| HVDC Inter-Island | |
|---|---|
The North Island HVDC terminal station at Haywards near Wellington, showing the Pole 2 converter building and switchyards |
|
| Location | |
| Country | New Zealand |
| General direction | South-North |
| From | Benmore Hydroelectric Power Station, Canterbury |
| To | Haywards transmission substation, Wellington |
| Ownership information | |
| Owner | Transpower New Zealand Limited |
| Operator | Transpower New Zealand Limited |
| Construction information | |
| Construction started | 1961 |
| Commissioned | April 1965 |
| Technical information | |
| Type | Bipole HVDC scheme with Overhead transmission line and Submarine power cables across the Cook Strait |
| Type of current | HVDC |
| Total length | 610 km (380 mi) |
| Power rating | 700 MW (northwards) 600 MW (southwards) |
| DC Voltage | +270kV and −350kV |
| Number of poles | One (in operation as of 2010) |
The HVDC Inter-Island link is a high-capacity, bipolar high-voltage direct current (HVDC) transmission system connecting the electricity transmission networks of New Zealand's two main islands to form the National Grid. The HVDC link is owned and operated by state-owned transmission company Transpower New Zealand. The link is commonly referred to as the Cook Strait cable. This is somewhat of a misnomer, because there are actually three submarine HVDC power cables across Cook Strait in current use and that they make up only a short section of the route. However, the term Cook Strait cable is commonly used in the media and press releases.[1]
The 610 km link starts at the Benmore Hydroelectric Power Station, on the Waitaki River in Canterbury, and travels 534 km on an overhead transmission line through inland Canterbury and Marlborough to Fighting Bay in the Marlborough Sounds. From Fighting Bay, the link travels 40 km via submarine cables across Cook Strait to Oteranga Bay, near Wellington, before travelling the final 37 km to Haywards transmission sub-station in the Hutt Valley.
The HVDC link was first commissioned in April 1965, originally as a bipolar 600 MW link with mercury arc valves. The original equipment was paralleled onto a single pole (Pole 1) in 1992, and a new thyristor-based pole (Pole 2) was commissioned alongside it. The mercury-arc pole was partially decommissioned in 2007, and ork is underway to replace it with a new thyristor pole, with work expected to be completed in 2012.
Contents |
The HVDC link is an important component of the transmission system in New Zealand. It connects the transmission grids of the two islands, and is used as an energy-balancing system, helping to match energy availability and demand in the two islands.
The two islands are geographically different – the South Island is 33% larger than the North Island, but the North Island has 3.2 times the population of the South Island. As a consequence, the North Island has a substantially larger energy demand. However, the South Island loads include the Tiwai Point Aluminium Smelter, which at a peak demand of 640 MW is New Zealand's largest single electricity user, and the second largest load centre after the city of Auckland.[2] In total, around 32.5% of the total electricity generated was consumed in the South Island, while 67.5% was consumed in the North Island.[3]
The South Island is more mountainous than the North Island, containing 38 of the 40 New Zealand peaks over 2500 m, creating larger resources for hydroelectricity. However, the North Island has numerous natural gas reserves, geothermal areas, and suitable coalfields to support thermal generation (South Island coal is generally harder and more suitable for steel manufacture than electricity generation). Both islands are suited for wind generation, although the North Island has more wind generators currently than the South Island. The South Island has a total generating capacity of 3582 MW (37.8%) – of which 98% is hydroelectricity. The North Island's generating capacity is 5905 MW (62.2%) – of which 31.6% is hydro, 29.6% is gas, 16.0% is coal, 10.8% is geothermal, 7.4% is wind, and 4.6% is other fuels.[3]
Although both islands normally have enough generating capacity to power themselves in the short term without the connection between the two islands, the HVDC link provides benefits for both South Island and North Island energy markets[4]:
The link plays an important role in the New Zealand electricity market and facilitates competition. Deregulation of the electricity industry that occurred the 1990s led to the breakup of the generation previously owned by the Electricity Corporation of New Zealand. With the exception of Contact Energy, the split up of the Electricity Corporation generators was carried out geographically. As a result, two generating companies (Genesis Power and Mighty River Power) were based solely in the North Island, and one (Meridian) solely in the South Island. Contact Energy owned stations in both islands. If the HVDC link didn't exist, or in the event of a failure, wholesale electricity prices could rise from a shortfall in capacity and reduced competition.[5]
The link is designed to be able to transmit electricity in both northwards and southwards directions, but the design of the transmission system in the lower North Island restricts the amount of electricity that can be transmitted southwards. The North Island's electricity system has most of its generation in the centre of the island, while the two major load centres, Auckland and Wellington, are located north and south of the main generation resources. The HVDC Inter-Island link connects to the North Island AC transmission system at Haywards in Wellington. The Wellington region is a major load centre with a regional peak demand of approximately 780 MW and local generation of only around one-fifth of that. During periods of northwards power flow on the HVDC link, the energy from the South Island is largely used in the Wellington region, and any surplus flows along four 220 kV transmission circuits to points further north. However, during periods of southwards HVDC flow, the 220 kV circuits into Wellington must transmit electricity from the North Island grid for both Wellington and the HVDC link. Southwards HVDC power transfer is limited by the capacity of the lower North Island 220 kV transmission circuits, and by the risk of voltage disturbances in the Wellington region in the event of a sudden disruption to HVDC transfer. Large southwards transfers on the HVDC link are not generally required except during period of prolonged low inflows to South Island hydro lakes, and the limited southbound capacity is not a major constraint.[5]
The inter-island transmission system was designed as HVDC, despite the cost of the conversion from AC to DC and back, to suit the requirements of a long transmission line and a sea crossing. The link crosses Cook Strait, between the two islands, using submarine power cables laid along the sea floor. HVDC is more suitable than AC for transmission over long distances, and particularly where cable transmission is required, because it typically has lower energy losses. See High-voltage direct current.
The HVDC inter-island link was designed and built between 1965 for the New Zealand Electricity Department. The major equipment suppliers were Asea Brown Boveri and British Insulated Callender's Cables.[6] The original Cook Strait cables were installed in 1964, from the cable laying ship Photinia.[7]
The HVDC Inter-Island link was built with large mercury-arc rectifiers and inverters – 1960s technology. When it was completed, the HVDC Inter-Island link was the world's longest with the highest power rating, and the largest undersea power cables.[8]
Until it was upgraded in 1993, the HVDC Inter-Island link was a bi-pole HVDC transmission line with normal operating voltages of plus and minus 250 kilovolts, and a maximum power transmission capacity of about 600 megawatts (MW).
The HVDC transmission line that connects the rectifier/inverter (converter) station at the Benmore Dam hydroelectric plant in the southern half of the South Island with the converter station at Haywards on the North Island has an overall length of 610 kilometres. The overhead transmission line is supported by 1649 transmission towers and has a total route length of 570 km. The submarine cables across Cook Strait are 40 km long.[9]
Between 1991 and 1993, the inter-island power transmission system was upgraded with the addition of new HVDC converter stations at each end of the link. These new HVDC converter stations used solid state thyristor technology. The existing mercury arc valve converters were re-configured to operate in parallel at each station (they had previously operated with opposite electrical polarity). The reconfigured mercury arc valve converters were designated as Pole 1, and the new thyristor converters were designated as Pole 2. The operating voltage of the new converters was 350 kV. The project scope included the laying of three new new submarine cables across Cook Strait, and re-insulation of the overhead HVDC line to accommodate the increased operating voltage.[10] The three new power cables were installed in 1991 by the specialist cable laying vessel Skagerrak.[11]
As of 21 September 2007[update], the part of Pole 1 of the inter-island link that still used the original mercury-arc rectifiers and inverters was shut down "indefinitely".[12] However, in December 2007, Transpower announced that one-half of the capacity of Pole 1 would be returned to "warm standby" service before the winter of 2008 in order to meet the demand for power on the North Island if needed. The remaining half-pole equipment of Pole 1 was to be decommissioned.[13]
Transpower also announced in November 2007 that by December 2007, it would increase the power transmission capacity from south to north of Pole 2 from 500 MW to 700 MW. This was done by reconfiguring the three operational submarine cables by moving one of the two cables of Pole 1 to Pole 2.[14]
On 13 March 2008, Transpower announced that work had been completed to restore 50% of the capacity of Pole 1 to service at times when the demand for power on the North Island peaked. Several mercury arc rectifiers were salvaged from the Konti-Skan link between Denmark and Sweden for this restoration.
The energy transfer on Pole 1 has been strictly limited to the northbound direction, to reduce the stress and strain on the aged converter system.[15] In May 2009 Transpower placed Pole 1 back into service at a limited capacity of 200 MW in response to a temporary loss of capacity on Pole 2.
Like all transmission systems, the HVDC Inter-Island link is not immune to failures. The importance of the link means that an unplanned outage can have major implications for the whole of the New Zealand electricity system, potentially causing nationwide electricity shortages and a spike in wholesale electricity prices.
Planned outages of the link are required occasionally to carry out maintenance that is not possible while the system is live. Maintenance outages are planned well in advance to minimise the effects – they are usually carried out in summer when inter-island electricity demand is at its lowest, and usually on one pole at a time, while the other pole remains in operation with earth electrodes providing a path for return current through the ground.
Notable faults and outages on the HVDC Inter-Island:-
In May 2008, Transpower submitted an investment proposal to the Electricity Commission for the replacement of the old mercury arc valve Pole 1 converter stations with new thyristor converter stations.[20] In July 2008, the Electricity Commission announced its intention to approve the project .[21]
The new converter stations are to be known as Pole 3, and will operate at 350 kV, matching the existing Pole 2. Site works on the $672 million project were formally commenced on 19 April 2010, when Minister of Energy Gerry Brownlee turned the first sod, with the new converter stations scheduled for commissioning in April 2012.[22] Work involved in the replacement of Pole 1 with the new Pole 3 converter stations includes:[5]
The decommissioning of Pole 1 is scheduled for July 2012, allowing works to switch the existing lines over Pole 3 and to test the new pole to occur during the summer months where electricity demand and therefore inter-island electricity transfer is low. Pole 3 is planned to be commissioned for operation in December 2012. The new pole will initially be limited to 500 MW northbound transfer (1000 MW total transfer with Pole 2) due to inadequate voltage support at Haywards. After a new static synchronous compensator (STATCOM) at Haywards is commissioned, planned for January 2014, Pole 3 will be able to operate at its full 700 MW capacity (1200 MW total transfer with Pole 2).[23]
During the Pole 1 replacement, work is also underway to carry out maintenance and remedial work on some sections of the transmission line. Work includes:[23]
There are proposals to install a fourth cable across the Cook Strait (Cable 7), connecting to Pole 2, to allow the HVDC link to increase to 1400 MW. In addition to a fourth cable, new filters would also be installed at Benmore and Haywards, and a new STATCOM at Haywards. The project is unlikely to be completed before 2016.
The Upper South Island north of the Waitaki Valley is generation-poor, yet has many large demand centres, especially Christchurch, Nelson, Ashburton and Timaru-Temuka. Almost all of the electricity has to be imported from the Waitaki Valley, via three major lines carrying between them four 220kV circuits. Increasing demand means that these lines are fast approaching capacity, and because they all converge on Islington sub-station in western Christchurch, a major fault at the sub-station could potentially interrupt the electricity supply to the entire South Island north of Christchurch.
One of the many proposals to alleviate this issue includes a tap into the HVDC Inter-Island and an inverter/rectifier station where it meets the two 220kV Islington to Kikiwa lines near Waipara in northern Canterbury. This would allow another route for electricity into Christchurch and the Upper South Island, and create redundancy in the network. However, it is unlikely for such a tap to be built before 2021.[24]