* carsten.bartzsch@siemens.com

DESIGN ASPECTS OF THE INTEGRATION OF THE NEW ZEALAND HVDC POLE 3 PROJECT

M. ZAVAHIR, I. HUNT,

K. MARTIN P. HOBY C. BARTZSCH *, A. LUDEBUEHL,

U. KINDLER

TRANSPOWER CPG NZ Ltd SIEMENS AG NEW ZEALAND GERMANY

SUMMARY The HVDC Inter-Island link is a vital transmission system between Benmore substation in the South Island and Haywards just north of Wellington, enabling the transfer of power between the South and North Islands substation of New Zealand [1][2]. HVDC technology is used because it is more effective for power transfer over long distances (535 km + 35 km overhead line sections and 40 km submarine power cables across Cook Strait). This paper highlights some key aspects of the HVDC Pole 3 Project, including relevant seismic design considerations, for all main plant items and taking also site specific conditions such as the very limited space into account. Both substations must have high level of seismic resilience, particularly Haywards substation which is located in a region with known fault lines. Stringent seismic analysis and testing of key plant components has been undertaken to achieve seismic qualification to IEEE 693, 2005 high performance level. The substation layout has been a major challenge due to tight space constraints and the need to stage construction in live brown filed substations whilst maintaining full operation of existing Pole 2 and providing safety improvements and necessary future proofing. One of the primary design aspects is the design coordination between the existing Pole 2 and the new plant of Pole 3. For example, the arrester arrangement, the V-I characteristics and the protective levels have been selected such that the rating of the existing plant will not be exceeded. Since the rating of Pole 3 is considerably higher than the rating of Pole 2 (thus the rating of the bipolar scheme is increased) additional adjustments are required. Various components installed at the DC neutral bus need to be replaced by components with higher rating.

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Considering the relative low short circuit levels at Haywards converter station as well as the increased rating of the HVDC Inter-Island link supplementary modulation controls and runbacks are implemented in the HVDC control system to ensure stable operation under all relevant system conditions. Moreover, a unique reactive power control (RPC) system has been developed to provide coordinated control of all reactive power supply and absorption plant (AC filters, shunt reactors, synchronous condensers) and the on-load tap-changers of the autotransformers at Haywards, Wilton andTakapu Rd. The installation of a SVC PLUS (STATCOM type) unit in Stage 1-2 and a second unit at a future Stage 3 at Haywards will enable the HVDC link to meet the specified performance requirements, providing suitable mitigation of potential overvoltages (TOV) and reactive support during undervoltage conditions [3] [4]. The paper introduces the design and performance criteria for the Pole 3 AC and DC filters and how the stringent power quality requirements, in particular those relating to harmonic limits in the New Zealand AC system, were addressed. The design of the new AC filters has to provide suitable sharing of harmonic currents between new and existing filters to achieve compliance with specified performance criteria. Furthermore, the paper discusses the compatibility aspects necessary to ensure that the new filters do not cause undue loading of the existing AC harmonic filters during normal operation or during AC system contingency events. Symmetry between the filters to the extent possible is essential to avoid the trip of filter sub-banks and to ensure that neither the existing nor the new AC filter components will be stressed to the point where there would be a detrimental effect on the life of the components. KEYWORDS HVDC Systems – Bipolar Systems - Design - Performance - Rating – AC Filter – Reactive Power – SVC – STATCOM – Seismic Design – Brown Field

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1 SYSTEM DESCRIPTION

The HVDC scheme is a vital link for New Zealand as it balances the distribution of energy between islands, carrying electricity from where it is generated to where it is needed [1][2]. As much of New Zealand’s electricity is supplied by renewable generation, this is more sustainable and in addition, facilitates the development of renewable generation like wind and hydro, which is often located remotely from major load centres. Most important, the HVDC link provides:

a) the South Island with access to the North Island’s gas and coal generation (important for the South Island during dry winter and summer periods); and

b) the North Island with access to the South Island’s large hydro generation (important for the North Island during peak winter periods).

The bipolar link consists of two separate circuits. Pole 2 commissioned 1992 will stay in service. The Pole 1 equipment based on mercury-arc valves will be replaced with Pole 3 (renamed) using latest thyristor technology. The HVDC Pole 3 Project in progress will be built in two stages resulting in a capacity increase of the overall HVDC link to 1000 MW from 2012 and 1200 MW from 2014. A third stage (subject to approval) will enable the bipole capacity to be increased to 1400 MW with the addition of submarine cable and reactive support capacities. Fig. 1 shows the HVDC link including reactive power control components at each station. The six 16 kV, 90 MW generators at Benmore are connected via 3 x three-winding transformers which will be in place once the generator reconfiguration project is completed by Meridian Energy Ltd. Also shown are the two SVC PLUS (Statcoms) and staging of filters.

Non Transpower Assets

16 Mvar

16 Mvar

C7-C1065 Mvar

each

BENMORE220 kV

HAYWARDS220 kV

Pole 2 (existing thyristor

Converters 700 MW)

535 km DC line section – South

Island

40 km Cook Strait Cables

35 km DC line section

North Island

40 km Cook Strait Cables

+ 350 kV

- 350 kV

Pole 3(new thyristor

converters 700 MW)

HAYWARDS110 kV

C7

C8

C9

C10

6 x 90 MW BENMOREGenerators

16 kV

±60 Mvar eachStatic Device

F3

F4

79.3 Mvar

79.3 Mvar

Stage 1

Existing

Stage 2

Stage 3

F5A/5B

F6B

109 Mvar

109 Mvar

F8

F7

F6

79 Mvar

F5

79 Mvar

F7

80 Mvar

F8

80 Mvar

F3

F4

106.3 Mvar

106.3 Mvar

Cable 6

Cable 4

Cable 5

Cable 7

40 Mvar

C1

60 Mvar

T1

C4C335 Mvar

each

T5

C2 60 Mvar

T2

R5

40 Mvar

R1

Statcom1

Statcom2

F6A/

Fig. 1: Schematic diagram of proposed New Zealand HVDC Link Upgrade The thyristor converters of Pole 2 are rated for 560 MW (350 kV, 1600 A) with a continuous overload capacity of 700 MW. Pole 3 system has a nominal continuous power transfer capacity of 700 MW (350 kV, 2000 A), a continuous overload capacity of 770 MW (with redundant cooling) and a 30 minute overload capacity of 1000 MW (2857 A, without redundant cooling). A reduced DC voltage operation mode has been provided on new Pole 3 to allow operation at 250 kV (0.71 pu) under conditions where the DC line insulators are contaminated and cannot withstand full voltage.

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2 SITE SPECIFIC CONDITIONS

2.1 Seismic Design

The northern most converter station at Haywards substation is located in a region of high seismicity being only a few hundred metres from an active geological fault capable of producing a magnitude 7.6 earthquake. The southern converter station at Benmore is situated in a region of lower seismicity but is designed to the same standards as the northern station. To achieve a high level of seismic resilience, Transpower specified a strategy that required, structural diversity between the new Pole 3 and the existing Pole 2 in an attempt to avoid common mode failures, seismic isolation of the converter building housing the thyristor valves, converter transformers and control system, qualification of outdoor equipment in accordance with IEEE 693 including shake table testing of most plant items, and additional spares to be provided for plant items that could not meet the specified design level. Stringent seismic analysis and testing of key plant components has been undertaken to achieve seismic qualification to IEEE 693, 2005 high performance level. The vertical component of the ground acceleration is specified as 100% of the horizontal (pga of 9.81m/sec²) recognising that peak vertical accelerations at sites close to major faults can be as high or even exceed peak horizontal accelerations. In addition to qualifying the plant to IEEE 693 High, the seismic performance was assessed based on the 2,500 year return period spectra for the site which in the case of the Haywards substation site exceeds the IEEE 693 High Performance level spectra. This performance assessment is used to identify the need for additional spares or alternative mitigation strategies. The buildings were designed using site specific earthquake spectra for compliance with local building code requirements rather than the IEEE 693 spectra used for plant qualification (Fig. 2).

Fig. 2: Cut away view of valve hall showing seismic isolation bearings and sliders. Equipment installed in the seismically (base) isolated buildings is treated differently. The converter building containing the thyristor valves, converter transformers, pole control equipment and auxiliary plant is seismically isolated using Lead Rubber Bearings with a free oscillation amplitude of ±600mm effectively decoupling the building from horizontal ground earthquake motion (Fig. 3). The effects of base isolation are accounted for, and seismic analysis is performed for position specific stresses which are determined from the response of

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the building to a set of historic earthquakes selected based on similarity to the site conditions (soil types, type and proximity of faults) of the Haywards and Benmore converter stations. The selected earthquake records are scaled to match the design spectra.

Fig. 3: Subfloor level showing lead rubber bearings and sliders. In contrast to the IEEE 693 requirements, converter transformers are analyzed not only statically but also dynamically. The thyristor valves, which are suspended from the valve hall ceiling and braced to the building base slab using dampers, are analyzed in the time domain using a non-linear direct integration method. Telescopic connectors capable of displacements up to 900mm are provided between the valve towers and transformer bushings as well as between the HVDC bushing and smoothing reactor. To meet the high seismic requirements the heavy smoothing reactors are equipped with extra high strength inclined support insulators and seismic isolation devices comprising helical steel springs and viscous type dampers (Fig. 4).

Fig. 4: Smoothing reactor showing base isolation seismic damping

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Supported by international experts a successful qualification of many components has been performed proving the high level of seismic resilience of the new Pole 3 plant (Fig. 5).

Fig. 5: Valve side star-bushing of the converter transformer and 350 kV DC disconnector during shake table test

2.2 Site Layout

The site and switchyard layouts are a major challenge as the installation must be constructed within an existing, operational substation and, in the case of Haywards Substation, the site is spatially constrained and of the unused land that is available to develop none of it is level. The difficulty is further complicated as the existing Pole 1 mercury-arc valves (MAV) is being retained, in-service, until within a few months of Pole 3 commissioning, the majority of the DC neutral equipment is being upgraded for both electrical and seismic ratings and due to safety the minimum electrical clearances have increased from those used to construct the existing installation. Changes in occupational safety and health (OSH) regulations and an increased focus on safety have resulted in all maintenance above ground level being undertaken using mobile elevated work platforms (MEWP), both scissor lift and boom types. This in turn results in a requirement for wider maintenance access to allow for MEWP movement within the AC switchyards, DC switchyards, AC filter compounds and the cable terminal stations. Both Haywards and Benmore have audible noise limits applied by the relevant District Councils. For Haywards the maximum LA weighted limits are severe due to the close proximity of the residential to the south and the residential area about 800m across the valley which is direct line-of-sight to the converter transformers and AC filters. At Benmore there is a recreational area on the southern boundary, across a body of water, which is sparsely populated in the winter but very popular in the summer for camping. Haywards Substation located in the North Island, is a large hub for both the 110kV and 220kV networks and also distributes 11kV and 33kV supplies within the local area. Additionally Haywards contains eight synchronous condensers and the existing MAV Pole 1 and Pole 2 facilities in an area bounded on two sides by State Highways, plus a regional park on the northern side and a residential zone hard up against the southern boundary. Benmore Station in the South Island is a significant generation node in the 220kV network and is on the same site as Benmore Hydro Power Station. Benmore contains the existing MAV Pole 1 and Pole 2 facilities and is located within the popular recreational areas of Lake Benmore to the north and Lake Waitaki to the south.

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Fig. 6: General layout of Haywards Converter Station upgrade (extract)

Fig. 7: General layout of Benmore Converter Station upgrade (extract)

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3 POLE 3 DESIGN AND PERFORMANCE CRITERIA

3.1 Design Coordination between Existing and New Plant

One of the primary design aspects is the design coordination between the existing Pole 2 and the new plant of Pole 3. Special attention has been paid to ensure that the energy capabilities or ratings of the Pole 2 arresters are not exceeded. The arrester arrangement including all existing arresters, the V-I characteristics and the protective levels of the new surge arresters have been selected such that the rating of the existing plant will not be exceeded (Fig. 8). Using “A”-arresters [5] with considerably lower protective levels (SIPL, LIPL) all AC plant is adequately protected from fundamental frequency, harmonic, ferro-resonance, switching surge and lightning impulse overvoltages under all operating conditions including AC/DC disturbances or control mal-operation. For example, with Pole 3 (A”- arresters) in service the transferred switching surge stresses of the Pole 2 thyristor valves including their “V”-arresters [5] are lower compared to standalone operation of Pole 2. The new “A”-arresters have been rated to withstand the energy duties caused by a bipolar load rejection taking the increased transmission system rating as well as the extended reactive compensation scheme of the bipolar system into account. Similarly, the new arresters installed at the DC neutral bus are coordinated with the existing “E”-arresters [5] in a way to ensure lower switching surge / low frequency overvoltages for Pole 2 equipment. Consequently, the new “E”-arresters are designed to withstand the interruption of the DC current in the ground electrode return conductor during monopolar operation, DC line pole faults including unsuccessful restart attempts or other DC and AC faults that result in maximum discharging duty on the arresters. As the existing “A” or “E”-arresters provide adequate protection of Pole 2 plant with Pole 3 not available for service as well as for steep front and lightning impulse overvoltages, the existing arresters will remain installed.

Fig. 8: NZ Pole 3 arrester arrangement [5]

The existing Pole 1 DC filters, built identical to Pole 2 DC filters, will be retained for Pole 3 use. Similar to the AC filter design aspects as discussed in Section 3.3 below, performance and rating calculations considering the existing DC filters have been carried out. The implementation of a damping resistor ensures that the DC filter components will not be operated above their ratings. Since the rating of Pole 3, especially the 30 minute overload capacity of 1000 MW, 2857 Adc, is considerably higher than the rating of Pole 2 additional adjustments are required. Various components installed at the DC neutral bus need to be replaced by components with higher rating. This includes the exchange of disconnect switches of the electrode lines, the high-speed neutral bus switch (HSNBS) of Pole 2, the

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neutral surge capacitors and the electrode line fault locator. The HSNBS of Pole 2 is affected since this switch is installed to clear a ground fault at the DC neutral of Pole 2 by commutating the maximum DC current of the healthy Pole 3 back into the electrode line path without power interruption of Pole 3. The installation of four new DC switches and associated commutation circuit as well as consideration of the individual protection zones / functions adds to the complexity of installation in the congested DC yard in Haywards. The existing DC line fault location system has been ineffective and is replaced by a new system capable of locating faults to approximately ±one tower on the lines or ±0.5 km. Two new PEMO (Pulse Echo Monitoring) devices will replace the existing electrode line fault locator systems at both Haywards and Benmore ends. Additionally, the existing 270 kV rated DC roof bushings at the cable terminal stations are replaced by 350 kV rated equipment. 3.2 Reactive Power Control (RPC)

A unique reactive power control (RPC) system has been developed to provide coordinated control of all reactive power supply and absorption plant and the on-load tap-changers of the substation transformers to control the 220 kV and 110 kV (Haywards only) AC bus voltages. At Haywards the following plant is included:

Converter Mvar consumption of Pole 2 (existing) and Pole 3 (new) AC filter (sub-)banks (ST – single-tuned, TT – triple-tuned filter, HP – high-pass):

- F3 (HP 12 + HP 24) (60 + 46.3) Mvar at 220 kV existing plant - F4 (HP 12 + HP 24) (60 + 46.3) Mvar at 220 kV existing plant - F5 (TT 11/13/24 + ST 24) (60 + 49) Mvar at 220 kV new plant (Stage 1) - F6 (TT 11/13/24 + ST 24) (60 + 49) Mvar at 220 kV new plant (Stage 3) - F7 (ST 5 + ST 7) (16.1) Mvar at 110 kV replacement (Stage 1) - F8 (ST 5 + ST 7) (16.1) Mvar at 110 kV replacement (Stage 1)

Shunt reactors: R1 and R5 each 40 Mvar at 11 kV SVC PLUS 1&2 (STATCOM) ± 60 Mvar at 220 kV new plant (Stage 2/3) Synchronous Condensers C1, C2, C3, C4, C5, C6, C7, C8, C9, C10:

- 30…60 (cap) / 20…50 (ind) Mvar at 11 kV existing plant On-load tap-changer of the 220 / 110 kV interconnector transformers at Haywards,

Wilton and Takapu Rd. and the 110 kV / 11 kV synchronous condenser transformers To address the additional compensation needs of Pole 3 and to comply with specified AC voltage change limits during switching a total of 169 (Stage 1/2) MVAr shunt capacitance increasing to 218 (Stage 3) will be installed at the 220 kV system, subdivided into two sub-banks of 60 Mvar and two 49 Mvar sub-banks. Taking the requirements for dynamic compensation devices into account, one SVC PLUS needs to be installed at Stage 2 and a second device will be provided at Stage 3. Each SVC PLUS has a continuously adjustable reactive power output from 60 Mvar capacitive to 60 Mvar inductive at the 220 kV bus. Additionally, a time limited overload capability is implemented to reduce overvoltages (198 Mvar inductive at 1.45 pu AC voltage) and to provide voltage support at reduced voltages in case of network disturbances (98 Mvar capacitive at 0.72 pu AC voltage). The objective of the RPC is the simultaneous control of the 220 kV and the 110 kV bus voltages, while minimizing the loading on the synchronous condenser, balancing the output of all condenser units as well as reducing the number of transformer tap-changer operations. Since the SVC PLUS acts very fast and controls the voltage continuously by variation of the reactive power output, the SVC PLUS is used to control the 220 kV bus voltage (operator

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selected VREF_220) [3][4]. If at least one SVC PLUS is available, the synchronous condensers are used to control the reactive power output of the SVC PLUS to the set point QREF_SVC, which is normally zero. Thus, the SVC PLUS output is zero in the steady state and has the full reactive power band-width available for dynamic voltage support. In case that no SVC PLUS is available for service, the synchronous condensers are used to control the 220 kV bus voltage. The synchronous condensers are balanced to ensure operating at the same percentage of loading, which is especially necessary after switching of shunt reactors. The tap-changers of the condenser transformers connecting the units SC 7 - 10 to the 110 kV bus are controlled to achieve VREF_11 at the 11 kV bus. If the total reactive power output of all synchronous condensers exceeds a capacitive reactive power threshold, filter sub-banks are switched-on. If all available filter sub-banks are in service, shunt reactors are switched-off alternatively. Similar, in case that the total reactive power output of all synchronous condensers exceeds the inductive reactive power threshold, shunt reactors are switched-on. With all shunt reactors in service, filter sub-bank will be switched-off, provided that the harmonic performance requirements are fulfilled after disconnection of the filter sub-bank. Both, the capacitive and inductive reactive power threshold depend on the number of synchronous condensers in operation. The control of the 110 kV bus voltage to the set point VREF_110 selected by the operator is achieved by changing the tap positions of the 220 / 110 kV interconnector transformers T1, T2, and T5 at Haywards as well as T8 at Wilton. Provision is made to incorporate future 220 / 110 kV interconnector transformers T3 at Haywards, T9 at Wilton and T1 at Takapu Road in the controls as well. The RPC monitors the reactive power flow on the transformers at the 110 kV side and changes the tap positions considering equal reactive power sharing to prevent excessive reactive power unbalance. Implemented dead-bands for voltage control take the number of 220 / 110 kV interconnector transformers into account. For example, to minimize tapping, the dead-band for VREF_110 is set to ± 1% considering that at least 4 transformer units are in operation. The RPC system of the Benmore Converter Station manages the reactive power or AC voltage control in a similar manner. In addition to the existing AC filter banks F3 and F4 (each 79.3 Mvar, DT 11/13 + HP 24), two triple-tuned filter banks F5 and F6 and one single-tuned, low-order filter F7 with a rating of 80 Mvar each will be installed at Stage 1 to fulfill the specified compensation limits (2 x TT 11/13/24 + 1 x ST LO3). At Stage 3 the installation of a second redundant low-order filter bank F8 is required. The objective of the Benmore RPC is to either control the voltage at the 220 kV bus or to control the reactive power exchange with the AC system. If the generators are not under control of the RPC, the system will be operated in Q-mode maintaining a small reactive power flow into the AC system. In case that the generator controls are integrated with the HVDC controls, the RPC system will be operated in voltage control mode (V-mode). In V-mode, the generators control the voltage at the 220 kV bus to the operator selected set point with an adjustable droop setting to co-ordinate with neighbouring generation stations. AC filter sub-banks are switched if the generators exceed their reactive power limits. The tap positions of the 220 / 16 kV generator transformers are controlled to obtain nominal voltage at 16 kV. The aim is to reduce the tap changer operation on the transformers as well as to maintain dynamic reactive control range on the generators to respond to system events.

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The high degree of compensation combined with high AC system impedances introduces the potential for considerable temporary overvoltages (TOV) after load rejection. A control limitation strategy minimizes the impact of TOV by using the short-time overload of the SVC PLUS, operation of the synchronous condensers as well as by restarting the DC system and restoring power transfer to pre-disturbance levels as fast as possible. During AC system faults, the HVDC system will be kept in operation to continue power transfer / DC current flow or to facilitate fast recovery. An AC filter tripping logic and DC power runbacks are implemented in the HVDC control system as part of the overvoltage limitation strategy. Moreover, best engineering practices have been applied in the design of both converter stations and in particular of the AC filters to avoid low-order harmonic resonances that substantially increase temporary overvoltage crest values above the fundamental-frequency magnitude (ST LO3 at Benmore, ST5 and ST7 at Haywards). 3.3 AC Filters

The operation of an HVDC converter inherently generates harmonic currents, which if left unaddressed may propagate through the interconnected transmission system, perhaps even amplified due to system resonances. Besides power quality impacts, one potential consequence of harmonic currents injected into a transmission system is interference with telephone circuits due to mutual coupling with transmission lines. Therefore, the new AC filters have been designed to meet the stringent harmonic performance requirements, i.e. total harmonic distortion THD≤ 3.0%, equivalent disturbing voltage EDV ≤ 1.0% and individual harmonic distortion limits Dn: 3rd ≤ 2.0%, 5th ≤ 1.4%, 7th ≤ 1.0%, 11th ≤ 0.7%, 13th ≤ 0.6%, 23rd / 25th / 35th / 37th / 47th / 49th ≤ 0.3% etc. for all applicable operating modes. In addition to meeting the reactive power and harmonic performance targets the overall filter design shall ensure that the new AC filters do not cause undue loading of the existing filters during operation. The existing Pole 2 filters were rated to a lower frequency range (+/- 0.75 Hz) applicable in early 1990s. However, taking the different system conditions such as AC harmonic impedances, the wider AC frequency range (+/-2 Hz), increased number of filters etc. into account, the duplication of the existing filters (e.g. Haywards HP12 or alternatively filters tuned to the 12th) is not sufficient to meet the performance limits. The proposed triple-tuned filter design (similar to that shown in Fig. 9) has been determined considering the symmetry requirements between the existing and new ac filter sub-banks (adequate sharing of harmonics), specified system conditions as well as other design aspects such as the Mvar sub-bank size limits and layout / footprint constraints of both converter stations. Triple-tuned AC filters TT 11/13/24 ensure a very low impedance at the characteristic 11th and 13th harmonics and thus, minimizing the impact on the existing Pole 2 filters. Additionally, these new filters are tuned to the 24th harmonic and include damping resistors providing a high-pass characteristic. Considering the pre-existing low order harmonics potential resonances might result in harmonic voltage distortions above compliance limits. Therefore, 3rd harmonic filters (ST LO3) will be installed at Benmore. The filter impedance characteristic has been determined to provide also filtering at the 4th and 5th harmonic. Besides the steady state stresses, all new filter components are adequately rated for the duty resulting from transient events, such as unbalanced faults, DC load rejection, back-to-back filter switching, transformer energization and / or AC system frequency excursions which will result in high short-time stresses. Furthermore, design calculations prove that with the design of the new AC filters undue loading of the existing filters can be avoided.

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Fig. 9: An example of a Triple-tuned AC filter in operation (Gurun Converter Station) 3.4 Stability, Modulation and Frequency Control

Taking the increased power transfer capability of the HVDC Inter-Island link as well as the low short circuit levels at Haywards Converter Station into account, supplementary modulation controls and runbacks are implemented in the HVDC control system to ensure stable operation under all relevant system conditions. System studies performed have shown that during the DC power recovery interval following the clearing of some North Island AC faults, particularly at high power transfer levels, the modulation of the DC current can effectively damp voltage swings at the Haywards AC buses and thereby prevent voltage collapse. Therefore, a Fault Recovery Modulation (FRM) controller for transient AC voltage support at Haywards has been implemented. Depending on the load demand of the Wellington area adjustable gains of the FRM controller are required to maintain stability of the North Island AC system. Supplementary to the existing Frequency Stabilization Control (FSC) and Spinning Reserve Sharing (SRS) control functions, a Frequency Keeping Controller (FKC) has been developed. The FKC would act to keep the two ac systems operating at the same frequency which is not a function of the existing controls. This function is added to allow for a possible change in the electricity market operation in New Zealand which could employ the HVDC link to perform a frequency keeping role across the two islands. If the AC system of the Wellington area becomes separated from the rest of the North Island power system a Constant Frequency Controller (CFC) will control the AC frequency of the Wellington Island ensuring stable operation under such contingency conditions. In addition to the frequency control, a fast DC power reduction will be initiated to limit the frequency rise to 52 Hz in the Wellington area after islanding (Wellington Over-frequency Brake (WFB)). An interlocking scheme coordinates the operation of several modulation controllers and avoids controller conflicts and malfunctioning. Furthermore, several fast power runback functions are identified to maintain stability of the power systems and slow runback functions are demanded for system security. Comprehensive

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system studies carried out provide evidence that instabilities will not occur and that the AC systems can be kept stable if the appropriate modulation controllers are enabled and the predefined runbacks are initiated upon bus section clearing in Haywards or Bunnythorpe. A high level of reliability of the fast runback (special protection) scheme is essential, so the System Operator could have the confidence not to limit HVDC transfer to post contingency limits. This will enable high pre contingency transfer levels and hence increase availability of HVDC link capacity. 3.5 Converter Transformers A number of initiatives were taken with the design of the converter transformers in an attempt to ensure lower operational hot spot temperature, higher availability and longer life as the converter transformers are key to successful operation of the link. The transformers were specified to have a 90°C maximum copper hot spot temperature at full load, rather than the higher value allowed by the IEC 60076-2. Another detail required was the provision of more robust winding lead out supports inside the tanks. More robust lead out supports minimise the risk of damage due to violent motions associated with travel through stormy sea conditions and seismic shaking. Transpower specified not to use wooden cellulose blocks between the winding coils and in direct contact with the iron core laminations, although this is common practice. Blocks of higher temperature withstand insulating material were provided. The intention was to prevent generation of dissolved gasses into the insulating oil due to thermally induced decomposition of the wooden cellulose blocks and to prevent miss-diagnosis of winding insulation failure. Each transformer is provided with five integral oil/air coolers with associated fans and oil pump, adequate for continuous and overload rating. Also provided on each transformer is an integral 6th redundant cooler to allow maintenance of any one cooler while the transformer remains in service and increase DC link availability. Fig. 10 shows one of the Pole 3 single-phase three-winding converter transformers during factory test.

Fig. 10: Pole 3 converter transformer during factory test

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3.5 Pole 2 Control System Replacement

Following successful demonstration of Pole 3 operation, the existing Pole 2 HVDC control and protection system will undergo a half life replacement. New Siemens control system cubicles will be installed adjacent to the existing control system except the VBE (valve base electronics). A short 3 weeks outage is required for the transition to the new control system for Pole 2. 4 CONCLUSION

Due to the high seismic design requirements, the need to maintain supply of existing HVDC link and working within constrained switchyard makes the HVDC Pole 3 project a challenging exercise. This required extensive preliminary planning with particular attention to detailed design and additional product development not normally associated with a conventional green field HVDC project. Specific design aspects and performance criteria for the HVDC Pole 3 Project, in particular those relating to a unique reactive power control system and to the stringent power quality requirements, were addressed. In addition, stability, modulation controls and runbacks have been determined and are implemented in the HVDC control system to ensure stable operation even under weak system conditions. Due consideration has been given to a prudent design coordination between the existing Pole 2 and the new Pole 3 in order to avoid excessive loading or detrimental effects on the lifetime of neither the new nor the existing plant. BIBLIOGRAPHY [1] P. Griffiths: “NZ Inter Island HVDC Pole 3 Project”, CIGRE SC B4 Colloquium October 2011

Brisbane [2] P. Griffiths, M. Zavahir: “Planning for New Zealand’s Inter-Island HVDC Pole 1 replacement”,

CIGRE SC B4 Session Paper B4-108, 2008 [3] M. Pereira, A. Zenkner, M. Claus: "Characteristics and benefits of modular multilevel

converters for FACTS", CIGRE SC B4 session paper B4-104, 2010 [4] M. Pereira, M. Pieschel, R. Stoeber: “Prospects of the new SVC with Modular Multilevel

Voltage Source Converter” CIGRE Colloquium, October 2011, Brisbane [5] IEC 60071-5-2002 “Insulation co-ordination – Part 5: Procedures for high-voltage direct current

(HVDC) converter stations”