future-proofing of the HVDC link between the islands will encourage investment in more renewable generation, says Wanninger, by providing generators with more site options.