Connection of Renewable Energy Sources through ...

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Connection of Renewable Energy Sources through Grid Constraint Points using HVDC Power Transmission Systems Norman M MacLeod, Non-member Carl D Barker, Non-Member,

Abstract- The use of HVDC as an effective means of transmitting electrical energy now has a 50 year history since the first modern schemes were developed. Technological advances have resulted in HVDC becoming a reliable and efficient means of power transmission, both in competition with, and complementary to, AC transmission schemes. Initially HVDC was used for point – to – point transmission of power, by long distance overhead lines, or submarine cables, or in a few cases by underground cables. In cases where synchronous connection of AC networks was problematic, back – to – back HVDC converters were used to allow power to be transferred without the associated issues of stability, power quality, frequency synchronisation, being involved. In some cases more than two terminals have been used in HVDC schemes. There are two working examples of multiterminal schemes in operation and other schemes with the flexibility to work in a multi-terminal mode. The next generation of HVDC technology is taking the equipment designs from 600kV up to 660kV and 800kV to achieve higher power transmission from 3150MW up to 7200MW in a single corridor. Schemes currently under construction are intended to access sources of renewable energy, principally hydroelectric power, but as discussed in this paper the same rationale will be applied for access to large energy sources derived from photovoltaic, solar concentrator and wind turbine generators. Where network constraints, or “bottlenecks” exist, HVDC may be the ideal solution to access renewable generation sources, without a considerable increase in infrastructure being required. When transmission utilities consider future system expansion HVDC transmission schemes, whether as a long distance interconnectors, a back- to – back between two networks, or embedded within the AC network, can bring major operational advantages to the owner. By its nature HVDC has the ability to deliver increases in real power to a part of a network, without a commensurate increase in the short circuit level of the receiving transmission system. This paper will consider these opportunities and also some of the challenges involved in a range of HVDC scheme configurations. This will cover overhead transmission schemes, submarine cable schemes and back- to – back schemes. The paper will consider the specific issues involved in the design of a multi-terminal HVDC system. In each case the key issues in the planning, design and execution of the schemes will be discussed. As one of the world’s major manufacturers of HVDC systems, AREVA has experience of operation in North and South America, Africa, Europe, the Middle N. Macleod is with AREVA T&D Power Electronic Systems Ltd, St Leonards Ave, Stafford, England (e-mail: [email protected]). C. Barker is with AREVA T&D Power Electronic Systems Ltd, St Leonards Ave, Stafford, England (e-mail: [email protected]). N. Kirby is with AREVA T&D Inc., based in Philadelphia, USA (e-mail: [email protected]).

Neil M Kirby, Member

East, India, China and the Far East. Each of these very different regions presents its own challenges in the design of the converter stations and the execution of the project. The paper will consider the most recent schemes in design and construction, such as the 1800MW Al Fadhili station in Saudi Arabia, the long distance 3000MW ±500kV Three Gorges – Shanghai project and 4000MW ±660kV Ningdong – Shangdong projects in China. All of these projects bring new challenges to the design engineers and require considerable study of the interaction between the HVDC schemes and the AC transmission networks.

Index Terms- inter-connector, HVDC, renewable energy, constraint, VSC

I. INTRODUCTION In its modern implementation HVDC has been used for 50 years as an effective and efficient power transmission medium, either linking different power networks, or embedded within a network. As illustrated in Figure 1 there are three basic scheme implementations, a)

Back – to back schemes, where the two converters are at the same location b) Point – to – point schemes using overhead transmission lines c) Point – to - point schemes using submarine (or underground) cables In some cases the schemes are a hybrid of basic types b) and c). Many point to point schemes consist of a mixture of overhead lines and submarine cables and most submarine cable schemes have underground cable sections close to the converter stations. Network planners, when considering future system expansion or reinforcement may consider the opportunities which HVDC links may bring in comparison with conventional AC connections. It is widely accepted that on an economic basis, for transmission distances greater than about 800km, HVDC is the preferred solution, the higher cost of the converter stations being off-set by the lower costs and losses on the transmission lines. For submarine cable schemes this

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economic evaluation suggests that for distances as short as 40km, HVDC would be the preferred solution. The following section will discuss the technical opportunities together with the challenges involved in implementing HVDC links. The final section will discuss the specific case of multi-terminal operation, in which three converter stations are used, allowing a more flexible operation of the link.

a) back-to-back

DC

1 station AC

AC

b) point – point

DC

Station1

Station2 AC

AC

c) submarine cable

largest Back – to - back station in the world, comprising three independent poles, each of 600MW rating. This station links the 60Hz 380kV transmission of Saudi Arabia to the long distance 50Hz 400kV GCCIA transmission system, which links Kuwait, Bahrain and Qatar [Ref 2,3]. In its final implementation the GCCIA inter-connector will also connect to Oman and United Arab Emirates. A key functionality provided in this scheme is Dynamic Reserve Power Sharing (DRPS), in which upon the detection of a sudden frequency drop as a result of a generator trip in any country the Back – to - back scheme will automatically re-schedule the power flow to provide the necessary power support to the relevant AC system. The full details of the operation of this function are provided in Ref 4. This project illustrates one of the main functions of a Back – to - back scheme, the asynchronous connection of systems which operate at different frequencies. There are examples of such schemes in South America (Uruguay – Brazil), North America (Mexico – USA) and within Japan, which has both 50Hz and 60Hz transmission systems. HVDC provides the ideal means of bi-directional power transmission which would otherwise be impossible. Back – to - back connections may also be used to provide an asynchronous connection between countries which both operate at the same frequency (Finland – Russia, China Russia). In such cases it may not be advisable to directly link the two networks with an AC connection, due to concerns about, -

DC

Station 1

Station 2

AC

-

AC

Submarine Cables Figure 1 – HVDC Schemes

II. BACK – TO BACK CONNECTIONS

The concept of installing the rectifier and inverter stations at the same location, to act as a back – to – back connector has been widely used for many years. In North America there are many examples of such stations providing segmentation between the western and eastern grids of USA/Canada, between Quebec and the USA, between Texas and the rest of the USA and between Texas and Mexico. Such installations normally consist of one or two individual power blocks (poles). An example of a single pole station is the 150MW McNeil converter [Ref 1], which links Alberta to Saskatchewan in Canada. The recently commissioned 1800MW station at Al Fadhili in Saudi Arabia is now the

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increasing short circuit level when linking to a much stronger system potential for system instability in the larger interconnected network propagation of system faults requirement to harmonise operating procedures potential for inter-area oscillations

Back – to - back connections have also been used within countries to separate large systems into smaller asynchronous regions, such as India [Ref 5] and as discussed above USA/Canada. This use of back – to back HVDC provides the benefits as discussed above and acts as a “firewall”, to make the transmission systems more robust against cascading fault conditions. There may be future applications of back – to back technology to segment large synchronous grids, such as the European grid [Ref 6].

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III. POINT – TO – POINT CONNECTIONS For many years the de facto upper limit to overhead line HVDC transmission schemes has been 500kV. Although two early schemes have operated at higher voltages, Cahora – Bassa at 533kV and Itaipu at 600kV, these voltages have not been used in recent schemes. However, in the last few years there has been a renewed interest in DC transmission voltage from 600kV to 800kV and possibly up to 1000kV, now termed Ultra High Voltage Direct Current (UHVDC). This has been driven by the need to access large sources of hydroelectric power, which are remote from the load centers. AREVA is at the forefront of UHVDC activity as discussed in the following sections. A. 600kV transmission Brazil, the fifth largest country in the world, has a rapidly developing economy and a great need to increase its power generation and transmission capacity. It has vast hydroelectric power capability in the West of the country, but this is remote from the major load centers in the East around Rio de Janerio and Sao Paulo. To access this energy reserve, a total of 6350MW of generation will be installed on the Rio Madeira, a tributary of the Amazon River and two UHVDC bi-pole

design, unlike the earlier Itaipu 600kV project which used two series connected 12-pulse bridges. The converters will use the same 5 inch (125mm) 8.5kV thyristor devices as used for the Al Fadhili project, operating at a DC current of XXXXA. The system operators undertook an extensive study to compare the AC and HVDC transmission alternatives. For such a long distance a UHVAC transmission voltage (765kV) plus series capacitor compensation would be required. Although AC transmission provides more flexibility of connections along the route, it was decided that UHVDC gave the greatest overall benefit in terms of costs and line losses. The two bipoles will built by different manufacturers, Bipole 1 by ABB and Bipole 2 by AREVA. As the schemes are connected to the same sending and receiving AC systems it is clear that they will need to have compatible designs and operating strategies to ensure that there will be no adverse interactions in terms of, -

power flow control reactive power control harmonic distortion transient stability commutation failure

There are many examples in the world where HVDC schemes feed into the same AC system or where stations supplied by different manufacturers operate in parallel without any adverse interactions. B. 660kV transmission The Ningdong – Shandong project will be the first scheme to operate at 660kV. It will be located in China, as shown in Figure 3, to take power from the central region to the load centers on the coast. The rated power of the scheme will be 4000MW and for the transmission distance 1335km, a DC voltage of 660kV was chosen by the transmission operator to optimise the technical

Heilongjiang

NEPG Jilin

Liaoning

Xinjiang

Inner Mongolia

Figure 2 Rio Madeira HVDC scheme

NCPGBeijing Tianjin Hebei

Gansu

NWPG

Shanxi

Ningxia

Shandong

Qinghai

schemes will transport 6300MW of this power to the south, as shown in Figure 2. These two schemes are being constructed by different consortia of electrical, mechanical and civil constructors.

Henan Shaanxi Xizang

Jiangsu

Ningdong-Shandong 660kV, 4000MW, 1335km

ECPG

Chongqing & Sichuan

Hubei

Shanghai

Anhui

SWPG

Zheijang

CCPG Guizhou

Hunan

CSG Guangxi

Jiangxi Fujian

Guangdong

Taiwan

Yunnan

Each of the two bi-poles is rated at 3150 MW and will operate at 600kV, the voltage chosen to optimise the overall scheme costs and losses over the transmission distance of 2375km. The converter will be of the single 12-pulse converter bridge

Hainan

Figure 3: Ningdong – Shandong UHVDC scheme and economic design of the scheme. Like the Rio Madeira

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project the thyristor converters will be of the single bridge design, but in this case using 125mm (5 inch) 7.2kV rated thyristors operating at a DC current of 3000A. For projects in China, AREVA is able to use indigenous manufacturers of thyristor devices for both 5 inch and 6 inch designs, working through its local partner [Ref 8]. C. 800kV transmission The highest UHVDC scheme designed to date use 800kV transmission voltage to transport power of up to 7200MW in a single scheme over distances of up to XXXXkm. The first such schemes are currently under construction in China and the converters are based on two series 12-pulse bridges per pole, i.e. the same topology as the Itaipu scheme. In India the first 800kV 6000MW scheme under design may use a single 12-pulse bridge per pole, but for this project will operate with parallel converters, i.e. two rectifiers which are geographically separate and two inverters, which are at the same location. This step in DC voltage to 800kV has required a major research and development exercise to be undertaken to develop new equipment designs for this extremely high voltage. This has included new designs for the following equipment [Ref 9], • thyristor valves, including 150mm (6 inch) thyristors • converter transformers • by-pass switches for series bridges • wall bushings • disconnects • DC current transducers • DC voltage dividers

Figure 4 800kV valve test object

IV. SUBMARINE CABLE CONNECTIONS On the thyristor valve the corona shields, which were suitable for up to 500kV have been re-designed for UHVDC applications.

Sea crossings represent a particular challenge for network planners as the costs and the technical issues of AC cables can

Following a major study of the electrostatic fields using an enhanced version of the well established Finite Element Analysis (FEA) technique, known as Boundary Element Method (BEM), a new corona shield design for the thyristor valve was developed, as shown in Figure 4 [Ref 10,11]. The valve was subject to an extensive series of high voltage tests, including lightning impulse, switching impulse and DC overvoltage tests, the latter including partial discharge measurements. Figure 5 shows a typical flashover under a switching impulse of XXXkV (positive polarity) with a XXm separation from the test object to the floor and wall of the artificial ground plane. A key feature of this new valve design is that it can incorporate the newly developed 150mm (6 inch) thyristors. These devices, rated at 7.2kV and 4500A DC are required for the largest projects in China, rated at 7200MW

Figure 5: Switching surge test at xxxkV

have a major impact on the viability of the scheme. Even for

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relatively short distances HVDC can represent the preferred technical solution to exchange power without the impacts of direct AC connection. The UK – France 2000MW interconnector, although a relatively short (30km) sea crossing, allows the island power system of the UK to remain immune to any disturbances on the large European (UCTE) grid. As the sea crossing is one of the busiest shipping lanes in the world, the scheme owners took the decision to bury the DC cables along their whole length, to prevent damage from ships anchors. Although a significant expense for the project this has prevented any damage to shipping and hence added considerably to the overall reliability of the scheme. Originally built 25 years ago by two separate contractors, who are now part of AREVA, the scheme is presently being refurbished by AREVA to provide a further 30 years of operating life. The thyristor valves, associated cooling systems and control systems will be replaced, for Bipole 1 in 2010 and Bipole 2 in 2011. The Juju I 300MW bi-pole project linked the Korean Mainland with the island of Jeju via a 100km cable operating at ±180kV. When first installed the DC cables were not buried and soon after commercial service began, the cables were damaged by fishing activity, forcing a lengthy outage of the scheme. Following repairs the cables were protected in the areas close to the coasts, although the deep water section the cable is on the sea bed. Originally intended as the sole source of power to the island, such has been the load growth on the island since the scheme was commissioned in 1997, that a second HVDC inter-connector has been ordered. This scheme, known as Jeju II is rated at 400MW and will operate at ±250kV. This scheme has a 105km submarine cable plus 17km of underground cables linking the two stations. In many countries off-shore windfarms are being developed to access renewable energy resources. Initially installed in the near off-shore, where AC connections are technically and economically viable, new and larger schemes are being considered for the far off-shore, (>50km). Here HVDC will be the preferred technical and economic option, but classic HVDC as discussed above has severe limitations for such applications. These include, the need for a source of voltage at both terminals large footprint due to switched reactive power banks (harmonic filters) - coarse reactive power control - inability to work into a weak system, without dynamic reactive power support - difficulty in achieving low reverse power transfer capability for emergency conditions These factors can be overcome by the new generation of Voltage Source Converter (VSC) HVDC schemes, which are bases on high power transistors as the switching device. This technology can overcome the limitations of classic HVDC, but

to date have higher operational losses than classic HVDC. Depending on the scheme topology and control used, a VSC converter station may have losses of 1.2 – 2.0% of rating, compared with the losses in a classic HVDC converter station of 0.75% of rating. The impact of the higher losses must be considered together with smaller footprint, typically 50 – 60% of a classic scheme, and the other benefits, when considering the overall economic viability of an off-shore HVDC scheme. V. POWER CORRIDORS

A key issue facing network planners is the need to evacuate power from renewable energy sources through AC transmission systems. These may be existing HV transmission lines, which in many cases, due to restriction on capacity, may be either thermally or stability limited, hence may act as a constraint point on the network preventing access to the energy sources. In other cases additional transmission lines may be required, but this may involve extensions to the right of way and significant project delays in land acquisition and planning issues. The use of HVDC as a transmission medium can relieve such power constraint points in two ways, -

installing HVDC lines instead of AC lines in a new transmission corridor

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converting existing AC lines to DC lines, which could involve retaining the existing insulators and conductors, re-insulating the line, or re-insulating and re-conductoring the line.

As discussed in Ref 11. the use of HVDC rather than AC can produce a significant increase of power transmission in the same corridor. Depending on the AC transmission systems 480MVA

1440MW

-

+

-

Unchanged tower body and foundations

220kV AC

±380kV DC

Figure 6: HVDC gives 3 times increase in power

considered, from 220kV to 400kV and the choice of HVDC system voltage, from ±380kV to ±600kV, the increase in power flow in a DC circuit can be from 1.73 to 3.0 times the power flow in the AC circuit. This concept of conversion of AC lines to HVDC lines is shown in Fig. 6. Here the towers and foundations remain un-changed and the insulators are

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modified to accommodate the DC conductors. The visual impact of the transmission lines is un-changed and no additional lines are required for the increased power flow. VI. MULTI-TERMINAL HVDC

One of the pioneering schemes of the HVDC business, built in 1968, was the link from Sardinia (rectifier station) to the Italian mainland (inverter station). This scheme crosses the island of Corsica and consists of a mixture of submarine cable and overhead line. In the original design provision was made for a future (inverter) tap connection to provide power into Corsica, which was installed in 1992. This is one of only two genuine multi-terminal schemes in the world, i.e. having a tap connection part way along the DC line. The other scheme is in Canada/USA., which was originally designed to have five terminals, but difficulties in operation meant that it only operated as a three terminal scheme. Some other schemes can parallel rectifiers and inverters, to share the same transmission line, thus having multiple terminals, but do not have a tapping point. A multiplicity of rectifiers can be included in a line commutated HVDC scheme with relative simplicity, but multiple inverters can give rise to complex control systems and the need for additional plant. The advent of VSC technology will allow the creation of genuine multi-terminal HVDC operation. Each terminal of the scheme, whether a rectifier or inverter, can be considered to be functionally independent from the others, as each creates its own AC voltage from the common DC voltage. No polarity reversal is required to change from rectifier to inverter operation or vice versa, as is the case with line commutated HVDC, only a change of magnitude of the rectifier and inverter DC voltage. Thus a multi terminal VSC HVDC system could have several rectifier stations, feeding in power from several wind farms or photovoltaic/solar generators and several inverters feeding out power to different load centers. The concept is illustrated in Fig 7, which shows a HVDC transmission line, with three connected rectifier stations (R) importing power from renewable energy sources and three connected inverter stations (I), exporting power to load centers. This concept allows a staged construction of a multi-terminal DC scheme. Following an initial scheme comprising one rectifier and one inverter, further converter stations can be installed as required to access newly developed energy sources or to feed new or existing load centers. Communications will be required between the different converter stations to schedule the power flows and respond to emergency outage conditions. The aim of such a multiterminal scheme would be that each converter station could operate virtually autonomously and can be designed and

supplied at different stages of the overall project probably by different manufacturers. Such HVDC schemes based on VSC technology could be a viable alternative to AC transmission systems, as they have lower overall scheme costs above about 800km transmission distances and can now approach the flexibility of connection of AC systems. However, a multi-terminal scheme, as shown in Figure 7 will require a high voltage DC circuit breaker, to enable faulted sections of the scheme to be isolated, in the event of a permanent DC side fault. The operational and economic impact of de-energising the complete scheme to allow mechanical isolation of a faulted section, would be unacceptable. VII. CONCLUSIONS HVDC has proven itself to be an adaptable and reliable technology, able to provide economic and technical benefits to transmission system operators. Scheme designs are available from AREVA, covering all of the arrangements used throughout the world for DC transmission, up to the highest voltages now being considered. Each project has is own R

Wind Generation

R R PV Generation

Solar Generation

I I Industrial Center

Minor Load Center I Major Load Center

Figure 7: Multi-terminal HVDC concept diagram

challenges, whether system related, or environmental, which can be overcome to build schemes which can meet the highest reliability and energy availability requirements. With the advent of VSC HVDC technology, true multi-terminal schemes can now be proposed which would provide the interconnection of remote sources of renewable energy into the major transmission grids feeding large load centers.

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VIII. REFERENCES [1]

[2]

R P Burgess, J D Ainsworth, H L Thanawala, M Jain, R S Burton, “Voltage/Var control at the McNeil Back – to Back converter station”, Paper 14-104, CIGRE Conference, Paris 1990 B T Barrett, N M MacLeod, A A Ebrahim, R Azar. “GCC Interconnector Project Phase 1 : Operational requirements and planning studies for the Interconnector and the HVDC converter station” GCC/CIGRE Regional conference, Dubai, 2007

[3]

B T Barrett, N M MacLeod, S Sud, A I Al-Mohaisen, R S Al Nasser, “Planning and design of the 1800MW Al Fadhili HVDC Inter-connector in Saudi Arabia”, paper B4-113, CIGRE Conference, Paris, 2008

[4]

S Sadullah, A Ebrahim, “Application of a HVDC link to promote stability by sharing dynamic reserve power after geberation deficiencies”, IEEE PSCE conference, Seattle, USA, 2009

[5]

J D Wheeler, J L Haddock “Chandrapur Back - to Back Scheme in India”, International Conference on Power System Technology, Delhi, India, October 2001.

[6]

N M MacLeod, D R Critchley and R E Bonchang, “Enhancing the control of large AC transmission systems using HVDC technology”, PowerGrid Europe conference, Madrid, Spain, 2007 C C Davidson, R M Preedy and J Wen, “The design and type testing of the HVDC thyristor valve for the Lingbao 2 back – to – back project using 6 inch thyristors”, EPRI HVDC/FACTS conference, Westminister, Co, USA, 2009.

[7]

[8]

N M MacLeod, R G Wilson and S Lelaidier, “ The development of a range of products for turn-key ±800kV HVDC power transmission schemes”, GridTech conference, Delhi, India, 2009

[9]

J Sturgess, A Baker, N M MacLeod, and F Perrot, “Development of insulation structures for thyristor valves for use on 800kV HVDC transmission schemes”, Powercon conference, Delhi, India, 2008

[10]

N M MacLeod, J Sturgess, A Baker and F Perrot, “A new generation of thyristor valves for 800kV HVDC projects”, IEC/Cigré 2nd International symposium for standards on UHV transmission, Delhi, India, 2009.

[11]

H.L. Thanawala, M.H. Baker, G.R. Moore, “Discussion on embedding of DC transmission in AC networks” Cigré Symposium 1999, London IX. BIOGRAPHIES

Norman MacLeod joined AREVA in 1976 and since then has worked extensively in the fields of HVDC and FACTS. He is presently the Technology Director of the Power

Electronics unit. He is a Chartered Engineer, a Fellow of the IET, a member of the IEEE and CIGRE. Carl Barker joined AREVA in 1989, initially working on the design and development of individual projects and then managing technical aspects across many projects. He is presently the Chief Engineer, Systems within the HVDC group. He is a Chartered Engineer and a member of the IET, IEEE and CIGRE. Neil Kirby joined AREVA in 1982 and has worked on the design of HVDC projects, in the areas of control hardware and software, system design, and overall project engineering. This has included extensive periods of site work and commissioning tests. In 2003 he moved to the USA where he is presently Business Development Manager for the Power Electronics business. He is a member of IEEE and CIGRE.