AC vs DC Cable Transmission for Offshore

AC Vs DC Cable Transmission for Offshore Wind farm Seminar Report-‘09

1. INTRODUCTION

The application of wind energy throughout the world is growing fast. The

development of larger, more efficient turbines is opening up new frontiers in wind energy

generation in the form of large offshore wind farms. The use of high-voltage direct current

(HVDC) technology can fully realize the potential of these developments. Wind farms

located offshore are planned because of higher average wind speeds at sea and space

limitations on-shore. Offshore wind farms will be different from their onshore counterparts

for several reasons. The turbines will on average have a larger diameter and rated powers,

the farm will be difficult to access during periods with high winds, erection and

maintenance will be more expensive, the turbine noise will probably not be an important

issue, and a submarine electrical connection to shore will be required.

Figure 1: Offshore Wind farm

As the increasing demand, offshore wind power characterized by larger size of

the farms, 200 – 1000 MW are planned, and increasing distances from the grid. Cable

transmission is the only solution for the transmission from the farm to the shore. Often land

cables are also required to reach a sufficiently strong interconnection point in the grid.

Together this gives transmission distances of 50 – 100 km. The electrical system concerns

Dept. of Electrical & Electronics Engineering 1 MACE


the electrical power components between the generator shaft and the grid connection and it

concerns the way these components are interconnected and operated. Its function is to

convert mechanical power to electric power, to collect electric power from individual

turbines, to transmit it to the shore and to convert to an appropriate voltage and frequency.

The system consists amongst other of generators, cables, transformers and power

electronic converters. Systems are mainly characterized by the type of voltage used within

the farm and for the shore connection (AC or DC) and the frequency of the electrical signals

(fixed or variable). Some efficient way of configuration to collect the electric power from

individual wind turbines and to transmit this power to an on-shore high-voltage power

system node has been discussed here. The inventory concerns both constant and variable

speed wind turbines and transmission by AC and DC cable networks.

Background

Wind power is the world’s fastest growing energy source. By 2020, 12% of the

world’s demand of electricity will be produced by wind. Recent trends are a move from

onshore to offshore, the up scaling of wind turbine size (to 3-5 MW), and the integration of

land and marine-based networks. A major challenge is connecting a variable energy source

to a distant grid demanding power stability.



2. WIND POWER

Wind power is the conversion of wind energy into a useful form of energy, such as

electricity, using wind turbines. At the end of 2008, worldwide nameplate capacity of wind-

powered generators was 121.2 gigawatts (GW). In 2008, wind power produced about 1.5%

of worldwide electricity usage; and is growing rapidly, having doubled in the three years

between 2005 and 2008. Several countries have achieved relatively high levels of wind

power penetration, such as 19% of stationary electricity production in Denmark, 11%

in Spain and Portugal, and 7% in Germany and the Republic of Ireland in 2008. As of May

2009, eighty countries around the world are using wind power on a commercial basis.

Large-scale wind farms are connected to the electric power transmission network;

smaller facilities are used to provide electricity to isolated locations. Utility companies

increasingly buy back surplus electricity produced by small domestic turbines. Wind energy

as a power source is attractive as an alternative to fossil fuels, because it is

plentiful, renewable, widely distributed, clean, and produces no greenhouse gas emissions.

However, the construction of wind farms is not universally welcomed due to their visual

impact and other effects on the environment. Wind power is non-dispatchable, meaning that

for economic operation, all of the available output must be taken when it is available. Other

resources, such as hydropower, and standard load management techniques must be used to

match supply with demand. The intermittency of wind seldom creates problems when using

wind power to supply a low proportion of total demand. Where wind is to be used for a

moderate fraction of demand such as 40%, additional costs for compensation of

intermittency are considered to be modest.

2.1 Effect on power grid

The intermittency of wind power and other renewable power sources creates issues in

power grids, which expect some supplied power to have a certain degree of constancy and

reliability to satisfy baseline demand while other supplied power must respond to variations

in demand.



One proposed solution in Europe is to create a super grid of interconnected wind

farms. This large-scale array of dispersed wind farms would be located in different wind

regimes, reducing the overall variation in power output.

2.2 Development

To develop a wind farm, a suitable location is first identified. Good locations for

wind farms should have fast steady winds and be near transmission lines. Land parcels on

which wind turbines will be located then must be leased from the land owners. The wind

resource must then be evaluated using data recorded by onsite meteorological towers. The

wind farm project must then be financed and constructed.

2.3 Types

Depending on the location of the turbines installed, the wind farms can be classified

as Onshore, Nearshore, Airborne, and Offshore. Among these, onshore windfarms became

very popular because of its comparative low initial investment and pollution free energy.

Thus such windfarms were constructed in site where continuous unidirectional flow of wind

is available. But the increasing demand and non availability of suitable lands, the world is

now going for offshore wind farms.

2.3.1 Onshore

Onshore turbine installations in hilly or mountainous regions tend to be on ridgelines

generally three kilometers or more inland from the nearest shoreline. This is done to exploit

the so-called topographic acceleration as the wind accelerates over a ridge. The additional

wind speeds gained in this way make a significant difference to the amount of energy that is

produced. Great attention must be paid to the exact positions of the turbines (a process



known as micro-siting) because a difference of 30 m can sometimes mean a doubling in

output.

Figure 2: Onshore Windfarm

2.3.2 Nearshore

Figure 3: Nearshore Windfarm



Nearshore turbine installations are on land within three kilometers of a shoreline or

on water within ten kilometers of land. These areas are good sites for turbine installation,

because of wind produced by convection due to differential heating of land and sea each

day. Wind speeds in these zones share the characteristics of both onshore and offshore

wind, depending on the prevailing wind direction.

2.3.3 Airborne

Airborne wind turbines would eliminate the cost of towers and might also be flown in

high speed winds at high altitude. No such systems are in commercial operation.

2.3.4 Offshore

Figure 4: Offshore wind turbines

Offshore wind development zones are generally considered to be ten kilometers or

more from land. Offshore wind turbines are less obtrusive than turbines on land, as their

apparent size and noise is mitigated by distance. Because water has less surface roughness

than land (especially deeper water), the average wind speed is usually considerably higher

over open water. Capacity factors (utilisation rates) are considerably higher than for onshore

and nearshore locations. In stormy areas with extended shallow continental shelves, turbines

are practical to install


http://en.wikipedia.org/wiki/File:Hornsrev16.JPG


3. OFFSHORE WINDFARMS

Offshore wind farms are likely to be larger than those on shore as the economies of

scale in offshore projects are more significant. Compared to onshore wind power, offshore

wind power is more complex and costly to install and maintain but also has several key

advantages. Winds are typically stronger and more stable at sea, resulting in significantly

higher production per unit installed. Wind turbines can also be bigger than on land because

it is easier to transport very large turbine components by sea. Offshore wind development

zones are generally considered to be ten kilometers or more from land. Offshore wind

turbines are less obtrusive than turbines on land, as their apparent size and noise is mitigated

by distance. Because water has less surface roughness than land (especially deeper water),

the average wind speed is usually considerably higher over open water. Capacity factors

(utilisation rates) are considerably higher than for onshore and nearshore locations. In

stormy areas with extended shallow continental shelves, turbines are practical to install.

Offshore installation is more expensive than onshore but this depends on the

attributes of the site. Offshore towers are generally taller than onshore towers once the

submerged height is included. Offshore foundations may be more expensive to build. Power

transmission from offshore turbines is through undersea cable, often using high voltage

direct current operation if significant distance is to be covered. Offshore saltwater

environments also raise maintenance costs by corroding the towers

Offshore wind turbines will probably continue to be the largest turbines in operation,

since the high fixed costs of the installation are spread over more energy production,

reducing the average cost. Turbine components (rotor blades, tower sections) can be

transported by barge, making large parts easier to transport offshore than on land, where

turn clearances and underpass clearances of available roads limit the size of turbine

components that can be moved by truck. Similarly, large construction cranes are difficult to

move to remote wind farms on land, but crane vessels easily move over water. Offshore

wind farms tend to be quite large, often involving over 100 turbines. These wind farms are

likely to be located some distance from the shore.



3.1 Indian Scenario

At the end of September 2007, India had 7660 MW of wind generating capacity and

is the fourth largest market in the world. Indian Wind Energy Association has estimated that

with the current level of technology, the ‘on-shore’ potential for utilization of wind energy

for electricity generation is of the order of 65,000 MW. There are about a dozen wind

pumps of various designs providing water for agriculture, afforestation, and domestic

purposes, all scattered over the country. The wind farms are predominantly present in the

states of Tamil Nadu, Maharashtra, Karnataka and Gujarat. Other states like Andhra

Pradesh, Rajasthan, Kerala and Madhya Pradesh have a very good potential.

3.2 Transmission Issues for Offshore Wind Farms

Electric energy generated by offshore wind generating facilities requires one or more

submarine cables to transmit the power generated to the onshore utility grid that services the

end-users of this renewable energy source. Because the power from the wind turbines is

generated as an alternating current (AC) and the on-shore transmission grid is AC, the most

straightforward technical approach is to use an AC cable system connection to facilitate this

interconnection. Present state-of-the-art and the most cost effective AC technology for this

type of interconnection is solid dielectric (also called extruded dielectric or polymeric

insulated) cable, usually with cross- linked polyethylene (XLPE) insulation. This is the cable

system technology presently used for all offshore wind farms constructed to date (all of

which are located in Europe) primarily as a result of: ease of interconnection, installation,

and maintenance; operational reliability; and cost effectiveness. For relatively small

generating capacity wind farms it has been sufficient to bring the power to shore at the same

voltage used to interconnect the wind turbine generators (WTG), typically 33 kilovolt (kV).

As the energy generating capacity of the wind farm increases, however, use of submarine

cables in this voltage class for the connection to shore would require a prohibitively large

number of cables and would lead to high line losses and excessive voltage drops combined

with unnecessary sea-bed disturbance to accommodate installation of many cables. One



solution is to step up the wind farm transmission voltage from the WTG production and

collection voltage of 33 kV to a higher AC voltage suitable for transmission to shore. This

requires an offshore substation platform containing step-up transformers. The first wind farm

large enough to require this approach is the 160 MW Horns Rev Wind Farm commissioned

for operation in December 2002 in Denmark.

Corona is another factor. Corona discharge is the creation of ions in a fluid (such

as air) by the presence of a strong electric field. Electrons are torn from neutral air, and

either the positive ions or the electrons are attracted to the conductor, while the charged

particles drift. 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. Both AC and DC transmission lines can generate coronas, in the former

case in the form of oscillating particles, in the latter a constant wind. Due to the space

charge formed around the conductors, an HVDC system may have about half the loss per

unit length of a high voltage AC system carrying the same amount of power. With

monopolar transmission the choice of polarity of the energized conductor leads to a degree

of control over the corona discharge. In particular, the polarity of the ions emitted can be

controlled, which may have an environmental impact on particulate condensation. (Particles

of different polarities have a different mean-free path.) Negative coronas generate

considerably more ozone than positive coronas, and generate it further downwind of the

power line, creating the potential for health effects. The use of a positive voltage will reduce

the ozone impacts of monopole HVDC power lines.

Earthing, particularly for lightning protection, will need to be addressed as offshore

structures may be more exposed to positive polarity lightning strokes. Positive downward

lightning has higher peak currents and charge transfer, and is likely to be more destructive

than the more common negative downward strike. Coupled with the difficulties of offshore

access, this may lead to a much higher economic benefit of improved lightning protection.

Also for directly connected wind farms with 33 kV collection circuits, some form of

reactive power compensation/voltage control may be required. It will, of course, be cheaper

to locate this on land.



4. HIGH VOLTAGE DIRECT CURRENT (HVDC)

A high-voltage, direct current (HVDC) electric power transmission system uses direct

current for the bulk transmission of electrical power, in contrast with the more

common alternating current systems. For long-distance distribution, HVDC systems are less

expensive and suffer lower electrical losses. For shorter distances, the higher cost of DC

conversion equipment compared to an AC system may be warranted where other benefits of

direct current links are useful.

The modern form of HVDC transmission uses technology developed extensively in

the 1930s in Sweden at ASEA. Early commercial installations included one in the Soviet

Union in 1951 between Moscow and Kashira, and a 10-20 MW system between Gotland

and mainland Sweden in 1954. The longest HVDC link in the world is currently the Inga-

Shaba 1,700 km, 600 MW link connecting the Inga Dam to the Shaba copper mine, in

the Democratic Republic of Congo.

4.1 High voltage transmission

High voltage is used for transmission to reduce the energy lost in the resistance of the

wires. For a given quantity of power transmitted, higher voltage reduces the transmission

power loss. Power in a circuit is proportional to the current, but the power lost as heat in the

wires is proportional to the square of the current. However, power is also proportional to

voltage, so for a given power level, higher voltage can be traded off for lower current. Thus,

the higher the voltage, lower the power loss. Power loss can also be reduced by reducing

resistance, commonly achieved by increasing the diameter of the conductor; but larger

conductors are heavier and more expensive.

High voltages cannot be easily used in lighting and motors, and so transmission-level

voltage must be reduced to values compatible with end-use equipment. The transformer,

which only works with alternating current, is an efficient way to change voltages. The

competition between the DC of Thomas Edison and the AC of Nikola Tesla and George

Westinghouse was known as the War of Currents, with AC emerging victorious. Practical



manipulation of DC voltages only became possible with the development of high power

electronic devices such as mercury arc valves and later semiconductor devices, such

as thyristors, insulated-gate bipolar transistors (IGBTs), high power

capable MOSFETs (power metal–oxide–semiconductor field-effect transistors) and gate

turn-off thyristors (GTOs).

4.2 History of HVDC transmission

Figure 5: 150 KV mercury arc valve converter for transmitting AC hydropower voltage to long distance.

The first long-distance transmission of electric power was demonstrated using direct

current in 1882 at the Miesbach-Munich Power Transmission, but only 2.5 kW was

transmitted. An early method of high-voltage DC transmission was developed by the Swiss

engineer Rene Thury and his method 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 voltage. Each set was insulated from ground and driven by

insulated shafts from a prime mover. The line was operated in constant current mode, with

up to 5,000 volts on 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 120 km The Moutiers-Lyon system transmitted 8,600 kW of hydroelectric

power a distance of 124 miles, including 6 miles of underground cable. The system used


http://en.wikipedia.org/wiki/File:Mercury_Arc_Valve,_Radisson_Converter_Station,_Gillam_MB.jpg


eight series-connected generators with dual commutators for a total voltage of 150,000 volts

between the poles, and ran from about 1906 until 1936. Fifteen Thury systems were in

operation by 1913.Other Thury systems operating at up to 100 kV DC operated up to 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 conversion technique attempted for conversion of direct

current from a high transmission voltage to lower utilization voltage was to charge series-

connected batteries, then connect 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 connections, and the inherent energy inefficiency of a

battery charge/discharge cycle.

The grid controlled mercury arc valve became available for power transmission

during the period 1920 to 1940. 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, 115 km

buried cable link was designed for the city of Berlin using mercury arc valves (Elbe-

Project), 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.

Introduction of the fully-static mercury arc valve to commercial service in 1954

marked the beginning of the modern era of HVDC transmission. A HVDC-connection was

constructed by ASEA between the mainland of Sweden and the island Gotland. Mercury arc

valves were common in systems designed up to 1975, but since then, HVDC systems use

only solid-state devices. From 1975 to 2000, line-commutated converters (LCC)

using thyristor valves were relied on. According to experts such as Vijay Sood, the next 25

years may well be dominated by force commutated converters, beginning with capacitor

commutative converters (CCC) followed by self commutating converters which have



largely supplanted LCC use. Since use of semiconductor commutators, hundreds of HVDC

sea-cables have been laid and worked with high reliability, usually better than 96% of the

time.

4.3 Rectifying and inverting systems

Rectification and inversion use essentially the same machinery. Many substations are

set up in such a way that they can act as both rectifiers and inverters. At the AC end a set of

transformers, often three physically separate single-phase transformers, isolate the station

from the AC supply, to provide a local earth, and to ensure the correct eventual DC voltage.

The output of these transformers is then connected to a bridge rectifier formed by a number

of valves. The basic configuration uses six valves, connecting each of the three phases to

each of the two DC rails. However, with a phase change only every sixty degrees,

considerable harmonics remain on the DC rails.

An enhancement of this configuration uses 12 valves (often known as a twelve-pulse

system). The AC is split into two separate three phase supplies before transformation. One

of the sets of supplies is then configured to have a star (wye) secondary, the other a delta

secondary, establishing a thirty degree phase difference between the two sets of three

phases. With twelve valves connecting each of the two sets of three phases to the two DC

rails, there is a phase change every 30 degrees, and harmonics are considerably reduced.

In addition to the conversion transformers and valve-sets, various passive resistive and

reactive components help filter harmonics out of the DC rails.



5. HVDC TRANSMISSION BASED ON VSC’S

Voltage Source Converters (VSC) have for the first time been used for HVDC

transmission in a real network. Experience from the design and commissioning of the

transmission shows that the technology has now reached the stage where it is possible to

build high voltage converters utilizing Insulated Gate Bipolar Transistors (IGBTs).

Operation and system tests have proved that the properties that have been discussed for

many years regarding VSCs for HVDC are a reality now. They include independent control

of active and reactive power, operation against isolated ac. networks with no generation of

their own, very limited need of filters and no need of transformers for the conversion

process. This is only the first installation of VSC for HVDC.

The development of semiconductors and control equipment is presently very rapid

and it is evident that this technology will play an important role in the future expansion of

electric transmission and distribution systems.

VSC based HVDC Transmission Layout.

5.1 Converter Technologies

5.1.1 HVDC Classic

Using HVDC to interconnect two points in a power grid, in many cases is the best

economic alternative, and furthermore it has excellent environmental benefits. The HVDC

technology (High Voltage Direct Current) is used to transmit electricity over long distances



by overhead transmission lines or submarine cables. It is also used to interconnect separate

power systems, where traditional alternating current (AC) connections can not be used.

ABB pioneered the HVDC technology and is the undisputed world leader in the HVDC

field.

In a high voltage direct current (HVDC) system, electric power is taken from one point in a

three-phase AC network, converted to DC in a converter station, transmitted to the

receiving point by an overhead line or cable and then converted back to AC in another

converter station and injected into the receiving AC network. Typically, an HVDC

transmission has a rated power of more than 100 MW and many are in the 1,000 - 3,000

MW range. HVDC transmissions are used for transmission of power over long or very long

distances, because it then becomes economically attractive over conventional AC

lines. With an HVDC system, the power flow can be controlled rapidly and accurately as to

both the power level and the direction. This possibility is often used in order to improve the

performance and efficiency of the connected AC networks.

5.1.2

HVDC Light

The Pulse Width Modulated Voltage Source Converter a close to ideal component in

the transmission network. From a system point of view it acts as a motor or generator

without mass that can control active and reactive power almost instantaneously.

Conventional HVDC converter technology is based on the use of line-commutated or

phase-commutated converters (PCC). With the appearance of high switching frequency

components, such as IGBTs (Insulated Gate Bipolar Transistor) it becomes advantageous to

build VSC (Voltage Source Converters) using PWM (Pulse Width Modulation)

Technology.

The key part of the HVDC Light converter consists of an IGBT valve bridge. No

special converter transformers are necessary between the valve bridge and the AC-grid.

Aconverter reactor can separate the fundamental frequency from the raw PWM waveform.



If the desired DC voltage does not match the AC system voltage, a normal AC transformer

may be used in addition to the reactor. A small shunt AC-filter is placed on the AC-side of

the reactor. On the DC-side there is a DC capacitor that serves as a DC filter too.

5.1.2.1 Pulse width modulation technology for HVDC Light

This is an entirely different concept compared with the classical HVDC converter.

In the PWM bridge switching very fast between two fixed voltages creates the AC-voltage.

The desired fundamental frequency voltage is formed through low pass filtering of the high

frequency pulse modulated voltage.

VSC three phase converter



The PWM pattern and the corresponding power frequency voltage of a VSC converter

With PWM it is possible to create any phase angle or amplitude (up to a certain limit) by

changing the PWM pattern, which can be done almost instantaneous. Hereby PWM offers

the possibility to control both active and reactive power independently.

This makes the Pulse Width Modulated Voltage Source Converter a close to ideal

component in the transmission network. From a system point of view it acts as a motor or

generator without mass that can control active and reactive power almost instantaneously.

Furthermore, it does not contribute to the short circuit power as the AC current can be

controlled.

5.1.2.2 Active and reactive power control

The fundamental frequency voltage across the converter reactor defines the power

flow between the AC and DC sides. Changing the phase angle between the fundamental

frequency voltage generated by the converter (Ug) and the voltage on the AC bus controls

the active power flow between the converter and the network. The reactive power flow is

determined by the amplitude of Ug, which is controlled by the width of the pulses from the

converter bridge. The control is performed by the MACH2 system developed by ABB. All

functions for control, supervision and protection of the stations are implemented in software

running in a family of microprocessor circuit boards.



5.1.2.3 Station Design

The majority of equipment in a HVDC Light is delivered in enclosures and tested at

factory before shipment. For example the IGBT valves, the control equipment, the valve

cooling equipment and the station service are all delivered in enclosures. This simplifies the

civil works and also makes the installation and commissioning faster than for a traditional

converter. The HVDC Light concept lends itself to a modular standardized design with a

high degree of factory testing.

5.1.3 HVDC-Plus

Siemens Power Transmission and Distribution (PTD) launched a high-voltage direct

current transmission (HVDC) system on the market, based on a new generation of

converters using voltage-sourced converter (VSC) technology. The HVDC Plus system is

suitable for direct current links up to the 1,000 MW power range where line-commutated

converters are still used exclusively today. In contrast to line-commutated converter

technology, the HVDC-Plus system operates with power semiconductors which have both

turn-on and turn-off capability. As a result, the commutation processes in the converter are

independent from the AC system voltage. Next to other applications the transmission

system allows the low-loss transport of electrical energy from offshore wind farms to the



coast and the economical and environmentally-friendly supply of power to oil platforms

from the AC system on the mainland.

The high-voltage direct-current transmission system HVDC Plus makes use of all the

advantages offered by self-commutated voltage-sourced converter technology. This

includes grid access to very weak AC systems as well as supplying passive networks.

Active and reactive power can be controlled independently. The capability of very rapid

control and protection actions of the converter makes the system highly dynamic, which is

necessary especially for AC faults and system disturbances. Last but not least, the black-

start capability function enables the HVDC system to restart a collapsed network.

HVDC Plus operates with an innovative multilevel converter concept, which offers in

comparison to existing VSC solutions additional significant benefits. Amongst others these

are low losses due to low switching frequencies, full modular design and therewith a

straightforward scalability. In addition to the operation as back-to-back link and as cable

transmission, HVDC Plus can also be used in combination with overhead lines.

Offshore wind farms in the power range of a few hundred megawatts usually demand for

particularly high requirements of power transmission. Many wind farms are located

offshore over a hundred kilometers from the AC system on the coast. This generally

exceeds the economical and technical limits of AC-based cable transmission systems and

calls for new DC transmission concepts, for example based on the HVDC Plus system.

Oil platforms, which have a high power demand, also require a high level of power quality

for the transmission if they are to be supplied from the mainland and not locally as in the

past. Power delivery from the mainland not only increases the availability of the electric

supply on the drilling rigs but also renders the maintenance and servicing work unnecessary

for the small power plants currently used on the platforms. This also eliminates

environmentally harmful CO2 and NOX emissions from the small power plants usually

used at sea.

Submarine cables are used exclusively for power transmission across the sea.

However, the transport of power in the form of alternating current via cable is limited to a



length of about 80 to 120 kilometers for technical and economical reasons, depending on

the power to be transmitted. For this reason, direct-current transmission is the preferred

solution.

5.2 Configurations

5.2.1 Monopole and earth return

In a common configuration, called monopole, one of the terminals of the rectifier is

connected to earth ground. The other terminal, at a potential high above, or below, ground,

is connected to a transmission line. The earthed terminal may or may not be connected to

the corresponding connection at the inverting station by means of a second conductor.

If no metallic conductor is installed, current flows in the earth between the earth electrodes

at the two stations. Therefore it is a type of single wire earth return. The issues surrounding

earth-return current include

Electrochemical corrosion of long buried metal objects such as pipelines

Underwater earth-return electrodes in seawater may produce chlorine or otherwise

affect water chemistry.

An unbalanced current path may result in a net magnetic field, which can affect

magnetic navigational compasses for ships passing over an underwater cable.

These effects can be eliminated with installation of a metallic return conductor

between the two ends of the monopolar transmission line. Since one terminal of the

converters is connected to earth, the return conductor need not be insulated for the full

transmission voltage which makes it less costly than the high-voltage conductor. Use of a

metallic return conductor is decided based on economic, technical and environmental

factors. Modern monopolar systems for pure overhead lines carry typically 1,500 MW. If

underground or underwater cables are used the typical value is 600 MW.



Most monopolar systems are designed for future bipolar expansion. Transmission line

towers may be designed to carry two conductors, even if only one is used initially for the

monopole transmission system. The second conductor is either unused or used as electrode

line or connected in parallel with the other (as in case of Baltic-Cable).

5.2.2 Bipolar

In bipolar transmission a pair of conductors is used, each at a high potential with

respect to ground, in opposite polarity. Since these conductors must be insulated for the full

voltage, transmission line cost is higher than a monopole with a return conductor. However,

there are a number of advantages to bipolar transmission which can make it the attractive

option.

Figure 6: Bipolar system pylons of the HVDC Cable

Under normal load, negligible earth-current flows, as in the case of monopolar

transmission with a metallic earth-return. This reduces earth return loss and environmental

effects.

When a fault develops in a line, with earth return electrodes installed at each end of

the line, approximately half the rated power can continue to flow using the earth as a return

path, operating in monopolar mode.

Since for a given total power rating each conductor of a bipolar line carries only half

the current of monopolar lines, the cost of the second conductor is reduced compared to a

monopolar line of the same rating.


http://en.wikipedia.org/wiki/File:HVDCPylons.jpg


In very adverse terrain, the second conductor may be carried on an independent set of

transmission towers, so that some power may continue to be transmitted even if one line is

damaged.

A bipolar system may also be installed with a metallic earth return conductor.

Bipolar systems may carry as much as 3,200 MW at voltages of +/-600 kV. Submarine

cable installations initially commissioned as a monopole may be upgraded with additional

cables and operated as a bipole.

A block diagram of a bipolar HVDC transmission system, between two stations

designated A and B. AC - represents an alternating current network CON - represents a

converter valve, either rectifier or inverter, TR represents a power transformer, DCTL is the

direct-current transmission line conductor, DCL is a direct-current filter inductor, BP

represents a bypass switch, and PM represent power factor correction and harmonic filter

networks required at both ends of the link. The DC transmission line may be very short in a

back-to-back link, or extend hundreds of miles (km) overhead, underground or underwater.

One conductor of the DC line may be replaced by connections to earth ground.

Figure 7: Bipolar HVDC transmission system



5.2.3 Back to back

A back-to-back station (or B2B for short) is a plant in which both static inverters and

rectifiers are in the same area, usually in the same building. The length of the direct current

line is kept as short as possible. HVDC back-to-back stations are used for coupling of

electricity mains of different frequency and phase number and two network of the same

nominal frequency but no fixed phase relationship. The DC voltage in the intermediate

circuit can be selected freely at HVDC back-to-back stations because of the short conductor

length. The DC voltage is as low as possible, in order to build a small valve hall and to

avoid series connections of valves. For this reason at HVDC back-to-back stations valves

with the highest available current rating are used.

5.2.4 Systems with transmission lines

The most common configuration of an HVDC link is two inverter/rectifier stations

connected by an overhead power line. This is also a configuration commonly used in

connecting unsynchronised grids, in long-haul power transmission, and in undersea cables.

Multi-terminal HVDC links, connecting more than two points, are rare. The configuration

of multiple terminals can be series, parallel, or hybrid (a mixture of series and parallel).

Parallel configuration tends to be used for large capacity stations, and series for lower

capacity stations. An example is the 2,000 MW Quebec - New England

Transmission system opened in 1992, which is currently the largest multi-terminal HVDC

system in the world.

5.2.5 Tripole: current-modulating control

A newly patented scheme (As of 2004) (Current modulation of direct current

transmission lines) is intended for conversion of existing AC transmission lines to HVDC.

Two of the three circuit conductors are operated as a bipole. The third conductor is used as a

parallel monopole, equipped with reversing valves (or parallel valves connected in reverse

polarity). The parallel monopole periodically relieves current from one pole or the other,

switching polarity over a span of several minutes. The bipole conductors would be loaded to



either 1.37 or 0.37 of their thermal limit, with the parallel monopole always carrying +/- 1

times its thermal limit current. The combined RMS heating effect is as if each of the

conductors is always carrying 1.0 of its rated current. This allows heavier currents to be

carried by the bipole conductors, and full use of the installed third conductor for energy

transmission. High currents can be circulated through the line conductors even when load

demand is low, for removal of ice.

Combined with the higher average power possible with a DC transmission line for the

same line-to-ground voltage, a tripole conversion of an existing AC line could allow up to

80% more power to be transferred using the same transmission right-of-way, towers, and

conductors. Some AC lines cannot be loaded to their thermal limit due to system stability,

reliability, and reactive power concerns, which would not exist with an HVDC link.

The system would operate without earth-return current. Since a single failure of a

pole converter or a conductor results in only a small loss of capacity and no earth-return

current, reliability of this scheme would be high, with no time required for switching. As of

2008, no tri-pole conversions are in operation, although a transmission line in India has

been converted to bipole HVDC.

5.3 Possible Connections

Three options for connecting an offshore wind farm have been examined to establish

the electrical characteristics, feasibility and costs.

5.3.1 Multiple 33 kV links

This appears to be the cheapest option for distances offshore up to 20 km and power

levels up to 200 MW. Outside these ranges the cable laying costs and electrical losses are

the limiting factors. Also it must be recognized that 200 MW is a large injection of power

for any distribution circuit to accept and so there may well be limitations imposed by the

utility for large wind farms. This option has no wind farm transformers offshore, only the

individual turbine transformers. The wind farm is divided into blocks. Each block is fed by



its own, 3 core cable from shore. The maximum practical conductor size for operation at 33

kV appears to be 300 mm2, giving a block rating in the range 25 to 30 MW. If necessary,

two blocks could be connected by one cable, while the faulty cable is repaired.

5.3.2 Single 132 kV link and transformer

This is the simplest system with a higher transmission voltage for the link to the

shore. From discussion with cable manufacturers, 132 kV is their preferred voltage rather

than 66 kV. However, an offshore substation is required, on a separate platform. Also, if the

link fails, the whole wind farm is disconnected. This option is expensive for all distances

out to 30 km and power levels less than 200 MW. Putting a substation offshore for this type

of link is novel and the first few would be expensive and require careful monitoring. Thus,

it is unlikely to be used for the first offshore wind farms around the UK.

5.4 HVDC link

Advances in power electronic technology have led to the development of HVDC

systems at lower ratings than were previously cost effective. For instance, one manufacturer

has a system in the range 2 to 200 MW based on IGBT voltage source converters. Typically

a 110 MW link including cable, might cost £13M. One advantage of voltage source forced

commutated converters, over traditional HVDC current source converters based on

thyristors, is that synchronous rotating machines are not required at each end of the link.

The AC connection voltage at the ends does not have to be the same, possibly saving a site

transformer at the shore. To date only a demonstration system has been installed and there

has yet to be an offshore installation. The technology is in its infancy and further advances

are likely. In the longer term, there is the possibility that offshore turbines will be connected

at DC offshore, making HVDC links more attractive. The HVDC link uses the technology

available at present on the assumption that a marinised version is available. Again a

platform is required to house the offshore converter and switchgear, and the whole wind

farm is lost if the cable fails. This option is too expensive for distances closer to shore than

25 km and for power levels less than 200 MW. There is also a risk, which will decrease

with time, associated with applying this new technology offshore.



6. HVDC CABLE TRANSMISSION

6.1 Advantages of HVDC over AC transmission

The advantage of HVDC is the ability to transmit large amounts of power over long

distances with lower capital costs and with lower losses than AC. Depending on voltage

level and construction details, losses are quoted as about 3% per 1,000 km High-voltage

direct current transmission allows efficient use of energy sources remote from load centers.

Long undersea cables have a high capacitance. While this has minimal effect for DC

transmission, the current required to charge and discharge the capacitance of the cable

causes additional I2R power losses when the cable is carrying AC. In addition, AC power is

lost to dielectric losses.

HVDC can carry more power per conductor, because for a given power rating the

constant voltage in a DC line is lower than the peak voltage in an AC line. In AC power,

the root mean square (RMS) voltage measurement is considered the standard, but RMS is

only about 71% of the peak voltage. The peak voltage of AC determines the actual

insulation thickness and conductor spacing. Because DC operates at a constant maximum

voltage without RMS, this allows existing transmission line corridors with equally sized

conductors and insulation to carry 100% more power into an area of high power

consumption than AC, which can lower costs.

Because HVDC allows power transmission between unsynchronised AC distribution

systems, it can help increase system stability, by preventing cascading failures from

propagating from one part of a wider power transmission grid to another. Changes in load

that would cause portions of an AC network to become unsynchronized and separate would

not similarly affect a DC link, and the power flow through the DC link would tend to

stabilize the AC network. The magnitude and direction of power flow through a DC link

can be directly commanded, and changed as needed to support the AC networks at either

end of the DC link. This has caused many power system operators to contemplate wider use

of HVDC technology for its stability benefits alone.



6.2 Disadvantages

The disadvantages of HVDC are in conversion, switching and control. Further

operating an HVDC scheme requires keeping many spare parts, which may be used

exclusively in one system as HVDC systems are less standardized than AC systems and the

used technology changes fast.

The required static inverters are expensive and have limited overload capacity. At

smaller transmission distances the losses in the static inverters may be bigger than in an AC

transmission line. The cost of the inverters may not be offset by reductions in line

construction cost and lower line loss. With two exceptions, all former mercury rectifiers

worldwide have been dismantled or replaced by thyristor units. Pole 1 of the HVDC scheme

between the North and South Islands of New Zealand still uses mercury arc rectifiers, as

does Pole 1 of the Vancouver Island link in Canada.

In contrast to AC systems, realizing multiterminal systems is complex, as is

expanding existing schemes to multiterminal systems. Controlling power flow in a

multiterminal DC system requires good communication between all the terminals; power

flow must be actively regulated by the control system instead of by the inherent properties

of the transmission line. High voltage DC circuit breakers are difficult to build because

some mechanism must be included in the circuit breaker to force current to zero, otherwise

arcing and contact wear would be too great to allow reliable switching. Multi-terminal lines

are rare. One is in operation at the Hydro Québec - New England transmission from

Radisson to Sandy Pond. Another example is the Sardinia-mainland Italy link which was

modified in 1989 to also provide power to the island of Corsica.

For cable links longer than 40-50 km, DC provides lower Investment costs. The

saving gained from installing only one DC cable instead of three AC cables more than

compensates for the cost of the AC/DC converter stations.



• DC cable transmissions have lower losses than a corresponding AC cable link. The

converter station losses are normally as low as 0.6% per station, and

DC cable losses are only around 0.3-0.4% per 100 km.

• Long AC cables produce high amounts of reactive power requiring shunt reactors at both

ends. In extreme cases the reactive current may seriously reduce the active power

transmission capability. These drawbacks do not arise in a DC cable.

• DC links can connect two asynchronous power grids in cases where it is impossible or

impracticable to establish a synchronous interconnection.

• The high controllability of the DC system can be exploited to improve the operating

conditions of the interconnected grids.

6.3 AC Cable transmission Vs. DC Cable transmission

AC Cable DC Cable

Higher cable costs: more cables needed Lower cable costs: fewer cables needed

Lower power transfer capabilities (per cable) Higher power transfer capabilities (per cable)

Capacity reduction due to charging currents No capacity reduction by charging currents

No additional costs of the converter stationsAdditional costs involved due to the

requirement of converter stations at either

end of the transmission line



7. APPLICATIONS

In a number of applications HVDC is more effective than AC transmission. Examples

include:

Undersea cables, where high capacitance causes additional AC losses. (e.g.,

250 km Baltic Cable between Sweden and Germany)

Endpoint-to-endpoint long-haul bulk power transmission without intermediate 'taps',

for example, in remote areas

Increasing the capacity of an existing power grid in situations where additional wires

are difficult or expensive to install

Power transmission and stabilization between unsynchronised AC distribution

systems

Connecting a remote generating plant to the distribution grid, for example Nelson

River Bipole

Stabilizing a predominantly AC power-grid, without increasing prospective short

circuit current

Reducing line cost. HVDC needs fewer conductors as there is no need to support

multiple phases. Also, thinner conductors can be used since HVDC does not suffer from

the skin effect

Facilitate power transmission between different countries that use AC at differing

voltages and/or frequencies

Synchronize AC produced by renewable energy sources.



8. COST AND ECONOMICS FOR HVDC CABLE TRANSMISSION

Costs vary widely depending on the specifics of the project such as power rating,

circuit length, overhead vs. underwater route, land costs, and AC network improvements

required at either terminal. A detailed evaluation of DC vs. AC cost may be required where

there is no clear technical advantage to DC alone and only economics drives the selection.

However some practitioners have given out some information that can be reasonably well

relied upon:

For an 8 GW 40 km link laid under the English Channel, the following are

approximate primary equipment costs for a 2000 MW 500 kV bipolar conventional HVDC

link

Converter stations ~£110M

Subsea cable + installation ~£1M/km

While choosing the technology used for conversion of AC and DC based on VSC’s,

the HVDC Light is an attractive solution for offshore wind power when HVDC is

considered for offshore wind power, the most attractive technology is the voltage source

technology in ABB version named HVDC Light. The evidence is in the table describing the

differences between the technologies.

Figure 8: Development of HVDC Light ratings and losses

The new converter design gives the following benefits:



Well-proven semiconductor technology with large number of components in

service with identical voltage.

Simple and robust converter design.

Good dynamic properties.

Low losses

Reduced costs

A recent study performed by Econnect, regarding the technological options related to

the UK offshore projects also use voltage source converters as the HVDC alternative. This

study concludes that for the UK projects in a number of projects HVDC would be feasible

particularly if “joint connection” is applied. “Joint connection” is to combine the

transmission for a number of wind parks. The total interconnection cost for the studied

projects are in the range of 250 kEuro/MW to 370 kEuro/MW with an average cost of 270

kEuro/MW. The joint connection alternative shoved an average of 240 kEuro/MW. The

studied range in power and transmission distance is 64 to 1000 MW and 30 – 100 km. The

study suggests that HVDC (Voltage source converters) should be considered particularly in

the joint connection alternatives that also gives the lowest overall costs. This study does not

cover potential transmission reinforcement costs or the cost for power flow equipment. It is

clear that the competitiveness of the HVDC alternative increases with the size of the

projects but also with the transmission distance. The following screening questions based on

the above chart are important.

Need for power transmission 200 - 1000 MW

Need for accurate and fast control

Distance more than 50 km

Difficult to obtain permits for OH-lines

Difficult to find/reach interconnection point in the grid

Difficult to build a substation near the coastline (for reactive power compensation)

Weak AC network

Risk for dynamic instability



Power quality issues

Need for grid black start capability

Need for high availability although occurrence of thunderstorms, windstorms/

hurricanes or heavily icing conditions may apply

Need for compact offshore module

Risk of low harmonic resonances

Need for fast voltage and reactive power control to enhance network security

When the HVDC transmission an interesting alternative, a typical case for HVDC

Light in an offshore application could be of 350 MW transmissions with 70 km sub sea

cable and 30 km land cable

The direct investment cost for HVDC Light option including converters, cables and

installation of cable and converters will be in the range of 110 – 140 MEuro. The range is

primarily given be differences in installation costs and local market conditions. For the AC

cable option there is similarly a range in cost 110 – 140 MEuro. This corresponds in both

cases to 310 – 400 kEuro/MW and gives similar results as in the previously quoted study.

The two alternatives are thus similar in cost and a detailed study for the individual case will

determine the best solution. But other factors should also be considered such that may show

beneficial for the HVDC option:

Grid reinforcement costs may be significant in the AC case but are very unlikely for

a HVDC voltage source solution

Cost for power flow equipment in the AC case

Possibilities to go much further on land with underground cable at very moderate

cost in the HVDC case.

Increased transmission capacity in existing AC grid (HVDC case).

Obtaining cost information on the different options for different wind farm sizes

proved quite difficult as none of the equipment is off-the-shelf. Budget costs and some

simple assumptions on scaling have led to the following conclusions.



8. CONCLUSION

The equipment required for the electrical infrastructure of offshore wind farms is

available. The early offshore wind farms are likely to use electrical designs quite similar to

those adopted for recent on shore developments. A maximum voltage of 33 kV both for the

wind farm collection circuits and for the connection to land is likely in the first instance.

However, as large offshore installations are developed (>100 MW) then HVDC

transmission to shore may be more cost effective. Considerable development work is still

required for the large offshore substations or converter stations which will be required for

large offshore wind farms.



8. REFERENCES

1) http://en.wikipedia.org/wiki/High-voltage_direct_current#High_voltage_transmission

2) http://en.wikipedia.org/wiki/Submarine_power_cable#Submarine_cables_for_AC

3) www.abb.com/cawp/gad02181/18e68b778f900952c1256e4b002b25be.aspx

4) http://energyzarr.typepad.com/energyzarrnationalcom/2009/03/ac-dc-wars-continue-

part-ii.html

5) powersystemsdesign.com/index.php?option=com_content&view=article&id=86:pdf-

full-magazine-archives&catid=21:content&Itemid=87

6) http://en.wikipedia.org/wiki/Submarine_power_cable

7) www.abb.com/cawp/gad02181/c1256d71001e0037c1256d08002e7282.aspx

8) http://energyzarr.typepad.com/energyzarrnationalcom/2009/02/index.html


Documents

AC vs DC Cable Transmission for Offshore