High-voltage direct current

Early commercial installations included one in the Soviet Union in 1951 between Moscow and Kashira, and a 100 kV, 20 MW system between Gotland and mainland Sweden in 1954.

[b] First proposed in 1914,[13] the grid controlled mercury-arc valve became available during the period 1920 to 1940 for the rectifier and inverter functions associated with DC transmission.

In 1941, a 60 MW, ±200 kV, 115 km (71 mi) buried cable link, known as the Elbe-Project, was designed for the city of Berlin using mercury arc valves but, owing to the collapse of the German government in 1945, the project was never completed.

[15] The Moscow–Kashira system and the 1954 connection by Uno Lamm's group at ASEA between the mainland of Sweden and the island of Gotland marked the beginning of the modern era of HVDC transmission.

Like mercury arc valves, thyristors require connection to an external AC circuit in HVDC applications to turn them on and off.

On March 15, 1979, a 1920 MW thyristor based direct current connection between Cabora Bassa and Johannesburg (1,410 km; 880 mi) was energized.

The conversion equipment was built in 1974 by Allgemeine Elektricitäts-Gesellschaft AG (AEG), and Brown, Boveri & Cie (BBC) and Siemens were partners in the project.

Therefore, modern VSC HVDC converter stations are designed with sufficient redundancy to guarantee operation over their entire service lives.

There are several different variants of VSC technology: most installations built until 2012 use pulse-width modulation in a circuit that is effectively an ultra-high-voltage motor drive.

In other words, transmitting electric AC power over long distances inevitably results in a phase shift between voltage and current.

Specific applications where HVDC transmission technology provides benefits include: Long undersea or underground high-voltage cables have a high electrical capacitance compared with overhead transmission lines since the live conductors within the cable are surrounded by a relatively thin layer of insulation (the dielectric), and a metal sheath.

Another factor that reduces the useful current-carrying ability of AC lines is the skin effect, which causes a nonuniform distribution of current over the cross-sectional area of the conductor.

HVDC is less reliable and has lower availability than alternating current (AC) systems, mainly due to the extra conversion equipment.

As of 2012[update] only two are in service: the Quebec – New England Transmission between Radisson, Sandy Pond, and Nicolet[30] and the Sardinia–mainland Italy link which was modified in 1989 to also provide power to the island of Corsica.

[31] HVDC circuit breakers are difficult to build because of arcing: under AC, the voltage inverts and in doing so crosses zero volts dozens of times a second.

Conversely, semiconductor breakers are fast enough but have a high resistance when conducting, wasting energy and generating heat in normal operation.

Generally, vendors of HVDC systems, such as GE Vernova, Siemens and ABB, do not specify pricing details of particular projects; such costs are typically proprietary information between the supplier and the client.

With some other types of semiconductor devices such as the insulated-gate bipolar transistor (IGBT), both turn-on and turn-off can be controlled, giving a second degree of freedom.

The additional controllability gives many advantages, notably the ability to switch the IGBTs on and off many times per cycle in order to improve the harmonic performance.

Such converters derive their name from the discrete, two voltage levels at the AC output of each phase that correspond to the electrical potentials of the positive and negative DC terminals.

The IGBTs in each submodule either bypass the capacitor or connect it into the circuit, allowing the valve to synthesize a stepped voltage with very low levels of harmonic distortion.

VSCs, on the other hand, can either produce or consume reactive power on demand, with the result that usually no separate shunt capacitors are needed (other than those required purely for filtering).

The most common configuration of an HVDC link consists of two converter stations connected by an overhead power line or undersea cable.

This effect can cause considerable power loss, create audible and radio-frequency interference, generate toxic compounds such as oxides of nitrogen and ozone, and bring forth arcing.

Continental North America, while operating at 60 Hz throughout, is divided into regions which are unsynchronized: East, West, Texas, Quebec, and Alaska.

Wind farms located off-shore may use HVDC systems to collect power from multiple unsynchronized generators for transmission to the shore by an underwater cable.

[46] Czisch's study concludes that a grid covering the fringes of Europe could bring 100% renewable power (70% wind, 30% biomass) at close to today's prices.

There has been debate over the technical feasibility of this proposal[47] and the political risks involved in energy transmission across a large number of international borders.

The purpose of this interconnector is to facilitate cross-border renewable power trading with Indonesia and Australia, in preparation for the future Asian Pacific Super Grid.

[53] Increasing the transmission voltage on such lines reduces the power loss, but until recently, the interconnectors required to bridge the segments were prohibitively expensive.