High-voltage direct current
A high-voltage direct current system uses direct current and high voltages for electric power transmission. It is in contrast with the more common alternating current transmission systems.
HVDC lines are commonly used for long-distance power transmission, since they require fewer conductors and incur less power loss than equivalent AC lines. HVDC also allows power transmission between AC transmission systems that are not synchronized. Since the power flow through an HVDC link can be controlled independently of the phase angle between source and load, it can stabilize a network against disturbances due to rapid changes in power. HVDC also allows the transfer of power between grid systems running at different frequencies, such as 50 and 60 Hz. This improves the stability and economy of each grid, by allowing the exchange of power between previously incompatible networks.
The modern form of HVDC transmission uses technology developed extensively in the 1930s in Sweden and in Germany. 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. The longest HVDC link in the world is the Zhundong–South Anhui link in China a ±1,100 kV, ultra HVDC line with a length of more than.
High voltage transmission
is used for electric power transmission to reduce the energy lost in the resistance of the wires. For a given quantity of power transmitted, doubling the voltage will deliver the same power at only half the current:Since the energy lost as heat in the wires is directly proportional to the square of the current using half the current at double the voltage reduces the line losses by a factor of 4. While energy lost in transmission can also be reduced by decreasing the resistance by increasing the conductor size, larger conductors are heavier and more expensive.
High voltage cannot readily be used for lighting or motors, so transmission-level voltages must be reduced for end-use equipment. Transformers are used to change the voltage levels in alternating current transmission circuits, but cannot pass DC current. Transformers made AC voltage changes practical, and AC generators were more efficient than those using DC. These advantages led to early low-voltage DC transmission systems being supplanted by AC systems around the turn of the 20th century.
Practical conversion of current between AC and DC became possible with the development of power electronics devices such as mercury-arc valves and, starting in the 1970s, power semiconductor devices including thyristors, integrated gate-commutated thyristors, MOS-controlled thyristors and insulated-gate bipolar transistors.
History
Electromechanical systems
The first long-distance transmission of electric power was demonstrated using direct current in 1882 in the 57 km Miesbach-Munich Power Transmission, but only 1.5 kW was transmitted. An early method of HVDC transmission was developed by the Swiss engineer René Thury and his method, the Thury system, was put into practice by 1889 in Italy by the Acquedotto De Ferrari-Galliera company. This system used series-connected motor-generator sets to increase the voltage. Each set was insulated from electrical ground and driven by insulated shafts from a prime mover. The transmission line was operated in a constant-current mode, with up to 5,000 volts across each machine, some machines having double commutators to reduce the voltage on each commutator. This system transmitted 630 kW at 14 kV DC over a distance of. The Moutiers–Lyon system transmitted 8,600 kW of hydroelectric power a distance of, including of underground cable. This system used eight series-connected generators with dual commutators for a total voltage of 150 kV between the positive and negative poles, and operated from 1906 until 1936. Fifteen Thury systems were in operation by 1913. Other Thury systems operating at up to 100 kV DC worked into the 1930s, but the rotating machinery required high maintenance and had high energy loss.Various other electromechanical devices were tested during the first half of the 20th century with little commercial success. One technique attempted for conversion of direct current from a high transmission voltage to lower utilization voltage was to charge series-connected batteries, then reconnect the batteries in parallel to serve distribution loads. While at least two commercial installations were tried around the turn of the 20th century, the technique was not generally useful owing to the limited capacity of batteries, difficulties in switching between series and parallel configurations, and the inherent energy inefficiency of a battery charge/discharge cycle.
Mercury arc valves
First proposed in 1914, the grid controlled mercury-arc valve became available during the period 1920 to 1940 for the rectifier and inverter functions associated with DC transmission. Starting in 1932, General Electric tested mercury-vapor valves and a 12 kV DC transmission line, which also served to convert 40 Hz generation to serve 60 Hz loads, at Mechanicville, New York. In 1941, a 60 MW, ±200 kV, 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. The nominal justification for the project was that, during wartime, a buried cable would be less conspicuous as a bombing target. The equipment was moved to the Soviet Union and was put into service there as the Moscow–Kashira HVDC system. 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.Mercury arc valves were common in systems designed up to 1972, the last mercury arc HVDC system having been put into service in stages between 1972 and 1977. Since then, all mercury arc systems have been either shut down or converted to use solid-state devices. The last HVDC system to use mercury arc valves was the Inter-Island HVDC link between the North and South Islands of New Zealand, which used them on one of its two poles. The mercury arc valves were decommissioned on 1 August 2012, ahead of the commissioning of replacement thyristor converters.
Thyristor valves
The development of thyristor valves for HVDC began in the late 1960s. The first complete HVDC scheme based on thyristor was the Eel River scheme in Canada, which was built by General Electric and went into service in 1972.Since 1977, new HVDC systems have used solid-state devices, in most cases thyristors. Like mercury arc valves, thyristors require connection to an external AC circuit in HVDC applications to turn them on and off. HVDC using thyristors is also known as line-commutated converter HVDC.
On March 15, 1979, a 1920 MW thyristor based direct current connection between Cabora Bassa and Johannesburg was energized. The conversion equipment was built in 1974 by Allgemeine Elektricitäts-Gesellschaft AG, and Brown, Boveri & Cie and Siemens were partners in the project. Service interruptions of several years were a result of a civil war in Mozambique. The transmission voltage of ±533 kV was the highest in the world at the time.
Capacitor-commutated converters
Line-commutated converters have some limitations in their use for HVDC systems. This results from requiring a period of reverse voltage to affect the turn off. An attempt to address these limitations is the capacitor-commutated converter. The CCC has series capacitors inserted into the AC line connections. CCC has remained only a niche application because of the advent of voltage-source converters which more directly address turn-off issues.Voltage-source converters
Widely used in motor drives since the 1980s, voltage-source converters started to appear in HVDC in 1997 with the experimental Hellsjön–Grängesberg project in Sweden. By the end of 2011, this technology had captured a significant proportion of the HVDC market.The development of higher rated insulated-gate bipolar transistors, gate turn-off thyristors, and integrated gate-commutated thyristors, has made HVDC systems more economical and reliable. This is because modern IGBTs incorporate a short-circuit failure mode, wherein should an IGBT fail, it is mechanically shorted. Therefore, modern VSC HVDC converter stations are designed with sufficient redundancy to guarantee operation over their entire service lives. The manufacturer Hitachi Energy calls this concept HVDC Light, while Siemens calls a similar concept HVDC PLUS and Alstom call their product based upon this technology HVDC MaxSine. They have extended the use of HVDC down to blocks as small as a few tens of megawatts and overhead lines as short as a few dozen kilometers. 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. More recent installations, including HVDC PLUS and HVDC MaxSine, are based on variants of a converter called a modular multilevel converter.
Multilevel converters have the advantage that they allow harmonic filtering equipment to be reduced or eliminated altogether. By way of comparison, AC harmonic filters of typical line-commutated converter stations cover nearly half of the converter station area.
With time, voltage-source converter systems will probably replace all installed simple thyristor-based systems, including the highest DC power transmission applications.
Comparison with AC
Advantages
A long-distance, point-to-point HVDC transmission scheme generally has lower overall investment cost and lower losses than an equivalent AC transmission scheme. Although HVDC conversion equipment at the terminal stations is costly, the total DC transmission-line costs over long distances are lower than for an AC line of the same distance. HVDC requires less conductor per unit distance than an AC line, as there is no need to support three phases and there is no skin effect. AC systems use a higher peak voltage for the same power, increasing insulator costs.Depending on voltage level and construction details, HVDC transmission losses are quoted at 3.5% per, about 50% less than AC lines at the same voltage. This is because direct current transfers only active power and thus causes lower losses than alternating current, which transfers both active and reactive power. In other words, transmitting electric AC power over long distances inevitably results in a phase shift between voltage and current. Because of this phase shift the effective Power=Current*Voltage, where * designates a vector product, decreases. Since DC power has no phase, the phase shift cannot occur in the DC case.
HVDC transmission may also be selected for other technical benefits. HVDC can transfer power between separate AC networks. HVDC power flow between separate AC systems can be automatically controlled to support either network during transient conditions, but without the risk that a major power-system collapse in one network will lead to a collapse in the second. The controllability feature is also useful where control of energy trading is needed.
Specific applications where HVDC transmission technology provides benefits include:
- Undersea-cable transmission schemes.
- Endpoint-to-endpoint long-haul bulk power transmission without intermediate taps, usually to connect a remote generating plant to the main grid.
- Increasing the capacity of an existing transmission line in situations where additional wires are difficult or expensive to install.
- Power transmission and stabilization between unsynchronized AC networks, with the extreme example being an ability to transfer power between countries that use AC at different frequencies.
- Stabilizing a predominantly AC power grid, without increasing prospective short-circuit current.
- Integration of renewable resources such as wind into the main transmission grid. HVDC overhead lines for onshore wind integration projects and HVDC cables for offshore projects have been proposed in North America and Europe for both technical and economic reasons. DC grids with multiple VSCs are one of the technical solutions for pooling offshore wind energy and transmitting it to load centers located far away onshore.